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, 2023
 OR

 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

 (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

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

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

 Common Stock, $0.01 Par Value

 ETR

 Common Stock, $0.01 Par Value

 ETR

 NYSE Chicago, Inc.

 Mortgage Bonds, 4.875% Series due September 2066

 EAI

 Mortgage Bonds, 4.875% Series due September 2066

 ELC

 Mortgage Bonds, 4.90% Series due October 2066

 EMP

 Mortgage Bonds, 5.0% Series due December 2052

 ENJ

 Mortgage Bonds, 5.50% Series due April 2066

 ENO

 5.375% Series A Preferred Stock, Cumulative, No Par Value (Liquidation Value $25 Per Share)
 ETI/PR

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

 Title of Class

 Common Stock, no par value

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

 Yes
 No

 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

 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 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 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

 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.

 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

 Common Stock Outstanding
 Outstanding at January 31, 2024

 ($0.01 par value)
 213,237,552

 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.

 The aggregate market value of Entergy Corporation Common Stock, $0.01 Par Value, held by non-affiliates as of the end of the second quarter of 2023 was $ 20.6 billion based on the reported last sale price of $97.37 per share for such stock on the New York Stock Exchange on June 30, 2023. 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.

 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 3, 2024, are incorporated by reference into Part III hereof.

 SEC Form 10-K Reference Number
 Page Number

 Forward-looking information

 iv

 Definitions

 viii

 Report of Management

 Consolidated Income Statements For the Years Ended December 31, 2023, 2022, and 20 21

 Consolidated Statements of Comprehensive Income For the Years Ended December 31, 2023, 2022, and 20 21

 Consolidated Statements of Cash Flows For the Years Ended December 31, 2023, 2022, and 20 21

 Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022, and 20 21

 Note 1. Summary of Significant Accounting Policies

 Note 2. Rate and Regulatory Matters

 Note 3. Income Taxes

 Note 4. Revolving Credit Facilities, Lines of Credit, and Short-term Borrowings

 Note 5. Long-term Debt

 Note 6. Preferred Equity and Noncontrolling Interests

 Note 7. Common Equity

 Note 8. Commitments and Contingencies

 Note 9. Asset Retirement Obligations

 Note 10. Leases

 Note 11. Retirement, Other Postretirement Benefits, and Defined Contribution Plans

 Note 12. Stock-based Compensation

 Note 13. Business Segment Information

 Note 14. Acquisitions and Dispositions

 Note 15. Risk Management and Fair Values

 Note 16. Decommissioning Trust Funds

 Note 17. Variable Interest Entities

 Note 18. Transactions with Affiliates

 Note 19. Revenue

 Entergy's Business
 Part I. Item 1.

 Risk Factors Summary

 Other Business Activities

 Regulation of Entergy's Business

 Litigation

 Human Capital

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

 Risk Factors

 Part I. Item 1A.

 Unresolved Staff Comments

 Part I. Item 1B.

 i

 Cybersecurity

 Part I. Item 1C.

 Consolidated Income Statements For the Years Ended December 31, 2023, 2022, and 20 21

 Consolidated Statements of Cash Flows For the Years Ended December 31, 2023, 2022, and 20 21

 Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022, and 20 21

 Consolidated Income Statements For the Years Ended December 31, 2023, 2022, and 20 21

 Consolidated Statements of Comprehensive Income For the Years Ended December 31, 2023, 2022, and 20 21

 Consolidated Statements of Cash Flows For the Years Ended December 31, 2023, 2022, and 20 21

 Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022, and 20 21

 Consolidated Income Statements For the Years Ended December 31, 2023, 2022, and 2 021

 Consolidated Statements of Cash Flows For the Years Ended December 31, 2023, 2022, and 20 21

 Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022, and 20 21

 Consolidated Income Statements For the Years Ended December 31, 2023, 2022, and 202 1

 Consolidated Statements of Cash Flows For the Years Ended December 31, 2023, 2022, and 202 1

 Consolidated Statements of Changes in Member's Equity for the Years Ended December 31, 2023, 2022, and 20 21

 Consolidated Income Statements For the Years Ended December 31, 2023, 2022, and 20 21

 Consolidated Statements of Cash Flows For the Years Ended December 31, 2023, 2022, and 2021

 Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022, and 20 21

 ii

 Statements of Operations For the Years Ended December 31, 2023, 2022, and 20 21

 Statements of Cash Flows For the Years Ended December 31, 2023, 2022, and 20 21

 Balance Sheets, December 31, 2023 and 202 2

 Statements of Changes in Common Equity for the Years Ended December 31, 2023, 2022, and 2021

 Properties

 Part I. Item 2.

 Legal Proceedings

 Part I. Item 3.

 Mine Safety Disclosures

 Part I. Item 4.

 Information about Executive Officers of Entergy Corporation

 Part I. and Part III. Item 10.

 Market for Registrants' Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

 Part II. Item 5.

 Reserved

 Part II. Item 6.

 Management's Discussion and Analysis of Financial Condition and Results of Operations

 Quantitative and Qualitative Disclosures About Market Risk

 Part II. Item 7A.

 Financial Statements and Supplementary Data

 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 Part II. Item 9.

 Controls and Procedures

 Part II. Item 9A.

 Attestation Report of Registered Public Accounting Firm

 Part II. Item 9A.

 Other Information

 Part II. Item 9B.

 Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

 Part II. Item 9C.

 Directors, Executive Officers, and Corporate Governance of the Registrants

 Part III. Item 10.

 Executive Compensation

 Part III. Item 11.

 Security Ownership of Certain Beneficial Owners and Management

 Part III. Item 12.

 Certain Relationships and Related Party Transactions and Director Independence

 Part III. Item 13.

 Principal Accountant Fees and Services

 Part III. Item 14.

 Exhibits and Financial Statement Schedules

 Part IV. Item 15.

 Form 10-K Summary

 Part IV. Item 16.

 Exhibit Index

 Signatures

 Consents of Independent Registered Public Accounting Firm

 Index to Financial Statement Schedules

 S-1

 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

 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, (b) those factors discussed or incorporated by reference in Management's Financial Discussion and Analysis, and (c) the following factors (in addition to others described elsewhere in this combined report and in subsequent securities filings):

 • 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 absence of a minimum capacity obligation for load serving entities in MISO and the consequent ability of some load serving entities to "free ride" on the energy market without paying appropriate compensation for the capacity needed to produce that energy, 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, 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;
 • changes in utility regulation, including, with respect to retail and wholesale competition, the ability to recover net utility assets and other potential stranded costs, 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 owned or operated 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, and related regulatory proceedings and litigation, for license modifications or other authorizations required of nuclear generating facilities and the effect of public and political opposition on these applications, regulatory proceedings, and litigation;
 • 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 economic conditions, and emerging operating and industry issues, 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;
 iv

 FORWARD-LOOKING INFORMATION (Continued)

 • 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 increase in natural gas prices, 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, and the effect of those changes on Entergy and its customers;
 • changes in law resulting from federal or state energy legislation or legislation subjecting energy derivatives used in hedging and risk management transactions to governmental regulation;
 • 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;
 • 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, and other governmental actions or policies, including changes in monetary, fiscal, tax, environmental, trade/tariff, domestic purchase requirements, or energy 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, 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 extreme weather events, such as hurricanes, drought or wildfires, and sea levels or coastal land and wetland loss;
 • the risk that an incident at any nuclear generation facility in the U.S. could lead to the assessment of significant retrospective assessments and/or retrospective insurance premiums as a result of Entergy's participation in a secondary financial protection system and a utility industry mutual insurance company;
 • changes in the quality and availability of water supplies and the related regulation of water use and diversion;
 • Entergy's ability to manage its capital projects, including by completing 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, 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 Entergy's 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 federal income tax laws, regulations, and interpretive guidance, including the Inflation Reduction Act of 2022 and the continued impact of 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;
 v

 FORWARD-LOOKING INFORMATION (Continued)

 • the effect of increased interest rates and other changes in the financial markets 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 our customers;
 • the effects of litigation, including the outcome and resolution of the proceedings involving System Energy currently before the FERC and any appeals of FERC decisions in those proceedings;
 • the effects of government investigations, proceedings, or audits;
 • changes in technology, including (i) Entergy's ability to effectively assess, 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 ethical, security, legal, operational, or regulatory challenges, (iii) 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 incentivizing development or utilization of the foregoing, and (iv) 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 increase its carbon-free energy capacity and to reduce its carbon emission rate and aggregate carbon emissions, including its commitment to achieve net-zero carbon emissions by 2050 and the related increasing investment in renewable power generation sources, and the potential impact on its business and financial condition of attempting to achieve such objectives;
 • 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;
 • 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 the military activities between Russia and Ukraine, or Israel and Hamas, 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; 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;
 • Entergy's ability to attract, retain, and manage an appropriately qualified workforce;
 • changes in accounting standards and corporate governance best practices;
 • declines in the market prices of marketable securities and resulting funding requirements and the effects on benefits costs for Entergy's defined benefit pension and other postretirement benefits plans;

 vi

 FORWARD-LOOKING INFORMATION (Concluded)

 • future wage and employee benefits costs, including changes in discount rates and returns on benefit plan assets;
 • 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 to satisfy their financial and performance commitments; and
 • Entergy and its subsidiaries' ability to successfully execute on their business strategies, including their ability to complete strategic transactions that they may undertake.
 vii

 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 Corporation and its direct and indirect subsidiaries

 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, 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, 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

 FitzPatrick
 James A. FitzPatrick Nuclear Power Plant (nuclear), previously owned as part of Entergy's non-utility business, which was sold in March 2017

 GAAP
 Generally Accepted Accounting Principles

 Grand Gulf

 Unit No. 1 of Grand Gulf Nuclear Station (nuclear), 90% owned or leased by System Energy

 viii

 DEFINITIONS (Continued)
 Abbreviation or Acronym
 Term

 GWh

 Gigawatt-hour(s), which equals one million kilowatt-hours

 HLBV
 Hypothetical liquidation at book value

 Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi, and 7% by Entergy Power, LLC

 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

 Mcf

 1,000 cubic feet of gas

 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

 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

 Pilgrim

 Pilgrim Nuclear Power Station (nuclear), previously owned as part of Entergy's non-utility business, which ceased power production in May 2019 and was sold in August 2019

 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

 ix

 DEFINITIONS (Concluded)

 Abbreviation or Acronym
 Term

 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.

 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

 Entergy's reportable segment that generates, transmits, distributes, and sells electric power, with a small amount of natural gas distribution in portions of Louisiana

 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

 x

 Entergy operates primarily through a single reportable segment, Utility. The Utility segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operation of a small natural gas distribution business in portions of Louisiana. See "Planned Sale of Gas Distribution Businesses" below for discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana gas distribution businesses.

 Entergy completed its multi-year strategy to exit the merchant nuclear power business in 2022 and upon completion of all transition activities, effective January 1, 2023, Entergy Wholesale Commodities is no longer a reportable segment. Remaining business activity previously reported under Entergy Wholesale Commodities is now included under Parent & Other. Historical segment financial information presented herein has been restated for 2022 and 2021 to reflect the change in reportable segments. The change in reportable segments had no effect on Entergy's consolidated financial statements or historical segment financial information for the Utility reportable segment. See Note 13 to the financial statements for discussion of and financial information regarding Entergy's business segment.

 Following are income statement variances for Utility, Parent & Other, and Entergy comparing 2023 to 2022 showing how much the line item increased or (decreased) in comparison to the prior period.

 Parent & Other (a)

 2022 Net Income (Loss) Attributable to Entergy Corporation
 $1,406,605
 ($303,439)
 $1,103,166

 Operating revenues
 (1,397,860)
 (218,965)
 (1,616,825)

 (878,601)
 (52,670)
 (931,271)

 (573,937)
 (19,571)
 (593,508)

 (807,872)
 —
 (807,872)

 (61,702)
 (78,544)
 (140,246)

 79,962
 126,181
 206,143

 35,951
 (13,915)
 22,036

 92,806
 (8,826)
 83,980

 Other income (deductions)
 145,999
 (5,415)
 140,584

 66,468
 27,701
 94,169

 Other expenses
 23,324
 (46,611)
 (23,287)

 (340,584)
 (310,973)
 (651,557)

 Preferred dividend requirements of subsidiaries and noncontrolling interests
 11,802
 —
 11,802

 2023 Net Income (Loss) Attributable to Entergy Corporation
 $2,507,127
 ($150,591)
 $2,356,536

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

 Results of operations for 2023 include: (1) a $568 million reduction, recorded at Utility, and a $275 million reduction, recorded at Parent & Other, in income tax expense as a result of the resolution of the 2016-2018 IRS audit, partially offset by $98 million ($72 million net-of-tax) of regulatory charges, recorded at Utility, to reflect credits expected to be provided to customers by Entergy Louisiana and Entergy New Orleans as a result of the resolution of the 2016-2018 IRS audit; (2) the reversal of a $106 million regulatory liability, associated with the Hurricane Isaac securitization, recognized in 2017 as a result of the Tax Cuts and Jobs Act, recorded at Utility, as part of the settlement of Entergy Louisiana's test year 2017 formula rate plan filing; (3) a $129 million reduction in income tax expense as a result of the Hurricane Ida securitization in March 2023, which also resulted in a $103 million ($76 million net-of-tax) regulatory charge, recorded at Utility, to reflect Entergy Louisiana's obligation to provide credits to its customers as described in an LPSC ancillary order issued as part of the securitization regulatory proceeding; and (4) write-offs of $78 million ($59 million net-of-tax), recorded at Utility, as a result of Entergy Arkansas's approved motion to forgo recovery of identified costs resulting from the 2013 ANO stator incident. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit. See Note 2 to the financial statements for further discussion of the Entergy Louisiana formula rate plan global settlement. See Notes 2 and 3 to the financial statements for further discussion of the Entergy Louisiana March 2023 storm cost securitization. See Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.

 Results of operations for 2022 include: (1) a regulatory charge of $551 million ($413 million net-of-tax), recorded at Utility, as a result of System Energy's partial settlement agreement and offer of settlement related to pending proceedings before the FERC; (2) a $283 million reduction in income tax expense as a result of the Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida May 2022 securitization financing, which also resulted in a $224 million ($165 million net-of-tax) regulatory charge, recorded at Utility, to reflect Entergy Louisiana's obligation to provide credits to its customers as described in an LPSC ancillary order issued as part of the securitization regulatory proceeding; and (3) a gain of $166 million ($130 million net-of-tax), reflected in "Asset write-offs, impairments, and related charges (credits)," as a result of the sale of the Palisades plant in June 2022. See Note 2 to the financial statements for further discussion of the System Energy settlement agreement with the MPSC. See Notes 2 and 3 to the financial statements for further discussion of the Entergy Louisiana May 2022 storm cost securitization. See Note 14 to the financial statements for discussion of the sale of the Palisades plant.

 Following is an analysis of the change in operating revenues comparing 2023 to 2022:

 $13,421

 (1,801)

 Storm restoration carrying costs
 (23)

 Retail one-time bill credit

 Return of unprotected excess accumulated deferred income taxes to customers

 $12,023

 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.

 Storm restoration carrying costs, representing the equity component of storm restoration carrying costs, includes $22 million recognized by Entergy Texas as part of its April 2022 storm cost securitization, $37 million recognized by Entergy Louisiana as part of its May 2022 storm cost securitization, $31 million recognized by Entergy Louisiana as part of its March 2023 storm cost securitization, and $5 million recognized by Entergy New Orleans as part of the City Council's approval of the Entergy New Orleans storm cost certification report in December 2023. See Note 2 to the financial statements for discussion of storm cost securitizations.

 The volume/weather variance is primarily due to the effect of more favorable weather on commercial sales and an increase in industrial usage, substantially offset by the effect of less favorable weather on residential sales. The increase in industrial usage is primarily due to an increase in demand from new customers and expansion projects, primarily in the primary metals, industrial gases, and chemicals industries, and an increase in demand from small industrial customers, substantially offset by a decrease in demand from cogeneration customers.

 The retail one-time bill credit represents the disbursement of settlement proceeds in the form of a one-time bill credit provided to Entergy Mississippi's retail customers during the September 2022 billing cycle as a result of the System Energy settlement agreement with the MPSC. See Note 2 to the financial statements for discussion of the settlement agreement and the MPSC directive related to the disbursement of settlement proceeds.

 The return of unprotected excess accumulated deferred income taxes to customers resulted from activity at the Utility operating companies in response to the enactment of the Tax Cuts and Jobs Act. The return of unprotected excess accumulated deferred income taxes began in second quarter 2018. In 2022, $53 million was returned to customers through reductions in operating revenues. There was no return of unprotected excess accumulated deferred income taxes for Entergy or the Utility operating companies for 2023. There was no effect on net income as the reductions in operating revenues were offset by reductions in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.

 The retail electric price variance is primarily due to:

 • an increase in Entergy Arkansas's formula rate plan rates effective January 2023;
 • increases in Entergy Louisiana's formula rate plan revenues, including increases in the distribution and transmission recovery mechanisms, effective September 2022 and September 2023;
 • increases in Entergy Mississippi's formula rate plan rates effective August 2022, April 2023, and July 2023;
 • an increase in Entergy New Orleans's formula rate plan rates effective September 2022; and
 • an increase in base rates, including the realignment of the costs previously being collected through the distribution and transmission cost recovery factor riders and the generation cost recovery rider to base rates, effective June 2023, at Entergy Texas.

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

 Total electric energy sales for Utility for the years ended December 31, 2023 and 2022 are as follows:

 2023
 2022

 (GWh)

 36,372
 37,134
 (2)

 28,221
 27,982

 52,807
 52,501

 2,458
 2,512
 (2)

 119,858
 120,129
 —

 Sales for resale
 15,189
 15,968
 (5)

 Total
 135,047
 136,097
 (1)

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

 Other Income Statement Items

 Other operation and maintenance expenses decreased from $2,900 million for 2022 to $2,838 million for 2023 primarily due to:

 • a decrease of $59 million in compensation and benefits costs primarily due to lower health and welfare costs, including higher prescription drug rebates in second quarter 2023, a decrease in net periodic pension and other postretirement benefits service costs as a result of an increase in the discount rates used to value the benefits liabilities, and a revision to estimated incentive compensation expense in first quarter 2023. See "Critical Accounting Estimates" below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;
 • a decrease of $51 million in transmission costs allocated by MISO. See Note 2 to the financial statements for further information on the recovery of these costs;
 • a decrease of $21 million in non-nuclear generation expenses primarily due to a lower scope of work, including during plant outages, performed in 2023 as compared to 2022;
 • a decrease of $17 million in nuclear generation expenses primarily due to a lower scope of work performed in 2023 as compared to 2022 and lower nuclear labor costs;
 • a decrease of $11 million in customer service center support costs primarily due to lower contract costs; and
 • the effects of recording a final judgment in first quarter 2023 to resolve claims in the ANO damages case against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $10 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expenses. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

 • an increase of $43 million in contract costs related to operational performance, customer service, and organizational health initiatives;
 • an increase of $15 million in power delivery expenses primarily due to higher vegetation maintenance costs;
 • an increase of $11 million in insurance expenses primarily due to lower nuclear insurance refunds received in 2023; and

 Asset write-offs, impairments, and related charges (credits) includes the effects of Entergy Arkansas forgoing recovery of identified costs resulting from the 2013 ANO stator incident. In third quarter 2023, Entergy Arkansas recorded write-offs of its regulatory asset for deferred fuel of $68.9 million and the undepreciated balance of $9.5 million in capital costs related to the ANO stator incident. See Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.

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

 Depreciation and amortization expenses increased primarily due to:

 • additions to plant in service;
 • an increase in depreciation rates at Entergy Texas, effective in June 2023. See Note 2 to the financial statements for discussion of the 2022 base rate case at Entergy Texas; and
 • a reduction in depreciation expense at System Energy in 2022 related to the Grand Gulf sale-leaseback property, which resulted from the FERC order on the Grand Gulf sale-leaseback renewal complaint in December 2022. See Note 2 to the financial statements for further discussion of the Grand Gulf sale-leaseback renewal complaint.

 The increase was partially offset by a reduction in depreciation expense of $41 million in 2023 at System Energy as a result of the approval by the FERC in August 2023 of the settlement establishing updated depreciation rates used in calculating Grand Gulf plant depreciation and amortization expenses under the Unit Power Sales Agreement. See Note 2 to the financial statements for discussion of the Unit Power Sales Agreement depreciation amendment proceeding.

 Other regulatory charges (credits) - net includes:

 • a regulatory charge of $103 million, recorded by Entergy Louisiana in first quarter 2023, to reflect its obligation to provide credits to its customers as described in an LPSC ancillary order issued in the Hurricane Ida securitization regulatory proceeding. See Note 2 to the financial statements for discussion of the Entergy Louisiana March 2023 storm cost securitization;
 • a regulatory charge of $224 million, recorded by Entergy Louisiana in second quarter 2022, to reflect its obligation to provide credits to its customers as described in an LPSC ancillary order issued in the Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida securitization regulatory proceeding. See Note 2 to the financial statements for discussion of the Entergy Louisiana May 2022 storm cost securitization;
 • a regulatory charge of $38 million, recorded by Entergy Louisiana in fourth quarter 2023, to reflect credits expected to be provided to customers as a result of the resolution of the 2016-2018 IRS audit. See Note 3 to the financial statements for discussion of the resolution of the 2016-2018 IRS audit;
 • regulatory credits of $23 million, recorded by Entergy Mississippi in third quarter 2022, to reflect the effects of the joint stipulation reached in the 2022 formula rate plan filing proceeding. See Note 2 to the financial statements for discussion of the Entergy Mississippi 2022 formula rate plan filing;
 • regulatory credits of $18 million, recorded by Entergy Mississippi in fourth quarter 2022, to reflect that the 2022 estimated earned return was below the formula bandwidth. See Note 2 to the financial statements for discussion of Entergy Mississippi's formula rate plan filings;
 • a regulatory charge of $60 million, recorded by Entergy New Orleans in fourth quarter 2023, to reflect credits expected to be provided to customers as a result of the resolution of the 2016-2018 IRS audit. See Note 3 to the financial statements for discussion of the resolution of the 2016-2018 IRS audit;
 • the reversal in third quarter 2023 of $22 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved. See Note 2 to the financial statements for discussion of Entergy Texas's 2022 base rate case; and

 • a regulatory charge of $551 million, recorded by System Energy in second quarter 2022, to reflect the effects of the partial settlement agreement and offer of settlement related to pending proceedings before the FERC. See Note 2 to the financial statements for discussion of the partial settlement agreement with the MPSC.

 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 increased primarily due to:

 • an increase of $113 million in intercompany dividend income from affiliated preferred membership interests related to storm cost securitizations. The intercompany dividend income on the affiliate preferred membership interests is eliminated for consolidation purposes and has no effect on net income since the investment is in another Entergy subsidiary;
 • an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2023, including the Orange County Advanced Power Station project at Entergy Texas;
 • a $32 million charge, recorded by Entergy Louisiana in second quarter 2022, for the LURC's 1% beneficial interest in the storm trust I established as part of the May 2022 storm cost securitization as compared to a $15 million charge, recorded by Entergy Louisiana in first quarter 2023, for the LURC's 1% beneficial interest in the storm trust II established as part of the March 2023 storm cost securitization; and
 • changes in decommissioning trust fund activity, including portfolio rebalancing of decommissioning trust funds in 2022.

 This increase was partially offset by:

 • a decrease of $21 million in the amount of storm restoration carrying costs recognized in 2023 as compared to 2022, primarily related to Hurricane Ida; and
 • lower interest income from carrying costs related to deferred fuel balances.

 See Note 2 to the financial statements for discussion of the Entergy Louisiana storm cost securitizations.

 Interest expense increased primarily due to:

 • the issuance by Entergy Arkansas of $425 million of 5.15% Series mortgage bonds in January 2023;
 • the issuance by Entergy Louisiana of $500 million of 4.75% Series mortgage bonds in August 2022;
 • the issuance by Entergy Texas of $325 million of 5.00% Series mortgage bonds in August 2022;
 • the issuance by Entergy Texas of $350 million of 5.80% Series mortgage bonds in August 2023; and
 • the issuance by System Energy of $325 million of 6.00% Series mortgage bonds in March 2023.

 The increase was partially offset by the repayment by Entergy Louisiana of $200 million of 3.30% Series mortgage bonds in December 2022 and the repayment by System Energy of $250 million of 4.10% Series mortgage bonds in April 2023.

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

 Noncontrolling interests reflects the earnings or losses attributable to the noncontrolling partner of Entergy Arkansas's tax equity partnership for the Searcy Solar facility and Entergy Mississippi's tax equity partnership for the Sunflower Solar facility, both under HLBV accounting, and to the LURC's beneficial interest in the Entergy Louisiana storm trusts. Entergy Mississippi recorded regulatory charges of $9 million in 2023 compared to $21 million in 2022 to defer the difference between the losses allocated to the tax equity partner under the HLBV method of accounting and the earnings/loss that would have been allocated to the tax equity partner under its

 respective ownership percentage in the partnership. See Note 1 to the financial statements for discussion of the HLBV method of accounting.

 Parent and Other

 Operating revenues decreased primarily due to the absence of revenues from Palisades, after it was shut down in May 2022.

 Other operation and maintenance expenses decreased primarily due to the absence of expenses from Palisades, after it was shut down in May 2022.

 Asset write-offs, impairments, and related charges (credits) includes a gain of $166 million as a result of the sale of the Palisades plant in June 2022 and the effects of recording a final judgment of $40 million in third quarter 2023 to resolve claims in the Indian Point 2 fourth round and Indian Point 3 third round combined damages case against the DOE. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

 Taxes other than income taxes decreased primarily due to decreases in employment taxes due to the absence of expenses from Palisades, after its sale in June 2022.

 Depreciation and amortization expenses decreased primarily due to the absence of depreciation expense from Palisades, after it was shut down in May 2022.

 Other income decreased primarily due to the elimination for consolidation purposes of intercompany dividend income of $113 million from affiliated preferred membership interests, as discussed above, substantially offset by losses on Palisades decommissioning trust fund investments in 2022, the timing of charitable donations, and higher non-service pension income. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below and Note 11 to the financial statements for discussion of pension and other postretirement benefits costs.

 Interest expense increased primarily due to higher variable interest rates on commercial paper and credit facilities in 2023 and higher commercial paper balances, partially offset by the redemption by Entergy of $650 million of 4.00% Series senior notes in June 2022. See Note 4 to the financial statements for discussion of Entergy's commercial paper program and credit facilities. See Note 5 to the financial statements for a discussion of long-term debt.

 Other expenses decreased primarily due to the absence of decommissioning expense and nuclear refueling outage expense as a result of the shutdown and sale of Palisades in second quarter 2022.

 See Note 14 to the financial statements for a discussion of the shutdown and sale of the Palisades plant.

 Income Taxes

 The effective income tax rates were (41.3%) for 2023 and (3.7%) for 2022. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.

 See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations" in Item 7 of Entergy's Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.

 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 plants. 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 December 2022 the IRS issued a notice which provided guidance 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 initial guidance and current internal forecasts, Entergy and the Registrant Subsidiaries may be subject to the CAMT beginning in the next two to four years. The United States Treasury Department 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. There are no effects on the financial statements of Entergy or the Registrant Subsidiaries as of and for the years ended December 31, 2023 and 2022.

 In June 2023 the IRS issued temporary and proposed regulations related to applicable tax credit transferability and direct pay provisions of the IRA. In August 2023 the IRS issued proposed regulations related to the prevailing wage and apprenticeship requirements under the IRA. Entergy and the Registrant Subsidiaries are closely monitoring any potential effects associated with such federal tax incentives to assess the expected future effects on their results of operations, cash flows, and financial condition. There are no effects on the financial statements of Entergy or the Registrant Subsidiaries as of and for the year ended December 31, 2023.

 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 intends to adopt this new method of income tax accounting under the safe harbor in accordance with Revenue Procedure 2023-15, which is not expected to have a significant effect on the results of operations, cash flows, or financial condition of Entergy or the Registrant Subsidiaries.

 Entergy Wholesale Commodities Exit from the Merchant Power Business

 Entergy completed its multi-year strategy to exit the merchant nuclear power business in 2022. See Note 13 to the financial statements for discussion of the exit from the merchant nuclear power business.

 Shutdown and Sale of Palisades

 In July 2018, Entergy entered into a purchase and sale agreement with Holtec International to sell to a Holtec subsidiary 100% of the equity interests in the subsidiary that owns Palisades and the Big Rock Point Site, with a subsequent amendment to the purchase and sale agreement in February 2020. In December 2020, Entergy and Holtec submitted a license transfer application to the NRC requesting approval to transfer the Palisades and Big Rock Point licenses from Entergy to Holtec. In February 2021 several parties filed with the NRC petitions to intervene and requests for hearing challenging the license transfer application. In March 2021, Entergy and Holtec filed answers opposing the petitions to intervene and hearing requests, and the petitioners filed replies. In March 2021 an additional party also filed a petition to intervene and request for hearing. Entergy and Holtec filed an answer to the March 2021 petition in April 2021. The NRC issued an order approving the application in December 2021, subject to the NRC's authority to condition, revise, or rescind the approval order based on the resolution of

 four pending requests for hearing. These petitions and requests for hearing remained pending with the NRC at the time of the closing of the Palisades transaction in June 2022. In July 2022 the NRC issued an order granting the Michigan Attorney General's petition hearing request. The hearing was held in February 2023. A decision from the NRC is pending. See Note 14 to the financial statements for discussion of the sale of the Palisades plant.

 Planned Sale of Gas Distribution Businesses

 On October 28, 2023, Entergy New Orleans and Entergy Louisiana each entered into separate purchase and sale agreements with respect to the sale of their respective regulated natural gas local distribution company businesses to two separate affiliates of Bernhard Capital Partners Management LP. Under the purchase and sale agreements, Entergy New Orleans has agreed to sell its regulated natural gas local distribution company business serving customers in the Parish of Orleans, Louisiana, and Entergy Louisiana has agreed to sell its regulated natural gas local distribution company business serving customers in the Parish of East Baton Rouge, Louisiana.

