etr-20251231

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


(Mark One)
☑			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2025


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

			For the transition period from ____________ to ____________


Commission File Number	Registrant, State of Incorporation or Organization, Address of Principal Executive Offices, Telephone Number, and IRS Employer Identification No.	Commission File Number	Registrant, State of Incorporation or Organization, Address of Principal Executive Offices, Telephone Number, and IRS Employer Identification No.

1-11299	ENTERGY CORPORATION	1-35747	ENTERGY NEW ORLEANS, LLC
	(a Delaware corporation) 639 Loyola Avenue New Orleans, Louisiana 70113 Telephone (504) 576-4000		(a Texas limited liability company) 1600 Perdido Street New Orleans, Louisiana 70112 Telephone (504) 670-3702
	72-1229752		82-2212934


1-10764	ENTERGY ARKANSAS, LLC	1-34360	ENTERGY TEXAS, INC.
	(a Texas limited liability company) 425 West Capitol Avenue Little Rock, Arkansas 72201 Telephone (501) 377-4000		(a Texas corporation) 2107 Research Forest Drive The Woodlands, Texas 77380 Telephone (409) 981-2000
	83-1918668		61-1435798


1-32718	ENTERGY LOUISIANA, LLC	1-09067	SYSTEM ENERGY RESOURCES, INC.
	(a Texas limited liability company) 4809 Jefferson Highway Jefferson, Louisiana 70121 Telephone (504) 576-4000		(an Arkansas corporation) 1340 Echelon Parkway Jackson, Mississippi 39213 Telephone (601) 368-5000
	47-4469646		72-0752777


1-31508	ENTERGY MISSISSIPPI, LLC
	(a Texas limited liability company) 308 East Pearl Street Jackson, Mississippi 39201 Telephone (601) 368-5000
	83-1950019

Table of Contents

Securities registered pursuant to Section 12(b) of the Act:


Registrant	Title of Class	Trading Symbol	Name of Each Exchange on Which Registered

Entergy Corporation	Common Stock, $0.01 Par Value	ETR	New York Stock Exchange
	Common Stock, $0.01 Par Value	ETR	NYSE Texas

Entergy Arkansas, LLC	Mortgage Bonds, 4.875% Series due September 2066	EAI	New York Stock Exchange

Entergy Louisiana, LLC	Mortgage Bonds, 4.875% Series due September 2066	ELC	New York Stock Exchange

Entergy Mississippi, LLC	Mortgage Bonds, 4.90% Series due October 2066	EMP	New York Stock Exchange

Entergy New Orleans, LLC	Mortgage Bonds, 5.0% Series due December 2052	ENJ	New York Stock Exchange
	Mortgage Bonds, 5.50% Series due April 2066	ENO	New York Stock Exchange

Entergy Texas, Inc.	5.375% Series A Preferred Stock, Cumulative, No Par Value (Liquidation Value $25 Per Share)	ETI/PR	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:


Registrant			Title of Class

Entergy Texas, Inc.			Common Stock, no par value

Table of Contents

Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.


	Yes	No

Entergy Corporation	ü
Entergy Arkansas, LLC	ü
Entergy Louisiana, LLC	ü
Entergy Mississippi, LLC	ü
Entergy New Orleans, LLC		ü
Entergy Texas, Inc.	ü
System Energy Resources, Inc.		ü

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.


	Yes	No

Entergy Corporation		ü
Entergy Arkansas, LLC		ü
Entergy Louisiana, LLC		ü
Entergy Mississippi, LLC		ü
Entergy New Orleans, LLC		ü
Entergy Texas, Inc.		ü
System Energy Resources, Inc.		ü

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files). Yes þ No o

Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

Accelerated

filer

Non-accelerated filer

Smaller
reporting
company

Emerging
growth
company

Entergy Corporation

Entergy Arkansas, LLC

Entergy Louisiana, LLC

Entergy Mississippi, LLC

Entergy New Orleans, LLC

Entergy Texas, Inc.

System Energy Resources, Inc.

Table of Contents

If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.


Entergy Corporation			ü
Entergy Arkansas, LLC
Entergy Louisiana, LLC
Entergy Mississippi, LLC
Entergy New Orleans, LLC
Entergy Texas, Inc.
System Energy Resources, Inc.

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrants included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrants’ executive officers during the relevant recovery period pursuant to § 240.10D-1(b). ☐

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Act).

Yes ☐ No þ

The aggregate market value of Entergy Corporation Common Stock, $0.01 Par Value, held by non-affiliates at June 30, 2025 was $37.1 billion. Entergy Corporation is the sole holder of the common stock of Entergy Texas, Inc. and System Energy Resources, Inc. Entergy Corporation is the direct and indirect holder of the common membership interests of Entergy Utility Holding Company, LLC, which is the sole holder of the common membership interests of Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, LLC, and Entergy New Orleans, LLC.


Common Stock Outstanding		Outstanding at January 30, 2026
Entergy Corporation	($0.01 par value)	452,989,837

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders, to be held May 8, 2026, are incorporated by reference into Part III hereof.

System Energy Resources, Inc. meets the requirements set forth in General Instruction I(1) of Form 10-K and is therefore filing this Form 10-K with reduced disclosure as allowed in General Instruction I(2). System Energy Resources, Inc. is reducing its disclosure by not including Part III, Items 10 through 13 in its Form 10-K.

Table of Contents

(Page left blank intentionally)

Table of Contents

TABLE OF CONTENTS


	SEC Form 10-K Reference Number	Page Number

Forward-looking Information		iv
Definitions		viii
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	1
Report of Management		41
Report of Independent Registered Public Accounting Firm		42
Consolidated Income Statements for the Years Ended December 31, 202 5 , 202 4 , and 2023	Part II. Item 8.	45
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 20 25 , 202 4 , and 2023	Part II. Item 8.	47
Consolidated Statements of Cash Flows for the Years Ended December 31, 20 25 , 202 4 , and 2023	Part II. Item 8.	48
Consolidated Balance Sheets, December 31, 20 25 and 2024	Part II. Item 8.	50
Consolidated Statements of Changes in Equity for the Years Ended December 31, 20 25 , 202 4 , and 2023	Part II. Item 8.	52
Notes to Financial Statements	Part II. Item 8.
Note 1. Summary of Significant Accounting Policies		53
Note 2. Rate and Regulatory Matters		64
Note 3. Income Taxes		118
Note 4. Revolving Credit Facilities, Lines of Credit, and Short-term Borrowings		139
Note 5. Long-term Debt		143
Note 6. Preferred Equity and Noncontrolling Interests		152
Note 7. Common Equity		155
Note 8. Commitments and Contingencies		161
Note 9. Asset Retirement Obligations		168
Note 10. Leases		171
Note 11. Retirement, Other Postretirement Benefits, and Defined Contribution Plans		177
Note 12. Stock-based Compensation		208
Note 13. Business Segment Information		213
Note 14. Acquisitions and Dispositions		216
Note 15. Risk Management and Fair Values		219
Note 16. Decommissioning Trust Funds		232
Note 17. Variable Interest Entities		238
Note 18. Transactions with Affiliates		240
Note 19. Revenue		242
Entergy’s Business	Part I. Item 1.
Risk Factors Summary		247
Utility		249
Other Business Activities		278
Regulation of Entergy’s Business		279
Litigation		291
Human Capital		292
Availability of SEC filings and other information on Entergy’s website		294
Risk Factors	Part I. Item 1A.	295
Unresolved Staff Comments	Part I. Item 1B.	322

Table of Contents


Cybersecurity	Part I. Item 1C.	322
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	326
Report of Independent Registered Public Accounting Firm		346
Consolidated Income Statements for the Years Ended December 31, 202 5 , 202 4 , and 2023	Part II. Item 8.	348
Consolidated Statements of Cash Flows for the Years Ended December 31, 202 5 , 202 4 , and 2023	Part II. Item 8.	349
Consolidated Balance Sheets, December 31, 202 5 and 2024	Part II. Item 8.	350
Consolidated Statements of Changes in Equity for the Years Ended December 31, 202 5 , 202 4 , and 2023	Part II. Item 8.	352
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	353
Report of Independent Registered Public Accounting Firm		375
Consolidated Income Statements for the Years Ended December 31, 20 25 , 202 4 , and 2023	Part II. Item 8.	377
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 20 25 , 202 4 , and 2023	Part II. Item 8.	378
Consolidated Statements of Cash Flows for the Years Ended December 31, 202 5 , 202 4 , and 2023	Part II. Item 8.	379
Consolidated Balance Sheets, December 31, 20 25 and 2024	Part II. Item 8.	380
Consolidated Statements of Changes in Equity for the Years Ended December 31, 202 5 , 202 4 , and 2023	Part II. Item 8.	382
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	383
Report of Independent Registered Public Accounting Firm		400
Consolidated Income Statements for the Years Ended December 31, 20 25 , 202 4 , and 2023	Part II. Item 8.	402
Consolidated Statements of Cash Flows for the Years Ended December 31, 202 5 , 202 4 , and 2023	Part II. Item 8.	403
Consolidated Balance Sheets, December 31, 202 5 and 2024	Part II. Item 8.	404
Consolidated Statements of Changes in Equity for the Years Ended December 31, 202 5 , 202 4 , and 2023	Part II. Item 8.	406
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	407
Report of Independent Registered Public Accounting Firm		419
Consolidated Income Statements for the Years Ended December 31, 20 25 , 202 4 , and 2023	Part II. Item 8.	421
Consolidated Statements of Cash Flows for the Years Ended December 31, 20 25 , 202 4 , and 2023	Part II. Item 8.	423
Consolidated Balance Sheets, December 31, 20 25 and 2024	Part II. Item 8.	424
Consolidated Statements of Changes in Member’s Equity for the Years Ended December 31, 20 25 , 202 4 , and 2023	Part II. Item 8.	426
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	427
Report of Independent Registered Public Accounting Firm		446
Consolidated Income Statements for the Years Ended December 31, 202 5 , 202 4 , and 2023	Part II. Item 8.	449
Consolidated Statements of Cash Flows for the Years Ended December 31, 202 5 , 202 4 , and 2023	Part II. Item 8.	451
Consolidated Balance Sheets, December 31, 20 25 and 2024	Part II. Item 8.	452
Consolidated Statements of Changes in Equity for the Years Ended December 31, 202 5 , 202 4 , and 2023	Part II. Item 8.	454

Table of Contents


System Energy Resources, Inc.
Management’s Financial Discussion and Analysis	Part II. Item 7.	455
Report of Independent Registered Public Accounting Firm		465
Income Statements for the Years Ended December 31, 202 5 , 202 4 , and 2023	Part II. Item 8.	467
Statements of Cash Flows for the Years Ended December 31, 20 25 , 202 4 , and 2023	Part II. Item 8.	469
Balance Sheets, December 31, 202 5 and 2024	Part II. Item 8.	470
Statements of Changes in Common Equity for the Years Ended December 31, 20 25 , 202 4 , and 2023	Part II. Item 8.	472
Properties	Part I. Item 2.	473
Legal Proceedings	Part I. Item 3.	473
Mine Safety Disclosures	Part I. Item 4.	473
Information about Executive Officers of Entergy Corporation	Part I. and Part III. Item 10.	473
Market for Registrants’ Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	Part II. Item 5.	476
Reserved	Part II. Item 6.	476
Management’s Discussion and Analysis of Financial Condition and Results of Operations	Part II. Item 7.	477
Quantitative and Qualitative Disclosures About Market Risk	Part II. Item 7A.	477
Financial Statements and Supplementary Data	Part II. Item 8.	477
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	Part II. Item 9.	477
Controls and Procedures	Part II. Item 9A.	477
Attestation Report of Registered Public Accounting Firm	Part II. Item 9A.	479
Other Information	Part II. Item 9B.	480
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	Part II. Item 9C.	480
Directors, Executive Officers, and Corporate Governance of the Registrants	Part III. Item 10.	481
Executive Compensation	Part III. Item 11.	485
Security Ownership of Certain Beneficial Owners and Management	Part III. Item 12.	533
Certain Relationships and Related Party Transactions and Director Independence	Part III. Item 13.	535
Principal Accountant Fees and Services	Part III. Item 14.	536
Exhibits and Financial Statement Schedules	Part IV. Item 15.	539
Form 10-K Summary	Part IV. Item 16.	539
Exhibit Index		540
Signatures		559
Consents of Independent Registered Public Accounting Firm		566

This combined Form 10-K is separately filed by Entergy Corporation and its six Registrant Subsidiaries: Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, LLC, Entergy New Orleans, LLC, Entergy Texas, Inc., and System Energy Resources, Inc. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes representations only as to itself and makes no other representations whatsoever as to any other company.

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

iii

Table of Contents

FORWARD-LOOKING INFORMATION

In this combined report and from time to time, Entergy Corporation and the Registrant Subsidiaries each makes statements as a registrant concerning its expectations, beliefs, plans, objectives, goals, projections, strategies, and future events or performance. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Words such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “intend,” “goal,” “commitment,” “expect,” “estimate,” “continue,” “potential,” “plan,” “predict,” “forecast,” and other similar words or expressions are intended to identify forward-looking statements but are not the only means to identify these statements. Although each of these registrants believes that these forward-looking statements and the underlying assumptions are reasonable, it cannot provide assurance that they will prove correct. Any forward-looking statement is based on information current as of the date of this combined report and speaks only as of the date on which such statement is made. Except to the extent required by the federal securities laws, each registrant undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

Forward-looking statements involve a number of risks and uncertainties. There are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements, including (a) those factors discussed or incorporated by reference in Item 1A. Risk Factors in this report, (b) those factors discussed or incorporated by reference in Management’s Financial Discussion and Analysis in this report, and (c) the following factors (in addition to others described elsewhere in this combined report and in subsequent filings with the SEC):

•resolution of pending and future rate cases and related litigation, formula rate proceedings and related negotiations, including various performance-based rate discussions, Entergy’s utility supply plan, and recovery of fuel and purchased power costs, as well as delays in cost recovery resulting from these proceedings;

•regulatory and operating challenges and uncertainties and economic risks associated with the Utility operating companies’ participation in MISO, including the benefits of continued MISO participation, the effect of current or projected MISO market rules, market design and market and system conditions in the MISO markets, the allocation of MISO system transmission upgrade costs, delays in developing or interconnecting new generation or other resources or other adverse effects arising from the volume of requests in the MISO transmission interconnection queue, which delays or other adverse effects may be exacerbated by significant current and expected load growth, the MISO-wide base rate of return on equity allowed or any MISO-related charges and credits required by the FERC, and the effect of planning decisions that MISO makes with respect to future transmission investments by the Utility operating companies (including, in each case, as it relates to new generation or transmission projects designed to serve the increased load growth of new large-scale data centers and other large customers);

•changes in utility regulation, including, with respect to retail and wholesale competition and special rules supporting service to large-scale data centers, the ability to recover net utility assets and other potential stranded costs, including those capital investments associated with unrealized customer growth expectations (including data center customers), and the application of more stringent return on equity criteria, transmission reliability requirements, or market power criteria by the FERC or the U.S. Department of Justice;

•changes in the regulation or regulatory oversight of Entergy’s nuclear generating facilities, nuclear materials and fuel, and the effects of new or existing safety or environmental concerns regarding nuclear power plants and fuel;

•resolution of pending or future applications, as well as regulatory proceedings, litigation or actions of governmental officials (including the presidential administration), relating to generation, transmission, or other facilities (including license modifications or other authorizations for nuclear generating facilities and applications relating to any facilities designed to serve large-scale data centers) and the effect of public and political opposition on these applications, regulatory proceedings, litigation, and actions, including without limitation opposition to the employment of technologies to capture, transport, and store carbon dioxide from gas plants, land use opposition to new solar facilities and transmission lines, and land use and other opposition to wind turbines;

Table of Contents

FORWARD-LOOKING INFORMATION (Continued)

•the performance of and deliverability of power from Entergy’s generation resources, including the capacity factors at Entergy’s nuclear generating facilities;

•increases in costs and capital expenditures that could result from changing regulatory requirements, changing governmental policies, priorities, programs, and actions, including as a result of tariffs, shifts in international trade policies, and other measures, changing or volatile economic conditions, disruptions to pre-existing supply chains and vendor relations, and emerging operating and industry issues, such as anticipated growth in demand from large-scale data centers, and the risks related to recovery of these costs and capital expenditures from Entergy’s customers (especially in an increasing cost environment);

•the commitment of substantial human and capital resources required for the safe and reliable operation and maintenance of Entergy’s utility system, including its nuclear generating facilities;

•Entergy’s ability to develop and execute on a point of view regarding future prices of electricity, natural gas, and other energy-related commodities;

•the prices and availability of fuel and power Entergy must purchase for its Utility customers, particularly given the recent and ongoing significant growth in liquified natural gas exports and the associated significantly increased demand for natural gas and resulting fluctuation in natural gas prices, increasing challenges with respect to natural gas transportation arrangements, and Entergy’s ability to meet credit support requirements for fuel and power supply contracts;

•volatility and changes in markets for electricity, natural gas, uranium, emissions allowances, and other energy-related commodities, including as a result of trade-related governmental actions, such as tariffs and other measures, and the effect of those changes on Entergy and its customers;

•changes in environmental laws and regulations, agency positions, or associated litigation, including requirements for reduced emissions of sulfur dioxide, nitrogen oxide, greenhouse gases, mercury, particulate matter and other regulated air emissions, heat and other regulated discharges to water, waste management and disposal, remediation of contaminated sites, wetlands protection and permitting, and reporting, and changes in costs of compliance with environmental laws and regulations, as well as changes to federal, state, or local laws and regulations, including the One Big Beautiful Bill Act of 2025, and governmental policies incentivizing the development or utilization of alternative sources of generation;

•changes in laws and regulations, agency positions, or associated litigation related to protected species and associated critical habitat designations;

•the effects of changes in federal, state, or local laws and regulations, such as the One Big Beautiful Bill Act of 2025, and other governmental actions or policies, including changes in monetary, fiscal, tax, environmental, trade/tariff, domestic purchase requirements, or energy (including, among other things, data center energy use, efficiency standards, and sources of power) policies and related laws, regulations, and other governmental actions, including as a result of prolonged litigation over proposed legislation or regulatory actions;

•the effects of full or partial shutdowns of the federal government or delays in obtaining government or regulatory actions or decisions;

•uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel and nuclear waste storage and disposal and the level of spent fuel and nuclear waste disposal fees charged by the U.S. government or other providers related to such sites;

•variations in weather and the occurrence of hurricanes and other storms and disasters, including uncertainties associated with efforts to remediate the effects of hurricanes, ice storms, floods, wildfires, or other weather events and the recovery of costs associated with restoration, including the ability to access funded storm reserves, federal and local cost recovery mechanisms, securitization, and insurance, as well as any related unplanned outages;

•effects of climate change, including the potential for increases in the frequency or severity of extreme weather events, such as hurricanes, heat waves, floods, drought or wildfires, and rising sea levels or coastal land and wetland loss, and Entergy’s ability to effectively prepare for such effects and events, including through accelerated resilience plans and projects, and any challenges in execution thereof and/or in obtaining any necessary regulatory approvals for appropriate scope and timing of such plans and projects now and in the future;

Table of Contents

FORWARD-LOOKING INFORMATION (Continued)

•the risk that as a result of Entergy’s membership in Nuclear Electric Insurance Limited (NEIL), an incident at a NEIL member-insured nuclear generation facility could lead to a significant retrospective assessment;

•the risk that an incident at a nuclear generation facility participating in a secondary financial protection system could lead to a significant retrospective insurance premium;

•changes in the quality and availability of water supplies and the related regulation of water use and diversion;

•Entergy’s ability to manage and execute on its capital projects, including any capital projects to serve the growing demand for electricity driven in part by the anticipated development of large-scale data centers, and to complete such capital projects timely and within budget, to obtain the anticipated performance or other benefits of such capital projects, and to manage its capital and operation and maintenance costs;

•the effects of supply chain disruptions, including those driven by geopolitical developments or trade-related governmental actions, including tariffs and other measures, and labor pressures, including from increased demand in the electric sector, on Entergy’s ability to complete its capital projects in a timely and cost-effective manner;

•Entergy’s ability to purchase and sell assets at attractive prices and on other attractive terms;

•the economic climate, and particularly economic conditions in the Utility service area and events and circumstances that could influence economic conditions in those areas, including power prices and inflation, and the risk that anticipated load growth may not materialize;

•changes to or the repeal of federal income tax laws, regulations, and interpretive guidance and policies, including the One Big Beautiful Bill Act of 2025 and the continuing impact of the Inflation Reduction Act of 2022 and the Tax Cuts and Jobs Act of 2017, and any related intended or unintended consequences on financial results and future cash flows;

•the effects of Entergy’s strategies to reduce tax payments;

•the effect of interest rate volatility and other changes in the financial markets, federal law, including the One Big Beautiful Bill Act of 2025, and regulatory requirements for the issuance of securities, particularly as they affect access to and cost of capital and Entergy’s ability to refinance existing securities and fund investments and acquisitions;

•actions of rating agencies, including changes in the ratings of debt and preferred stock, changes in general corporate ratings, and changes in the rating agencies’ ratings criteria;

•changes in inflation and interest rates and the impacts of inflation or a recession on Entergy’s customers;

•the effects of government investigations, proceedings, or audits;

•changes in technology, including (i) Entergy’s ability to effectively assess, acquire, implement, and manage new or emerging technologies, including its ability to maintain and protect personally identifiable information while doing so; (ii) the emergence of artificial intelligence (including machine learning), which may present increased electricity demand, as well as ethical, security, legal, operational, or regulatory challenges; (iii) advances in artificial intelligence (including machine learning) technologies that could reduce the expected electricity demand for these technologies and data centers; (iv) the impact of changes relating to new, developing, or alternative sources of generation such as distributed energy and energy storage, renewable energy, energy efficiency, demand side management, and other measures that reduce load and government policies impacting development or utilization of the foregoing; and (v) competition from other companies offering products and services to Entergy’s customers based on new or emerging technologies or alternative sources of generation;

•Entergy’s ability to effectively formulate and implement plans to reduce emissions of greenhouse gases associated with climate change and increase carbon-free energy generation capacity, including its goal to achieve net-zero carbon emissions by 2050, the potential impact on its business and financial condition of attempting to achieve such objectives, and Entergy’s ability to make measurable progress toward any climate goals due to expected load growth or other factors;

•the effects, including increased security costs, of threatened or actual terrorism, cyber attacks or data security breaches, physical attacks on or other interference with facilities or infrastructure, natural or man-made electromagnetic pulses that affect transmission or generation infrastructure, accidents, and war or a catastrophic event such as a nuclear accident or a natural gas pipeline explosion;

Table of Contents

FORWARD-LOOKING INFORMATION (Concluded)

•impacts of perceived or actual cybersecurity or data security threats or events on Entergy and its subsidiaries, its vendors, suppliers or other third parties interconnected through the grid, which could, among other things, result in disruptions to its operations, including but not limited to, the loss of operational control, temporary or extended outages, or loss of data, including but not limited to, sensitive customer, employee, financial or operations data;

•the effects of a catastrophe, pandemic (or other health-related event), or a global or geopolitical event such as escalating trade tensions between the United States and China or the military activities between Russia and Ukraine, or in the Middle East, including resultant economic and societal disruptions; fuel procurement disruptions; volatility in the capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available bank credit facilities); reduced demand for electricity, particularly from commercial and industrial customers; increased or unrecoverable costs; supply chain, vendor, and contractor disruptions, including as a result of trade-related sanctions; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed outages; impacts to Entergy’s workforce availability, health, or safety; increased cybersecurity risks as a result of many employees telecommuting and/or working partially remotely; increased late or uncollectible customer payments; regulatory delays; executive orders affecting, or increased regulation of, Entergy’s business; changes in credit ratings or outlooks as a result of any of the foregoing; or other adverse impacts on Entergy’s ability to execute on its business strategies and initiatives or, more generally, on Entergy’s results of operations, financial condition, and liquidity;

•Entergy’s ability to attract and retain talented management, directors, and employees with specialized skills, institutional knowledge, capacity, and abilities, including the ability to effectively execute on Entergy’s growth strategy;

•Entergy’s ability to attract, retain, and manage an appropriately qualified and sufficiently staffed workforce;

•changes in accounting standards and corporate governance best practices;

•declines in the market prices of marketable securities and changes in interest rates and resulting pension and retiree welfare plan funding requirements and the effects on benefits costs for Entergy’s defined benefit pension and other postretirement benefits plans;

•future wage and employee benefits costs, including changes in discount rates and returns on benefit plan assets and fluctuating costs to provide employee and retiree health benefits;

•changes in decommissioning trust fund values or earnings or in the timing of, requirements for, or cost to decommission Entergy’s nuclear plant sites and the implementation of decommissioning of such sites following shutdown;

•the effectiveness of Entergy’s risk management policies and procedures and the ability and willingness of its counterparties, such as lending, hedging, credit support, and major customer counterparties, including counterparties to data center electric service agreements, to satisfy their financial and performance commitments;

•reductions in the demand for electricity to power large-scale data centers and other large customers and the potential for stranded assets;

•concentration of business and credit risk with a small number of customers in an industry based on emerging technologies, including artificial intelligence and machine learning; and

•Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete strategic transactions that they may undertake, and their ability to meet the rapidly growing demand for electricity, including from large-scale data center and other large customers, and to manage the impacts of growth in demand for electricity on customers and Entergy’s business.

vii

Table of Contents

DEFINITIONS

Certain abbreviations or acronyms used in the text and notes are defined below:


Abbreviation or Acronym			Term

AFUDC			Allowance for Funds Used During Construction
ALJ			Administrative Law Judge
ANO 1 and 2			Units 1 and 2 of Arkansas Nuclear One (nuclear), owned by Entergy Arkansas
APSC			Arkansas Public Service Commission
ASU			Accounting Standards Update issued by the FASB
Board			Board of Directors of Entergy Corporation
Cajun			Cajun Electric Power Cooperative, Inc.
capacity factor			Actual plant output divided by maximum potential plant output for the period
City Council			Council of the City of New Orleans, Louisiana
COVID-19			The novel coronavirus disease declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention in March 2020
D.C. Circuit			U.S. Court of Appeals for the District of Columbia Circuit
DOE			United States Department of Energy
Entergy			Entergy Corporation and its direct and indirect subsidiaries
Entergy Corporation			Entergy Corporation, a Delaware corporation
Entergy Gulf States, Inc.			Predecessor company for financial reporting purposes to Entergy Gulf States Louisiana that included the assets and business operations of both Entergy Gulf States Louisiana and Entergy Texas
Entergy Gulf States Louisiana			Entergy Gulf States Louisiana, L.L.C., a Louisiana limited liability company formally created as part of the jurisdictional separation of Entergy Gulf States, Inc. and the successor company to Entergy Gulf States, Inc. for financial reporting purposes. The term is also used to refer to the Louisiana jurisdictional business of Entergy Gulf States, Inc., as the context requires. Effective October 1, 2015, the business of Entergy Gulf States Louisiana was combined with Entergy Louisiana.
Entergy Louisiana			Entergy Louisiana, LLC, a Texas limited liability company formally created as part of the combination of Entergy Gulf States Louisiana and the company formerly known as Entergy Louisiana, LLC (Old Entergy Louisiana) into a single public utility company and the successor to Old Entergy Louisiana for financial reporting purposes
Entergy Texas			Entergy Texas, Inc., a Texas corporation formally created as part of the jurisdictional separation of Entergy Gulf States, Inc. The term is also used to refer to the Texas jurisdictional business of Entergy Gulf States, Inc., as the context requires.
Entergy Wholesale Commodities			Prior to January 1, 2023, one of Entergy’s reportable business segments consisting of non-utility business activities primarily comprised of the ownership, operation, and decommissioning of nuclear power plants, the ownership of interests in non-nuclear power plants, and the sale of the electric power produced by its operating power plants to wholesale customers
EPA			United States Environmental Protection Agency
ERCOT			Electric Reliability Council of Texas
FASB			Financial Accounting Standards Board
FERC			Federal Energy Regulatory Commission

GAAP			Generally Accepted Accounting Principles
Grand Gulf			Unit No. 1 of Grand Gulf Nuclear Station (nuclear), 90% owned or leased by System Energy
GWh			Gigawatt-hour(s), which equals one million kilowatt-hours
HLBV			Hypothetical liquidation at book value
Independence			Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi, and 7% by Entergy Power, LLC

viii

Table of Contents

DEFINITIONS (Continued)


Abbreviation or Acronym			Term




Indian Point 2			Unit 2 of Indian Point Energy Center (nuclear), previously owned as part of Entergy’s non-utility business, which ceased power production in April 2020 and was sold in May 2021
Indian Point 3			Unit 3 of Indian Point Energy Center (nuclear), previously owned as part of Entergy’s non-utility business, which ceased power production in April 2021 and was sold in May 2021
IRS			Internal Revenue Service
ISO			Independent System Operator
kV			Kilovolt
kW			Kilowatt, which equals one thousand watts
kWh			Kilowatt-hour(s)
LDEQ			Louisiana Department of Environmental Quality
LPSC			Louisiana Public Service Commission
LURC			Louisiana Utilities Restoration Corporation

MISO			Midcontinent Independent System Operator, Inc., a regional transmission organization
MMBtu			One million British Thermal Units
MPSC			Mississippi Public Service Commission
MW			Megawatt(s), which equals one thousand kilowatts
MWh			Megawatt-hour(s)
Nelson Unit 6			Unit No. 6 (coal) of the Nelson Steam Electric Generating Station, 70% of which is co-owned by Entergy Louisiana (57.5%) and Entergy Texas (42.5%) and 10.9% of which is owned by EAM Nelson Holding, LLC
Net debt to net capital ratio			Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents, which is a non-GAAP measure
NRC			Nuclear Regulatory Commission
Palisades			Palisades Nuclear Plant (nuclear), previously owned as part of Entergy’s non-utility business, which ceased power production in May 2022 and was sold in June 2022
Parent & Other			The portions of Entergy not included in the Utility segment, primarily consisting of the activities of the parent company, Entergy Corporation, and other business activity, including Entergy’s non-utility operations business which owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers and also provides decommissioning services to nuclear power plants owned by non-affiliated entities in the United States

PPA			Purchased power agreement or power purchase agreement
PRP			Potentially responsible party (a person or entity that may be responsible for remediation of environmental contamination)
PUCT			Public Utility Commission of Texas
Registrant Subsidiaries			Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, LLC, Entergy New Orleans, LLC, Entergy Texas, Inc., and System Energy Resources, Inc.
River Bend			River Bend Station (nuclear), owned by Entergy Louisiana
RTO			Regional transmission organization
SEC			Securities and Exchange Commission
System Agreement			Agreement, effective January 1, 1983, as modified, among the Utility operating companies relating to the sharing of generating capacity and other power resources. The agreement terminated effective August 2016.
System Energy			System Energy Resources, Inc.

Table of Contents

DEFINITIONS (Concluded)


Abbreviation or Acronym			Term







Unit Power Sales Agreement			Agreement, dated as of June 10, 1982, as amended and approved by the FERC, among Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, relating to the sale of capacity and energy from System Energy’s share of Grand Gulf
Utility			Entergy’s reportable segment that generates, transmits, distributes, and sells electric power, and which included a small amount of natural gas distribution in portions of Louisiana through June 30, 2025
Utility operating companies			Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas
Vermont Yankee			Vermont Yankee Nuclear Power Station (nuclear), previously owned as part of Entergy’s non-utility business, which ceased power production in December 2014 and was disposed of in January 2019
Waterford 3			Unit No. 3 (nuclear) of the Waterford Steam Electric Station, owned by Entergy Louisiana
weather-adjusted usage			Electric usage excluding the effects of deviations from normal weather
White Bluff			White Bluff Steam Electric Generating Station, 57% owned by Entergy Arkansas

Table of Contents

ENTERGY CORPORATION AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

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 included operation of a small natural gas distribution business in portions of Louisiana through June 30, 2025. See “Dispositions - Natural Gas Distribution Businesses” in Note 14 to the financial statements for discussion of the sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses on July 1, 2025. See Note 13 to the financial statements for discussion of and financial information regarding Entergy’s reportable segment.

Winter Storm Fern

In January 2026, portions of Entergy’s service territory experienced the effects of Winter Storm Fern, including prolonged freezing temperatures, heavy ice accumulation, and wind, which caused severe damage to Entergy’s infrastructure. Entergy’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $460 million to $560 million, primarily at Entergy Louisiana and Entergy Mississippi, with the majority of the costs being capital. There are well-established mechanisms and precedent for addressing these catastrophic events and providing the process for regulatory review of storm costs for prudence and for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles.

The severe weather event also affected the market for natural gas due to the effects of severe cold on the gas supply system and increased demand for gas to support electricity loads. Natural gas purchases for January 2026 for Entergy were $483 million, including $74 million for Entergy Arkansas, $256 million for Entergy Louisiana, $85 million for Entergy Mississippi, $20 million for Entergy New Orleans, and $48 million for Entergy Texas. This compares to natural gas purchases for January 2025 for Entergy of $207 million, including $25 million for Entergy Arkansas, $115 million for Entergy Louisiana, $28 million for Entergy Mississippi, $4 million for Entergy New Orleans, and $35 million for Entergy Texas. The Utility operating companies each have fuel recovery mechanisms in place to recover their natural gas costs. With the potential effect of the higher natural gas costs on customers, the Utility operating companies plan to work with their retail regulators to recover these costs in a manner that mitigates the effects on customer bills.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Results of Operations

2025 Compared to 2024

Following are income statement variances for Utility, Parent & Other, and Entergy comparing 2025 to 2024 showing how much the line item increased or (decreased) in comparison to the prior period.


	Utility	Parent & Other (a)	Entergy
	(In Thousands)
2024 Net Income (Loss) Attributable to Entergy Corporation	$1,826,704	($771,114)	$1,055,590

Operating revenues	1,082,119	(15,086)	1,067,033
Fuel, fuel-related expenses, and gas purchased for resale	123,876	(21,347)	102,529
Purchased power	421,069	(19,307)	401,762
Other regulatory charges (credits) - net	(155,413)	—	(155,413)
Other operation and maintenance	161,835	(4,975)	156,860
Asset write-offs, impairments, and related charges (credits)	(118,980)	24,641	(94,339)
Taxes other than income taxes	65,496	220	65,716
Depreciation and amortization	64,309	215	64,524
Other income (deductions)	138,047	325,665	463,712
Interest expense	186,062	(231)	185,831
Other expenses	(25,970)	176	(25,794)
Income taxes	35,607	81,318	116,925
Preferred dividend requirements of subsidiaries and noncontrolling interests	9,462	—	9,462
2025 Net Income (Loss) Attributable to Entergy Corporation	$2,279,517	($521,245)	$1,758,272

(a)Parent & Other includes eliminations, which are primarily intersegment activity.

Results of operations for 2024 include: (1) a $320 million ($253 million net-of-tax) settlement charge, reflected in Parent & Other above, recognized as a result of a group annuity contract purchased in 2024 to settle certain pension liabilities; (2) expenses of $151 million ($112 million net-of-tax), recorded at Utility in second quarter 2024, primarily consisting of regulatory charges to reflect the effects of an agreement in principle between Entergy Louisiana and the LPSC staff and the intervenors in July 2024 to renew Entergy Louisiana’s formula rate plan and resolve a number of other retail dockets and matters, including all formula rate plan test years prior to 2023; (3) a $132 million ($97 million net-of-tax) charge, recorded at Utility, to reflect the write-off of a previously recorded regulatory asset as a result of an adverse decision in the Entergy Arkansas opportunity sales proceeding in March 2024; and (4) a $78 million ($57 million net-of-tax) regulatory charge, recorded at Utility in first quarter 2024, primarily to reflect a settlement in principle between Entergy New Orleans and the City Council in April 2024 for additional sharing with customers of income tax benefits from the resolution of the 2016-2018 IRS audit. See Note 11 to the financial statements for discussion of the group annuity contract and settlement charge. See Note 2 to the financial statements for discussion of the Entergy Louisiana agreement in principle and the subsequently filed global stipulated settlement agreement. See Note 2 to the financial statements for discussion of the Entergy Arkansas opportunity sales proceeding. See Note 3 to the financial statements for discussion of the Entergy New Orleans April 2024 settlement in principle and discussion of the resolution of the 2016-2018 IRS audit.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Operating Revenues

Utility

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


			Amount
			(In Millions)
2024 operating revenues			$11,806
Fuel, rider, and other revenues that do not significantly affect net income			620
Volume/weather			235
Retail electric price			164
Retail one-time bill credit			92
Return on construction work in progress for certain utility plant investments			48
Effect of sale of natural gas distribution businesses			(77)
2025 operating revenues			$12,888

The Utility operating companies’ results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.

The volume/weather variance is primarily due to an increase in industrial usage and the effect of more favorable weather on residential sales. The increase in industrial usage is primarily due to an increase in demand from large industrial customers, primarily in the primary metals, petroleum refining, chlor-alkali, and technology industries.

The retail electric price variance is primarily due to:

•an increase in Entergy Arkansas’s formula rate plan rates effective January 2025;

•a decrease in Entergy Louisiana’s formula rate plan revenues for a two month period beginning in September 2025, resulting from earnings above the authorized return on common equity for the 2024 test year, partially offset by increases in Entergy Louisiana’s formula rate plan revenues, including an increase in the distribution recovery mechanism, effective September 2024;

•increases in Entergy Mississippi’s formula rate plan rates effective April 2024 and July 2024 and an increase in Entergy Mississippi’s formula rate plan rates resulting from an increase in interim facilities rate adjustment revenues effective January 2025; and

•the implementation of the distribution cost recovery factor rider effective with the first billing cycle in October 2024 and increases in the distribution cost recovery factor rider effective in December 2024 and June 2025, each at Entergy Texas.

See Note 2 to the financial statements for further discussion of the regulatory proceedings discussed above.

The retail one-time bill credit variance represents the disbursement of settlement proceeds in the form of a one-time bill credit provided to Entergy Arkansas’s retail customers during the August 2024 billing cycle through the Grand Gulf credit rider as a result of the System Energy settlement with the APSC. There is no effect on net income because Entergy previously recorded a regulatory liability at the time of the global black box settlement reached between System Energy and the MPSC in June 2022. See Note 2 to the financial statements for discussion

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

of the System Energy settlements with the APSC and the MPSC and discussion of Entergy Arkansas’s Grand Gulf credit rider.

The return on construction work in progress for certain utility plant investments variance represents the revenue related to the amortization of certain customer advances designed to provide a return on investment in construction work in progress for certain utility plant investments, which is recognized as the related costs are incurred.

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

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


	2025	2024	% Change
	(GWh)
Residential	37,177	36,039	3
Commercial	28,463	28,251	1
Industrial	60,882	57,081	7
Governmental	2,438	2,480	(2)
Total retail	128,960	123,851	4
Sales for resale	12,997	14,010	(7)
Total	141,957	137,861	3

See Note 19 to the financial statements for additional discussion of operating revenues.

Other Income Statement Items

Utility

Purchased power includes an increase in 2025 of $34 million in costs, at Entergy Texas, related to the procurement of capacity through MISO’s annual planning resource auction, including the effect of a significant increase in MISO’s seasonal auction clearing price, due in part to the implementation of a reliability-based demand curve, for capacity transactions during the summer months. Although Entergy Texas does not have the ability to recover its MISO capacity costs incurred to date beyond the level included in base rates, in June 2025, Texas legislation established a capacity cost recovery rider mechanism that would allow for the recovery of costs related to the procurement of capacity through MISO’s annual planning resource auction outside of base rates, through a rider that is updated annually. Entergy Texas plans in second quarter 2026 to file for such a rider to recover future capacity procurement costs.

Other operation and maintenance expenses increased from $2,851 million for 2024 to $3,013 million for 2025 primarily due to:

•an increase of $76 million in power delivery expenses primarily due to higher vegetation maintenance costs;

•an increase of $33 million in loss provisions;

•an increase of $31 million in bad debt expense;

•an increase of $29 million in non-nuclear generation expenses primarily due to a higher scope of work performed during plant outages in 2025 as compared to 2024;

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

•an increase of $12 million in transmission costs allocated by MISO. See Note 2 to the financial statements for discussion of the recovery of these costs;

•the expensing of $11 million at Entergy Louisiana of project costs associated with the Bayou Power Station project following Entergy Louisiana’s election in third quarter 2025 to cancel the project and evaluate an alternative transmission solution. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources” below for discussion of Entergy Louisiana’s Bayou Power Station project; and

•several individually insignificant items.

The increase was partially offset by:

•contract costs of $47 million in 2024 related to operational performance, customer service, and organizational health initiatives;

•a $15 million gain resulting from the sale of the Entergy Louisiana and Entergy New Orleans natural gas distribution businesses on July 1, 2025, which included the derecognition of $7 million of goodwill attributed to the businesses sold; and

•a decrease of $11 million in gas operation expenses resulting from the absence of expenses following the sale of the Entergy Louisiana and Entergy New Orleans natural gas distribution businesses on July 1, 2025.

See Note 14 to the financial statements for discussion of the sale of the Entergy Louisiana and Entergy New Orleans natural gas distribution businesses on July 1, 2025.

Asset write-offs, impairments, and related charges (credits) includes:

•a $132 million charge, recorded in first quarter 2024 at Entergy Arkansas, to reflect the write-off of a previously recorded regulatory asset as a result of an adverse decision in the Entergy Arkansas opportunity sales proceeding in March 2024. See Note 2 to the financial statements for discussion of the Entergy Arkansas opportunity sales proceeding; and

•a $13 million charge, recorded in third quarter 2025 at Entergy New Orleans, to reflect the write-off of retained natural gas plant assets that were not included in the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025, and which will not be recovered. See Note 14 to the financial statements for discussion of the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025.

Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments and millage rate increases and increases in local franchise fees as a result of higher retail revenues in 2025 as compared to 2024.

Depreciation and amortization expenses increased primarily due to additions to plant in service and increases in nuclear depreciation rates at Entergy Louisiana effective September 2024 and September 2025 in accordance with the global stipulated settlement agreement approved by the LPSC in August 2024. The increase was partially offset by the recognition of $28 million in depreciation expense in 2024 at Entergy Texas for the 2022 base rate case relate back period, effective over six months beginning January 2024. The recognition of depreciation expense for the relate back period was effective over the same period as collections from the relate back surcharge rider and resulted in no effect on net income. See Note 2 to the financial statements for discussion of the Entergy Louisiana global stipulated settlement agreement. See Note 2 to the financial statements for discussion of the 2022 base rate case at Entergy Texas.

Other regulatory charges (credits) - net includes:

•the reversal in third quarter 2024 of a $92 million regulatory liability recognized for Entergy Arkansas’s obligation to return to customers the refund from the System Energy settlement with the APSC. The

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

reversal of the regulatory liability offsets a reduction in gross revenues from the retail one-time bill credits provided to customers in the August 2024 billing cycle through the Grand Gulf credit rider. See Note 2 to the financial statements for discussion of the System Energy settlement with the APSC and discussion of Entergy Arkansas’s Grand Gulf credit rider;

•a regulatory credit of $16 million, recorded by Entergy Arkansas in fourth quarter 2024, to reflect the amount of the 2023 historical year netting adjustment to be collected from its customers during the 2025 rate effective period as included in the 2024 formula rate plan filing. See Note 2 to the financial statements for discussion of the Entergy Arkansas 2024 formula rate plan filing;

•a regulatory credit of $28 million, recorded by Entergy Arkansas in fourth quarter 2025, to reflect the amount of the 2024 historical year netting adjustment to be collected from its customers during the 2026 rate effective period as included in the 2025 formula rate plan filing. See Note 2 to the financial statements for discussion of the Entergy Arkansas 2025 formula rate plan filing;

•regulatory charges of $150 million, recorded by Entergy Louisiana in second quarter 2024, to reflect the effects of an agreement in principle between Entergy Louisiana and the LPSC staff and the intervenors in July 2024 to renew Entergy Louisiana’s formula rate plan and resolve a number of other retail dockets and matters, including all formula rate plan test years prior to 2023. The customer rate credits agreed to in the global stipulated settlement began in September 2024. See Note 2 to the financial statements for discussion of the Entergy Louisiana agreement in principle and the subsequently filed global stipulated settlement agreement; and

•a regulatory charge of $78 million, recorded by Entergy New Orleans in first quarter 2024, primarily to reflect a settlement in principle between Entergy New Orleans and the City Council in April 2024 for additional sharing with customers of income tax benefits from the resolution of the 2016-2018 IRS audit. See Note 3 to the financial statements for discussion of the April 2024 settlement in principle and discussion of the resolution of the 2016-2018 IRS audit.

In addition, Entergy records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation-related costs collected in revenue.

Other income (deductions) increased primarily due to:

•an increase of $65 million in the amortization of tax gross ups on customer advances, including customer advances for construction;

•an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2025, including the Orange County Advanced Power Station project, the Legend Power Station project, and the Lone Star Power Station project, each at Entergy Texas;

•an increase of $22 million in interest earned on money pool investments; and

•a $17 million true-up of Entergy Louisiana’s MISO cost recovery mechanism over-recovery balance to the 2024 formula rate plan filing, which was filed with the LPSC in May 2025. See Note 2 to the financial statements for discussion of the 2024 formula rate plan filing.

The increase was partially offset by a decrease of $17 million in intercompany dividend income from affiliated preferred membership interests related to storm cost securitizations. The intercompany dividend income on the affiliated preferred membership interests is eliminated for consolidation purposes and has no effect on net income since the investment is in another Entergy subsidiary. See Note 2 to the financial statements for discussion of Entergy Louisiana’s storm cost securitizations.

Interest expense increased primarily due to:

•the issuance by Entergy Arkansas of $400 million of 5.45% Series mortgage bonds in May 2024 and an additional $300 million in a reopening of the same series in May 2025;

•the issuance by Entergy Louisiana of $700 million of 5.15% Series mortgage bonds in August 2024;

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

•the issuance by Entergy Louisiana of $750 million of 5.80% Series mortgage bonds in January 2025;

•the issuance by Entergy Mississippi of $600 million of 5.80% Series mortgage bonds in March 2025;

•the issuance by Entergy Texas of $350 million of 5.55% Series mortgage bonds in August 2024;

•the issuance by Entergy Texas of $500 million of 5.25% Series mortgage bonds in February 2025;

•the issuance by System Energy of $300 million of 5.30% Series mortgage bonds in December 2024 and an additional $240 million in a reopening of the same series in May 2025; and

•an increase of $51 million in carrying costs on customer advances, including customer advances for construction.

The increase was partially offset by an increase in the allowance for borrowed funds used during construction due to higher construction work in progress in 2025, including the Orange County Advanced Power Station project, the Legend Power Station project, and the Lone Star Power Station project, each at Entergy Texas.

See Note 5 to the financial statements for a discussion of long-term debt.

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

Parent and Other

Asset write-offs, impairments, and related charges (credits) includes the effects of recording a favorable final judgment of $20 million in fourth quarter 2024 to resolve claims in the Northstar Vermont Yankee, LLC (previously Entergy Nuclear Vermont Yankee) final round Vermont Yankee damages case against the DOE and the effects of recording a favorable final judgment of $7 million in fourth quarter 2024 to resolve claims in the Holtec Palisades, LLC (previously Entergy Nuclear Palisades) final round Palisades damages case against the DOE. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

Other income (deductions) increased primarily due to a $320 million ($253 million net-of-tax) non-cash settlement charge recognized as a result of a group annuity contract purchased in 2024 to settle certain pension liabilities. See Note 11 to the financial statements for discussion of the group annuity contract and settlement charge.

Income Taxes

The effective income tax rates were 21.9% for 2025 and 26.4% for 2024. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 18, 2025, for discussion of results of operations for 2024 compared to 2023.

Income Tax Legislation and Regulation

On July 4, 2025, the One Big Beautiful Bill Act (OBBBA) was enacted. The OBBBA is a wide ranging update to U.S. tax and spending policy. In particular, the OBBBA modified and extended various clean energy tax incentives relevant to electric utilities, preserving production tax credits under Internal Revenue Code section 45U for existing nuclear facilities through 2032 and generally maintaining the existing phase-out schedule for new nuclear and battery storage under Internal Revenue Code sections 45Y (clean electricity production credit) or Internal Revenue Code section 48E (clean electricity investment credit). In addition, the OBBBA preserved the tax

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

credits for carbon capture and sequestration facilities that meet the requirements of Internal Revenue Code section 45Q. The OBBBA also retained full transferability of all credits and preserved five-year modified accelerated cost recovery system treatment for eligible Internal Revenue Code section 45Y and 48E assets.

In contrast, the OBBBA significantly shortened the time period for solar and wind facilities to claim clean energy tax incentives. In general, solar and wind facilities must be placed in service by December 31, 2027 to qualify for the tax credits, unless construction begins by July 3, 2026, and certain safe harbor requirements are met.

In addition, the OBBBA adopted new foreign entity of concern (FEOC) rules designed to deny clean energy tax incentives to all clean energy projects beginning construction after December 31, 2025 that use equipment beyond statutory guidelines from prohibited foreign entities (entities with ties to China, Russia, Iran, or North Korea). The FEOC rules also deny these incentives to taxpayers that rely beyond certain thresholds on equity or debt held by or sold to specified foreign entities or that make payments to specified foreign entity counterparties under contracts or licensing agreements that give such counterparties “effective control” over an eligible project. These taxpayer FEOC rules will apply to taxpayers in their first taxable year following enactment of the OBBBA.

On July 7, 2025, an executive order was issued directing the U.S. Treasury to issue, among other things, new safe harbor guidance, particularly with respect to wind and solar facilities. On August 15, 2025, in response to the executive order, the U.S. Treasury released Notice 2025-42, which provides updated guidance regarding the beginning of construction requirements and termination of the wind and solar energy tax credits under sections 45Y and 48E. Notice 2025-42 provides additional guidance on these safe harbor provisions, clarifying the criteria for beginning construction and offering examples of equipment and contractual terms that will qualify a project for safe harbor treatment under the OBBBA. Notice 2025-42 states that the U.S. Treasury and the IRS are currently drafting additional guidance to address the FEOC rules.

The changes in law and federal energy policy reflected in the OBBBA could have a material effect on Entergy’s current and future resource planning, including particularly solar and wind resources, and on its results of operations, cash flows, or financial condition. Entergy may not be able to realize the anticipated benefits of federal tax credits for certain of its planned solar and battery facilities to the extent that these projects do not meet the safe harbor requirements set forth in the OBBBA. In addition, as the policy changes reflected in the OBBBA and anticipated related guidance disfavor certain renewable resource development as compared to prior law, Entergy may not be successful in achieving current or future carbon emission goals. Provisions of the OBBBA may also affect customer decisions relating to major new projects in Entergy’s service area, to the extent that project economics or the achievement of customer sustainability objectives are affected by the changes in the OBBBA.

The Inflation Reduction Act of 2022 (IRA), signed into law on August 16, 2022, significantly expanded federal tax incentives for clean energy production, including the extension of production tax credits to solar projects and certain qualified nuclear power facilities. Additionally, the IRA enacted a 1% excise tax on the buyback of public company stock and a new corporate alternative minimum tax (CAMT). Effective for tax years beginning after December 31, 2022, the CAMT imposes a 15% tax on the Adjusted Financial Statement Income (AFSI) on each corporation in a group of corporations that averages greater than $1 billion in AFSI over a three-year period. Taxpayers subject to the CAMT regime must pay the greater of 15% of AFSI or their regular federal tax liability. In September 2024 the IRS issued proposed regulations regarding the application of the CAMT. Entergy and the Registrant Subsidiaries are closely monitoring any potential impact associated with the expansion of federal tax incentives, the 1% excise tax, and CAMT. Based on current IRS guidance and internal forecasts, Entergy and the Registrant Subsidiaries may become subject to the CAMT beginning in the next one to three years. The U.S. Treasury is expected to issue further guidance that will clarify how the tax credit provisions and CAMT provisions will be interpreted and applied. This guidance will determine the amount of tax credits and incremental cash tax payments Entergy expects in the future as a result of the legislation. Prior to receiving this guidance, Entergy cannot adequately assess the expected future effects on its results of operations, financial position, and cash flows. Entergy is not able to predict the effects of any change to or repeal of the above tax legislation, including any

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

federal tax incentives or tax credits, on its or the Registrant Subsidiaries’ results of operations, financial position, and cash flows.

In April 2023 the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized and provides procedures for taxpayers to obtain automatic consent to change their method of accounting. Entergy adopted this new method of income tax accounting beginning with the 2023 federal income tax return utilizing the safe harbor method in accordance with Revenue Procedure 2023-15. The additional temporary deductions taken using the new method resulted in the recognition of deferred tax liabilities of $14.2 million for Entergy, $7.6 million for Entergy Louisiana, and $6.6 million for Entergy New Orleans in 2024.

Liquidity and Capital Resources

This section discusses Entergy’s capital structure, capital spending plans and other uses of capital, sources of capital, and the cash flow activity presented in the cash flow statement.

Recent announcements of changes to international trade policy and tariffs and further similar changes may impact Entergy’s business, operations, results of operations, and liquidity and capital resources. Potential impacts may include increases in costs associated with Entergy’s capital investments or operation and maintenance expenses; operational impacts, such as supply chain, manufacturing, cost and availability of qualified, skilled labor, or raw materials sourcing disruptions which may affect Entergy’s ability to make planned capital investments as and when expected and needed; legal uncertainties, such as potential legal or other challenges to presidential tariff authority; or broader economic risks, including changes to domestic monetary policy, shifting customer demand, impacts on customer investment decisions, and volatile or uncertain credit and capital markets, which may affect Entergy’s ability to access needed capital. The nature and extent of any such effects will depend on, among other things, the specifics of the changes that are ultimately implemented both domestically and internationally, the responses of vendors, suppliers, and other counterparties to those changes, indirect effects on the price and availability of non-tariffed goods, and the effectiveness of mitigation measures.

The Registrant Subsidiaries have incurred incremental cost increases due to certain tariff-exposed inputs, including select equipment, components, or underlying raw materials. As of the date of this Form 10-K, such increases have not had a material effect on such Registrant Subsidiaries' capital spending plans. Entergy is not able to predict any further effects of such tariffs or the effects of potential changes in regulation and law, changes to governmental programs, such as loans, grants, guarantees, and other subsidies, and trade-related governmental actions, such as tariffs and other measures, on such capital spending plans.

Capital Structure

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


	December 31, 2025	December 31, 2024
Debt to capital	64.3%	65.3%
Effect of excluding securitization bonds	(0.2%)	(0.2%)
Debt to capital, excluding securitization bonds (non-GAAP) (a)	64.1%	65.1%
Effect of subtracting cash	(1.5%)	(0.7%)
Net debt to net capital, excluding securitization bonds (non-GAAP) (a)	62.6%	64.4%

(a)Calculation excludes the Texas securitization bonds, which are non-recourse to Entergy Texas.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

As of December 31, 2025, 20.4% of the debt outstanding is at the parent company, Entergy Corporation, and 79.6% is at the Utility segment. Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable and commercial paper, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt, equity, and subsidiaries’ preferred stock without sinking fund. Net capital consists of capital less cash and cash equivalents. The debt to capital ratio excluding securitization bonds and net debt to net capital ratio excluding securitization bonds are non-GAAP measures. Entergy uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy’s financial condition because the securitization bonds are non-recourse to Entergy, as more fully described in Note 5 to the financial statements. Entergy also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy’s financial condition because net debt indicates Entergy’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

The Utility operating companies and System Energy seek to optimize their capital structures in accordance with regulatory requirements and to control their cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that their operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend to their parent, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that their operating cash flows are insufficient to support planned investments, the Utility operating companies and System Energy may issue incremental debt or reduce dividends, or both, to maintain their capital structures. In addition, Entergy may make equity contributions to the Utility operating companies and System Energy to maintain their capital structures in certain circumstances such as financing of large transactions or payments that would materially alter the capital structure if financed entirely with debt and reduced dividends.

Long-term debt, including the currently maturing portion, makes up most of Entergy’s total debt outstanding. Following are Entergy’s long-term debt principal maturities and estimated interest payments as of December 31, 2025. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2025. The amounts below include payments on System Energy’s Grand Gulf sale-leaseback transaction, which are included in long-term debt on the balance sheet.


Long-term debt maturities and estimated interest payments	2026	2027	2028	2029-2030	after 2030
	(In Millions)
Utility	$2,670	$2,068	$2,426	$2,238	$33,106
Parent & Other	996	231	873	1,027	8,219
Total	$3,666	$2,299	$3,299	$3,265	$41,325

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

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Entergy Corporation has in place a credit facility that has a borrowing capacity of $3 billion and expires in June 2030. The facility includes fronting commitments for the issuance of letters of credit against $20 million of the total borrowing capacity of the credit facility. The commitment fee is currently 0.225% of the undrawn commitment amount. Commitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior unsecured debt ratings of Entergy Corporation. Although there were no borrowings under the facility for the year ended December 31, 2025, the estimated interest rate for the year ended December 31, 2025 that would have been applied to outstanding borrowings under the facility was 5.32%. The following is a summary of the amounts outstanding and capacity available under the credit facility as of December 31, 2025:


Capacity	Borrowings	Letters of Credit	Capacity Available
(In Millions)
$3,000	$—	$3	$2,997

Entergy Corporation’s credit facility includes a covenant requiring Entergy to maintain a consolidated debt ratio, as defined, of 65% or less of its total capitalization. The calculation of this debt ratio under Entergy Corporation’s credit facility is different than the calculation of the debt to capital ratio above. Entergy is currently in compliance with the covenant and expects to remain in compliance with this covenant. If Entergy fails to meet this ratio, or if Entergy Corporation or one of the Registrant Subsidiaries (except Entergy New Orleans and System Energy) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the Entergy Corporation credit facility’s maturity date may occur. See Note 4 to the financial statements for additional discussion of the Entergy Corporation credit facility and discussion of the Registrant Subsidiaries’ credit facilities.

Entergy Corporation has a commercial paper program with a Board-approved program limit of $2 billion. As of December 31, 2025, Entergy Corporation had $637.8 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2025 was 4.58%.

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2025 as follows:


Company	Expiration Date	Amount of Facility	Interest Rate (a)	Amount Drawn as of December 31, 2025	Letters of Credit Outstanding as of December 31, 2025
Entergy Arkansas	April 2026	$25 million (b)	5.67%	—	—
Entergy Arkansas	June 2030	$300 million (c)	4.94%	—	—
Entergy Louisiana	June 2030	$400 million (c)	5.07%	—	—
Entergy Mississippi	June 2030	$300 million (c)	4.94%	—	—
Entergy New Orleans	June 2027	$25 million (c)	5.44%	—	—
Entergy Texas	June 2030	$300 million (c)	5.07%	—	$1.1 million

(a)The interest rate is the estimated interest rate as of December 31, 2025 that would have been applied to outstanding borrowings under the facility.

(b)Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable at Entergy Arkansas’s option.

(c)The credit facility includes fronting commitments for the issuance of letters of credit against a portion of the borrowing capacity of the facility as follows: $5 million for Entergy Arkansas; $15 million for Entergy Louisiana; $5 million for Entergy Mississippi; $10 million for Entergy New Orleans; and $25 million for Entergy Texas.

Each of the credit facilities requires the Registrant Subsidiary borrower to maintain a debt ratio, as defined, of 65% or less of its total capitalization. Each Registrant Subsidiary is in compliance with this covenant.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

In addition, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each has one or more uncommitted standby letter of credit facilities as a means to post collateral to support their obligations to MISO and for other purposes. The following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2025:

Company

Amount of Uncommitted Facility

Letter of Credit Fee

Letters of Credit Issued as of December 31, 2025

(a)

Entergy Arkansas

$25 million

0.78%

$18.3 million

Entergy Arkansas

$75 million

0.50%

$75.0 million

Entergy Louisiana

$125 million

0.78%

$119.1 million

Entergy Louisiana

$45 million

0.50%

$45.0 million

Entergy Mississippi

$65 million

0.78%

$44.4 million (b)

Entergy Mississippi

$65 million

0.50%

$43.0 million

Entergy New Orleans

$1 million

1.625%

$0.5 million

Entergy Texas

$150 million

1.250%

$59.6 million

Entergy Texas

$160 million

1.05%

$—

(a)As of December 31, 2025, letters of credit posted with MISO covered financial transmission rights exposure of $0.1 million for Entergy Arkansas, $0.8 million for Entergy Louisiana, $0.8 million for Entergy Mississippi, and $0.1 million for Entergy Texas. See Note 15 to the financial statements for discussion of financial transmission rights.

(b)As of December 31, 2025, the letters of credit issued for Entergy Mississippi under this facility include $43.1 million in MISO letters of credit and $1.3 million in non-MISO letters of credit outstanding.

Finance lease obligations are a minimal part of Entergy’s overall capital structure. Following are Entergy’s payment obligations under those leases.


	2026	2027	2028	2029-2030	after 2030
	(In Millions)
Finance lease payments	$25	$23	$20	$28	$53

Finance leases are discussed in Note 10 to the financial statements.

Operating Lease Obligations and Guarantees of Unconsolidated Obligations

Entergy has a minimal amount of operating lease obligations and guarantees in support of unconsolidated obligations. Entergy’s guarantees in support of unconsolidated obligations are not likely to have a material effect on Entergy’s financial condition, results of operations, or cash flows. Following are Entergy’s payment obligations as of December 31, 2025 on non-cancelable operating leases with a term over one year:


	2026	2027	2028	2029-2030	after 2030
	(In Millions)
Operating lease payments	$78	$66	$54	$63	$52

Operating leases are discussed in Note 10 to the financial statements.

Other Obligations

Entergy currently expects to contribute approximately $200 million to its qualified pension plans and approximately $40.9 million to its other postretirement plans in 2026, although the 2026 required pension contributions will be known with more certainty when the January 1, 2026 valuations are completed, which is

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

expected by April 1, 2026. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Entergy has $808 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

See below for discussion of the Entergy Texas build-to-suit lease arrangement for the Legend Power Station.

In addition, the Registrant Subsidiaries enter into fuel and purchased power agreements that contain minimum purchase obligations. The Registrant Subsidiaries each have rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations.

Capital Expenditure Plans and Other Uses of Capital

Following are the amounts of Entergy’s planned construction and other capital investments for 2026 through 2029.


Planned construction and capital investments	2026	2027	2028	2029
	(In Millions)
Generation	$6,350	$8,010	$6,330	$4,215
Transmission	2,380	2,605	2,325	1,885
Distribution	2,555	2,055	1,710	1,845
Utility Support	330	295	290	290
Total	$11,615	$12,965	$10,655	$8,235

Planned construction and capital investments refer to amounts Entergy plans to spend on routine capital projects that are necessary to support reliability of its service, equipment, or systems and to support normal customer growth. In addition to routine capital projects, they also refer to amounts Entergy plans to spend on non-routine capital investments for which Entergy is either contractually obligated, has Board approval, or otherwise expects to make to satisfy regulatory or legal requirements. Amounts include the following types of construction and capital investments:

•investments in generation projects to modernize, decarbonize, expand, and diversify the Utility operating companies’ portfolios, as well as to support customer growth, including Ironwood Power Station (formerly Lake Catherine Unit 5), Jefferson Power Station, Arkansas Cypress Solar, Segno Solar, Votaw Solar, Bogalusa West Solar, Cypress Harvest Solar, Franklin Farms Power Station Units 1 and 2, Waterford 5 Power Station, Cottonwood Power Station, Westlake Power Station, Delta Blues Advanced Power Station, Delta Solar, Penton Solar, Traceview Advanced Power Station, Vicksburg Advanced Power Station, Orange County Advanced Power Station, Lone Star Power Station, Legend Power Station, and potential construction of additional generation;

•investments in the Utility nuclear fleet;

•transmission spending to improve reliability and resilience while also supporting renewables expansion and customer growth; and

•distribution and Utility support spending to improve reliability, resilience, and customer experience through projects focused on asset renewals and enhancements and grid stability.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

The Utility’s owned and contracted generating capacity is planned on a long-term basis with an aim to enable the Utility operating companies to meet MISO target reserve requirements; however, MISO has implemented changes to its resource adequacy construct that generally move from an annual to a seasonal design and that changes the way that resources are assigned capacity credit. MISO has also recently obtained FERC approval to implement additional changes that further affect the assignment of capacity credit to resources. As a result of these changes, there may be seasonal variations in the capacity credit afforded to the Utility operating companies’ resources by MISO, and some resource types generally may be assigned less capacity credit than they have historically. MISO continues to pursue market design changes related to its resource adequacy construct. The FERC recently approved a reliability-based demand curve that, along with a tighter balance of supply and demand, has had the effect of increasing the clearing prices in the MISO planning resource auction. MISO has also received approval from the FERC for changes to the market rules governing load modifying resources, which could affect the accreditation of these resources and, as a result, the capacity positions of the Utility operating companies. These market design changes may have an effect on both the Utility operating companies’ liquidity and the capital investment needed for long-term resources. Entergy is monitoring the evolution and application of these rules, which may require the Utility operating companies to procure additional capacity credits from the MISO market and in the longer-term may impact the incremental additional supply resources needed. The Utility’s supply plan initiative will continue to seek to transform its generation portfolio with new generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of business restructuring, regulatory constraints and requirements, governmental actions, including trade-related governmental actions, such as tariffs and other measures, environmental regulations, business opportunities, market volatility, economic trends, changes in project plans, and the ability to access capital, including any changes to governmental programs, such as loans, grants, guarantees, and other subsidies. Entergy is not able to predict the effect of potential changes in regulation and law, changes to governmental programs, such as loans, grants, guarantees, and other subsidies, and trade-related governmental actions, such as tariffs and other measures, on its current and planned capital projects.

Renewables

Entergy Arkansas Special Rate Contract and Arkansas Cypress Solar

In September 2025, Entergy Arkansas filed an application with the APSC seeking approval of a long-term special rate contract between Altitude, LLC, a subsidiary of Alphabet, Inc. (Google) and Entergy Arkansas for the sale of electricity to a new large-scale data center in West Memphis, Arkansas. In October 2025 the APSC general staff filed testimony finding that based on its evaluation of Entergy Arkansas’s application and the results of the ratepayer impact measure test, the special rate contract meets the requirements of the APSC’s promotional practice rules and is in the public interest. No other parties filed testimony. In December 2025 the APSC issued an order approving the special rate contract but denying the requested ratemaking treatment of Google’s upfront payments and deferring a decision on the treatment under the contract pricing providing for the deferral and amortization of the investment tax credits from the Arkansas Cypress Solar facility (discussed below). Also in December 2025, Entergy Arkansas filed a petition with the APSC regarding these findings, noting that they would require renegotiation of the special rate contract. In January 2026 the APSC issued an order maintaining its position on the ratemaking treatment of Google’s upfront payments but reversing itself on the treatment of the Arkansas Cypress Solar facility investment tax credits and allowing those to be used in the pricing of the Arkansas Cypress Solar facility to Google as provided for in the contract.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

support of its long-term special rate contract with Google. In October 2025 the APSC general staff and the Arkansas Attorney General filed responsive testimony opposing the project cost and seeking additional information. Subsequently, the APSC general staff submitted supplemental testimony to update its initial conclusion and recommendations, noting that the Arkansas Cypress Solar facility is a reasonable project and recommending the APSC approve the project under certain conditions. Entergy Arkansas proposes to recover the costs of constructing the Arkansas Cypress Solar facility through the Generating Arkansas Jobs Act rider. A hearing was held in December 2025, and an APSC decision is due in March 2026. Subject to receipt of required regulatory approval and other conditions, the facility is expected to be in service by the end of 2028. See “Retail Rate Proceedings – Filings with the APSC (Entergy Arkansas) – Retail Rates - Generating Arkansas Jobs Act Rider” in Note 2 to the financial statements for discussion of the Generating Jobs Act rider, which was approved by the APSC in October 2025.

Bogalusa West Solar

In July 2025, Entergy Louisiana filed an application seeking LPSC approval and certification of the Bogalusa West Solar facility, a 200 MW single axis tracking solar photovoltaic power facility in Washington Parish, Louisiana. In October 2025 the LPSC voted to grant Entergy Louisiana’s application and approve the Bogalusa West Solar facility. The facility is expected to be in service by 2028.

Cypress Harvest Solar

In February 2026, Entergy Louisiana filed an application seeking LPSC approval and certification for the Cypress Harvest Solar facility, a 200 MW solar facility to be located in Iberville Parish. Entergy Louisiana requested that the LPSC consider the request at its April 2026 meeting.

Delta Solar

In December 2024 the Bolivar County Board of Supervisors approved Entergy Mississippi’s plans to construct, own, and operate the Delta Solar facility, an 80 MW solar facility to be located in Bolivar County, Mississippi. The Delta Solar facility is estimated to cost $157.2 million, inclusive of estimated transmission interconnection costs. Construction of the Delta Solar facility qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. The project costs will be reviewed for prudence by the MPSC following the completion of construction. Construction is in progress, and the Delta Solar facility is expected to be in service by the end of 2027.

Penton Solar

In May 2025 the DeSoto County Board of Supervisors approved Entergy Mississippi’s plans to construct, own, and operate the Penton Solar facility, a 190 MW solar facility to be located in DeSoto County, Mississippi. The Penton Solar facility is estimated to cost $327.2 million, inclusive of estimated transmission interconnection and upgrade costs. Construction of the Penton Solar facility qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. The project costs will be reviewed for prudence by the MPSC following the completion of construction. Construction is in progress, and the Penton Solar facility is expected to be in service by early 2028.

Segno Solar and Votaw Solar

In July 2024, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Segno Solar facility, a 170 MW solar facility to be located in Polk County, Texas, and the Votaw Solar facility, a 141 MW solar facility to be located in

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Hardin County, Texas. In August 2025, Entergy Texas filed, and the ALJs with the State Office of Administrative Hearings granted, an unopposed motion to withdraw the application. In September 2025, Entergy Texas and Entergy Louisiana entered into assignment and assumption agreements pursuant to which Entergy Texas assigned, and Entergy Louisiana assumed, certain interests in the Segno Solar and Votaw Solar facilities, and the associated assets were transferred in third quarter 2025 from Entergy Texas to Entergy Louisiana for approximately $42.1 million, which included adjustments per the assignment and assumption agreements.

In December 2025, Entergy Louisiana filed an application with the LPSC seeking approval and certification to construct the Segno Solar facility and Votaw Solar facility. The application asks that the LPSC approve, subject to certain ongoing discussions, allocation of the two facilities to a designated renewable resources subscription to Entergy Louisiana’s Rider Geaux Zero, and further asserts that the two solar resources fall below certain breakeven parameters established in connection with the LPSC’s order allowing Entergy Louisiana to procure up to 3 GW of solar resources, thus supporting that the resources should be certified as being in the public interest. The application requests consideration by the LPSC at or before its August 2026 meeting. A procedural schedule has been set with a hearing scheduled for July 2026. The Segno Solar facility and the Votaw Solar facility are expected to be in service by 2029.

Other Generation and Transmission

Ironwood Power Station

In November 2024, Entergy Arkansas filed an application with the APSC seeking a certificate of environmental compatibility and public need for the construction and operation of Ironwood Power Station (formerly Lake Catherine Unit 5), a 446 MW simple cycle natural gas combustion turbine facility to be located at the existing Lake Catherine facility site in Hot Spring County, Arkansas. The facility will primarily be powered by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. In December 2024 other parties, including the APSC general staff, filed testimony opposing the resource, although the APSC general staff recognized the capacity need for the resource. Entergy Arkansas filed testimony in January 2025 further supporting its application, and in February 2025 the opposing parties filed responsive rebuttal testimony continuing to dispute the estimated costs and to dispute that Entergy Arkansas performed a market solicitation sufficient to demonstrate that this resource is the most reasonable option for customers. Also in February 2025, Entergy Arkansas filed surrebuttal testimony responding to the opposing parties’ testimony. A hearing was held in March 2025, and in April 2025 the APSC issued an order approving certification of the facility. The order also provided a presumption of prudence finding with respect to a benchmark project cost. In May 2025, Entergy Arkansas filed a motion for clarification concerning the appropriate calculation of the benchmark that was below the estimated cost of Ironwood Power Station and was based upon older technology and dated pricing. Entergy Arkansas will have the opportunity to present later all actual costs to the APSC for review and a prudence determination of final costs, including costs incremental to the benchmark. In June 2025, Entergy Arkansas filed its independent monitor proposal with the APSC and is awaiting direction on the proposal and the motion for clarification. Entergy Arkansas proposes to recover the costs of constructing Ironwood Power Station through the Generating Arkansas Jobs Act rider. The facility is expected to be in service by the end of 2028. See “Retail Rate Proceedings – Filings with the APSC (Entergy Arkansas) – Retail Rates - Generating Arkansas Jobs Act Rider” in Note 2 to the financial statements for discussion of the Generating Jobs Act rider, which was approved by the APSC in October 2025.

Jefferson Power Station

In August 2025, Entergy Arkansas filed an application with the APSC seeking a certificate of environmental compatibility and public need for the construction and operation of Jefferson Power Station, an approximately 754 MW natural gas-fired combined cycle combustion turbine facility to be located in Jefferson County, Arkansas. The facility will primarily be powered by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The estimated cost of the project is $1,602

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

million. In September 2025 other parties, including the APSC general staff, filed testimony opposing the resource pending further information, although the APSC general staff recognized the capacity need for the resource and that Entergy Arkansas had satisfied the statutory requirements for a certificate of environmental compatibility and public need. Much of the opposition focused on the fact that the resource was not identified through a competitive solicitation. Entergy Arkansas filed testimony further supporting its application in September and October 2025. A hearing was held in October 2025 and November 2025. In January 2026 the APSC issued its order finding that Entergy Arkansas had demonstrated a need for the resource but had not met its burden with respect to supporting the prudence of the costs to construct the resource. The APSC acknowledged that the costs would be greater if Entergy Arkansas waited to pursue the resource. The APSC authorized Entergy Arkansas to proceed with Jefferson Power Station as a strategic investment with estimated costs set at a benchmark, which the APSC erroneously believed reflected the current cost estimate but is, in fact, $90 million below the cost presented. Entergy Arkansas is evaluating whether to make a request for rehearing to correct the benchmark. Additionally, the APSC found that Entergy Arkansas should conduct all-source competitive solicitations moving forward with a limited exception for certain resources associated with customer growth projects. Entergy Arkansas proposes to recover the costs of constructing Jefferson Power Station through the Generating Arkansas Jobs Act rider. Subject to receipt of required regulatory approval and other conditions, the facility is expected to be in service by the end of 2029. See “Retail Rate Proceedings – Filings with the APSC (Entergy Arkansas) – Retail Rates - Generating Arkansas Jobs Act Rider” in Note 2 to the financial statements for discussion of the Generating Jobs Act rider, which was approved by the APSC in October 2025.

Bayou Power Station

In March 2024, Entergy Louisiana filed an application seeking LPSC approval and certification that the public convenience and necessity would be served by the construction of the Bayou Power Station, a 112 MW aggregated capacity floating natural gas power station with black-start capability in Leeville, Louisiana and an associated microgrid that would serve nearby areas, including Port Fourchon, Golden Meadow, Leeville, and Grand Isle. In its application, Entergy Louisiana noted that the estimated cost of the Bayou Power Station was $411 million, including estimated costs of transmission interconnection and other related costs. In October 2024, Entergy Louisiana filed a motion to suspend the procedural schedule in this proceeding in order to evaluate certain recent developments related to the project including potential changes to the estimated cost of the project. In October 2025, Entergy Louisiana filed with the LPSC a motion to dismiss its application without prejudice, noting that this project has been canceled and that Entergy Louisiana is evaluating an alternative transmission solution. In November 2025 the LPSC granted the motion and dismissed the application, without prejudice. In third quarter 2025, Entergy Louisiana expensed $10.8 million of project costs related to the Bayou Power Station project.

Entergy Louisiana Additional Generation and Transmission Resources

In October 2024, Entergy Louisiana filed an application with the LPSC seeking approval of a variety of generation and transmission resources proposed in connection with establishing service to a new data center to be developed by a subsidiary of Meta Platforms, Inc. in north Louisiana, for which an electric service agreement has been executed. The filing requested LPSC certification of three new combined cycle combustion turbine generation resources totaling 2,262 MW, each of which will be enabled for future carbon capture and storage, a new 500 kV transmission line, and 500 kV substation upgrades. Two of the new combined cycle combustion turbine generation resources are to be located at Franklin Farms in north Louisiana (Franklin Farms Power Station Units 1 and 2). The application also requested approval to implement a corporate sustainability rider applicable to the new customer. The corporate sustainability rider contemplates the new customer contributing to the costs of the future addition of 1,500 MW of new solar and energy storage resources, agreements involving carbon capture and storage at Entergy Louisiana’s existing Lake Charles Power Station, and potential future wind and nuclear resources. The combined cost of Franklin Farms Power Station Units 1 and 2 is estimated to be approximately $2,387 million. In testimony filed with its application, Entergy Louisiana noted that the third new generation resource, Waterford 5 Power Station, is expected to have an estimated cost similar to the cost of each of Franklin Farms Power Station Units 1 and 2. Also in its testimony, Entergy Louisiana noted that the cost of the new 500 kV transmission line is estimated

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

to be $546 million. Entergy Louisiana anticipates funding the incremental cost to serve the customer through direct financial contributions from the customer and the revenues it expects to earn under the electric service agreement. The electric service agreement also contains provisions for termination payments that will help ensure that there is no harm to Entergy Louisiana and its customers in the event of early termination. A directive was issued at the LPSC’s November 2024 meeting for the matter to be decided by October 2025. In February 2025 intervenors filed a motion asking the LPSC to deny Entergy Louisiana’s requested exemption from the LPSC’s order addressing competitive solicitation procedures and further asking the LPSC to dismiss the application. The ALJ issued an order denying the motion to dismiss the application and deferring the LPSC’s consideration of the motion regarding the competitive solicitation procedures until the hearing. In March 2025 the same intervenors filed a motion requesting the LPSC to require the customer and its parent company to be joined as parties to the proceeding or dismiss the application. In April 2025 the ALJ issued an order denying the March 2025 motion, and the moving parties filed a motion asking the LPSC to review and reverse the ALJ’s decision.

In February 2025, Entergy Louisiana filed supplemental testimony with the LPSC stating that the third combined cycle combustion turbine resource presented in the October 2024 application (Waterford 5 Power Station) would be sited at Entergy Louisiana’s Waterford site in Killona, Louisiana, alongside existing Entergy Louisiana generation resources. The testimony also notes that Entergy Louisiana is negotiating with the customer in response to the customer’s request to increase the load associated with its project in north Louisiana. The testimony indicates further that the additional load can be served without additional generation capacity beyond what was presented in the October 2024 application, but that additional transmission facilities, which will be funded directly by the customer, are needed to serve this additional load.

In April 2025 and May 2025 the LPSC staff and certain intervenors each filed their direct testimony and cross-answering testimony, respectively. The LPSC staff’s testimony discussed the significant projected benefits associated with the data center project; however, both the LPSC staff and such intervenors also identified purported risks associated with constructing the requested resources based on the terms and conditions under which the customer would be taking service. Both the LPSC staff and such intervenors also recommended that the LPSC impose certain conditions on its approval which, if adopted, would support approval of Entergy Louisiana’s application. The LPSC staff’s recommendations included a condition that would require, under specified circumstances, certain sharing of net revenues from service to the project with Entergy Louisiana’s other customers. The LPSC staff also recommended that the LPSC deny approval of the corporate sustainability rider terms providing for the customer to supply funding toward the cost of installing carbon capture and storage infrastructure at Entergy Louisiana’s Lake Charles Power Station. The Louisiana Energy Users Group and other intervenors recommended that the LPSC require various changes to the terms of the electric service agreement with the customer that would shift additional risk and cost to the customer rather than Entergy Louisiana’s broader customer base. Certain intervenors also challenged approval on the basis that Entergy Louisiana did not conduct a request for proposals to procure the proposed generation resources to serve the customer’s project; these intervenors also advocated that Entergy Louisiana be required to procure more renewable generation and evaluate transmission alternatives rather than proceeding with development of all of the proposed new generation resources. In May 2025, Entergy Louisiana filed its rebuttal testimony responding to the direct and cross-answering testimony of the LPSC staff and intervenors. The rebuttal testimony expressed support for or no opposition to the LPSC’s adoption of certain of the proposed recommendations and identified why other proposed recommendations should not be adopted. In addition, the rebuttal testimony stated that the negotiations related to the increase in the load amount for the customer’s project had concluded and that a rider to the electric service agreement reflecting this increase had been executed. In advance of the July 2025 hearing, Entergy Louisiana reached a settlement agreement with the LPSC staff and three separate intervenors. In August 2025 the LPSC issued an order accepting the settlement agreement. Franklin Farms Power Station Units 1 and 2 are expected to be in service in 2028, and Waterford 5 Power Station is expected to be in service in 2029. In January 2026, several months after the LPSC order became final, certain intervenors filed a motion asking the LPSC to investigate the financing arrangements that the customer implemented for its data center project and to initiate a prudence review. The motion questions whether the credit protections for the customer’s obligations under the electric service agreement are adversely affected by the change in the customer’s financial structure and asks the LPSC to initiate a review of whether Entergy Louisiana withheld

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

relevant information from the LPSC at the time of the LPSC’s order. Entergy Louisiana filed its opposition to the motion in February 2026.

Amite South Transmission Projects

In March 2024, Entergy Louisiana filed an application seeking an exemption determination, or alternatively, a certificate of public convenience and necessity, for a transmission project that includes a new 500 kV/230 kV Commodore substation and an approximately 60-mile 230 kV line connecting the new Commodore substation to the Waterford substation. The project, which was approved by MISO in the 2023 MISO Transmission Expansion Plan, also includes certain common elements with, and right-of-way acquisition for, a future transmission project in the same area consisting of 500 kV elements. The estimated cost of the project is $498.8 million. In February 2025, Entergy Louisiana and the LPSC staff jointly filed, for consideration by the LPSC, an uncontested stipulated settlement agreement resolving all issues in the proceeding. In the motion requesting approval of the uncontested stipulated settlement agreement, the parties requested a settlement hearing in March 2025. The LPSC approved the uncontested stipulated settlement agreement in March 2025 and thereby granted certification of the project.

In December 2024, Entergy Louisiana filed an application with the LPSC seeking a certificate of public convenience and necessity for a 500 kV transmission project that includes the construction of a new 84-mile Commodore to Churchill 500 kV transmission line, the expansion of the Waterford 500 kV substation, the construction of a new Churchill 500 kV substation and improvements to the Churchill 230 kV substation, and the conversion of the existing 230 kV Waterford to Churchill transmission line to 500 kV, forming a 500 kV loop into the Downstream of Gypsy load pocket. The project, which was approved by MISO in the 2023 MISO Transmission Expansion Plan, shares common elements with a future transmission project in the same area consisting of 230 kV elements. The estimated cost of the project is $954.7 million. In April 2025 the LPSC staff and the Louisiana Energy Users Group, an intervenor, filed direct testimony. The LPSC staff’s testimony recommends LPSC approval of the project. The Louisiana Energy Users Group’s testimony opines that Entergy Louisiana has shown that there is a need for additional transmission investment in the West Bank area of Amite South but recommends that the LPSC withhold approval pending further analysis, including analysis of potential lower cost alternatives to the proposed project, and also pending Entergy Louisiana demonstrating that it has contributions in aid of construction from the customers whose block load additions would be enabled by the proposed transmission project in amounts sufficient to substantially, if not fully, cover the revenue requirement of the proposed project. In June 2025, Entergy Louisiana filed rebuttal testimony. A hearing was held in August 2025. In November 2025 the presiding ALJ issued a proposed recommendation granting the application and the requested certification. The Louisiana Energy Users Group filed exceptions to the proposed recommendation, and the LPSC staff and Entergy Louisiana filed responses in opposition to those exceptions. In December 2025 the ALJ issued a final recommendation granting the application and the requested certification. In December 2025 the LPSC issued an order adopting the final recommendation granting the application and the requested certification.

Cottonwood Power Station

In December 2025, Entergy Louisiana filed an application seeking LPSC approval and a certificate of convenience and necessity to acquire the Cottonwood combined cycle combustion turbine facility, a 1,263 MW combined cycle facility in Deweyville, Texas that was originally placed in commercial service in 2003. The filing seeks findings from the LPSC that the costs of the acquisition, including the approximately $1.5 billion purchase price and $309.3 million in capital upgrades and maintenance items needed to bring Cottonwood into alignment with Entergy Louisiana’s fleet standards with respect to operations and safety, are eligible for recovery in customer rates. The application requests an LPSC decision by October 2026. A procedural schedule has been set with a hearing scheduled for September 2026. The acquisition is currently targeted to occur in January 2027.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Babel - Webre 500 kV Transmission Project

In December 2025, Entergy Louisiana filed an application with the LPSC seeking a certificate of public convenience and necessity for a 500 kV transmission project that includes the construction of a new 147-mile Babel to Webre 500 kV transmission line, the reconstruction of the Webre 500 kV switching station in Louisiana, and coordination with Entergy Texas of the construction of an approximately 4-mile 500 kV transmission line in Texas. The project was approved by MISO in the 2025 MISO Transmission Expansion Plan and has an estimated cost of $1,238 million and an estimated in-service date of August 2029. The application requests an LPSC decision by June 2026.

Waterford 6 Power Station and Westlake Power Station

In February 2026, Entergy Louisiana filed an application seeking LPSC approval and certification to construct two 754 MW combined cycle combustion turbine generators, the Waterford 6 Power Station and the Westlake Power Station, to be located at Entergy Louisiana’s existing Waterford site near Killona, Louisiana and existing Roy S. Nelson site in Westlake, Louisiana, respectively. In its application, Entergy Louisiana noted the estimated costs are approximately $2,027 million for the Waterford 6 Power Station and $2,091 million for the Westlake Power Station. Entergy Louisiana asked that the LPSC consider the requests in the application at or before its December 2026 meeting. The estimated in-service dates for the Waterford 6 Power Station and Westlake Power Station are July 2030 and October 2030, respectively.

Entergy Mississippi Additional Generation and Transmission Resources

In March 2024, Entergy Mississippi executed a large customer supply and service agreement to serve two data center campuses located in Madison County, Mississippi in which Amazon Web Services is investing. In February 2025, Entergy Mississippi also executed a large customer supply and service agreement to serve a data center campus located in Warren County, Mississippi in which Amazon Web Services is investing. Entergy Mississippi will need generation and transmission resources to reliably serve all Entergy Mississippi customers, including the data centers. The large customer supply and service agreements also contain provisions which cover Entergy Mississippi’s incremental investment costs in the event of early termination. Entergy Mississippi anticipates recovering the incremental cost to serve the customer through the revenues it is collecting under the large customer supply and service agreements.

In May 2024 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan to comply with state legislation passed in January 2024 allowing Entergy Mississippi to make interim rate adjustments, including the collection of a return on construction work in progress on a cash basis, to recover the non-fuel related annual ownership cost of certain facilities that directly or indirectly provide service to customers who own certain data processing center projects as specified in the legislation.

Delta Blues Advanced Power Station

In September 2024, Entergy Mississippi announced plans to construct, own, and operate the Delta Blues Advanced Power Station, a 754 MW combined cycle combustion turbine facility, to be located in Washington County, Mississippi. The facility will primarily be powered by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The Delta Blues Advanced Power Station is estimated to cost $1.2 billion. Construction of the Delta Blues Advanced Power Station qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. As provided for in this legislation, Entergy Mississippi began recovery of certain costs of construction of the Delta Blues Advanced Power Station through the interim facilities rate adjustments provision of its formula rate plan rider. Non-fuel revenue collected from the data center customer will be included in the formula rate plan to offset the facility’s revenue requirement. The project costs will be reviewed

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

for prudence by the MPSC following the completion of construction. Construction is in progress, and the facility is expected to be in service by May 2028.

Traceview Advanced Power Station

Entergy Mississippi is constructing a 754 MW combined cycle combustion turbine facility located in the City of Ridgeland, Madison County, Mississippi. The facility will be powered primarily by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The project is estimated to cost in excess of $1 billion. Construction of the Traceview Advanced Power Station qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. As provided for in this legislation, Entergy Mississippi will begin recovery of certain costs of construction of the Traceview Advanced Power Station through the interim facilities rate adjustments provision of its formula rate plan rider. Non-fuel revenue collected from the data center customer will be included in the formula rate plan to offset the facility’s revenue requirement. The project costs will be reviewed for prudence by the MPSC following the completion of construction. The facility is expected to be in service in 2029.

Vicksburg Advanced Power Station

In October 2025, Entergy Mississippi announced plans to construct, own, and operate the Vicksburg Advanced Power Station, a 754 MW combined cycle combustion turbine facility, to be located in the City of Vicksburg, Warren County, Mississippi. The facility will be powered primarily by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The Vicksburg Advanced Power Station is estimated to cost $1.2 billion. Construction of the Vicksburg Advanced Power Station qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. As provided for in this legislation, Entergy Mississippi will begin recovery of certain costs of construction of the Vicksburg Advanced Power Station through the interim facilities rate adjustments provision of its formula rate plan rider. Non-fuel revenue collected from the data center customer will be included in the formula rate plan to offset the facility’s revenue requirement. The project costs will be reviewed for prudence by the MPSC following the completion of construction. Construction is in progress, and the facility is expected to be in service in August 2028.