 The base purchase price to be paid by the buyer of the Entergy New Orleans gas business is $285.5 million, and the base purchase price to be paid by the buyer of the Entergy Louisiana gas business is $198 million, in each case subject to certain adjustments at the closing of the transactions. Each purchase and sale agreement contains customary representations, warranties, and covenants related to the applicable business and the respective transactions. Between the date of the purchase and sale agreements and the completion of the transactions, Entergy New Orleans and Entergy Louisiana have each agreed to operate the respective gas businesses in the ordinary course of business and subject to certain operating covenants.

 The transactions will proceed in two phases: (1) an "Initial Phase" prior to regulatory approvals in connection with both transactions; and (2) a "Second Phase" following regulatory approvals in connection with both transactions to the extent that certain conditions are satisfied or, where permissible, waived for both transactions. Required regulatory approvals include the approval of the City Council for the sale of the Entergy New Orleans gas business and the approval of the LPSC and the Metropolitan Council for the City of Baton Rouge and Parish of East Baton Rouge for the sale of the Entergy Louisiana gas business. Additionally, while approval of the transactions is generally not required from the FERC, the parties will seek a waiver of the FERC's capacity release rules, as applicable. In December 2023, Entergy New Orleans and Entergy Louisiana and the respective buyers filed their joint applications with the City Council and the LPSC, respectively, seeking approval for the proposed transactions. The applications request a decision by June 2024. In February 2024 the City Council adopted a procedural schedule in which the hearing officer shall certify the record of the proceeding for City Council consideration no later than September 2024.

 The purchase and sale agreements may be terminated by any party if the Second Phase does not start within 15 months of October 28, 2023, or within 18 months if the only remaining conditions to starting the Second Phase are obtaining the regulatory approvals. The consummation of each of the transactions is subject to satisfaction of certain customary closing conditions, including the receipt of the regulatory approvals, clearance under the Hart-Scott Rodino Act, and the concurrent closing of the other transaction. Under the purchase and sale agreements, the closing of the transactions is not required to occur earlier than the later of six months following the initiation of the Second Phase and July 28, 2025, and the purchase and sale agreements may be terminated by either party in the event the closing has not occurred prior to October 28, 2025. Neither transaction is subject to a financing condition for the applicable buyer.

 The purchase and sale agreements are subject to customary termination provisions. If the purchase and sale agreements are terminated in certain circumstances, each seller may be liable to the applicable buyer for a portion of the buyer's transition costs incurred in connection with transitioning the applicable business. Entergy New Orleans's and Entergy Louisiana's aggregate liability for such transaction costs shall not exceed $7.5 million if termination occurs during the Initial Phase or $12.5 million if termination occurs during the Second Phase, with responsibility allocated between the sellers pro rata based on the relative purchase price. If the purchase and sale agreements are terminated in certain circumstances, each buyer may be liable to the corresponding seller for a

 reverse termination fee, equal to 7% of the applicable base purchase price if termination occurs during the Initial Phase, or 10% of the applicable base purchase price if the termination occurs in the Second Phase.

 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.

 Entergy's debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio is primarily due to net income in 2023.

2023
2022

 63.8%
 66.9%

 Effect of excluding securitization bonds
 (0.3%)
 (0.3%)

 Debt to capital, excluding securitization bonds (non-GAAP) (a)
 63.5%
 66.6%

 (0.1%)
 (0.1%)

 Net debt to net capital, excluding securitization bonds (non-GAAP) (a)
 63.4%
 66.5%

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

 As of December 31, 2023, 19.6% of the debt outstanding is at the parent company, Entergy Corporation, and 79.9% is at the Utility. The remaining 0.5% of the debt outstanding relates to the Vermont Yankee credit facility, as discussed in Note 4 to the financial statements herein. 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, 2023. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2023. 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
 2024
 2025
 2026
 after 2028

 $2,753
 $1,481
 $2,315
 $3,653
 $23,540

 2,393

 Total
 $2,997
 $2,375
 $3,148
 $4,430
 $25,933

 Note 5 to the financial statements provides more detail concerning long-term debt outstanding.

 Entergy Corporation has in place a credit facility that has a borrowing capacity of $3.5 billion and expires in June 2028. 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. The weighted-average interest rate for the year ended December 31, 2023 was 6.52% on the drawn portion of the facility. The following is a summary of the amounts outstanding and capacity available under the credit facility as of December 31, 2023:

 Capacity
 Borrowings
 Letters of Credit
 Capacity Available

 $3,500
 $—
 $3
 $3,497

 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.

 Entergy Corporation has a commercial paper program with a Board-approved program limit of $2 billion. As of December 31, 2023, Entergy Corporation had $1,138.1 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2023 was 5.44%.

 Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2023 as follows:

 Expiration Date
 Amount of Facility
 Interest Rate (a)
 Amount Drawn
 as of
 Letters of Credit
Outstanding as of

 April 2024
 $25 million (b)
 7.29%
 —
 —

 $150 million (c)
 6.58%
 —
 —

 $350 million (c)
 6.71%
 —
 —

 July 2025
 $150 million
 6.58%
 —
 —

 June 2024
 $25 million (c)
 7.08%
 —
 —

 $150 million (c)
 6.71%
 —
 $1.1 million

 (a)The interest rate is the estimated interest rate as of December 31, 2023 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; $10 million for Entergy New Orleans; and $30 million for Entergy Texas.

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

 In addition, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each have an uncommitted standby letter of credit facility 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, 2023:

 Amount of Uncommitted Facility
 Letter of Credit Fee
 Letters of Credit Issued as of December 31, 2023
(a) (b)

 $25 million
 0.78%
 $5.8 million

 $125 million
 0.78%
 $17.1 million

 $65 million
 0.78%
 $20.0 million

 $15 million
 1.625%
 $0.5 million

 $80 million
 1.250%
 $76.5 million

 (a)As of December 31, 2023, letters of credit posted with MISO covered financial transmission rights exposure of $1.2 million for Entergy Arkansas, $0.5 million for Entergy Louisiana, $0.3 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, 2023, in addition to the $20 million in MISO letters of credit, Entergy Mississippi has $1 million in non-MISO letters of credit outstanding under this facility.

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

 2024
 2025
 2026
 after 2028

 Finance lease payments
 $20
 $18
 $16
 $25
 $34

 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, 2023 on non-cancelable operating leases with a term over one year:

 2024
 2025
 2026
 after 2028

 Operating lease payments
 $67
 $53
 $45
 $47
 $14

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

 Entergy currently expects to contribute approximately $270 million to its qualified pension plans and approximately $45.9 million to its other postretirement plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024 valuations are completed, which is expected by April 1, 2024. 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 $279 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

 In addition, 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 2024 through 2026.

 Planned construction and capital investments
 2024
 2025
 2026

 $2,270
 $2,675
 $3,135

 1,190
 1,385
 1,880

 2,110
 2,125
 1,940

 Total
 $5,920
 $6,500
 $7,335

 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, and diversify Entergy's portfolio, including Walnut Bend Solar, West Memphis Solar, Driver Solar, Orange County Advanced Power Station, and potential construction of additional generation;
 • Investments in Entergy's 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.

 For the next several years, the Utility's owned and contracted generating capacity is projected to be adequate to meet MISO reserve requirements; however, MISO recently implemented changes to its resource adequacy

 construct, and continues to pursue other changes, that generally move from an annual to a seasonal design and that change the way that resources are assigned capacity credit. As a result of these changes, there may be seasonal variations in the capacity credit afforded to the Utility operating companies' resources by MISO. 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, government actions, environmental regulations, business opportunities, market volatility, economic trends, changes in project plans, and the ability to access capital.

 Renewables

 Walnut Bend Solar

 In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 100 MW Walnut Bend Solar facility is in the public interest. Entergy Arkansas primarily requested cost recovery through the formula rate plan rider. In July 2021 the APSC granted Entergy Arkansas's petition and approved the acquisition of the resource and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In January 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. The counterparty notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination. Negotiations were conducted, including with respect to cost and schedule and to updates arising as a result of the Inflation Reduction Act of 2022. In April 2023, Entergy Arkansas filed an application for an amended certificate of environmental compatibility and public need with the APSC seeking approval by June 2023 for the updates to the cost and schedule that were previously approved by the APSC. In June 2023, Entergy Arkansas, the APSC general staff, and the Arkansas Attorney General filed a unanimous settlement supporting that the approval of the Walnut Bend Solar facility is in the public interest based on the terms in the settlement, including the treatment for the production tax credits associated with the facility. In July 2023, after requesting further testimony and purporting to modify several terms in the settlement and upon rehearing, the APSC approved the settlement largely on the terms submitted, including a 30-year amortization period for the production tax credits. In February 2024, Entergy Arkansas made an initial payment of approximately $169.7 million to acquire the facility. The project will achieve commercial operation once testing is completed and the project has achieved substantial completion. Entergy Arkansas currently expects the project to achieve commercial operation in the first half of 2024, at which time a substantial completion payment of approximately $20 million is expected.

 West Memphis Solar

 In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 180 MW West Memphis Solar facility is in the public interest. In October 2021 the APSC granted Entergy Arkansas's petition and approved the acquisition of the West Memphis Solar facility and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In April 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. In March 2022 the counterparty notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC seeking approval for a change in the transmission route and updates to the cost and schedule that were previously approved by the APSC. In March 2023 the APSC approved Entergy

 Arkansas's supplemental application. The project is currently expected to achieve commercial operation by the end of 2024.

 Driver Solar

 In April 2022, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 250 MW Driver Solar facility is in the public interest and requested cost recovery through the formula rate plan rider. The APSC established a procedural schedule with a hearing scheduled in June 2022, but the parties later agreed to waive the hearing and submit the matter to the APSC for a decision consistent with the filed record. In August 2022 the APSC granted Entergy Arkansas's petition and approved the acquisition of Driver Solar and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to inform the APSC as to the status of a tax equity partnership once construction is commenced. The parties are evaluating the effects of certain matters related to the Inflation Reduction Act of 2022, including the viability of a tax equity partnership. The project is expected to achieve commercial operation as early as mid-2024.

 2021 Solar Certification and the Geaux Green Option

 In November 2021, Entergy Louisiana filed an application with the LPSC seeking certification of and approval for the addition of four new solar photovoltaic resources with a combined nameplate capacity of 475 megawatts (the 2021 Solar Portfolio) and the implementation of a new green tariff, the Geaux Green Option (Rider GGO). The 2021 Solar Portfolio consists of four resources that are expected to provide $242 million in net benefits to Entergy Louisiana's customers. These resources, all of which would be constructed in Louisiana, include (i) the Vacherie Facility, a 150 megawatt resource in St. James Parish; (ii) the Sunlight Road Facility, a 50 megawatt resource in Washington Parish; (iii) the St. Jacques Facility, a 150 megawatt resource in St. James Parish; and (iv) the Elizabeth Facility, a 125 megawatt resource in Allen Parish. The St. Jacques Facility would be acquired through a build-own-transfer agreement; the remaining resources involve power purchase agreements. The Sunlight Road Facility and the Elizabeth Facility have estimated in service dates in 2024, and the Vacherie Facility and the St. Jacques Facility originally had estimated in service dates in 2025, but are now expected to be no sooner than 2027. The filing proposed to recover the costs of the power purchase agreements through the fuel adjustment clause and the formula rate plan and the acquisition costs through the formula rate plan.

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

 In March 2022 direct testimony from Walmart, the Louisiana Energy Users Group (LEUG), and the LPSC staff was filed. Each party recommended that the LPSC approve the resources proposed in Entergy Louisiana's application, and the LPSC staff witness indicated that the process through which Entergy Louisiana solicited or obtained the proposals for the resources complied with applicable LPSC orders. The LPSC staff and LEUG's witnesses made recommendations to modify the proposed Rider GGO and Entergy Louisiana's proposed rate relief. In April 2022 the LPSC staff and LEUG filed cross-answering testimony concerning each other's proposed modifications to Rider GGO and the proposed rate recovery. Entergy Louisiana filed rebuttal testimony in June 2022. In August 2022 the parties reached a settlement certifying the 2021 Solar Portfolio and approving implementation of Rider GGO. In September 2022 the LPSC approved the settlement. Following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities until the later of March 2023 or the completion of an environmental and economic impact study. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish's land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparties to the Vacherie and St. Jacques facilities regarding amendments to the respective agreements to

 address the impact of the St. James Parish ordinance, and the facilities are expected to reach commercial operation no sooner than 2027, depending upon agreement by the parties on the terms of the amendments. In September 2023, Entergy Louisiana reported to the LPSC that it also entered into amended agreements related to the Sunlight Road and Elizabeth facilities. Both facilities are still expected to achieve commercial operation in 2024.

 2022 Solar Portfolio and Expansion of the Geaux Green Option

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

 Alternative RFP and Certification

 In March 2023, Entergy Louisiana made the first phase of a bifurcated filing to seek approval from the LPSC for an alternative to the requests for proposals (RFP) process that would enable the acquisition of up to 3 GW of solar resources on a faster timeline than the current RFP and certification process allows. The initial phase of the filing established the need for the acquisition of additional resources and the need for an alternative to the RFP process. The second phase of the filing, which contains the details of the proposal for the alternative competitive procurement process and the information necessary to support certification, was filed in May 2023. In addition to the acquisition of up to 3 GW of solar resources, the filing also seeks approval of a new renewable energy credits-based tariff, Rider Geaux ZERO. Several parties have intervened, and a procedural schedule was established in May 2023 with a hearing scheduled for March 2024. In October 2023 the LPSC staff and intervenors filed testimony, with the LPSC staff supporting the amount of solar resources to be acquired and the alternative RFP process. The LPSC staff also supported, subject to certain recommendations, the proposed framework for evaluation and certification of the solar resources by the LPSC and the proposed tariff.

 Other Generation

 Orange County Advanced Power Station

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

 rebutting these various arguments. The hearing on the merits was held in June 2022, and post-hearing briefs were submitted in July 2022. In September 2022 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas's application for certification of Orange County Advanced Power Station subject to certain conditions, including a cap on cost recovery at $1.37 billion, the exclusion of investment associated with co-firing hydrogen, weatherization requirements, and customer receipt of any contractual benefits associated with the facility's guaranteed heat rate. In October 2022 the parties in the proceeding filed exceptions and replies to exceptions to the proposal for decision. Also in October 2022, Entergy Texas filed with the PUCT information regarding a new fixed pricing option for an estimated project cost of approximately $1.55 billion associated with Entergy Texas's issuance of limited notice to proceed by mid-November 2022. In November 2022 the PUCT issued a final order approving the requested amendment to Entergy Texas's certificate of convenience and necessity to construct, own, and operate the Orange County Advanced Power Station without the investment associated with hydrogen co-firing capability, without a cap on cost recovery, and subject to certain conditions, including weatherization requirements and customer receipt of any contractual benefits associated with the facility's guaranteed heat rate.

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

 System Resilience and Storm Hardening

 In December 2022, Entergy Louisiana filed an application with the LPSC seeking a public interest finding regarding Phase I of Entergy Louisiana's Future Ready resilience plan and approval of a rider mechanism to recover the program's costs. Phase I reflects the first five years of a ten-year resilience plan and includes investment of approximately $5 billion, including hardening investment, transmission dead-end structures, enhanced vegetation management, and telecommunications improvement. In April 2023 a procedural schedule was established with a hearing scheduled for January 2024. The LPSC staff and certain intervenors filed direct testimony in August, September, and October 2023. The LPSC staff filed cross-answering testimony in October 2023. The testimony largely supports implementation of some level of accelerated investment in resilience, but raises various issues related to the magnitude of the investment, the cost recovery mechanism applicable to the investment, and the ratemaking for the investment. In January 2024 the hearing in this matter was rescheduled to April 2024.

 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.

 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. The docket will identify a plan for storm hardening and resiliency projects with other stakeholders. 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, with final comments on that filing due July 2023. 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 rider to recover from customers the costs of the infrastructure hardening plan. In July 2023, Entergy New Orleans filed comments in support of its application. 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 Department of Energy's Grid Resilience and Innovation Partnerships program. The resolution also requires Entergy New Orleans to submit, no later than July 2024, a revised resilience plan consisting of projects in three-year intervals. Entergy New Orleans continues to seek approval of its application.

 Dividends and Stock Repurchases

 Declarations of dividends on Entergy's common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy's 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. At its January 2024 meeting, the Board declared a dividend of $1.13 per share. Entergy paid $918 million in 2023, $842 million in 2022, and $775 million in 2021 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 unit awards to key employees, which may be exercised to obtain shares of Entergy's common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy's management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans.

 In addition to 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, 2023, $350 million of authority remains under the $500 million share repurchase program. The amount of repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities, or if limitations in the credit markets continue for a prolonged period.

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

 • cash on hand ($133 million as of December 31, 2023);
 • 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 issuance tests 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 Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas are effective through April 2025. The FERC-authorized short-term borrowing limit for System Energy is effective through March 2025. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2025. Entergy New Orleans also has obtained long-term financing authorization from the City Council that extends through December 2025. Entergy Arkansas and Entergy Louisiana each has obtained long-term financing authorization from the FERC that extends through April 2025 for issuances by the nuclear fuel company variable interest entities. System Energy has obtained long-term financing authorization from the FERC that extends through March 2025 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 $2 billion. Through 2021, 2022, and 2023, Entergy Corporation 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 $1.5 billion, of which approximately $1.3 billion of aggregate gross sales price was the subject of forward sale agreements and was subject to adjustment pursuant to the forward sale agreements. Entergy Corporation settled the forward sales agreements for cash proceeds of $853 million in November 2022, $48 million

 in November 2023, and $83 million in December 2023. Entergy Corporation currently expects to issue approximately $1.4 billion of equity through 2026 under the at the market equity distribution program, with approximately $280 million already contracted under forward sales agreements as of December 31, 2023. See Note 7 to the financial statements for discussion of the forward sales agreements and common stock issuances and sales under the equity distribution program.

 Hurricane Ida (Entergy Louisiana)

 As discussed in Note 2 to the financial statements, in August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana's service area. In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to Louisiana. 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 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 in Note 2 to the financial statements, 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 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 Louisiana Local Government Facilities and Community Development Authority (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, LLC, a majority owned indirect subsidiary of Entergy. 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 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.

 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.

 Cash Flow Activity

 As shown in Entergy's Consolidated Statements of Cash Flows, cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:

 2023
 2022
 2021

 $224
 $443
 $1,759

 4,294
 2,585
 2,301

 (4,629)
 (5,710)
 (6,179)

 2,906
 2,562

 (91)
 (219)
 (1,316)

 $133
 $224
 $443

 Net cash flow provided by operating activities increased $1,709 million in 2023 primarily due to:

 • lower fuel costs and the timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;
 • a decrease of $210 million in storm spending primarily due to Hurricane Ida restoration efforts in 2022;
 • a decrease of $203 million in pension contributions in 2023. 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;
 • an increase of $57 million in interest received, including shorter-term financing interest earnings at Entergy Louisiana and interest on storm reserve escrow accounts. See Note 2 to the financial statements for a discussion of Entergy Louisiana's shorter-term financing interest earnings; and
 • severance and retention payments of $40 million in 2022 related to Entergy's exit from the merchant power business. See Note 13 to the financial statements for further discussion of Entergy's exit from the merchant power business.

 • lower collections from Utility customers;
 • net proceeds of $202 million received from the LURC in December 2022 from the Entergy New Orleans storm cost securitization. See Note 2 to the financial statements for discussion of the Entergy New Orleans storm cost securitization; and
 • an increase of $85 million in interest paid.

 Net cash flow used in investing activities decreased $1,081 million in 2023 primarily due to:

 • a decrease of $595 million in distribution construction expenditures primarily due to lower capital expenditures for storm restoration in 2023. The decrease in storm restoration expenditures is primarily due to Hurricane Ida restoration efforts in 2022;
 • net receipts from storm reserve escrow accounts of $79 million in 2023 compared to net payments to storm reserve escrow accounts of $369 million in 2022;
 • a decrease of $86 million in information technology capital expenditures primarily due to decreased spending on various technology projects in 2023;
 • the initial payment of approximately $105 million in 2022 as compared to the substantial completion and final payments totaling approximately $35 million in 2023 for the purchase of the Sunflower Solar facility by the Entergy Mississippi tax equity partnership. See Note 14 to the financial statements for discussion of the Sunflower Solar facility purchase; and
 • a decrease of $57 million in transmission construction expenditures primarily due to lower capital expenditures for storm restoration in 2023. The decrease in storm restoration expenditures is primarily due to Hurricane Ida restoration efforts in 2022.

 • an increase of $98 million in non-nuclear generation construction expenditures primarily due to higher spending at Entergy Texas on the Orange County Advanced Power Station project, partially offset by a lower scope of work on projects performed, including during plant outages, in 2023 as compared to 2022;
 • an increase of $47 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
 • an increase of $30 million in decommissioning trust fund investment activity.

 Net cash flow provided by financing activities decreased $2,662 million in 2023 primarily due to:

 • proceeds from securitization of $1.5 billion received by the storm trust II at Entergy Louisiana in 2023 compared to proceeds from securitization of $3.2 billion received by the storm trust I at Entergy Louisiana in 2022;
 • long-term debt activity using approximately $862 million of cash in 2023 compared to providing approximately $24 million of cash in 2022;
 • a decrease of $722 million in net proceeds from the issuance of common stock under the at the market equity distribution program in 2023 as compared to 2022; and
 • an increase of $77 million in common stock dividends paid in 2023 as a result of an increase in the dividend paid per share and an increase in the number of shares outstanding.

 The decrease was partially offset by net issuances of $311 million of commercial paper in 2023 as compared to net repayments of $374 million of commercial paper in 2022 and an increase of $110 million in prepaid deposits related to contributions-in-aid-of-construction primarily for customer and generator interconnection agreements.

 See Note 2 to the financial statements for a discussion of the Entergy Louisiana storm cost securitizations. See Note 4 to the financial statements for details of Entergy's commercial paper program. See Note 5 to the financial statements for details of long-term debt. See Note 7 to the financial statements for discussion of the equity distribution program.

 See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow Activity" in Item 7 of Entergy's Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.

 Rate, Cost-recovery, and Other Regulation

 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:

 Authorized Return on Common Equity

 9.15% - 10.15%

 9.0% - 10.0% Electric; 9.3% - 10.3% Gas

 9.74% - 11.88%

 8.85% - 9.85%

 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.

 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 Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. The current return on equity and capital structure of System Energy are currently the subject of complaints filed by certain of the Utility operating companies' retail regulators. The current return on equity under the Unit Power Sales Agreement is 10.94% for Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans and 9.65% for Entergy Mississippi as a result of the System Energy settlement with the MPSC. If the System Energy settlement with the APSC is approved by the FERC, the authorized rate of return on equity under the Unit Power Sales Agreement for Entergy Arkansas will be adjusted to 9.65% in accordance with the settlement terms. Prior to each Utility operating companies' termination of participation in the System Agreement (Entergy Arkansas in December 2013, Entergy Mississippi in November 2015, and Entergy Louisiana, Entergy New Orleans, and Entergy Texas, each in August 2016), the Utility operating companies engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which was a rate schedule approved by the FERC. Certain of the Utility operating companies' retail regulators are pursuing or have settled litigation involving the System Agreement at the FERC and in federal courts. See Note 2 to the financial statements for discussion of the complaints filed with the FERC, including challenges with respect to System Energy's authorized return on equity and capital structure, renewal of System Energy's 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, as well as System Energy formula rate annual protocols formal challenges

 concerning 2020 and 2021 calendar year bills and discussion of the System Energy settlements with the MPSC and the APSC.

 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. See Notes 4 and 5 to the financial statements for the details of Entergy's debt outstanding.

 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 the non-utility operations business contain provisions that require an Entergy subsidiary to provide credit support to secure its obligations under the agreements. The primary form of credit support to satisfy these requirements is an Entergy Corporation guarantee. Cash and letters of credit are also acceptable forms of credit support. At December 31, 2023, based on power prices at that time, Entergy had liquidity exposure of $9 million under the guarantees in place supporting its non-utility operations business transactions and $8 million of posted cash collateral.

 Entergy's Utility business includes the ownership and operation of nuclear generating plants and is, therefore, subject to the risks related to such ownership and operation. These include risks related to: the 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; the risk of an adverse outcome to a challenge to the prudence of operations at Grand Gulf; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets

 and earnings to complete decommissioning of 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, except River Bend, which is in Column 2.

 In July 2023 the NRC placed River Bend in Column 2, effective April 2023, based on failure to inspect wiring associated with the high pressure core spray system. In August 2023 the NRC issued a finding and notice of violation related to a radiation monitor calibration issue at River Bend. In December 2023, River Bend successfully completed the inspection on the high pressure core spray system issue and in February 2024, River Bend successfully completed the supplemental inspection for the radiation monitor calibration issue involving radiation monitor calibrations. River Bend will remain in Column 2 pending receipt of the formal report on the inspection, which is expected in first quarter 2024.

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

 Nuclear Decommissioning Costs

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

 • Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant's retirement must be estimated for those plants that do not have an announced shutdown date. The estimate may include assumptions regarding the possibility that the plant may have an operating life shorter than the operating license expiration. Second, an assumption must be made regarding whether all decommissioning activity will proceed immediately upon plant retirement, or whether the plant will be placed in SAFSTOR status. SAFSTOR is decommissioning a facility by placing it in a safe, stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation

 of operations. A change of assumption regarding either the period of continued operation, the use of a SAFSTOR period, or whether Entergy will continue to hold the plant or the plant is held for sale can change the present value of the asset retirement obligation.
 • Cost Escalation Factors - Entergy's current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by factors ranging from approximately 2% to 3% annually. A 50-basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 10% to 17%. The timing assumption influences the significance of the effect of a change in the estimated inflation or cost escalation rate because the effect increases with the length of time assumed before decommissioning activity ends.
 • Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. The DOE has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law. The DOE continues to delay meeting its obligation and Entergy's nuclear plant owners are continuing to pursue damage claims against the DOE for its failure to provide timely spent fuel storage. Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities during the decommissioning period can have a significant effect (as much as an average of 20% to 30% of total estimated decommissioning costs). Entergy's decommissioning studies include cost estimates for spent fuel storage. These estimates could change in the future, however, based on the expected timing of when the DOE begins to fulfill its obligation to receive and store spent nuclear fuel. See Note 8 to the financial statements for further discussion of Entergy's spent nuclear fuel litigation.
 • Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of nuclear facilities has been gained and that experience has been incorporated into Entergy's current decommissioning cost estimates. Given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could be gained and affect current cost estimates. In addition, if regulations regarding nuclear decommissioning were to change, this could affect cost estimates.
 • Interest Rates - The estimated decommissioning costs that are the basis for the recorded decommissioning liability are discounted to present value using a credit-adjusted risk-free rate. When the decommissioning liability is revised, increases in cash flows are discounted using the current credit-adjusted risk-free rate. Decreases in estimated cash flows are discounted using the credit-adjusted risk-free rate used previously in estimating the decommissioning liability that is being revised. Therefore, to the extent that a revised cost study results in an increase in estimated cash flows, a change in interest rates from the time of the previous cost estimate will affect the calculation of the present value of the revised decommissioning liability.

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

 Entergy's Utility operating companies and System Energy are subject to retail regulation by their respective state and local regulators and to wholesale regulation by the FERC. Because these regulatory agencies set the rates the Utility operating companies and System Energy are allowed to charge customers based on allowable costs, including a reasonable return on equity, the Utility operating companies and System Energy apply accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be credited to customers through future regulated rates or (2) billings in advance of expenditures for approved regulatory programs. See Note 2 to the

 financial statements for a discussion of rate and regulatory matters, including details of Entergy's and the Registrant Subsidiaries' regulatory assets and regulatory liabilities.

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

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

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

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

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

 Entergy's reported costs of providing these benefits, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations,

 the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate for Entergy and the Registrant Subsidiaries.

 Assumptions

 Key actuarial assumptions utilized in determining qualified pension and other 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 other 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 2023 weighted-average target pension asset allocation is 49% equity and 51% fixed income securities, of which 43% is long duration fixed income.

 In 2017, Entergy implemented a new 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 new 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. The 2023 weighted-average target postretirement asset allocation is 42% equity and 58% fixed income securities.

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

 Costs and Sensitivities

 The estimated 2024 and actual 2023 qualified pension and other postretirement costs and related underlying assumptions and sensitivities are shown below:

 Costs
 Estimated 2024
 2023

 Qualified pension cost
 $52.6
 $253.7 (a)

 Other postretirement income
 ($24.3)
 ($13.8)

 Assumptions
 2024
 2023

 Discount rates

 Qualified pension

 5.08%
 5.26%

 4.97%
 5.16%

 Other postretirement

 4.82%
 5.00%

 4.91%
 5.09%

 Expected long-term rates of return

 Qualified pension assets
 6.75%
 7.00%

 Other postretirement - non-taxable assets
 6.50% - 7.25%
 6.00% - 7.00%

 Other postretirement - taxable assets - after tax rate
 5.25%
 5.25%

 Weighted-average rate of increase in future compensation
 3.98% - 4.40%
 3.98% - 4.40%

 Assumed health care cost trend rates

 Pre-65 retirees
 6.95%
 6.65%

 Post-65 retirees
 7.88%
 7.50%

 Ultimate health care cost trend rate
 4.75%
 4.75%

 Year ultimate health care cost trend rate is reached and beyond

 Pre-65 retirees
 2032
 2032

 Post-65 retirees
 2032
 2032

 (a) In 2023, qualified pension cost included settlement costs of $160.4 million.

 Actual asset returns have an effect on Entergy's qualified pension and other postretirement costs. In 2023, Entergy's actual annual return on qualified pension assets was approximately 15% and on other postretirement assets was approximately 13%, as compared to the 2023 expected long-term rates of return discussed above.

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

 $4
 $145

 $14
 $—

 0.25%
 $4
 $24

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

 $1
 $21

 0.25%
 $2
 $14

 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.

 Employer Contributions

 Entergy contributed $267 million to its qualified pension plans in 2023. Entergy estimates pension contributions will be approximately $270 million in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024.

 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 $49.1 million to its postretirement plans in 2023 and plans to contribute $45.9 million in 2024.

 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 by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters.
 • The identification of additional impacts, sites, issues, or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party.
 • The resolution or progression of existing matters through the court system or resolution by the EPA or relevant state or local authority.