Orange County Advanced Power Station

In September 2021, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Orange County Advanced Power Station, a new 1,215 MW combined cycle combustion turbine facility to be located in Bridge City, Texas at an initially-estimated expected total cost of $1.2 billion inclusive of the estimated costs of the generation facilities, transmission upgrades, contingency, an allowance for funds used during construction, and necessary regulatory expenses, among others. The project includes combustion turbine technology with dual fuel capability, able to co-fire up to 30% hydrogen by volume upon commercial operation and upgradable to support 100% hydrogen operations in the future. In December 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. In March 2022 certain intervenors filed testimony opposing the hydrogen co-firing component of the proposed project and others filed testimony opposing the project outright. Also in March 2022 the PUCT staff filed testimony opposing the hydrogen co-firing component of the proposed project, but otherwise taking no specific position on the merits of the project. The PUCT staff also proposed that the PUCT establish a maximum amount that Entergy Texas may recover in rates attributable to the project. In April 2022, Entergy Texas filed rebuttal testimony addressing and rebutting these various arguments. The hearing on the merits was held in June 2022, and post-hearing briefs were submitted in July 2022. In September 2022 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas’s application for certification of Orange

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

County Advanced Power Station subject to certain conditions, including a cap on cost recovery at $1.37 billion, the exclusion of investment associated with co-firing hydrogen, weatherization requirements, and customer receipt of any contractual benefits associated with the facility’s guaranteed heat rate. In October 2022 the parties in the proceeding filed exceptions and replies to exceptions to the proposal for decision. Also in October 2022, Entergy Texas filed with the PUCT information regarding a new fixed pricing option for an estimated project cost of approximately $1.55 billion associated with Entergy Texas’s issuance of limited notice to proceed by mid-November 2022. In November 2022 the PUCT issued a final order approving the requested amendment to Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Orange County Advanced Power Station without the investment associated with hydrogen co-firing capability, without a cap on cost recovery, and subject to certain conditions, including weatherization requirements and customer receipt of any contractual benefits associated with the facility’s guaranteed heat rate.

In December 2022, Texas Industrial Energy Consumers and Sierra Club filed motions for rehearing of the PUCT’s final order alleging the PUCT erred in granting the certification of the Orange County Advanced Power Station, in not imposing a cost cap, in including certain findings related to the reasonableness of Entergy Texas’s request for proposals from which the Orange County Advanced Power Station was selected, and in other regards. Also in December 2022, Entergy Texas filed a response to the motions for rehearing refuting the points raised therein. In January 2023 the PUCT issued letters noting that it voted to consider Texas Industrial Energy Consumers’ motion for rehearing at its upcoming January 2023 open meeting and voted not to consider Sierra Club’s motion for rehearing at an open meeting. At the January 2023 open meeting, the PUCT voted to grant Texas Industrial Energy Consumers’ motion for rehearing for the limited purpose of issuing an order on rehearing that excludes three findings related to Entergy Texas’s request for proposals. The order on rehearing does not change the PUCT’s certification of the Orange County Advanced Power Station or the conditions placed thereon in the PUCT’s November 2022 final order. Construction is in progress, and subject to receipt of required permits, the facility is expected to be in service by mid-2026.

Legend Power Station and Lone Star Power Station

In June 2024, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Legend Power Station, a 754 MW combined cycle combustion turbine facility, which will be enabled for future carbon capture and storage and for hydrogen co-firing optionality, to be located in Jefferson County, Texas, and the Lone Star Power Station, a 453 MW simple cycle combustion turbine facility, which will be enabled with hydrogen co-firing optionality, to be located in Liberty County, Texas. In its application, Entergy Texas noted that the Legend Power Station was expected to cost an estimated $1.46 billion and the Lone Star Power Station was expected to cost an estimated $735.3 million, in each case inclusive of the estimated costs of the generation facilities, interconnection costs, transmission network upgrades, and an allowance for funds used during construction. In July 2024 the PUCT referred the proceeding to the State Office of Administrative Hearings and, also in July 2024, the ALJ with the State Office of Administrative Hearings adopted a procedural schedule, with a hearing on the merits scheduled to begin in October 2024. In September 2024, Entergy Texas filed, and the ALJ with the State Office of Administrative Hearings granted, a motion to extend the procedural schedule in this proceeding in order to address certain developments relating to the cost and scope of the Legend Power Station and the Lone Star Power Station. In December 2024, Entergy Texas filed supplemental testimony and exhibits addressing the cost and scope developments associated with the Legend Power Station and the Lone Star Power Station in further support of its application. The cost and scope developments include cost estimate increases of $139 million for Legend Power Station and $63.7 million for Lone Star Power Station and the consideration of an alternate site for Lone Star Power Station, which would reduce the estimated cost increase of the Lone Star Power Station to $36.2 million. In March 2025, Entergy Texas filed testimony explaining that Entergy Texas planned to move forward with building the Lone Star Power Station on a more cost-effective alternative site in San Jacinto County, Texas. A hearing on the merits was held in April 2025. Also in April 2025, Entergy Texas, intervenors, and the PUCT staff filed initial briefs. In its initial brief, the PUCT staff recommended denial of Entergy Texas’s application or, in the alternative, approval subject to conditions that include a prudence review by an external consultant if actual project costs exceed

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

estimated costs by more than 10%, transmission cost reporting, and weatherization of both the Legend Power Station and the Lone Star Power Station. Certain intervenors requested that the PUCT impose various conditions upon the approval of the resources, including, among others, cost recovery limitations, a direction that Entergy Texas initiate a competitive tariff proceeding to facilitate industrial sleeving, a requirement for additional regulatory approvals related to hydrogen or carbon capture and storage implementation, limits on the recovery of supplemental filing costs, and calculation of AFUDC based on an adjusted weighted average cost of capital. Reply briefs were filed in May 2025. In June 2025 the ALJs with the State Office of Administrative Hearings issued a proposal for decision, in which they recommended rejection of Entergy Texas’s application to construct the Legend Power Station and the Lone Star Power Station based upon their finding that Entergy Texas did not demonstrate the resources to be cost-effective alternatives to address the uncontested need for additional generation. In the alternative, the ALJs recommended that if the PUCT approves the resources, that conditions be imposed, including a deferral of the finding that the resources were prudently selected until Entergy Texas’s next rate case, a prudence review by an external consultant if actual project costs exceed estimated costs by more than 10%, weatherization requirements, and a requirement that Entergy Texas obtain additional regulatory approvals prior to implementing hydrogen co-firing or carbon capture and storage. The ALJs’ proposal for decision was an interim step in the certification process and was not binding upon the PUCT. Entergy Texas filed exceptions in July 2025. In September 2025 the PUCT issued a decision granting the application, subject to conditions that include a cost cap at Entergy Texas’s previously-filed modified estimated costs of $1.6 billion for the Legend Power Station and $799 million for the Lone Star Power Station, weatherization requirements, environmental compliance requirements, and a requirement to request additional authorization prior to implementing hydrogen co-firing or carbon capture and storage. In October 2025 an intervenor filed a motion for rehearing requesting that the PUCT modify the Lone Star Power Station cost cap to reflect the estimated project costs associated with a new project site, clarify that the cost cap is inclusive of transmission upgrades, and reconsider the intervenor’s prior proposal for a “soft cost cap” below the estimated project costs, and that Entergy Texas be directed to initiate a competitive tariff proceeding to facilitate industrial sleeving of purchased power. Entergy Texas filed a response to the motion for rehearing in October 2025. In December 2025 the PUCT issued an order on rehearing modifying the Lone Star Power Station cost cap to $771.5 million to reflect the estimated project costs associated with a new project site and clarifying that the cost cap is inclusive of transmission upgrades, but denying the other relief requested in the motion for rehearing. See Note 8 to the financial statements for discussion of the build-to-suit lease arrangement for the Legend Power Station. Construction is underway, and subject to receipt of required permits and other conditions, both facilities are expected to be in service by mid-2028.

Southeast Texas Area Reliability Project (SETEX)

In February 2025, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate a new single-circuit 500 kV transmission line and associated stations and 138/230 kV facilities. The transmission line is expected to be approximately 131 to 160 miles in length and the estimated cost of the project ranges from $1.3 billion to $1.5 billion, depending upon the route ultimately approved by the PUCT. Also in February 2025 the PUCT referred the proceeding to the State Office of Administrative Hearings. A hearing on the merits was held in May 2025. In July 2025 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas’s application to construct SETEX and recommending the PUCT’s approval include selection of a specific route with an estimated cost of $1.4 billion. In October 2025 the PUCT issued a final order approving the requested amendment to Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the new single-circuit 500 kV transmission line and associated stations and 138/230 kV facilities, and selecting the final route for the project, which has an estimated cost of $1.36 billion. In November 2025, multiple parties filed motions for rehearing primarily challenging the routing of the transmission line. In December 2025 the PUCT issued an order on rehearing reaffirming and providing additional support for its initial decision. Subject to receipt of required permits and other conditions, the facility is expected to be in service by the end of 2029.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Cypress to Legend 500 kV Transmission Line

In May 2025, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate a new single-circuit 500 kV transmission line. The transmission line is expected to be approximately 40 to 49 miles in length and the estimated cost of the project ranges from $392.7 million to $436.2 million, depending on the route ultimately approved by the PUCT. In June 2025 the PUCT referred the proceeding to the State Office of Administrative Hearings and a hearing on the merits was held in August 2025. In October 2025 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas’s application to construct the transmission line and recommending the PUCT’s approval include selection of a specific route with an estimated cost of $398.7 million. In December 2025 the PUCT issued a final order approving the requested amendment to Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the new single-circuit 500 kV transmission line, and selecting the final route previously recommended. In February 2026, landowners not party to the PUCT proceeding filed in the 345th District Court of Travis County, Texas a petition for declaratory relief and temporary and permanent injunction against the PUCT’s final order. The petition, which names the PUCT, its commissioners, and Entergy Texas as defendants, challenges Entergy Texas’s notice, the application of the PUCT’s notice rule, and the PUCT order’s approval of a route the petitioner’s assert was not adequately noticed. Entergy Texas expects to file an answer disputing all aspects of the petition by the applicable deadline. Subject to receipt of required permits and other conditions, the facility is expected to be in service by the end of 2028.

Resilience and Grid Hardening

Entergy Louisiana

In December 2022, Entergy Louisiana filed an application with the LPSC seeking a public interest finding regarding Phase I of Entergy Louisiana’s Future Ready resilience plan and approval of a rider mechanism to recover the program’s costs. Phase I in the December 2022 application reflected the first five years of a ten-year resilience plan and included investment of approximately $5 billion, including hardening investment, transmission dead-end structures, enhanced vegetation management, and telecommunications improvement. In April 2024 the LPSC approved a framework which includes an initial five-year resilience plan providing for an investment of approximately $1.9 billion with cost recovery via a forward-looking rider with semi-annual true-ups. The plan is subject to specified reporting requirements and includes a performance review of the hardened assets. The LPSC order approving the framework does not include any restrictions on Entergy Louisiana’s ability to file applications for approval of additional investments in resilience.

The LPSC had previously opened a formal rulemaking proceeding in December 2021 to investigate efforts to improve resilience of electric utility infrastructure. In April 2023 the LPSC staff issued a draft rule in the rulemaking proceeding related to a requirement to file a grid resilience plan. The procedural schedule entered in the rulemaking proceeding contemplated adoption of a final rule in October 2023, but this did not occur, and a new date has not been set.

The LPSC also has pending rulemakings addressing issues related to pole viability and grid maintenance practices. In December 2023, in those rulemakings, the LPSC staff issued a report and recommendation proposing to impose significant new reporting and compliance obligations related to jurisdictional utilities’ distribution and transmission operations, including new obligations related to grid hardening plans, pole inspections, pole replacement, vegetation management, storm restoration plans, new reliability metrics, software for handling customer complaints and complaint resolution, required use of drone technology, and new penalties and incentives for reliability performance and for compliance with the new obligations. In February 2024, Entergy Louisiana and other parties filed comments on the LPSC staff’s report. These rulemakings were formally closed in August 2025 without the adoption of any rules or obligations being promulgated by the LPSC.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Entergy New Orleans

In October 2021 the City Council passed a resolution and order establishing a docket and procedural schedule with respect to system resiliency and storm hardening. In July 2022, Entergy New Orleans filed with the City Council a response identifying a preliminary plan for storm hardening and resiliency projects, including microgrids, to be implemented over ten years at an approximate cost of $1.5 billion. In February 2023 the City Council approved a revised procedural schedule requiring Entergy New Orleans to make a filing in April 2023 containing a narrowed list of proposed hardening projects. In April 2023, Entergy New Orleans filed the required application and supporting testimony seeking City Council approval of the first phase (five years and $559 million) of a ten-year infrastructure hardening plan totaling approximately $1 billion. Entergy New Orleans also sought, among other relief, City Council approval of a resilience and storm hardening cost recovery rider to recover from customers the costs of the infrastructure hardening plan. In February 2024 the City Council approved a resolution authorizing Entergy New Orleans to implement a resilience project to be partially funded by $55 million of matching funding through the DOE’s Grid Resilience and Innovation Partnerships program. The resolution also required Entergy New Orleans to submit, no later than July 2024, a revised resilience plan consisting of projects over a three-year period. In March 2024, Entergy New Orleans filed with the City Council for approval the requested three-year resilience plan, which included $168 million in hardening projects. The three-year resilience plan was to be in addition to the previously authorized resilience project to be partially funded by the DOE’s Grid Resilience and Innovation Partnerships program. In October 2024 the City Council approved a resolution authorizing a two-year resilience plan totaling $100 million and approved the requested resilience and storm hardening cost recovery rider. In December 2024, Entergy New Orleans notified the City Council of the subset of hardening projects from the revised three-year resilience plan to be included in the two-year resilience plan. Entergy New Orleans implemented the approved resilience and storm hardening cost recovery rider effective with the first billing cycle of January 2025. In December 2025, the City Council issued a resolution establishing certain metrics and reporting requirements for the approved hardening projects. Also in December 2025, Entergy New Orleans filed an application and supporting testimony seeking the City Council’s approval of the second phase of its infrastructure hardening plan totaling approximately $400 million over a five-year period (2027 to 2031). Entergy New Orleans also sought, among other relief, the City Council’s approval to continue to use the resilience and storm hardening cost recovery rider to recover from customers the costs of the plan. Entergy New Orleans requested the City Council approve the application by October 2026.

Entergy Texas

In June 2024, Entergy Texas filed an application with the PUCT requesting approval of Phase I of its Texas Future Ready Resiliency Plan, a set of measures to begin accelerating the resiliency of Entergy Texas’s transmission and distribution system. Phase I is comprised of projects totaling approximately $335.1 million, including approximately $137 million of projects to be funded by Entergy Texas and approximately $198 million of projects contingent upon Entergy Texas’s receipt of grant funds in that amount from the Texas Energy Fund. The projects in Phase I include distribution and transmission hardening and modernization projects and targeted vegetation management projects to mitigate the risk of wildfire. These projects are expected to be implemented within approximately three years of PUCT approval. In January 2025 the PUCT unanimously approved Phase I of Entergy Texas’s Texas Future Ready Resiliency Plan, including the approximately $137 million of projects to be funded by Entergy Texas and application of performance metrics consistent with the unopposed settlement. The PUCT clarified that, while not part of Entergy Texas’s Phase I plan, Entergy Texas is permitted to pursue the remaining $198 million of identified projects and Texas Energy Fund grant funding for those projects. In February 2025 the PUCT issued an order adopting a new rule establishing the procedures for application to the grant fund. In July 2025, Entergy Texas submitted an application for approximately $200 million in grant funding from the Texas Energy Fund to implement the resilience projects originally included in its Texas Future Ready Resiliency Plan. In October 2025 the PUCT voted to approve the approximately $200 million grant request in full. The portion of the projects funded by Entergy Texas will be eligible for recovery through Entergy Texas’s transmission or distribution cost recovery factor riders, as applicable.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Dividends and Stock Repurchases

Declarations of dividends on Entergy Corporation common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy Corporation common stock dividends based upon earnings per share from the Utility segment and the Parent and Other portion of the business, financial strength, and future investment opportunities. In January 2026 the Board declared a dividend of $0.64 per share. Entergy paid $1,074 million in 2025, $982 million in 2024, and $918 million in 2023 in cash dividends on its common stock.

In accordance with Entergy’s stock-based compensation plans, Entergy periodically grants stock options, restricted stock, performance units, and restricted stock units to key employees, which may be exercised to obtain shares of Entergy Corporation common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy’s management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans.

In addition to the authority to fund grant exercises, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2010 the Board granted authority for a $500 million share repurchase program. As of December 31, 2025, $350 million of authority remains under the $500 million share repurchase program. The amount of repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities, or if limitations in the credit markets continue for a prolonged period.

Sources of Capital

Entergy’s sources to meet its capital requirements and to fund potential investments include:

•internally generated funds;

•cash on hand ($1,929 million as of December 31, 2025);

•storm reserve escrow accounts;

•debt and equity issuances in the capital markets, including debt issuances to refund or retire currently outstanding or maturing indebtedness;

•bank financing under new or existing facilities or commercial paper; and

•sales of assets.

Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, the Registrant Subsidiaries expect to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

Provisions within the organizational documents relating to preferred stock or membership interests of certain of Entergy Corporation’s subsidiaries could restrict the payment of cash dividends or other distributions on their common and preferred equity. All debt and preferred equity issuances by the Registrant Subsidiaries require prior regulatory approval and their debt issuances are also subject to requirements set forth in bond indentures and other agreements. Entergy believes that the Registrant Subsidiaries have sufficient capacity under these tests to meet foreseeable capital needs for the next twelve months and beyond.

The FERC has jurisdiction over securities issuances by the Utility operating companies and System Energy. The City Council has concurrent jurisdiction over Entergy New Orleans’s securities issuances with maturities longer than one year. The APSC has concurrent jurisdiction over Entergy Arkansas’s issuances of securities secured by Arkansas property, including first mortgage bond issuances. No regulatory approvals are necessary for Entergy Corporation to issue securities. The current FERC-authorized short-term borrowing limits and long-term financing authorization for Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

are effective through January 2027. The current FERC-authorized short-term borrowing limit and long-term financing authorization for Entergy Arkansas is effective through February 2028. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2027. Entergy New Orleans also has obtained long-term financing authorization from the City Council that extends through December 2027. Entergy Louisiana and System Energy each has obtained long-term financing authorization from the FERC that extends through January 2027 for issuances by the nuclear fuel company variable interest entities. Entergy Arkansas has obtained long-term financing authorization from the FERC that extends through February 2028 for issuances by its nuclear fuel company variable interest entity. In addition to borrowings from commercial banks, the Registrant Subsidiaries may also borrow from the Entergy system money pool and from other internal short-term borrowing arrangements. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and the other internal borrowing arrangements are designed to reduce Entergy’s subsidiaries’ dependence on external short-term borrowings. Borrowings from internal and external short-term borrowings combined may not exceed the FERC-authorized limits. See Notes 4 and 5 to the financial statements for further discussion of Entergy’s borrowing limits, authorizations, and amounts outstanding.

Equity Issuances and Equity Distribution Program

In January 2021, Entergy Corporation entered into an equity distribution sales agreement with several counterparties establishing an at the market equity distribution program, pursuant to which Entergy Corporation may offer and sell from time to time shares of its common stock. The sales agreement provides that, in addition to the issuance and sale of shares of Entergy Corporation common stock, Entergy Corporation may enter into forward sale agreements for the sale of its common stock. The aggregate number of shares of common stock sold under this sales agreement and under any forward sale agreement may not exceed an aggregate gross sales price of $4.5 billion. As of December 31, 2025, Entergy Corporation has utilized the equity distribution program either to sell or to enter into forward sale agreements with respect to shares of common stock with an aggregate gross sales price of approximately $2.8 billion, of which approximately $2.6 billion of aggregate gross sales price was the subject of forward sale agreements, subject to adjustment pursuant to the forward sale agreements. Entergy Corporation settled certain of its then-outstanding forward sale agreements for cash proceeds of $131 million in 2023 and $1,138 million in 2025. There were no settlements of forward sale agreements for the year ended December 31, 2024.

In March 2025, Entergy Corporation marketed an equity offering of 17.8 million shares of Entergy Corporation common stock. In lieu of issuing equity at the time of the offering, Entergy Corporation entered into forward sale agreements with several forward counterparties. The forward sale agreements require Entergy Corporation to, at its election on or prior to September 30, 2026, either (1) physically settle the transactions by issuing the total of 17.8 million shares of its common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements (initially $81.87 per share) or (2) net settle the transactions in whole or in part through the delivery or receipt of cash or shares. The forward sale price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements.

In February 2026, Entergy Corporation physically settled a portion of its obligations under certain of its outstanding forward sale agreements under its at the market equity distribution program for cash proceeds of $346 million.

Entergy Corporation currently expects to issue approximately $4.4 billion of equity through 2029, which it may issue under its at the market equity distribution program or otherwise, with approximately $1.9 billion already contracted under forward sale agreements as of December 31, 2025, including under its at the market equity distribution program ($346 million of which were settled in February 2026 as described above) and the March 2025 equity offering described above. See Note 7 to the financial statements for discussion of the forward sale agreements and common stock issuances and sales under the equity distribution program.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

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

In December 2025, Entergy Texas entered into a build-to-suit lease arrangement for the Legend Power Station as the lessee with a consortium of investors (the Investors). Under the terms of the arrangement, the Investors purchased the in-process Legend Power Station construction project from Entergy Texas at a cost of $359 million and will spend up to $1.45 billion (including the initial purchase price) to construct the Legend Power Station project as designed by Entergy Texas. Entergy Texas is engaged to serve as the construction agent for the Legend Power Station project. The Investors, however, control the asset during construction. If Entergy Texas defaults in its role as construction agent, the Investors have various options available to remedy the default, including by accelerating the lease balance payable by Entergy Texas, causing a sale of the Legend Power Station project to a third party, or certain other options. If there are certain changes to the terms of the PUCT approval of the Legend Power Station project or certain other circumstances outside of Entergy Texas’s control, then either the Investors or Entergy Texas could exercise the right to terminate the arrangement, in which case Entergy Texas would be required to purchase the in-process Legend Power Station project from the Investors at an amount equal to their costs incurred to date, including carrying costs. Since Entergy Texas does not control the in-process construction project, it will not recognize the asset (i.e., construction work in progress) or an associated liability during construction.

Upon the Legend Power Station’s readiness for first synchronization to the grid, expected in early 2028, a triple-net lease will commence under which Entergy Texas will have control of the Legend Power Station and receive all output from the plant. The initial term of the lease will end seven years from the closing of the arrangement, or approximately five years after the Legend Power Station’s expected readiness for first synchronization to the grid. The lease cost will be equal to the Secured Overnight Financing Rate plus a margin which is based on the credit rating of Entergy Texas, multiplied by the total costs (including carrying costs) incurred by the Investors as of the commencement of the lease. Entergy Texas will have the option to purchase the Legend Power Station at any time during the lease term at a price equal to the total cost of the plant to the Investors, plus any fees and carrying charges owed to the Investors. If the purchase price option is exercised within two years of commencement of the triple-net lease, Entergy Texas must enter into a secured note payable to the Investors for the amount of the purchase price. The note payable would be due at the end of the initial lease term, but may be prepaid at any time beginning two years after the commencement date of the lease. The note will be secured by the Legend Power Station and related equipment and collateral.

At the end of the initial lease term, Entergy Texas must exercise one of the following options: 1) renew the lease for an additional five year term, subject to unanimous consent of the Investors, 2) purchase the plant at a price equal to the total cost of the plant to Investors, plus any fees and carrying charges owed to the Investors, or 3) sell the plant on behalf of the Investors. If Entergy Texas chooses the third option, then it will owe or be owed any difference between the total cost of the plant to Investors and the sale price.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Cash Flow Activity

As shown in Entergy’s Consolidated Statements of Cash Flows, cash flows for the years ended December 31, 2025, 2024, and 2023 were as follows:


	2025	2024	2023
	(In Millions)
Cash and cash equivalents at beginning of period	$860	$133	$224

Net cash provided by (used in):
Operating activities	5,150	4,488	4,294
Investing activities	(7,109)	(5,849)	(4,629)
Financing activities	3,028	2,088	244
Net increase (decrease) in cash and cash equivalents	1,069	727	(91)

Cash and cash equivalents at end of period	$1,929	$860	$133

2025 Compared to 2024

Operating Activities

Net cash flow provided by operating activities increased $662 million in 2025 primarily due to:

•higher collections from Utility customers;

•the receipt of $547 million in proceeds from the transfer of 2024 nuclear and solar production tax credits to third parties in 2025. See Note 3 to the financial statements for discussion of the nuclear and solar production tax credits;

•an increase of $401 million in receipts from advance payments related to customer agreements in 2025, of which $366 million is recorded as current liabilities and included within changes in other working capital accounts; and

•one-time bill credits of $92 million in 2024 to Entergy Arkansas’s retail customers through the Grand Gulf credit rider as a result of the System Energy settlement with the APSC. See Note 2 to the financial statements for discussion of the System Energy settlement agreement with the APSC and Entergy Arkansas’s Grand Gulf credit rider.

The increase was partially offset by higher fuel and purchased power payments, an increase of $124 million in interest paid, and the timing of payments to vendors. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery.

Investing Activities

Net cash flow used in investing activities increased $1,260 million in 2025 primarily due to:

•an increase of $2,154 million in non-nuclear generation construction expenditures primarily due to higher spending by Entergy Arkansas on the Ironwood Power Station (formerly Lake Catherine Unit 5) project and the Jefferson Power Station project, by Entergy Louisiana on the Franklin Farms Power Station Units 1 and 2 project, by Entergy Mississippi on the Delta Blues Advanced Power Station project, the Vicksburg Advanced Power Station project, the Traceview Advanced Power Station project, and the Penton Solar project, and by Entergy Texas on the Legend Power Station project, the Lone Star Power Station project, and the Orange County Advanced Power Station project;

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

•an increase of $400 million in distribution construction expenditures primarily due to increased investment in the resilience of the Utility distribution system;

•an increase of $234 million in transmission construction expenditures primarily due to higher capital expenditures as a result of increased development in the Utility service area and increased spending on various transmission projects in 2025;

•an increase of $115 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2025;

•a decrease of $79 million in proceeds received in 2025 as compared to 2024 from the DOE resulting from litigation regarding spent nuclear fuel storage costs. See Note 8 to the financial statements for discussion of the spent nuclear fuel storage litigation;

•cash collateral of $95 million posted in 2025 to support Entergy Arkansas’s and Entergy Louisiana’s obligations to MISO; and

•an increase of $43 million in decommissioning trust fund investment activity.

The increase was partially offset by:

•the receipt of $484 million in proceeds from the sale of the Entergy Louisiana and Entergy New Orleans natural gas distribution businesses on July 1, 2025. See Note 14 to the financial statements for discussion of the sale of the Entergy Louisiana and Entergy New Orleans natural gas distribution businesses on July 1, 2025;

•the initial and substantial completion payments totaling approximately $393 million in 2024 for the purchase of the Driver Solar facility by Entergy Arkansas;

•the receipt of $359 million in proceeds from the sale of assets related to Entergy Texas’s Legend Power Station project in 2025. See Note 8 to the financial statements for discussion of the Entergy Texas build-to-suit lease arrangement for the Legend Power Station;

•the initial and substantial completion payments totaling approximately $240 million in 2024 for the purchase of the West Memphis Solar facility by Entergy Arkansas;

•the initial and substantial completion payments totaling approximately $186 million in 2024 for the purchase of the Walnut Bend Solar facility by Entergy Arkansas;

•a decrease of $68 million in information technology capital expenditures primarily due to decreased spending on various technology projects in 2025;

•a decrease of $57 million in nuclear fuel purchases due to variations from year to year in the timing and pricing of fuel reload requirements, materials and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and

•net receipts from storm reserve escrow accounts of $32 million in 2025 compared to net payments to storm reserve escrow accounts of $17 million in 2024.

See Note 14 to the financial statements for discussion of the Driver Solar facility, the West Memphis Solar facility, and the Walnut Bend Solar facility purchases.

Financing Activities

Net cash flow provided by financing activities increased $940 million in 2025 primarily due to:

•$1,136 million in net proceeds from the issuance of common stock in settlement of forward contracts under the at the market equity distribution program in 2025. There were no issuances of common stock under the at the market equity distribution program in 2024; and

•an increase of $638 million in net customer advances for construction related to transmission, distribution, and generator interconnection agreements.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

The increase was partially offset by:

•long-term debt activity providing approximately $2,249 million of cash in 2025 compared to providing approximately $2,845 million of cash in 2024;

•a decrease of $100 million in proceeds received from treasury stock issuances in 2025 due to a smaller amount of previously repurchased Entergy Corporation common stock issued in 2025 to satisfy stock option exercises as compared to 2024;

•an increase of $92 million in common stock dividends paid in 2025 as a result of an increase in the dividend paid per share in 2025 as compared to 2024 and an increase in the number of shares outstanding; and

•an increase of $59 million in net repayments of commercial paper in 2025 as compared to 2024.

See Note 7 to the financial statements for discussion of the equity distribution program. See Note 5 to the financial statements for details of long-term debt. See Note 4 to the financial statements for details of Entergy’s commercial paper program.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow Activity” in Item 7 of Entergy’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 18, 2025, for discussion of operating, investing, and financing cash flow activities for 2024 compared to 2023.

Industrial and Commercial Customers

Entergy’s large industrial and commercial customers continually explore ways to reduce their energy costs. Entergy responds by working with industrial and commercial customers to negotiate electric service contracts with competitive rates that match specific customer needs and load profiles. Additionally, cogeneration is an option available to a portion of Entergy’s industrial customer base. Entergy actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand from both new and existing customers.

Rate, Cost-recovery, and Other Regulation

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that the Utility operating companies charge for their services significantly influence Entergy’s financial position, results of operations, and liquidity. These companies are regulated, and the rates charged to their customers are determined in regulatory proceedings. Governmental agencies, including the APSC, the LPSC, the MPSC, the City Council, and the PUCT, are primarily responsible for approval of the rates charged to customers. Following is a summary of the Utility operating companies’ authorized returns on common equity:


Company						Authorized Return on Common Equity

Entergy Arkansas						9.15% - 10.15%
Entergy Louisiana						9.3% - 10.1%
Entergy Mississippi						10.25% - 12.26%
Entergy New Orleans						8.85% - 9.85%
Entergy Texas						9.57%

Rate regulation and related regulatory proceedings and fuel and purchased power cost recovery proceedings for the Utility operating companies are discussed in Note 2 to the financial statements.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Federal Regulation

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

Market and Credit Risk Sensitive Instruments

Market risk is the risk of changes in the value of commodity and financial instruments, or in future net income or cash flows, in response to changing market conditions. Entergy holds commodity and financial instruments that are exposed to the following significant market risks:

•The commodity price risk associated with the sale of electricity by Entergy’s non-utility operations business.

•The interest rate and equity price risk associated with Entergy’s investments in qualified pension and other postretirement benefits trust funds. See Note 11 to the financial statements for details regarding Entergy’s qualified pension and other postretirement benefits trust funds.

•The interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds. See Note 16 to the financial statements for details regarding Entergy’s decommissioning trust funds.

•The interest rate risk associated with changes in interest rates as a result of Entergy’s outstanding indebtedness. Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to total capitalization, and by hedging some of its exposure to interest rates via derivative instruments. See Notes 4 and 5 to the financial statements for the details of Entergy’s debt outstanding. See Note 15 to the financial statements for further details on Entergy’s derivative instruments and hedging activities.

The Utility has limited exposure to the effects of market risk because it operates primarily under cost-based rate regulation. To the extent approved by their retail regulators, the Utility operating companies use commodity and financial instruments to hedge the exposure to price volatility inherent in their purchased power, fuel, and gas purchased for resale costs that are recovered from customers.

Entergy’s commodity and financial instruments are also exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Entergy is also exposed to a potential demand on liquidity due to credit support requirements within its supply or sales agreements.

Some of the agreements to sell the power produced by Entergy’s non-utility operations business contain provisions that require an Entergy subsidiary to provide credit support to secure its obligations under such agreements. The primary form of credit support used to satisfy these requirements is an Entergy Corporation guarantee. Cash and letters of credit are also acceptable forms of credit support. At December 31, 2025, based on power prices at that time, Entergy had $4 million of posted cash collateral.

In addition to the ability to post cash collateral, each of the Utility operating companies has uncommitted standby letter of credit facilities as a means to post collateral to support its obligations to MISO and for other purposes. See Note 4 to the financial statements for discussion of these letter of credit facilities. As of December 31, 2025, Entergy Arkansas had $37 million of posted cash collateral and Entergy Louisiana had $58 million of posted cash collateral.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Nuclear Matters

Entergy’s Utility business includes the ownership and operation of nuclear generating plants and is, therefore, subject to the risks related to such ownership and operation. These include risks related to: the acquisition, use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, including the financial requirements to address emerging issues related to equipment reliability, to position Entergy’s nuclear fleet to meet its operational goals; the performance and capacity factors of these nuclear plants; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts of insurance recoveries for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident.

NRC Reactor Oversight Process

The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, “multiple/repetitive degraded cornerstone column,” or Column 4, and “unacceptable performance,” or Column 5. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC with, in general, progressively increasing levels of associated costs. Continued plant operation is not permitted for plants in Column 5. All of the nuclear generating plants owned and operated by Entergy’s Utility business are currently in Column 1.

Critical Accounting Estimates

The preparation of Entergy’s financial statements in conformity with GAAP requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy’s financial position, results of operations, or cash flows.

Nuclear Decommissioning Costs

Certain of the Utility operating companies and System Energy own nuclear generation facilities. Regulations require these Entergy subsidiaries to decommission the nuclear power plants after each facility is taken out of service, and cash is deposited in trust funds during the facilities’ operating lives in order to provide for this obligation. Entergy conducts periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities. The following key assumptions have a significant effect on these estimates.

•Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant’s retirement must be estimated for those plants that do not have an announced shutdown date. The estimate may include assumptions regarding the possibility that the plant may have an operating life shorter than the operating license expiration. Second, an assumption must be made regarding whether all decommissioning activity will proceed immediately upon plant

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

retirement, or whether the plant will be placed in SAFSTOR status. SAFSTOR is decommissioning a facility by placing it in a safe, stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation of operations. A change of assumption regarding either the period of continued operation, the use of a SAFSTOR period, or whether Entergy will continue to hold the plant or the plant is held for sale can change the present value of the asset retirement obligation.

•Cost Escalation Factors - Entergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by factors ranging from approximately 2% to 3% annually. A 50-basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 8% to 15%. The timing assumption influences the significance of the effect of a change in the estimated inflation or cost escalation rate because the effect increases with the length of time assumed before decommissioning activity ends.

•Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. The DOE has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law. The DOE continues to delay meeting its obligation and Entergy’s nuclear plant owners are continuing to pursue damage claims against the DOE for its failure to provide timely spent fuel storage. Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities during the decommissioning period can have a significant effect (as much as an average of 20% to 30% of total estimated decommissioning costs). Entergy’s decommissioning studies include cost estimates for spent fuel storage. These estimates could change in the future, however, based on the expected timing of when the DOE begins to fulfill its obligation to receive and store spent nuclear fuel. See Note 8 to the financial statements for further discussion of Entergy’s spent nuclear fuel litigation.

•Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of nuclear facilities has been gained and that experience has been incorporated into Entergy’s current decommissioning cost estimates. Given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could be gained and affect current cost estimates. In addition, if regulations regarding nuclear decommissioning were to change, this could affect cost estimates.

•Interest Rates - The estimated decommissioning costs that are the basis for the recorded decommissioning liability are discounted to present value using a credit-adjusted risk-free rate. When the decommissioning liability is revised, increases in cash flows are discounted using the current credit-adjusted risk-free rate. Decreases in estimated cash flows are discounted using the credit-adjusted risk-free rate used previously in estimating the decommissioning liability that is being revised. Therefore, to the extent that a revised cost study results in an increase in estimated cash flows, a change in interest rates from the time of the previous cost estimate will affect the calculation of the present value of the revised decommissioning liability.

Revisions of estimated decommissioning costs that decrease the liability also result in a decrease in the asset retirement cost asset. Revisions of estimated decommissioning costs that increase the liability result in an increase in the asset retirement cost asset, which is then depreciated over the asset’s remaining economic life. See Note 9 to the financial statements for further discussion of asset retirement obligations.

Utility Regulatory Accounting

Entergy’s Utility operating companies and System Energy are subject to retail regulation by their respective state and local regulators and to wholesale regulation by the FERC. Because these regulatory agencies set the rates the Utility operating companies and System Energy are allowed to charge customers based on allowable costs, including a reasonable return on equity, the Utility operating companies and System Energy apply accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. Regulatory assets represent incurred costs that have been deferred because they are

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

probable of future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be credited to customers through future regulated rates, (2) billings in advance of expenditures for approved regulatory programs, or (3) refunds ordered by regulators. See Note 2 to the financial statements for a discussion of rate and regulatory matters, including details of Entergy’s and the Registrant Subsidiaries’ regulatory assets and regulatory liabilities.

For each regulatory jurisdiction in which they conduct business, the Utility operating companies and System Energy assess whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. If the assessments made by the Utility operating companies and System Energy are ultimately different than actual regulatory outcomes, it could materially affect the results of operations, financial position, and cash flows of Entergy or the Registrant Subsidiaries.

Taxation and Uncertain Tax Positions

Management exercises significant judgment in evaluating the potential tax effects of Entergy’s operations, transactions, and other events. Entergy accounts for uncertain income tax positions using a recognition model under a two-step approach with a more likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement. Management evaluates each tax position based on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether available information supports the assertion that the recognition threshold has been met. Additionally, measurement of unrecognized tax benefits to be recorded in the consolidated financial statements is based on the probability of different potential outcomes. Income tax expense and tax positions recorded could be significantly affected by events such as additional transactions contemplated or consummated by Entergy as well as audits by taxing authorities of the tax positions taken in transactions. Management believes that the financial statement tax balances are accounted for and adjusted appropriately each quarter, as necessary, in accordance with applicable authoritative guidance; however, the ultimate outcome of tax matters could result in favorable or unfavorable effects on the consolidated financial statements.

Certain Entergy subsidiaries have elected to apply the mark-to-market method of accounting for income tax return purposes to wholesale power purchase agreements as appropriate under the Internal Revenue Code and U.S. Treasury Regulations. The mark-to-market tax gain or loss computed each year is based on an estimated fair market valuation which includes analyses of market prices and conditions. Entergy’s and the Registrant Subsidiaries’ mark-to-market tax position could be affected by the outcome of federal and state income tax audits should taxing authorities challenge such valuations.

Entergy’s income taxes, including unrecognized tax benefits, open audits, and other significant tax matters, are discussed in Note 3 to the financial statements. See “Income Tax Legislation and Regulation” above for discussion of income tax legislation and regulation.

Qualified Pension and Other Postretirement Benefits

Entergy sponsors qualified, defined benefit pension plans, including cash balance plans and final average pay plans. Generally, plan participation is determined based on the employee’s most recent date of hire and collective bargaining agreement, where applicable. Additionally, Entergy currently provides other postretirement health care and life insurance benefits for full-time employees whose most recent date of hire or rehire is before July 1, 2014, and who reach retirement age and meet certain eligibility requirements while still working for Entergy.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate for Entergy and the Registrant Subsidiaries.

Assumptions

Key actuarial assumptions utilized in determining qualified pension and postretirement health care and life insurance costs include discount rates, projected healthcare cost rates, expected long-term rate of return on plan assets, rate of increase in future compensation levels, retirement rates, expected timing and form of payments, and mortality rates.

Annually, Entergy reviews and, when necessary, adjusts the assumptions for the qualified pension and other postretirement plans. Every three-to-five years, a formal actuarial assumption experience study that compares assumptions to the actual experience of the qualified pension and postretirement health care and life insurance plans is conducted. The interest rate environment over the past few years and volatility in the financial equity markets have affected Entergy’s funding and reported costs for these benefits.

Discount rates

In selecting an assumed discount rate to calculate benefit obligations, Entergy uses a yield curve based on high-quality corporate debt with cash flows matching the expected plan benefit payments. In estimating the service cost and interest cost components of net periodic benefit cost, Entergy discounts the expected cash flows by the applicable spot rates.

Projected health care cost trend rates

Entergy’s health care cost trend is affected by both medical cost inflation and, with respect to capped costs under the plan, the effects of general inflation. Entergy reviews actual recent cost trends and projected future trends in establishing its health care cost trend rates.

Expected long-term rate of return on plan assets

In determining its expected long-term rate of return on plan assets used in the calculation of benefit plan costs, Entergy reviews past performance, current and expected future asset allocations, and capital market assumptions of its investment consultant and some of its investment managers. Entergy conducts periodic asset/liability studies in order to set its target asset allocations.

In 2023, Entergy implemented a new asset allocation strategy for its pension assets, based on the funded status of each plan within the trust. The new strategy no longer focuses on targeting an overall asset allocation for the trust, but rather a target asset allocation for each plan within the trust that adjusts dynamically based on the funded status. The ultimate asset allocation for each plan is expected to be attained when the plan is 110% funded. The 2025 weighted-average target pension asset allocation is 30% equity and 70% fixed income securities, of which 66% is long duration fixed income.

In 2017, Entergy changed its asset allocation strategy for its non-taxable and taxable other postretirement assets, based on the funded status of each sub-account within each trust. The strategy no longer focuses on targeting an overall asset allocation for each trust, but rather a target asset allocation for each sub-account within each trust that adjusts dynamically based on the funded status. This strategy was reaffirmed based upon an asset/liability study in 2024. The 2025 weighted-average target postretirement asset allocation is 23% equity and 77% fixed income securities.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

See Note 11 to the financial statements for discussion of the current asset allocations for Entergy’s pension and other postretirement assets.

Costs and Sensitivities

The estimated 2026 and actual 2025 qualified pension and other postretirement costs and related underlying assumptions and sensitivities are shown below:


Costs	Estimated 2026	2025
	(In Millions)
Qualified pension cost	$66.2	$99.3 (a)
Other postretirement income	($2.4)	($20.3) (a)

Assumptions	2026	2025
Discount rates
Qualified pension
Service cost	5.66%	5.75%
Interest cost	5.06%	5.46%

Other postretirement
Service cost	5.55%	5.50%
Interest cost	4.90%	5.36%

Expected long-term rates of return
Qualified pension assets	6.25% - 6.75% Blended 6.72%	6.00% - 7.00% Blended 6.75%
Other postretirement - non-taxable assets	5.75% - 6.75%	6.00% - 7.00%
Other postretirement - taxable assets - after tax rate	4.75%	4.75%

Weighted-average rate of increase in future compensation	3.98% - 4.45%	3.98% - 4.45%

Assumed health care cost trend rates
Pre-65 retirees	8.50%	8.15%
Post-65 retirees	10.63%	10.13%
Ultimate health care cost trend rate	4.75%	4.75%
Year ultimate health care cost trend rate is reached and beyond
Pre-65 retirees	2036	2035
Post-65 retirees	2036	2035

(a) In 2025, qualified pension cost included settlement costs of $23.9 million and other postretirement income included settlement and curtailment credits of $5.2 million.

Actual asset returns have an effect on Entergy’s qualified pension and other postretirement costs. In 2025, Entergy’s actual annual return on qualified pension assets was approximately 12.50% and on other postretirement assets was approximately 11%, as compared to the 2025 expected long-term rates of return discussed above.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

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


Actuarial Assumption	Change in Assumption	Impact on 2026 Qualified Pension Cost	Impact on 2025 Qualified Pension Projected Benefit Obligation
	Increase/(Decrease)
Discount rate	(0.25%)	$4	$103
Rate of return on plan assets	(0.25%)	$12	$—
Rate of increase in compensation	0.25%	$4	$22

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


Actuarial Assumption	Change in Assumption	Impact on 2026 Postretirement Benefits Cost	Impact on 2025 Accumulated Postretirement Benefit Obligation
	Increase/(Decrease)
Discount rate	(0.25%)	$2	$21
Health care cost trend	0.25%	$2	$11

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

Accounting Mechanisms

In accordance with pension accounting standards, Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into expense only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. If almost all of the plan participants are inactive, as is the case for certain qualified pension plans, the excess is amortized over the remaining life expectancy of plan participants. Additionally, accounting standards allow for the deferral of prior service costs/credits arising from plan amendments that attribute an increase or decrease in benefits to employee service in prior periods. Prior service costs/credits are then amortized into expense over the average future working life of active employees. Certain decisions, including workforce reductions, plan amendments, and plant shutdowns, may significantly reduce the expense amortization period and result in immediate recognition of certain previously-deferred costs and gains/losses in the form of curtailment gains or losses. Similarly, payments made to settle benefit obligations, including lump sum benefit payments, can also result in accelerated recognition in the form of settlement losses or gains. Several Entergy subsidiaries received regulatory approval to defer the expense portion of settlement charges and amortize into expense over time. See Note 11 to the financial statements for further discussion.

Entergy calculates the expected return on pension and other postretirement benefits plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets. Entergy determines the MRV of its pension plan assets, except for the long duration fixed income assets, by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns. For the long duration fixed income assets in the pension trust and for its other postretirement benefits plan assets, Entergy uses fair value as the MRV.

Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. See Note 11 to the financial statements for further discussion of Entergy’s funded status.

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Employer Contributions

Entergy contributed $240 million to its qualified pension plans in 2025. Entergy estimates pension contributions will be approximately $200 million in 2026 although the 2026 required pension contributions will be known with more certainty when the January 1, 2026, valuations are completed, which is expected by April 1, 2026.

Minimum required funding calculations as determined under Pension Protection Act guidance, as amended by the American Rescue Plan Act of 2021, are performed annually as of January 1 of each year and are based on measurements of the assets and funding liabilities as measured at that date. Any excess of the funding liability over the calculated fair market value of assets results in a funding shortfall that must be funded over a fifteen-year rolling period. The Pension Protection Act also imposes certain plan limitations if the funded percentage, which is based on calculated fair market values of assets divided by funding liabilities, does not meet certain thresholds. For funding purposes, asset gains and losses are smoothed into the calculated fair market value of assets. The funding liability is based upon a weighted-average 24-month corporate bond rate published by the U.S. Treasury which is generally subject to a corridor of the 25-year average of prior segment rates. Periodic changes in asset returns and interest rates can affect funding shortfalls and future cash contributions.

Entergy contributed $45.2 million to its other postretirement plans in 2025 and plans to contribute $40.9 million in 2026.

Other Contingencies

As a company with multi-state utility operations, Entergy is subject to a number of federal and state laws and regulations and other factors and conditions in the areas in which it operates, which potentially subjects it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a provision for those matters which are considered probable and estimable in accordance with GAAP.

Environmental

Entergy must comply with environmental laws and regulations applicable to air emissions, water discharges, solid waste (including coal combustion residuals), hazardous waste, toxic substances, protected species, and other environmental matters. Under these various laws and regulations, Entergy could incur substantial costs to comply or address any impacts to the environment. Entergy conducts studies to determine the extent of any required remediation and has recorded liabilities based upon its evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites or issues could be identified which require environmental remediation or corrective action for which Entergy could be liable. The amounts of environmental liabilities recorded can be significantly affected by the following external events or conditions.

•Changes to existing federal, state, or local regulation or related policies by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters.

•The identification of additional impacts, sites, issues, or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party.

•The resolution or progression of existing matters through the court system or resolution by the EPA or relevant state or local authority.

Litigation

Entergy is regularly named as a defendant in a number of lawsuits involving employment, customers, and injuries and damages issues, among other matters. Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably possible, or remote and records liabilities for cases that have a probable likelihood of loss and the loss can be estimated. Given the

Table of Contents

Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, the ultimate outcome of the litigation to which Entergy is exposed has the potential to materially affect the results of operations, financial position, and cash flows of Entergy or the Registrant Subsidiaries.

New Accounting Pronouncements

See Note 1 to the financial statements for discussion of new accounting pronouncements.

Table of Contents

ENTERGY CORPORATION AND SUBSIDIARIES

REPORT OF MANAGEMENT

Management of Entergy Corporation and its subsidiaries has prepared and is responsible for the financial statements and related financial information included in this document. To meet this responsibility, management establishes and maintains a system of internal controls over financial reporting designed to provide reasonable assurance regarding the preparation and fair presentation of financial statements in accordance with generally accepted accounting principles. This system includes communication through written policies and procedures, an employee Code of Entegrity, and an organizational structure that provides for appropriate division of responsibility and training of personnel. This system is also tested by a comprehensive internal audit program.

Entergy management assesses the design and effectiveness of Entergy’s internal control over financial reporting on an annual basis. In making this assessment, management uses 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. Management acknowledges, however, that all internal control systems, no matter how well designed, have inherent limitations and can provide only reasonable assurance with respect to financial statement preparation and presentation.

Entergy Corporation’s independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the effectiveness of Entergy Corporation’s internal control over financial reporting as of December 31, 2025.

In addition, the Audit Committee of the Board of Directors, composed solely of independent Directors, meets with the independent auditors, internal auditors, management, and internal accountants periodically to discuss internal controls, and auditing and financial reporting matters. The Audit Committee appoints the independent auditors annually, seeks shareholder ratification of the appointment, and reviews with the independent auditors the scope and results of the audit effort. The Audit Committee also meets periodically with the independent auditors and the chief internal auditor without management present, providing free access to the Audit Committee.

Based on management’s assessment of internal controls using the 2013 COSO criteria, management believes that Entergy and each of the Registrant Subsidiaries maintained effective internal control over financial reporting as of December 31, 2025. Management further believes that this assessment, combined with the policies and procedures noted above, provides reasonable assurance that Entergy’s and each of the Registrant Subsidiaries’ financial statements are fairly and accurately presented in accordance with generally accepted accounting principles.


ANDREW S. MARSH Chair of the Board and Chief Executive Officer of Entergy Corporation			KIMBERLY A. FONTAN Executive Vice President and Chief Financial Officer of Entergy Corporation, Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, LLC, Entergy New Orleans, LLC, Entergy Texas, Inc., and System Energy Resources, Inc. Chair of the Board and President of System Energy Resources, Inc.
LAURA R. LANDREAUX Chair of the Board, President, and Chief Executive Officer of Entergy Arkansas, LLC			PHILLIP R. MAY, JR. Chairman of the Board, President, and Chief Executive Officer of Entergy Louisiana, LLC
HALEY R. FISACKERLY Chairman of the Board, President, and Chief Executive Officer of Entergy Mississippi, LLC			DEANNA D. RODRIGUEZ Chair of the Board, President, and Chief Executive Officer of Entergy New Orleans, LLC
ELIECER VIAMONTES Chairman of the Board, President, and Chief Executive Officer of Entergy Texas, Inc.

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and Board of Directors of

Entergy Corporation and Subsidiaries

Opinion on the Financial Statements

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

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Corporation’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 19, 2026, expressed an unqualified opinion on the Corporation’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on the Corporation’s financial statements based on our audits. 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 US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

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

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

Critical Audit Matter Description

The Corporation is subject to rate regulation by their respective state or local utility regulatory agencies and wholesale regulation by the Federal Energy Regulatory Commission (collectively, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

Table of Contents

The Corporation’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the Commissions set the rates, the Corporation is allowed to charge customers based on allowable costs, including a reasonable return on equity, and the Corporation applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Corporation assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Corporation has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.

We identified the impact of rate regulation as a critical audit matter due to the judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and the likelihood of refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the Commissions, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities involved specialized knowledge of accounting for rate regulation and the rate-setting process due to its inherent complexities and auditor judgment to evaluate management estimates and the subjectivity of audit evidence.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of regulatory assets; and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•We evaluated the Corporation’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•We read relevant regulatory orders issued by the Commissions for the Corporation to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated external information and compared to management’s recorded regulatory asset and liability balances for completeness.

•For regulatory matters in process, we inspected the Corporation’s and intervenors’ filings with the Commissions, initial Administrative Law Judge decisions and orders issued, and settlement offers and agreements with the Commissions for any evidence that might contradict management’s assertions.

•We obtained an analysis from management and support from the Corporation’s internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order, to assess management’s assertion that amounts are probable of recovery or refund or a future reduction in rates.

•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery, refund, or a future reduction in rates.

Entergy Texas Build-to-Suit Lease Arrangement for the Legend Power Station — Entergy Corporation and Subsidiaries — Refer to Note 8 to the financial statements

Critical Audit Matter Description

In December 2025, the Corporation entered into a build-to-suit lease arrangement for the Legend Power Station (the “Facility”) as the lessee with a consortium of investors (“the Investors”). Under the terms of the arrangement, the

Table of Contents

Investors purchased the in-process Facility from the Corporation at cost of $359 million and will spend up to $1.45 billion (including the initial purchase price) to construct the Facility as designed by the Corporation. The Corporation is engaged to serve as the construction agent for the Facility. The Investors, however, control the Facility during construction. If the Corporation defaults in its role as construction agent, the Investors have various options available to remedy the default, including by accelerating the lease balance payable by the Corporation, causing a sale of the Facility to a third party, or certain other options. If there are certain changes to the terms of the Public Utility Commission of Texas (“PUCT”) approval of the Facility or certain other circumstances outside of the Corporation’s control, then either the Investors or the Corporation could exercise the right to terminate the arrangement, in which case the Corporation would be required to purchase the in-process Facility from the Investors at an amount equal to their costs incurred to date, including carrying costs. Since the Corporation does not control the in-process Facility, it will not recognize the Facility (i.e., construction work in progress) or an associated liability during construction.

Upon the Facility’s readiness for first synchronization to the grid, expected in early 2028, a triple-net lease will commence under which the Corporation will have control of the Facility and receive all output from the plant.

We identified management’s conclusion that the Corporation does not control the Facility being constructed before the commencement of the lease (i.e., during the construction period) and thus is not the deemed accounting owner of the Facility during the construction period as a critical audit matter due to the judgments made by management to support its conclusion. Auditing management’s judgments involved especially subjective judgment and specialized knowledge of accounting for lease transactions.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the build-to-suit lease arrangement for the Facility included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the accounting impact of this build-to-suit lease arrangement, including the conclusion that the Corporation does not control the Facility being constructed before the commencement of the lease.

•We evaluated the Corporation’s disclosures related to the impacts of the build-to-suit lease arrangement.

•We read relevant transaction documents between the Corporation and the Investors as well as regulatory orders issued by the PUCT for the Corporation and evaluated the external information to compare to management’s conclusions.

•We obtained an analysis from management to assess management’s assertion that the Corporation does not control the Facility being constructed before the commencement date of the lease.

•With the assistance of professionals in our firm having expertise and experience in addressing the accounting for build-to-suit lease arrangements, we evaluated the Corporation’s analysis, including the conclusion that the Corporation does not control the Facility being constructed before the commencement date of the lease.

•We obtained representation from management regarding the conclusion that the Corporation does not control the Facility being constructed before the commencement date of the lease.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 19, 2026

We have served as the Corporation’s auditor since 2001.

Table of Contents


ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands, Except Share Data)

OPERATING REVENUES
Electric	$12,775,314	$11,627,732	$11,842,454
Natural gas	112,607	178,070	180,490
Other	58,765	73,851	124,468
TOTAL	12,946,686	11,879,653	12,147,412

OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale	2,359,403	2,256,874	2,801,580
Purchased power	1,240,998	839,236	968,036
Nuclear refueling outage expenses	113,429	147,019	150,147
Other operation and maintenance	3,055,097	2,898,237	2,898,213
Asset write-offs, impairments, and related charges (credits)	12,795	107,134	42,679
Decommissioning	227,876	220,080	206,674
Taxes other than income taxes	818,664	752,948	755,574
Depreciation and amortization	2,077,692	2,013,168	1,845,003
Other regulatory charges (credits) - net	(161,546)	(6,133)	(138,469)
TOTAL	9,744,408	9,228,563	9,529,437

OPERATING INCOME	3,202,278	2,651,090	2,617,975

OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	180,726	133,046	98,493
Interest and investment income	317,348	298,865	162,726
Miscellaneous - net	(92,421)	(489,970)	(201,013)
TOTAL	405,653	(58,059)	60,206

INTEREST EXPENSE
Interest expense	1,412,955	1,203,588	1,046,164
Allowance for borrowed funds used during construction	(76,304)	(52,768)	(39,758)
TOTAL	1,336,651	1,150,820	1,006,406

INCOME BEFORE INCOME TAXES	2,271,280	1,442,211	1,671,775

Income taxes	497,952	381,027	(690,535)

CONSOLIDATED NET INCOME	1,773,328	1,061,184	2,362,310

Preferred dividend requirements of subsidiaries and noncontrolling interests	15,056	5,594	5,774

NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$1,758,272	$1,055,590	$2,356,536

Earnings per average common share:
Basic	$3.98	$2.47	$5.57
Diluted	$3.91	$2.45	$5.55

Basic average number of common shares outstanding	442,029,481	427,713,121	423,139,862
Diluted average number of common shares outstanding	450,151,884	431,581,696	424,752,990

See Notes to Financial Statements.

Table of Contents

(Page left blank intentionally)

Table of Contents


ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands)

Net Income	$1,773,328	$1,061,184	$2,362,310

Other comprehensive income (loss)
Pension and other postretirement plan changes
(net of tax expense (benefit) of ($15,138), $54,711, and $9,248)	(45,775)	205,229	29,294
Other comprehensive income (loss)	(45,775)	205,229	29,294

Comprehensive Income	1,727,553	1,266,413	2,391,604
Preferred dividend requirements of subsidiaries and noncontrolling interests	15,056	5,594	5,774
Comprehensive Income Attributable to Entergy Corporation	$1,712,497	$1,260,819	$2,385,830

See Notes to Financial Statements.

Table of Contents


ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands)

OPERATING ACTIVITIES
Consolidated net income	$1,773,328	$1,061,184	$2,362,310
Adjustments to reconcile consolidated net income to net cash flow provided by operating activities:
Depreciation, amortization, and decommissioning, including nuclear fuel amortization	2,537,138	2,443,562	2,244,479
Deferred income taxes, tax credits, and non-current taxes accrued	1,015,509	320,705	(707,822)
Asset write-offs, impairments, and related charges (credits)	12,795	107,134	42,679
Pension settlement charge	—	319,675	—
Changes in working capital:
Receivables	(79,833)	3,056	101,801
Fuel inventory	38,927	21,898	(45,166)
Accounts payable	38,755	111,839	(135,048)
Taxes accrued	68,083	22,893	10,122
Interest accrued	26,103	45,357	18,933
Deferred fuel costs	(271,109)	182,578	759,361
Other working capital accounts	296,714	(19,177)	(210,038)
Changes in provisions for estimated losses	(10,284)	43,493	(68,631)
Changes in regulatory assets	284,914	378,514	435,877
Changes in other regulatory liabilities	180,811	660,559	463,805
Change in customer advances - non-current	35,000	—	—
Effect of securitization on regulatory asset	—	—	(491,150)
Changes in pension and other postretirement funded status	(278,186)	(469,721)	(610,479)
Other	(518,014)	(745,039)	123,295
Net cash flow provided by operating activities	5,150,651	4,488,510	4,294,328

INVESTING ACTIVITIES
Construction/capital expenditures	(7,684,922)	(4,838,339)	(4,440,652)
Allowance for equity funds used during construction	180,726	133,046	98,493
Nuclear fuel purchases	(252,912)	(309,437)	(270,973)
Payment for purchase of plant and assets	(3,517)	(821,934)	(35,094)
Proceeds from sale of business and assets	858,588	—	11,000
Insurance proceeds received for property damages	—	7,907	19,493
Changes in securitization account	2,834	3,308	5,493
Payments to storm reserve escrow accounts	(14,894)	(17,990)	(19,780)
Receipts from storm reserve escrow accounts	46,570	736	98,529
Decrease (increase) in other investments	(113,388)	212	(16,733)
Litigation proceeds for reimbursement of spent nuclear fuel storage costs	3,546	82,412	23,655
Proceeds from nuclear decommissioning trust fund sales	1,509,997	2,805,145	1,082,722
Investment in nuclear decommissioning trust funds	(1,642,082)	(2,894,076)	(1,185,130)
Net cash flow used in investing activities	(7,109,454)	(5,849,010)	(4,628,977)

See Notes to Financial Statements.

Table of Contents


ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands)

FINANCING ACTIVITIES
Proceeds from the issuance of:
Long-term debt	5,750,445	7,898,968	4,273,297
Treasury stock	36,641	136,794	9,823
Common stock	1,136,103	—	130,649
Retirement of long-term debt	(3,501,800)	(5,054,094)	(5,135,753)
Changes in commercial paper - net	(269,517)	(210,880)	310,550
Capital contributions from noncontrolling interests	—	—	25,708
Proceeds received by storm trusts related to securitization	—	—	1,457,676
Customer advances received for construction	1,643,765	547,500	259,505
Customer advances used for construction	(662,896)	(204,991)	(108,903)
Other	(12,255)	(25,664)	(43,007)
Dividends paid:
Common stock	(1,074,151)	(981,659)	(918,193)
Preferred stock	(18,319)	(18,319)	(18,319)
Net cash flow provided by financing activities	3,028,016	2,087,655	243,033

Net increase (decrease) in cash and cash equivalents	1,069,213	727,155	(91,616)

Cash and cash equivalents at beginning of period	859,703	132,548	224,164

Cash and cash equivalents at end of period	$1,928,916	$859,703	$132,548

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$1,238,284	$1,114,631	$987,252
Income taxes - net (includes production tax credit sale proceeds of $547,261 in 2025, $— in 2024, and $— in 2023)	($515,071)	$41,551	$42,821
Noncash investing activities:
Accrued construction expenditures	$800,047	$615,490	$487,439

See Notes to Financial Statements.

Table of Contents


ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS

	December 31,
	2025	2024
	(In Thousands)

CURRENT ASSETS
Cash and cash equivalents:
Cash	$45,895	$48,424
Temporary cash investments	1,883,021	811,279
Total cash and cash equivalents	1,928,916	859,703
Accounts receivable:
Customer	735,734	681,504
Allowance for doubtful accounts	(32,324)	(17,919)
Other	242,402	204,868
Accrued unbilled revenues	524,420	521,946
Total accounts receivable	1,470,232	1,390,399
Deferred fuel costs	54,133	—
Fuel inventory - at average cost	131,974	166,408
Materials and supplies	1,710,395	1,631,056
Deferred nuclear refueling outage costs	86,497	99,885
Current assets held for sale	—	15,574
Prepayments and other	424,704	233,212
TOTAL	5,806,851	4,396,237

OTHER PROPERTY AND INVESTMENTS
Decommissioning trust funds	6,300,880	5,562,575
Non-utility property - at cost (less accumulated depreciation)	481,590	423,764
Storm reserve escrow accounts	308,784	340,460
Other	124,414	82,344
TOTAL	7,215,668	6,409,143

PROPERTY, PLANT, AND EQUIPMENT
Electric	74,750,917	70,818,667
Natural gas	—	77,054
Construction work in progress	6,020,008	3,206,308
Nuclear fuel	834,690	765,661
TOTAL PROPERTY, PLANT, AND EQUIPMENT	81,605,615	74,867,690
Less - accumulated depreciation and amortization	28,751,001	27,444,740
PROPERTY, PLANT, AND EQUIPMENT - NET	52,854,614	47,422,950

DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Other regulatory assets (includes securitization property of $216,107 as of December 31, 2025 and $234,112 as of December 31, 2024)	5,005,976	5,255,509
Deferred fuel costs	172,201	172,201
Goodwill	367,582	367,625
Accumulated deferred income taxes	15,540	18,986
Non-current assets held for sale	—	462,797
Other	452,298	284,584
TOTAL	6,013,597	6,561,702

TOTAL ASSETS	$71,890,730	$64,790,032

See Notes to Financial Statements.

Table of Contents


ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY

	December 31,
	2025	2024
	(In Thousands)

CURRENT LIABILITIES
Currently maturing long-term debt	$2,375,140	$1,378,090
Notes payable and commercial paper	657,774	927,291
Accounts payable	2,565,546	1,929,162
Customer deposits	479,796	462,436
Taxes accrued	525,189	457,093
Interest accrued	285,657	259,554
Deferred fuel costs	14,562	237,146
Pension and other postretirement liabilities	63,214	64,854
Customer advances	632,850	151,662
Other	223,240	243,749
TOTAL	7,822,968	6,111,037

NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	5,592,681	4,467,748
Accumulated deferred investment tax credits	187,173	194,146
Regulatory liability for income taxes - net	1,079,699	1,168,078
Other regulatory liabilities	3,911,839	3,609,463
Customer advances	35,000	—
Decommissioning and asset retirement cost liabilities	4,947,530	4,713,426
Accumulated provisions	495,779	506,063
Pension and other postretirement liabilities	113,930	254,704
Long-term debt (includes securitization bonds of $221,139 as of December 31, 2025 and $239,622 as of December 31, 2024)	27,902,021	26,613,505
Customer advances for construction	1,615,455	634,587
Other	953,078	1,112,881
TOTAL	46,834,185	43,274,601

Commitments and Contingencies

Subsidiaries’ preferred stock without sinking fund	219,410	219,410

EQUITY
Preferred stock, no par value, authorized 1,000,000 shares in 2025 and 2024; issued shares in 2025 and 2024 - none	—	—
Common stock, $0.01 par value, authorized 998,000,000 shares in 2025 and 2024; issued 583,203,774 shares in 2025 and 561,950,696 shares in 2024	5,832	5,620
Paid-in capital	8,979,387	7,833,525
Retained earnings	12,698,436	12,014,315
Accumulated other comprehensive income (loss)	(3,006)	42,769
Less - treasury stock, at cost (130,864,409 shares in 2025 and 132,370,280 shares in 2024)	4,757,573	4,812,321
Total shareholders’ equity	16,923,076	15,083,908
Subsidiaries’ preferred stock without sinking fund and noncontrolling interests	91,091	101,076
TOTAL	17,014,167	15,184,984

TOTAL LIABILITIES AND EQUITY	$71,890,730	$64,790,032

See Notes to Financial Statements.

Table of Contents


ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2025, 2024, and 2023

		Shareholders’ Equity
	Subsidiaries’ Preferred Stock and Noncontrolling Interests	Common Stock	Treasury Stock	Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Total
	(In Thousands)
Balance at December 31, 2022	$97,907	$5,594	($4,978,994)	$7,630,098	$10,502,041	($191,754)	$13,064,892
Consolidated net income (a)	5,774	—	—	—	2,356,536	—	2,362,310
Other comprehensive income	—	—	—	—	—	29,294	29,294
Common stock issuances and sales under the at the market equity distribution program	—	26	—	132,391	—	—	132,417
Common stock issuance costs	—	—	—	(1,768)	—	—	(1,768)
Common stock issuances related to stock plans	—	—	25,496	31,880	—	—	57,376
Common stock dividends declared	—	—	—	—	(918,193)	—	(918,193)
Beneficial interest in storm trust	14,577	—	—	—	—	—	14,577
Capital contributions from noncontrolling interest	25,708	—	—	—	—	—	25,708
Distributions to noncontrolling interests	(5,188)	—	—	—	—	—	(5,188)
Preferred dividend requirements of subsidiaries (a)	(18,319)	—	—	—	—	—	(18,319)
Balance at December 31, 2023	$120,459	$5,620	($4,953,498)	$7,792,601	$11,940,384	($162,460)	$14,743,106
Consolidated net income (a)	5,594	—	—	—	1,055,590	—	1,061,184
Other comprehensive income	—	—	—	—	—	205,229	205,229


Common stock issuances related to stock plans	—	—	141,177	40,924	—	—	182,101
Common stock dividends declared	—	—	—	—	(981,659)	—	(981,659)
Distributions to noncontrolling interests	(6,658)	—	—	—	—	—	(6,658)
Preferred dividend requirements of subsidiaries (a)	(18,319)	—	—	—	—	—	(18,319)
Balance at December 31, 2024	$101,076	$5,620	($4,812,321)	$7,833,525	$12,014,315	$42,769	$15,184,984
Consolidated net income (a)	15,056	—	—	—	1,758,272	—	1,773,328
Other comprehensive loss	—	—	—	—	—	(45,775)	(45,775)
Common stock issuances and sales under the at the market equity distribution program	—	212	—	1,148,890	—	—	1,149,102
Common stock issuance costs	—	—	—	(13,000)	—	—	(13,000)
Common stock issuances related to stock plans	—	—	54,748	9,972	—	—	64,720
Common stock dividends declared	—	—	—	—	(1,074,151)	—	(1,074,151)
Distributions to noncontrolling interests	(6,722)	—	—	—	—	—	(6,722)
Preferred dividend requirements of subsidiaries (a)	(18,319)	—	—	—	—	—	(18,319)
Balance at December 31, 2025	$91,091	$5,832	($4,757,573)	$8,979,387	$12,698,436	($3,006)	$17,014,167

See Notes to Financial Statements.

(a) Consolidated net income and preferred dividend requirements of subsidiaries include $16 million for 2025, 2024, and 2023 of preferred dividends on subsidiaries’ preferred stock without sinking fund that is not presented as equity.

Table of Contents

ENTERGY CORPORATION AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

The accompanying consolidated financial statements include the accounts of Entergy Corporation and its subsidiaries. As required by GAAP in the United States of America, all intercompany transactions have been eliminated in the consolidated financial statements. Entergy’s Registrant Subsidiaries (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy) also include their separate financial statements in this Form 10-K. Certain previously reported amounts in the financial statements have been reclassified to conform to current classification, with no effect on results of operations, financial positions, or cash flows. The Registrant Subsidiaries and many other Entergy subsidiaries also maintain accounts in accordance with FERC and other regulatory guidelines.

Use of Estimates in the Preparation of Financial Statements

In conformity with GAAP in the United States of America, the preparation of Entergy Corporation’s consolidated financial statements and the separate financial statements of the Registrant Subsidiaries requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses, and the disclosure of contingent assets and liabilities. Adjustments to the reported amounts of assets and liabilities may be necessary in the future to the extent that future estimates or actual results are different from the estimates used.

Revenues and Fuel Costs

See Note 19 to the financial statements for a discussion of Entergy’s and the Registrant Subsidiaries’ revenues and fuel costs.

Customer Advances

Certain large industrial customers are required by Entergy’s Regulators to make advance payments in excess of what would typically be required under existing utility rates to offset the costs the Utility operating companies will incur to serve the customer. The Utility operating companies will be required to include the revenue related to these additional payments in ratemaking in future periods to offset the costs of serving the customer that made the payment. In some cases, the advance payment is designed to provide the Utility operating companies with a return on construction work in progress for utility plant investments typically received through the recognition of AFUDC (as defined and described further below). In such cases, AFUDC is not added to the associated construction work in progress, which results in a lower amount of utility plant recovered through utility rates. Customer advances are initially recorded as a current or non-current liability and then recognized as revenue as the related costs are incurred.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less regulatory disallowances and impairments. Depreciation is computed on the straight-line basis at rates based on the applicable estimated service lives of the various classes of property. For the Registrant Subsidiaries, the original cost of plant retired or removed, less salvage, is charged to accumulated depreciation. Normal maintenance, repairs, and minor replacement costs are charged to operating expenses. Certain combined cycle gas turbine generating units are maintained under long-term service agreements with third-party service providers. The costs under these

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

agreements are split between operating expenses and capital additions based upon the nature of the work performed. Substantially all of the Registrant Subsidiaries’ plant is subject to mortgage liens.

Customers may be required to make advance payments to reimburse the Utility operating companies for costs of constructing new utility plants that are not expected to be recovered through existing retail rates. Under the regulatory framework, these payments are required to ensure the cost to serve a particular customer does not increase the utility rates charged to other utility customers. These advance payments generally do not reduce the retail rate charged to the customer making the payment and do not create any additional obligation for the respective Utility operating company to provide electrical service beyond the general obligation to serve all customers in its service area. Because the cost is fully reimbursed by the customer through the advance payment, the Utility operating company does not earn a return or recover through retail rates the cost of utility plant reimbursed by these payments. These advance payments are initially recorded as a non-current liability, which is then reduced by the costs incurred to construct the associated utility plant. This results in Entergy and the Utility operating companies recording utility plant funded by customer advances at a net cost of zero, consistent with utility ratemaking treatment.

Electric plant includes the portion of Grand Gulf that was sold and leased back in a prior period. For financial reporting purposes, this sale and leaseback arrangement is reported as a financing transaction.

Net property, plant, and equipment (including property under lease and associated accumulated amortization) for Entergy by functional category, as of December 31, 2025 and 2024, is shown below:


	2025	2024
	(In Millions)
Production
Nuclear	$8,591	$8,024
Other	7,721	7,809
Transmission	11,116	10,414
Distribution	16,374	14,321
Other	2,198	3,286
Construction work in progress	6,020	3,209
Nuclear fuel	835	766
Property, plant, and equipment - net (a)	$52,855	$47,829

(a)Includes $403 million of natural gas property, plant, and equipment and accumulated depreciation and $3 million of construction work in progress classified as held for sale in “Non-current assets held for sale” on Entergy’s consolidated balance sheet as of December 31, 2024. See Note 14 to the financial statements for further discussion of the sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses on July 1, 2025 and the classification as held for sale as of December 31, 2024.

Depreciation rates on average depreciable property for Entergy approximated 2.9% in 2025, 2.9% in 2024, and 2.9% in 2023.

Entergy amortizes nuclear fuel using a units-of-production method. Nuclear fuel amortization is included in fuel expense in the income statements.

Non-utility property - at cost (less accumulated depreciation) for Entergy is reported net of accumulated depreciation of $251 million as of December 31, 2025 and $231 million as of December 31, 2024.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Net property, plant, and equipment (including property under lease and associated accumulated amortization) for the Registrant Subsidiaries by functional category, as of December 31, 2025 and 2024, is shown below:


2025	Entergy Arkansas	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Millions)
Production
Nuclear	$2,077	$4,473	$—	$—	$—	$2,041
Other	1,691	3,516	993	378	1,098	—
Transmission	2,195	4,578	1,748	168	2,397	28
Distribution	4,056	5,843	2,696	835	2,944	—
Other	418	722	293	108	288	5
Construction work in progress	621	2,032	1,396	43	1,761	123
Nuclear fuel	303	323	—	—	—	209
Property, plant, and equipment - net	$11,361	$21,487	$7,126	$1,532	$8,488	$2,406


2024	Entergy Arkansas	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Millions)
Production
Nuclear	$1,887	$4,121	$—	$—	$—	$2,016
Other	1,721	3,532	980	374	1,154	—
Transmission	2,267	4,339	1,567	155	2,054	30
Distribution	3,615	4,973	2,418	761	2,554	—
Other	606	1,175	385	384	318	44
Construction work in progress	320	762	487	20	1,513	85
Nuclear fuel	258	288	—	—	—	220
Property, plant, and equipment - net (a)	$10,674	$19,190	$5,837	$1,694	$7,593	$2,395

(a)Includes $164 million of natural gas property, plant, and equipment and accumulated depreciation and $1 million of construction work in progress for Entergy Louisiana and $239 million of natural gas property, plant, and equipment and accumulated depreciation and $2 million of construction work in progress for Entergy New Orleans classified as held for sale in “Non-current assets held for sale” on their respective consolidated balance sheet as of December 31, 2024. See Note 14 to the financial statements for further discussion of the sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses on July 1, 2025 and the classification as held for sale as of December 31, 2024.

Depreciation rates on average depreciable property for the Registrant Subsidiaries are shown below:


	Entergy Arkansas	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
2025	2.8%	2.7%	3.4%	3.3%	3.6%	2.1%
2024	2.7%	2.7%	3.5%	3.3%	3.8%	2.1%
2023	2.7%	2.6%	3.6%	3.3%	4.0%	1.6%

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $240.8 million as of December 31, 2025 and $225.4 million as of December 31, 2024. Non-utility property - at cost (less accumulated depreciation) for Entergy Mississippi is reported net of accumulated depreciation of $0.6 million as of December 31, 2025 and $0.5 million as of December 31, 2024.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Jointly-Owned Generating Stations

Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties. All parties are required to provide their own financing. The investments, fuel expenses, and other operation and maintenance expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, 2025, the subsidiaries’ investment and accumulated depreciation in each of these generating stations were as follows:


Generating Stations		Fuel Type	Total Megawatt Capability (a)	Ownership		Investment	Accumulated Depreciation
						(In Millions)
Utility:
Entergy Arkansas -
Independence	Unit 1	Coal	824	31.50	%	$153	$110
Independence	Common Facilities	Coal		15.75	%	$43	$33
White Bluff	Units 1 and 2	Coal	1,253	57.00	%	$624	$424
Ouachita (b)	Common Facilities	Gas		66.67	%	$174	$162
Union (c)	Common Facilities	Gas		25.00	%	$29	$15
Entergy Louisiana -
Roy S. Nelson	Unit 6	Coal	514	40.25	%	$302	$237
Roy S. Nelson	Unit 6 Common Facilities	Coal		40.25	%	$22	$11
Big Cajun 2	Unit 3	Coal	551	24.15	%	$146	$142
Big Cajun 2	Unit 3 Common Facilities	Coal		8.05	%	$5	$3
Ouachita (b)	Common Facilities	Gas		33.33	%	$91	$80
Acadia	Common Facilities	Gas		50.00	%	$22	$4
Union (c)	Common Facilities	Gas		50.00	%	$58	$17
Entergy Mississippi -
Independence	Units 1 and 2 and Common Facilities	Coal	1,666	25.00	%	$307	$204
Entergy New Orleans -
Union (c)	Common Facilities	Gas		25.00	%	$30	$12
Entergy Texas -
Roy S. Nelson	Unit 6	Coal	514	29.75	%	$213	$178
Roy S. Nelson	Unit 6 Common Facilities	Coal		29.75	%	$8	$5
Big Cajun 2	Unit 3	Coal	551	17.85	%	$109	$129
Big Cajun 2	Unit 3 Common Facilities	Coal		5.95	%	$4	$3
Montgomery County	Unit 1	Gas	940	92.44	%	$761	$54
System Energy -
Grand Gulf (d)	Unit 1	Nuclear	1,397	90.00	%	$5,763	$3,681
Other:
Independence	Unit 2	Coal	842	14.37	%	$82	$63
Independence	Common Facilities	Coal		7.18	%	$21	$17
Roy S. Nelson	Unit 6	Coal	514	10.90	%	$121	$79
Roy S. Nelson	Unit 6 Common Facilities	Coal		10.90	%	$3	$2

(a)“Total Megawatt 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.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

(b)Ouachita Units 1 and 2 are owned 100% by Entergy Arkansas and Ouachita Unit 3 is owned 100% by Entergy Louisiana. The investment and accumulated depreciation numbers above are only for the common facilities and not for the generating units.

(c)Union Unit 1 is owned 100% by Entergy New Orleans, Union Unit 2 is owned 100% by Entergy Arkansas, Union Units 3 and 4 are owned 100% by Entergy Louisiana. The investment and accumulated depreciation numbers above are only for the specified common facilities and not for the generating units.

(d)Includes a leasehold interest held by System Energy. System Energy’s Grand Gulf lease obligations are discussed in Note 5 to the financial statements.

Nuclear Refueling Outage Costs

Nuclear refueling outage costs are deferred during the outage and amortized over the estimated period to the next outage because these refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line.

Allowance for Funds Used During Construction (AFUDC)

AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction by the Registrant Subsidiaries. AFUDC increases both the plant balance and earnings and is realized in cash through depreciation provisions included in the rates charged to customers.

Income Taxes

Entergy Corporation and the majority of its subsidiaries file a United States consolidated federal income tax return. Each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the tax filing entities in accordance with the Entergy Tax Allocation Agreement. Deferred income taxes are recorded for temporary differences between the book and tax basis of assets and liabilities, and for certain losses and credits available for carryforward.

Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates in the period in which the tax or rate was enacted.

The benefits of investment tax credits are deferred and amortized over the average useful life of the related property, as a reduction of income tax expense, for such credits associated with rate-regulated operations in accordance with ratemaking treatment.

Accounting for the Effects of Regulation

Entergy’s Utility operating companies and System Energy are rate-regulated entities that are required to reflect the effects of rate regulation in their financial statements, including the recording of regulatory assets and liabilities, as the Utility operating companies and System Energy have rates that meet the following three criteria: (1) are approved by a third-party regulator; (2) are designed to recover the entities’ cost of providing the regulated services or products; and (3) can reasonably be assumed will be charged to and collected from customers. These criteria may also be applied to separable portions of a utility’s business, such as the generation or transmission functions, or to specific classes of customers.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

rate regulation, or future recovery or settlement is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are eliminated from the balance sheet and the impact is recognized on the income statement.

In addition, regulatory accounting requires recognition of an impairment loss if it becomes probable that part of the cost of a recently completed plant asset will be disallowed for rate-making purposes and a reasonable estimate of the amount of the disallowance can be made.

Entergy Louisiana does not apply regulatory accounting standards to the Louisiana retail deregulated portion of River Bend or to the 30% interest in River Bend formerly owned by Cajun unless specific cost recovery is provided for in tariff rates. The Louisiana retail deregulated portion of River Bend is operated under a deregulated asset plan representing a portion (approximately 15%) of River Bend plant costs, generation, revenues, and expenses established under a 1992 LPSC order. The plan allows Entergy Louisiana to sell the electricity from the deregulated assets to Louisiana retail customers at 4.6 cents per kWh or off-system at higher prices, with certain provisions for sharing incremental revenue above 4.6 cents per kWh between customers and shareholders.

Regulatory Asset or Liability for Income Taxes

Accounting standards for income taxes provide that a regulatory asset or liability be recorded if it is probable that the currently determinable future increase or decrease in regulatory income tax expense will be recovered from or credited to customers through future rates. There are two main sources of Entergy’s regulatory asset or liability for income taxes. There is a regulatory asset related to the ratemaking treatment of the tax effects of book depreciation for the equity component of AFUDC that has been capitalized to property, plant, and equipment but for which there is no corresponding tax basis. Equity-AFUDC is a component of property, plant, and equipment that is included in rate base when the plant is placed in service. There is a regulatory liability related to the adjustment of Entergy’s net deferred income taxes that was required by the enactment in December 2017 of a change in the federal corporate income tax rate, which is discussed in Note 3 to the financial statements.

Cash and Cash Equivalents

Entergy considers all unrestricted highly liquid debt instruments with an original maturity of three months or less at date of purchase to be cash equivalents.

Securitization Recovery Trust Accounts

The funds that Entergy New Orleans and Entergy Texas hold in their securitization recovery trust accounts are not classified as cash and cash equivalents or restricted cash and cash equivalents because of their nature, uses, and restrictions. These funds are classified as part of other current assets and other investments, depending on the timeframe within which the Registrant Subsidiary expects to use the funds.

Allowance for Doubtful Accounts

The allowance for doubtful accounts reflects Entergy’s best estimate of expected losses on its accounts receivable balances. The allowance is calculated as the historical rate of customer write-offs multiplied by the current accounts receivable balance, taking into account the length of time the receivable balances have been outstanding. Although the rate of customer write-offs has historically experienced minimal variation, management monitors the current condition of individual customer accounts and general economic conditions to manage collections and ensure bad debt expense is recorded in a timely manner. The Utility operating companies’ customer accounts receivable are written off consistent with approved regulatory requirements. See Note 19 to the financial statements for further details on the allowance for doubtful accounts.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Materials and Supplies

Materials and supplies consist of tangible goods, equipment, and other materials that Entergy holds for use or consumption in the normal course of business, whether for capital projects or operation and maintenance activities, or that are required to be kept for regulatory reasons or service reliability. Materials and supplies are valued at a weighted average unit cost when expensed or capitalized, as appropriate, when used or installed. Materials and supplies are valued at the lower of weighted average cost or net realizable value, net of provisions for surplus and obsolete materials and supplies.

Investments

Entergy records decommissioning trust funds on the balance sheet at their fair value. Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, for unrealized gains/(losses) on investment securities, the Registrant Subsidiaries record an offsetting amount in other regulatory liabilities/assets. For the 30% interest in River Bend formerly owned by Cajun, Entergy Louisiana records an offsetting amount in other long-term liabilities on the consolidated balance sheets of Entergy and Entergy Louisiana for the unrealized trust earnings not currently expected to be needed to decommission the plant. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. See Note 16 to the financial statements for details on the decommissioning trust funds.

Partnerships with Disproportionate Allocation of Earnings and Losses in Relation to an Investor’s Ownership Interest

Entergy Arkansas and Entergy Mississippi, as managing members, each control a tax equity partnership with a third party tax equity investor and consolidate the partnerships for financial reporting purposes. For each respective partnership, the limited liability company agreement with the tax equity investor stipulates a disproportionate allocation of tax attributes, earnings, and cash flows between the Registrant Subsidiary and the tax equity investor with the tax equity investor being allocated a significant portion of the tax attributes, earnings, and cash flows until it receives its target return, at which point the earnings and cash flows will primarily be allocated to the Registrant Subsidiary. Each Registrant Subsidiary has the option to purchase, at a future date specified in their respective partnership agreement, the tax equity investor’s interests at the then-current fair market value, plus an amount that results in the tax equity investor reaching its target return, if needed.

Because of this disproportionate allocation, each Registrant Subsidiary accounts for its earnings in the partnership using the HLBV method of accounting. Under the HLBV method, the amounts of income and loss attributable to both the Registrant Subsidiary and the tax equity investor reflect changes in the amount each would hypothetically receive at the balance sheet date under the respective liquidation provisions of the limited liability company agreement, assuming the net assets of the partnership were liquidated at book value, after consideration of contributions and distributions, between the Registrant Subsidiary and the tax equity investor. Once the tax equity investor reaches its target return in the hypothetical liquidation, the remaining proceeds are primarily allocated to the Registrant Subsidiary. This allocation may result in fluctuations of income on a periodic basis that differ significantly from what would otherwise be recognized if the earnings were allocated under the relative ownership percentages between the Registrant Subsidiary and the tax equity investor. Entergy Arkansas and Entergy Mississippi have determined these differences are primarily due to timing, and both the APSC and the MPSC have approved that, for purposes of ratemaking, each Registrant Subsidiary reflect its interest in its respective partnership using its relative ownership percentage and disregard the effects of the HLBV method of accounting. Because of this, each Registrant Subsidiary has recorded a regulatory liability for the difference between the earnings allocated to it under the HLBV method of accounting and the earnings that would have been allocated to it under its respective ownership percentage in the partnership.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Derivative Financial Instruments and Commodity Derivatives

The accounting standards for derivative instruments require that all derivatives be recognized at fair value on the balance sheet, either as assets or liabilities, unless they meet various exceptions including the normal purchase/normal sale criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings. Due to regulatory treatment, an offsetting regulatory asset or liability is recorded for changes in fair value of recognized derivatives for the Registrant Subsidiaries.

Contracts for commodities that will be physically delivered in quantities expected to be used or sold in the ordinary course of business, including certain purchases and sales of power and fuel, meet the normal purchase, normal sales criteria and are not recognized on the balance sheet. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.

Entergy has determined that contracts to purchase uranium do not meet the definition of a derivative under the accounting standards for derivative instruments because they do not provide for net settlement and the uranium markets are not sufficiently liquid to conclude that forward contracts are readily convertible to cash. If the uranium markets do become sufficiently liquid in the future and Entergy begins to account for uranium purchase contracts as derivative instruments, the fair value of these contracts would be accounted for consistent with Entergy’s other derivative instruments. See Note 15 to the financial statements for further details on Entergy’s derivative instruments and hedging activities.

Fair Values

The estimated fair values of Entergy’s financial instruments and derivatives are determined using historical prices, bid prices, market quotes, and financial modeling. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. Gains or losses realized on financial instruments are reflected in future rates and therefore do not affect net income. Entergy considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. See Note 15 to the financial statements for further discussion of fair value.

Impairment of Long-lived Assets

Entergy periodically reviews long-lived assets whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from such operations and assets. Projected net cash flows depend on the expected operating life of the assets, the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy and capacity over the remaining life of the assets.

Assets Held for Sale

A long-lived asset or component of an entity meets the criteria to be classified as held for sale, generally, when management with requisite approvals commits to a plan to sell and it is probable that the sale will be completed within one year. When held for sale criteria is met, the assets and liabilities of the disposal group are separately presented as assets and liabilities held for sale on the balance sheet. Any long-lived assets of the disposal group are measured at the lower of their carrying value or their estimated fair value less costs to sell. If the disposal group meets the definition of a business, then a portion of any goodwill with that reporting unit is allocated to the disposal group based on the relative fair value of the components representing a business that will be retained and disposed.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

As described in Note 14 to the financial statements, the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses met the criteria to be to classified as held for sale as of December 31, 2024, and were subsequently sold on July 1, 2025.

Reacquired Debt

The premiums and costs associated with reacquired debt of Entergy’s Utility operating companies and System Energy (except that portion allocable to the deregulated operations of Entergy Louisiana) are included in regulatory assets and are being amortized over the life of the related new issuances, or over the life of the original debt issuance if the debt is not refinanced, in accordance with ratemaking treatment.

Taxes Imposed on Revenue-Producing Transactions

Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues, unless required to report them differently by a regulatory authority.

New Accounting Pronouncements

The accounting standard-setting process is ongoing, and the FASB is currently working on several projects that have not yet resulted in final pronouncements. Final pronouncements that result from these projects could have a material effect on Entergy’s future results of operations, financial positions, or cash flows.

In March 2024 the SEC issued final rules that require registrants to provide certain climate-related disclosures in annual reports and registration statements in order to enhance and standardize climate-related disclosures for investors. The final rules require a registrant to disclose, among other things: material climate-related risks; activities to mitigate or adapt to such risks; information about the registrant’s board of directors’ oversight of climate-related risks and management’s role in managing material climate-related risks; and information on any climate-related targets or goals that are material to the registrant’s business, results of operations, or financial condition. In addition, the final rules require disclosure of Scope 1 and/or Scope 2 greenhouse gas emissions on a phased-in basis by certain larger registrants when those emissions are material; the filing of an attestation report covering the required disclosure of such registrant’s Scope 1 and/or Scope 2 emissions, also on a phased-in basis; and disclosure of the financial statement effects of severe weather events and other natural conditions. The final rules provide that the phase-in compliance period is effective for Entergy beginning with its annual report for the fiscal year ending December 31, 2025. In April 2024 the SEC stayed the final rules, pending judicial review of consolidated challenges to the rules by the United States Court of Appeals for the Eighth Circuit. In February 2025 then Acting SEC Chairman directed the SEC staff to request that the court not schedule the case for argument to provide time for the SEC to deliberate and determine the appropriate next steps in these cases. In March 2025 the SEC voted to end its defense of the final rules against parties that have legally challenged the rules. In April 2025 the United States Court of Appeals for the Eighth Circuit ordered the litigation to be held in abeyance and directed the SEC to indicate within 90 days whether the SEC would reconsider or review the climate disclosure rules. In July 2025 the SEC submitted a status report to the United States Court of Appeals for the Eighth Circuit stating that it does not intend to review or reconsider its final rules at this time and requesting that the Court of Appeals terminate the abeyance and proceed with its judicial review of the case. In September 2025 the United States Court of Appeals for the Eighth Circuit paused its consideration of legal challenges against the rules, pending further action by the SEC. Entergy will continue to monitor developments related to the SEC’s final rules on climate-related disclosures.