 Litigation

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

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

 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 Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. System Energy and the Unit Power Sales Agreement are currently the subject of several litigation proceedings at the FERC (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit). See Note 2 to the financial statements for discussion of these proceedings.

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

 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, 2023.

 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, 2023. 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.

 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.
 RODERICK K. WEST
Chairman of the Board, President, and Chief Executive Officer of System Energy Resources, Inc.

 We have audited the accompanying consolidated balance sheets of Entergy Corporation and Subsidiaries (the "Corporation") as of December 31, 2023 and 2022, 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, 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, 2023, 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 23, 2024, expressed an unqualified opinion on the Corporation's internal control over financial reporting.

 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

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

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

 We identified the impact of rate regulation as a critical audit matter due to the judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the (1) likelihood of recovery in future rates of incurred costs and the (2) likelihood of refunds to customers. Auditing management's judgments regarding the outcome of future decisions by the Commissions, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities involved specialized knowledge of accounting for rate regulation and the rate-setting process due to its inherent complexities and auditor judgment to evaluate management estimates and the subjectivity of audit evidence.

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

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

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

 • We read relevant regulatory orders issued by the Commissions for the Corporation to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the 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 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.

 Securitization Financing — Storm Cost Recovery Filings with Retail Regulators — Entergy Corporation and Subsidiaries — Refer to Note 2 to the financial statements

 Hurricane Ida in 2021 caused significant damage to portions of the Corporation's service area within the state of Louisiana. In January 2023, the Louisiana Public Service Commission ("LPSC") issued a Financing Order authorizing financing of $1.491 billion of system restoration costs utilizing the securitization process authorized by Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature's Regular Session of 2021 ("Act 55, as supplemented by Act 293"). In March 2023, the securitization financing closed, resulting in the issuance of $1.491 billion principal amount bonds by Louisiana Local Government Environmental Facilities and Community Development Authority ("LCDA"), a political subdivision of the State of Louisiana. The LCDA loaned the proceeds to the Louisiana Utilities Restoration Corporation ("LURC"), and the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust II (the "storm trust II"). The Corporation and the LURC each hold beneficial interests in the storm trust II.

 The Corporation does not report the bonds issued by the LCDA on its balance sheet 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 Corporation collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. The Corporation does not report the collection of system restoration charges as revenue because the Corporation 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 II is required to liquidate Entergy Finance Company preferred interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial. The Corporation consolidates the storm trust II as a variable interest entity and the LURC's 1% beneficial interest is shown as a noncontrolling interest in the financial statements.

 We identified management's conclusion that the bonds issued by the LCDA are the obligation of the LCDA 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 securitization financing transactions.

 Our audit procedures related to the Act 55, as supplemented by Act 293, securitization financing included the following, among others:

 • We tested the effectiveness of management's controls over the evaluation of the accounting impact of this securitization financing transaction, including the conclusion that the bonds issued by the LCDA are the obligation of the LCDA.

 • We evaluated the Corporation's disclosures related to the impacts of the Act 55, as supplemented by Act 293, securitization financing, including the balances recorded.

 • We read relevant regulatory and financing orders issued by the LPSC for the Corporation, the LURC, and the LCDA, and evaluated external information to compare to management's conclusions.

 • We obtained an analysis from management and support from the Corporation's internal and external legal counsel regarding the legal status of the bonds issued by the LCDA and the system restoration property granted to the LURC to assess management's assertion that the bonds issued by the LCDA are the obligation of the LCDA.

 • With the assistance of professionals in our firm having expertise and experience in addressing the accounting for securitization financing transactions by regulated utilities, we evaluated the Company's conclusion, including the conclusion that the bonds issued by the LCDA are the obligation of the LCDA.

 Uncertain Tax Positions — Entergy Corporation and Subsidiaries — Refer to Note 3 to the financial statements

 The Corporation accounts for uncertain income tax positions 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 fifty percent likely of being realized upon settlement. The Corporation has uncertain tax positions which require management to make judgments and assumptions to determine whether available information supports the assertion that the recognition threshold is met, particularly related to the technical merits and facts and circumstances of each position, as well as the probability of different potential outcomes. These uncertain tax positions could be significantly affected by audits by taxing authorities of the tax positions and changes to relevant tax law. There is an uncertain tax position related to the March 2023 securitization financing that provided for a tax benefit in the first quarter of 2023 of approximately $129 million.

 Given the judgments made by management, we identified management's conclusion that the securitization uncertain tax position met the more-likely-than-not recognition threshold as a critical audit matter. Auditing management's judgments regarding this uncertain tax position involved specialized knowledge of uncertain tax positions and auditor judgment to evaluate the subjectivity of audit evidence.

 Our audit procedures related to the securitization uncertain tax position included the following, among others:

 • We tested the effectiveness of controls related to the securitization uncertain tax position, including those over the recognition and measurement of the income tax benefit.

 • We evaluated the Corporation's disclosures, and the balances recorded, related to the securitization uncertain tax position.

 • We evaluated the methods and assumptions used by management to estimate the securitization uncertain tax position by testing the underlying data that served as the basis for the uncertain tax position.

 • With the assistance of our income tax specialists, we tested the technical merits of the securitization uncertain tax position and management's key estimates and judgments made by:

 • Assessing the technical merits of the uncertain tax position by comparing to similar cases filed with the Internal Revenue Service.

 • Obtaining an opinion from the Corporation's external legal counsel regarding certain federal income tax consequences related to the Act 55, as supplemented by Act 293, securitization financing and evaluating whether the analysis was consistent with our interpretation of the relevant laws and circumstances.

 • Considering the impact of changes or settlements in the tax environment on management's methods and assumptions used to estimate the uncertain tax position.

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

 2023
 2022
 2021

 (In Thousands, Except Share Data)

 $ 11,842,454
 $ 13,186,845
 $ 10,873,995

 180,490
 233,920
 170,610

 Other

 124,468
 343,472
 698,291

 TOTAL
 12,147,412
 13,764,237
 11,742,896

 2,801,580
 3,732,851
 2,458,096

 968,036
 1,561,544
 1,271,677

 Nuclear refueling outage expenses
 150,147
 156,032
 172,636

 2,898,213
 3,038,459
 2,968,621

 42,679
 ( 163,464)
 263,625

 206,674
 224,076
 306,411

 755,574
 733,538
 660,290

 1,845,003
 1,761,023
 1,684,286

 ( 138,469)
 669,403
 111,628

 TOTAL
 9,529,437
 11,713,462
 9,897,270

 2,617,975
 2,050,775
 1,845,626

 OTHER INCOME (DEDUCTIONS)

 98,493
 72,832
 70,473

 Interest and investment income (loss)
 162,726
 ( 75,581)
 430,466

 ( 201,013)
 ( 77,629)
 ( 201,778)

 TOTAL
 60,206
 ( 80,378)
 299,161

 1,046,164
 940,060
 863,712

 ( 39,758)
 ( 27,823)
 ( 29,018)

 TOTAL
 1,006,406
 912,237
 834,694

 1,671,775
 1,058,160
 1,310,093

 ( 690,535)
 ( 38,978)
 191,374

 CONSOLIDATED NET INCOME
 2,362,310
 1,097,138
 1,118,719

 Preferred dividend requirements of subsidiaries and noncontrolling interests
 5,774

 NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION
 $ 2,356,536
 $ 1,103,166
 $ 1,118,492

 Earnings per average common share:

 Basic
 $ 11.14
 $ 5.40
 $ 5.57

 Diluted
 $ 11.10
 $ 5.37
 $ 5.54

 Basic average number of common shares outstanding
 211,569,931
 204,450,354
 200,941,511

 Diluted average number of common shares outstanding
 212,376,495
 205,547,578
 201,873,024

 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 2023
 2022
 2021

 $ 2,362,310
 $ 1,097,138
 $ 1,118,719

 Cash flow hedges net unrealized gain (loss)

 (net of tax benefit of $ —, $ —, and ($ 7,935))

 —
 1,035
 ( 29,754)

 (net of tax expense of $ 9,248, $ 46,789, and $ 55,161)

 146,893
 195,929

 Net unrealized investment loss

 (net of tax benefit of $ —, ($ 2,231), and ($ 28,435))

 —
 ( 7,154)
 ( 49,496)

 140,774
 116,679

 Comprehensive Income
 2,391,604
 1,237,912
 1,235,398

 Preferred dividend requirements of subsidiaries and noncontrolling interests
 5,774

 Comprehensive Income Attributable to Entergy Corporation
 $ 2,385,830
 $ 1,243,940
 $ 1,235,171

 2023
 2022
 2021

 Consolidated net income
 $ 2,362,310
 $ 1,097,138
 $ 1,118,719

 Adjustments to reconcile consolidated net income to net cash flow provided by operating activities:

 Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 2,244,479
 2,190,371
 2,242,944

 ( 707,822)
 ( 47,154)
 248,719

 42,679
 ( 163,464)
 263,599

 Changes in working capital:

 101,801
 ( 157,267)
 ( 84,629)

 ( 45,166)
 6,943
 18,359

 ( 135,048)
 ( 102,013)
 269,797

 10,122
 4,263
 ( 21,183)

 18,933
 4,113
 ( 10,640)

 759,361
 ( 393,746)
 ( 466,050)

 ( 210,038)
 ( 157,235)
 ( 53,883)

 Changes in provisions for estimated losses
 ( 68,631)
 374,079
 ( 85,713)

 Changes in regulatory assets
 435,877
 576,859
 ( 536,707)

 Changes in other regulatory liabilities
 463,805
 ( 266,559)
 43,631

 Effect of securitization on regulatory asset
 ( 491,150)
 ( 941,035)
 —

 Changes in pension and other postretirement liabilities
 ( 610,479)
 ( 699,261)
 ( 897,167)

 Other
 123,295
 1,259,458
 250,917

 4,294,328
 2,585,490
 2,300,713

 Construction/capital expenditures
 ( 4,440,652)
 ( 5,065,126)
 ( 6,087,296)

 98,493
 72,832
 70,473

 Nuclear fuel purchases
 ( 270,973)
 ( 223,613)
 ( 166,512)

 Payment for purchase of assets
 ( 35,094)
 ( 106,193)
 ( 168,304)

 Net proceeds (payments) from sale of assets
 11,000
 ( 1,195)
 17,421

 Insurance proceeds received for property damages
 19,493
 —
 —

 Litigation proceeds from settlement agreement
 —
 9,829
 —

 Changes in securitization account
 5,493
 15,514
 13,669

 Payments to storm reserve escrow accounts
 ( 19,780)
 ( 1,494,048)
 ( 25)

 Receipts from storm reserve escrow accounts
 98,529
 1,125,279
 83,105

 ( 16,733)
 ( 3,328)
 2,343

 Litigation proceeds for reimbursement of spent nuclear fuel storage costs
 23,655
 32,367
 49,236

 Proceeds from nuclear decommissioning trust fund sales
 1,082,722
 1,636,686
 5,553,629

 Investment in nuclear decommissioning trust funds
 ( 1,185,130)
 ( 1,708,901)
 ( 5,547,015)

 ( 4,628,977)
 ( 5,709,897)
 ( 6,179,276)

 2023
 2022
 2021

 Proceeds from the issuance of:

 4,273,297
 6,019,835
 8,308,427

 Treasury stock
 9,823
 32,042
 5,977

 Common stock
 130,649
 852,555
 200,776

 ( 5,135,753)
 ( 5,995,903)
 ( 4,827,827)

 Changes in commercial paper - net
 310,550
 ( 373,556)
 ( 426,312)

 Capital contributions from noncontrolling interests

 Proceeds received by storm trusts related to securitization
 3,163,572
 —

 Other
 107,595
 42,761
 43,221

 Dividends paid:

 Common stock
 ( 918,193)
 ( 841,677)
 ( 775,122)

 Preferred stock

 Net cash flow provided by financing activities
 243,033
 2,906,012
 2,562,023

 ( 91,616)
 ( 218,395)
 ( 1,316,540)

 224,164
 442,559
 1,759,099

 $ 132,548
 $ 224,164
 $ 442,559

 Cash paid during the period for:

 $ 987,252
 $ 901,884
 $ 843,228

 $ 42,821
 $ 28,354
 $ 98,377

 $ 487,439
 $ 461,748
 $ 722,622

 2023
 2022

 Cash
 $ 71,609
 $ 115,290

 60,939
 108,874

 132,548
 224,164

 699,411
 788,552

 ( 25,905)
 ( 30,856)

 Other
 225,334
 241,702

 494,615
 495,859

 1,393,455
 1,495,257

 169,967
 710,401

 192,799
 147,632

 1,418,969
 1,183,308

 Deferred nuclear refueling outage costs
 140,115
 143,653

 213,016
 190,611

 TOTAL
 3,660,869
 4,095,026

 Decommissioning trust funds
 4,863,710
 4,121,864

 418,546
 366,405

 Storm reserve escrow accounts
 323,206
 401,955

 Other
 69,494
 102,259

 TOTAL
 5,674,956
 4,992,483

 PROPERTY, PLANT, AND EQUIPMENT

 66,850,474
 64,646,911

 717,503
 691,970

 2,109,703
 1,844,171

 707,852
 582,119

 TOTAL PROPERTY, PLANT, AND EQUIPMENT
 70,385,532
 67,765,171

 26,551,203
 25,288,047

 PROPERTY, PLANT, AND EQUIPMENT - NET
 43,834,329
 42,477,124

 Other regulatory assets (includes securitization property of $ 250,830 as of December 31, 2023 and $ 282,886 as of December 31, 2022)

 5,669,404
 6,036,397

 172,201
 241,085

 Goodwill
 374,099
 377,172

 Accumulated deferred income taxes
 16,367
 84,100

 Other
 301,171
 291,804

 TOTAL
 6,533,242
 7,030,558

 $ 59,703,396
 $ 58,595,191

 2023
 2022

 $ 2,099,057
 $ 2,309,037

 Notes payable and commercial paper
 1,138,171
 827,621

 1,566,745
 1,777,590

 446,146
 424,723

 434,213
 424,091

 214,197
 195,264

 218,927
 —

 59,508
 104,845

 Sale-leaseback/depreciation regulatory liability
 —
 103,497

 Other
 219,528
 202,779

 TOTAL
 6,396,492
 6,369,447

 4,245,982
 4,818,837

 205,973
 211,220

 Regulatory liability for income taxes-net
 1,033,242
 1,258,276

 3,116,926
 2,324,590

 Decommissioning and asset retirement cost liabilities
 4,505,782
 4,271,531

 462,570
 531,201

 648,413
 1,213,555

 Long-term debt (includes securitization bonds of $ 263,007 as of December 31, 2023 and $ 292,760 as of December 31, 2022)

 23,008,839
 23,623,512

 Other
 1,116,661
 688,720

 TOTAL
 38,344,388
 38,941,442

 Subsidiaries' preferred stock without sinking fund

 219,410
 219,410

 Preferred stock, no par value, authorized 1,000,000 shares in 2023 and 2022; issued shares in 2023 and 2022 - none

 —
 —

 Common stock, $ 0.01 par value, authorized 499,000,000 shares in 2023 and 2022; issued 280,975,348 shares in 2023 and 279,653,929 shares in 2022

 2,810
 2,797

 Paid-in capital
 7,795,411
 7,632,895

 Retained earnings
 11,940,384
 10,502,041

 Accumulated other comprehensive loss
 ( 162,460)
 ( 191,754)

 Less - treasury stock, at cost ( 68,126,778 shares in 2023 and 68,477,429 shares in 2022)

 4,953,498
 4,978,994

 Total shareholders' equity
 14,622,647
 12,966,985

 Subsidiaries' preferred stock without sinking fund and noncontrolling interests

 120,459
 97,907

 TOTAL
 14,743,106
 13,064,892

 $ 59,703,396
 $ 58,595,191

 Shareholders' Equity

 Subsidiaries' Preferred Stock and Noncontrolling Interests
 Common Stock
 Treasury Stock
 Paid-in Capital
 Retained Earnings
 Accumulated Other Comprehensive Loss
 Total

 $ 35,000
 $ 2,700
 ($ 5,074,456)
 $ 6,549,923
 $ 9,897,182
 ($ 449,207)
 $ 10,961,142

 Consolidated net income (a)
 —
 —
 —
 1,118,492
 —
 1,118,719

 —
 —
 —
 —
 —
 116,679
 116,679

 Common stock issuances and sales under the at the market equity distribution program
 —
 —
 204,194
 —
 —
 204,214

 Common stock issuance costs
 —
 —
 —
 ( 3,438)
 —
 —
 ( 3,438)

 Common stock issuances related to stock plans
 —
 —
 34,757
 15,560
 —
 —
 50,317

 Common stock dividends declared
 —
 —
 —
 —
 ( 775,122)
 —
 ( 775,122)

 —
 —
 —
 —
 —

 Preferred dividend requirements of subsidiaries (a)
 —
 —
 —
 —
 —

 $ 68,110
 $ 2,720
 ($ 5,039,699)
 $ 6,766,239
 $ 10,240,552
 ($ 332,528)
 $ 11,705,394

 Consolidated net income (loss) (a)
 —
 —
 —
 1,103,166
 —
 1,097,138

 —
 —
 —
 —
 —
 140,774
 140,774

 Common stock issuances and sales under the at the market equity distribution program
 —
 —
 861,916
 —
 —
 861,993

 Common stock issuance costs
 —
 —
 —
 ( 9,438)
 —
 —
 ( 9,438)

 Common stock issuances related to stock plans
 —
 —
 60,705
 14,178
 —
 —
 74,883

 Common stock dividends declared
 —
 —
 —
 —
 ( 841,677)
 —
 ( 841,677)

 Beneficial interest in storm trust
 31,636
 —
 —
 —
 —
 —
 31,636

 Capital contributions from noncontrolling interests
 —
 —
 —
 —
 —

 Distributions to noncontrolling interests
 ( 2,194)
 —
 —
 —
 —
 —
 ( 2,194)

 Preferred dividend requirements of subsidiaries (a)
 —
 —
 —
 —
 —

 $ 97,907
 $ 2,797
 ($ 4,978,994)
 $ 7,632,895
 $ 10,502,041
 ($ 191,754)
 $ 13,064,892

 Consolidated net income (a)
 5,774
 —
 —
 —
 2,356,536
 —
 2,362,310

 —
 —
 —
 —
 —

 Common stock issuances and sales under the at the market equity distribution program
 —
 —
 132,404
 —
 —
 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

 —
 —
 —
 —
 —

 Distributions to noncontrolling interests
 ( 5,188)
 —
 —
 —
 —
 —
 ( 5,188)

 Preferred dividend requirements of subsidiaries (a)
 —
 —
 —
 —
 —

 $ 120,459
 $ 2,810
 ($ 4,953,498)
 $ 7,795,411
 $ 11,940,384
 ($ 162,460)
 $ 14,743,106

 (a) Consolidated net income (loss) and preferred dividend requirements of subsidiaries include $ 16 million for 2023, 2022, and 2021 of preferred dividends on subsidiaries' preferred stock without sinking fund that is not presented as equity.

 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.

 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 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.

 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, 2023 and 2022, is shown below:

 2023
 2022

 Production

 $ 7,944
 $ 7,936

 Other
 7,045
 7,256

 9,927
 9,590

 12,927
 12,363

 Other
 3,173
 2,906

 2,110
 1,844

 Property, plant, and equipment - net
 $ 43,834
 $ 42,477

 Depreciation rates on average depreciable property for Entergy approximated 2.9 % in 2023, 2.8 % in 2022, and 2.7 % in 2021.

 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 $ 193 million as of December 31, 2023 and $ 208 million as of December 31, 2022.

 Net property, plant, and equipment (including property under lease and associated accumulated amortization) for the Registrant Subsidiaries by functional category, as of December 31, 2023 and 2022, is shown below:

 2023

 Production

 $ 1,859
 $ 4,153
 $ —
 $ —
 $ —
 $ 1,932

 Other
 3,583
 1,177
 —

 2,102
 4,283
 1,483
 1,882

 3,395
 4,371
 2,272
 2,197
 —

 Other
 1,156

 —
 —
 —

 Property, plant, and equipment - net
 $ 9,374
 $ 18,472
 $ 5,248
 $ 1,616
 $ 6,425
 $ 2,294

 2022

 Production

 $ 1,858
 $ 4,116
 $ —
 $ —
 $ —
 $ 1,962

 Other
 3,652
 1,244
 —

 2,086
 4,055
 1,435
 1,846

 2,981
 4,827
 2,035
 1,895
 —

 Other
 1,062

 —
 —
 —

 Property, plant, and equipment - net
 $ 8,942
 $ 18,662
 $ 4,985
 $ 1,556
 $ 5,613
 $ 2,309

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

 2023
 2.7 %
 2.6 %
 3.6 %
 3.3 %
 4.0 %
 1.6 %

 2022
 2.7 %
 2.4 %
 3.6 %
 3.2 %
 3.1 %
 2.0 %

 2021
 2.7 %
 2.4 %
 3.6 %
 3.2 %
 3.2 %
 1.9 %

 Non-utility property - at cost (less accumulated depreciation) for Entergy Arkansas is reported net of accumulated depreciation of $ 0.1 million as of December 31, 2023 and $ 0.1 million as of December 31, 2022. Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $ 187.2 million as of December 31, 2023 and $ 202.2 million as of December 31, 2022. Non-utility property - at cost (less accumulated depreciation) for Entergy Mississippi is reported net of accumulated depreciation of $ 0.5 million as of December 31, 2023 and $ 0.5 million as of December 31, 2022.

 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, 2023, 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

 Utility:

 Entergy Arkansas -

 Unit 1
 Coal
 31.50
 %
 $ 145
 $ 108

 Coal

 15.75
 %
 $ 42
 $ 31

 White Bluff
 Units 1 and 2
 Coal
 1,244
 57.00
 %
 $ 593
 $ 404

 Ouachita (b)
 Gas
 66.67
 %
 $ 173
 $ 159

 Union (c)
 Gas
 25.00
 %
 $ 29
 $ 12

 Entergy Louisiana -

 Unit 6
 Coal
 40.25
 %
 $ 299
 $ 224

 Unit 6 Common Facilities
 Coal

 22.04
 %
 $ 22
 $ 11

 Big Cajun 2
 Unit 3
 Coal
 24.15
 %
 $ 149
 $ 136

 Big Cajun 2
 Unit 3 Common Facilities
 Coal
 8.05
 %
 $ 5
 $ 3

 Ouachita (b)
 Gas
 33.33
 %
 $ 91
 $ 79

 Acadia
 Gas
 50.00
 %
 $ 22
 $ 3

 Union (c)
 Gas
 50.00
 %
 $ 59
 $ 14

 Entergy Mississippi -

 Units 1 and 2 and Common Facilities
 Coal
 1,666
 25.00
 %
 $ 293
 $ 182

 Entergy New Orleans -

 Union (c)
 Gas
 25.00
 %
 $ 30
 $ 10

 Entergy Texas -

 Unit 6
 Coal
 29.75
 %
 $ 211
 $ 141

 Unit 6 Common Facilities
 Coal

 16.30
 %
 $ 8
 $ 4

 Big Cajun 2
 Unit 3
 Coal
 17.85
 %
 $ 112
 $ 101

 Big Cajun 2
 Unit 3 Common Facilities
 Coal
 5.95
 %
 $ 4
 $ 2

 Montgomery County
 Unit 1
 Gas
 92.44
 %
 $ 745
 $ 54

 System Energy -

 Grand Gulf (d)
 Unit 1
 1,383
 90.00
 %
 $ 5,499
 $ 3,494

 Unit 2
 Coal
 14.37
 %
 $ 79
 $ 59

 Coal

 7.18
 %
 $ 21
 $ 15

 Unit 6
 Coal
 10.90
 %
 $ 120
 $ 74

 Unit 6 Common Facilities
 Coal

 5.97
 %
 $ 3
 $ 1

 (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.

 (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 Entergy's intercompany income tax allocation agreements. 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. See the "Other Tax Matters - Tax Cuts and Jobs Act" section in Note 3 to the financial statements for discussion of the effects of the enactment of the Tax Cuts and Jobs Act in December 2017.

 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.

 Earnings per Share

 The following table presents Entergy's basic and diluted earnings per share calculations included on the consolidated income statements:

 2023
 2022
 2021

 (Dollars In Thousands, Except Per Share Data; Shares in Millions)

 $/share

 $/share

 $/share

 Consolidated net income
 $ 2,362,310
 $ 1,097,138
 $ 1,118,719

 Less: Preferred dividend requirements of subsidiaries and noncontrolling interests
 5,774

 Net income attributable to Entergy Corporation
 $ 2,356,536

 $ 1,103,166

 $ 1,118,492

 Basic shares and earnings per average common share
 211.6
 $ 11.14
 204.5
 $ 5.40
 200.9
 $ 5.57

 Average dilutive effect of:

 Stock options
 0.3
 ( 0.01)
 0.4
 ( 0.01)
 0.4
 ( 0.01)

 Other equity plans
 0.5
 ( 0.03)
 0.5
 ( 0.02)
 0.6
 ( 0.02)

 Equity forwards
 —
 —
 0.1
 —
 —
 —

 Diluted shares and earnings per average common share
 212.4
 $ 11.10
 205.5
 $ 5.37
 201.9
 $ 5.54

 The calculation of diluted earnings per share excluded 1,179,962 options outstanding at December 31, 2023, 931,453 options outstanding at December 31, 2022, and 1,013,320 options outstanding at December 31, 2021 because they were antidilutive. In addition, as discussed further in Note 7 to the financial statements, at December 31, 2023, 1,762,709 shares under a forward sale agreement were not included in the calculation of diluted earnings per share because their effect would have been antidilutive, and at December 31, 2021, 1,158,917 shares under then-outstanding forward sale agreements were not included in the calculation of diluted earnings per share because their effect would have been antidilutive.

 Stock-based Compensation Plans

 Entergy grants stock options, restricted stock, performance units, and restricted stock unit awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans, which are shareholder-approved stock-based compensation plans. These plans are described more fully in Note 12 to the financial statements. The cost of the stock-based compensation is charged to income over the vesting period. Awards under Entergy's plans generally vest over three years. Entergy accounts for forfeitures of stock-based compensation when they occur. Entergy recognizes all income tax effects related to share-based payments through the income statement.

 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.

 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 or (2) billings in advance of expenditures for approved regulatory programs. To the extent that all or portions of the Utility operating companies or System Energy's operations cease to be subject to 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, 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 2 and 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 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.

 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 deferred credits for the unrealized trust earnings not currently expected to be needed to decommission the plant. Decommissioning trust funds for the nuclear plants previously owned by Entergy's non-utility operations, all of which have been sold as of June 2022, did not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains/(losses) recorded on the equity securities in the trust funds for these plants were recognized in earnings with no offsetting regulatory liability/asset amount. Unrealized gains/(losses) recorded on the available-for-sale debt securities in the trust funds were recognized in the accumulated other comprehensive income component of shareholders' equity. 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.

 Derivative Financial Instruments and Commodity Derivatives

 The accounting standards for derivative instruments and hedging activities 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 or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction. 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.

 For other contracts for commodities in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified to earnings in the periods when the underlying transactions actually occur. Changes in the fair value of derivative instruments that are not designated as cash flow hedges are recorded in current-period earnings on a mark-to-market basis.

 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.

 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.

 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 November 2023 the FASB issued ASU 2023-07, "Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures." The ASU is intended to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. In addition, the ASU requires enhanced interim disclosures, provides new segment disclosure requirements for entities with a single reportable segment, and contains other new disclosure requirements. ASU 2023-07 is effective for Entergy for fiscal years beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024. Entergy does not expect ASU 2023-07 to materially affect its results of operations, financial positions, or cash flows.

 In December 2023 the FASB issued ASU 2023-09, "Income Taxes (Topic 740): Improvements to Income Tax Disclosures." The ASU is intended to enhance the transparency and decision usefulness of income tax disclosures. The amendments in the ASU require enhanced income tax disclosures, primarily related to consistent categorization and disaggregation of information in the rate reconciliation and income taxes paid disaggregated by jurisdiction. The ASU also removes certain disclosures that are no longer considered cost beneficial or relevant. ASU 2023-09 is effective for Entergy for fiscal years beginning after December 15, 2024. Entergy does not expect ASU 2023-09 to materially affect its results of operations, financial positions, or cash flows.