In November 2024 the FASB issued ASU 2024-03, “Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40).” The ASU is intended to improve disclosures around income statement expenses by requiring disaggregated information within the footnotes to the financial statements

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

about specific expense categories in commonly presented income statement expense captions. ASU 2024-03 is effective for Entergy for fiscal years beginning after December 15, 2026. Entergy does not expect ASU 2024-03 to materially affect its results of operations, financial positions, or cash flows.

In September 2025 the FASB issued ASU 2025-06, “Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Targeted Improvements to the Accounting for Internal-Use Software.” The ASU is intended to improve the operability of the guidance around capitalizing development costs incurred for internal-use software by removing all references to software development project stages so that the guidance is neutral to different software development methods. Instead, entities will be required to start capitalizing software costs when management has authorized and committed to funding the project and it is probable that the project will be completed and the software used to perform the function intended. ASU 2025-06 is effective for Entergy for fiscal years beginning after December 15, 2027. Entergy does not expect ASU 2025-06 to materially affect its results of operations, financial positions, or cash flows.

In December 2025 the FASB issued ASU 2025-10, “Government Grants (Topic 832): Accounting for Government Grants Received by Business Entities.” The ASU establishes the accounting for a government grant received by a business entity, including guidance for a grant related to an asset and a grant related to income. Currently, in the absence of specific guidance, many business entities look to other guidance within GAAP or in International Accounting Standards to account for government grants. ASU 2025-10 is effective for Entergy for fiscal years beginning after December 15, 2028. Entergy does not expect ASU 2025-10 to materially affect its results of operations, financial positions, or cash flows.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

NOTE 2. RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Regulatory Assets and Regulatory Liabilities

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be credited to customers through future regulated rates, (2) billings in advance of expenditures for approved regulatory programs, or (3) refunds ordered by regulators. In addition to the regulatory assets and liabilities that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” and “Other regulatory liabilities” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 2025 and 2024 (as noted in footnotes to the tables, a portion of these regulatory assets and regulatory liabilities was classified as held for sale in the balance sheets as of December 31, 2024):

Other Regulatory Assets

Entergy


	2025	2024
	(In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants and solar facilities (Note 9) (a)	$1,437.9	$1,358.7
Removal costs (Note 9)	1,178.9	1,107.6
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	1,067.2	1,207.6
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Securitization Bonds)	481.4	547.3
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)	200.2	227.1
Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined by retail regulators	140.5	195.1
Retired electric and gas meters - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)	117.9	135.7
Non-service pension & postretirement costs (Note 11 - Accounting for Pension and Other Postretirement Benefits)	73.0	180.0
Advanced metering system surcharge for residential customers - recovered through December 2029	53.7	39.7
Unamortized loss on reacquired debt - recovered over term of debt	53.6	57.9
Production tax credits (Note 3 - Other Tax Matters - Inflation Reduction Act of 2022) (b)	47.9	—
Deferred COVID-19 costs - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)	40.3	104.0
Retired distribution plant - resiliency plan - recovered over a 33-year period	22.4	—
Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings) (c)	28.3	15.5
Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)	0.9	15.0



Other	61.9	99.7
Entergy Total (d)	$5,006.0	$5,290.9

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy Arkansas


	2025	2024
	(In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants and solar facilities (Note 9) (a)	$750.5	$693.0
Removal costs (Note 9)	369.6	337.9
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	333.4	391.2
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)	68.1	75.8
Production tax credits (Note 3 - Other Tax Matters - Inflation Reduction Act of 2022) (e)	37.1	—
Deferred COVID-19 costs - recovered over a 10-year period through December 2033	31.2	35.1
Storm damage costs - recovered through retail rates	29.3	29.8
Retired electric meters - recovered over a 15-year period through March 2034	29.2	32.8
Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings) (c)	28.3	15.5
Non-service pension & postretirement costs (Note 11 - Accounting for Pension and Other Postretirement Benefits)	24.9	42.1
Unamortized loss on reacquired debt - recovered over term of debt	17.4	18.6
Retail rate deferrals - recovered through rate riders as rates are redetermined annually (c)	14.6	13.6
Other	10.2	14.7
Entergy Arkansas Total	$1,743.8	$1,700.1

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy Louisiana


	2025	2024
	(In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants (Note 9) (a)	$438.0	$421.5
Removal costs (Note 9)	348.5	323.2
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	215.3	271.5
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	188.1	226.6
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)	98.7	111.4
Production tax credits (Note 3 - Other Tax Matters - Inflation Reduction Act of 2022) (e)	77.0	—
Retired electric and gas meters - recovered over a 22-year period through July 2041	72.9	78.5
Retired distribution plant - resiliency plan - recovered over a 33-year period	22.4	—
Non-service pension & postretirement costs (Note 11 - Accounting for Pension and Other Postretirement Benefits)	21.4	96.2
Unamortized loss on reacquired debt - recovered over term of debt	20.3	21.7
Deferred COVID-19 costs - offset with shorter-term financing interest earnings regulatory liability in 2025 (a)	—	47.8
Other	38.1	48.5
Entergy Louisiana Total (d)	$1,540.7	$1,646.9

Entergy Mississippi


	2025	2024
	(In Millions)
Removal costs (Note 9)	$198.6	$184.8
Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined annually	105.3	162.5
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	70.3	82.2
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)	26.0	29.1
Non-service pension & postretirement costs (Note 11 - Accounting for Pension and Other Postretirement Benefits)	21.2	29.9
Asset retirement obligation - recovery dependent upon timing of shutdown of non-nuclear power plants and solar facility (Note 9) (a)	12.2	9.4
Unamortized loss on reacquired debt - recovered over term of debt	8.2	9.1


Other	13.9	18.8
Entergy Mississippi Total	$455.7	$525.8

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy New Orleans


	2025	2024
	(In Millions)
Removal costs (Note 9)	$56.8	$62.5
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	18.2	22.9
Retired electric and gas meters - recovered over a 12-year period through July 2031 (c)	10.0	13.5
Qualified pension settlement cost deferral - recovered through June 2047 (Note 11 - Qualified Pension Settlement Cost)	7.4	10.8
Deferred COVID-19 costs - recovered over a five-year period through August 2028 (c)	5.8	10.2
Unamortized loss on reacquired debt - recovered over term of debt	0.3	0.5
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Securitization Bonds)	0.2	4.0
Gas cross-boring costs - recovered through formula rates as rates are redetermined by retail regulators	—	11.9
Other	11.0	20.7
Entergy New Orleans Total (d)	$109.7	$157.0

Entergy Texas


	2025	2024
	(In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Securitization Bonds)	$263.8	$286.5
Removal costs (Note 9)	105.0	102.3
Advanced metering system surcharge for residential customers - recovered through December 2029	53.7	39.7
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	43.0	57.1
Unamortized loss on reacquired debt - recovered over term of debt	7.0	7.6
Neches and Sabine costs - recovered over a 10-year period through October 2028	6.7	9.2
Retired electric meters - recovered through retail rates (Note 2 - Retail Rate Proceedings)	5.8	10.9
Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)	0.9	15.0

Non-service pension & postretirement costs (Note 11 - Accounting for Pension and Other Postretirement Benefits)	—	5.8
Other	24.9	15.6







Entergy Texas Total	$510.8	$549.7

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

System Energy


	2025	2024
	(In Millions)
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear unit (Note 9) (c)	$222.4	$224.8
Production tax credits (Note 3 - Other Tax Matters - Inflation Reduction Act of 2022) (e)	185.7	—
Removal costs - recovered through depreciation rates (Note 9)	100.4	96.9
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	87.2	96.5
Non-service pension & postretirement costs (Note 11 - Accounting for Pension and Other Postretirement Benefits)	5.1	7.9
Unamortized loss on reacquired debt - recovered over term of debt	0.4	0.4

System Energy Total	$601.2	$426.5

(a)Does not earn a return on investment, but is offset by related liabilities.

(b)The regulatory asset represents the potential for the Registrant Subsidiaries to recover from customers the total deferred transaction and administrative costs and a market-based discount on the sale transactions.

(c)Does not earn a return on investment.

(d)Includes $35.4 million at Entergy, $8.9 million at Entergy Louisiana, and $23.7 million at Entergy New Orleans as of December 31, 2024 of regulatory assets related to the respective natural gas distribution businesses classified as held for sale and included within “Non-current assets held for sale” on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses on July 1, 2025 and the classification as held for sale as of December 31, 2024.

(e)Regulatory assets include the MSS-4 replacement tariff and the Unit Power Sales Agreement payments which are affiliate transactions and are eliminated in consolidation.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Other Regulatory Liabilities

Entergy


	2025	2024
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)	$2,731.9	$2,262.5
Securitization financing savings obligation (Note 2)	345.5	371.3
Retail rate rider over-recovery - refunded through formula rate or rate riders as rates are redetermined by retail regulators	143.3	164.9
Credits from resolution of the 2016-2018 IRS audit (Note 3)	132.5	163.3
Non-service pension & postretirement costs (Note 11 - Accounting for Pension and Other Postretirement Benefits)	84.7	—
Deferred tax equity partnership earnings (Note 1)	73.6	69.9
Vidalia purchased power agreement (Note 8)	54.5	67.4
Customer rate credits from global stipulated settlement with the LPSC - returned to customers September 2024 through August 2026 (Note 2)	48.7	121.7
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC	44.4	44.4
Refund from System Energy settlement with the LPSC - returned to customers January 2025 through August 2027 (Note 2)	42.2	75.8
Refund from System Energy settlement with the City Council - returned to customers over a 25-year period beginning September 2024 (Note 2)	41.7	42.7
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	39.3	40.9
Refund from System Energy settlement with the City Council - return to customers to be determined (Note 2)	29.2	32.0
Refund from System Energy settlement with the City Council - returned to customers over a 10-year period beginning September 2024 (Note 2)	18.7	22.0
Production tax credits (Note 3 - Other Tax Matters - Inflation Reduction Act of 2022)	15.3	—
Shorter-term financing interest earnings - offset with deferred COVID-19 costs regulatory asset in 2025 (a)	—	48.9
Refund from System Energy settlement with the APSC - refunded through a rate rider (Note 2)	—	8.2
Other	66.3	75.2
Entergy Total (b)	$3,911.8	$3,611.1

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy Arkansas


	2025	2024
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)	$917.1	$761.3
Production tax credits (Note 3 - Other Tax Matters - Inflation Reduction Act of 2022) (c)	52.1	—
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually	39.0	27.9
Deferred tax equity partnership earnings (Note 1)	35.4	32.4
Refund from System Energy settlement with the APSC - refunded through a rate rider (Note 2)	—	8.2
Other	0.5	1.4
Entergy Arkansas Total	$1,044.1	$831.2

Entergy Louisiana


	2025	2024
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)	$961.9	$798.4
Securitization financing savings obligation (Note 2)	345.5	371.3
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually	75.1	111.6
Vidalia purchased power agreement (Note 8)	54.5	67.4
Customer rate credits from global stipulated settlement with the LPSC - returned to customers September 2024 through August 2026 (Note 2)	48.7	121.7
Refund from System Energy settlement with the LPSC - returned to customers January 2025 through August 2027 (Note 2)	42.2	75.8
Production tax credits (Note 3 - Other Tax Matters - Inflation Reduction Act of 2022) (c)	39.9	—
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	39.3	40.9
Shorter-term financing interest earnings - offset with deferred COVID-19 costs regulatory asset in 2025 (a)	—	48.9
Hurricane Ida insurance proceeds - returned to customers August 2024 through July 2025	—	26.0
Credits from resolution of the 2016-2018 IRS audit - returned to customers September 2024 through August 2025 (Note 3)	—	25.3
Other	23.7	6.4
Entergy Louisiana Total (b)	$1,630.8	$1,693.7

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy Mississippi


	2025	2024
	(In Millions)
Production tax credits (Note 3 - Other Tax Matters - Inflation Reduction Act of 2022) (c)	$72.2	$—
Deferred tax equity partnership earnings (Note 1)	38.2	37.5
Other postretirement benefits (Note 11 - Entergy Mississippi Other Postretirement Benefits)	18.6	7.4
Retail rate rider over-recovery - refunded through formula rate or rate riders as rates are redetermined annually	14.2	12.2
Other	0.9	2.4
Entergy Mississippi Total	$144.1	$59.5

Entergy New Orleans


	2025	2024
	(In Millions)
Credits from resolution of the 2016-2018 IRS audit - returned to customers over a 25-year period beginning January 2025 (Note 3)	$132.5	$138.0
Production tax credits (Note 3 - Other Tax Matters - Inflation Reduction Act of 2022) (c)	61.6	—
Refund from System Energy settlement with the City Council - returned to customers over a 25-year period beginning September 2024 (Note 2)	41.7	42.7
Refund from System Energy settlement with the City Council - return to customers to be determined (Note 2)	29.2	32.0
Refund from System Energy settlement with the City Council - returned to customers over a 10-year period beginning September 2024 (Note 2)	18.7	22.0
Non-service pension & postretirement costs (Note 11 - Accounting for Pension and Other Postretirement Benefits)	11.5	—
Sale-leaseback and depreciation refunds - returned to customers over a 10-year period beginning September 2023 (Note 2)	4.6	5.2
Gain on sale of natural gas business - to be returned to customers over a 3-year period beginning September 2026 (Note 14 - Dispositions)	4.1	—
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually	1.8	16.3

Other	7.3	4.5
Entergy New Orleans Total (b)	$313.0	$260.7

Entergy Texas


	2025	2024
	(In Millions)
Non-service pension & postretirement costs (Note 11 - Accounting for Pension and Other Postretirement Benefits)	$73.2	$—
Production tax credits (Note 3 - Other Tax Matters - Inflation Reduction Act of 2022) (c)	45.8	—
Retail rate rider over-recovery - return to customers to be determined	13.0	12.2
Retail refunds - return to customers to be determined	6.2	6.2


Other	0.8	0.3
Entergy Texas Total	$139.0	$18.7

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

System Energy


	2025	2024
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)	$852.9	$702.8
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC	44.4	44.4
System Energy Total	$897.3	$747.2

(a)Offset by related asset.

(b)Includes $1.6 million at Entergy, $1.2 million at Entergy Louisiana, and $0.4 million at Entergy New Orleans as of December 31, 2024 of regulatory liabilities related to the respective natural gas distribution businesses classified as held for sale and included within other non-current liabilities on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses on July 1, 2025 and the classification as held for sale as of December 31, 2024.

(c)Regulatory liabilities include the MSS-4 replacement tariff and the Unit Power Sales Agreement payments which are affiliate transactions and are eliminated in consolidation.

Fuel and purchased power cost recovery

The Utility operating companies are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements. The table below shows the amount of current deferred fuel costs as of December 31, 2025 and 2024 that each Utility operating company expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.


	2025	2024
	(In Millions)
Entergy Arkansas	$27.7	($45.2)
Entergy Louisiana (a)	$15.7	($4.7)
Entergy Mississippi	$10.8	($126.3)
Entergy New Orleans (a)	($3.2)	$3.9
Entergy Texas	($11.4)	($59.3)

(a)Includes $0.7 million at Entergy Louisiana and $4.9 million at Entergy New Orleans as of December 31, 2024 of deferred fuel assets related to the respective natural gas distribution businesses classified as held for sale and included within “Current assets held for sale” on the respective consolidated balance sheets. See Note 14 to the financial statements for further discussion of the sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses on July 1, 2025 and the classification as held for sale as of December 31, 2024.

In addition, Entergy Louisiana and Entergy New Orleans have $168.1 million and $4.1 million, respectively, classified as long-term deferred fuel costs for fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months, on their consolidated balance sheets as of December 31, 2025 and 2024.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy Arkansas

Energy Cost Recovery Rider

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

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

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

In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Cuts and Jobs Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Cuts and Jobs Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it initiated an audit of the 2017 fuel costs. The timing of the audit’s completion is uncertain at this time.

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

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

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

Entergy Louisiana

Entergy Louisiana recovers electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Louisiana’s purchased gas adjustments, which ceased following the sale of its natural gas distribution business on July 1, 2025, included estimates for the

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

billing month adjusted by a surcharge or credit that arose from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 14 to the financial statements for discussion of the sale of Entergy Louisiana’s natural gas distribution business on July 1, 2025.

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

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

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

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

Entergy Mississippi

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

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

Entergy Mississippi had a deferred fuel balance of approximately $291.7 million under the energy cost recovery rider as of July 31, 2022, along with an over-recovery balance of $51.1 million under the power management rider. Without further action, Entergy Mississippi anticipated a year-end deferred fuel balance of approximately $200 million after application of a portion of the System Energy settlement proceeds, as discussed above. In September 2022, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider. Entergy Mississippi proposed five monthly incremental adjustments to the net energy cost factor designed to collect the under-recovered fuel balance as of July 31, 2022 and to reflect the

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

recovery of a higher natural gas price. Entergy Mississippi also proposed five monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance as of July 31, 2022. In October 2022 the MPSC approved modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider. The MPSC approved dividing the energy cost recovery rider interim adjustment into two components that would allow Entergy Mississippi to (1) recover a natural gas fuel rate that is better aligned with current prices; and (2) recover the estimated under-recovered deferred fuel balance as of September 30, 2022 over a period of 20 months. The MPSC approved six monthly incremental adjustments to the net energy cost factor designed to reflect the recovery of a higher natural gas price. The MPSC also approved six monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance. In accordance with the order of the MPSC, Entergy Mississippi did not file an annual redetermination of the energy cost recovery rider or the power management rider in November 2022.

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

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

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

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

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

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

Entergy New Orleans

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 Texas

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

In September 2022, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2019 through March 2022. During the reconciliation period, Entergy Texas incurred approximately $1.7 billion in eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. As of the end of the reconciliation period, Entergy Texas’s cumulative under-recovery balance was approximately $103.1 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2022, pending future surcharges or refunds as approved by the PUCT. In November 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2023, Entergy Texas filed an unopposed settlement, supporting testimony, and an agreed motion to admit evidence and remand the proceeding to the PUCT. Pursuant to the unopposed settlement, Entergy Texas would receive no disallowance of fuel costs incurred over the three-year reconciliation period and retain $9.3 million in margins from off-system sales made during the reconciliation period, resulting in a cumulative under-recovery balance of approximately $99.7 million, including interest, as of the end of the reconciliation period. In July 2023 the ALJ with the State Office of Administrative Hearings granted the motion to admit evidence and remanded the proceeding to the PUCT for consideration of the unopposed settlement. The PUCT approved the settlement in September 2023.

In September 2024, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2022 through March 2024. During the reconciliation period, Entergy Texas incurred approximately $1.6 billion in eligible fuel and purchased power expenses to generate and purchase electricity to serve its customers, net of certain revenues credited to such expenses and other adjustments. Entergy Texas’s cumulative under-recovery balance for the reconciliation period was approximately $30 million, including interest, which Entergy Texas requested authority to carry over as part of the cumulative fuel balance for the

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

subsequent reconciliation period beginning April 2024. In March 2025, Texas Industrial Energy Consumers, an intervenor, filed testimony regarding the recovery of capacity costs for a certain power purchase agreement, arguing the capacity costs should be imputed and treated as non-reconcilable fuel expense, recovered in Entergy Texas’s base rates. In April 2025 the PUCT staff filed testimony and later in April 2025, Entergy Texas filed rebuttal testimony. In August 2025, Entergy Texas filed an unopposed settlement agreement that results in no disallowance and establishes a regulatory asset for the future recovery of imputed capacity costs and associated carrying costs related to a certain purchased power agreement, with recovery effective retroactive to June 1, 2024. In October 2025 the PUCT approved the unopposed settlement agreement.

In December 2024, Entergy Texas filed an application with the PUCT to implement an interim fuel refund of $45.5 million, including interest. Entergy Texas proposed that the interim fuel refund be implemented over a three-month period beginning with the first billing cycle in February 2025 for residential and other small customers and through a one-time credit, or surcharge depending on historical usage for the respective customer, for certain transmission voltage level and seasonal agricultural customers in February 2025. Also in December 2024 the PUCT referred the proceeding to the State Office of Administrative Hearings. In January 2025 the ALJ with the State Office of Administrative Hearings issued an order approving the interim fuel refund consistent with Entergy Texas’s application and, because no hearing was requested in the proceeding, dismissing the case from the State Office of Administrative Hearings and the PUCT.

Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2023 Formula Rate Plan Filing

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

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

2024 Formula Rate Plan Filing

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

2025 Formula Rate Plan Filing

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

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

to reflect the amount of the 2024 historical year netting adjustment that it expects to collect from its customers during the 2026 rate effective period.

Grand Gulf Credit Rider

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

Generating Arkansas Jobs Act Rider

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

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

Special Rate Contract and Arkansas Cypress Solar

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

ratemaking treatment of Google’s upfront payments but reversing itself on the treatment of the Arkansas Cypress Solar facility investment tax credits and allowing those to be used in the pricing of the Arkansas Cypress Solar facility to Google as provided for in the contract.

In September 2025, Entergy Arkansas filed an application with the APSC seeking a certificate of environmental compatibility and public need for the construction and operation of the Arkansas Cypress Solar facility, a planned 600 MW solar photovoltaic array with a 350 MW battery energy storage system and associated transmission facilities interconnecting at Entergy Arkansas’s White Bluff substation. The estimated cost of the project is $1,602 million. Entergy Arkansas is seeking public interest and prudence findings from the APSC no later than 180 days from the filing, pursuant to Act 373 of 2025, to construct the Arkansas Cypress Solar facility in support of its long-term special rate contract with Google. In October 2025 the APSC general staff and the Arkansas Attorney General filed responsive testimony opposing the project cost and seeking additional information. Subsequently, the APSC general staff submitted supplemental testimony to update its initial conclusion and recommendations, noting that the Arkansas Cypress Solar facility is a reasonable project and recommending the APSC approve the project under certain conditions. Entergy Arkansas proposes to recover the costs of constructing the Arkansas Cypress Solar facility through the Generating Arkansas Jobs Act rider. A hearing was held in December 2025, and an APSC decision is due in March 2026. Subject to receipt of required regulatory approval and other conditions, the facility is expected to be in service by the end of 2028. See “Generating Arkansas Jobs Act Rider” above for discussion of the Generating Jobs Act rider, which was approved by the APSC in October 2025.

Filings with the LPSC (Entergy Louisiana)

Retail Rates - Electric

2022 Formula Rate Plan Filing

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

2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request

In August 2023, Entergy Louisiana filed an application for approval of a regulatory blueprint necessary for it to strengthen the electric grid for the State of Louisiana, which contained a dual-path request to update rates

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

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

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

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

•continuation of the formula rate plan for 2024-2026 (test years 2023-2025);

•a base formula rate plan revenue increase of $120 million for test year 2023, effective for rates beginning September 2024;

•a $140 million cumulative cap on base formula rate plan revenue increases, if needed, for test years 2024 and 2025, excluding outside the bandwidth items;

•$184 million of customer rate credits to be given over two years, including increasing customer sharing of income tax benefits resulting from the 2016-2018 IRS audit, to resolve any remaining disputed issues stemming from formula rate plan test years prior to test year 2023, including but not limited to the investigation into Entergy Services costs billed to Entergy Louisiana. As discussed in Note 3 to the financial statements, a $38 million regulatory liability was recorded in 2023 in connection with the 2016-2018 IRS audit;

•$75.5 million of customer rate credits, as provided for in the System Energy global settlement, to be credited over three years subject to and conditioned upon FERC approval of the System Energy global settlement, which was approved in November 2024. See “Complaints Against System Energy – System Energy Settlement with the LPSC” below for further details of the System Energy global settlement;

•$5.8 million of customer rate credits provided for in the Entergy Louisiana formula rate plan global settlement agreement approved by the LPSC in November 2023 credited over one year. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement;

•an increase in the allowed midpoint return on common equity from 9.5% to 9.7%, with a bandwidth of 40 basis points above and below the midpoint, for the extended term of the formula rate plan, except that for test year 2023 in which the authorized return on common equity shall have no bearing on the change in base formula rate plan revenue described above and, for test year 2024, any earnings above the authorized return on common equity shall be returned to customers through a credit;

•an increase in nuclear depreciation rates by $15 million in each of the 2023, 2024, and 2025 test years outside of the formula rate plan bandwidth calculation; and

•for the transmission recovery mechanism and the distribution recovery mechanism, no change to the existing floors, but the caps for both would be $350 million for test year 2023, $375 million for test year 2024, and $400 million for test year 2025. Transmission projects filed with the LPSC will be exempt from the transmission recovery mechanism cap.

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

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

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Formula Rate Plan Global Settlement

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

2023 Formula Rate Plan Filing

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

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

2024 Formula Rate Plan Filing

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

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

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

As noted above, the 2024 evaluation report included the effects of the change in Louisiana state tax law that reduced the corporate income tax rate to a flat 5.5% (from the then-current highest marginal rate of 7.5%) effective January 1, 2025. As such, the 2024 evaluation report reflected the calculation of current and deferred income tax expenses as well as the revaluation of accumulated deferred income taxes based on the income tax laws currently in effect. The 2024 evaluation report proposed that the rate effects associated with the revaluation of accumulated deferred income taxes, including the collection of any net accumulated deferred income tax deficiency and any related effects on rate base, should be reflected in the tax adjustment mechanism consistent with the treatment of similar Tax Cuts and Jobs Act and prior state tax change-related impacts. The effects of the change in tax law on Entergy Louisiana’s authorized return on rate base were also reflected in the 2024 evaluation report consistent with the treatment cited above, including a credit in the extraordinary cost change mechanism for the prospective change in Entergy Louisiana’s authorized return and a credit within the tax adjustment mechanism for over-collection of income tax expense through August 2025. Subject to LPSC review, the resulting changes from the 2024 formula rate plan evaluation report became effective for bills rendered during the first billing cycle of September 2025, subject to refund. In August 2025 the LPSC staff filed its errors and objections report, as required by the formula rate plan’s process, and found that Entergy Louisiana’s formula rate plan is in compliance with the LPSC’s requirements and the global stipulated settlement agreement. The LPSC staff reserved the right to determine whether Entergy Louisiana appropriately credited certain revenues to customers during the September and October 2025 billing cycles. In December 2025 the LPSC staff and Entergy Louisiana filed a joint report indicating that no unresolved, disputed issues existed and recommending that the LPSC accept the joint report, confirm that no outstanding issues existed, and close the docket. In January 2026 the LPSC issued an order accepting the joint report.

Additional Generation and Transmission Resources

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

no harm to Entergy Louisiana and its customers in the event of early termination. A directive was issued at the LPSC’s November 2024 meeting for the matter to be decided by October 2025. In February 2025 intervenors filed a motion asking the LPSC to deny Entergy Louisiana’s requested exemption from the LPSC’s order addressing competitive solicitation procedures and further asking the LPSC to dismiss the application. The ALJ issued an order denying the motion to dismiss the application and deferring the LPSC’s consideration of the motion regarding the competitive solicitation procedures until the hearing. In March 2025 the same intervenors filed a motion requesting the LPSC to require the customer and its parent company to be joined as parties to the proceeding or dismiss the application. In April 2025 the ALJ issued an order denying the March 2025 motion, and the moving parties filed a motion asking the LPSC to review and reverse the ALJ’s decision.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Filings with the MPSC (Entergy Mississippi)

Retail Rates

2023 Formula Rate Plan Filing

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

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

2024 Formula Rate Plan Filing

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

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

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

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

2025 Formula Rate Plan Filing

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

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

Interim Facilities Rate Adjustments to the Formula Rate Plan

In May 2024, Entergy Mississippi received approval from the MPSC for formula rate plan revisions that were necessary for Entergy Mississippi to comply with state legislation passed in January 2024. The legislation allows Entergy Mississippi to make interim rate adjustments to recover the non-fuel related annual ownership cost of certain facilities that directly or indirectly provide service to customers who own certain data processing center projects as specified in the legislation. Entergy Mississippi filed the first of its annual interim facilities rate adjustment reports in May 2024 to recover approximately $8.7 million of these costs over a six-month period with rates effective the first billing cycle of July 2024. Entergy Mississippi filed its second annual interim facilities rate adjustment report in November 2024 to recover approximately $46.7 million of these costs over a 12-month period with rates effective the first billing cycle of January 2025. In February 2025, Entergy Mississippi filed a true-up interim facilities rate adjustment report to the initial annual interim facilities rate adjustment report filed in May 2024, reflecting the recovery of an additional approximately $1.0 million of costs over a 12-month period with rates effective with the first billing cycle of April 2025. Entergy Mississippi filed its third annual interim facilities rate adjustment report in November 2025 to recover approximately $111.3 million of these costs over a 12-month

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

period, or approximately $64.7 million incremental to the second annual interim facilities rate adjustment report filed in November 2024, with rates effective the first billing cycle of January 2026.

Grand Gulf Capacity Filing

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

Additional Generation and Transmission Resources

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Filings with the City Council (Entergy New Orleans)

Retail Rates

2023 Formula Rate Plan Filing

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

Request for Extension and Modification of Formula Rate Plan

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

2024 Formula Rate Plan Filing

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

2025 Formula Rate Plan Filing

In April 2025, Entergy New Orleans submitted to the City Council its formula rate plan 2024 test year filing. The 2024 evaluation report produced an electric earned return on equity of 10.98% compared to the

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

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

Filings with the PUCT and Texas Cities (Entergy Texas)

Retail Rates

2022 Base Rate Case

In July 2022, Entergy Texas filed a base rate case with the PUCT seeking a net increase in base rates of approximately $131.4 million. The base rate case was based on a 12-month test year ending December 31, 2021. Key drivers of the requested increase were changes in depreciation rates as the result of a depreciation study and an increase in the return on equity. In addition, Entergy Texas included capital additions placed into service for the period of January 1, 2018 through December 31, 2021, including those additions reflected in the then-effective distribution and transmission cost recovery factor riders and the generation cost recovery rider, all of which were reset to zero in June 2023 as a result of this proceeding. In July 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In October 2022 intervenors filed direct testimony challenging and supporting various aspects of Entergy Texas’s rate case application. The key issues addressed included the appropriate return on equity, generation plant deactivations, depreciation rates, and proposed tariffs related to electric vehicles. In November 2022 the PUCT staff filed direct testimony addressing a similar set of issues and recommending a reduction of $50.7 million to Entergy Texas’s overall cost of service associated with the requested net increase in base rates of approximately $131.4 million. Entergy Texas filed rebuttal testimony in November 2022.

In May 2023, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding, except for issues related to electric vehicle charging infrastructure which were eventually severed to a separate proceeding and resolved in October 2024, and Entergy Texas filed an agreed motion for interim rates, subject to refund or surcharge to the extent that the interim rates differ from the final approved rates. The unopposed settlement reflected a net base rate increase to be effective and relate back to December 2022 of $54 million, exclusive of, and incremental to, the costs being realigned from the distribution and transmission cost recovery factor riders and the generation cost recovery rider and $4.8 million of rate case expenses to be recovered through a rider over a period of 36 months. The net base rate increase of $54 million includes updated depreciation rates and a total annual revenue requirement of $14.5 million for the accrual of a self-insured storm reserve and the recovery of the regulatory assets for the pension and postretirement benefits expense deferral, costs associated with the COVID-19 pandemic, and retired non-advanced metering system electric meters. In May 2023 the ALJ with the State Office of Administrative Hearings granted the motion for interim rates, which became effective in June 2023. Additionally, the ALJ remanded the proceeding to the PUCT to consider the settlement. In August 2023 the PUCT issued an order approving the unopposed settlement. Concurrently, Entergy Texas recorded the reversal of $21.9 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Following the PUCT’s approval of the unopposed settlement in August 2023, Entergy Texas recorded a regulatory liability of $10.3 million, which reflected the net effects of higher depreciation and amortizations for the relate back period, partially offset by the relate back of base rate revenues that would have been collected had the approved rates been in effect for the period from December 2022 through June 2023, the date the new base rates were implemented on an interim basis. In October 2023, Entergy Texas filed a relate back surcharge rider to collect over six months beginning in January 2024 an additional approximately $24.6 million, which was the revenue requirement associated with the relate back of rates from December 2022 through June 2023, including carrying costs, as authorized by the PUCT’s August 2023 order. In November 2023, Entergy Texas filed an amended relate back surcharge rider to collect approximately $24.1 million based on a revised carrying cost rate. The amended relate back surcharge rider was approved by the PUCT in December 2023. The higher depreciation and amortizations for the relate back period were also recognized over the six months beginning in January 2024, resulting in no effect on net income from the collection of the relate back surcharge rider.

Distribution Cost Recovery Factor (DCRF) Rider

In June 2024, Entergy Texas filed with the PUCT a request to set a new DCRF rider. The new rider was designed to collect from Entergy Texas’s retail customers approximately $40.3 million annually based on its capital invested in distribution between January 1, 2022 and March 31, 2024. In September 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective with the first billing cycle in October 2024.

In September 2024, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $48.9 million annually, or $8.6 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between April 1, 2024 and June 30, 2024. In December 2024, Entergy Texas filed an errata to revise its DCRF application for minor corrections, which decreased the requested annual revenue requirement to $48.5 million. The amended request represented an incremental increase of $8.2 million in annual revenues beyond Entergy Texas’s then-effective DCRF rider. Also in December 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s filed errata, and rates became effective on December 20, 2024.

In April 2025, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $77.8 million annually, or $29.3 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between July 1, 2024 and December 31, 2024, including distribution-related restoration costs associated with Hurricane Beryl. In June 2025 the PUCT approved the DCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective on June 25, 2025.

In September 2025, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $94.7 million annually, or $16.9 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between January 1, 2025 and June 30, 2025. In November 2025, Entergy Texas filed an errata to revise its DCRF application for minor corrections, which decreased the requested annual revenue requirement to $92.1 million. The amended request represented an incremental increase of $14.3 million in annual revenues beyond Entergy Texas’s then-effective DCRF filing. In December 2025 the PUCT approved the DCRF rider, consistent with Entergy Texas’s filed errata, and rates became effective on December 15, 2025.

Transmission Cost Recovery Factor (TCRF) Rider

In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The new TCRF rider was designed to collect approximately $2.7 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and September 30, 2018. In April 2019 parties filed

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

testimony proposing a load growth adjustment, which would fully offset Entergy Texas’s proposed TCRF revenue requirement. In July 2019 the PUCT granted Entergy Texas’s application as filed to begin recovery of the requested $2.7 million annual revenue requirement, rejecting opposing parties’ proposed adjustment; however, the PUCT found that the question of prudence of the actual investment costs should be determined in Entergy Texas’s next rate case similar to the procedure used for the costs recovered through the DCRF rider. In October 2019 the PUCT issued an order on a motion for rehearing, clarifying and affirming its prior order granting Entergy Texas’s application as filed. Also in October 2019 a second motion for rehearing was filed, and Entergy Texas filed a response in opposition to the motion. The second motion for rehearing was overruled by operation of law. In December 2019, Texas Industrial Energy Consumers filed an appeal to the PUCT order in district court alleging that the PUCT erred in declining to apply a load growth adjustment.

In October 2024, Entergy Texas filed with the PUCT a request to amend its TCRF rider, which was previously reset to zero in June 2023 as a result of the 2022 base rate case. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $9.7 million annually based on its capital invested in transmission between January 1, 2022 and June 30, 2024 and changes in other transmission charges. In April 2025 the PUCT approved the TCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective for usage on and after April 7, 2025.

In October 2025, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $30.3 million annually, or $20.6 million in incremental annual revenues beyond Entergy Texas’s currently effective TCRF rider based on its capital invested in transmission between July 1, 2024 and June 30, 2025 and changes in other transmission charges. In January 2026 the PUCT staff filed a recommendation that the PUCT approve Entergy Texas’s as-filed application.

Generation Cost Recovery Rider

In December 2020, Entergy Texas also filed an application to amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which closed in June 2021. Because the facility was to be acquired in the future, the initial generation cost recovery rider rates proposed in the application represented no change from the generation cost recovery rider rates established in Entergy Texas’s previous generation cost recovery rider proceeding. In July 2021 the PUCT issued an order approving the application. In August 2021, Entergy Texas filed an update application to recover its actual investment in the acquisition of the Hardin County Peaking Facility, and in January 2022, Entergy Texas filed an update to its application to align the requested revenue requirement with the terms of the generation cost recovery rider settlement approved by the PUCT in January 2022. In April 2022, Entergy Texas filed on behalf of the parties a unanimous settlement agreement that would adjust its generation cost recovery rider to recover an annual revenue requirement of approximately $92.8 million, which was $4.5 million in incremental annual revenue above the revenue requirement approved in January 2022 described above and related to Entergy Texas’s investment in the Montgomery County Power Station. The PUCT approved the settlement agreement and rates became effective in August 2022. In September 2022, Entergy Texas filed a relate-back rider designed to collect over three months an additional approximately $5.7 million, which is the revenue requirement, plus carrying costs, associated with Entergy Texas’s acquisition of Hardin County Peaking Facility from June 2021 through August 2022 when the updated revenue requirement took effect. In April 2023 the PUCT approved Entergy Texas’s as-filed request with rates effective over three months beginning in May 2023.

Entergy Arkansas Opportunity Sales Proceeding

In June 2009 the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocated the energy generated by Entergy System resources; (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity; and (c) violated the provision of

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

the System Agreement that prohibited sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenged sales made beginning in 2002 and requested refunds. In July 2009 the Utility operating companies filed a response to the complaint arguing among other things that the System Agreement contemplated that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The FERC subsequently ordered a hearing in the proceeding.

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

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

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

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

In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing.

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

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

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

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

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

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

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Complaints Against System Energy

System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans, and sold to Entergy Louisiana through September 30, 2025, pursuant to the Unit Power Sales Agreement. System Energy and the Unit Power Sales Agreement have been the subject of several litigation proceedings at the FERC, including challenges with respect to System Energy’s authorized return on equity and capital structure, renewal of its sale-leaseback arrangement, treatment of uncertain tax positions, a broader investigation of rates under the Unit Power Sales Agreement, and two prudence complaints, one challenging the extended power uprate completed at Grand Gulf in 2012 and the operation and management of Grand Gulf, particularly in the 2016-2020 time period, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. Settlements that resolve all significant aspects of these complaints have been reached with the MPSC, the APSC, the City Council, and the LPSC, and these settlements have been approved by the FERC. Following are discussions of the proceedings.

Return on Equity and Capital Structure Complaints

In January 2017 the APSC and the MPSC filed a complaint with the FERC against System Energy. The complaint sought a reduction in the return on equity component of the Unit Power Sales Agreement pursuant to which System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. Entergy Arkansas also sells some of its Grand Gulf capacity and energy to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under separate agreements. The return on equity under the Unit Power Sales Agreement at the time of the complaint was 10.94%, which was established in a rate proceeding that became final in July 2001.

The APSC and the MPSC complaint alleged that the return on equity was unjust and unreasonable because capital market and other considerations indicated that it was excessive. The complaint requested proceedings to investigate the return on equity and establish a lower return on equity, and also requested that the FERC establish January 23, 2017 as a refund effective date. The complaint included a return on equity analysis that purported to establish that the range of reasonable return on equity for System Energy was between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputed that a return on equity of 8.37% to 8.67% was just and reasonable. The LPSC and the City Council intervened in the proceeding expressing support for the complaint. In September 2017 the FERC established a refund effective date of January 23, 2017 and directed the parties to engage in settlement proceedings before an ALJ. The parties were unable to settle the return on equity issue and a FERC hearing judge was assigned in July 2018. The 15-month refund period in connection with the APSC/MPSC complaint expired on April 23, 2018.

In April 2018 the LPSC filed a complaint with the FERC against System Energy seeking an additional 15-month refund period. The LPSC complaint requested similar relief from the FERC with respect to System Energy’s return on equity and also requested the FERC to investigate System Energy’s capital structure. The APSC, the MPSC, and the City Council intervened in the proceeding, filed an answer expressing support for the complaint, and asked the FERC to consolidate this proceeding with the proceeding initiated by the complaint of the APSC and the MPSC in January 2017. System Energy answered the LPSC complaint in May 2018 and also filed a motion to dismiss the complaint. In August 2018 the FERC issued an order dismissing the LPSC’s request to investigate System Energy’s capital structure and setting for hearing the return on equity complaint, with a refund effective date of April 27, 2018. The 15-month refund period in connection with the LPSC return on equity complaint expired on July 26, 2019.

The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and the MPSC complaint for hearing. The parties also addressed an order (issued in a separate FERC proceeding involving New England transmission owners) that proposed modifying the FERC’s standard methodology for determining return on equity. In September 2018 the LPSC filed an amended complaint raising

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

the same capital structure claim the FERC had earlier dismissed. The FERC initiated a new proceeding for the amended capital structure complaint, and System Energy answered the complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings. Settlement proceedings in the capital structure proceeding commenced in February 2019, but were terminated in June 2019, and the amended capital structure complaint was consolidated with the ongoing return on equity proceeding. The 15-month refund period in connection with the capital structure complaint was from September 24, 2018 to December 23, 2019.

Several rounds of testimony were filed by the parties in these proceedings between January 2019 and August 2020. Some of these rounds of testimony were precipitated by developments in an unrelated proceeding in which the FERC issued orders addressing the methodology for determining the return on equity applicable to transmission owners in MISO (Opinion Nos. 569 and 569-A). The final positions of the parties, after the submission of all pre-filed testimony, were as follows. With regard to the return on equity complaints for the first refund period, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argued for an authorized return on equity for System Energy of 7.97%; the MPSC and the APSC argued for an authorized return on equity of 9.24%; and the FERC trial staff argued for an authorized return on equity of 9.49%. For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argued for an authorized return on equity for System Energy of 7.78%; the MPSC and the APSC argued that an authorized return on equity of 9.15% may be appropriate if the second complaint was not dismissed; and the FERC trial staff argued for an authorized return on equity of 9.09% if the second complaint was not dismissed. The LPSC also continued to support as its primary recommendation, based on an alternative analysis to the Opinion No. 569-A methodology, an authorized return on equity for System Energy as low as 7.56% for the first complaint refund period and as low as 7.18% for the second complaint refund period and prospectively. The MPSC and the APSC also continued to support as their primary recommendation, based on an alternative analysis to the Opinion No. 569-A methodology, an authorized return on equity for System Energy as low as 8.26% for the first complaint refund period and as low as 8.32% for the second complaint refund period and prospectively. System Energy argued that strict application of the Opinion No. 569-A methodology produces results inconsistent with investor requirements and does not provide a sound basis on which to evaluate System Energy’s authorized return on equity. Therefore, as its primary recommendation, System Energy argued for the use of a methodology that incorporates four separate financial models and, based on application of this recommended methodology, an authorized return on equity of 10.12% for the first refund period, which also fell within the presumptively just and reasonable range calculated for the second refund period and prospectively. Under the Opinion No. 569-A methodology, System Energy calculated an authorized return on equity of 9.44% for the first refund period, which also fell within the presumptively just and reasonable range calculated for the second refund period and prospectively.

With regard to the capital structure, the LPSC’s primary recommendation was that the FERC establish a hypothetical capital structure for System Energy for ratemaking purposes, according to which System Energy’s common equity ratio would be set to Entergy Corporation’s equity ratio of 37% equity and 63% debt. The APSC and the MPSC recommended that 35.98% be set as the common equity ratio for System Energy. The FERC trial staff argued that the average capital structure of the proxy group used to develop System Energy’s return on equity should be used to establish the capital structure. Using this approach, the FERC trial staff calculated the average capital structure for its proposed proxy group of 46.74% common equity and 53.26% debt. System Energy disputed all of these recommendations and argued that the use of its actual capital structure was just and reasonable.

After conducting a hearing, in March 2021 the FERC ALJ issued an initial decision. With regard to System Energy’s authorized return on equity, the ALJ determined that the existing return on equity of 10.94% was no longer just and reasonable, and that the replacement authorized return on equity, based on application of the Opinion No. 569-A methodology, should be 9.32%. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (January 2017-April 2018) based on the difference between the current return on equity and the replacement authorized return on equity. The ALJ determined that the April 2018 complaint concerning the authorized return on equity should be dismissed, and that no refunds for a second fifteen-month refund period should be due. With regard to System Energy’s capital structure, the ALJ determined that

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

System Energy’s actual equity ratio was excessive and that the just and reasonable equity ratio was 48.15% equity, based on the average equity ratio of the proxy group used to evaluate the return on equity for the second complaint. The ALJ further determined that System Energy should pay refunds for a fifteen-month refund period (September 2018-December 2019) based on the difference between the actual equity ratio and the 48.15% equity ratio.