 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 or (2) billings in advance of expenditures for approved regulatory programs. 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, 2023 and 2022:

 Other Regulatory Assets

 2023
 2022

 Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)

 $ 1,655.5
 $ 1,968.5

 Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants (Note 9) (a)

 1,285.0
 1,103.2

 1,010.7
 1,058.9

 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)

 536.9
 841.3

 Qualified Pension Settlement Cost Deferral - recovered through October 2034 (Note 11 - Qualified Pension Settlement Cost)

 250.9
 194.7

 Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined by retail regulators

 248.6
 160.0

 Retired electric and gas meters - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings)

 153.8
 166.8

 Opportunity Sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)

 131.8
 131.8

 Deferred COVID-19 costs - recovered through retail rates as determined by retail regulators (Note 2 - Retail Rate Proceedings) (b)

 118.0
 120.9

 63.1
 68.4

 Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)

 32.7
 30.6

 Rate case depreciation relate back deferral - will be recovered over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)

 27.6
 —

 Attorney General litigation costs - recovered over a six-year period through March 2026 (b)

 10.9
 15.7

 Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings)

 —
 18.2

 Other
 143.9
 157.4

 Entergy Total
 $ 5,669.4
 $ 6,036.4

 2023
 2022

 Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants (Note 9) (a)

 $ 639.1
 $ 562.7

 Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)

 536.6
 597.6

 319.7
 267.1

 Opportunity sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b)

 131.8
 131.8

 Qualified Pension Settlement Cost Deferral - recovered through October 2034 (Note 11 - Qualified Pension Settlement Cost)

 84.1
 67.1

 Deferred COVID-19 costs - recovered over a 10-year period through December 2033

 39.0
 39.0

 Retired electric meters - recovered over 15-year period through March 2034

 36.3
 39.8

 Storm damage costs - recovered through retail rates

 33.1
 35.9

 Retail rate deferrals - recovered through rate riders as rates are redetermined annually (b)

 24.9
 26.4

 19.9
 21.4

 ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (b)

 3.8
 5.6

 Other
 17.1
 15.9

 Entergy Arkansas Total
 $ 1,885.4
 $ 1,810.3

 2023
 2022

 Pension & postretirement costs (Note 11 - Qualified Pension Plans and Non-Qualified Pension Plans) (a)

 $ 412.0
 $ 481.7

 Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or shutdown of non-nuclear power plants (Note 9) (a)

 408.7
 346.3

 262.3
 418.8

 Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)

 202.6
 472.8

 Qualified Pension Settlement Cost Deferral - recovered through October 2034 (Note 11 - Qualified Pension Settlement Cost)

 123.0
 93.9

 Retired electric and gas meters - recovered over a 22-year period through July 2041

 83.2
 88.0

 Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (a)

 47.8
 47.8

 23.4
 25.1

 Other
 85.9
 81.8

 Entergy Louisiana Total
 $ 1,648.9
 $ 2,056.2

 2023
 2022

 Retail rate deferrals - recovered through formula rates or rate riders as rates are redetermined annually

 $ 192.8
 $ 111.1

 Removal Costs (Note 9)

 188.0
 159.4

 Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)

 127.6
 148.8

 Qualified Pension Settlement Cost Deferral - recovered through October 2034 (Note 11 - Qualified Pension Settlement Cost)

 32.0
 24.3

 Attorney General litigation costs - recovered over a six-year period through March 2026 (b)

 10.9
 15.7

 10.0
 10.9

 Asset retirement obligation - recovery dependent upon timing of shutdown of non-nuclear power plants (Note 9) (a)

 6.8
 6.3

 Formula rate plan historical year rate adjustment (Note 2 - Retail Rate Proceedings)

 —
 18.2

 Other
 11.0
 24.8

 Entergy Mississippi Total
 $ 579.1
 $ 519.5

 2023
 2022

 $ 61.1
 $ 56.3

 Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)

 41.4
 51.4

 Retired electric and gas meters - recovered over a 12-year period through July 2031 (b)

 15.5
 17.6

 Deferred COVID-19 costs - recovered over a five-year period through August 2028 (Note 2 - Retail Rate Proceedings) (b)

 13.0
 13.9

 Qualified Pension Settlement Cost Deferral - recovered through October 2034 (Note 11 - Qualified Pension Settlement Cost)

 11.8
 9.4

 Gas cross-boring costs - recovered through formula rates as rates are redetermined by retail regulators

 10.9
 9.9

 Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy New Orleans Securitization Bonds - Hurricane Isaac)

 3.9
 17.2

 0.8
 1.2

 Other
 24.0
 25.2

 Entergy New Orleans Total
 $ 182.4
 $ 202.1

 2023
 2022

 Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy Texas Securitization Bonds - Hurricane Ike and Gustav and Entergy Texas Securitization Bonds - Hurricane Laura, Hurricane Delta, and Winter Storm Uri)

 $ 297.3
 $ 315.4

 Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)

 85.6
 100.5

 77.5
 62.9

 Pension & postretirement benefits expense deferral - recovered through retail rates (Note 2 - Retail Rate Proceedings and Note 11 - Entergy Texas Reserve)

 32.7
 30.6

 Rate case depreciation relate back deferral - will be recovered over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)

 27.6
 —

 Advanced metering system (AMS) surcharge for residential customers - recovered through December 2029

 20.2
 —

 Retired electric meters - recovered through retail rates (Note 2 - Retail Rate Proceedings)

 18.8
 21.4

 Neches and Sabine costs - recovered over a 10-year period through September 2028

 11.6
 14.0

 Deferred COVID-19 costs - recovered through retail rates (Note 2 - Retail Rate Proceedings) (b)

 8.4
 10.4

 8.3
 9.1

 Other
 8.6
 14.4

 Entergy Texas Total
 $ 596.6
 $ 578.7

 2023
 2022

 Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear unit (Note 9) (b)

 $ 222.0
 $ 186.1

 Pension & postretirement costs (Note 11 - Qualified Pension Plans and Other Postretirement Benefits) (a)

 121.6
 133.9

 Removal costs - recovered through depreciation rates (Note 9)

 102.1
 94.4

 0.7
 0.7

 System Energy Total
 $ 446.4
 $ 415.1

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

 Other Regulatory Liabilities

 2023
 2022

 Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)

 $ 1,826.2
 $ 1,237.9

 Securitization financing savings obligation (Note 3)

 405.2
 327.7

 Complaints against System Energy - potential future refunds (Note 2) (b)

 177.9
 249.8

 Retail rate over-recovery - refunded through formula rate or rate riders as rates are redetermined by retail regulators

 138.0
 180.2

 Credits expected to be shared with customers from resolution of the 2016-2018 IRS audit (Note 3)

 98.0
 —

 Refund from System Energy settlement with the APSC - return to customers to be determined (Note 2)

 93.0
 —

 Vidalia purchased power agreement (Note 8)

 82.5
 95.4

 Deferred tax equity partnership earnings (Note 1)

 57.9
 43.8

 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

 Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)

 44.3
 43.5

 Other
 149.5
 101.9

 Entergy Total
 $ 3,116.9
 $ 2,324.6

 2023
 2022

 Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)

 $ 621.6
 $ 428.2

 Refund from System Energy settlement with the APSC - return to customers to be determined (Note 2)

 93.0
 —

 Deferred tax equity partnership earnings (Note 1)

 27.4
 22.4

 Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually

 10.6
 3.9

 Internal restructuring guaranteed customer credits - returned to customers over a six-year period through December 2024

 6.6
 13.2

 Other
 —
 8.1

 Entergy Arkansas Total
 $ 759.2
 $ 475.8

 2023
 2022

 Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)

 $ 644.0
 $ 438.9

 Securitization financing savings obligation (Note 3)

 405.2
 327.7

 Retail rate rider over-recovery - refunded through rate riders as rates are determined annually

 86.4
 87.7

 Vidalia purchased power agreement (Note 8)

 82.5
 95.4

 Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)

 44.3
 43.5

 Credits expected to be shared with customers from resolution of the 2016-2018 IRS audit (Note 3)

 38.0
 —

 Shorter-term financing interest earnings (Note 2 - Retail Rate Proceedings) (a)

 36.8
 —

 Hurricane Ida insurance proceeds - refunded through rate rider as rates are determined periodically

 32.3
 —

 Sale-leaseback and depreciation refunds - returned to customers September 2023 through August 2024

 14.1
 —

 Other
 24.1
 44.8

 Entergy Louisiana Total
 $ 1,407.7
 $ 1,038.0

 2023
 2022

 Deferred tax equity partnership earnings (Note 1)

 $ 30.5
 $ 21.4

 Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually

 2.4
 58.2

 Other
 0.8
 0.3

 Entergy Mississippi Total
 $ 33.7
 $ 79.9

 2023
 2022

 Credits expected to be shared with customers from resolution of the 2016-2018 IRS audit (Note 3)

 $ 60.0
 $ —

 Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually

 20.1
 19.5

 Sale-leaseback and depreciation refunds - returned to customers over a 10-year period beginning September 2023 (Note 2)

 9.8
 —

 Other
 0.5
 1.2

 Entergy New Orleans Total
 $ 90.4
 $ 20.7

 2023
 2022

 Retail rate rider over-recovery - return to customers to be determined

 $ 23.8
 $ 10.9

 Rate case settlement relate back - will be amortized over a six-month period beginning January 2024 (Note 2 - Retail Rate Proceedings)

 10.3
 —

 Retail refunds - return to customers to be determined

 6.2
 25.5

 Securitization over-recovery - return to customers to be determined (Note 2 - Storm Cost Recovery Filings with Retail Regulators and Note 5 - Entergy Texas Securitization Bonds - Hurricane Rita and Entergy Texas Securitization Bonds - Hurricane Ike and Hurricane Gustav)

 0.3
 8.8

 Other
 2.4
 —

 Entergy Texas Total
 $ 43.0
 $ 45.2

 2023
 2022

 Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)

 $ 560.6
 $ 370.8

 Complaints against System Energy - potential future refunds (Note 2) (b)

 177.9
 249.8

 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
 $ 782.9
 $ 665.0

 (a)Offset by related asset.
 (b)As discussed in "Complaints Against System Energy" below, there was an additional $ 103.5 million classified as a current regulatory liability as of December 31, 2022.

 Regulatory activity regarding the Tax Cuts and Jobs Act

 See the "Other Tax Matters - Tax Cuts and Jobs Act" section in Note 3 to the financial statements for discussion of the effects of the December 2017 enactment of the Tax Cuts and Jobs Act (Tax Act), including its effects on Entergy's and the Registrant Subsidiaries' regulatory asset/liability for income taxes.

 Consistent with its previously stated intent to return unprotected excess accumulated deferred income taxes to customers as expeditiously as possible, Entergy Arkansas initiated a tariff proceeding in February 2018 proposing to establish a tax adjustment rider to provide retail customers with certain tax benefits of $ 467 million associated with the Tax Act. For the residential customer class, unprotected excess accumulated deferred income taxes were returned to customers over a 21-month period from April 2018 through December 2019. For all other customer classes, unprotected excess accumulated deferred income taxes were returned to customers over a nine-month period from April 2018 through December 2018. A true-up provision also was included in the rider, with any over- or under-returned unprotected excess accumulated deferred income taxes credited or billed to customers during the billing month of January 2020, with any residual amounts of over- or under-returned unprotected excess accumulated deferred income taxes to be flowed through Entergy Arkansas's energy cost recovery rider. In March 2018 the APSC approved the tax adjustment rider effective with the first billing cycle of April 2018.

 In July 2018, Entergy Arkansas made its formula rate plan filing to set its formula rate for the 2019 calendar year. A hearing was held in May 2018 regarding the APSC's inquiries into the effects of the Tax Act, including Entergy Arkansas's proposal to utilize its formula rate plan rider for its customers to realize the remaining benefits

 of the Tax Act. Entergy Arkansas's formula rate plan rider included a netting adjustment that compared actual annual results to the allowed rate of return on common equity. In July 2018 the APSC issued an order agreeing with Entergy Arkansas's proposal to have the effects of the Tax Act on current income tax expense flow through Entergy Arkansas's formula rate plan rider and with Entergy Arkansas's treatment of protected and unprotected excess accumulated deferred income taxes. The APSC also directed Entergy Arkansas to submit in the tax adjustment rider proceeding, discussed above, the adjustments to all other riders affected by the Tax Act and to include an amendment for a true up mechanism where a rider affected by the Tax Act does not already contain a true-up mechanism. Pursuant to a 2018 settlement agreement in Entergy Arkansas's formula rate plan proceeding, Entergy Arkansas also removed the net operating loss accumulated deferred income tax asset caused by the Tax Act from Entergy Arkansas's tax adjustment rider. Entergy Arkansas's compliance tariff filings were accepted by the APSC in October 2018. In February 2021, pursuant to its 2020 formula rate plan evaluation report settlement, Entergy Arkansas flowed $ 5.6 million in credits to customers through the tax adjustment rider based on the outcome of certain federal tax positions and a decrease in the state tax rate. In the October 2023 settlement agreement filed in the 2023 formula rate plan proceeding, discussed below in "Retail Rate Proceedings - Filings with the APSC (Entergy Arkansas) - Retail Rates - 2023 Formula Rate Plan Filing", Entergy Arkansas included 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. The settlement was approved by the APSC in December 2023. 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 an electric formula rate plan settlement approved by the LPSC in April 2018, the parties agreed that Entergy Louisiana would return to customers one-half of its eligible unprotected excess deferred income taxes from May 2018 through December 2018 and return to customers the other half from January 2019 through August 2022. In addition, the settlement provided that in order to flow back to customers certain other tax benefits created by the Tax Act, Entergy Louisiana established a regulatory liability effective January 1, 2018 in the amount of $ 9.1 million per month to reflect these tax benefits already included in retail rates until new base rates under the formula rate plan were established in September 2018, and this regulatory liability was returned to customers over the September 2018 through August 2019 formula rate plan rate-effective period. The LPSC staff and intervenors in the settlement reserved the right to obtain data from Entergy Louisiana to confirm the determination of excess accumulated deferred income taxes resulting from the Tax Act and the analysis thereof as part of the formula rate plan review proceeding for the 2017 test year filing. As discussed below in "Retail Rate Proceedings - Filings with the LPSC (Entergy Louisiana) - Retail Rates - Electric - Formula Rate Plan Global Settlement", a global settlement resolving the outstanding issues related to the 2017 formula rate plan filing was reached in October 2023 and approved by the LPSC in November 2023.

 After enactment of the Tax Act the City Council passed a resolution ordering Entergy New Orleans to, effective January 1, 2018, record deferred regulatory liabilities to account for the Tax Act's effect on Entergy New Orleans's revenue requirement and to make a filing by mid-March 2018 regarding the Tax Act's effects on Entergy New Orleans's operating income and rate base and potential mechanisms for customers to receive benefits of the Tax Act. The City Council's resolution also directed Entergy New Orleans to request that Entergy Services file with the FERC for revisions of the Unit Power Sales Agreement and MSS-4 replacement tariffs to address the return of excess accumulated deferred income taxes. Entergy submitted filings of this type to the FERC.

 In March 2018, Entergy New Orleans filed its response to the resolution stating that the Tax Act reduced income tax expense from what was then reflected in rates by approximately $ 8.2 million annually for electric operations and by approximately $ 1.3 million annually for gas operations. In the filing, Entergy New Orleans proposed to return to customers from June 2018 through August 2019 the benefits of the reduction in income tax

 expense and its unprotected excess accumulated deferred income taxes through a combination of bill credits and investments in energy efficiency programs, grid modernization, and Smart City projects. Entergy New Orleans submitted supplemental information in April 2018 and May 2018. Shortly thereafter, Entergy New Orleans and the City Council's advisors reached an agreement in principle that provides for benefits that will be realized by Entergy New Orleans customers through bill credits that started in July 2018 and offsets to future investments in energy efficiency programs, grid modernization, and Smart City projects, as well as additional benefits related to the filings made at the FERC. The agreement in principle was approved by the City Council in June 2018. In April 2023, Entergy New Orleans completed the bill credits necessary to comply with the 2018 agreement in principle.

 After enactment of the Tax Act the PUCT issued an order requiring most utilities, including Entergy Texas, beginning January 25, 2018, to record a regulatory liability for the difference between revenues collected under existing rates and revenues that would have been collected had existing rates been set using the new federal income tax rates and also for the balance of excess accumulated deferred income taxes. Entergy Texas had previously provided information to the PUCT staff and stated that it expected the PUCT to address the lower tax expense as part of Entergy Texas's rate case expected to be filed in May 2018.

 In May 2018, Entergy Texas filed its 2018 base rate case with the PUCT. Entergy Texas's proposed rates and revenues reflected the inclusion of the federal income tax reductions due to the Tax Act. The PUCT issued an order in December 2018 establishing that (1) $ 25 million be credited to customers through a rider to reflect the lower federal income tax rate applicable to Entergy Texas from January 2018 through the date new rates were implemented; (2) $ 242.5 million of protected excess accumulated deferred income taxes be returned to customers through base rates under the average rate assumption method over the lives of the associated assets; and (3) $ 185.2 million of unprotected excess accumulated deferred income taxes be returned to customers through a rider. The unprotected excess accumulated deferred income taxes rider included carrying charges and was in effect over a period of 12 months for larger customers and over a period of four years for other customers.

 In a filing made with the FERC in March 2018, System Energy proposed revisions to the Unit Power Sales Agreement to reflect the effects of the Tax Act. In the filing System Energy proposed to return identified quantities of unprotected excess accumulated deferred income taxes to its customers by the end of 2018. In May 2018 the FERC accepted System Energy's proposed tax revisions with an effective date of June 1, 2018, subject to refund and the outcome of settlement and hearing procedures. Settlement discussions were terminated in April 2019, and a hearing was held in March 2020. The retail regulators of the Utility operating companies that are parties to the Unit Power Sales Agreement challenged the treatment and amount of excess accumulated deferred income tax liabilities associated with uncertain tax positions related to nuclear decommissioning. In July 2020 the presiding ALJ in the proceeding issued an initial decision finding that there is an additional $ 147 million in unprotected excess accumulated deferred income taxes related to System Energy's uncertain decommissioning tax deduction. The initial decision determined that System Energy should have included the $ 147 million in its March 2018 filing. System Energy had not included credits related to the effect of the Tax Act on the uncertain decommissioning tax position because it was uncertain whether the IRS would allow the deduction. The initial decision rejected both System Energy's alternative argument that any crediting should occur over a ten-year period and the retail regulators' argument that any crediting should occur over a two-year period. Instead, the initial decision concluded that System Energy should credit the additional unprotected excess accumulated deferred income taxes in a single lump sum revenue requirement reduction following a FERC order addressing the initial decision.

 In September 2020, System Energy filed a brief on exceptions with the FERC, re-urging its positions and requesting the reversal of the ALJ's initial decision. In December 2020, the LPSC, APSC, MPSC, City Council, and FERC trial staff filed briefs opposing exceptions.

 As discussed below in "Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue," in September 2020 the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. In September 2020, System Energy filed a motion to lodge the NOPA into the record in the FERC proceeding. In October 2020 the LPSC, APSC, MPSC, City Council, and FERC trial staff filed oppositions to System Energy's motion. As a result of the NOPA, System Energy filed, in October 2020, a new Federal Power Act section 205 filing at the FERC to credit the excess accumulated deferred income taxes resulting from the decommissioning uncertain tax position. System Energy proposed to credit the entire amount of the excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position by issuing a one-time credit of $ 17.8 million. In November 2020, the LPSC, APSC, MPSC, and City Council filed a protest to the filing, and System Energy responded.

 In November 2020 the IRS issued the Revenue Agent's Report (RAR) for the 2014-2015 tax years and in December 2020 Entergy executed it. In December 2020, System Energy filed a motion to lodge the RAR into the record in the FERC proceeding addressing the Tax Act. In January 2021 the LPSC, APSC, MPSC, and City Council filed a joint answer opposing System Energy's motion, and the FERC trial staff also filed an answer opposing System Energy's motion.

 As a result of the RAR, in December 2020, System Energy also filed an amendment to its Federal Power Act section 205 filing to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. The amendment proposed the inclusion of the RAR as support for the filing. In December 2020 the LPSC, APSC, and City Council filed a protest in response to the amendment, reiterating objections to the filing to credit excess accumulated deferred income taxes arising from the successful portion of the decommissioning uncertain tax position. 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.

 In November 2020, System Energy filed a motion to vacate the ALJ's decision, arguing that it had been overtaken by changed circumstances because of the IRS's determination resulting from the NOPA and RAR. In January 2021 the LPSC, APSC, MPSC, and City Council filed a joint answer opposing System Energy's motion, and the FERC trial staff also filed an answer opposing System Energy's motion. Additional responsive pleadings were filed in February and March 2021.

 In December 2022 the FERC issued an order addressing the ALJ's initial decision and denying System Energy's motion to vacate the initial decision. The FERC disagreed with the ALJ's determination that $ 147 million should be credited to customers in the same manner as the excess accumulated deferred income taxes addressed in System Energy's March 2018 filing, which had included a stated amount of excess accumulated deferred income taxes to be returned pursuant to a specified methodology and had not included any excess accumulated deferred income taxes associated with the decommissioning tax position. Instead, the FERC ordered System Energy to compute the amount of excess accumulated deferred income taxes associated with the decommissioning tax position with consideration for the resolution of the tax position by the IRS. System Energy had previously issued a one-time credit for the excess accumulated deferred income taxes associated with the decommissioning tax position, and System Energy believes no further refunds are required under the methodology provided in the order. The FERC further ordered System Energy to submit a compliance filing within 60 days addressing the justness and reasonableness of the Unit Power Sales Agreement, with respect to its provisions for excess accumulated deferred income taxes. In February 2023, System Energy filed the compliance filing with the FERC, which provided the calculation of the excess accumulated deferred income taxes associated with the decommissioning tax position with consideration for the resolution of the tax position by the IRS. System Energy confirmed that this amount of excess accumulated deferred income taxes had already been credited to customers, and therefore concluded that no further modifications to the Unit Power Sales Agreement are needed to address excess accumulated deferred income taxes associated with the Tax Act.

 In June 2023 the FERC issued a deficiency letter requesting additional information about the IRS's resolution of the tax position for 2016 and 2017. In July 2023, System Energy provided the additional information.

 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 deferred fuel costs as of December 31, 2023 and 2022 that each Utility operating company expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

 2023
 2022

 Entergy Arkansas (a)
 ($ 88.3)
 $ 208.6

 Entergy Louisiana (b)
 $ 192.9
 $ 327.3

 ($ 130.6)
 $ 143.2

 Entergy New Orleans (b)
 $ 10.2
 $ 14.2

 $ 139.0
 $ 258.1

 (a)Includes $ 68.9 million in 2022 of fuel and purchased power costs whose recovery period was indeterminate but was expected to be recovered over a period greater than twelve months. In 2023, Entergy Arkansas recorded a write-off of its regulatory asset for deferred fuel of $ 68.9 million as a result of Entergy Arkansas's approved motion to forgo recovery of identified costs resulting from the 2013 ANO stator incident. See Note 8 to the financial statements for further discussion of the 2013 ANO stator incident.
 (b)Includes $ 168.1 million in both years for Entergy Louisiana and $ 4.1 million in both years for Entergy New Orleans of 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.

 Energy Cost Recovery Rider

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

 In January 2014, Entergy Arkansas filed a motion with the APSC relating to its upcoming energy cost rate redetermination filing that was made in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude from the redetermination of its 2014 energy cost rate $ 65.9 million of incremental fuel and replacement energy costs incurred in 2013 as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information was available regarding various claims associated with the ANO stator incident. In February 2014 the APSC approved Entergy Arkansas's request to retain that amount in its deferred fuel balance. In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that proceeding, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a regulatory proceeding for the purpose of

 recovering funds currently withheld from rates and related to the stator incident, including the $ 65.9 million of deferred fuel and purchased energy costs and costs related to the incremental oversight previously noted, subject to certain timelines and conditions set forth in the settlement agreement. In October 2023, Entergy Arkansas made a commitment to the APSC to make a filing to forgo its opportunity to seek recovery of the incremental fuel and purchased energy expense, among other identified costs, resulting from the ANO stator incident. As a result, in third quarter 2023, Entergy Arkansas recorded a write-off of its regulatory asset for deferred fuel of $ 68.9 million, which includes interest, related to the ANO stator incident. Consistent with its October 2023 commitment, Entergy Arkansas filed a motion to forgo recovery in November 2023, and the motion was approved by the APSC in December 2023. See the "ANO Damage, Outage, and NRC Reviews" section in Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.

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

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

 In March 2021, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $ 0.01052 per kWh to $ 0.00959 per kWh. The redetermined rate calculation also included an adjustment to account for a portion of the increased fuel costs resulting from the February 2021 winter storms. The redetermined rate became effective with the first billing cycle in April 2021 through the normal operation of the tariff.

 In March 2022, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase from $ 0.00959 per kWh to $ 0.01785 per kWh. The primary reason for the rate increase was a large under-recovered balance as a result of higher natural gas prices in 2021, particularly in the fourth quarter 2021. At the request of the APSC general staff, Entergy Arkansas deferred its

 request for recovery of $ 32 million from the under-recovery related to the February 2021 winter storms until the 2023 energy cost rate redetermination, unless a request for an interim adjustment to the energy cost recovery rider is necessary. This resulted in a redetermined rate of $ 0.016390 per kWh, which became effective with the first billing cycle in April 2022 through the normal operation of the tariff. In February 2023 the APSC issued orders initiating proceedings with the utilities under its jurisdiction to address the prudence of costs incurred and appropriate cost allocation of the February 2021 winter storms. With respect to any prudence review of Entergy Arkansas fuel costs, as part of the APSC's draft report issued in its February 2021 winter storms investigation docket, the APSC included findings that the load shedding plans of the investor-owned utilities and some cooperatives were appropriate and comprehensive, and, further, that Entergy Arkansas's emergency plan was comprehensive and had a multilayered approach supported by a system-wide response plan, which is considered an industry standard. In September 2023 the APSC issued an order in Entergy Arkansas's company-specific proceeding and found that Entergy Arkansas's practices during the winter storms were prudent.

 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 from $ 0.01639 per kWh to $ 0.01883 per kWh. The primary reason for the rate increase is a large under-recovered balance as a result of higher natural gas prices in 2022 and a $ 32 million deferral related to the February 2021 winter storms consistent with the APSC general staff's request in 2022. The under-recovered balance included in the 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.

 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 include estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.

 In February 2021, Entergy Louisiana incurred extraordinary fuel costs associated with the February 2021 winter storms. To mitigate the effect of these costs on customer bills, in March 2021, Entergy Louisiana requested and the LPSC approved the deferral and recovery of $ 166 million in incremental fuel costs over five months beginning in April 2021. The incremental fuel costs remain subject to review for reasonableness and eligibility for recovery through the fuel adjustment clause mechanism. The final amount of incremental fuel costs is subject to change through the resettlement process. At its April 2021 meeting, the LPSC authorized its staff to review the prudence of the February 2021 fuel costs incurred by all LPSC-jurisdictional utilities, including both gas and electric utilities. At its June 2021 meeting, the LPSC approved the hiring of consultants to assist its staff in this review. In May 2022 the LPSC staff issued an audit report regarding Entergy Louisiana's fuel adjustment clause charges (for its electric operations) recommending no financial disallowances, but including several prospective recommendations. Responsive testimony was filed by one intervenor and the parties agreed to suspend any procedural schedule and move toward settlement discussions to close the matter. Also in May 2022 the LPSC staff issued an audit report regarding Entergy Louisiana's purchased gas adjustment charges (for its gas operations) that did not propose any financial disallowances. The LPSC staff and Entergy Louisiana submitted a joint report on the audit report and draft order to the LPSC concluding that Entergy Louisiana's gas distribution operations and fuel costs were not significantly adversely affected by the February 2021 winter storms and the resulting increase in natural gas prices. The LPSC issued an order approving the joint report in October 2022.

 In March 2021 the LPSC staff provided notice of an audit of Entergy Louisiana's purchased gas adjustment clause filings covering the period January 2018 through December 2020. The audit included a review of the

 reasonableness of charges flowed through Entergy Louisiana's purchased gas adjustment clause for that period. In August 2023 the LPSC submitted its audit report and found that materially all costs recovered through the purchased gas adjustment filings were reasonable and eligible for recovery through the purchased gas adjustment clause. The LPSC approved the report in December 2023.

 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 is 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 purchased gas adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana's purchased gas adjustment clause for the period from 2021 through 2022. Discovery is ongoing, and no audit report has been filed.

 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.

 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.

 In November 2020, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an over-recovery of approximately $ 24.4 million as of September 30, 2020. In January 2021 the MPSC approved the proposed energy cost factor effective for February 2021 bills.

 In November 2021, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $ 80.6 million as of September 30, 2021. In December 2021, at the request of the MPSC, Entergy Mississippi submitted a proposal to mitigate the impact of rising fuel costs on customer bills during 2022. Entergy Mississippi proposed that the deferred fuel balance as of December 31, 2021, which was $ 121.9 million, be amortized over three years and that the MPSC authorize Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. In January 2022 the MPSC approved the amortization of $ 100 million of the deferred fuel balance over two years and authorized Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. The MPSC approved the proposed energy cost factor effective for February 2022 bills.

 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 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 at the end of January 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $ 47 million at the end of January 2024. In January 2024 the MPSC approved the proposed energy cost factor and the proposed power management cost factor effective for February 2024 bills.

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

 Entergy New Orleans's gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.

 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 to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation by the end of 2024.

 In May 2022, Entergy Texas filed an application with the PUCT to implement an interim fuel surcharge to collect the cumulative under-recovery of approximately $ 51.7 million, including interest, of fuel and purchased power costs incurred from May 1, 2020 through December 31, 2021. The under-recovery balance is primarily attributable to the impacts of Winter Storm Uri, including historically high natural gas prices, partially offset by settlements received by Entergy Texas from MISO related to Hurricane Laura. Entergy Texas proposed that the interim fuel surcharge be assessed over a period of six months beginning with the first billing cycle after the PUCT issues a final order, but no later than the first billing cycle of September 2022. Also in May 2022, the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2022, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding. In addition, Entergy Texas filed on behalf of the parties a motion to admit evidence, to approve interim rates as requested in the initial application, and to remand the proceeding to the PUCT to consider the unopposed settlement. In August 2022 the ALJ with the State Office of Administrative Hearings issued an order granting Entergy Texas's motion, approving interim rates effective with the first billing cycle of September 2022, and remanding the case to the PUCT for final approval. The interim fuel surcharge was approved by the PUCT in January 2023.

 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 May 2023, Entergy Texas filed, and the ALJ with the State Office of Administrative Hearings granted, a joint motion to abate the proceeding to give parties additional time to finalize a settlement. 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.

 Retail Rate Proceedings

 Filings with the APSC (Entergy Arkansas)

 2020 Formula Rate Plan Filing

 In July 2020, Entergy Arkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas's earnings for the projected year 2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The filing showed that Entergy Arkansas's earned rate of return on common equity for the 2021 projected year was 8.22 % resulting in a revenue deficiency of $ 64.3 million. The earned rate of return on common equity for the 2019 historical year was 9.07 % resulting in a $ 23.9 million netting adjustment. The total proposed revenue change for the 2021 projected year and 2019 historical year netting adjustment was $ 88.2 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 $ 74.3 million. As part of the formula rate plan tariff the calculation for the revenue constraint was updated based on actual revenues which had the effect of reducing the initially-proposed $ 74.3 million revenue requirement increase to $ 72.6 million. In October 2020, Entergy Arkansas filed with the APSC a unanimous settlement agreement reached with the other parties that resolved all but one issue. As a result of the settlement agreement, Entergy Arkansas's requested revenue increase was $ 68.4 million, including a $ 44.5 million increase for the projected 2021 year and a $ 23.9 million netting adjustment. The remaining issue litigated concerned the methodology used to calculate the netting adjustment within the formula rate plan. In December 2020 the APSC issued an order rejecting the netting adjustment method used by Entergy Arkansas. Applying the approach ordered by the APSC changed the netting adjustment for the 2019 historical year from a $ 23.9 million deficiency to $ 43.5 million excess. Overall, the decision reduced Entergy Arkansas's revenue adjustment for 2021 to $ 1 million. In December 2020, Entergy Arkansas filed a petition for rehearing of the APSC's decision in the 2020 formula rate plan proceeding regarding the 2019 netting adjustment, and in January 2021 the APSC granted further consideration of Entergy Arkansas's petition. Based on the progress of the proceeding at that point, in December 2020, Entergy Arkansas recorded a regulatory liability of $ 43.5 million to reflect the netting adjustment for 2019, as included in the APSC's December 2020 order, which would be returned to customers in 2021. Entergy Arkansas also requested an extension of the formula rate plan rider for a second five-year term. In March 2021 the Arkansas Governor signed HB1662 into law (Act 404). Act 404 clarified aspects of the original formula rate plan legislation enacted in 2015, including with respect to the extension of a formula rate plan, the methodology for the netting adjustment, and debt and equity levels; it also reaffirmed the customer protections of the original formula rate plan legislation, including the cap on annual formula rate plan rate changes. Pursuant to Act 404, Entergy Arkansas's formula rate plan rider was extended for a second five-year term. Entergy Arkansas filed a compliance tariff in its formula rate plan docket in April 2021 to effectuate the netting provisions of Act 404, which reflected a net change in required formula rate plan rider revenue of $ 39.8 million, effective with the first billing cycle of May 2021. In April 2021 the APSC issued an order approving the compliance tariff and recognizing the formula rate plan extension. Also in April 2021, Entergy Arkansas filed for approval of modifications to the formula rate plan tariff incorporating the provisions in Act 404, and the APSC approved the tariff modifications in April 2021. Given the APSC general staff's support for the expedited approval of these filings by the APSC, Entergy Arkansas supported an amendment to Act 404 to achieve a reduced return on equity from 9.75 % to 9.65 % to apply for years applicable to the extension term; that amendment was signed by the Arkansas Governor in April 2021 and is now Act 894. Based on the APSC's order issued in April 2021, in the first quarter 2021, Entergy Arkansas reversed the remaining regulatory liability for the netting adjustment for 2019. In June 2021, Entergy Arkansas filed another compliance tariff in its formula rate plan proceeding to effectuate the additional provisions of Act 894, and the APSC approved the second compliance tariff filing in July 2021.

 In July 2021, Entergy Arkansas filed with the APSC its 2021 formula rate plan filing to set its formula rate for the 2022 calendar year. The filing contained an evaluation of Entergy Arkansas's earnings for the projected year 2022 and a netting adjustment for the historical year 2020. The filing showed that Entergy Arkansas's earned rate of return on common equity for the 2022 projected year was 7.65 % resulting in a revenue deficiency of $ 89.2 million. The earned rate of return on common equity for the 2020 historical year was 7.92 % resulting in a $ 19.4 million netting adjustment. The total proposed revenue change for the 2022 projected year and 2020 historical year netting adjustment was $ 108.7 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 $ 72.4 million. In October 2021, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding. As a result of the settlement agreement, the total proposed revenue change was $ 82.2 million, including a $ 62.8 million increase for the projected 2022 year and a $ 19.4 million netting adjustment. Because Entergy Arkansas's revenue requirement exceeded the constraint, the resulting increase was limited to $ 72.1 million. In December 2021 the APSC approved the settlement as being in the public interest and approved Entergy Arkansas's compliance tariff effective with the first billing cycle of January 2022.

 In July 2022, Entergy Arkansas filed with the APSC its 2022 formula rate plan filing to set its formula rate for the 2023 calendar year. The filing contained an evaluation of Entergy Arkansas's earnings for the projected year 2023 and a netting adjustment for the historical year 2021. The filing showed that Entergy Arkansas's earned rate of return on common equity for the 2023 projected year was 7.40 % resulting in a revenue deficiency of $ 104.8 million. The earned rate of return on common equity for the 2021 historical year was 8.38 % resulting in a $ 15.2 million netting adjustment. The total proposed revenue change for the 2023 projected year and 2021 historical year netting adjustment was $ 119.9 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 $ 79.3 million. In October 2022 other parties filed their testimony recommending various adjustments to Entergy Arkansas's overall proposed revenue deficiency, and Entergy Arkansas filed a response including an update to actual revenues through August 2022, which raised the constraint to $ 79.8 million. In November 2022, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding. As a result of the settlement agreement, the total revenue change was $ 102.8 million, including a $ 87.7 million increase for the 2023 projected year and a $ 15.2 million netting adjustment. Because Entergy Arkansas's revenue requirement exceeded the constraint, the resulting increase was limited to $ 79.8 million. In December 2022 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 2023.

 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 is $ 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 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. Entergy Arkansas filed its rebuttal in October 2023. 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 cap 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.

 Filings with the LPSC (Entergy Louisiana)

 Retail Rates - Electric

 2017 Formula Rate Plan Filing

 In June 2018, Entergy Louisiana filed its formula rate plan evaluation report for its 2017 calendar year operations. The 2017 test year evaluation report produced an earned return on equity of 8.16 %, due in large part to revenue-neutral realignments to other recovery mechanisms. Without these realignments, the evaluation report produces an earned return on equity of 9.88 % and a resulting base rider formula rate plan revenue increase of $ 4.8 million. Excluding the Tax Cuts and Jobs Act credits provided for by the tax reform adjustment mechanisms, total formula rate plan revenues were further increased by a total of $ 98 million as a result of the evaluation report due to adjustments to the additional capacity and MISO cost recovery mechanisms of the formula rate plan, and implementation of the transmission recovery mechanism. In August 2018, Entergy Louisiana filed a supplemental formula rate plan evaluation report to reflect changes from the 2016 test year formula rate plan proceedings, a decrease to the transmission recovery mechanism to reflect lower actual capital additions, and a decrease to evaluation period expenses to reflect the terms of a new power sales agreement. Based on the August 2018 update, Entergy Louisiana recognized a total decrease in formula rate plan revenue of approximately $ 17.6 million. Results of the updated 2017 evaluation report filing were implemented with the September 2018 billing month subject to refund and review by the LPSC staff and intervenors. In accordance with the terms of the formula rate plan, in September 2018 the LPSC staff filed its report of objections/reservations and intervenors submitted their responses to Entergy Louisiana's original formula rate plan evaluation report and supplemental compliance updates. In August 2021 the LPSC staff issued a letter updating its objections/reservations for the 2017 test year formula rate plan evaluation report. In its letter, the LPSC staff reiterated its original objections/reservations. The LPSC staff further reserved its rights for future proceedings and to dispute future proposed adjustments to the 2017 test year formula rate plan evaluation report. The LPSC staff withdrew all other objections/reservations.

 In November 2023 the LPSC approved 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. See "Formula Rate Plan Global Settlement" below for further discussion of the settlement.

 2018 Formula Rate Plan Filing

 In May 2019, Entergy Louisiana filed its formula rate plan evaluation report for its 2018 calendar year operations. The 2018 test year evaluation report produced an earned return on common equity of 10.61 % leading to a base rider formula rate plan revenue decrease of $ 8.9 million. While base rider formula rate plan revenue decreased as a result of this filing, overall formula rate plan revenues increased by approximately $ 118.7 million. This outcome was primarily driven by a reduction to the credits previously flowed through the tax reform adjustment mechanism and an increase in the transmission recovery mechanism, partially offset by reductions in the

 additional capacity mechanism revenue requirements and extraordinary cost items. The filing was subject to review by the LPSC. Resulting rates were implemented in September 2019, subject to refund.

 Several parties intervened in the proceeding and the LPSC staff filed its report of objections/reservations in accordance with the applicable provisions of the formula rate plan. In August 2021 the LPSC staff issued a letter updating its objections/reservations for the 2018 test year formula rate plan evaluation report. In its letter, the LPSC staff reiterated its original objection/reservation pertaining to test year expenses billed from Entergy Services to Entergy Louisiana and outstanding issues from the 2017 test year formula rate plan evaluation report. The LPSC staff withdrew all other objections/reservations.

 Commercial operation at Lake Charles Power Station commenced in March 2020. In March 2020, Entergy Louisiana filed an update to its 2018 formula rate plan evaluation report to include the estimated first-year revenue requirement of $ 108 million associated with the Lake Charles Power Station. The resulting interim adjustment to rates became effective with the first billing cycle of April 2020.

 In November 2023 the LPSC approved 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. See "Formula Rate Plan Global Settlement" below for further discussion of the settlement.

 2019 Formula Rate Plan Filing

 In May 2020, Entergy Louisiana filed with the LPSC its formula rate plan evaluation report for its 2019 calendar year operations. The 2019 test year evaluation report produced an earned return on common equity of 9.66 %. As such, no change to base rider formula rate plan revenue is required. Although base rider formula rate plan revenue did not change as a result of this filing, overall formula rate plan revenues increased by approximately $ 103 million. This outcome is driven by the removal of prior year credits associated with the sale of the Willow Glen Power Station and an increase in the transmission recovery mechanism. Also contributing to the overall change was an increase in legacy formula rate plan revenue requirements driven by legacy Entergy Louisiana capacity cost true-ups and higher annualized legacy Entergy Gulf States Louisiana revenues due to higher billing determinants, offset by reductions in MISO cost recovery mechanism and tax reform adjustment mechanism revenue requirements. In August 2020 the LPSC staff submitted a list of items for which it needs additional information to confirm the accuracy and compliance of the 2019 test year evaluation report. The LPSC staff objected to a proposed revenue neutral adjustment regarding a certain rider as being beyond the scope of permitted formula rate plan adjustments. Rates reflected in the May 2020 filing, with the exception of a revenue neutral rider adjustment, and as updated in an August 2020 filing, were implemented in September 2020, subject to refund. In August 2021 the LPSC staff issued a letter updating its objections/reservations for the 2019 test year formula rate plan filing. In its letter, the LPSC staff disputed Entergy Louisiana's exclusion of approximately $ 251 thousand of interest income allocated from Entergy Operations and Entergy Services to Entergy Louisiana to the extent that there are other adjustments that would move Entergy Louisiana out of the formula rate plan deadband. The LPSC staff reserved the right to further contest the issue in future proceedings. The LPSC staff further reserved outstanding issues from the 2017 and 2018 formula rate plan evaluation reports and withdrew all other remaining objections/reservations.

 In November 2023 the LPSC approved 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. See "Formula Rate Plan Global Settlement" below for further discussion of the settlement.

 Request for Extension and Modification of Formula Rate Plan

 In May 2020, Entergy Louisiana filed with the LPSC its application for authority to extend its formula rate plan. In its application, Entergy Louisiana sought to maintain a 9.8 % return on equity, with a bandwidth of 60 basis points above and below the midpoint, with a first-year midpoint reset. The parties reached a settlement in April 2021 regarding Entergy Louisiana's proposed formula rate plan extension. In May 2021 the LPSC approved the uncontested settlement. Key terms of the settlement include: a three year term (test years 2020, 2021, and 2022) covering a rate-effective period of September 2021 through August 2024; a 9.50 % return on equity, with a smaller, 50 basis point deadband above and below ( 9.0 %- 10.0 %); elimination of sharing if earnings are outside the deadband; a $ 63 million rate increase for test year 2020 (exclusive of riders); continuation of existing riders (transmission, additional capacity, etc.); addition of a distribution recovery mechanism permitting $ 225 million per year of distribution investment above a baseline level to be recovered dollar for dollar; modification of the tax mechanism to allow timely rate changes in the event the federal corporate income tax rate is changed from 21 %; a cumulative rate increase limit of $ 70 million (exclusive of riders) for test years 2021 and 2022; and deferral of up to $ 7 million per year in 2021 and 2022 of expenditures on vegetation management for outside of right of way hazard trees.

 2020 Formula Rate Plan Filing

 In June 2021, Entergy Louisiana filed its formula rate plan evaluation report for its 2020 calendar year operations. The 2020 test year evaluation report produced an earned return on common equity of 8.45 %, with a base formula rate plan revenue increase of $ 63 million. Certain reductions in formula rate plan revenue driven by lower sales volumes, reductions in capacity cost and net MISO cost, and higher credits resulting from the Tax Cuts and Jobs Act offset the base formula rate plan revenue increase, leading to a net increase in formula rate plan revenue of $ 50.7 million. The report also included multiple new adjustments to account for, among other things, the calculation of distribution recovery mechanism revenues. The effects of the changes to total formula rate plan revenue were different for each legacy company, primarily due to differences in the legacy companies' capacity cost changes, including the effect of true-ups. Legacy Entergy Louisiana formula rate plan revenues increased by $ 27 million and legacy Entergy Gulf States Louisiana formula rate plan revenues increased by $ 23.7 million. Subject to LPSC review, the resulting changes became effective for bills rendered during the first billing cycle of September 2021, subject to refund. Discovery commenced in the proceeding. In August 2021, Entergy Louisiana submitted an update to its evaluation report to account for various changes. Relative to the June 2021 filing, the total formula rate plan revenue increased by $ 14.2 million to an updated total of $ 64.9 million. Legacy Entergy Louisiana formula rate plan revenues increased by $ 32.8 million and legacy Entergy Gulf States Louisiana formula rate plan revenues increased by $ 32.1 million. The results of the 2020 test year evaluation report bandwidth calculation were unchanged as there was no change in the earned return on common equity of 8.45 %. In September 2021 the LPSC staff filed a letter with a general statement of objections/reservations because it had not completed its review and indicated it would update the letter once its review was complete. Should the parties be unable to resolve any objections, those issues will be set for hearing, with recovery of the associated costs subject to refund.

 In November 2023 the LPSC approved 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. See "Formula Rate Plan Global Settlement" below for further discussion of the settlement.

 In May 2022, Entergy Louisiana filed its formula rate plan evaluation report for its 2021 calendar year operations. The 2021 test year evaluation report produced an earned return on common equity of 8.33 %, with a base formula rate plan revenue increase of $ 65.3 million. Other increases in formula rate plan revenue driven by reductions in Tax Cut and Jobs Act credits and additions to transmission and distribution plant in service reflected through the transmission recovery mechanism and distribution recovery mechanism are partly offset by an increase

 in net MISO revenues, leading to a net increase in formula rate plan revenue of $ 152.9 million. The effects of the changes to total formula rate plan revenue are different for each legacy company, primarily due to differences in the legacy companies' capacity cost changes, including the effect of true-ups. Legacy Entergy Louisiana formula rate plan revenues increased by $ 86 million and legacy Entergy Gulf States Louisiana formula rate plan revenues increased by $ 66.9 million. In August 2022 the LPSC staff filed a list of objections/reservations, including outstanding issues from the test years 2017-2020 formula rate plan filings, utilizing the extraordinary cost mechanism to address one-time changes such as state tax rate changes, and failing to include an adjustment for revenues not received as a result of Hurricane Ida. Subject to LPSC review, the resulting changes to formula rate plan revenues became effective for bills rendered during the first billing cycle of September 2022, subject to refund.

 In November 2023 the LPSC approved 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. See "Formula Rate Plan Global Settlement" below for further discussion of the settlement.

 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 are only being 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 are 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 is 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, is $ 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.

 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 contains a dual-path request to update rates through either: (1) extension of Entergy Louisiana's current formula rate plan (with certain modifications) for three years (the Rate Mitigation Proposal), which is Entergy Louisiana's recommended path; or (2) implementation of rates resulting from a cost-of-service study (the Rate Case path). The application complies 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 supports the need to extend Entergy Louisiana's formula rate plan with credit supportive mechanisms to facilitate investment in the distribution, transmission, and generation functions.

 The Rate Case path proposes a 2024-2026 test year formula rate plan with an initial revenue requirement increase of $ 430 million, net of $ 17 million of one-time credits, and a return on common equity of 10.5 %. Depreciation rates would be updated for all asset classes. The Rate Mitigation Proposal proposes a 2023-2025 test year formula rate plan with an expected initial revenue requirement increase of $ 173 million, also net of $ 17 million

 of one-time credits, based on a 2023 formula rate plan test year, and a return on common equity of 10.0 %. Depreciation rates would be updated only for nuclear assets and would be phased in over three years.

 Under both paths, Entergy Louisiana's filing proposes removing the cap on amounts allowed to be recovered through the distribution recovery mechanism and continuing the distribution recovery mechanism performance accountability targets, which tie Entergy Louisiana's ability to fully recover its distribution recovery mechanism investments to its reliability performance. Entergy Louisiana's filing also includes new customer-centric programs specifically focused on affordability, including reducing late fees and certain other fees assessed to customers, lowering additional facilities charge rates, providing eligible low-income seniors with monthly discounts on their electric bill, and adding new voluntary customer options to support new transportation electrification technologies. A status conference was held in October 2023 at which a procedural schedule was adopted that includes three technical conferences, the last of which is in March 2024, and a hearing date in August 2024.

 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, associated with the Hurricane Isaac securitization, recognized in 2017 as a result of the Tax Cuts and Jobs Act. See Note 3 to the financial statements for further discussion of the reversal of the regulatory liability.

 Investigation of Costs Billed by Entergy Services

 In November 2018 the LPSC issued a notice of proceeding initiating an investigation into costs incurred by Entergy Services that are included in the retail rates of Entergy Louisiana. As stated in the notice of proceeding, the LPSC observed an increase in capital construction-related costs incurred by Entergy Services. Discovery was issued and included efforts to seek highly detailed information on a broad range of matters unrelated to the scope of the audit. There has been no further activity in the investigation since May 2019.

 COVID-19 Orders

 In April 2020 the LPSC issued an order authorizing utilities to record as a regulatory asset expenses incurred from the suspension of disconnections and collection of late fees imposed by LPSC orders associated with the COVID-19 pandemic. In addition, utilities may seek future recovery, subject to LPSC review and approval, of losses and expenses incurred due to compliance with the LPSC's COVID-19 orders. The suspension of late fees and disconnects for non-pay was extended until the first billing cycle after July 16, 2020. In January 2021, Entergy Louisiana resumed disconnections for customers in all customer classes with past-due balances that had not made payment arrangements. Utilities seeking to recover the regulatory asset must formally petition the LPSC to do so, identifying the direct and indirect costs for which recovery is sought. Any such request is subject to LPSC review and approval. In April 2023, Entergy Louisiana filed an application proposing to utilize approximately $ 1.6 billion in certain low interest debt to generate earnings to apply toward the reduction of the COVID-19 regulatory asset, as well as to conduct additional outside right-of-way vegetation management activities and fund the minor storm reserve account. In that filing, Entergy Louisiana proposed to delay repayment of certain shorter-term first mortgage bonds that were issued to finance storm restoration costs until the costs could be securitized, and to invest the funds that otherwise would be used to repay those bonds in the money pool to take advantage of the spread between prevailing interest rates on investments in the money pool and the interest rates on the bonds. The LPSC approved Entergy Louisiana's requested relief in June 2023. A subsequent filing will be required to permit the LPSC to review the COVID-19 regulatory asset. As of December 31, 2023, Entergy Louisiana had a regulatory

 asset of $ 47.8 million for costs associated with the COVID-19 pandemic and a regulatory liability of $ 36.8 million for the deferred earnings related to the approximately $ 1.6 billion in low interest debt.

 Filings with the MPSC (Entergy Mississippi)

 In March 2021, Entergy Mississippi submitted its formula rate plan 2021 test year filing and 2020 look-back filing showing Entergy Mississippi's earned return for the historical 2020 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2021 calendar year to be below the formula rate plan bandwidth. The 2021 test year filing showed a $ 95.4 million rate increase was necessary to reset Entergy Mississippi's earned return on common equity to the specified point of adjustment of 6.69 % return on rate base, within the formula rate plan bandwidth. The change in formula rate plan revenues, however, was capped at 4 % of retail revenues, which equated to a revenue change of $ 44.3 million. The 2021 evaluation report also included $ 3.9 million in demand side management costs for which the MPSC approved realignment of recovery from the energy efficiency rider to the formula rate plan. These costs were not subject to the 4 % cap and resulted in a total change in formula rate plan revenues of $ 48.2 million. The 2020 look-back filing compared actual 2020 results to the approved benchmark return on rate base and reflected the need for a $ 16.8 million interim increase in formula rate plan revenues. In addition, the 2020 look-back filing included an interim capacity adjustment true-up for the Choctaw Generating Station, which increased the look-back interim rate adjustment by $ 1.7 million. These interim rate adjustments totaled $ 18.5 million. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $ 22.1 million interim rate increase, reflecting a cap equal to 2 % of 2020 retail revenues, effective with the April 2021 billing cycle, subject to refund, pending a final MPSC order. The $ 3.9 million of demand side management costs and the Choctaw Generating Station true-up of $ 1.7 million, which were not subject to the 2 % cap of 2020 retail revenues, were included in the April 2021 rate adjustments.

 In June 2021, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2021 test year filing that resulted in a total rate increase of $ 48.2 million. Pursuant to the joint stipulation, Entergy Mississippi's 2020 look-back filing reflected an earned return on rate base of 6.12 % in calendar year 2020, which was below the look-back bandwidth, resulting in a $ 17.5 million increase in formula rate plan revenues on an interim basis through June 2022. This included $ 1.7 million related to the Choctaw Generating Station and $ 3.7 million of COVID-19 non-bad debt expenses. The joint stipulation also included Entergy Mississippi's quantification and methodology for calculating incremental COVID-19 bad debt expenses and provided for Entergy Mississippi to continue to defer these incremental COVID-19 bad debt expenses through December 2021. In June 2021 the MPSC approved the joint stipulation with rates effective for the first billing cycle of July 2021. In June 2021, Entergy Mississippi recorded regulatory credits of $ 19.9 million to reflect the effects of the joint stipulation.

 In March 2022, Entergy Mississippi submitted its formula rate plan 2022 test year filing and 2021 look-back filing showing Entergy Mississippi's earned return for the historical 2021 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2022 calendar year to be below the formula rate plan bandwidth. The 2022 test year filing showed a $ 69 million rate increase was necessary to reset Entergy Mississippi's earned return on common equity to the specified point of adjustment of 6.70 % return on rate base, within the formula rate plan bandwidth. The change in formula rate plan revenues, however, was capped at 4 % of retail revenues, which equated to a revenue change of $ 48.6 million. The 2021 look-back filing compared actual 2021 results to the approved benchmark return on rate base and reflected the need for a $ 34.5 million interim increase in formula rate plan revenues. In fourth quarter 2021, Entergy Mississippi recorded a regulatory asset of $ 19 million to reflect the then-current estimate in connection with the look-back feature of the formula rate plan. In

 accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $ 24.3 million interim rate increase, reflecting a cap equal to 2 % of 2021 retail revenues, effective in April 2022. With the implementation of the interim formula rate plan rates, Entergy Mississippi began recovery of the bad debt expense deferral resulting from the COVID-19 pandemic over a three-year period.

 In June 2022, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2022 test year filing that resulted in a total rate increase of $ 48.6 million. Pursuant to the joint stipulation, Entergy Mississippi's 2021 look-back filing reflected an earned return on rate base of 5.99 % in calendar year 2021, which was below the look-back bandwidth, resulting in a $ 34.3 million increase in the formula rate plan revenues on an interim basis through June 2023. In July 2022 the MPSC approved the joint stipulation with rates effective in August 2022. In July 2022, Entergy Mississippi recorded regulatory credits of $ 22.6 million to reflect the effects of the joint stipulation. In August 2022 an intervenor filed a statutorily-authorized direct appeal to the Mississippi Supreme Court seeking review of the MPSC's July 2022 order approving the joint stipulation confirming Entergy Mississippi's 2022 formula rate plan filing. Formula rate plan rates are not stayed or otherwise impacted while the appeal is pending.

 In July 2022 the MPSC directed Entergy Mississippi to flow $ 14.1 million of the power management rider over-recovery balance to customers beginning in August 2022 through December 2022 to mitigate the bill impact of the increase in formula rate plan revenues.

 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 and will resume in 2024. In June 2023 the MPSC approved the joint stipulation with rates effective in July 2023.

 Filings with the City Council (Entergy New Orleans)

 In July 2021, Entergy New Orleans submitted to the City Council its formula rate plan 2020 test year filing. The 2020 test year evaluation report produced an earned return on equity of 6.26 % compared to the authorized return on equity of 9.35 %. Entergy New Orleans sought approval of a $ 64 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula resulted in an increase in authorized electric revenues of $ 40 million and an increase in authorized gas revenues of $ 18.8 million. Entergy New Orleans also sought to commence collecting $ 5.2 million in electric revenues and $ 0.3 million in gas revenues that were previously approved by the City Council for collection through the formula rate plan. The filing was subject to review by the City Council and other parties over a 75-day review period, followed by a 25-day period to resolve any disputes among the parties. In October 2021 the City Council's advisors filed a 75-day report recommending a reduction of $ 10 million for electric revenues and a reduction of $ 4.5 million for gas revenues, along with one-time credits funded by certain electric regulatory liabilities currently held by Entergy New Orleans for customers. On October 26, 2021, Entergy New Orleans provided notice to the City Council that it intends to implement rates effective with the first billing cycle of November 2021, with such rates reflecting an amount agreed-upon by Entergy New Orleans including adjustments filed in the City Council's 75-day report, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $ 49.5 million, with an increase of $ 34.9 million in electric revenues and $ 14.6 million in gas revenues. Also, credits of $ 17.4 million funded by certain regulatory liabilities currently held by Entergy New Orleans for customers will be issued over a five-month period from November 2021 through March 2022. Resulting rates went into effect with the first billing cycle of November 2021 pursuant to the formula rate plan tariff.

 In April 2022, Entergy New Orleans submitted to the City Council its formula rate plan 2021 test year filing. The 2021 test year evaluation report, subsequently updated in a July 2022 filing, produced an earned return on equity of 6.88 % compared to the authorized return on equity of 9.35 %. Entergy New Orleans sought approval of a $ 42.1 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula resulted in an increase in authorized electric revenues of $ 34.1 million and an increase in authorized gas revenues of $ 3.3 million. Entergy New Orleans also sought to commence collecting $ 4.7 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2022 the City Council's advisors issued a report seeking a reduction to Entergy New Orleans's proposed increase of approximately $ 17.1 million in total for electric and gas revenues. Effective with the first billing cycle of September 2022, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council including adjustments filed in the City Council's advisors' report, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $ 24.7 million, which includes an increase of $ 18.2 million in electric revenues, $ 4.7 million in previously approved electric revenues, and an increase of $ 1.8 million in gas revenues. Additionally, credits of $ 13.9 million funded by certain regulatory liabilities currently held by Entergy New Orleans for customers were issued over an eight-month period beginning September 2022.

 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 provides 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 provides for a minor storm accrual of $ 0.5 million per year and the distribution of $ 8.9 million of currently 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 % fixed capital structure for rate setting purposes.

 Filings with the PUCT and Texas Cities (Entergy Texas)

 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 have been reset to zero 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 December 2022 the ALJs with the State Office of Administrative Hearings issued two orders, one adopting the parties' joint proposal that issues related to electric vehicle charging infrastructure be decided exclusively on written evidence and briefing, and one adopting a joint proposed briefing outline and schedule with deadlines in January 2023 for the parties to submit briefing on issues related to electric vehicle charging infrastructure and admitting evidence related to electric vehicle charging infrastructure issues. In January 2023 the parties filed initial and reply briefs addressing issues related to electric vehicle charging infrastructure.

 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, 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, except for the issues related to electric vehicle charging infrastructure, to the PUCT to consider the settlement. In June 2023 the ALJ issued a proposal for decision related to the electric vehicle charging infrastructure issues and which noted recent legislation enacted which permits electric utilities to own and operate such infrastructure. The ALJ's proposal for decision deferred to the PUCT regarding whether it is appropriate for any vertically integrated electric utility, or Entergy Texas specifically, to own electric vehicle charging infrastructure, and in the event that the PUCT decided ownership is permissible, the ALJ recommended approval of the proposed tariff to charge host customers for utility-owned and operated electric vehicle charging infrastructure sited on customer premises and denial of the proposed tariff to temporarily adjust billing demand charges for separately metered electric vehicle charging infrastructure, citing cost-shifting concerns. In July 2023 the parties filed exceptions and replies to exceptions to the proposal for decision. In August 2023 the PUCT issued an order approving the unopposed settlement and also issued an order severing the issues related to electric vehicle charging infrastructure addressed in the ALJ's proposal for decision to a separate proceeding. Concurrently, Entergy Texas recorded the reversal of $ 21.9 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved.

 Following the PUCT's approval of the unopposed settlement in August 2023, Entergy Texas recorded a regulatory liability of $ 10.3 million, which reflects 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 is 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 will also be 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.

 In December 2023 the PUCT referred the separate proceeding to resolve issues related to electric vehicle charging infrastructure to the State Office of Administrative Hearings. In January 2024, the ALJ with the State Office of Administrative Hearings adopted a procedural schedule setting a hearing on the merits for April 2024.

 Distribution Cost Recovery Factor (DCRF) Rider

 In October 2020, 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 $ 26.3 million annually, or $ 6.8 million in incremental annual revenues beyond Entergy Texas's then-effective DCRF rider based on its capital invested in distribution between January 1, 2020 and August 31, 2020. In February 2021 the ALJ with the State Office of Administrative Hearings approved Entergy Texas's agreed motion for interim rates, which went into effect in March 2021. In March 2021 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested DCRF revenue requirement and resolving all issues in the proceeding. In May 2021 the PUCT issued an order approving the settlement.

 In August 2021, 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 $ 40.2 million annually, or

 $ 13.9 million in incremental annual revenues beyond Entergy Texas's then-effective DCRF rider based on its capital invested in distribution between September 1, 2020 and June 30, 2021. In September 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. A procedural schedule was established with a hearing scheduled in December 2021. In December 2021 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested DCRF revenue requirement and resolving all issues in the proceeding, including a motion for interim rates to take effect for usage on and after January 24, 2022. Also, in December 2021, the ALJ with the State Office of Administrative Hearings issued an order granting the motion for interim rates, which went into effect in January 2022, admitting evidence, and remanding the proceeding to the PUCT to consider the settlement. In March 2022 the PUCT issued an order approving the settlement.