In April 2021, System Energy filed its brief on exceptions, in which it challenged the initial decision’s findings on both the return on equity and capital structure issues. Also in April 2021 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed briefs on exceptions. Reply briefs opposing exceptions were filed in May 2021 by System Energy, the FERC trial staff, the LPSC, the APSC, the MPSC, and the City Council.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, the City Council, and the LPSC have settled their claims related to these proceedings. As part of the settlements with their respective retail regulators, effective July 2022 for Entergy Mississippi, November 2023 for Entergy Arkansas, June 2024 for Entergy New Orleans, and September 2024 for Entergy Louisiana, bills issued under the Unit Power Sales Agreement reflect a return on equity of 9.65% and a capital structure not to exceed 52% equity.

Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue

In May 2018 the LPSC filed a complaint against System Energy and Entergy Services related to System Energy’s renewal of a sale-leaseback transaction originally entered into in December 1988 for an 11.5% undivided interest in Grand Gulf Unit 1. The complaint alleged that System Energy violated the filed rate and the FERC’s ratemaking and accounting requirements when it included in Unit Power Sales Agreement billings the cost of capital additions associated with the sale-leaseback interest, and that System Energy was double-recovering costs by including both the lease payments and the capital additions in Unit Power Sales Agreement billings. The complaint also claimed that System Energy was imprudent in entering into the sale-leaseback renewal because the Utility operating companies that purchase Grand Gulf’s output from System Energy could have obtained cheaper capacity and energy in the MISO markets. The complaint further alleged that System Energy violated various other reporting and accounting requirements and should have sought prior FERC approval of the lease renewal. The complaint sought various forms of relief from the FERC, including refunds for capital addition costs for all years in which they were recorded in allegedly non-formula accounts or, alternatively, the disallowance of the return on equity for the capital additions in those years plus interest; a disallowance and refund of the lease costs of the sale-leaseback renewal on grounds of imprudence; an investigation into System Energy’s treatment of a DOE litigation payment; and the imposition of certain forward-looking procedural protections, including audit rights for retail regulators of the Unit Power Sales Agreement formula rates. The APSC, the MPSC, and the City Council intervened in the proceeding.

In June 2018, System Energy and Entergy Services filed a motion to dismiss and an answer to the LPSC complaint denying that System Energy’s treatment of the sale-leaseback renewal and capital additions violated the terms of the filed rate or any other FERC ratemaking, accounting, or legal requirements or otherwise constituted double recovery. The response also argued that the complaint was inconsistent with a FERC-approved settlement to which the LPSC is a party and that explicitly authorized System Energy to recover its lease payments. Finally, the response argued that both the capital additions and the sale-leaseback renewal were prudent investments and the LPSC complaint failed to justify any disallowance or refunds. The response also offered to submit formula rate protocols for the Unit Power Sales Agreement similar to the procedures used for reviewing transmission rates under the MISO tariff. In September 2018 the FERC issued an order setting the complaint for hearing and settlement proceedings and establishing a refund effective date of May 18, 2018.

In February 2019 the presiding ALJ ruled that the hearing ordered by the FERC includes the issue of whether specific subcategories of accumulated deferred income tax should be included in, or excluded from, System Energy’s formula rate. Testimony was filed by the LPSC, the MPSC, the APSC, the City Council, the FERC trial

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

staff, and System Energy between March 2019 and October 2019. The final positions of the parties, after all pre-filed testimony was submitted, were as follows. The LPSC sought refunds that included the renewal lease payments (approximately $17.2 million per year since July 2015), rate base reductions for accumulated deferred income tax associated with uncertain tax positions (with a corresponding refund of approximately $512 million), and the cost of capital additions associated with the sale-leaseback interest, as well as interest on those amounts. The LPSC also argued that adjustments to depreciation rates should require retroactive depreciation expense refunds but only prospective rate base adjustments. The APSC, the MPSC, and the City Council generally agreed with the LPSC’s positions. The FERC trial staff argued for refunds for rate base reductions for liabilities associated with uncertain tax positions, and also argued that System Energy recovered $32 million more than it should have in depreciation expense for capital additions. System Energy filed testimony asking the FERC to reject all of the LPSC’s claims for refunds and opposing the FERC trial staff’s position regarding the uncertain tax position issue. System Energy also argued that the FERC trial staff’s position regarding depreciation rates for capital additions was not unreasonable, but any change in depreciation expense is only one element of a Unit Power Sales Agreement re-billing calculation. Adjustments to depreciation expense in any re-billing under the Unit Power Sales Agreement formula rate would also involve changes to accumulated depreciation, accumulated deferred income taxes, and other formula elements as needed.

After holding a hearing in November 2019, in April 2020 the FERC ALJ issued the initial decision. Among other things, the ALJ determined that refunds were due on three main issues. First, with regard to the lease renewal payments, the ALJ determined that System Energy was recovering an unjust acquisition premium through the lease renewal payments, and that System Energy’s recovery from customers through rates should be limited to the cost of service based on the remaining net book value of the leased assets, which was approximately $70 million. The ALJ found that the remedy for this issue should be the refund of lease payments (approximately $17.2 million per year since July 2015) with interest determined at the FERC quarterly interest rate, which would be offset by the addition of the net book value of the leased assets in the cost of service. The ALJ did not calculate a value for the refund expected as a result of this remedy. In addition, System Energy would no longer recover the lease payments in rates prospectively. Second, with regard to the liabilities associated with uncertain tax positions, the ALJ determined that the liabilities are accumulated deferred income taxes and that System Energy’s rate base should have been reduced for those liabilities. The ALJ also found that System Energy should include liabilities associated with uncertain tax positions as a rate base reduction going forward. Third, with regard to the depreciation expense adjustments, the ALJ found that System Energy should correct for the error in re-billings retroactively and prospectively, but that System Energy should not be permitted to recover interest on any retroactive return on enhanced rate base resulting from such corrections.

In June 2020, System Energy, the LPSC, and the FERC trial staff filed briefs on exceptions, challenging several of the initial decision’s findings. System Energy’s brief on exceptions challenged the initial decision’s limitations on recovery of the lease renewal payments, its proposed rate base refund for the liabilities associated with uncertain tax positions, and its proposal to asymmetrically treat interest on bill corrections for depreciation expense adjustments. The LPSC’s and the FERC trial staff’s briefs on exceptions each challenged the initial decision’s allowance for recovery of the cost of service associated with the lease renewal based on the remaining net book value of the leased assets, its calculation of the remaining net book value of the leased assets, and the amount of the initial decision’s proposed rate base refund for the liabilities associated with uncertain tax positions. The LPSC’s brief on exceptions also challenged the initial decision’s proposal that depreciation expense adjustments include retroactive adjustments to rate base and its finding that section 203 of the Federal Power Act did not apply to the lease renewal. The FERC trial staff’s brief on exceptions also challenged the initial decision’s finding that the FERC need not institute a formal investigation into System Energy’s tariff. In October 2020, System Energy, the LPSC, the MPSC, the APSC, and the City Council filed briefs opposing exceptions. System Energy opposed the exceptions filed by the LPSC and the FERC trial staff. The LPSC, the MPSC, the APSC, the City Council, and the FERC trial staff opposed the exceptions filed by System Energy. Also in October 2020 the MPSC, the APSC, and the City Council filed briefs adopting the exceptions of the LPSC and the FERC trial staff.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

In addition, in September 2020, the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. The NOPA memorialized the IRS’s decision to adjust the 2015 consolidated federal income tax return of Entergy Corporation and certain of its subsidiaries, including System Energy, with regard to the uncertain decommissioning tax position. Pursuant to the audit resolution documented in the NOPA, the IRS allowed System Energy’s inclusion of $102 million of future nuclear decommissioning costs in System Energy’s cost of goods sold for the 2015 tax year, roughly 10% of the requested deduction, but disallowed the balance of the position. In September 2020, System Energy filed a motion to lodge the NOPA into the record in the FERC proceeding. In October 2020 the LPSC, the APSC, the MPSC, the City Council, and the FERC trial staff filed oppositions to System Energy’s motion. As a result of the NOPA issued by the IRS in September 2020, System Energy filed, in October 2020, a new Federal Power Act section 205 filing at FERC to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from the decommissioning uncertain tax position. On a prospective basis beginning with the October 2020 bill, System Energy proposed to include the accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position as a credit to rate base under the Unit Power Sales Agreement. In November 2020 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the filing, and System Energy responded.

In November 2020 the IRS issued a Revenue Agent’s Report (RAR) for the 2014/2015 tax year and in December 2020 Entergy executed it. The RAR contained the same adjustment to the uncertain nuclear decommissioning tax position as that which the IRS had announced in the NOPA. In December 2020, System Energy filed a motion to lodge the RAR into the record in the FERC proceeding addressing the uncertain tax position rate base issue. In January 2021 the LPSC, the APSC, the MPSC, and the City Council filed a protest to the motion.

As a result of the RAR, in December 2020, System Energy filed amendments to its new Federal Power Act section 205 filings to establish an ongoing rate base credit for the accumulated deferred income taxes resulting from the decommissioning uncertain tax position and to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. The amendments both proposed the inclusion of the RAR as support for the filings. In December 2020 the LPSC, the APSC, and the City Council filed protests to the amendments. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filings subject to refund, setting them for hearing, and holding the hearing in abeyance.

In December 2020, System Energy filed a new Federal Power Act section 205 filing to provide a one-time, historical credit of $25.2 million for the accumulated deferred income taxes that would have been created by the decommissioning uncertain tax position if the IRS’s decision had been known in 2016. In January 2021 the LPSC, APSC, MPSC, and City Council filed a protest to the filing. In February 2021 the FERC issued an order accepting System Energy’s Federal Power Act section 205 filing subject to refund, setting it for hearing, and holding the hearing in abeyance. System Energy provided the one-time credit during the first quarter 2021.

In December 2022 the FERC issued an order on the ALJ’s initial decision, which affirmed it in part and modified it in part. The FERC’s order directed System Energy to calculate refunds on three issues, and to provide a compliance report detailing the calculations. The FERC’s order also disallowed the future recovery of sale-leaseback renewal costs, which is estimated at approximately $11.5 million annually for purchases from Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans through July 2036. The three refund issues were rental expenses related to the renewal of the sale-leaseback arrangements; refunds, if any, for the revenue requirement impact of including accumulated deferred income taxes resulting from the decommissioning uncertain tax positions from 2004 through the present; and refunds for the net effect of correcting the depreciation inputs for capital additions attributable to the portion of plant subject to the sale-leaseback.

As a result of the FERC order’s directives regarding the recovery of the sale-leaseback transaction, in December 2022 System Energy reduced the Grand Gulf sale-leaseback regulatory liability by $56 million, reduced the related accumulated deferred income tax asset by $94 million, and reduced the Grand Gulf sale-leaseback accumulated deferred income tax regulatory liability by $25 million, resulting in an increase in income tax expense

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

of $13 million. In addition, the FERC determined that System Energy recognized excess depreciation expense related to property subject to the sale-leaseback. As a result, in December 2022, System Energy recorded a reduction in depreciation expense and the related accumulated depreciation of $33 million.

In January 2023, System Energy filed its compliance report with the FERC. With respect to the sale-leaseback renewal costs, System Energy calculated a refund of $89.8 million, which represented all of the sale-leaseback renewal rental costs that System Energy recovered in rates, with interest. With respect to the decommissioning uncertain tax position issue, System Energy calculated that no additional refunds were owed because it had already provided a one-time historical credit (for the period January 2016 through September 2020) of $25.2 million based on the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position, and because it has been providing an ongoing rate base credit for the accumulated deferred income taxes that resulted from the IRS’s partial acceptance of the decommissioning tax position since October 2020. With respect to the depreciation refund, System Energy calculated a refund of $13.7 million, which is the net total of a refund to customers for excess depreciation expense previously collected, plus interest, offset by the additional return on rate base that System Energy previously did not collect, without interest. See “System Energy Settlement with the MPSC” below for discussion of the regulatory charge and corresponding regulatory liability recorded in June 2022 related to these proceedings. In January 2023, System Energy paid the refunds of $103.5 million, which included refunds of $41.7 million to Entergy Arkansas, $27.8 million to Entergy Louisiana, and $34 million to Entergy New Orleans.

In February 2023 the LPSC, the APSC, and the City Council filed protests to System Energy’s January 2023 compliance report, in which they challenged System Energy’s calculation of the refunds associated with the decommissioning tax position but did not protest the other components of the compliance report. Each of them argued that System Energy should have paid additional refunds for the decommissioning tax position issue, and the City Council estimated the total additional refunds owed to customers of Entergy Louisiana, Entergy New Orleans, and Entergy Arkansas for that issue as $493 million, including interest (and without factoring in the $25.2 million refund that System Energy already paid in 2021).

In January 2023, System Energy filed a request for rehearing of the FERC’s determinations in the December 2022 order on sale-leaseback refund issues and future lease cost disallowances, the FERC’s prospective policy on uncertain tax positions, and the proper accounting of System Energy’s accumulated deferred income taxes adjustment for the Tax Cuts and Jobs Act of 2017; and a motion for confirmation of its interpretation of the December 2022 order’s remedy concerning the decommissioning tax position. In January 2023 the retail regulators filed a motion for confirmation of their interpretation of the refund requirement in the December 2022 FERC order and a provisional request for rehearing. In February 2023 the FERC issued a notice that the rehearing requests were denied by operation of law. In March 2023, System Energy filed in the United States Court of Appeals for the Fifth Circuit a petition for review of the December 2022 order. In March 2023, System Energy also filed an unopposed motion to stay the proceeding in the Fifth Circuit pending the FERC’s disposition of the pending motions, and the court granted the motion to stay.

In February 2023, System Energy submitted a tariff compliance filing with the FERC to clarify that, consistent with the releases provided in the MPSC settlement, Entergy Mississippi will continue to be charged for its allocation of the sale-leaseback renewal costs under the Unit Power Sales Agreement. See “System Energy Settlement with the MPSC” below for discussion of the settlement. In March 2023 the MPSC filed a protest to System Energy’s tariff compliance filing. The MPSC argues that the settlement did not specifically address post-settlement sale-leaseback renewal costs and that the sale-leaseback renewal costs may not be recovered under the Unit Power Sales Agreement. Entergy Mississippi’s allocated sale-leaseback renewal costs are estimated at $5.7 million annually for the remaining term of the sale-leaseback renewal. In February 2025, System Energy and the MPSC resolved their dispute concerning the sale-leaseback renewal costs. As a result, the MPSC withdrew its protest at the FERC to System Energy’s tariff compliance filing. Entergy Mississippi will continue to pay the allocated sale-leaseback renewal costs of approximately $5.7 million annually and there are no refunds due for prior

100

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

periods. In March 2025, System Energy filed a status report with the FERC explaining that the dispute is resolved. In April 2025 the FERC accepted System Energy’s tariff compliance filing.

In August 2023 the FERC issued an order addressing arguments raised on rehearing and partially setting aside the prior order (rehearing order). The rehearing order addressed rehearing requests that were filed in January 2023 separately by System Energy and the LPSC, the APSC, and the City Council.

In the rehearing order, the FERC directed System Energy to recalculate refunds for two issues: (1) refunds of rental expenses related to the renewal of the sale-leaseback arrangements and (2) refunds for the net effect of correcting the depreciation inputs for capital additions associated with the sale-leaseback. With regard to the sale-leaseback renewal rental expenses, the rehearing order allowed System Energy to recover an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback as of the expiration of the initial lease term. With regard to the depreciation input issue, the rehearing order allowed System Energy to offset refunds so that System Energy may collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. The rehearing order further directed System Energy to submit within 60 days of the date of the rehearing order an additional compliance filing to revise the total refunds for these two issues. As discussed above, System Energy’s January 2023 compliance filing calculated $103.5 million in total refunds, and the refunds were paid in January 2023. In October 2023, System Energy filed its compliance report with the FERC as directed in the August 2023 rehearing order. The October 2023 compliance report reflected recalculated refunds totaling $35.7 million for the two issues resulting in $67.8 million in refunds that could be recouped by System Energy. As discussed below in “System Energy Settlement with the APSC,” System Energy reached a settlement in principle with the APSC to resolve several pending cases under the FERC’s jurisdiction, including this one, pursuant to which it agreed not to recoup the $27.3 million calculated for Entergy Arkansas in the compliance filing. As a result of the FERC’s rulings on the sale-leaseback and depreciation input issues in the August 2023 rehearing order, in third quarter 2023, System Energy recorded a regulatory asset and corresponding regulatory credit of $40 million to reflect the portion of the January 2023 refunds to be recouped from Entergy Louisiana and Entergy New Orleans. Consistent with the compliance filing, in October 2023, Entergy Louisiana and Entergy New Orleans paid recoupment amounts of $18.2 million and $22.3 million, respectively, to System Energy.

On the third refund issue identified in the rehearing requests, concerning the decommissioning uncertain tax positions, the rehearing order denied all rehearing requests, re-affirmed the remedy contained in the December 2022 order, and did not direct System Energy to recalculate refunds or to submit an additional compliance filing.

In September 2023, System Energy filed a protective appeal of the rehearing order with the United States Court of Appeals for the Fifth Circuit. The appeal was consolidated with System Energy’s prior appeal of the December 2022 order.

In September 2023 the LPSC filed with the FERC a request for rehearing and clarification of the rehearing order. The LPSC requested that the FERC reverse its determination in the rehearing order that System Energy may collect an implied return of and on the depreciated cost of the portion of the plant subject to the sale-leaseback, as of the expiration of the initial lease term, as well as its determination in the rehearing order that System Energy may offset the refunds for the depreciation rate input issue and collect interest on the rate base recalculations that were part of the overall depreciation rate recalculations. In addition, the LPSC requested that the FERC either confirm the LPSC’s interpretation of the refund associated with the decommissioning uncertain tax positions or explain why it is not doing so. In October 2023 the FERC issued a notice that the rehearing request was deemed denied by operation of law. In November 2023 the FERC issued a further notice stating that it would not issue any further order addressing the rehearing request. Also in November 2023 the LPSC filed with the United States Court of Appeals for the Fifth Circuit a petition for review of the FERC’s August 2023 rehearing order and denials of the September 2023 rehearing request.

In December 2023 the United States Court of Appeals for the Fifth Circuit lifted the abeyance on the consolidated System Energy appeals and it also consolidated the LPSC’s appeal with the System Energy appeals.

101

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Briefing of the appeals occurred between March 2024 and July 2024. In September 2024 the parties filed a joint motion to continue and stay oral argument, previously scheduled for October 2024, pending the FERC’s decision whether to approve the settlement between System Energy and the LPSC, and the United States Court of Appeals for the Fifth Circuit granted the motion. In November 2024, after the FERC issued the order approving the settlement between System Energy and the LPSC, System Energy, the LPSC, the APSC, and the FERC filed a joint stipulation to dismiss the pending appeals, which the United States Court of Appeals for the Fifth Circuit granted.

LPSC Additional Complaints

In May 2020 the LPSC authorized its staff to file additional complaints at the FERC related to the rates charged by System Energy for Grand Gulf energy and capacity supplied to Entergy Louisiana under the Unit Power Sales Agreement. The LPSC directive noted that the initial decision issued by the presiding ALJ in the Grand Gulf sale-leaseback complaint proceeding did not address, for procedural reasons, certain rate issues raised by the LPSC and declined to order further investigation of rates charged by System Energy.

Unit Power Sales Agreement Complaint

The first of the additional complaints was filed by the LPSC, the APSC, the MPSC, and the City Council in September 2020. The first complaint raised two sets of rate allegations: violations of the filed rate and a corresponding request for refunds for prior periods; and elements of the Unit Power Sales Agreement are unjust and unreasonable and a corresponding request for refunds for the 15-month refund period and changes to the Unit Power Sales Agreement prospectively. Several of the filed rate allegations overlapped with the previous complaints. The filed rate allegations not previously raised were that System Energy: failed to provide a rate base credit to customers for the “time value” of sale-leaseback lease payments collected from customers in advance of the time those payments were due to the owner-lessors; improperly included certain sale-leaseback transaction costs in rate base as prepayments; improperly included nuclear refueling outage costs in rate base; wrongly included categories of accumulated deferred income taxes as increases to rate base; charged customers based on a higher equity ratio than would be appropriate due to excessive retained earnings; and did not correctly reflect money pool investments and imprudently invested cash into the money pool. The elements of the Unit Power Sales Agreement that the complaint alleged were unjust and unreasonable include: the current cash working capital allowance of zero, uncapped recovery of incentive and executive compensation, lack of an equity re-opener, and recovery of lobbying and private airplane travel expenses. The complaint also requested a rate investigation into the Unit Power Sales Agreement and System Energy’s billing practices pursuant to section 206 of the Federal Power Act, including any issue relevant to the Unit Power Sales Agreement and its inputs. System Energy filed its answer opposing the complaint in November 2020. In its answer, System Energy argued that all of the claims raised in the complaint should be dismissed and agreed that bill adjustment with respect to two discrete issues were justified. System Energy argued that dismissal was warranted because all claims fell into one or more of the following categories: the claims had been raised and were being litigated in another proceeding; the claims did not present a prima facie case and did not satisfy the threshold burden to establish a complaint proceeding; the claims were premised on a theory or request relief that is incompatible with federal law or FERC policy; the claims request relief that is inconsistent with the filed rate; the claims were barred or waived by the legal doctrine of laches; and/or the claims had been fully addressed and do not warrant further litigation. In December 2020, System Energy filed a bill adjustment report indicating that $3.4 million had been credited to customers in connection with the two discrete issues concerning the inclusion of certain accumulated deferred income taxes balances in rates.

In May 2021 the FERC issued an order addressing the complaint, establishing a refund effective date of September 21, 2020, establishing hearing procedures, and holding those procedures in abeyance pending the FERC’s review of the initial decision in the Grand Gulf sale-leaseback renewal complaint discussed above. System

102

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Energy agreed that the hearing should be held in abeyance but sought rehearing of FERC’s decision as related to matters set for hearing that were beyond the scope of FERC’s jurisdiction or authority. The complainants sought rehearing of FERC’s decision to hold the hearing in abeyance and filed a motion to proceed, which motion System Energy opposed. In June 2021, System Energy’s request for rehearing was denied by operation of law, and System Energy filed an appeal of FERC’s orders in the Court of Appeals for the Fifth Circuit. In November 2021 the Fifth Circuit dismissed the appeal as premature.

In August 2021 the FERC issued an order addressing System Energy’s and the complainants’ rehearing requests. The FERC dismissed part of the complaint seeking an equity re-opener, maintained the abeyance for issues related to the proceeding addressing the sale-leaseback renewal and uncertain tax positions, lifted the abeyance for issues unrelated to that proceeding, and clarified the scope of the hearing.

In November 2021 the LPSC, the APSC, and the City Council filed direct testimony and requested the FERC to order refunds for prior periods and prospective amendments to the Unit Power Sales Agreement. The LPSC’s refund claims included, among other things, allegations that: (1) System Energy should not have included certain sale-leaseback transaction costs in prepayments; (2) System Energy should have credited rate base to reflect the time value of money associated with the advance collection of lease payments; (3) System Energy incorrectly included refueling outage costs that were recorded in account 174 in rate base; and (4) System Energy should have excluded several accumulated deferred income tax balances in account 190 from rate base. The LPSC also sought a retroactive adjustment to retained earnings and capital structure in conjunction with the implementation of its proposed refunds. In addition, the LPSC sought amendments to the Unit Power Sales Agreement going forward to address below-the-line costs, incentive compensation, the working capital allowance, litigation expenses, and the 2019 termination of the capital funds agreement. The APSC argued that: (1) System Energy should have included borrowings from the Entergy system money pool in its determination of short-term debt in its cost of capital; and (2) System Energy should credit customers with System Energy’s allocation of earnings on money pool investments. The City Council alleged that System Energy has maintained excess cash on hand in the money pool and that retention of excess cash was imprudent. Based on this allegation, the City Council’s witness recommended a refund of approximately $98.8 million for the period 2004-September 2021 or other alternative relief. The City Council further recommended that the FERC impose a hypothetical equity ratio such as 48.15% equity to capital on a prospective basis.

In January 2022, System Energy filed answering testimony arguing that the FERC should not order refunds for prior periods or any prospective amendments to the Unit Power Sales Agreement. In response to the LPSC’s refund claims, System Energy argued, among other things, that: (1) the inclusion of sale-leaseback transaction costs in prepayments was correct; (2) that the filed rate doctrine bars the request for a retroactive credit to rate base for the time value of money associated with the advance collection of lease payments; (3) that an accounting misclassification for deferred refueling outage costs had been corrected, caused no harm to customers, and requires no refunds; and (4) that its accounting and ratemaking treatment of specified accumulated deferred income tax balances in account 190 had been correct. System Energy further responded that no retroactive adjustment to retained earnings or capital structure should be ordered because there was no general policy requiring such a remedy, and there was no showing that the retained earnings element of the capital structure was incorrectly implemented. Further, System Energy presented evidence that all of the costs that were being challenged were long known to the retail regulators and were approved by them for inclusion in retail rates, and the attempt to retroactively challenge these costs, some of which had been included in rates for decades, was unjust and unreasonable. In response to the LPSC’s proposed going-forward adjustments, System Energy presented evidence to show that none of the proposed adjustments were needed. On the issue of below-the-line expenses, during discovery procedures System Energy identified a historical allocation error in certain months and agreed to provide a bill credit to customers to correct the error. In response to the APSC’s claims, System Energy argued that the Unit Power Sales Agreement did not include System Energy’s borrowings from the Entergy system money pool or earnings on deposits to the Entergy system money pool in the determination of the cost of capital; and accordingly, no refunds were appropriate on those issues. In response to the City Council’s claims, System Energy argued that it has reasonably managed its cash and that the City Council’s theory of cash management was defective because it

103

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

failed to adequately consider the relevant cash needs of System Energy and it made faulty presumptions about the operation of the Entergy system money pool. System Energy further pointed out that the issue of its capital structure was already subject to pending FERC litigation.

In March 2022 the FERC trial staff filed direct and answering testimony in response to the LPSC, the APSC, and the City Council’s direct testimony. In its testimony, the FERC trial staff recommended refunds for two primary reasons: (1) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with rate refunds; and (2) it concluded that System Energy should have excluded specified accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. The FERC trial staff recommended refunds of $84.1 million, exclusive of any tax gross-up or FERC interest. In addition, the FERC trial staff recommended the following prospective modifications to the Unit Power Sales Agreement: (1) inclusion of a rate base credit to recognize the time value of money associated with the advance collection of lease payments; (2) exclusion of executive incentive compensation costs for members of the Office of the Chief Executive and long-term performance unit costs where awards are based solely or primarily on financial metrics; and (3) exclusion of unvested, accrued amounts for stock options, performance units, and restricted stock awards. With respect to issues that ultimately concerned the reasonableness of System Energy’s rate of return, the FERC trial staff stated that it was unnecessary to consider such issues in the proceeding, in light of the pending case concerning System Energy’s return on equity and capital structure. On all other material issues raised by the LPSC, the APSC, and the City Council, the FERC trial staff recommended either no refunds or no modification to the Unit Power Sales Agreement.

In April 2022, System Energy filed cross-answering testimony in response to the FERC trial staff’s recommendations of refunds for the accumulated deferred income taxes issues and proposed modifications to the Unit Power Sales Agreement for the executive incentive compensation issues. In June 2022 the FERC trial staff submitted revised answering testimony, in which it recommended additional refunds associated with the accumulated deferred income tax balances in account 190 associated with a deemed contract satisfaction and reissuance that occurred in 2005. Based on the testimony revisions, the FERC trial staff’s recommended refunds total $106.6 million, exclusive of any tax gross-up or FERC awarded interest. Also in June 2022, System Energy filed revised and supplemental cross-answering testimony to respond to the FERC trial staff’s testimony and oppose its revised recommendation.

In May 2022 the LPSC, the APSC, and the City Council filed rebuttal testimony. The LPSC’s testimony asserted new claims, including that: (1) certain of the sale-leaseback transaction costs may have been imprudently incurred; (2) accumulated deferred income taxes associated with sale-leaseback transaction costs should have been included in rate base; (3) accumulated deferred income taxes associated with federal investment tax credits should have been excluded from rate base; (4) monthly net operating loss accumulated deferred income taxes should have been excluded from rate base; and (5) several categories of proposed rate changes, including executive incentive compensation, air travel, industry dues, and legal costs, also warranted historical refunds. The LPSC’s rebuttal testimony argued that refunds for the alleged tariff violations and other claims must be calculated by rerunning the Unit Power Sales Agreement formula rate; however, it included estimates of refunds associated with some, but not all, of its claims, totaling $286 million without interest. The City Council’s rebuttal testimony also proposed a new, alternate theory and claim for relief regarding System Energy’s participation in the Entergy system money pool, under which it calculates estimated refunds of approximately $51.7 million. The APSC’s rebuttal testimony agreed with the LPSC’s direct testimony that retained earnings should be adjusted in a comprehensive refund calculation. The testimony quantified the estimated impacts of three issues: (1) a $1.5 million reduction in the revenue requirement under the Unit Power Sales Agreement if System Energy’s borrowings from the money pool were included in short-term debt; (2) a $1.9 million reduction in the revenue requirement if System Energy’s allocated share of money pool earnings were credited through the Unit Power Sales Agreement; and (3) a $1.9 million reduction in the revenue requirement for every $50 million of refunds ordered in a given year, without interest. In total, excluding the settled issues noted below, the claims sought more than $700 million in refunds and interest, based on charges to all Unit Power Sales Agreement purchasers including Entergy Mississippi. The hearing before a FERC ALJ occurred between September and December 2022.

104

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

In November 2022, System Energy filed a partial settlement agreement with the APSC, the City Council, and the LPSC that resolved the following issues raised in the Unit Power Sales Agreement complaint: advance collection of lease payments, aircraft costs, executive incentive compensation, money pool borrowings, advertising expenses, deferred nuclear refueling outage costs, industry association dues, and termination of the capital funds agreement. The settlement provided that System Energy would provide a black box refund of $18 million (inclusive of interest), plus additional refund amounts with interest to be calculated for certain issues to be distributed to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans as the Utility operating companies other than Entergy Mississippi purchasing under the Unit Power Sales Agreement. The settlement further provided that if the APSC, the City Council, or the LPSC agreed to the global settlement System Energy entered into with the MPSC (discussed below), and such global settlement included a black box refund amount, then the black box refund for this settlement agreement would not be incremental or in addition to the global black box refund amount. The settlement agreement addressed other matters as well, including adjustments to rate base beginning in October 2022, exclusion of certain other costs, and inclusion of money pool borrowings, if any, in short-term debt within the cost of capital calculation used in the Unit Power Sales Agreement. In April 2023 the FERC approved the settlement agreement. The refund provided for in the settlement agreement was included in the May 2023 service month bills under the Unit Power Sales Agreement.

In May 2023 the presiding ALJ issued an initial decision finding that System Energy should have excluded multiple identified categories of accumulated deferred income taxes from rate base when calculating Unit Power Sales Agreement bills. The initial decision also found that the Unit Power Sales Agreement should be modified such that a cash working capital allowance of negative $36.4 million is applied prospectively. On the other non-settled issues for which the complainants sought refunds or changes to the Unit Power Sales Agreement, the initial decision ruled against the complainants.

System Energy disagreed with the ALJ’s findings concerning the accumulated deferred income taxes issues and cash working capital. In July 2023, System Energy filed a brief on exceptions to the initial decision’s accumulated deferred income taxes findings. Also in July 2023, the APSC, the LPSC, the City Council, and the FERC trial staff filed separate briefs on exceptions. In August 2023 all parties filed separate briefs opposing exceptions.

As discussed below in “System Energy Settlement with the MPSC,” “System Energy Settlement with the APSC,” and “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the MPSC, the APSC, and the City Council, and the LPSC have settled their claims related to this proceeding.

Grand Gulf Prudence Complaints

The second of the additional complaints was filed at the FERC in March 2021 by the LPSC, the APSC, and the City Council against System Energy, Entergy Services, Entergy Operations, and Entergy Corporation. The second complaint contained two primary allegations. First, it alleged that, based on the plant’s capacity factor and alleged safety performance, System Energy and the other respondents imprudently operated Grand Gulf during the period 2016-2020, and it sought refunds of at least $360 million in alleged replacement energy costs, in addition to other costs, including those that could only be identified upon further investigation. Second, it alleged that the performance and/or management of the 2012 extended power uprate of Grand Gulf was imprudent, and it sought refunds of all costs of the 2012 uprate that were determined to result from imprudent planning or management of the project. In addition to the requested refunds, the complaint asked that the FERC modify the Unit Power Sales Agreement to provide for full cost recovery only if certain performance indicators were met and to require pre-authorization of capital improvement projects in excess of $125 million before related costs could be passed through to customers in rates. In April 2021, System Energy and the other respondents filed their motion to dismiss and answer to the complaint. System Energy requested that the FERC dismiss the claims within the complaint. With respect to the claim concerning operations, System Energy argued that the complaint did not meet its legal burden

105

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

because, among other reasons, it failed to allege any specific imprudent conduct. With respect to the claim concerning the uprate, System Energy argued that the complaint failed because, among other reasons, the complainants’ own conduct prevented them from raising a serious doubt as to the prudence of the uprate. System Energy also requested that the FERC dismiss other elements of the complaint, including the proposed modifications to the Unit Power Sales Agreement, because they were not warranted. In February 2023 the FERC issued an order denying rehearing and thereby affirming its order setting the complaint for settlement and hearing procedures. In July 2023 the FERC chief ALJ terminated settlement procedures and appointed a presiding ALJ to oversee hearing procedures. In September 2023 a procedural schedule for hearing procedures was established. Also in September 2023 the LPSC authorized its staff to file an additional complaint concerning the prudence of System Energy’s operation and management of Grand Gulf in the year 2022. In October 2023 the LPSC, the APSC, and the City Council filed what they styled as an amended and supplemental complaint with the FERC against System Energy, Entergy Services, and Entergy Operations. In November 2023, System Energy answered the amended and supplemental complaint. Pursuant to the procedural schedule, the complainants’ testimony in the original complaint proceeding was filed in December 2023. System Energy’s answering testimony was filed in May 2024, and the FERC trial staff’s direct and answering testimony was filed in June 2024.

As discussed below in “System Energy Settlement with the APSC,” “System Energy Settlement with the City Council,” and “System Energy Settlement with the LPSC,” the APSC, the City Council, and the LPSC have settled all of their claims related to this proceeding.

System Energy Settlement with the MPSC

In June 2022, System Energy, Entergy Mississippi, and additional named Entergy parties involved in thirteen docketed proceedings before the FERC filed with the FERC a partial settlement agreement and offer of settlement. The settlement memorialized the Entergy parties’ agreement with the MPSC to globally resolve all actual and potential claims between the Entergy parties and the MPSC associated with those FERC proceedings and with System Energy’s past implementation of the Unit Power Sales Agreement.

The settlement provided for a black box refund of $235 million from System Energy to Entergy Mississippi. In addition, beginning with the July 2022 service month, the settlement provided for Entergy Mississippi’s bills from System Energy to be adjusted to reflect: an authorized rate of return on equity of 9.65%, a capital structure not to exceed 52% equity through June 2026, a rate base reduction for the advance collection of sale-leaseback rental costs, and the exclusion of certain long-term incentive plan performance unit costs from rates. The settlement was approved by the MPSC in June 2022 and the FERC in November 2022.

System Energy had previously recorded a provision and associated liability of $37 million for elements of the applicable litigation. In June 2022, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing the regulatory liability to $588 million, which consisted of $235 million for the settlement with the MPSC and $353 million for potential future refunds to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. Based on analysis of the then-pending complaints against System Energy and potential future settlement negotiations, in third quarter 2023, System Energy recorded a regulatory charge of $40 million to increase System Energy’s regulatory liability related to complaints against System Energy. System Energy paid the black box refund of $235 million to Entergy Mississippi in November 2022.

System Energy Settlement with the APSC

In October 2023, System Energy, Entergy Arkansas, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the APSC to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaints,” filed at the FERC in October 2023. System

106

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Energy, Entergy Arkansas, additional Entergy parties, and the APSC filed the settlement agreement and supporting materials with the FERC in November 2023.

The terms of the settlement with the APSC aligned with the $588 million global black box settlement reached between System Energy and the MPSC in June 2022 and provided for Entergy Arkansas to receive a black box refund of $142 million from System Energy, inclusive of $49.5 million already received by Entergy Arkansas from System Energy. In addition, beginning with the November 2023 service month, the settlement provided for Entergy Arkansas’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity through June 2026. In March 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $93 million to Entergy Arkansas in 2024.

System Energy Settlement with the City Council

In April 2024, System Energy, Entergy New Orleans, and additional named Entergy parties involved in multiple docketed proceedings pending before the FERC reached a settlement in principle with the City Council to globally resolve all of their actual and potential claims in those dockets and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed in “Grand Gulf Prudence Complaints” above, filed by the LPSC, the APSC, and the City Council at the FERC in October 2023. In May 2024, System Energy, Entergy New Orleans, additional named Entergy parties, and the City Council filed the settlement agreement and supporting materials with the FERC.

The terms of the settlement with the City Council aligned with the $588 million global black box settlement amount reflected in the prior settlements reached between System Energy and the MPSC in June 2022 and between System Energy and the APSC in November 2023. The settlement provided for Entergy New Orleans to receive a black box refund of $116 million from System Energy, inclusive of approximately $18 million already received by Entergy New Orleans from System Energy. In addition, beginning with the June 2024 service month, the settlement provided for Entergy New Orleans’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity through June 2026. In August 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $98 million to Entergy New Orleans in October 2024.

System Energy Settlement with the LPSC

In July 2024, System Energy and the LPSC staff reached a settlement in principle to globally resolve all of the LPSC’s actual and potential claims in multiple docketed proceedings pending before the FERC (including all docketed proceedings resolved by the MPSC, the APSC, and the City Council settlements) and with System Energy’s past implementation of the Unit Power Sales Agreement. The settlement also covered the amended and supplemental complaint, discussed above in “Grand Gulf Prudence Complaints,” filed by the LPSC, the APSC, and the City Council at the FERC in October 2023. In August 2024 the LPSC approved the settlement. In September 2024 the settling parties filed the settlement for approval by the FERC.

The terms of the settlement with the LPSC staff aligned with the $588 million global black box settlement amount reflected in the prior settlements reached between System Energy and the MPSC in June 2022, between System Energy and the APSC in November 2023, and between System Energy and the City Council in April 2024. The settlement in principle provided for Entergy Louisiana to receive a black box refund of $95 million from System Energy, inclusive of approximately $15 million already received by Entergy Louisiana from System Energy. In addition, beginning with the September 2024 service month, the settlement provided for Entergy Louisiana’s bills from System Energy to be adjusted to reflect an authorized rate of return on equity of 9.65% and a capital structure not to exceed 52% equity through June 2026. In November 2024 the FERC approved the settlement, and System Energy paid the remaining black box refund of $80 million to Entergy Louisiana in December 2024.

107

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

The settlement also included an agreement that, subject to the receipt of necessary regulatory approvals, Entergy Louisiana would divest to Entergy Mississippi all of its interest in Grand Gulf capacity and energy under the Unit Power Sales Agreement and its purchases from Entergy Arkansas under the MSS-4 replacement tariff. In October 2024 Entergy Louisiana and Entergy Mississippi filed with the FERC a PPA under which Entergy Mississippi would purchase Entergy Louisiana’s purchases of Grand Gulf capacity and energy. The PPA was governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies. The requisite approvals for the PPA were issued by the FERC in November 2024 and the MPSC in February 2025. The divestiture was effective as of January 1, 2025. In compliance with the settlement, in May 2025, System Energy, Entergy Louisiana, and Entergy Mississippi submitted the following filings with the FERC: (1) a Federal Power Act Section 203 application seeking approval for the permanent divestiture by Entergy Louisiana to Entergy Mississippi of its rights to capacity and energy from Grand Gulf; and (2) a Federal Power Act Section 205 application seeking approval to modify the entitlement percentages of the remaining purchasers under the Unit Power Sales Agreement in connection with the foregoing divestiture. In July 2025, the FERC issued an order accepting the Federal Power Act Section 205 application to remove Entergy Louisiana as a party to the Unit Power Sales Agreement. As a result of the order, the Unit Power Sales Agreement entitlement percentages of the remaining purchasers were permanently modified to exclude Entergy Louisiana effective October 2025. The FERC also issued an order dismissing the Federal Power Act Section 203 application based on lack of jurisdiction. In September 2025 the APSC filed a request for rehearing of the FERC’s July 2025 order accepting the revised Unit Power Sales Agreement entitlement percentages. In November 2025 the FERC issued an order denying the APSC’s rehearing request. See Note 8 to the financial statements for additional information regarding the Unit Power Sales Agreement.

Unit Power Sales Agreement

System Energy Formula Rate Annual Protocols Formal Challenges Concerning 2020-2022 Calendar Year Bills

System Energy’s Unit Power Sales Agreement includes formula rate protocols that provide for the disclosure of cost inputs, an opportunity for informal discovery procedures, and a challenge process. In February 2022, pursuant to the protocols procedures, the LPSC, the APSC, the MPSC, the City Council, and the Mississippi Public Utilities Staff filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2020. In March 2023, pursuant to the protocols procedures discussed above, the LPSC, the APSC, and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2021. In February 2024, pursuant to the protocols procedures, the LPSC and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2022. These formal challenges were ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” above for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

Depreciation Amendment Proceeding

In December 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to adopt updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses. The proposed amendments would result in higher charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. In February 2022 the FERC accepted System Energy’s proposed increased depreciation rates with an effective date of March 1, 2022, subject to refund pending the outcome of the settlement and/or hearing procedures. In June 2023 System Energy filed with the FERC an unopposed offer of settlement that it had negotiated with intervenors to the proceeding. In August 2023 the FERC approved the settlement, which resolves the proceeding. In third quarter 2023, System Energy recorded a reduction in depreciation expense of $41 million representing the cumulative difference in depreciation expense resulting from the depreciation rates used from March 2022 through June 2023 and the depreciation rates included in the

108

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

settlement filing approved by the FERC. In October 2023, System Energy filed a refund report with the FERC. The refund provided for in the refund report was included in the September 2023 service month bills under the Unit Power Sales Agreement. No comments or protests to the refund report were filed.

Pension Costs Amendment Proceeding

In October 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to include in rate base the prepaid and accrued pension costs associated with System Energy’s qualified pension plans. Based on data ending in 2020, the increased annual revenue requirement associated with the filing is approximately $8.9 million. In March 2022 the FERC accepted System Energy’s proposed amendments with an effective date of December 1, 2021, subject to refund pending the outcome of the settlement and/or hearing procedures. In August 2023 the FERC chief ALJ terminated settlement procedures and designated a presiding ALJ to oversee hearing procedures. Testimony was filed by the parties from October 2023 through April 2024, and the hearing concluded in June 2024.

In September 2024 the presiding ALJ issued an initial decision recommending that the FERC approve inclusion of a line item in rate base for prepaid and accrued pension costs; however, the presiding ALJ did not agree with System Energy’s proposed methodology to calculate the value of the prepaid and accrued pension cost input. Instead, the presiding ALJ recommended limiting System Energy’s recovery to the prepaid and accrued pension costs that were incurred beginning in 2015 and later. The ALJ’s initial decision was not binding on the FERC and was an interim step in the hearing process.

System Energy disputed the presiding ALJ's determination concerning the methodology used to calculate the prepaid and accrued pension input, and System Energy filed exceptions to these rulings in October 2024. In October 2024, the LPSC, the APSC, and the FERC trial staff filed separate briefs on exceptions; these parties generally argue that the presiding ALJ should have rejected System Energy’s filing entirely, rather than limit System Energy’s recovery of the prepaid and accrued pension costs. Later in October 2024, System Energy, the LPSC, the APSC, and the FERC trial staff filed separate briefs opposing exceptions.

In November 2025 the FERC issued an order on the initial decision and reversed the ALJ’s decision. The FERC approved System Energy’s proposed prepaid and accrued pension recovery mechanism. System Energy has been utilizing this methodology in billings since December 1, 2022 and will continue to utilize it going forward. As a result of the FERC’s order, System Energy does not owe any refunds. In December 2025 the APSC filed a request for rehearing of the November 2025 order. In January 2026 the FERC denied the APSC’s rehearing request by operation of law. The FERC indicated that the APSC’s request for rehearing will be addressed substantively in a future order. This proceeding is not covered by the global settlements described above.