 Transmission Cost Recovery Factor (TCRF) Rider

 In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The new TCRF rider was designed to collect approximately $ 2.7 million annually from Entergy Texas's retail customers based on its capital invested in transmission between January 1, 2018 and September 30, 2018. In April 2019 parties filed testimony proposing a load growth adjustment, which would fully offset Entergy Texas's proposed TCRF revenue requirement. In July 2019 the PUCT granted Entergy Texas's application as filed to begin recovery of the requested $ 2.7 million annual revenue requirement, rejecting opposing parties' proposed adjustment; however, the PUCT found that the question of prudence of the actual investment costs should be determined in Entergy Texas's next rate case similar to the procedure used for the costs recovered through the DCRF rider. In October 2019 the PUCT issued an order on a motion for rehearing, clarifying and affirming its prior order granting Entergy Texas's application as filed. Also in October 2019 a second motion for rehearing was filed, and Entergy Texas filed a response in opposition to the motion. The second motion for rehearing was overruled by operation of law. In December 2019, Texas Industrial Energy Consumers filed an appeal to the PUCT order in district court alleging that the PUCT erred in declining to apply a load growth adjustment.

 In October 2020, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended rider was designed to collect from Entergy Texas's retail customers approximately $ 51 million annually, or $ 31.6 million in incremental annual revenues beyond Entergy Texas's then-effective TCRF rider based on its capital invested in transmission between July 1, 2019 and August 31, 2020. In March 2021 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested TCRF revenue requirement with interim rates effective March 2021 and resolving all issues in the proceeding. In March 2021 the ALJ granted the motion for interim rates, admitted evidence, and remanded the case to the PUCT for consideration of a final order at a future open meeting. In June 2021 the PUCT issued an order approving the settlement.

 In October 2021, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended rider was designed to collect from Entergy Texas's retail customers approximately $ 66.1 million annually, or $ 15.1 million in incremental annual revenues beyond Energy Texas's then-effective TCRF rider based on its capital invested in transmission between September 1, 2020 and July 31, 2021 and changes in approved transmission charges. In January 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In February 2022 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested TCRF revenue requirement with interim rates effective March 2022. In February 2022 the ALJ granted the motion for interim rates, admitted evidence, and remanded the case to the PUCT for consideration of a final order at a future open meeting. In June 2022 the PUCT issued an order approving the settlement.

 Generation Cost Recovery Rider

 In October 2020, Entergy Texas filed an application to establish a generation cost recovery rider with an initial annual revenue requirement of approximately $ 91 million to begin recovering a return of and on its generation capital investment in the Montgomery County Power Station through August 31, 2020. In December 2020, Entergy Texas filed an unopposed settlement supporting a generation cost recovery rider with an annual revenue requirement of approximately $ 86 million. The settlement revenue requirement was based on a

 depreciation rate intended to fully depreciate Montgomery County Power Station over 38 years and the removal of certain costs from Entergy Texas's request. Under the settlement, Entergy Texas retained the right to propose a different depreciation rate and seek recovery of a majority of the costs removed from its request in its next base rate proceeding, and such depreciation rate was revised to fully depreciate Montgomery County Power Station over 40 years and all requested capital additions were approved as prudent in the 2022 base rate case proceeding discussed above. On January 14, 2021, the PUCT approved the generation cost recovery rider settlement rates on an interim basis and abated the proceeding. In March 2021, Entergy Texas filed to update its generation cost recovery rider to include its generation capital investment in Montgomery County Power Station after August 31, 2020. In April 2021 the ALJ issued an order unabating the proceeding and in May 2021 the ALJ issued an order finding Entergy Texas's application and notice of the application to be sufficient. In May 2021, Entergy Texas filed an amendment to the application to reflect the PUCT's approval of the sale of a 7.56 % partial interest in the Montgomery County Power Station to East Texas Electric Cooperative, Inc., which closed in June 2021. In June 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2021 the ALJ with the State Office of Administrative Hearings adopted a procedural schedule setting a hearing on the merits for September 2021. In July 2021 the parties filed a motion to abate the procedural schedule noting they had reached an agreement in principle and to allow the parties time to finalize a settlement agreement, which motion was granted by the ALJ. In October 2021, Entergy Texas filed on behalf of the parties an unopposed settlement agreement that would adjust its generation cost recovery rider to recover an annual revenue requirement of approximately $ 88.3 million related to Entergy Texas's investment in the Montgomery County Power Station through January 1, 2021, with Entergy Texas able to seek recovery of the remainder of its investment in its next base rate case, and all requested capital additions were approved as prudent in the 2022 base rate case proceeding discussed above. Also in October 2021 the ALJ granted a motion to admit evidence and remand the proceeding to the PUCT. In January 2022 the PUCT issued an order approving the unopposed settlement. In February 2022, Entergy Texas filed a relate-back rider to collect over five months an additional approximately $ 5 million, which is the difference between the interim revenue requirement approved in January 2021 and the revenue requirement approved in January 2022 that reflects Entergy Texas's full generation capital investment and ownership in Montgomery County Power Station on January 1, 2021, plus carrying costs from January 2021 through January 2022 when the updated revenue requirement took effect. In April 2022, Entergy Texas and the PUCT staff filed a joint proposed order supporting approval of Entergy Texas's as-filed request. The PUCT approved the relate-back rider consistent with Entergy Texas's as-filed request, and rates became effective over a five-month period, in August 2022.

 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 Hardin 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. In September 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. A procedural schedule was established with a hearing scheduled in April 2022. 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 March 2022, Entergy Texas filed on behalf of the parties an unopposed motion, which motion was granted by the ALJ with the State Office of Administrative Hearings, to abate the procedural schedule indicating that the parties had reached an agreement in principle. 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 is $ 4.5 million in incremental annual revenue above the $ 88.3 million approved in January 2022, related to Entergy Texas's actual investment in the acquisition of the Hardin County Peaking Facility. Concurrently with filing of the unanimous settlement agreement, Entergy Texas submitted an agreed motion to admit evidence and remand the case to the PUCT for review and consideration of the settlement agreement, which motion was granted by the ALJ with the State Office of Administrative Hearings. 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. See Note 14 to the financial statements for discussion of the Hardin County Peaking Facility purchase.

 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 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 contemplates 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.

 After a hearing, the ALJ issued an initial decision in December 2010. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that "shareholders" should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ's initial decision and in January 2011 filed with the FERC exceptions to the decision.

 The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does 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 does 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. The LPSC, the APSC, the City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that the FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.

 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.

 In May 2016, Entergy Services filed a request for rehearing of the FERC's April 2016 order arguing that payments made by Entergy Arkansas should be reduced as a result of the timing of the LPSC's approval of certain contracts. Entergy Services also filed a request for clarification and/or rehearing of the FERC's April 2016 order addressing the ALJ's August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC's April 2016 order. In September 2017 the FERC issued an order denying the request for rehearing on the issue of whether any payments by Entergy Arkansas to the other Utility operating companies should be reduced due to the timing of the LPSC's approval of Entergy Arkansas's wholesale baseload contract with Entergy Louisiana. In November 2017 the FERC issued an order denying all of the remaining requests for rehearing of the April 2016 order. In November 2017, Entergy Services filed a petition for review in the D.C. Circuit of the FERC's orders in the first two phases of the opportunity sales case. In December 2017 the D.C. Circuit granted Entergy Services' request to hold the appeal in abeyance pending final resolution of the related proceeding before the FERC. In January 2018 the APSC and the LPSC filed separate petitions for review in the D.C. Circuit, and the D.C. Circuit consolidated the appeals with Entergy Services' appeal.

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

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

 In October 2018 the FERC issued an order addressing the ALJ's July 2017 initial decision. The FERC reversed the ALJ's decision to cap the reduction in Entergy Arkansas's payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ's decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas's payment. The FERC affirmed on other grounds the ALJ's rejection of the LPSC's claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas's payment. In November 2018 the LPSC requested rehearing of the FERC's October 2018 decision. In December 2019 the FERC denied the LPSC's request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.

 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. No protests were filed in response to the December 2018 compliance filing. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:

 Total refunds including interest

 Payment/(Receipt)

 Principal
 Interest
 Total

 $ 68
 $ 67
 $ 135

 ($ 30)
 ($ 29)
 ($ 59)

 ($ 18)
 ($ 18)
 ($ 36)

 ($ 3)
 ($ 4)
 ($ 7)

 ($ 17)
 ($ 16)
 ($ 33)

 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.

 As described above, 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 February 2019 the LPSC filed a new complaint relating to two issues that were raised in the opportunity sales proceeding, but that, in its October 2018 order, the FERC held were outside the scope of the proceeding. In March 2019, Entergy Services filed an answer and motion to dismiss the new complaint. In November 2019 the FERC issued an order denying the LPSC's complaint. The order concluded that the settlement agreement approved by the FERC in December 2015 terminating the System Agreement barred the LPSC's new complaint. In December 2019 the LPSC requested rehearing of the FERC's November 2019 order, and in July 2020 the FERC issued an order dismissing the LPSC's request for rehearing. In September 2020 the LPSC appealed to the D.C. Circuit the FERC's orders dismissing the new opportunity sales complaint. In November 2020 the D.C. Circuit issued an order establishing that briefing will occur in January 2021 through April 2021. Oral argument was held in September 2021. In December 2021 the D.C. Circuit denied the LPSC's Petition for Review of the new opportunity sales complaint. The opportunity sales cases are complete at FERC and at the D.C. Circuit and no additional refund amounts are owed by Entergy Arkansas.

 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. The application requested that the APSC approve the rider to take effect within 30 days or, if suspended by the APSC as allowed by commission rule, approve the rider to take effect in the first billing cycle of the first month occurring 30 days after issuance of the APSC's order approving the rider. In June 2019 the APSC suspended Entergy Arkansas's tariff and granted Entergy Arkansas's motion asking the APSC to establish the proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC's October 2018 order and related FERC orders in the opportunity sales proceeding. In January 2020 the APSC adopted a procedural schedule with a hearing in April 2020. In January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed a joint motion seeking to dismiss Entergy Arkansas's application alleging that the APSC, in a prior proceeding, ruled on the issues addressed in the application and determined that Entergy Arkansas's requested relief violates the filed rate doctrine and the prohibition against retroactive ratemaking. Entergy Arkansas responded to the joint motion in February 2020 rebutting these

 arguments, including demonstrating that the claims in this proceeding differ substantially from those the APSC addressed previously and that the payment resulting from a FERC tariff violation for which Entergy Arkansas seeks retail cost recovery in this proceeding differs materially from the refunds resulting from a FERC tariff amendment that the APSC previously rejected on filed rate doctrine and the retroactive ratemaking grounds. In addition, 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. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas's request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $ 13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas's stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $ 13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. 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 October 2020 the APSC filed a motion to dismiss Entergy Arkansas's complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary. In March 2022 the court denied the APSC's motion to dismiss, and, in April 2022, issued a scheduling order including a trial date in February 2023. In June 2022, Entergy Arkansas filed a motion asserting that it is entitled to summary judgment because Entergy Arkansas's position that the APSC's order is pre-empted by the filed rate doctrine and violates the Dormant Commerce Clause is premised on facts that are not subject to genuine dispute. In July 2022, Arkansas Electric Energy Consumers, Inc., an industrial customer association, filed a motion to intervene and to hold Entergy Arkansas's motion for summary judgment in abeyance pending a ruling on the motion to intervene. Entergy Arkansas filed a consolidated opposition to both motions. In August 2022 the APSC filed a motion for summary judgment arguing that there is no genuine issue as to any material fact and the APSC is entitled to judgment as a matter of law. In September 2022, Entergy Arkansas filed an opposition to the motion. In October 2022 the APSC filed a motion asking the court to hold further proceedings in abeyance pending a decision on the motions for summary judgment filed by Entergy Arkansas and the APSC. Also in October 2022, Entergy Arkansas filed an opposition to the motion, and the APSC filed a reply in support of its motion for summary judgment. In January 2023 the judge assigned to the case, on her own motion, identified facts that may present a conflict and recused herself; a new judge was assigned to the case, but he also recused due to a conflict. The case again was reassigned to a new judge. In January 2023 the court denied all pending motions (including those described above) except for a motion by the APSC to exclude certain testimony and further ruled that the matter would proceed to trial. In January 2023, Arkansas Electric Energy Consumers, Inc. filed a notice of appeal of the court's order denying its motion to intervene to the United States Court of Appeals for the Eighth Circuit and a motion with the district court to stay the proceedings pending the appeal, which was denied. In February 2023, Arkansas Electric Energy Consumers, Inc. filed a motion with the United States Court of Appeals for the Eighth District to stay the proceedings pending the appeal, which also was denied. The trial was held in February 2023. Following the trial, Entergy Arkansas filed a motion with the United States Court of Appeals for the Eighth District to expedite the appeal filed by Arkansas Electric Energy Consumers, Inc. The United States Court of Appeals for

 the Eighth District granted Entergy Arkansas's request, and oral arguments were held in June 2023. In August 2023 the United States Court of Appeals for the Eighth District affirmed the order of the court denying Arkansas Electric Energy Consumers, Inc.'s motion to intervene. An order from the district court is pending and is anticipated in 2024.

 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 Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. System Energy and the Unit Power Sales Agreement are currently the subject of several litigation proceedings at the FERC (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit), 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. The settlement with the MPSC described in "System Energy Settlement with the MPSC" below, and the settlement in principle with the APSC described in "System Energy Settlement with the APSC" below, if approved by the FERC, substantially reduce the aggregate amount of exposure resulting from these claims. The claims in these proceedings include claims for refunds and claims for rate adjustments; the aggregate amount of refunds claimed in these proceedings, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. Following are discussions of the proceedings.

 Return on Equity and Capital Structure Complaints

 In January 2017 the APSC and MPSC filed a complaint with the FERC against System Energy. The complaint seeks 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 current return on equity under the Unit Power Sales Agreement is 10.94 %, which was established in a rate proceeding that became final in July 2001. As discussed below in "System Energy Settlement with the MPSC," beginning with the July 2022 service month, bills issued to Entergy Mississippi under the Unit Power Sales Agreement reflect a return on equity of 9.65 %.

 The APSC and MPSC complaint alleges that the return on equity is unjust and unreasonable because capital market and other considerations indicate that it is excessive. The complaint requests proceedings to investigate the return on equity and establish a lower return on equity, and also requests that the FERC establish January 23, 2017 as a refund effective date. The complaint includes return on equity analysis that purports to establish that the range of reasonable return on equity for System Energy is between 8.37 % and 8.67 %. System Energy answered the complaint in February 2017 and disputes that a return on equity of 8.37 % to 8.67 % is 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 requests similar relief from the FERC with respect to System Energy's return on equity and also requests the FERC to investigate System Energy's capital structure. The APSC, MPSC,

 and 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 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 MPSC complaint for hearing. The parties 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, System Energy filed a request for rehearing and the LPSC filed a request for rehearing or reconsideration of the FERC's August 2018 order. The LPSC's request referenced an amended complaint that it filed on the same day raising 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 submitted a response 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. As noted below, in June 2019, settlement discussions were terminated 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.

 In January 2019 the LPSC, the APSC, and the MPSC filed direct testimony in the return on equity proceeding. For the refund period January 23, 2017 through April 23, 2018, the LPSC argues for an authorized return on equity for System Energy of 7.81 % and the APSC and the MPSC argue for an authorized return on equity for System Energy of 8.24 %. For the refund period April 27, 2018 through July 27, 2019, and for application on a prospective basis, the LPSC argues for an authorized return on equity for System Energy of 7.97 % and the APSC and the MPSC argue for an authorized return on equity for System Energy of 8.41 %. In March 2019, System Energy submitted answering testimony. For the first refund period, System Energy's testimony argues for a return on equity of 10.10 % (median) or 10.70 % (midpoint). For the second refund period, System Energy's testimony shows that the calculated returns on equity for the first period fall within the range of presumptively just and reasonable returns on equity, and thus the second complaint should be dismissed (and the first period return on equity used going forward). If the FERC nonetheless were to set a new return on equity for the second period (and going forward), System Energy argues the return on equity should be either 10.32 % (median) or 10.69 % (midpoint).

 In May 2019 the FERC trial staff filed its direct and answering testimony in the return on equity proceeding. For the first refund period, the FERC trial staff calculates an authorized return on equity for System Energy of 9.89 % based on the application of FERC's proposed methodology. The FERC trial staff's direct and answering testimony noted that an authorized return on equity of 9.89 % for the first refund period was within the range of presumptively just and reasonable returns on equity for the second refund period, as calculated using a study period ending January 31, 2019 for the second refund period.

 In June 2019, System Energy filed testimony responding to the testimony filed by the FERC trial staff. Among other things, System Energy's testimony rebutted arguments raised by the FERC trial staff and provided updated calculations for the second refund period based on the study period ending May 31, 2019. For that refund period, System Energy's testimony shows that strict application of the return on equity methodology proposed by the FERC staff indicates that the second complaint would not be dismissed, and the new return on equity would be set at 9.65 % (median) or 9.74 % (midpoint). System Energy's testimony argues that these results are insufficient in light of benchmarks such as state returns on equity and treasury bond yields, and instead proposes that the calculated returns on equity for the second period should be either 9.91 % (median) or 10.3 % (midpoint). System Energy's testimony also argues that, under application of its proposed modified methodology, the 10.10 % return on equity calculated for the first refund period would fall within the range of presumptively just and reasonable returns on equity for the second refund period.

 Also in June 2019, the FERC's Chief ALJ issued an order terminating settlement discussions in the amended complaint addressing System Energy's capital structure. The ALJ consolidated the amended capital structure complaint with the ongoing return on equity proceeding and set new procedural deadlines for the consolidated hearing.

 In August 2019 the LPSC, the APSC, and the MPSC filed rebuttal testimony in the return on equity proceeding and direct and answering testimony relating to System Energy's capital structure. The LPSC re-argues for an authorized return on equity for System Energy of 7.81 % for the first refund period and 7.97 % for the second refund period. The APSC and the MPSC argue for an authorized return on equity for System Energy of 8.26 % for the first refund period and 8.32 % for the second refund period. With respect to capital structure, the LPSC proposes that the FERC establish a hypothetical capital structure for System Energy for ratemaking purposes. Specifically, the LPSC proposes that System Energy's common equity ratio be set to Entergy Corporation's equity ratio of 37 % equity and 63 % debt. In the alternative, the LPSC argues that the equity ratio should be no higher than 49 %, the composite equity ratio of System Energy and the other Entergy operating companies who purchase under the Unit Power Sales Agreement. The APSC and the MPSC recommend that 35.98 % be set as the common equity ratio for System Energy. As an alternative, the APSC and the MPSC propose that System Energy's common equity be set at 46.75 % based on the median equity ratio of the proxy group for setting the return on equity.

 In September 2019 the FERC trial staff filed its rebuttal testimony in the return on equity proceeding. For the first refund period, the FERC trial staff calculates an authorized return on equity for System Energy of 9.40 % based on the application of the FERC's proposed methodology and an updated proxy group. For the second refund period, based on the study period ending May 31, 2019, the FERC trial staff rebuttal testimony argues for a return on equity of 9.63 %. In September 2019 the FERC trial staff also filed direct and answering testimony relating to System Energy's capital structure. The FERC trial staff argues 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 calculates the average capital structure for its proposed proxy group of 46.74 % common equity, and 53.26 % debt.

 In October 2019, System Energy filed answering testimony disputing the FERC trial staff's, the LPSC's, and the APSC's and MPSC's arguments for the use of a hypothetical capital structure and arguing that the use of System Energy's actual capital structure is just and reasonable.

 In November 2019, in a proceeding that did not involve System Energy, the FERC issued an order addressing the methodology for determining the return on equity applicable to transmission owners in MISO. Thereafter, the procedural schedule in the System Energy proceeding was amended to allow the participants to file supplemental testimony addressing the order in the MISO transmission owner proceeding (Opinion No. 569).

 In February 2020 the LPSC, the MPSC and APSC, and the FERC trial staff filed supplemental testimony addressing Opinion No. 569 and how it would affect the return on equity evaluation for the two complaint periods concerning System Energy. For the first refund period, based on their respective interpretations and applications of the Opinion No. 569 methodology, the LPSC argues for an authorized return on equity for System Energy of 8.44 %; the MPSC and APSC argue for an authorized return on equity of 8.41 %; and the FERC trial staff argues for an authorized return on equity of 9.22 %. For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569 methodology, the LPSC argues for an authorized return on equity for System Energy of 7.89 %; the MPSC and APSC argue that an authorized return on equity of 8.01 % may be appropriate; and the FERC trial staff argues for an authorized return on equity of 8.66 %.

 In April 2020, System Energy filed supplemental answering testimony addressing Opinion No. 569. System Energy argues that the Opinion No. 569 methodology is conceptually and analytically defective for purposes of establishing just and reasonable authorized return on equity determinations and proposes an alternative approach. As its primary recommendation, System Energy continues to support the return on equity determinations

 in its March 2019 testimony for the first refund period and its June 2019 testimony for the second refund period. Under the Opinion No. 569 methodology, System Energy calculates a "presumptively just and reasonable range" for the authorized return on equity for the first refund period of 8.57 % to 9.52 %, and for the second refund period of 8.28 % to 9.11 %. System Energy argues that these ranges are not just and reasonable results. Under its proposed alternative methodology, System Energy calculates an authorized return on equity of 10.26 % for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively.

 In May 2020 the FERC issued an order on rehearing of Opinion No. 569 (Opinion No. 569-A). In June 2020 the procedural schedule in the System Energy proceeding was further revised in order to allow parties to address the Opinion No. 569-A methodology. Pursuant to the revised schedule, in June 2020, the LPSC, MPSC and APSC, and the FERC trial staff filed supplemental testimony addressing Opinion No. 569-A and how it would affect the return on equity evaluation for the two complaint periods concerning System Energy. For the first refund period, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argues for an authorized return on equity for System Energy of 7.97 %; the MPSC and APSC argue for an authorized return on equity of 9.24 %; and the FERC trial staff argues 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 argues for an authorized return on equity for System Energy of 7.78 %; the MPSC and APSC argue that an authorized return on equity of 9.15 % may be appropriate if the second complaint is not dismissed; and the FERC trial staff argues for an authorized return on equity of 9.09 % if the second complaint is not dismissed.

 Pursuant to the revised procedural schedule, in July 2020, System Energy filed supplemental testimony addressing Opinion No. 569-A. System Energy argues 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. As its primary recommendation, System Energy argues for the use of a methodology that incorporates four separate financial models, including the constant growth form of the discounted cash flow model and the empirical capital asset pricing model. Based on application of its recommended methodology, System Energy argues for an authorized return on equity of 10.12 % for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively. Under the Opinion No. 569-A methodology, System Energy calculates an authorized return on equity of 9.44 % for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively.

 The parties and FERC trial staff filed final rounds of testimony in August 2020. The hearing before a FERC ALJ occurred in late-September through early-October 2020, post-hearing briefing took place in November and December 2020.

 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 % is 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 System Energy's actual equity ratio is excessive and that the just and reasonable equity ratio is 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. If the ALJ's initial decision is upheld, the estimated refund for this proceeding is approximately $ 41 million, which includes interest through December 31, 2023, and the estimated resulting annual rate reduction would be approximately $ 25 million. As a result of the

 2022 settlement agreement with the MPSC, both the estimated refund and rate reduction exclude Entergy Mississippi's portion. See "System Energy Settlement with the MPSC" below for discussion of the settlement. The estimated refund will continue to accrue interest until a final FERC decision is issued.

 The ALJ initial decision is an interim step in the FERC litigation process, and an ALJ's determinations made in an initial decision are not controlling on the FERC. 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. Refunds, if any, that might be required will only become due after the FERC issues its order reviewing the initial decision.

 As discussed in "System Energy Settlement with the MPSC" below, beginning with the July 2022 service month, bills issued to Entergy Mississippi under the Unit Power Sales Agreement were adjusted to reflect a capital structure not to exceed 52 % equity.

 In August 2022 the D.C. Circuit Court of Appeals issued an order addressing appeals of FERC's Opinion No. 569 and 569-A, which established the methodology applied in the ALJ's initial decision in the proceeding against System Energy discussed above. The appellate order addressed the methodology for determining the return on equity applicable to transmission owners in MISO. The D.C. Circuit found the FERC's use of the Risk Premium model as part of the methodology to be arbitrary and capricious, and remanded the case back to the FERC. The remanded case is pending FERC action.

 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 alleges 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 is double-recovering costs by including both the lease payments and the capital additions in Unit Power Sales Agreement billings. The complaint also claims 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 alleges that System Energy violated various other reporting and accounting requirements and should have sought prior FERC approval of the lease renewal. The complaint seeks various forms of relief from the FERC. The complaint seeks 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. The complaint also asks that the FERC disallow and refund the lease costs of the sale-leaseback renewal on grounds of imprudence, investigate System Energy's treatment of a DOE litigation payment, and impose 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 is inconsistent with a FERC-approved settlement to which the LPSC is a party and that explicitly authorizes 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 fails 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. The FERC established 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. In March 2019 the LPSC, the MPSC, the APSC and the City Council filed direct testimony. The LPSC testimony sought refunds that include 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, and the cost of capital additions associated with the sale-leaseback interest, as well as interest on those amounts.

 In June 2019 System Energy filed answering testimony arguing that the FERC should reject all claims for refunds. Among other things, System Energy argued that claims for refunds of the costs of lease renewal payments and capital additions should be rejected because those costs were recovered consistent with the Unit Power Sales Agreement formula rate, System Energy was not over or double recovering any costs, and ratepayers will save costs over the initial and renewal terms of the leases. System Energy argued that claims for refunds associated with liabilities arising from uncertain tax positions should be rejected because the liabilities do not provide cost-free capital, the repayment timing of the liabilities is uncertain, and the outcome of the underlying tax positions is uncertain. System Energy's testimony also challenged the refund calculations supplied by the other parties.

 In August 2019 the FERC trial staff filed direct and answering testimony seeking refunds for rate base reductions for liabilities associated with uncertain tax positions. The FERC trial staff also argued that System Energy recovered $ 32 million more than it should have in depreciation expense for capital additions. In September 2019, System Energy filed cross-answering testimony disputing the FERC trial staff's arguments for refunds, stating that the FERC trial staff's position regarding depreciation rates for capital additions is not unreasonable, but explaining that 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 will also involve changes to accumulated depreciation, accumulated deferred income taxes, and other formula elements as needed. In October 2019 the LPSC filed rebuttal testimony increasing the amount of refunds sought for liabilities associated with uncertain tax positions. The LPSC seeks approximately $ 512 million plus interest, which is approximately $ 310 million through December 31, 2023. The FERC trial staff also filed rebuttal testimony in which it seeks refunds of a similar amount as the LPSC for the liabilities associated with uncertain tax positions. The LPSC testimony also argued that adjustments to depreciation rates should affect rate base on a prospective basis only.

 A hearing was held before a FERC ALJ in November 2019. In April 2020 the 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 is 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 is 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.

 In addition, in September 2020, the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. The NOPA memorializes 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 proposes 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 propose the inclusion of the RAR as support for the filings. In December 2020 the LPSC, the APSC, and the City Council filed a protest in response to the amendments, reiterating their prior objections to the filings. 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. The one-time credit was made 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 disallows 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 are 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 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 are 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. The $ 103.5 million in total refunds calculated in the compliance filing were reclassified from long-term other regulatory liabilities to a current regulatory liability as of December 31, 2022. 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 have been deemed denied by operation of law. The deemed denial of the rehearing request initiates a sixty-day period in which aggrieved parties may petition for federal appellate court review of the underlying FERC orders; however, the FERC may issue a substantive order on rehearing as long as it continues to have jurisdiction over the case. 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 August 2023 the FERC issued an order addressing arguments raised on rehearing and partially setting aside the prior order (rehearing order). The rehearing order addresses 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 directs 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 allows 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 allows 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 directs 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 has 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. On this issue, as reflected in its January 2023 compliance filing, System Energy believes it has already paid the refunds due under the remedy that the FERC outlined for the uncertain tax positions issue in its December 2022 order. In August 2023 the LPSC issued a media release in which it stated that it disagrees with System Energy's determination that the rehearing order requires no further refunds to be made on this issue.

 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 requests 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 requests 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 has been 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. In February 2024 the parties filed a proposed briefing schedule under which briefing will occur from March 2024 through July 2024.

 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. The LPSC directive authorized its staff to file complaints at the FERC "necessary to address these rate issues, to request a full investigation into the rates charged by System Energy for Grand Gulf power, and to seek rate refund, rate reduction, and such other remedies as may be necessary and appropriate to protect Louisiana ratepayers." The LPSC directive further stated that the LPSC has seen "information suggesting that the Grand Gulf plant has been significantly underperforming compared to other nuclear plants in the United States, has had several extended and unexplained outages, and has been plagued with serious safety concerns." The LPSC expressed concern that the costs paid by Entergy Louisiana's retail customers may have been detrimentally impacted, and authorized "the filing of a FERC complaint to address these performance issues and to seek appropriate refund, rate reduction, and other remedies as may be appropriate."

 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 raises 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 overlap with the previous complaints. The filed rate allegations not previously raised are 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 alleges are 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 requests 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 is warranted because all claims fall into one or more of the following categories: the claims have been raised and are being litigated in another proceeding; the claims do not present a prima facie case and do not satisfy the threshold burden to establish a complaint proceeding; the claims are 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 are barred or waived by the legal doctrine of laches; and/or the claims have 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 January 2021 the complainants filed a response to System Energy's November 2020 answer, and in February 2021, System Energy filed a response to the complainant's response.

 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 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 subsequently 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. The appeal was initially stayed for a period of 90 days, but the stay expired. 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 include, 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 is also seeking a retroactive adjustment to retained earnings and capital structure in conjunction with the implementation of its proposed refunds. In addition, the LPSC seeks 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 argues 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 alleges 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 recommends a refund of approximately $ 98.8 million for the period 2004-September 2021 or other alternative relief. The City Council

 further recommends 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 argues, 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 has 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 has been correct. System Energy further responds that no retroactive adjustment to retained earnings or capital structure should be ordered because there is 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 are 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 have been included in rates for decades, is unjust and unreasonable. In response to the LPSC's proposed going-forward adjustments, System Energy presents evidence to show that none of the proposed adjustments are 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 argues that the Unit Power Sales Agreement does 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 are appropriate on those issues. In response to the City Council's claims, System Energy argues that it has reasonably managed its cash and that the City Council's theory of cash management is defective because it fails to adequately consider the relevant cash needs of System Energy and it makes faulty presumptions about the operation of the Entergy system money pool. System Energy further points out that the issue of its capital structure is 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 recommends 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 recommends refunds of $ 84.1 million, exclusive of any tax gross-up or FERC interest. In addition, the FERC trial staff recommends 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 concern the reasonableness of System Energy's rate of return, the FERC trial staff states that it is unnecessary to consider such issues in this 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 recommends 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 asserts 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 warrant historical refunds. The LPSC's rebuttal testimony argues that refunds for the alleged tariff violations and other claims must be calculated by rerunning the Unit Power Sales Agreement formula rate; however, it includes estimates of refunds associated with some, but not all, of its claims, totaling $ 286 million without interest. The City Council's rebuttal testimony also proposes 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 agrees with the LPSC's direct testimony that retained earnings should be adjusted in a comprehensive refund calculation. The testimony quantifies 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 are 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 are 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 seek more than $ 700 million in refunds and interest, based on charges to all Unit Power Sales Agreement purchasers including Entergy Mississippi.

 In June 2022 a new procedural schedule was adopted, providing for additional rounds of testimony and for the hearing to begin in September 2022. The hearing concluded in December 2022.

 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 agrees to the global settlement System Energy entered into with the MPSC (discussed below), and such global settlement includes a black-box refund amount, then the black-box refund for this settlement agreement shall 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. Based on this finding, the initial decision recommended refunds; System Energy estimates that those refunds for Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans would total approximately $ 116 million plus $ 152 million of interest through December 31, 2023. The initial decision also finds that the Unit Power Sales Agreement should be modified such that a cash working capital allowance of negative $ 36.4 million is applied prospectively. If the FERC ultimately orders these modifications to cash working capital be implemented, the estimated annual revenue requirement impact is expected to be immaterial. 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.

 The initial decision is an interim step in the FERC litigation process, and an ALJ's determination made in an initial decision is not controlling on the FERC. System Energy disagrees 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. The APSC's brief on exceptions challenges the ALJ's determinations on the money pool interest and retained earnings issues. The LPSC's brief on exceptions challenges the ALJ's determinations regarding the sale-leaseback transaction costs, legal fees, and retained earnings issues. The City Council's brief on exceptions challenges the ALJ's determinations on the money pool and cash management issues. The FERC trial staff's brief on exceptions challenges the ALJ's determinations on the cash working capital issue as well as certain of the accumulated deferred income taxes issues. In August 2023 all parties filed separate briefs opposing exceptions. System Energy filed a brief opposing the exceptions of the APSC, the LPSC, and the City Council. The APSC, the LPSC, and the City Council filed separate briefs opposing the exceptions raised by System Energy and the FERC trial staff. The FERC trial staff filed its own brief opposing certain exceptions raised by System Energy, the APSC, the LPSC, and the City Council. The case is now pending a decision by the FERC. Refunds, if any, that might be required will become due only after the FERC issues its order reviewing the initial decision.

 Grand Gulf Prudence Complaint

 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 contains two primary allegations. First, it alleges 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 seeks refunds of at least $ 360 million in alleged replacement energy costs, in addition to other costs, including those that can only be identified upon further investigation. Second, it alleges that the performance and/or management of the 2012 extended power uprate of Grand Gulf was imprudent, and it seeks refunds of all costs of the 2012 uprate that are determined to result from imprudent planning or management of the project. In addition to the requested refunds, the complaint asks that the FERC modify the Unit Power Sales Agreement to provide for full cost recovery only if certain performance indicators are met and to require pre-authorization of capital improvement projects in excess of $ 125 million before related costs may 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 argues that the complaint does not meet its legal burden because, among other reasons, it fails to allege any specific imprudent conduct. With respect to the claim concerning the uprate, System Energy argues that the complaint fails because, among other reasons, the complainants' own conduct prevents them from raising a serious doubt as to the prudence of the uprate. System Energy also requests that the FERC dismiss other elements of the complaint, including the proposed modifications to the Unit Power Sales Agreement, because they are not warranted. Additional responsive pleadings were filed by the complainants and System Energy during the period from March through July 2021. In November 2022 the FERC issued an order setting the complaint for settlement and hearing procedures. 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. Pursuant to that schedule, the complainant's testimony was filed in December 2023. System Energy's answering testimony is due April 2024, and additional rounds of testimony are due through October 2024. The hearing is scheduled to begin in January 2025, with the presiding ALJ's initial decision due in July 2025.

 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. As discussed below in "System Energy Settlement with the APSC", the APSC has settled all of its claims related to this proceeding. The amended complaint states that it is being filed for three primary purposes: (1) to include System Energy's performance in 2021-2022 in the scope of the hearing; (2) to explicitly allege that System Energy's inadequate performance, excessive costs, unplanned outages, and costs attributable to safety violations violate the contractual obligation to maintain and operate the plant in accordance with "good utility practice"; and (3) to provide and substantiate allegations concerning the damages attributable to the alleged breach of contractual obligations. The amended complaint alleges that potentially more than $ 1 billion in damages may be due. In November 2023, System Energy and the other Entergy respondents filed an answer and motion to dismiss the amended and supplemental complaint.

 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 memorializes 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 Unit Power Sales Agreement is a FERC-jurisdictional formula rate tariff for sales of energy and capacity from System Energy's owned and leased share of Grand Gulf to Entergy Mississippi, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. Entergy Mississippi purchases the greatest single amount, nearly 40 % of System Energy's share of Grand Gulf, after its additional purchases from affiliates are considered. The settlement therefore limits System Energy's overall refund exposure associated with the identified proceedings because they will be resolved completely as between the Entergy parties and the MPSC.

 The settlement provided for a black-box refund of $ 235 million from System Energy to Entergy Mississippi, which was to be paid within 120 days of the settlement's effective date (either the date of the FERC approval of the settlement without material modification, or the date that all settling parties agree to accept modifications or otherwise modify the settlement in response to a proposed material modification by the FERC). 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, 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 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. System Energy paid the black-box refund of $ 235 million to Entergy Mississippi in November 2022. See "System Energy Regulatory Liability for Pending Complaints" below for discussion of the regulatory liability related to complaints against System Energy as of December 31, 2023.

 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 covers the amended and supplemental complaint, discussed above in "Grand Gulf Prudence Complaint," filed at the FERC in October 2023. System Energy, Entergy Arkansas, additional Entergy parties, and the APSC filed the settlement agreement and supporting materials with the FERC in November 2023. The Unit Power Sales Agreement is a FERC-jurisdictional formula

 rate tariff for sales of energy and capacity from System Energy's owned and leased share of Grand Gulf to Entergy Mississippi, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. As discussed above in "System Energy Settlement with the MPSC," System Energy previously settled with the MPSC with respect to these complaints before the FERC. Entergy Mississippi has nearly 40 % of System Energy's share of Grand Gulf's output, after its additional purchases from affiliates are considered. The settlements with both the APSC and the MPSC represent almost 65 % of System Energy's share of the output of Grand Gulf.

 The terms of the settlement with the APSC align with the $ 588 million global black box settlement reached between System Energy and the MPSC in June 2022 and provide 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 November 2022 the FERC approved the System Energy settlement with the MPSC and stated that the settlement "appears to be fair and reasonable and in the public interest."

 In addition to the black box refund of $ 142 million described above, beginning with the November 2023 service month, the settlement provides 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.

 In December 2023 the FERC trial staff and the LPSC filed comments. The FERC trial staff commented that it "believes that the settlement is fair, and in the public interest," and neither it nor the LPSC oppose the settlement. In December 2023 the $ 93 million black box refund to Entergy Arkansas was reclassified from long-term other regulatory liabilities to accounts payable - associated companies on System Energy's balance sheet. If the FERC approves the filed settlement in accordance with its terms, it will become binding upon the Entergy parties and the APSC.

 System Energy Regulatory Liability for Pending Complaints

 Prior to June 2022, System Energy recorded a provision and associated liability of $ 37 million for elements of the complaints against System Energy. In June 2022, as discussed in "System Energy Settlement with the MPSC" above, System Energy recorded a regulatory charge of $ 551 million ($ 413 million net-of-tax), increasing System Energy's 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 New Orleans, and Entergy Louisiana. The $ 142 million of refunds for Entergy Arkansas, discussed above in "System Energy Settlement with the APSC" is covered within the $ 353 million previously recorded. System Energy paid the black-box refund of $ 235 million to Entergy Mississippi in November 2022. As discussed above in "Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue," in January 2023 System Energy paid refunds of $ 103.5 million as a result of the FERC's order in December 2022 in that proceeding and recouped $ 40.5 million of the $ 103.5 million from Entergy Louisiana and Entergy New Orleans in October 2023. In addition, as discussed above in "Unit Power Sales Agreement Complaint," a black-box refund of $ 18 million was made by System Energy in 2023 in connection with a partial settlement in that proceeding.

 Based on analysis of the pending complaints against System Energy and potential future settlement negotiations with the LPSC and the City Council, 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. As discussed above, in December 2023 the $ 93 million black box refund to Entergy Arkansas was reclassified from the regulatory liability to accounts payable - associated companies on System Energy's balance sheet. System Energy's remaining regulatory liability related to complaints against System Energy as of December 31, 2023 is $ 178 million. This regulatory liability is consistent with the settlement agreements reached with the MPSC and the APSC, as described above, taking into account amounts already or expected to be refunded.

 Unit Power Sales Agreement

 System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2020 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. The formal challenge alleges: (1) that it was imprudent for System Energy to accept the IRS's partial acceptance of a previously uncertain tax position; (2) that System Energy should have delayed recording the result of the IRS's partial acceptance of the previously uncertain tax position until after internal tax allocation payments were made; (3) that the equity ratio charged in rates was excessive; (4) that sale-leaseback rental payments should have been excluded from rates; and (5) that all issues in the ongoing Unit Power Sales Agreement complaint proceeding should also be reflected in calendar year 2020 bills. While System Energy disagrees that any refunds are owed for the 2020 calendar year bills, the formal challenge estimates that the financial impact of the first through fourth allegations is approximately $ 53 million; it does not provide an estimate of the financial impact of the fifth allegation. However, $ 17 million of the $ 53 million is attributable to the sale-leaseback rental payments. These were refunded to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans in January 2023 as a result of the FERC order received in the Grand Gulf sale-leaseback renewal complaint and uncertain tax position rate base issue. Entergy Mississippi's portion of the refund was included within the settlement with the MPSC, as discussed below.

 In March 2022, System Energy filed an answer to the formal challenge in which it requested that the FERC deny the formal challenge as a matter of law, or else hold the proceeding in abeyance pending the resolution of related dockets.

 System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2021 Calendar Year Bills

 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. The formal challenge alleges: (1) that it was imprudent for System Energy to accept the IRS's partial acceptance of a previously uncertain tax position; (2) that System Energy used incorrect inputs for retained earnings that are used to determine the capital structure; (3) that the equity ratio charged in rates was excessive; and (4) that all issues in the ongoing Unit Power Sales Agreement complaint proceeding should also be reflected in calendar year 2021 bills. The first, third, and fourth allegations are identical to issues that were raised in the formal challenge to the calendar year 2020 bills. The formal challenge to the calendar year 2021 bills states that the impact of the first allegation is "tens of millions of dollars," but it does not provide an estimate of the financial impact of the remaining allegations.

 In May 2023, System Energy filed an answer to the formal challenge in which it requested that the FERC deny the formal challenge as a matter of law, or else hold the proceeding in abeyance pending the resolution of related dockets.

 Depreciation Amendment Proceeding

 In December 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to adopt updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses. The proposed amendments would result in higher charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. In February 2022 the FERC accepted System Energy's proposed increased depreciation rates with an effective date of March 1, 2022, subject to refund pending the outcome of the settlement and/or hearing procedures. In June 2023 System Energy filed with the FERC an unopposed offer of settlement that it had negotiated with intervenors to the proceeding. In August 2023 the FERC

 approved the settlement, which resolves the proceeding. In third quarter 2023, System Energy recorded a reduction in depreciation expense of $ 41 million representing the cumulative difference in depreciation expense resulting from the depreciation rates used from March 2022 through June 2023 and the depreciation rates included in the settlement filing approved by the FERC. In October 2023, System Energy filed a refund report with the FERC. The refund provided for in the refund report was included in the September 2023 service month bills under the Unit Power Sales Agreement. No comments or protests to the refund report were filed.

 Pension Costs Amendment Proceeding

 In October 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to include in rate base the prepaid and accrued pension costs associated with System Energy's qualified pension plans. Based on data ending in 2020, the increased annual revenue requirement associated with the filing is approximately $ 8.9 million. In March 2022 the FERC accepted System Energy's proposed amendments with an effective date of December 1, 2021, subject to refund pending the outcome of the settlement and/or hearing procedures. In August 2023 the FERC chief ALJ terminated settlement procedures and designated a presiding ALJ to oversee hearing procedures. In October 2023, System Energy filed direct testimony in support of its proposed amendments. Under the procedural schedule, testimony will be filed through April 2024, and the hearing is scheduled to begin in May 2024. The presiding ALJ's initial decision is expected to be due in September 2024.

 Storm Cost Recovery Filings with Retail Regulators

 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. As discussed above in "Fuel and purchased power cost recovery," 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, 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.

 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 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 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.

 As discussed in Note 3 to the financial statements, 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.

 As discussed in 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 second quarter 2022, Entergy Louisiana recorded a charge of $ 31.6 million in other income to reflect the LURC's beneficial interest in the storm trust I.

 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 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 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.

 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.

 Hurricane Gustav and Hurricane Ike

 In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy Louisiana's service territory. In December 2009, Entergy Louisiana entered into a stipulation agreement with the LPSC staff regarding its storm costs. In March and April 2010, Entergy Louisiana and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana's proposal to utilize Act 55 financing, which included a commitment to pass on to customers a minimum of $ 43.3 million of customer benefits through a prospective annual rate reduction of $ 8.7 million for five years. In April 2010 the LPSC approved the settlement and subsequently issued financing orders and a ratemaking order intended to facilitate the implementation of the Act 55 financings. In June 2010 the Louisiana State Bond Commission approved the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35 % to 21 %, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricane Gustav and Hurricane Ike was reduced by $ 2.7 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

 In July 2010 the LCDA issued two series of bonds totaling $ 713.0 million under Act 55. From the $ 702.7 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $ 290 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $ 412.7 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana used $ 412.7 million to acquire 4,126,940.15 Class B preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 9 % annual distribution rate. Distributions were payable quarterly commencing on September 15, 2010, 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 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 4,126,940.15 units of Class B preferred membership interests.

 The bonds were repaid in 2022. Entergy and Entergy Louisiana did not report the bonds issued by the LCDA on their balance sheets because the bonds were the obligation of the LCDA, and there was no recourse against Entergy or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Louisiana collected a system restoration charge on behalf of the LURC and remitted 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.

 Hurricane Katrina and Hurricane Rita

 In August and September 2005, Hurricanes Katrina and Rita caused catastrophic damage to Entergy Louisiana's service territory. In March 2008, Entergy Louisiana and the LURC filed at the LPSC an application requesting that the LPSC grant a financing order authorizing the financing of Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 55. Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and savings to customers via a storm cost offset rider. In April 2008 the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financing, approved requests for the Act 55 financing. Also in April 2008, Entergy Louisiana and the LPSC staff filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana's proposal under the Act 55 financing, which included a commitment to pass on to customers a minimum

 of $ 40 million of customer benefits through a prospective annual rate reduction of $ 8 million for five years. The LPSC subsequently approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financing. In May 2008 the Louisiana State Bond Commission granted final approval of the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35 % to 21 %, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricanes Katrina and Rita was reduced by $ 22.3 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

 In July 2008 the LPFA issued $ 687.7 million in bonds under the aforementioned Act 55. From the $ 679 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $ 152 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $ 527 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $ 545 million, including $ 17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85 Class A preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 10 % annual distribution rate. In August 2008 the LPFA issued $ 278.4 million in bonds under the aforementioned Act 55. From the $ 274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $ 87 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $ 187.7 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $ 189.4 million, including $ 1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company that carry a 10 % annual distribution rate. Distributions were payable quarterly commencing on September 15, 2008 and 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 billion. In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company to a third party. Those preferred membership units were subsequently repurchased by Entergy Holdings Company in March 2019. 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 remaining 6,843,780.24 units of Class A preferred membership interests.

 The bonds were repaid in 2018. Entergy and Entergy Louisiana did not report the bonds issued by the LPFA on their balance sheets because the bonds were the obligation of the LPFA, and there was no recourse against Entergy or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Louisiana collected a system restoration charge on behalf of the LURC and remitted the collections to the bond indenture trustee. Entergy and Entergy Louisiana did not report the collections as revenue because Entergy Louisiana was merely acting as the billing and collection agent for the state.

 Entergy Mississippi has 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 exceeds $ 15 million, the collection of the storm damage provision ceases until such time that the accumulated storm damage provision becomes less than $ 10 million. Entergy Mississippi's storm damage provision balance has been less than $ 10 million since May 2019, and Entergy Mississippi has 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 exceeds $ 15 million, in anticipation of a subsequent filing by Entergy Mississippi in this proceeding. The storm damage reserve 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.

 Hurricane Zeta

 In October 2020, Hurricane Zeta caused significant damage to Entergy New Orleans's service area. The storm resulted in widespread power outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the power outages. In March 2021, Entergy New Orleans withdrew $ 44 million from its funded storm reserves. In May 2021, Entergy New Orleans filed an application with the City Council requesting approval and certification that its system restoration costs associated with Hurricane Zeta of approximately $ 36 million, which included $ 7 million in estimated costs, were reasonable and necessary to enable Entergy New Orleans to restore electric service to its customers and Entergy New Orleans's electric utility infrastructure. In May 2022 the City Council advisors issued a report recommending that the City Council find that Entergy New Orleans acted prudently in restoring service following Hurricane Zeta and approximately $ 33 million in storm restoration costs were prudently incurred and recoverable. Additionally, the advisors concluded that approximately $ 7 million of the $ 44 million withdrawn from its funded storm reserve was in excess of Entergy New Orleans's costs and should be considered in Entergy New Orleans's application for certification of costs related to Hurricane Ida. In September 2022 the City Council issued a resolution finding that Entergy New Orleans's system restoration costs were reasonable and necessary, and that Entergy New Orleans acted prudently in restoring electricity following Hurricane Zeta. The City Council also found that approximately $ 33 million in storm costs were recoverable.

 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 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 is requesting 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 and prior miscellaneous storms are properly applied to Hurricane Ida storm restoration costs, the application of which reduces 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, authorizing 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 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.

 Hurricane Laura, Hurricane Delta, and Winter Storm Uri

 In August 2020 and October 2020, Hurricane Laura and Hurricane Delta caused extensive damage to Entergy Texas's service area. In February 2021, Winter Storm Uri also caused damage to Entergy Texas's service area. The storms resulted in widespread power outages, significant damage primarily to distribution and transmission infrastructure, and the loss of sales during the power outages. In April 2021, Entergy Texas filed an application with the PUCT requesting a determination that approximately $ 250 million of system restoration costs associated with Hurricane Laura, Hurricane Delta, and Winter Storm Uri, including approximately $ 200 million in capital costs and approximately $ 50 million in non-capital costs, were reasonable and necessary to enable Entergy Texas to restore electric service to its customers and Entergy Texas's electric utility infrastructure. The filing also included the projected balance of approximately $ 13 million of a regulatory asset containing previously approved

 system restoration costs related to Hurricane Harvey. In September 2021 the parties filed an unopposed settlement agreement, pursuant to which Entergy Texas removed from the amount to be securitized approximately $ 4.3 million that will instead be charged to its storm reserve, $ 5 million related to no particular issue, of which Entergy Texas would be permitted to seek recovery in a future proceeding, and approximately $ 300 thousand related to attestation costs. In December 2021 the PUCT issued an order approving the unopposed settlement and determining system restoration costs of $ 243 million related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri and the $ 13 million projected remaining balance of the Hurricane Harvey system restoration costs were eligible for securitization. The order also determines that Entergy Texas can recover carrying costs on the system restoration costs related to Hurricane Laura, Hurricane Delta, and Winter Storm Uri.

 In July 2021, Entergy Texas filed with the PUCT an application for a financing order to approve the securitization of the system restoration costs that are the subject of the April 2021 application. In November 2021 the parties filed an unopposed settlement agreement supporting the issuance of a financing order consistent with Entergy Texas's application and with minor adjustments to certain upfront and ongoing costs to be incurred to facilitate the issuance and serving of system restoration bonds. In January 2022 the PUCT issued a financing order consistent with the unopposed settlement. As a result of the financing order, Entergy Texas reclassified $ 153 million from utility plant to other regulatory assets.

 In April 2022, Entergy Texas Restoration Funding II, LLC, a company wholly-owned and consolidated by Entergy Texas, issued $ 290.85 million of senior secured system restoration bonds (securitization bonds). With the proceeds, Entergy Texas Restoration Funding II purchased from Entergy Texas the transition property, which is the right to recover from customers through a system restoration charge amounts sufficient to service the securitization bonds. Entergy Texas began cost recovery through the system restoration charge effective with the first billing cycle of May 2022 and the system restoration charge is expected to remain in place up to 15 years. See Note 5 to the financial statements for a discussion of the April 2022 issuance of the securitization bonds.

 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 2023, 2022, and 2021 consist of the following:

 2023
 2022
 2021

 Current:

 Federal
 $ 60,639
 $ 32,387
 ($ 5,003)

 State
 23,014
 ( 3,091)
 ( 8,995)

 Total
 83,653
 29,296
 ( 13,998)

 Deferred and non-current - net
 ( 768,941)
 ( 67,520)
 205,891

 Investment tax credits - net
 ( 5,247)
 ( 754)
 ( 519)

 ($ 690,535)
 ($ 38,978)
 $ 191,374

 Income taxes for the Registrant Subsidiaries for 2023, 2022, and 2021 consist of the following:

 2023

 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
 ( 126,878)
 ( 52,451)
 30,690
 ( 84,744)
 57,066
 31,005

 Investment tax credits - net
 ( 1,231)
 ( 4,680)
 ( 796)
 ( 32)
 ( 764)
 2,260

 ($ 99,210)
 ($ 205,781)
 $ 54,364
 ($ 189,973)
 $ 62,872
 $ 32,032

 2022

 Current:

 Federal
 $ 8,015
 ($ 79,079)
 $ 9,242
 $ 1,074
 $ 37,471
 ($ 11,720)

 State
 ( 1,066)
 ( 1,773)
 ( 6,486)
 6,221
 2,260

 Total
 6,949
 ( 80,852)
 2,756
 7,295
 39,731
 ( 11,139)

 Deferred and non-current - net
 74,802
 ( 77,223)
 48,443
 16,814
 11,520
 ( 83,369)

 Investment tax credits - net
 ( 855)
 ( 4,778)
 3,665
 ( 630)
 1,680

 $ 80,896
 ($ 162,853)
 $ 54,864
 $ 24,277
 $ 50,621
 ($ 92,828)

 2021

 Current:

 Federal
 ($ 20,285)
 ($ 24,053)
 ($ 5,868)
 ($ 6,724)
 ($ 189)
 $ 29,416

 State
 2,459
 ( 11,506)
 ( 413)
 1,261
 ( 10,258)

 Total
 ( 19,756)
 ( 21,594)
 ( 17,374)
 ( 7,137)
 1,072
 19,158

 Deferred and non-current - net
 96,180
 146,786
 60,861
 12,870
 25,087
 ( 25,229)

 Investment tax credits - net
 ( 1,229)
 ( 4,783)
 1,836
 ( 633)
 4,094

 $ 75,195
 $ 120,409
 $ 45,323
 $ 5,936
 $ 25,526
 ($ 1,977)

 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 2023, 2022, and 2021 are:

 2023
 2022
 2021

 Net income attributable to Entergy Corporation
 $ 2,356,536
 $ 1,103,166
 $ 1,118,492

 Preferred dividend requirements of subsidiaries and noncontrolling interests
 5,774

 Consolidated net income
 2,362,310
 1,097,138
 1,118,719

 ( 690,535)
 ( 38,978)
 191,374

 Income before income taxes
 $ 1,671,775
 $ 1,058,160
 $ 1,310,093

 Income taxes computed at statutory rate ( 21 %)

 $ 351,073
 $ 222,214
 $ 275,120

 Increases (reductions) in tax resulting from:

 State income taxes net of federal income tax effect
 70,144
 61,368
 79,273

 Regulatory differences - utility plant items
 ( 27,901)
 ( 32,143)
 ( 57,556)

 Equity component of AFUDC
 ( 20,172)
 ( 14,156)
 ( 14,799)

 Amortization of investment tax credits
 ( 7,978)
 ( 7,740)
 ( 7,695)

 Flow-through / permanent differences
 ( 1,374)
 1,011
 ( 5,585)

 Amortization of excess ADIT (a)
 9,102
 ( 34,899)
 ( 66,478)

 Arkansas and Louisiana rate changes (b)
 —
 —
 ( 27,108)

 IRS audit resolution (c)
 ( 842,769)
 —
 —

 Reversal of regulatory liability for Hurricane Isaac (d)

 ( 105,649)
 —
 —

 Entergy Louisiana securitization (e)
 ( 129,034)
 ( 282,620)
 —

 System Energy sale-leaseback order (f)
 —
 12,662
 —

 Provision for uncertain tax positions
 18,884
 34,423
 16,533

 Valuation allowance
 ( 8,697)
 ( 2,754)
 ( 2,600)

 Other - net
 3,836
 3,656
 2,269

 Total income taxes as reported
 ($ 690,535)
 ($ 38,978)
 $ 191,374

 Effective Income Tax Rate
 ( 41.3
 %)
 ( 3.7
 %)
 14.6
 %

 (a)See "Other Tax Matters - Tax Cuts and Jobs Act" below for discussion of the amortization of excess accumulated deferred income taxes (ADIT) in 2023, 2022, and 2021 and the tax legislation enactment in 2017.
 (b)See "Other Tax Matters - Arkansas and Louisiana Corporate Income Tax Rate Changes" below for details.
 (c)See "Income Tax Audits - 2016-2018 IRS Audit" below for discussion of the resolution of the 2016-2018 IRS audit in 2023.
 (d)See Note 2 to the financial statements for discussion of Entergy Louisiana's reversal of a regulatory liability, associated with the Hurricane Isaac securitization, recognized in 2017 as a result of the Tax Cuts and Jobs Act.
 (e)See "Other Tax Matters – Act 293 Securitizations" below for discussion of the Entergy Louisiana May 2022 and March 2023 storm cost securitizations.
 (f)See Note 2 to the financial statements for discussion of the December 2022 FERC order related to the Grand Gulf sale-leaseback renewal complaint.