MSS-4 Replacement Tariff – Net Operating Loss Carryforward Proceeding

In January 2021, pursuant to section 205 of the Federal Power Act, Entergy Services filed an amendment to the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies, in order to provide for the inclusion of specified accumulated deferred income taxes, including net operating loss carryforward accumulated deferred income taxes (NOLC ADIT), in the rate for sales of energy among the Utility operating companies on a prospective basis. In March 2021, the FERC accepted the filing, subject to refund and hearing procedures.

In October 2021 the LPSC filed a complaint with the FERC alleging that Entergy Services improperly excluded NOLC ADIT from MSS-4 replacement tariff rates in the period before March 20, 2021. The LPSC argued that sales from Entergy Louisiana to Entergy Texas and Entergy New Orleans were charged at rates lower than they otherwise should have been, and it accordingly seeks surcharges for the period prior to March 20, 2021. The FERC set the complaint for hearing procedures and subsequently the hearing for this complaint proceeding was consolidated with the hearing procedures for Entergy Services’ January 2021 NOLC ADIT filing.

109

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Testimony was filed by parties in 2023, and the hearing before a FERC ALJ was concluded in February 2024. In June 2024, the FERC ALJ issued an initial decision addressing three major issues: (1) whether Entergy Services’ proposed prospective inclusion and allocation of NOLC ADIT in MSS-4 replacement tariff rates using a modified with-and-without methodology is just and reasonable; (2) whether Entergy Services correctly calculated excess and deficient accumulated deferred income taxes in accordance with the terms of a prior settlement; and (3) whether NOLC ADIT should have been included in MSS-4 replacement tariff rates prior to the effective date of the January 2021 MSS-4 replacement tariff filing.

With respect to issues (1) and (2), the presiding ALJ concluded that Entergy Services’ proposed methodology for allocating and including NOLC ADIT in MSS-4 replacement tariff rates was just and reasonable and that Entergy Services correctly performed the excess and deficient accumulated deferred income taxes calculations. With respect to issue (3), however, the presiding ALJ agreed with the LPSC that NOLC ADIT should have been included in MSS-4 replacement tariff rates since September 1, 2016, and as a result, the presiding ALJ ordered that Entergy Louisiana and Entergy Arkansas recalculate bills for the period of September 1, 2016 through November 11, 2023 with surcharges expected to be due to those operating companies from the purchasing operating companies, Entergy New Orleans, Entergy Texas, and Entergy Louisiana (for some Entergy Arkansas sales). The presiding ALJ also ordered Entergy Services to pay the interest owed to Entergy Louisiana on these surcharges.

The surcharge methodology that the presiding ALJ recommended in connection with issue (3) was not supported by any participant in the hearing. As part of their exceptions to the initial decision, all parties to the proceeding opposed the use of the ALJ’s methodology, except for the FERC trial staff, which took no position. During the hearing, the LPSC and the FERC trial staff advocated that the alleged tariff violation should be remedied by the application of Entergy Services’ January 2021 proposed methodology. All other parties, including the PUCT, the City Council, and Entergy Services, opposed any surcharges for the period prior to the March 20, 2021 effective date of the January 2021 filing.

Entergy Services disputes the presiding ALJ's rulings on issue (3) and filed exceptions to these rulings in July 2024. The ALJ's initial decision is not binding on the FERC and is an interim step in the hearing process. No refunds will be owed in connection with this proceeding unless and until the FERC requires them in a final order.

The MSS-4 replacement tariff includes protocols that provide for the disclosure of cost inputs, an opportunity for informal discovery procedures, and a challenge process. In April 2025, pursuant to such protocols, the City Council filed with the FERC a formal challenge relating to Entergy Services’ inclusion and allocation of net operating loss carryforward accumulated deferred income taxes in the MSS-4 replacement tariff rates charged to Entergy New Orleans’s monthly bills for calendar year 2023. In May 2025, Entergy Services filed a response to the formal challenge and is awaiting a response from the FERC.

Storm Cost Recovery Filings with Retail Regulators

Entergy Louisiana

Hurricane Francine

In September 2024, Hurricane Francine caused damage to the areas served by Entergy Louisiana and Entergy New Orleans. The storm resulted in widespread power outages, primarily due to damage to distribution infrastructure as a result of strong winds and heavy rain, and the loss of sales during the power outages.

In December 2024, and subsequently amended in an errata filed in February 2025, Entergy Louisiana submitted an application to the LPSC seeking a determination that approximately $183.6 million in storm restoration costs associated with Hurricane Francine were reasonable and necessary and, therefore, eligible for recovery from customers, as well as approval to recover approximately $3.6 million in certain carrying costs from

110

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

customers. The $183.6 million included approximately $152.8 million in distribution capital costs and approximately $29.8 million in non-capital costs; the balance consisted of transmission and generation capital costs. Entergy Louisiana proposed in its application to recover its distribution-related capital costs of $152.8 million through the distribution recovery mechanism of its formula rate plan. Entergy Louisiana further requested the LPSC to authorize recovery of these distribution-related capital expenses through an interim rate adjustment, subject to true-up and refund, that would begin with the first billing cycle of March 2025. Entergy Louisiana also requested to recover, from its storm reserve escrow account, $33.5 million, which consisted of non-capital costs and certain carrying costs. Entergy Louisiana also proposed to recover the transmission and generation capital costs through separate ratemaking proceedings. See further discussion of the 2023 formula rate plan filing above. Also in February 2025, Entergy Louisiana withdrew the $33.5 million from its funded storm reserves. In June 2025 the LPSC staff filed direct testimony. The LPSC staff recommended approval of Entergy Louisiana’s as-requested storm restoration costs with the exception of approximately $10.6 million, comprised primarily of estimates of mutual assistance invoices that had not yet been received at the time of filing and that ultimately exceeded the actual amounts invoiced, as well as certain incentive compensation, and $1.8 million associated with certain carrying costs. In September 2025, Entergy Louisiana reached a settlement with the LPSC staff pursuant to which Entergy Louisiana and the LPSC staff agreed on the amounts recoverable by Entergy Louisiana in connection with Hurricane Francine. Both intervenors in the proceeding stated they did not oppose the settlement. A hearing on the proposed settlement before the ALJ occurred in October 2025. Pursuant to the terms of the settlement, Entergy Louisiana returned $1.9 million to its funded storm reserves in October 2025. The LPSC voted unanimously at its November 2025 meeting to adopt the settlement, and the order adopting the settlement was issued in December 2025.

Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida

In August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. The storms resulted in widespread outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild.

In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta. Subsequently, Entergy Louisiana and the LPSC staff filed a joint motion seeking approval to exclude from the derivation of Entergy Louisiana’s capital structure and cost rate of debt for ratemaking purposes, including the allowance for funds used during construction, shorter-term debt up to $1.1 billion issued by Entergy Louisiana to fund costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta costs on an interim basis. In November 2020 the LPSC issued an order approving the joint motion, and Entergy Louisiana issued $1.1 billion of 0.62% Series mortgage bonds due November 2023. Also in November 2020, Entergy Louisiana withdrew $257 million from its funded storm reserves.

In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to Louisiana. Ice accumulation sagged or downed trees, limbs, and power lines, causing damage to Entergy Louisiana’s transmission and distribution systems. The additional weight of ice caused trees and limbs to fall into power lines and other electric equipment. When the ice melted, it affected vegetation and electrical equipment, causing additional outages. Entergy Louisiana recovered the incremental fuel costs associated with Winter Storm Uri over a five-month period from April 2021 through August 2021.

In April 2021, Entergy Louisiana filed an application with the LPSC relating to Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri restoration costs and in July 2021, Entergy Louisiana made a supplemental filing updating the total restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by these storms were estimated to be approximately $2.06 billion,

111

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

including approximately $1.68 billion in capital costs and approximately $380 million in non-capital costs. Including carrying costs through January 2022, Entergy Louisiana sought an LPSC determination that $2.11 billion was prudently incurred and, therefore, was eligible for recovery from customers. Additionally, Entergy Louisiana requested that the LPSC determine that re-establishment of a storm escrow account to the previously authorized amount of $290 million was appropriate. In July 2021, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021.

In August 2021, Hurricane Ida caused extensive damage to Entergy Louisiana’s distribution and, to a lesser extent, transmission systems resulting in widespread power outages. In September 2021, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments in connection with the issuance of approximately $1 billion of shorter-term mortgage bonds to provide interim financing for restoration costs associated with Hurricane Ida, which bonds were issued in October 2021. Also in September 2021, Entergy Louisiana sought approval for the creation and funding of a $1 billion restricted escrow account for Hurricane Ida related restoration costs, subject to a subsequent prudence review.

After filing of testimony by the LPSC staff and intervenors, which generally supported or did not oppose Entergy Louisiana’s requests in regard to Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida, the parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in February 2022. The settlement agreement contained the following key terms: $2.1 billion of restoration costs from Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and eligible for recovery; carrying costs of $51 million were recoverable; a $290 million cash storm reserve should be re-established; a $1 billion reserve should be established to partially pay for Hurricane Ida restoration costs; and Entergy Louisiana was authorized to finance $3.186 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. The LPSC issued an order approving the settlement in March 2022. As a result of the financing order, Entergy Louisiana reclassified $1.942 billion from utility plant to other regulatory assets.

In May 2022 the securitization financing closed, resulting in the issuance of $3.194 billion principal amount of bonds by Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA), a political subdivision of the State of Louisiana. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana legislature approved in 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust I (the storm trust I).

Pursuant to Act 293, the net proceeds of the bonds were used by the storm trust I to purchase 31,635,718.7221 Class A preferred, non-voting membership interest units (the preferred membership interests) issued by Entergy Finance Company. Entergy Finance Company is required to make annual distributions (dividends) commencing on December 15, 2022 on the preferred membership interests issued to the storm trust I. These annual dividends received by the storm trust I will be distributed to Entergy Louisiana and the LURC, as beneficiaries of the storm trust I. Specifically, 1% of the annual dividends received by the storm trust I will be distributed to the LURC, for the benefit of customers, and 99% will be distributed to Entergy Louisiana, net of storm trust expenses. The preferred membership interests have a stated annual cumulative cash dividend rate of 7% and a liquidation price of $100 per unit. The terms of the preferred membership interests include certain financial covenants to which Entergy Finance Company is subject. Semi-annual redemptions of the preferred membership interests, subject to certain conditions, are expected to occur over the next 15 years.

112

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy Louisiana began collecting the system restoration charge effective with the first billing cycle of June 2022 and the system restoration charge is expected to remain in place for up to 15 years. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust I is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial.

From the proceeds from the issuance of the preferred membership interests, Entergy Finance Company distributed $1.4 billion to its then-current parent, Entergy Holdings Company, LLC, a company wholly-owned and consolidated by Entergy. Subsequently, Entergy Holdings Company liquidated, distributing the $1.4 billion it received from Entergy Finance Company to Entergy Louisiana as holder of 6,843,780.24 units of Class A, 4,126,940.15 units of Class B, and 2,935,152.69 units of Class C preferred membership interests. Entergy Louisiana had acquired these preferred membership interests with proceeds from previous securitizations of storm restoration costs. Entergy Finance Company loaned the remaining $1.7 billion from the preferred membership interests proceeds to Entergy which used the cash to redeem $650 million of 4.00% Series senior notes due July 2022 and indirectly contributed $1 billion to Entergy Louisiana as a capital contribution.

Entergy Louisiana used the $1 billion capital contribution to fund its Hurricane Ida escrow account and subsequently withdrew the $1 billion from the escrow account. With a portion of the $1 billion withdrawn from the escrow account and the $1.4 billion from the Entergy Holdings Company liquidation, Entergy Louisiana deposited $290 million in a restricted escrow account as a storm damage reserve for future storms, used $1.2 billion to repay its unsecured term loan due June 2023, and used $435 million to redeem a portion of its 0.62% Series mortgage bonds due November 2023.

The securitization resulted in recognition of a reduction of income tax expense of approximately $290 million by Entergy Louisiana. Entergy’s recognition of reduced income tax expense was partially offset by other tax charges resulting in a net reduction of income tax expense of $283 million. In recognition of obligations described in an LPSC ancillary order issued as part of the securitization regulatory proceeding, Entergy Louisiana recorded a $224 million ($165 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to provide credits to its customers. Entergy Louisiana is returning a portion of the credits to customers through the storm cost offset rider through 2034.

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust I as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in the financial statements.

In April 2022, Entergy Louisiana filed an application with the LPSC relating to Hurricane Ida restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Ida were estimated to be approximately $2.54 billion, including approximately $1.96 billion in capital costs and approximately $586 million in non-capital costs. Including carrying costs of $57 million through December 2022, Entergy Louisiana was seeking an LPSC determination that $2.60 billion was prudently incurred and, therefore, eligible for recovery from customers. As part of this filing, Entergy Louisiana also was seeking an LPSC determination that an additional $32 million in costs associated with the restoration of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta as well as Winter Storm Uri was prudently incurred. This amount was exclusive of the requested $3 million in carrying costs through December 2022. In total, Entergy Louisiana was requesting an LPSC determination that $2.64 billion was prudently incurred and, therefore, eligible for recovery from customers. As discussed above, in March 2022 the LPSC approved financing of a $1 billion storm escrow account from which funds were withdrawn to finance costs associated with Hurricane Ida restoration. In June 2022, Entergy Louisiana supplemented the application with a request regarding

113

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. In October 2022 the LPSC staff recommended a finding that the requested storm restoration costs of $2.64 billion, including associated carrying costs of $59.1 million, were prudently incurred and eligible for recovery from customers. The LPSC staff further recommended approval of Entergy Louisiana’s plans to securitize these costs, net of the $1 billion in funds withdrawn from the storm escrow account described above. The parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in December 2022. The settlement agreement contains the following key terms: $2.57 billion of restoration costs from Hurricane Ida, Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and eligible for recovery; carrying costs of $59.2 million were recoverable; and Entergy Louisiana was authorized to finance $1.657 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. A procedural motion to consider the uncontested settlement at the December 2022 LPSC meeting did not pass and the settlement was not voted on. In January 2023 an ALJ with the LPSC conducted a settlement hearing to receive the uncontested settlement and supporting testimony into evidence and issued a report of proceedings, which allows the LPSC to consider the uncontested settlement without the procedural motion that did not pass in December. In January 2023 the LPSC approved the stipulated settlement subject to certain modifications. These modifications include the recognition of accumulated deferred income tax benefits related to damaged assets and system restoration costs as a reduction of the amount authorized to be financed utilizing the securitization process authorized by Act 55, as supplemented by Act 293, from $1.657 billion to $1.491 billion. These modifications did not affect the LPSC’s conclusion that all system restoration costs sought by Entergy Louisiana were reasonable and prudent. In February 2023 the Louisiana Bond Commission voted to authorize the LCDA to issue the bonds authorized in the LPSC’s financing order.

In March 2023 the Hurricane Ida securitization financing closed, resulting in the issuance of approximately $1.491 billion principal amount of bonds by the LCDA and a remaining regulatory asset of $180 million to be recovered through the exclusion of the accumulated deferred income taxes related to damaged assets and system restoration costs from the determination of future rates. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust II (the storm trust II).

Pursuant to Act 293, the net proceeds of the bonds were used by the storm trust II to purchase 14,576,757.48 Class B preferred, non-voting membership interest units (the preferred membership interests) issued by Entergy Finance Company. Entergy Finance Company is required to make annual distributions (dividends) commencing on December 15, 2023 on the preferred membership interests issued to the storm trust II. These annual dividends received by the storm trust II will be distributed to Entergy Louisiana and the LURC, as beneficiaries of the storm trust II. Specifically, 1% of the annual dividends received by the storm trust II will be distributed to the LURC for the benefit of customers, and 99% will be distributed to Entergy Louisiana, net of storm trust expenses. The preferred membership interests have a stated annual cumulative cash dividend rate of 7.5% and a liquidation price of $100 per unit. The terms of the preferred membership interests include certain financial covenants to which Entergy Finance Company is subject. Semi-annual redemptions of the preferred membership interests, subject to certain conditions, are expected to occur over the next 15 years.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The system restoration charge is adjusted at least semi-annually to ensure that it is sufficient to service the bonds. Entergy Louisiana collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy Louisiana began collecting the system restoration charge effective with the first billing cycle of April 2023 and the system restoration charge is expected to remain in place for up to 15 years. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as a billing and collection agent for the

114

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust II is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial.

From the proceeds from the issuance of the preferred membership interests, Entergy Finance Company loaned approximately $1.5 billion to Entergy, which was indirectly contributed to Entergy Louisiana as a capital contribution.

As discussed in Note 3 to the financial statements, the securitization resulted in recognition of a net reduction of income tax expense of approximately $133 million, after taking into account a provision for uncertain tax positions, by Entergy Louisiana. Entergy’s recognition of reduced income tax expense was offset by other tax charges resulting in a net reduction of income tax expense of $129 million, after taking into account a provision for uncertain tax positions. In recognition of its obligations described in an LPSC ancillary order issued as part of the securitization regulatory proceeding, Entergy Louisiana recorded in first quarter 2023 a $103 million ($76 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to provide credits to its customers. Entergy Louisiana is returning a portion of the credits to customers through the storm cost offset rider through 2041.

As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust II as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in the financial statements. In first quarter 2023, Entergy Louisiana recorded a charge of $14.6 million in other income to reflect the LURC’s beneficial interest in the storm trust II.

Hurricane Isaac

In August 2012, Hurricane Isaac caused extensive damage to Entergy Louisiana’s service area. In June 2014 the LPSC authorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs. Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the LURC and the Louisiana State Bond Commission.

In August 2014 the LCDA issued $314.85 million in bonds under Louisiana Act 55. From the $309 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $16 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $293 million directly to Entergy Louisiana. Entergy Louisiana used the $293 million received from the LURC to acquire 2,935,152.69 Class C preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 7.5% annual distribution rate. Distributions were payable quarterly commencing on September 15, 2014, and the membership interests had a liquidation price of $100 per unit. The preferred membership interests were callable at the option of Entergy Holdings Company after ten years under the terms of the LLC agreement. The terms of the membership interests included certain financial covenants to which Entergy Holdings Company was subject, including the requirement to maintain a net worth of at least $1.75 billion. As discussed above in “Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida”, in May 2022, Entergy Holdings Company liquidated and distributed cash to Entergy Louisiana as holder of the 2,935,152.69 units of Class C preferred membership interests.

Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Louisiana collects a system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

115

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy Mississippi

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

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

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

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

Entergy New Orleans

Hurricane Ida

In August 2021, Hurricane Ida caused significant damage to Entergy New Orleans’s service area, including Entergy’s electrical grid. The storm resulted in widespread power outages, including the loss of 100% of Entergy New Orleans’s load and damage to distribution and transmission infrastructure, including the loss of connectivity to the eastern interconnection. In September 2021, Entergy New Orleans withdrew $39 million from its funded storm reserves. In June 2022, Entergy New Orleans filed an application with the City Council requesting approval and certification that storm restoration costs associated with Hurricane Ida of approximately $170 million, which

116

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

included $11 million in estimated costs, were reasonable, necessary, and prudently incurred to enable Entergy New Orleans to restore electric service to its customers and to repair Entergy New Orleans’s electric utility infrastructure. In addition, estimated carrying costs through December 2022 related to Hurricane Ida restoration costs were $9 million. Also, Entergy New Orleans requested approval that the $39 million withdrawal from its funded storm reserve in September 2021 and $7 million in excess storm reserve escrow withdrawals related to Hurricane Zeta in October 2020 and prior miscellaneous storms were properly applied to Hurricane Ida storm restoration costs, the application of which reduced the amount to be recovered from Entergy New Orleans customers by $46 million.

Additionally, in February 2022, Entergy New Orleans and the LURC filed with the City Council a securitization application requesting that the City Council review Entergy New Orleans’s storm reserve and increase the storm reserve funding level to $150 million, to be funded through securitization. In August 2022 the City Council’s advisors recommended that the City Council authorize a single securitization bond issuance to fund Entergy New Orleans’s storm recovery reserves to an amount sufficient to: (1) allow recovery of all of Entergy New Orleans’s unrecovered storm recovery costs following Hurricane Ida, subject to City Council review and certification; (2) provide initial funding of storm recovery reserves for future storms to a level of $75 million; and (3) fund the storm recovery bonds’ upfront financing costs. In September 2022, Entergy New Orleans and the City Council’s advisors entered into an agreement in principle, which was approved by the City Council along with a financing order in October 2022, which authorized Entergy New Orleans and the LURC to proceed with a single securitization bond issuance of approximately $206 million (subject to further adjustment and review pursuant to the Final Issuance Advice Letter process set forth in the financing order), with $125 million of that total to be used for interim recovery, subject to City Council review and certification, to be allocated to unrecovered Hurricane Ida storm recovery costs; $75 million of that total to provide for a storm recovery reserve for future storms; and the remainder to fund the recovery of the storm recovery bonds’ upfront financing costs.

In December 2022, Entergy New Orleans and the LURC filed with the City Council the Final Issuance Advice Letter for a securitization bond issuance in the amount of $209.3 million, the final structuring, terms, and pricing of which were approved by the City Council in accordance with the financing order. Also in December 2022 the LCDA issued $209.3 million in bonds pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act, Part V-B of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Regular Session of 2021. The LCDA loaned $201.8 million of bond proceeds, net of certain debt service and issuance costs, to the LURC. The LURC used the proceeds to purchase from Entergy New Orleans the storm recovery property, which is the right to collect storm recovery charges sufficient to pay the storm recovery bonds and associated financing costs, and Entergy New Orleans deposited $200 million in a restricted storm reserve escrow account as a storm damage reserve for Entergy New Orleans and received directly $1.8 million in estimated upfront financing costs. Subsequently, Entergy New Orleans withdrew $125 million from the newly securitized storm reserve to cover Hurricane Ida storm recovery costs, subject to a final determination from the City Council regarding the prudency of the storm recovery costs.

Entergy and Entergy New Orleans do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy or Entergy New Orleans in the event of a bond default. To service the bonds, Entergy New Orleans collects a storm recovery charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy and Entergy New Orleans do not report the collections as revenue because Entergy New Orleans is merely acting as the billing and collection agent for the LURC.

In August 2023 the City Council advisors issued a report recommending that the City Council find that Entergy New Orleans prudently incurred approximately $164.1 million in storm restoration costs and $7.5 million in carrying charges and that such costs have already been properly recovered by Entergy New Orleans through withdrawals from the storm reserve escrow account. The City Council advisors also recommended that the City Council find that approximately $1.2 million in storm restoration costs had already been recovered through Entergy New Orleans’s base rates and that approximately $0.9 million in unused credits be applied against future storm

117

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

costs. In August 2023 the City Council hearing officer certified the evidentiary record. In December 2023 the City Council approved a resolution adopting the advisors’ report and recommendations.

NOTE 3. INCOME TAXES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Income taxes for Entergy for 2025, 2024, and 2023 consist of the following:


	2025	2024	2023
	(In Thousands)
Current
Federal	$3,427	$66,708	$60,639
State	6,890	44,956	23,014
Total	10,317	111,664	83,653
Deferred and non-current - net
Federal	408,851	136,671	(815,222)
State	85,757	144,519	46,281
Total	494,608	281,190	(768,941)
Investment tax credits - net
Federal	(6,452)	(10,178)	(4,852)
State	(521)	(1,649)	(395)
Total	(6,973)	(11,827)	(5,247)
Income taxes	$497,952	$381,027	($690,535)

State income taxes are accrued primarily in the states in which the Registrant Subsidiaries operate, which includes Arkansas, Louisiana, Mississippi, and Texas.

Income taxes for the Registrant Subsidiaries for 2025, 2024, and 2023 consist of the following:


2025	Entergy Arkansas	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)
Current
Federal	($21,471)	($104,215)	$49,157	$18,671	$4,479	($3,190)
State	(4,595)	(2,779)	8,905	3,169	3,442	(3,115)
Total	(26,066)	(106,994)	58,062	21,840	7,921	(6,305)
Deferred and non-current - net
Federal	117,798	297,466	26,320	(3,398)	58,464	18,485
State	17,379	51,897	10,991	(2,387)	(252)	7,339
Total	135,177	349,363	37,311	(5,785)	58,212	25,824
Investment tax credits - net
Federal	(1,231)	(4,556)	(76)	(200)	(767)	381
State	—	—	(196)	—	—	(325)
Total	(1,231)	(4,556)	(272)	(200)	(767)	56
Income taxes	$107,880	$237,813	$95,101	$15,855	$65,366	$19,575

118

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements


2024	Entergy Arkansas	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)
Current
Federal	($10,558)	($79,519)	$38,680	($8,022)	$8,281	($5,527)
State	(2,275)	1,709	2,407	5,331	5,468	(396)
Total	(12,833)	(77,810)	41,087	(2,691)	13,749	(5,923)
Deferred and non-current - net
Federal	68,988	201,737	25,316	9,297	51,588	29,470
State	19,649	106,098	14,292	(2,916)	1,114	9,939
Total	88,637	307,835	39,608	6,381	52,702	39,409
Investment tax credits - net
Federal	(1,230)	(4,616)	3	(848)	—	(2,716)
State	—	—	(383)	—	(767)	(1,267)
Total	(1,230)	(4,616)	(380)	(848)	(767)	(3,983)
Income taxes	$74,574	$225,409	$80,315	$2,842	$65,684	$29,503


2023	Entergy Arkansas	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)
Current
Federal	$33,100	($142,253)	$20,328	($99,343)	$2,851	$337
State	(4,201)	(6,397)	4,142	(5,854)	3,719	(1,570)
Total	28,899	(148,650)	24,470	(105,197)	6,570	(1,233)
Deferred and non-current - net
Federal	(164,493)	(94,167)	21,244	(78,442)	56,496	26,528
State	37,615	41,716	9,446	(6,302)	570	4,477
Total	(126,878)	(52,451)	30,690	(84,744)	57,066	31,005
Investment tax credits - net
Federal	(1,231)	(4,680)	(622)	(32)	(764)	2,482
State	—	—	(174)	—	—	(222)
Total	(1,231)	(4,680)	(796)	(32)	(764)	2,260
Income taxes	($99,210)	($205,781)	$54,364	($189,973)	$62,872	$32,032

State income taxes are accrued primarily based on the retail jurisdiction in which each of the Utility operating companies operates and is subject to retail regulation for ratemaking purposes. Each Utility operating company serves retail customers within a single jurisdiction, which governs the determination of its state income tax cost of service and the related accruals. System Energy’s state income tax accrual pertains solely to Mississippi, the only state in which it operates.

119

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Income taxes paid (received) for Entergy and the Registrant Subsidiaries for 2025 consist of the following:


2025	Entergy	Entergy Arkansas	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
		(In Thousands)
US Federal (a)	($519,892)	($215,224)	($198,285)	$—	$—	$21,000	($133,752)
US Federal - ETAA	—	(25,975)	(146,563)	82,541	7,076	—	5,715
US state
Arkansas	—	—	—	—	—	—	—
Louisiana	2,726	—	—	—	2,550	—	—
Mississippi	—	—	—	—	—	—	—
Texas	2,077	—	—	—	—	2,077	—
State tax - ETAA	—	(3,712)	553	—	471	440	(3,260)
Other	18	—	—	—	—	—	—
Total US state	4,821	(3,712)	553	—	3,021	2,517	(3,260)
Total income taxes paid (received)	($515,071)	($244,911)	($344,295)	$82,541	$10,097	$23,517	($131,297)

(a)Federal income taxes paid (received) includes the receipt of production tax credit sale proceeds at Entergy of $547 million, including $215 million, $198 million, and $134 million at Entergy Arkansas, Entergy Louisiana, and System Entergy, respectively.

The table above disaggregates income taxes paid (net of refunds) by type, including amounts remitted to U.S. federal and state taxing authorities and amounts paid under the Entergy Tax Allocation Agreement (ETAA). The ETAA governs intercompany settlements of income tax obligations between the Registrant Subsidiaries and Entergy, as if the Registrant Subsidiaries were separate taxpayers on a stand-alone or separate company basis, as applicable. Payments under the ETAA are shown separately to distinguish them from direct remittances to taxing authorities. State income taxes presented reflect amounts attributable to the jurisdiction in which the Registrant Subsidiary has its primary state tax nexus.

120

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Total income taxes for Entergy differ from the amounts computed by applying the statutory income tax rate to income before income taxes. The reasons for the differences for the years 2025, 2024, and 2023 are:


	2025		2024		2023
	(Dollars In Thousands)
Net income attributable to Entergy Corporation	$1,758,272		$1,055,590		$2,356,536
Preferred dividend requirements of subsidiaries and noncontrolling interests	15,056		5,594		5,774
Consolidated net income	1,773,328		1,061,184		2,362,310
Income taxes	497,952		381,027		(690,535)
Income before income taxes	$2,271,280		$1,442,211		$1,671,775

Income taxes computed at Federal Statutory Tax rate	$476,969	21%	$302,864	21%	$351,073	21%
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect	92,942	4.1%	81,377	5.6%	70,144	4.2%
Regulatory differences - utility plant items	(30,443)	(1.3%)	(30,288)	(2.1%)	(27,901)	(1.7%)
Equity component of AFUDC	(37,357)	(1.6%)	(27,343)	(1.9%)	(20,172)	(1.2%)
Tax credits - amortization of investment tax credits	(8,067)	(0.4%)	(8,808)	(0.6%)	(7,978)	(0.5%)
Nontaxable or nondeductible items/flow-through	9,925	0.4%	33	—%	(1,374)	(0.1%)
Amortization of deficient/(excess) ADIT (a)	(25,947)	(1.1%)	19,169	1.3%	9,102	0.5%
IRS audit resolution (b)	—	—%	—	—%	(842,769)	(50.4%)
Reversal of regulatory liability (c)	—	—%	—	—%	(105,649)	(6.3%)
Entergy Louisiana securitization (d)	—	—%	—	—%	(129,034)	(7.7%)
State audit resolution (e)	—	—%	(9,057)	(0.6%)	—	—%
Enactment of new tax laws - state rate change (a)	—	—%	28,636	2.0%	—	—%
Changes in unrecognized tax benefits	12,434	0.5%	21,487	1.5%	18,884	1.1%
Changes in valuation allowances	4,134	0.2%	(780)	(0.1%)	(8,697)	(0.5%)
Other - net	3,362	0.1%	3,737	0.3%	3,836	0.2%
Total income taxes / Effective Tax Rate	$497,952	21.9%	$381,027	26.4%	($690,535)	(41.3%)

(a)See “Other Tax Matters - Arkansas and Louisiana Corporate Income Tax Rate Changes” below for details.

(b)See “Income Tax Audits - 2016-2018 IRS Audit” below for discussion of the resolution of the 2016-2018 IRS audit in 2023.

(c)See Note 2 to the financial statements for discussion of Entergy Louisiana’s reversal of a regulatory liability, primarily associated with the Hurricane Isaac securitization, initially recognized in 2017 as a result of the Tax Cuts and Jobs Act.

(d)See “Other Tax Matters – Act 293 Securitizations” below for discussion of the Entergy Louisiana March 2023 storm cost securitizations.

(e)See “Income Tax Audits - State Income Tax Audits” below for discussion of the resolution of the 2014-2018 Arkansas Department of Finance and Administration examination in 2024.

121

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Total income taxes for the Registrant Subsidiaries differ from the amounts computed by applying the statutory income tax rate to income before taxes. The reasons for the differences for each Registrant Subsidiary for the years 2025, 2024, and 2023 are:

Entergy Arkansas


	2025		2024		2023
	(Dollars In Thousands)
Earnings applicable to member’s equity	$440,532		$324,766		$402,081
Net loss attributable to noncontrolling interest	(3,079)		(5,300)		(5,231)
Net income	437,453		319,466		396,850
Income taxes	107,880		74,574		(99,210)
Income before income taxes	$545,333		$394,040		$297,640

Income taxes computed at Federal Statutory Tax rate statutory rate	$114,520	21%	$82,748	21%	$62,504	21%
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect	19,388	3.6%	13,940	3.5%	13,291	4.5%
Regulatory differences - utility plant items	(8,085)	(1.5%)	(9,885)	(2.5%)	(8,812)	(3.0%)
Equity component of AFUDC	(4,934)	(0.9%)	(6,032)	(1.5%)	(4,093)	(1.4%)
Tax credits - amortization of investment tax credits	(1,201)	(0.2%)	(1,201)	(0.3%)	(1,201)	(0.4%)
Nontaxable or nondeductible items/flow-through	(1,866)	(0.3%)	214	0.1%	1,105	0.4%
Amortization of deficient/(excess) ADIT (a)	(11,276)	(2.1%)	10,193	2.6%	(6,095)	(2.0%)
IRS audit resolution (b)	—	—%	—	—%	(159,588)	(53.6%)
State audit resolution (e)	—	—%	(18,276)	(4.6%)	—	—%

Changes in unrecognized tax benefits	(1,182)	(0.2%)	1,800	0.5%	2,600	0.9%
Changes in valuation allowances	1,462	0.3%	—	—%	—	—%
Other - net	1,054	0.2%	1,073	0.3%	1,079	0.4%
Total income taxes / Effective Tax Rate	$107,880	19.8%	$74,574	18.9%	($99,210)	(33.3%)

122

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy Louisiana


	2025		2024		2023
	(Dollars In Thousands)
Earnings applicable to member’s equity	$1,109,948		$887,645		$1,270,382
Net income attributable to noncontrolling interests	2,952		3,126		2,988
Net income	1,112,900		890,771		1,273,370
Income taxes	237,813		225,409		(205,781)
Income before income taxes	$1,350,713		$1,116,180		$1,067,589

Income taxes computed at Federal Statutory Tax rate statutory rate	$283,650	21%	$234,398	21%	$224,194	21%
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect	49,965	3.7%	50,760	4.5%	51,899	4.9%
Regulatory differences - utility plant items	(10,069)	(0.7%)	(9,988)	(0.9%)	(5,535)	(0.5%)
Equity component of AFUDC	(11,327)	(0.8%)	(7,513)	(0.7%)	(6,754)	(0.6%)
Tax credits - amortization of investment tax credits	(4,502)	(0.3%)	(4,563)	(0.4%)	(4,625)	(0.4%)
Nontaxable or nondeductible items/flow-through	(718)	(0.1%)	(3,244)	(0.3%)	126	—%
Amortization of deficient/(excess) ADIT (a)	(13,327)	(1.0%)	9,305	0.8%	14,032	1.3%
IRS audit resolution (b)	—	—%	—	—%	(179,111)	(16.8%)
Reversal of regulatory liability (c)	—	—%	—	—%	(105,649)	(9.9%)
Entergy Louisiana securitization (d)	—	—%	—	—%	(133,443)	(12.5%)
Enactment of new tax laws - state rate change (a)	—	—%	16,307	1.5%	—	—%
Non-taxable dividend income	(61,352)	(4.5%)	(64,982)	(5.8%)	(62,116)	(5.8%)
Changes in unrecognized tax benefits	4,307	0.3%	3,400	0.3%	(400)	—%
Changes in valuation allowances	5	—%	—	—%	—	—%
Other - net	1,181	0.1%	1,529	0.1%	1,601	0.1%
Total income taxes / Effective Tax Rate	$237,813	17.6%	$225,409	20.2%	($205,781)	(19.3%)

123

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy Mississippi


	2025		2024		2023
	(Dollars In Thousands)
Earnings applicable to member’s equity	$311,864		$255,958		$192,271
Net loss attributable to noncontrolling interest	(3,136)		(10,551)		(10,302)
Net income	308,728		245,407		181,969
Income taxes	95,101		80,315		54,364
Income before income taxes	$403,829		$325,722		$236,333

Income taxes computed at Federal Statutory Tax rate statutory rate	$84,804	21%	$68,402	21%	$49,630	21%
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect	15,876	3.9%	13,210	4.1%	11,133	4.7%
Regulatory differences - utility plant items	(5,400)	(1.3%)	(3,572)	(1.1%)	(5,290)	(2.2%)
Equity component of AFUDC	(1,984)	(0.5%)	(1,910)	(0.6%)	(1,796)	(0.8%)
Tax credits - amortization of investment tax credits	(228)	(0.1%)	(267)	(0.1%)	(223)	(0.1%)
Nontaxable or nondeductible items/flow-through	1,581	0.4%	2,987	0.9%	3,534	1.5%
IRS audit resolution (b)	—	—%	—	—%	(3,291)	(1.4%)
Changes in unrecognized tax benefits	93	—%	1,100	0.3%	300	0.1%
Other - net	359	0.1%	365	0.1%	367	0.2%
Total income taxes / Effective Tax Rate	$95,101	23.5%	$80,315	24.7%	$54,364	23.0%

Entergy New Orleans


	2025		2024		2023
	(Dollars In Thousands)
Net income	$50,411		$15,847		$228,938
Income taxes	15,855		2,842		(189,973)
Income before income taxes	$66,266		$18,689		$38,965

Income taxes computed at Federal Statutory Tax rate statutory rate	$13,916	21%	$3,925	21%	$8,183	21%
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect	3,985	6.0%	1,248	6.7%	1,907	4.9%
Regulatory differences - utility plant items	(131)	(0.2%)	(830)	(4.4%)	(1,353)	(3.5%)
Equity component of AFUDC	(390)	(0.6%)	(445)	(2.4%)	(309)	(0.8%)
Tax credits - amortization of investment tax credits	(97)	(0.1%)	(839)	(4.5%)	(25)	(0.1%)
Nontaxable or nondeductible items/flow-through	(1,138)	(1.7%)	(338)	(1.8%)	(1,913)	(4.9%)
Amortization of deficient/(excess) ADIT (a)	(1,344)	(2.0%)	(332)	(1.8%)	1,147	2.9%
IRS audit resolution (b)	—	—%	—	—%	(198,424)	(509.2%)
Enactment of new tax laws - state rate change (a)	—	—%	242	1.3%	—	—%
Changes in unrecognized tax benefits	847	1.3%	—	—%	600	1.5%
Other - net	207	0.3%	211	1.1%	214	0.5%
Total income taxes / Effective Tax Rate	$15,855	23.9%	$2,842	15.2%	($189,973)	(487.5%)

124

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy Texas


	2025		2024		2023
	(Dollars In Thousands)
Earnings applicable to common stock	$331,999		$291,550		$289,201
Preferred dividend requirements	2,072		2,072		2,072
Net income	334,071		293,622		291,273
Income taxes	65,366		65,684		62,872
Income before income taxes	$399,437		$359,306		$354,145

Income taxes computed at Federal Statutory Tax rate statutory rate	$83,882	21%	$75,454	21%	$74,370	21%
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect	2,731	0.7%	5,164	1.4%	2,574	0.7%
Regulatory differences - utility plant items	(3,427)	(0.9%)	(4,537)	(1.3%)	(6,394)	(1.8%)
Equity component of AFUDC	(17,172)	(4.3%)	(10,045)	(2.8%)	(5,920)	(1.7%)
Tax credits - amortization of investment tax credits	(748)	(0.2%)	(748)	(0.2%)	(748)	(0.2%)
Nontaxable or nondeductible items/flow-through	(149)	—%	(760)	(0.2%)	1,493	0.4%
Amortization of deficient ADIT (a)		—%	2	—%	17	—%
IRS audit resolution (b)		—%	—	—%	(3,112)	(0.9%)
Changes in unrecognized tax benefits	(122)	—%	777	0.2%	211	0.1%
Other - net	371	0.1%	377	0.1%	381	0.1%
Total income taxes / Effective Tax Rate	$65,366	16.4%	$65,684	18.3%	$62,872	17.8%

System Energy


	2025		2024		2023
	(Dollars In Thousands)
Net income	$88,095		$103,500		$108,772
Income taxes	19,575		29,503		32,032
Income before income taxes	$107,670		$133,003		$140,804

Income taxes computed at Federal Statutory Tax rate statutory rate	$22,611	21%	$27,931	21%	$29,569	21%
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect	4,893	4.5%	4,936	3.7%	5,798	4.1%
Regulatory differences - utility plant items	(3,330)	(3.1%)	(1,475)	(1.1%)	(517)	(0.4%)
Equity component of AFUDC	(1,549)	(1.4%)	(1,398)	(1.1%)	(1,301)	(0.9%)
Tax credits - amortization of investment tax credits	(1,155)	(1.1%)	(1,155)	(0.9%)	(1,155)	(0.8%)
Nontaxable or nondeductible items/flow-through	(1,057)	(1.0%)	(538)	(0.4%)	(191)	(0.1%)
IRS audit resolution (b)	—	—%	—	—%	(1,575)	(1.1%)
Changes in unrecognized tax benefits	(1,036)	(1.0%)	1,000	0.8%	1,200	0.9%
Other - net	198	0.2%	202	0.2%	204	0.1%
Total income taxes / Effective Tax Rate	$19,575	18.2%	$29,503	22.2%	$32,032	22.7%

(a)See “Other Tax Matters - Arkansas and Louisiana Corporate Income Tax Rate Changes” below for details.

(b)See “Income Tax Audits - 2016-2018 IRS Audit” below for discussion of the resolution of the 2016-2018 IRS audit in 2023.

125

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

(c)See Note 2 to the financial statements for discussion of Entergy Louisiana’s reversal of a regulatory liability, primarily associated with the Hurricane Isaac securitization, recognized in 2017 as a result of the Tax Cuts and Jobs Act.

(d)See “Other Tax Matters - Act 293 Securitizations” below for discussion of the Entergy Louisiana March 2023 storm cost securitizations.

(e)See “Income Tax Audits - State Income Tax Audits” below for discussion of the resolution of the 2014-2018 Arkansas Department of Finance and Administration examination in 2024.

Significant components of accumulated deferred income taxes and taxes accrued for Entergy Corporation and Subsidiaries as of December 31, 2025 and 2024 are as follows:


	2025	2024
	(In Thousands)
Deferred tax liabilities:
Plant basis differences - net	($7,183,430)	($6,451,189)
Regulatory assets	(1,030,792)	(1,003,045)
Nuclear decommissioning trusts/receivables	(601,444)	(563,423)
Pension, net regulatory asset	(323,779)	(303,007)
Combined unitary state taxes	(2,911)	(3,600)
Power purchase agreements	13,270	(89,614)
Deferred fuel	(20,652)	(23,305)
Other	(161,274)	(206,648)
Total	(9,311,012)	(8,643,831)
Deferred tax assets:
Regulatory liabilities	1,325,440	1,394,937
Nuclear and other decommissioning liabilities	169,880	164,685
Pension and other postretirement benefits	27,723	22,646
Compensation	87,837	79,580
Accumulated deferred investment tax credit	49,248	52,709
Provision for allowances and contingencies	191,295	141,769
Unbilled/deferred revenues	(3,586)	(9,960)
Net operating loss carryforwards	2,761,672	2,672,993
Capital losses and miscellaneous tax credits	145,625	111,325
Valuation allowance	(335,105)	(338,508)
Other	167,209	212,563
Total	4,587,238	4,504,739
Non-current accrued taxes (including unrecognized tax benefits)	(853,367)	(309,669)
Accumulated deferred income taxes and taxes accrued	($5,577,141)	($4,448,761)

126

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy’s estimated tax attributes carryovers and their expiration dates as of December 31, 2025 are as follows:

Carryover Description

Carryover Amount

Year(s) of expiration

Federal net operating losses before 1/1/2018

$4.4 billion

2028-2037

Federal net operating losses - 1/1/2018 forward

$14.4 billion

N/A

State net operating losses

$4.3 billion

2028-2045

State net operating losses with no expiration

$9.0 billion

N/A

Other federal and state carryforwards

$128.5 million

2026-2030

Miscellaneous federal and state credits

$413.3 million

2026-2045

As a result of the accounting for uncertain tax positions, the amount of the deferred tax assets reflected in the financial statements is less than the amount of the tax effect of the federal and state net operating loss carryovers, tax credit carryovers, and other tax attributes generated and reflected on income tax returns. Entergy evaluates the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate character will be generated to realize the benefits of existing deferred tax assets. When the evaluation indicates that Entergy will not be able to realize the existing benefits, a valuation allowance is recorded to reduce deferred tax assets to the realizable amount.

Because it is more likely than not that the benefits from certain state net operating losses and other federal and state deferred tax assets will not be utilized, valuation allowances totaling $335 million as of December 31, 2025 and $339 million as of December 31, 2024 have been provided on the deferred tax assets related to federal and state jurisdictions in which Entergy does not currently expect to be able to utilize certain separate company tax return attributes, preventing realization of such deferred tax assets. Certain accelerated tax deductions which generated taxable losses in various taxing jurisdictions, and which have a limited term carryover period, have resulted in the impairment of the realizability of such carryovers and are reflected in the valuation allowance disclosed above.

127

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Significant components of accumulated deferred income taxes and taxes accrued for the Registrant Subsidiaries as of December 31, 2025 and 2024 are as follows:


2025	Entergy Arkansas	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)
Deferred tax liabilities:
Plant basis differences - net	($1,752,176)	($2,993,462)	($927,853)	($243,442)	($788,106)	($473,895)
Regulatory assets	(237,989)	(469,902)	(39,316)	(53,375)	(111,154)	(119,157)
Nuclear decommissioning trusts/receivables	(223,747)	(202,364)	—	—	—	(175,341)
Pension, net regulatory asset	(102,847)	(87,917)	(26,416)	(8,725)	(15,642)	—
Power purchase agreements	13,633	(76,837)	1,140	(11,226)	(4,578)	—

Deferred fuel	(6,775)	(9,718)	(3,186)	(1)	(943)	(17)
Other	(20,874)	(88,305)	(4,763)	(2,208)	(6,158)	(10,214)
Total	(2,330,775)	(3,928,505)	(1,000,394)	(318,977)	(926,581)	(778,624)
Deferred tax assets:
Regulatory liabilities	348,063	595,662	51,201	70,190	35,726	226,660
Nuclear and other decommissioning liabilities	138,516	14,616	(155)	(407)	(449)	17,220
Pension and other postretirement benefits	(31,745)	41,555	(7,377)	(15,975)	(24,479)	(27,660)
Compensation	4,418	5,764	3,196	1,077	2,531	139
Accumulated deferred investment tax credit	6,067	23,882	3,291	3,909	1,358	10,740
Valuation allowance	(1,727)	(5)	—	—	—	—
Provision for allowances and contingencies	49,359	70,167	32,112	36,608	16,701	225
Unbilled/deferred revenues	5,490	(18,816)	897	(129)	8,561	—
Net operating loss carryforwards	169,743	360,028	—	6,803	54	84,302
Capital losses and miscellaneous tax credits	45,982	18,554	8,795	16,693	1,125	11,245
Other	10,373	40,459	(1,193)	612	404	36
Total	744,539	1,151,866	90,767	119,381	41,532	322,907
Non-current accrued taxes (including unrecognized tax benefits)	(260,477)	(316,579)	(17,107)	(1,749)	(62,018)	(169,448)
Accumulated deferred income taxes and taxes accrued	($1,846,713)	($3,093,218)	($926,734)	($201,345)	($947,067)	($625,165)

128

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements


2024	Entergy Arkansas	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)
Deferred tax liabilities:
Plant basis differences - net	($1,530,196)	($2,729,299)	($849,623)	($272,182)	($727,242)	($466,361)
Regulatory assets	(219,773)	(497,177)	(37,374)	(72,389)	(100,959)	(75,606)
Nuclear decommissioning trusts/receivables	(185,725)	(202,364)	—	—	—	(175,341)
Pension, net regulatory asset	(101,887)	(84,732)	(26,064)	(9,687)	(16,569)	—
Power purchase agreements	11,993	(97,846)	1,140	(12,385)	(5,148)	—
Deferred fuel	—	(4,785)	(17,234)	(1,247)	—	(78)
Other	(24,430)	(106,590)	(5,231)	(5,133)	(4,512)	(13,572)
Total	(2,050,018)	(3,722,793)	(934,386)	(373,023)	(854,430)	(730,958)
Deferred tax assets:
Regulatory liabilities	310,621	678,086	53,046	89,385	37,325	229,065
Nuclear and other decommissioning liabilities	127,933	18,649	—	(407)	97	17,956
Pension and other postretirement benefits	(29,923)	39,379	(8,989)	(19,443)	(23,403)	(24,642)
Compensation	4,851	7,119	3,277	1,394	2,596	515
Accumulated deferred investment tax credit	6,360	26,549	3,355	4,205	1,515	10,724
Provision for allowances and contingencies	31,686	59,448	11,361	23,998	4,358	225
Unbilled/deferred revenues	3,546	(24,017)	1,274	715	7,925	—
Net operating loss carryforwards	126,255	336,128	305	30,740	50	69,611
Capital losses and miscellaneous tax credits	14,489	17,029	8,206	16,220	1,273	10,788
Other	11,608	54,207	1,096	1,692	1,189	—
Total	607,426	1,212,577	72,931	148,499	32,925	314,242
Non-current accrued taxes (including unrecognized tax benefits)	(46,577)	32,262	(8,661)	22,983	(47,344)	(35,114)
Accumulated deferred income taxes and taxes accrued	($1,489,169)	($2,477,954)	($870,116)	($201,541)	($868,849)	($451,830)

129

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

The Registrant Subsidiaries’ estimated tax attributes carryovers and their expiration dates as of December 31, 2025 are as follows:

Entergy Arkansas

Entergy Louisiana

Entergy Mississippi

Entergy New Orleans

Entergy Texas

System Energy

Federal net operating losses before 1/1/2018

$— million

$812.8 million

$— million

Year(s) of expiration

N/A

2035-2037

N/A

2037

N/A

Federal net operating losses - 1/1/2018 forward

$802.9 million

$2.2 billion

$— million

$1.4 billion

$357.1 million

Year(s) of expiration

N/A

State net operating losses

$628.1 million

$6 billion

$— million

$181.3 million

$1.1 million

$314.2 million

Year(s) of expiration

2028-2032

N/A

2028

2042-2045

Misc. federal credits

$16.1 million

$24.5 million

$6.2 million

$17.4 million

$1.1 million

$6.3 million

Year(s) of expiration

2038-2045

2035-2045

2038-2045

2037-2045

2039-2045

2029-2045

State credits

$— million

$1.1 million

$8.6 million

$— million

$0.6 million

$19 million

Year(s) of expiration

N/A

2026-2028

N/A

2027-2033

2026-2028

Unrecognized tax benefits

Accounting standards establish a “more-likely-than-not” recognition threshold that must be met before a tax benefit can be recognized in the financial statements. If a tax deduction is taken on a tax return but does not meet the more-likely-than-not recognition threshold, an increase in income tax liability, above what is payable on the tax return, is required to be recorded. A reconciliation of Entergy’s beginning and ending amount of unrecognized tax benefits is as follows:


	2025	2024	2023
	(In Thousands)
Gross balance at January 1	$2,354,867	$2,439,910	$6,393,599
Additions based on tax positions related to the current year (a)	272,758	12,731	332,884
Additions for tax positions of prior years (a)	590,465	21,149	194,894
Reductions for tax positions of prior years (b)	(23,168)	(85,715)	(1,300,381)
Settlements (b)	—	(33,208)	(3,181,086)

Gross balance at December 31	3,194,922	2,354,867	2,439,910
Offsets to gross unrecognized tax benefits:
Loss and tax credit carryovers	(2,332,640)	(2,079,778)	(2,160,484)
Cash paid to taxing authorities	(54,000)	(27,000)	—
Unrecognized tax benefits net of unused tax attributes and payments (c)	$808,282	$248,089	$279,426

(a)Amounts in 2025 are primarily related to production tax credits generated in 2024 and 2025. See “Other Tax Matters - Inflation Reduction Act of 2022” below.

(b)Amounts in 2023 are primarily related to the resolution of the 2016-2018 IRS audit as discussed in “Income Tax Audits - 2016-2018 IRS Audit” below. Amounts in 2024 are primarily related to the resolution of 2014-2018 Arkansas tax examination as discussed in “Income Tax Audits - State Income Tax Audits” below.

(c)Potential tax liability above what is payable on tax returns.

130

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

The balances of unrecognized tax benefits include $2,781 million, $1,900 million, and $1,899 million as of December 31, 2025, 2024, and 2023, respectively, which, if recognized, would lower the effective income tax rates. Because of the effect of deferred tax accounting, the remaining balances of unrecognized tax benefits of $414 million, $455 million, and $541 million as of December 31, 2025, 2024, and 2023, respectively, if disallowed, would not affect the annual effective income tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

Entergy accrues interest expense, if any, related to unrecognized tax benefits in income tax expense. Entergy’s December 31, 2025, 2024, and 2023 accrued balance for the possible payment of interest is approximately $42 million, $32 million, and $39 million, respectively. Interest (net-of-tax) of $10 million, ($7) million, and ($11) million was recorded in 2025, 2024, and 2023, respectively.

A reconciliation of the Registrant Subsidiaries’ beginning and ending amount of unrecognized tax benefits for 2025, 2024, and 2023 is as follows:


2025	Entergy Arkansas	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)
Gross balance at January 1, 2025	$45,413	$867,116	$5,989	$19,508	$384,333	$16,415
Additions based on tax positions related to the current year (a)	112,354	75,825	1,768	871	1,934	74,391
Additions for tax positions of prior years (a)	221,636	210,263	709	22	4,048	142,840
Reductions for tax positions of prior years	(1,152)	(6,167)	(555)	(847)	(887)	(165)
Gross balance at December 31, 2025	378,251	1,147,037	7,911	19,554	389,428	233,481
Offsets to gross unrecognized tax benefits:
Loss and tax credit carryovers	(142,860)	(721,552)	(6,000)	(4,744)	(285,936)	(92,561)
Unrecognized tax benefits net of unused tax attributes	$235,391	$425,485	$1,911	$14,810	$103,492	$140,920


2024	Entergy Arkansas	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)
Gross balance at January 1, 2024	$69,197	$864,043	$5,653	$19,331	$415,205	$14,301
Additions based on tax positions related to the current year	2,732	1,921	237	163	378	833
Additions for tax positions of prior years	25,784	10,357	536	153	560	1,281
Reductions for tax positions of prior years	(52,300)	(9,205)	(437)	(139)	(31,810)	—
Gross balance at December 31, 2024	45,413	867,116	5,989	19,508	384,333	16,415
Offsets to gross unrecognized tax benefits:
Loss and tax credit carryovers	(30,333)	(753,101)	(4,997)	(11,639)	(314,446)	(16,415)
Unrecognized tax benefits net of unused tax attributes	$15,080	$114,015	$992	$7,869	$69,887	$—

131

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements


2023	Entergy Arkansas	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)
Gross balance at January 1, 2023	$1,452,819	$1,350,836	$547,548	$638,726	$389,366	$23,702
Additions based on tax positions related to the current year (b)	2,249	332,320	209	78	196	752
Additions for tax positions of prior years	—	—	—	—	94,793	—
Reductions for tax positions of prior years (c)	(148,558)	(458,072)	(16,853)	(191,336)	(67,156)	(9,532)
Settlements (c)	(1,237,313)	(361,041)	(525,251)	(428,137)	(1,994)	(621)
Gross balance at December 31, 2023	69,197	864,043	5,653	19,331	415,205	14,301
Offsets to gross unrecognized tax benefits:
Loss and tax credit carryovers	(34,683)	(735,612)	(3,778)	(11,721)	(381,561)	(14,301)
Unrecognized tax benefits net of unused tax attributes	$34,514	$128,431	$1,875	$7,610	$33,644	$—

(a)Amounts in 2025 are primarily related to production tax credits generated in 2024 and 2025. See “Other Tax Matters - Inflation Reduction Act of 2022” below.

(b)The primary additions for Entergy Louisiana in 2023 are related to the Entergy Louisiana storm cost securitizations as discussed in “Other Tax Matters - Act 293 Securitizations” below.

(c)Amounts in 2023 are primarily related to the resolution of the 2016-2018 IRS audit as discussed in “Income Tax Audits - 2016-2018 IRS Audit” below.

The Registrant Subsidiaries’ balances of unrecognized tax benefits included amounts which, if recognized, would have reduced income tax expense as follows:


	December 31,
	2025	2024	2023
	(In Millions)
Entergy Arkansas	$360.3	$32.6	$57.2
Entergy Louisiana	$1,141.9	$868.2	$862.5
Entergy Mississippi	$1.7	$1.3	$1.0
Entergy New Orleans	$18.1	$18.3	$18.2
Entergy Texas	$113.6	$50.3	$2.9
System Energy	$218.0	$4.0	$3.1

Accrued balances for the possible payment of interest related to unrecognized tax benefits for the Registrant Subsidiaries are as follows:


	December 31,
	2025	2024	2023
	(In Millions)
Entergy Arkansas	$9.5	$8.4	$7.8
Entergy Louisiana	$13.7	$5.1	$1.5
Entergy Mississippi	$4.5	$3.2	$2.1
Entergy New Orleans	$1.9	$0.6	$0.6
Entergy Texas	$1.3	$0.5	$—
System Energy	$2.3	$2.9	$1.9

132

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

The Registrant Subsidiaries record interest and penalties related to unrecognized tax benefits in income tax expense. No penalties were recorded in 2025, 2024, and 2023. Interest (net-of-tax) was recorded as follows:


	2025	2024	2023
	(In Millions)
Entergy Arkansas	$1.1	$0.6	$3.5
Entergy Louisiana	$8.6	$3.6	($2.6)
Entergy Mississippi	$1.3	$1.1	($1.0)
Entergy New Orleans	$1.3	$—	($5.8)
Entergy Texas	$0.8	$0.5	($1.1)
System Energy	($0.6)	$1.0	$—

Income Tax Audits

Entergy and its subsidiaries file U.S. federal and various state income tax returns. IRS examinations are complete for years before 2019. All state taxing authorities’ examinations are complete for years before 2016. Entergy regularly defends its positions and works with the IRS to resolve audits. The resolution of audit issues could result in significant changes to the amounts of unrecognized tax benefits in the next twelve months.

2016-2018 IRS Audit

The IRS completed its examination of the 2016 through 2018 tax years and issued a Revenue Agent Report (RAR) for each federal filer under audit in November 2023. Entergy agreed to all adjustments contained in the RARs. Entergy and the Registrant Subsidiaries recorded all the material effects resulting from the RARs in the fourth quarter of 2023.

Utility Restructurings

In 2017, Entergy New Orleans undertook an internal restructuring, and in 2018, Entergy Arkansas and Entergy Mississippi also participated in internal restructurings under which these three Utility operating companies joined Entergy Louisiana as wholly-owned subsidiaries of Entergy Utility Holding Company, LLC. The change in ownership required Entergy to recognize Entergy Arkansas’s nuclear decommissioning liabilities for income tax purposes, which resulted in recognition of a gain for income tax purposes and a corresponding increase in the tax basis of assets, in accordance with the Internal Revenue Code and Treasury Regulations. Entergy determined that there was uncertainty regarding the treatment of certain aspects of the restructurings and recorded provisions for uncertain tax positions which are now considered to be effectively settled in accordance with accounting standards. The reversal of such provisions for uncertain tax positions resulted in a reduction of income tax expense of $156 million for Entergy Arkansas, $1 million for Entergy Mississippi, and $6 million for Entergy New Orleans.

The IRS also required Entergy New Orleans to reverse a tax gain associated with the 2017 restructuring that had been previously recognized, allowing Entergy New Orleans to reduce its tax expense by $39 million.

After the restructuring, Entergy Arkansas adopted a new method of accounting for income tax purposes in which its nuclear decommissioning costs are treated as production costs of electricity includable in cost of goods sold, which resulted in a $1.8 billion reduction in taxable income on its 2018 tax return that was treated as an unrecognized tax benefit. In conjunction with the audit, Entergy agreed with the IRS adjustments concerning the nuclear decommissioning tax position allowing Entergy Arkansas to include $102 million of its decommissioning liability in cost of goods sold.

133

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Mark-to-Market Method of Accounting

In 2016, Entergy Louisiana elected mark-to-market income tax treatment for various wholesale electric power purchase and sale agreements, including Entergy Louisiana’s contract to purchase electricity from the Vidalia hydroelectric facility and from System Energy under the Unit Power Sales Agreement as well as other intercompany power purchase agreements. The election resulted in a $2 billion deduction upon which a deferred tax liability was recorded. The IRS allowed the mark-to-market tax method of accounting associated with the Vidalia contract and various other third-party and intercompany wholesale electric power purchase and sale agreements. The IRS disallowed the net deductions associated with the Unit Power Sales Agreement, which did not have an effect on net tax expense. The net allowance resulted in a reversal of a provision for uncertain tax positions of $132 million and a corresponding reduction of income tax expense.

In 2017, Entergy New Orleans also elected mark-to-market income tax treatment for the Unit Power Sales Agreement and various intercompany wholesale electric contracts which resulted in a $1 billion deduction upon which a deferred tax liability was recorded. The IRS allowed the mark-to-market tax method of accounting associated with various intercompany and third-party wholesale electric contracts. The IRS disallowed the net deductions associated with the Unit Power Sales Agreement, which did not have an effect on net tax expense. The net allowance resulted in a reversal of a provision for uncertain tax positions of $139 million and a corresponding reduction of income tax expense.

In 2018, Entergy Arkansas and Entergy Mississippi each accrued approximately $2 billion in deductions upon which deferred tax liabilities were recorded related to mark-to-market tax accounting for the Unit Power Sales Agreement and various wholesale electric contracts. The IRS allowed the mark-to-market tax method of accounting associated with various intercompany and third-party wholesale electric contracts. The IRS disallowed the net deductions associated with the Unit Power Sales Agreement, which did not have an effect on net tax expense. The effective settlement of the mark-to-market tax position for Entergy Arkansas resulted in the accrual of an increase to tax expense of $40 million, which was offset by approximately $5 million of miscellaneous excess ADIT recognized as a result of the 2016-2018 IRS audit resolution. The net increase to tax expense is deferred as a regulatory asset, as discussed within the “Regulatory and Other Matters” section below.

Restructuring of Entergy’s Non-Utility Operations Business

During the 2016 to 2018 audit period, the ownership of certain of Entergy’s non-utility operations business nuclear power plants (previously reported as part of Entergy Wholesale Commodities) was restructured. Such restructuring transactions required Entergy to recognize the plants’ nuclear decommissioning liabilities for income tax purposes. The accrual of the nuclear decommissioning liabilities also required Entergy to recognize a gain for income tax purposes, a significant portion of which resulted in an increase in the tax basis of the assets. Because certain aspects of the restructuring transactions involved uncertainty, Entergy recorded a provision for uncertain tax positions. The IRS did not propose adjustments to the tax treatment of the restructuring transactions resulting in a net decrease to income tax expense of $288 million from the reversal of the provision for uncertain tax positions in fourth quarter 2023.

Reduction of Net Operating Loss Carryovers

The IRS audit reduced Entergy’s net operating loss carryover by $8 billion. A portion of Entergy’s audit adjustments were not offset by losses which resulted in a tax liability of $79 million, which was fully offset by prior deposits made by Entergy. Entergy received an assessment of interest in excess of prior deposits of $13 million in December 2023, and such interest was paid in January 2024.

Net operating loss carryovers were reduced by $4 billion for Entergy Arkansas, $1 billion for Entergy Louisiana, $2 billion for Entergy Mississippi, $1 billion for Entergy New Orleans, and $40 million for System

134

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Energy. The IRS audit adjustments were also factored into the settle-up required under Entergy’s ETAA, and such amounts were settled in the fourth quarter of 2023.

Regulatory and Other Matters

In accordance with prior regulatory agreements associated with the Entergy Louisiana and Entergy Gulf States Louisiana business combination and Entergy New Orleans restructuring and general rate-making principles, Entergy Louisiana and Entergy New Orleans, respectively, recorded a regulatory liability and an associated regulatory charge of $38 million and $60 million ($28 million and $44 million net-of-tax), in December 2023.

Additionally, in December 2023, a regulatory asset for income tax associated with deficient ADIT of $35 million, $2 million, and $3 million, was recorded for Entergy Arkansas, Entergy Louisiana, and Entergy Mississippi, respectively. See Note 2 to the financial statements for discussion of Entergy Arkansas’s regulatory activity related to the Tax Cuts and Jobs Act and discussion of the settlement of Entergy Arkansas’s 2023 formula rate plan.

As noted above, Entergy accrues interest expense related to unrecognized tax benefits in income tax expense. As a result of the IRS audit resolution, Entergy reversed approximately $24 million of interest related to the allowance of previously unrecognized tax benefits in December 2023.

Reversal of net deferred credits associated with the accounting for income taxes upon the resolution of the IRS audit resulted in a reduction/(increase) in income tax expense in December 2023 of $9 million, $42 million, ($2) million, $2 million, $2 million, and $1 million for Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy, respectively.

In April 2024, Entergy New Orleans and the City Council entered into a settlement in principle whereby Entergy New Orleans agreed to share with customers $138 million of income tax benefits from the resolution of the 2016–2018 IRS audit. Based on this settlement in principle, in first quarter 2024 Entergy New Orleans increased the associated regulatory liability from $60 million to $138 million and recorded a corresponding $78 million regulatory charge ($57 million net-of-tax). The settlement in principle requires that the regulatory liability be amortized over 25 years beginning January 2025 with the unamortized balance included in rate base and the amortization treated as a reduction to Entergy New Orleans’s retail revenue requirement. In May 2024 the City Council approved the settlement.

In September 2024 the LPSC unanimously approved a jointly filed global stipulated settlement agreement between Entergy Louisiana and the LPSC staff whereby Entergy Louisiana agreed to $184 million of customer rate credits to be given over two years, including customer sharing of income tax benefits resulting from the 2016-2018 IRS audit. See Note 2 to the financial statements for further discussion of the Entergy Louisiana agreement in principle and the subsequently filed global stipulated settlement agreement.

Included in the effect of the IRS audit on the results of operations was the measurement of deferred tax assets and liabilities influenced by the 2017 enactment of the Tax Cuts and Jobs Act income tax rate change discussed below. With the conclusion of the audit, there are no remaining federal unrecognized tax benefits affected by the rate differential which could impact income tax expense and the regulatory liability for income taxes in future periods.

State Income Tax Audits

In the third quarter 2024, Entergy and the Arkansas Department of Finance and Administration resolved the terms of the Arkansas Department of Finance and Administration’s outstanding tax assessments related to the examination of the 2014 through 2018 tax years. The agreement resulted in a payment of tax of approximately $8 million by Entergy. As a result of the income tax audit adjustments and the reversal of a provision for uncertain

135

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

tax positions, Entergy Arkansas recorded a net reduction in income tax expense of approximately $18 million, which was offset by approximately $9 million of income tax expense recorded by other Entergy subsidiaries, resulting in a net reduction in income tax expense for Entergy of $9 million.

Other Tax Matters

Tax Cuts and Jobs Act (TCJA)

The most significant effect of the TCJA for Entergy and the Registrant Subsidiaries was the change in the federal corporate income tax rate from 35% to 21%, effective January 1, 2018. Entergy had net regulatory liability balances of $1.1 billion and $1.2 billion as of December 31, 2025 and December 31, 2024, respectively. These liabilities were primarily associated with the re-measurement of deferred tax assets and liabilities due to the income tax rate change and subsequent amortization of excess ADIT. In addition to the unamortized protected excess ADIT amounts, the net regulatory liability for income taxes includes other regulatory assets and liabilities for income taxes that are primarily for the regulatory asset related to AFUDC, as described in Note 1 to the financial statements.

Excess ADIT is generally classified into two categories: (1) the portion that is subject to the normalization requirements of the TCJA, referred to as “protected”, and (2) the portion that is not subject to such normalization provisions, referred to as “unprotected”. The majority of the remaining unamortized excess ADIT as of December 31, 2025 is classified as protected. The TCJA mandates the normalization method of accounting for income taxes for excess ADIT associated with public utility property. The TCJA specifies the use of the average rate assumption method (ARAM) to determine the timing of the return of excess ADIT associated with such property. Under ARAM, the excess ADIT is reduced over the remaining life of the asset. Remaining asset lives vary for each Registrant Subsidiary, but the average life of public utility property is typically 30 years or longer. Entergy will amortize the protected portion of the excess ADIT in compliance with the normalization requirements.

Entergy’s net regulatory liability for income taxes includes a gross-up using the applicable tax rate to account for the effect of income taxes on the revenue requirement in the ratemaking formula. The Registrant Subsidiaries’ December 31, 2025 and December 31, 2024 balance sheets reflect net regulatory liabilities for income taxes as follows:


	2025	2024
	(In Millions)
Entergy Arkansas	$423	$418
Entergy Louisiana	$313	$355
Entergy Mississippi	$171	$181
Entergy New Orleans	$16	$15
Entergy Texas	$58	$94
System Energy	$100	$105

Inflation Reduction Act of 2022

The Inflation Reduction Act of 2022, signed into law on August 16, 2022, significantly expanded federal tax incentives for clean energy production, including the extension of production tax credits to solar projects and certain qualified nuclear power facilities.

Entergy Arkansas accrued solar production tax credits associated with the Walnut Bend Solar facility, the Driver Solar facility, and the West Memphis Solar facility of approximately $5 million in 2024 and approximately $35 million in 2025. As the value of such credits is expected to be provided to customers, a regulatory liability has been recorded for all credits recognized.

136

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

In second quarter 2025, Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy determined, based on current analysis and evolving regulatory developments, that it was appropriate to record zero-emission nuclear production tax credits under Internal Revenue Code section 45U for electricity generated in 2024 by their respective nuclear power facilities. Such credits have been claimed on the Entergy 2024 federal income tax return. Because the U.S. Treasury and the IRS have not issued final guidance regarding the application of Internal Revenue Code section 45U, including the definition of “gross receipts,” Entergy treated the full amount of the Internal Revenue Code section 45U credits as an uncertain tax position in accordance with the income tax accounting standards.

The value of the nuclear production tax credits was calculated based on the amount of electricity generated and sold by each nuclear generating unit owned by Entergy Arkansas, Entergy Louisiana, and System Energy during the year, multiplied by the applicable credit rate (i.e., dollars per kWh). The applicable credit rate included the incremental amount of credit for meeting the “prevailing wages” criteria under the Inflation Reduction Act. Entergy also applied the statutorily required reduction amount in arriving at the value of the nuclear production tax credits. This reduction amount was driven by the “gross receipts” received by each unit for its yearly energy production. For credits claimed on the Entergy 2024 federal income tax return, Entergy Arkansas, Entergy Louisiana, and System Energy recognized nuclear production tax credits of $221.4 million, $208.9 million, and $140.9 million, respectively, resulting in Entergy consolidated nuclear production tax credits of $571.2 million recognized in second quarter 2025. Additionally, in fourth quarter 2025, Entergy Arkansas, Entergy Louisiana, and System Energy recognized nuclear production tax credits expected to be claimed on the Entergy 2025 federal income tax return of $104.4 million, $58.6 million, and $72.1 million, respectively, resulting in Entergy consolidated nuclear production tax credits of $235.1 million. Entergy also treated the full amount of the 2025 Internal Revenue Code section 45U credits as an uncertain tax position in accordance with the income tax accounting standards. To the extent future guidance allows Entergy to recognize the value of the credits under the provisions of income tax accounting standards, the monetized value of the production tax credits, net of applicable expenses, is expected to be shared with customers.

During September and October 2025, Entergy Arkansas, Entergy Louisiana, and System Energy transferred the 2024 nuclear production tax credits to third parties and received cash of $210.1 million, $198.3 million, and $133.8 million, respectively, resulting in total Entergy cash receipts of $542.2 million. In addition, Entergy Arkansas sold its 2024 solar production tax credits to a third party and received cash receipts of approximately $5.1 million. The proceeds from the transfers reflected a market-based discount. In accordance with the Unit Power Sales Agreement and the MSS-4 replacement tariff, portions of the net proceeds from the transfers of the production tax credits were paid by Entergy Arkansas, Entergy Louisiana, and System Energy to the buyers of energy and capacity under those wholesale agreements. These provisions include the right to recover the transferred proceeds from the 2024 nuclear production tax credits and associated costs if all or a portion of the value of the credits is disallowed by the IRS. Based on these provisions and the uncertainty regarding the tax position, Entergy Arkansas, Entergy Louisiana, and System Energy recognized regulatory assets upon flowing through the proceeds of the credits. The Utility operating companies receiving the proceeds from the nuclear production tax credits recognized corresponding regulatory liabilities. These intercompany balances are eliminated on Entergy’s consolidated balance sheet.

In August 2025 the LPSC issued an order approving an agreement between Entergy Louisiana and the LPSC staff regarding the monetization of 2024 nuclear production tax credits. The order allows Entergy Louisiana to retain the net proceeds of the nuclear production tax credits while the associated tax position remains uncertain. While it retains the net proceeds, Entergy Louisiana will accrue a liability to its customers at its weighted average cost of capital. It further provides that customers will be responsible for the associated costs should the IRS reduce some or all of the value of the nuclear production tax credits transferred to third parties. Once the IRS makes a final determination affirming the value of the nuclear production tax credits or the audit period expires without the IRS making a final determination disallowing some or all of the value of the nuclear production tax credits, Entergy Louisiana will commence flowing to its customers the value of the nuclear production tax credits, including carrying charges. In January 2026 the APSC opened a docket to investigate the sale of Entergy Arkansas’s nuclear

137

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

production tax credits and the appropriate ratemaking treatment of production tax credits for all of Entergy Arkansas’s eligible resources, including how the proceeds of any sales should flow through to customers. As directed by the APSC, in February 2026, Entergy Arkansas submitted a compliance filing to the APSC verifying the status of the solar production tax credits. The filing also verified that the net proceeds from the sale of the nuclear production tax credits were recorded in FERC accounts that are accruing a return for customers’ benefit at a rate that is above the customer deposit rate. Entergy will continue to monitor further developments and reassess the uncertain tax position as additional guidance or other information emerges.

Tax Accounting Methods

In 2020, Entergy Texas elected mark-to-market income tax treatment for wholesale electric power purchase and sale agreements which resulted in a $2.5 billion deduction upon which a deferred tax liability was recorded.

Arkansas and Louisiana Corporate Income Tax Rate Changes

Since 2019, the State of Arkansas has enacted corporate income tax law changes that have phased in rate reductions from the former rate of 6.5% to the currently enacted rate of 4.3%. As a result of the rate reductions, Entergy Arkansas has recorded regulatory liabilities for income taxes of approximately $29 million, $26 million, and $15 million in 2024, 2023, and 2022, respectively, and a total of $32 million for years prior to 2022. The regulatory liabilities include a tax gross-up related to the treatment of income taxes in the retail and wholesale ratemaking formulas and have been or are scheduled to be included in future rate mechanisms.

In November 2024, during the Louisiana Third Special Legislative Session of 2024, the Louisiana legislature enacted comprehensive tax reform measures that impact corporate income taxes through a reduction in rates to a flat 5.5% (from the then-current highest marginal rate of 7.5%), effective January 1, 2025. Accordingly, deferred tax assets and liabilities were adjusted, with associated regulatory assets and liabilities for income taxes, to reflect the new applicable state rate. As a result of the rate reduction, Entergy Louisiana and Entergy New Orleans recorded regulatory liabilities for income taxes of approximately $179 million and $9 million, respectively. The regulatory liabilities include a tax gross-up related to the treatment of income taxes in the retail and wholesale ratemaking formulas and have been or are scheduled to be included in future rate mechanisms. In fourth quarter 2024, as a result of the net reduction in certain deferred tax assets and liabilities, Entergy Louisiana and Entergy New Orleans recorded an increase of income tax expense of approximately $16.3 million and $0.2 million, respectively, with an additional $12.1 million increase of income tax expense recorded by other Entergy subsidiaries.

Act 293 Securitizations

As described in Note 2 to the financial statements, in March of 2023, Entergy Louisiana implemented a securitization transaction authorized under Act 293 of the Louisiana Legislature’s Regular Session of 2021. Act 293 provides that the LURC contribute the net bond proceeds to a LURC-sponsored trust. Over the 15-year term of the Act 293 bonds, the respective storm trusts will make distributions to Entergy Louisiana, a beneficiary of the storm trusts, that will not be taxable to Entergy Louisiana. Additionally, Entergy Louisiana will not include the receipt of the system restoration charges in taxable income because the right to receive the system restoration charges has been granted directly to the LURC, and Entergy Louisiana only acts as an agent to collect those charges on behalf of the LURC.

138

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Accordingly, the securitizations provided for a tax accounting permanent difference resulting in net reductions of income tax expense for Entergy Louisiana of approximately $133 million after taking into account a provision for uncertain tax positions. Entergy’s recognition of reduced income tax expense was offset by other tax changes resulting in a net reduction of income tax expense for Entergy of approximately $129 million after taking into account a provision for uncertain tax positions.

In recognition of its obligations described in LPSC ancillary orders issued as part of the securitization regulatory proceedings, Entergy Louisiana recorded regulatory liabilities of $103 million ($76 million net-of-tax) in first quarter 2023 to reflect its obligation to provide credits to its customers. See Note 2 to the financial statements for further discussion of the Entergy Louisiana March 2023 storm cost securitizations.

Sale of Natural Gas Distribution Business

See Note 14 to the financial statements for discussion of the sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses on July 1, 2025. Entergy recognized a gain of approximately $328 million for federal tax purposes, with Entergy Louisiana and Entergy New Orleans recognizing $149 million and $179 million, respectively. Both Entergy and Entergy Louisiana have sufficient federal tax net operating loss carryforwards to offset their respective gains. Accordingly, Entergy does not have a resulting federal income tax obligation as a result of the transaction, nor will Entergy Louisiana be required to make a federal tax payment under the terms of the ETAA. Entergy New Orleans fully absorbed its federal tax net operating loss carryforward in 2025, and its resulting federal tax payment under the ETAA will be dependent upon its results of operations reflected on its 2025 income tax returns.

NOTE 4. REVOLVING CREDIT FACILITIES, LINES OF CREDIT, AND SHORT-TERM BORROWINGS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)


Capacity	Borrowings	Letters of Credit	Capacity Available
(In Millions)
$3,000	$—	$3	$2,997

Entergy Corporation’s credit facility includes a covenant requiring Entergy to maintain a consolidated debt ratio, as defined, of 65% or less of its total capitalization. Entergy is in compliance with this covenant. If Entergy fails to meet this ratio, or if Entergy Corporation or one of the Registrant Subsidiaries (except Entergy New Orleans and System Energy) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the Entergy Corporation credit facility’s maturity date may occur.

139

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2025 as follows:


Company	Expiration Date	Amount of Facility	Interest Rate (a)	Amount Drawn as of December 31, 2025	Letters of Credit Outstanding as of December 31, 2025
Entergy Arkansas	April 2026	$25 million (b)	5.67%	—	—
Entergy Arkansas	June 2030	$300 million (c)	4.94%	—	—
Entergy Louisiana	June 2030	$400 million (c)	5.07%	—	—
Entergy Mississippi	June 2030	$300 million (c)	4.94%	—	—
Entergy New Orleans	June 2027	$25 million (c)	5.44%	—	—
Entergy Texas	June 2030	$300 million (c)	5.07%	—	$1.1 million

(a)The interest rate is the estimated interest rate as of December 31, 2025 that would have been applied to outstanding borrowings under the facility.

(b)Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable at Entergy Arkansas’s option.

The commitment fees on the credit facilities range from 0.075% to 0.375% of the undrawn commitment amount for Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas, and of the entire facility amount for Entergy New Orleans. Each of the credit facilities requires the Registrant Subsidiary borrower to maintain a debt ratio, as defined, of 65% or less of its total capitalization. Each Registrant Subsidiary is in compliance with this covenant.

In addition, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each has one or more uncommitted standby letter of credit facilities as a means to post collateral to support its obligations to MISO and for other purposes. The following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2025:

Company

Amount of Uncommitted Facility

Letter of Credit Fee

Letters of Credit Issued as of

December 31, 2025

(a)

Entergy Arkansas

$25 million

0.78%

$18.3 million

Entergy Arkansas

$75 million

0.50%

$75.0 million

Entergy Louisiana

$125 million

0.78%

$119.1 million

Entergy Louisiana

$45 million

0.50%

$45.0 million

Entergy Mississippi

$65 million

0.78%

$44.4 million (b)

Entergy Mississippi

$65 million

0.50%

$43.0 million

Entergy New Orleans

$1 million

1.625%

$0.5 million

Entergy Texas

$150 million

1.250%

$59.6 million

Entergy Texas

$160 million

1.05%

$—

140

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

The short-term borrowings of the Registrant Subsidiaries are limited to amounts authorized by the FERC. Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy have FERC-authorized short-term borrowing limits effective through January 2027. The FERC-authorized short-term borrowing limit for Entergy Arkansas is effective through February 2028. In addition to borrowings from commercial banks, these companies may also borrow from the Entergy system money pool and from other internal short-term borrowing arrangements. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and the other internal borrowing arrangements are designed to reduce the Registrant Subsidiaries’ dependence on external short-term borrowings. Borrowings from internal and external short-term borrowings combined may not exceed the FERC-authorized limits. The following are the FERC-authorized limits for short-term borrowings and the outstanding short-term borrowings as of December 31, 2025 (aggregating both internal and external short-term borrowings) for the Registrant Subsidiaries:


	Authorized	Borrowings
	(In Millions)
Entergy Arkansas	$250	$—
Entergy Louisiana	$450	$—
Entergy Mississippi	$200	$—
Entergy New Orleans	$150	$—
Entergy Texas	$200	$—
System Energy	$200	$16

Vermont Yankee Credit Facility (Entergy Corporation)

In January 2019, Entergy Nuclear Vermont Yankee was transferred to NorthStar and its credit facility was assumed by Entergy Assets Management Operations, LLC (formerly Vermont Yankee Asset Retirement, LLC), Entergy Nuclear Vermont Yankee’s parent company that remains an Entergy subsidiary after the transfer. In December 2024, Entergy repaid the total $139 million of cash borrowings outstanding under the facility, and the facility was subsequently terminated.

Variable Interest Entities (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)

See Note 17 to the financial statements for a discussion of the consolidation of the nuclear fuel company variable interest entities (VIEs). To finance the acquisition and ownership of nuclear fuel, the nuclear fuel company VIEs have credit facilities and three of the four VIEs also issue commercial paper, details of which follow as of December 31, 2025:


Company	Expiration Date	Amount of Facility	Weighted-Average Interest Rate on Borrowings (a)	Amount Outstanding as of December 31, 2025
	(Dollars in Millions)
Entergy Arkansas VIE	June 2027	$80	5.34%	$13.7
Entergy Louisiana River Bend VIE	June 2027	$105	5.36%	$50.3
Entergy Louisiana Waterford VIE	June 2027	$105	5.36%	$43.7
System Energy VIE	June 2027	$120	5.37%	$36.4

(a)Includes letter of credit fees and bank fronting fees on commercial paper issuances by the nuclear fuel company VIEs for Entergy Arkansas, Entergy Louisiana, and System Energy. The nuclear fuel company

141

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

VIE for Entergy Louisiana River Bend does not issue commercial paper, but borrows directly on its bank credit facility.

The commitment fees on the credit facilities are 0.100% of the undrawn commitment amount for the Entergy Arkansas, Entergy Louisiana, and System Energy nuclear fuel company VIEs. Each credit facility requires the respective lessee of nuclear fuel (Entergy Arkansas, Entergy Louisiana, or Entergy Corporation as guarantor for System Energy) to maintain a consolidated debt ratio, as defined, of 70% or less of its total capitalization. Each lessee is in compliance with this covenant.

The nuclear fuel company VIEs had notes payable that were included in debt on the respective balance sheets as of December 31, 2025 as follows:

Company

Description

Amount

Entergy Arkansas VIE

1.84% Series N due July 2026

$90 million

Entergy Arkansas VIE

5.54% Series O due May 2029

$70 million

Entergy Louisiana River Bend VIE

2.51% Series V due June 2027

$70 million

Entergy Louisiana Waterford VIE

5.94% Series J due September 2026

$70 million

System Energy VIE

2.05% Series K due September 2027

$90 million

In accordance with regulatory treatment, interest on the nuclear fuel company VIEs’ credit facilities, commercial paper, and long-term notes payable is reported in fuel expense.

In January 2026, the System Energy nuclear fuel company VIE issued $80 million of 5.28% Series L intermediate term secured notes due January 2029. The System Energy nuclear fuel company VIE expects to use the proceeds to purchase additional nuclear fuel.

As of December 31, 2025, Entergy Louisiana and System Energy each has obtained financing authorization from the FERC that extends through January 2027 for issuances by its nuclear fuel company VIEs. Entergy Arkansas has obtained financing authorization from the FERC that extends through February 2028 for issuances by its nuclear fuel company VIE.

142

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

NOTE 5. LONG - TERM DEBT (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Long-term debt for Entergy as of December 31, 2025 and 2024 consisted of:


Type of Debt and Maturity	Weighted-Average Interest Rate December 31, 2025	Interest Rate Ranges at December 31,		Outstanding at December 31,
		2025	2024	2025	2024
				(In Thousands)
Mortgage Bonds
2025-2029	3.72%	1.50% - 6.25%	1.50% - 6.25%	$4,025,000	$4,603,000
2030-2034	4.40%	1.60% - 6.54%	1.60% - 6.54%	6,405,000	5,865,000
2035-2045	4.57%	3.10% - 5.15%	3.10% - 5.15%	2,707,000	2,207,000
2048-2066	4.64%	2.65% - 5.85%	2.65% - 5.85%	10,335,000	8,985,000
Governmental Bonds (a)
2030-2044	2.43%	2.0% - 2.5%	2.0% - 2.5%	282,375	282,375
Securitization Bonds
2028-2036	3.67%	3.051% - 3.697%	3.051% - 3.697%	223,577	242,424
Variable Interest Entities Notes Payable (Note 4)
2026-2029	3.85%	1.84% - 5.94%	1.84% - 5.94%	390,000	390,000
Entergy Corporation Senior Notes
due September 2025	n/a	—	0.90%	—	800,000
due September 2026	n/a	2.95%	2.95%	750,000	750,000
due June 2028	n/a	1.9%	1.9%	650,000	650,000
due June 2030	n/a	2.80%	2.80%	600,000	600,000
due June 2031	n/a	2.40%	2.40%	650,000	650,000
due June 2050	n/a	3.75%	3.75%	600,000	600,000
Entergy Corporation Junior Subordinated Debentures
due December 2054 (b)	n/a	7.125%	7.125%	1,200,000	1,200,000
due June 2056 (c)	n/a	6.100%	—	700,000	—
due June 2056 (d)	n/a	5.875%	—	600,000	—
Entergy Arkansas VIE Credit Facility (Note 4)	n/a	5.34%	6.28%	13,700	22,500
Entergy Louisiana River Bend VIE Credit Facility (Note 4)	n/a	5.36%	6.33%	50,300	18,700
Entergy Louisiana Waterford VIE Credit Facility (Note 4)	n/a	5.36%	6.32%	43,700	18,900
System Energy VIE Credit Facility (Note 4)	n/a	5.37%	6.27%	36,400	72,700
Long-term DOE Obligation (e)	—	—	—	225,309	216,016
Grand Gulf Sale-Leaseback Obligation	n/a	—	—	34,113	34,203
Unamortized Premium and Discount - Net				(23,442)	(17,575)
Unamortized Debt Issuance Costs				(226,174)	(204,010)
Other				5,303	5,362
Total Long-Term Debt				30,277,161	27,991,595
Less Amount Due Within One Year				2,375,140	1,378,090
Long-Term Debt Excluding Amount Due Within One Year				$27,902,021	$26,613,505
Fair Value of Long-Term Debt				$28,208,822	$25,181,802

(a)Consists of pollution control revenue bonds and environmental revenue bonds, all of which are secured by mortgage bonds.

(b)Entergy Corporation will pay interest at an annual rate of 7.125% through November 2029. Commencing on December 1, 2029, the annual rate will equal the five-year treasury rate as of the most recent reset

143

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

interest determination date plus 2.67%, which interest resets will occur on each five-year anniversary of December 1 after December 1, 2029.

(c)Entergy Corporation will pay interest at an annual rate of 6.100% through June 14, 2036. Commencing on June 15, 2036, the annual rate will equal the five-year treasury rate as of the most recent reset interest determination date plus 2.013%, provided that the interest rate during an interest reset period will not reset below 6.100%. Interest resets will occur on each five-year anniversary of June 15 after June 15, 2036.

(d)Entergy Corporation will pay interest at an annual rate of 5.875% through June 14, 2031. Commencing on June 15, 2031, the annual rate will equal the five-year treasury rate as of the most recent reset interest determination date plus 2.179%, provided that the interest rate during an interest reset period will not reset below 5.875%. Interest resets will occur on each five-year anniversary of June 15 after June 15, 2031.

(e)Pursuant to the Nuclear Waste Policy Act of 1982, Entergy’s nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service. The contracts include a one-time fee for generation prior to April 7, 1983. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt.

The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2025, for the next five years are as follows:


			Amount
			(In Thousands)
2026			$2,375,720
2027			$1,054,820
2028			$2,158,446
2029			$405,720
2030			$916,822

Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through January 2027. Entergy Arkansas has obtained long-term financing authorization from the FERC that extends through February 2028. Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through December 2027. Entergy Arkansas has also obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2027.

144

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Long-term debt for the Registrant Subsidiaries as of December 31, 2025 and 2024 consisted of:


	2025	2024
	(In Thousands)
Entergy Arkansas
Mortgage Bonds:
3.5% Series due April 2026	$600,000	$600,000
4.00% Series due June 2028	350,000	350,000
5.15% Series due January 2033	425,000	425,000
5.30% Series due September 2033	300,000	300,000
5.45% Series due June 2034	700,000	400,000
4.95% Series due December 2044	250,000	250,000
4.20% Series due April 2049	550,000	550,000
2.65% Series due June 2051	675,000	675,000
3.35% Series due June 2052	400,000	400,000
5.75% Series due June 2054	400,000	400,000
4.875% Series due September 2066	410,000	410,000
Total mortgage bonds	5,060,000	4,760,000
Variable Interest Entity Notes Payable and Credit Facility (Note 4):
1.84% Series N due July 2026	90,000	90,000
5.54% Series O due May 2029