 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 the years 2023, 2022, and 2021 are:

 2023

 $ 396,850
 $ 1,273,370
 $ 181,969
 $ 228,938
 $ 291,273
 $ 108,772

 ( 99,210)
 ( 205,781)
 54,364
 ( 189,973)
 62,872
 32,032

 Income before income taxes
 $ 297,640
 $ 1,067,589
 $ 236,333
 $ 38,965
 $ 354,145
 $ 140,804

 Income taxes computed at statutory rate ( 21 %)

 $ 62,504
 $ 224,194
 $ 49,630
 $ 8,183
 $ 74,370
 $ 29,569

 Increases (reductions) in tax resulting from:

 State income taxes net of federal income tax effect
 13,291
 51,899
 11,133
 1,907
 2,574
 5,798

 Regulatory differences - utility plant items
 ( 8,812)
 ( 5,535)
 ( 5,290)
 ( 1,353)
 ( 6,394)
 ( 517)

 Equity component of AFUDC
 ( 4,093)
 ( 6,754)
 ( 1,796)
 ( 309)
 ( 5,920)
 ( 1,301)

 Amortization of investment tax credits
 ( 1,201)
 ( 4,625)
 ( 223)
 ( 25)
 ( 748)
 ( 1,155)

 Flow-through / permanent differences
 1,105
 3,534
 ( 1,913)
 1,493
 ( 191)

 IRS audit resolution (a)
 ( 159,588)
 ( 179,111)
 ( 3,291)
 ( 198,424)
 ( 3,112)
 ( 1,575)

 Amortization of excess ADIT (b)
 ( 6,095)
 14,032
 —
 1,147
 —

 Entergy Louisiana securitization (c)
 —
 ( 133,443)
 —
 —
 —
 —

 Reversal of regulatory liability for Hurricane Isaac (d)

 —
 ( 105,649)
 —
 —
 —
 —

 Non-taxable dividend income
 —
 ( 62,116)
 —
 —
 —
 —

 Provision for uncertain tax positions
 2,600
 ( 400)
 1,200

 Other - net
 1,079
 1,601

 Total income taxes as reported
 ($ 99,210)
 ($ 205,781)
 $ 54,364
 ($ 189,973)
 $ 62,872
 $ 32,032

 Effective Income Tax Rate
 ( 33.3 %)
 ( 19.3 %)
 23.0 %
 ( 487.5 %)
 17.8 %
 22.7 %

 2022

 $ 292,887
 $ 855,870
 $ 176,267
 $ 64,101
 $ 303,327
 ($ 276,593)

 80,896
 ( 162,853)
 54,864
 24,277
 50,621
 ( 92,828)

 Income before income taxes
 $ 373,783
 $ 693,017
 $ 231,131
 $ 88,378
 $ 353,948
 ($ 369,421)

 Income taxes computed at statutory rate ( 21 %)

 $ 78,494
 $ 145,534
 $ 48,538
 $ 18,559
 $ 74,329
 ($ 77,578)

 Increases (reductions) in tax resulting from:

 State income taxes net of federal income tax effect
 17,981
 44,244
 9,659
 6,733
 2,175
 ( 16,727)

 Regulatory differences - utility plant items
 ( 12,466)
 ( 6,347)
 ( 7,726)
 ( 1,908)
 ( 3,010)
 ( 686)

 Equity component of AFUDC
 ( 3,437)
 ( 5,513)
 ( 1,286)
 ( 174)
 ( 2,841)
 ( 905)

 Amortization of investment tax credits
 ( 1,201)
 ( 4,720)
 ( 223)
 ( 614)
 ( 1,155)

 Flow-through / permanent differences
 3,467
 4,837
 ( 641)

 Amortization of excess ADIT (b)
 —
 ( 13,164)
 —
 ( 752)
 ( 20,983)
 —

 System Energy sale-leaseback order (e)
 —
 —
 —
 —
 —
 12,662

 Entergy Louisiana securitization (c)
 —
 ( 289,609)
 —
 —
 —
 —

 Non-taxable dividend income
 —
 ( 38,735)
 —
 —
 —
 —

 Provision for uncertain tax positions
 1,600
 1,200
 ( 8,000)

 Valuation allowance
 ( 1,258)
 —
 —
 —
 —
 —

 Other - net
 1,077
 1,590

 Total income taxes as reported
 $ 80,896
 ($ 162,853)
 $ 54,864
 $ 24,277
 $ 50,621
 ($ 92,828)

 Effective Income Tax Rate
 21.6 %
 ( 23.5 %)
 23.7 %
 27.5 %
 14.3 %
 25.1 %

 2021

 $ 298,484
 $ 653,984
 $ 166,834
 $ 31,798
 $ 228,824
 $ 106,814

 75,195
 120,409
 45,323
 5,936
 25,526
 ( 1,977)

 Income before income taxes
 $ 373,679
 $ 774,393
 $ 212,157
 $ 37,734
 $ 254,350
 $ 104,837

 Income taxes computed at statutory rate ( 21 %)

 $ 78,473
 $ 162,623
 $ 44,553
 $ 7,924
 $ 53,413
 $ 22,016

 Increases (reductions) in tax resulting from:

 State income taxes net of federal income tax effect
 19,633
 41,030
 9,305
 2,579
 1,553
 5,385

 Regulatory differences - utility plant items
 ( 16,078)
 ( 14,123)
 ( 8,133)
 ( 4,332)
 ( 2,115)
 ( 12,776)

 Equity component of AFUDC
 ( 3,207)
 ( 6,016)
 ( 1,701)
 ( 498)
 ( 2,077)
 ( 1,300)

 Amortization of investment tax credits
 ( 1,201)
 ( 4,729)
 ( 56)
 ( 617)
 ( 1,155)

 Flow-through / permanent differences
 ( 814)
 ( 2,655)
 1,559
 ( 475)
 ( 1,235)

 Amortization of excess ADIT (b)
 ( 5,845)
 ( 24,323)
 —
 ( 1,028)
 ( 21,929)
 ( 13,354)

 Arkansas and Louisiana rate changes (f)
 ( 6,126)
 ( 1,569)

 Non-taxable dividend income
 —
 ( 26,801)
 —
 —
 —
 —

 Provision for uncertain tax positions
 1,200
 ( 2,716)

 Valuation allowance
 2,766
 —
 —
 —
 —
 —

 Other - net
 1,229

 Total income taxes as reported
 $ 75,195
 $ 120,409
 $ 45,323
 $ 5,936
 $ 25,526
 ($ 1,977)

 Effective Income Tax Rate
 20.1 %
 15.5 %
 21.4 %
 15.7 %
 10.0 %
 ( 1.9 %)

 (a)See "Income Tax Audits - 2016-2018 IRS Audit" below for discussion of the resolution of the 2016-2018 IRS audit in 2023.
 (b)See "Other Tax Matters - Tax Cuts and Jobs Act" below for discussion of the amortization of excess ADIT in 2023, 2022, 2021 and the tax legislation enactment in 2017.
 (c)See "Other Tax Matters - Act 293 Securitizations" below for discussion of the Entergy Louisiana May 2022 and March 2023 storm cost securitizations.
 (d)See Note 2 to the financial statements for discussion of Entergy Louisiana's reversal of a regulatory liability, associated with the Hurricane Isaac securitization, recognized in 2017 as a result of the Tax Cuts and Jobs Act.
 (e)See Note 2 to the financial statements for discussion of the December 2022 FERC order related to the Grand Gulf sale-leaseback renewal complaint.
 (f)See "Other Tax Matters - Arkansas and Louisiana Corporate Income Tax Rate Changes" below for details.

 Significant components of accumulated deferred income taxes and taxes accrued for Entergy Corporation and Subsidiaries as of December 31, 2023 and 2022 are as follows:

 2023
 2022

 Deferred tax liabilities:

 Plant basis differences - net
 ($ 6,192,156)
 ($ 5,270,010)

 Regulatory assets
 ( 989,405)
 ( 937,554)

 Nuclear decommissioning trusts/receivables
 ( 467,267)
 ( 318,570)

 Pension, net regulatory asset
 ( 363,829)
 ( 336,496)

 Combined unitary state taxes
 ( 8,783)
 ( 10,335)

 Power purchase agreements
 ( 75,612)
 ( 3,993)

 Accumulated storm damage provision
 ( 2,474)
 ( 35,213)

 Deferred fuel
 ( 69,436)
 ( 181,222)

 Other
 ( 251,107)
 ( 333,421)

 Total
 ( 8,420,069)
 ( 7,426,814)

 Deferred tax assets:

 Nuclear and other decommissioning liabilities
 147,011
 173,201

 Regulatory liabilities
 1,247,530
 1,108,075

 Pension and other post-employment benefits
 116,222
 141,399

 Compensation
 81,226
 76,317

 Accumulated deferred investment tax credit
 55,928
 57,501

 Provision for allowances and contingencies
 149,479
 97,545

 Unbilled/deferred revenues
 2,418
 21,905

 Net operating loss carryforwards
 2,857,908
 2,065,149

 Capital losses and miscellaneous tax credits
 107,009
 28,876

 Valuation allowance
 ( 372,119)
 ( 372,017)

 Other
 220,055
 245,236

 Total
 4,612,667
 3,643,187

 Non-current accrued taxes (including unrecognized tax benefits)
 ( 422,213)
 ( 951,110)

 ($ 4,229,615)
 ($ 4,734,737)

 Entergy's estimated tax attributes carryovers and their expiration dates as of December 31, 2023 are as follows:

 Carryover Description
 Carryover Amount

 Federal net operating losses before 1/1/2018
 $ 4.2 billion
 2028-2037

 Federal net operating losses - 1/1/2018 forward
 $ 13.8 billion
 N/A

 State net operating losses
 $ 3.9 billion
 2028-2042

 State net operating losses with no expiration
 $ 11.1 billion
 N/A

 Other federal and state carryforwards
 $ 523.6 million
 2024-2037

 Miscellaneous federal and state credits
 $ 124.9 million
 2024-2043

 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 deferred tax assets will not be utilized, valuation allowances totaling $ 372 million as of December 31, 2023 and $ 372 million as of December 31, 2022 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.

 Significant components of accumulated deferred income taxes and taxes accrued for the Registrant Subsidiaries as of December 31, 2023 and 2022 are as follows:

 2023

 Deferred tax liabilities:

 Plant basis differences - net
 ($ 1,421,272)
 ($ 2,639,079)
 ($ 810,120)
 ($ 272,187)
 ($ 671,072)
 ($ 450,559)

 Regulatory assets
 ( 241,427)
 ( 500,395)
 ( 41,519)
 ( 23,618)
 ( 104,562)
 ( 76,522)

 Nuclear decommissioning trusts/receivables
 ( 154,106)
 ( 173,402)
 —
 —
 —
 ( 139,858)

 Pension, net regulatory asset
 ( 96,853)
 ( 82,305)
 ( 24,342)
 ( 9,216)
 ( 17,522)
 ( 18,895)

 Deferred fuel
 —
 ( 17,065)
 ( 21,137)
 ( 1,563)
 ( 29,194)
 ( 37)

 Accumulated storm damage provision
 —
 —
 —
 —
 ( 1,387)
 —

 Power purchase agreements
 15,993
 ( 112,292)
 1,140
 ( 12,516)
 ( 4,551)
 —

 Other
 ( 21,187)
 ( 126,952)
 ( 6,844)
 ( 4,270)
 ( 3,301)
 ( 9,051)

 Total
 ( 1,918,852)
 ( 3,651,490)
 ( 902,822)
 ( 323,370)
 ( 831,589)
 ( 694,922)

 Deferred tax assets:

 Regulatory liabilities
 296,278
 575,459
 54,586
 42,921
 41,137
 240,310

 Nuclear and other decommissioning liabilities
 118,301
 9,055
 —
 —
 19,259

 Pension and other post-employment benefits
 ( 28,868)
 46,837
 ( 10,064)
 ( 19,354)
 ( 21,977)
 ( 2,641)

 Accumulated deferred investment tax credit
 6,761
 27,902
 3,446
 4,431
 1,672
 11,717

 Provision for allowances and contingencies
 23,956
 70,297
 10,072
 25,846
 8,659

 Unbilled/deferred revenues
 5,962
 ( 20,375)
 6,194
 1,045
 8,365
 —

 Compensation
 4,054
 6,078
 3,649
 1,268
 2,181

 Net operating loss carryforwards
 94,321
 459,553
 8,375
 26,227
 35,089

 Capital losses and miscellaneous tax credits
 7,137
 13,073
 7,613
 15,684
 1,655
 13,211

 Other
 17,072
 52,438
 1,556
 ( 235)
 1,740
 —

 Total
 544,974
 1,240,317
 85,427
 97,833
 43,590
 317,576

 Non-current accrued taxes (including unrecognized tax benefits)
 ( 63,175)
 19,731
 ( 4,349)
 29,922
 ( 26,906)
 ( 28,398)

 ($ 1,437,053)
 ($ 2,391,442)
 ($ 821,744)
 ($ 195,615)
 ($ 814,905)
 ($ 405,744)

 2022

 Deferred tax liabilities:

 Plant basis differences - net
 ($ 1,181,456)
 ($ 2,513,138)
 ($ 691,675)
 ($ 115,841)
 ($ 614,134)
 ($ 448,010)

 Regulatory assets
 ( 244,624)
 ( 457,102)
 ( 44,358)
 ( 24,738)
 ( 95,717)
 ( 68,742)

 Nuclear decommissioning trusts/receivables
 ( 107,858)
 ( 118,172)
 —
 —
 —
 ( 92,527)

 Pension, net regulatory asset
 ( 93,139)
 ( 82,891)
 ( 22,256)
 ( 9,604)
 ( 18,111)
 ( 17,889)

 Deferred fuel
 ( 35,205)
 ( 49,792)
 ( 37,333)
 ( 2,560)
 ( 54,204)
 ( 128)

 Accumulated storm damage provision
 —
 ( 31,337)
 —
 —
 ( 3,876)
 —

 Power purchase agreements
 ( 8,296)
 ( 11,181)
 —
 ( 9,372)
 ( 22,014)
 —

 Other
 ( 76,813)
 ( 126,350)
 ( 26,752)
 ( 21,977)
 ( 4,126)
 ( 14,364)

 Total
 ( 1,747,391)
 ( 3,389,963)
 ( 822,374)
 ( 184,092)
 ( 812,182)
 ( 641,660)

 Deferred tax assets:

 Regulatory liabilities
 236,318
 508,594
 54,454
 27,438
 47,248
 237,452

 Nuclear and other decommissioning liabilities
 139,499
 12,883
 —
 18,940

 Pension and other post-employment benefits
 ( 28,463)
 52,414
 ( 9,196)
 ( 18,114)
 ( 20,867)
 ( 2,481)

 Accumulated deferred investment tax credit
 7,171
 29,271
 3,641
 4,438
 1,829
 11,151

 Provision for allowances and contingencies
 26,432
 15,741
 10,300
 26,671
 7,755
 —

 Unbilled/deferred revenues
 6,211
 ( 2,405)
 5,826
 4,090
 7,572
 —

 Compensation
 3,361
 5,207
 2,316
 1,107
 1,712

 Net operating loss carryforwards
 10,491
 307,175
 10,140
 12,146
 27,620
 20,639

 Capital losses and miscellaneous tax credits
 2,774
 5,152
 11,006
 3,728
 8,261

 Other
 24,969
 41,310
 6,849
 11,105
 —

 Total
 426,708
 972,964
 89,483
 79,887
 77,423
 294,270

 Non-current accrued taxes (including unrecognized tax benefits)
 ( 177,551)
 42,121
 ( 47,139)
 ( 281,054)
 ( 9,468)
 ( 28,680)

 ($ 1,498,234)
 ($ 2,374,878)
 ($ 780,030)
 ($ 385,259)
 ($ 744,227)
 ($ 376,070)

 The Registrant Subsidiaries' estimated tax attributes carryovers and their expiration dates as of December 31, 2023 are as follows:

 Federal net operating losses before 1/1/2018
 $ 0.8 billion
 $ 0.1 billion

 N/A
 2035-2037
 N/A
 2037
 N/A
 N/A

 Federal net operating losses - 1/1/2018 forward
 $ 0.5 billion
 $ 2.8 billion
 $ 10.8 million
 $ 17.7 million
 $ 1.8 billion
 $ 0.1 billion

 N/A
 N/A
 N/A
 N/A
 N/A
 N/A

 State net operating losses
 $ 0.4 billion
 $ 5.7 billion
 $ 0.1 billion
 $ 0.2 billion
 $ 1 million
 $ 0.2 billion

 2028-2032
 N/A
 2040-2042
 N/A
 2028
 N/A

 Misc. federal credits
 $ 10 million
 $ 16.9 million
 $ 3.9 million
 $ 16.1 million
 $ 0.8 million
 $ 4.8 million

 2038-2043
 2035-2043
 2038-2043
 2037-2043
 2039-2043
 2029-2043

 State credits
 $ 8 million
 $ 1.6 million
 $ 19 million

 N/A
 N/A
 2024-2026
 N/A
 2027-2033
 2024-2027

 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:

 2023
 2022
 2021

 Gross balance at January 1
 $ 6,393,599
 $ 5,759,968
 $ 5,699,339

 Additions based on tax positions related to the current year
 332,884
 792,134
 101,623

 Additions for tax positions of prior years
 194,894
 37,259
 33,419

 Reductions for tax positions of prior years (a)
 ( 1,300,381)
 ( 195,762)
 ( 74,413)

 Settlements (a)
 ( 3,181,086)
 —
 —

 Gross balance at December 31
 2,439,910
 6,393,599
 5,759,968

 Offsets to gross unrecognized tax benefits:

 Loss and tax credit carryovers
 ( 2,160,484)
 ( 5,566,212)
 ( 4,987,799)

 Cash paid to taxing authorities
 —
 ( 82,000)
 ( 60,000)

 Unrecognized tax benefits net of unused tax attributes and payments (b)
 $ 279,426
 $ 745,387
 $ 712,169

 (a)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.
 (b)Potential tax liability above what is payable on tax returns.

 The balances of unrecognized tax benefits include $ 1,899 million, $ 3,254 million, and $ 2,256 million as of December 31, 2023, 2022, and 2021, 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 $ 541 million, $ 3,140 million, and $ 3,504 million as of December 31, 2023, 2022, and 2021, 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, 2023, 2022, and 2021 accrued balance for the possible payment of interest is approximately $ 39 million, $ 50 million, and $ 52 million, respectively. Interest (net-of-tax) of ($ 11) million, $ 8 million, and ($ 4) million was recorded in 2023, 2022, and 2021, respectively.

 A reconciliation of the Registrant Subsidiaries' beginning and ending amount of unrecognized tax benefits for 2023, 2022, and 2021 is as follows:

 2023

 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 (a)
 2,249
 332,320

 Additions for tax positions of prior years
 —
 —
 —
 —
 94,793
 —

 Reductions for tax positions of prior years (b)
 ( 148,558)
 ( 458,072)
 ( 16,853)
 ( 191,336)
 ( 67,156)
 ( 9,532)

 Settlements (b)
 ( 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
 $ —

 2022

 Gross balance at January 1, 2022
 $ 1,408,494
 $ 604,628
 $ 549,569
 $ 639,497
 $ 552,295
 $ 23,356

 Additions based on tax positions related to the current year (a)
 40,502
 750,320

 Additions for tax positions of prior years
 6,233
 10,262
 1,122

 Reductions for tax positions of prior years
 ( 2,410)
 ( 14,374)
 ( 3,328)
 ( 1,236)
 ( 163,903)
 ( 1,105)

 Gross balance at December 31, 2022
 1,452,819
 1,350,836
 547,548
 638,726
 389,366
 23,702

 Offsets to gross unrecognized tax benefits:

 Loss and tax credit carryovers
 ( 1,277,414)
 ( 1,328,916)
 ( 504,940)
 ( 455,928)
 ( 377,054)
 ( 23,702)

 Unrecognized tax benefits net of unused tax attributes
 $ 175,405
 $ 21,920
 $ 42,608
 $ 182,798
 $ 12,312
 $ —

 2021

 Gross balance at January 1, 2021
 $ 1,364,635
 $ 640,295
 $ 549,717
 $ 639,546
 $ 521,932
 $ 21,652

 Additions based on tax positions related to the current year
 30,419
 13,437
 1,050
 32,616
 1,753

 Additions for tax positions of prior years
 15,013
 9,304
 1,504
 2,315
 1,897

 Reductions for tax positions of prior years
 ( 1,573)
 ( 58,408)
 ( 2,336)
 ( 1,105)
 ( 4,568)
 ( 1,946)

 Gross balance at December 31, 2021
 1,408,494
 604,628
 549,569
 639,497
 552,295
 23,356

 Offsets to gross unrecognized tax benefits:

 Loss and tax credit carryovers
 ( 992,643)
 ( 604,628)
 ( 388,728)
 ( 484,899)
 ( 540,694)
 ( 8,576)

 Unrecognized tax benefits net of unused tax attributes
 $ 415,851
 $ —
 $ 160,841
 $ 154,598
 $ 11,601
 $ 14,780

 (a)The primary additions for Entergy Louisiana in 2022 and 2023 are related to the Entergy Louisiana securitizations as discussed in "Other Tax Matters - Act 293 Securitizations" 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.

 The Registrant Subsidiaries' balances of unrecognized tax benefits included amounts which, if recognized, would have reduced income tax expense as follows:

 2023
 2022
 2021

 $ 57.2
 $ 377.9
 $ 262.1

 $ 862.5
 $ 720.8
 $ 66.3

 $ 1.0
 $ 151.2
 $ 51.7

 $ 18.2
 $ 310.7
 $ 228.6

 $ 2.9
 $ 3.3
 $ 2.6

 $ 3.1
 $ 2.5
 $ 1.7

 Accrued balances for the possible payment of interest related to unrecognized tax benefits for the Registrant Subsidiaries are as follows:

 2023
 2022
 2021

 $ 7.8
 $ 4.3
 $ 2.7

 $ 1.5
 $ 4.1
 $ 3.7

 $ 2.1
 $ 3.1
 $ 2.4

 $ 0.6
 $ 6.4
 $ 5.2

 $ —
 $ 1.1
 $ 1.1

 $ 1.9
 $ 1.9
 $ 12.1

 The Registrant Subsidiaries record interest and penalties related to unrecognized tax benefits in income tax expense. No penalties were recorded in 2023, 2022, and 2021. Interest (net-of-tax) was recorded as follows:

 2023
 2022
 2021

 $ 3.5
 $ 1.6
 $ 0.4

 ($ 2.6)
 $ 0.4
 $ 0.3

 ($ 1.0)
 $ 0.7
 $ 0.5

 ($ 5.8)
 $ 1.2
 $ 1.3

 ($ 1.1)
 $ —
 $ 0.2

 $ —
 ($ 10.2)
 $ 0.2

 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 2014. 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 results 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.

 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 deductible temporary difference. 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 primarily associated with the effect of the Tax Cuts and Jobs Act rate reduction discussed below.

 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 deductible temporary difference. 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 deductible temporary differences 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

 Energy. The IRS audit adjustments were also factored into the settle-up required under Entergy's intercompany income tax allocation agreement, and such amounts were settled in the fourth quarter of 2023.

 Regulatory and Other Matters

 Additional customer credits related to the audit outcome may be due 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. A regulatory liability and associated regulatory charge of $ 38 million and $ 60 million ($ 28 million and $ 44 million net-of-tax) were recorded for Entergy Louisiana and Entergy New Orleans, respectively. The inclusion of the effects of the audit on customer rates is subject to the review and approval of the retail regulators. Additionally, 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 for 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.

 Reversal of net deferred credits associated with the accounting for income taxes upon the resolution of the IRS audit resulted in a reduction/(increase) of income tax expense 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.

 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

 As a result of income tax audit adjustments proposed by the Arkansas Department of Finance and Administration, an Entergy subsidiary in the non-utility operations business recorded a provision in third quarter 2022 for uncertain tax positions of approximately $ 21 million, which includes interest expense.

 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 remaining regulatory liabilities of $ 1.0 billion and $ 1.3 billion as of December 31, 2023 and December 31, 2022, respectively, mainly associated with the re-measurement of deferred tax assets and liabilities from the income tax rate change, subsequent amortization of excess ADIT, and payments to customers since the enactment of the TCJA. In addition to the protected and unprotected excess ADIT amounts, the net regulatory liability for income taxes includes other regulatory assets and liabilities for income taxes mainly for AFUDC, which is described in Note 1 to the financial statements.

 Entergy's regulatory liability for income taxes includes a gross-up at the applicable tax rate because of the effect that excess ADIT has on the ratemaking formula. The regulatory liability for income taxes includes the effect

 of (1) the reduction of the net deferred tax liability resulting in excess ADIT, and (2) the tax gross-up of excess ADIT. The Registrant Subsidiaries' December 31, 2023 and December 31, 2022 balance sheets reflect net regulatory liabilities for income taxes as follows:

 2023
 2022

 $ 392
 $ 435

 $ 194
 $ 338

 $ 189
 $ 202

 $ 36
 $ 40

 $ 115
 $ 133

 $ 107
 $ 111

 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". See Note 2 to the financial statements for discussion of Entergy Louisiana's $ 106 million reversal of a regulatory liability, associated with the Hurricane Isaac securitization, recognized in 2017 as a result of the TCJA, recorded in fourth quarter 2023. The majority of the remaining unamortized Excess ADIT as of December 31, 2023 is classified as protected. The TCJA provides that the normalization method of accounting for income taxes is required for excess ADIT associated with public utility property. The TCJA provides for the use of the average rate assumption method (ARAM) for the determination of 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 conformity with the normalization requirements.

 During the second quarter 2018, the Registrant Subsidiaries began returning unprotected excess accumulated deferred income taxes, associated with the effects of the TCJA, to their customers through rate riders and other means approved by their respective regulatory authorities. Return of the unprotected excess accumulated deferred income taxes results in a reduction in the regulatory liability for income taxes and a corresponding reduction in income tax expense. This manner of regulatory accounting affects the effective tax rate for the period as compared to the statutory tax rate. There was no return of unprotected excess accumulated deferred income taxes for Entergy or the Registrant Subsidiaries for the year ended December 31, 2023. For the year ended December 31, 2022, the return of unprotected excess accumulated deferred income taxes reduced the regulatory liability for income taxes by $ 53 million for Entergy, including $ 25 million for Entergy Louisiana, $ 1 million for Entergy New Orleans, and $ 27 million for Entergy Texas.

 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 plants. Additionally, the Inflation Reduction Act of 2022 enacted a 1 % excise tax on the buyback of public company stock and a new corporate alternative minimum tax. There are no effects on the financial statements of Entergy or the Registrant Subsidiaries as of and for the years ended December 31, 2023 and 2022 related to the enactment of the law. See the "Income Tax Legislation and Regulation" section of Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis for additional discussion of the effects of the Inflation Reduction Act of 2022.

 Restructuring of Entergy's Non-Utility Operations Business in 2020

 In the fourth quarter 2020, Entergy's ownership of Palisades was restructured. The restructuring required Entergy to recognize Palisades' nuclear decommissioning liability for income tax purposes resulting in a tax accounting permanent difference that reduced income tax expense, net of unrecognized tax benefits, by $ 9.2 million. The accrual of the nuclear decommissioning liability also required Entergy to recognize a gain for income tax purposes, a portion of which resulted in an increase in the tax basis of the assets. Recognition of the gain and the increase in the tax basis of the assets represents a tax accounting temporary difference.

 Tax Accounting Methods

 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.

 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 deductible temporary difference.

 Arkansas and Louisiana Corporate Income Tax Rate Changes

 Since 2019, the State of Arkansas has enacted corporate income tax law changes that phased in rate reductions from the former rate of 6.5 % to 6.2 % in 2021, 5.9 % in 2022, 5.1 % in 2023, and 4.8 % in 2024. Legislation in 2022 accelerated the rate reduction to 5.3 % for tax years beginning on or after January 1, 2023, accelerating the rate reductions that were originally scheduled to take effect in the 2025 tax year. As a result of the rate reductions, Entergy Arkansas has recorded regulatory liabilities for income taxes of approximately $ 26 million, $ 15 million, $ 11 million, and $ 21 million in 2023, 2022, 2021, and 2020, 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 the approved rate mechanisms. The Arkansas tax law enactment also phases in an increase to the net operating loss carryover period from five to ten years.

 Pursuant to legislation enacted in 2021 and approved by Louisiana citizens by amendment to the state constitution, beginning January 1, 2022, federal income taxes paid are no longer deductible for state income tax purposes, and the top Louisiana corporate income tax rate has been reduced from 8 % to 7.5 %. As a result of this change in Louisiana tax law, the Louisiana applicable tax rate increased by 0.85 %. Accordingly, deferred tax assets and liabilities were adjusted to reflect the new applicable federal and state rates. In fourth quarter 2021, Entergy recorded a net increase to its deferred tax asset of $ 27 million. Entergy Louisiana and Entergy New Orleans recorded net increases to their deferred tax liabilities before consideration of the tax gross-up of $ 77 million and $ 8 million, respectively, which were offset by regulatory assets for income taxes. Therefore, these increases had no effect on tax expense. However, the increase of deferred tax assets associated with certain assets reduced tax expense for Entergy Louisiana and Entergy New Orleans by $ 6 million and $ 2 million, respectively. The legislation enacted in 2021 also provided that Louisiana net operating losses generally have an indefinite carryover period.

 Act 293 Securitizations

 As described in Note 2 to the financial statements, Entergy Louisiana has implemented two separate securitization transactions authorized under Act 293 of the Louisiana Legislature's Regular Session of 2021. The first transaction occurred in May of 2022 and the second occurred in March of 2023. 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.

 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 in March 2023 and $ 290 million in May 2022, both 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 in March 2023 and $ 283 million in May 2022, both 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 and $ 224 million ($ 165 million net-of-tax) in second quarter 2022 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 and May 2022 storm cost securitizations.

 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)

 Entergy Corporation has in place a credit facility that has a borrowing capacity of $ 3.5 billion and expires in June 2028. 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. The weighted-average interest rate for the year ended December 31, 2023 was 6.52 % on the drawn portion of the facility. The f ollowing is a summary of the amounts outstanding and capacity available under the credit facility as of December 31, 2023:

 Capacity
 Borrowings
 Letters of Credit
 Capacity Available

 $ 3,500
 $ —
 $ 3
 $ 3,497

 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.

 Entergy Corporation has a commercial paper program with a Board-approved program limit of $ 2 billion. As of December 31, 2023, Entergy Corporation had $ 1,138.1 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2023 was 5.44 %.

 Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2023 as follows:

 Expiration Date
 Amount of Facility
 Interest Rate (a)
 Amount Drawn
as of
 Letters of Credit Outstanding as of December 31, 2023

 April 2024
 $ 25 million (b)
 7.29 %
 —
 —

 $ 150 million (c)
 6.58 %
 —
 —

 $ 350 million (c)
 6.71 %
 —
 —

 July 2025
 $ 150 million
 6.58 %
 —
 —

 June 2024
 $ 25 million (c)
 7.08 %
 —
 —

 $ 150 million (c)
 6.71 %
 —
 $ 1.1 million

 (a)The interest rate is the estimated interest rate as of December 31, 2023 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; $ 10 million for Entergy New Orleans; and $ 30 million for Entergy Texas.

 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 an uncommitted standby letter of credit facility 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, 2023:

 Amount of Uncommitted Facility
 Letter of Credit Fee
 Letters of Credit Issued as of
(a) (b)

 $ 25 million
 0.78 %
 $ 5.8 million

 $ 125 million
 0.78 %
 $ 17.1 million

 $ 65 million
 0.78 %
 $ 20 million

 $ 15 million
 1.625 %
 $ 0.5 million

 $ 80 million
 1.250 %
 $ 76.5 million

 (a)As of December 31, 2023, letters of credit posted with MISO covered financial transmission rights exposure of $ 1.2 million for Entergy Arkansas, $ 0.5 million for Entergy Louisiana, $ 0.3 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, 2023, in addition to the $ 20 million MISO letters of credit, Entergy Mississippi had $ 1 million in a non-MISO letter of credit outstanding under this facility.

 The short-term borrowings of the Registrant Subsidiaries are limited to amounts authorized by the FERC. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas have FERC-authorized short-term borrowing limits effective through April 2025. The FERC-authorized short-term borrowing

 limit for System Energy is effective through March 2025. 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, 2023 (aggregating both internal and external short-term borrowings) for the Registrant Subsidiaries:

 Authorized
 Borrowings

 $ 250
 $ 145

 $ 450
 $ 156

 $ 200
 $ 74

 $ 150
 $ 22

 $ 200
 $ —

 $ 200
 $ 12

 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. The credit facility has a borrowing capacity of $ 139 million and expires in December 2024. The commitment fee is currently 0.20 % of the undrawn commitment amount. As of December 31, 2023, $ 139 million in cash borrowings were outstanding under the credit facility. The weighted-average interest rate for the year ended December 31, 2023 was 6.61 % on the drawn portion of the facility.

 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, 2023:

 Expiration Date
 Amount of Facility
 Weighted-Average Interest Rate on Borrowings (a)
 Amount Outstanding as of December 31, 2023

 (Dollars in Millions)

 Entergy Arkansas VIE
 June 2025
 $ 80
 6.10 %
 $ 70.2

 Entergy Louisiana River Bend VIE
 June 2025
 $ 105
 6.17 %
 $ 46.6

 Entergy Louisiana Waterford VIE
 June 2025
 $ 105
 6.07 %
 $ 29.5

 System Energy VIE
 June 2025
 $ 120
 5.91 %
 $ 21.5

 (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 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 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, 2023 as follows:

 Entergy Arkansas VIE
 1.84 % Series N due July 2026

 $ 90 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.

 As of December 31, 2023, Entergy Arkansas and Entergy Louisiana each has obtained financing authorization from the FERC that extends through April 2025 for issuances by its nuclear fuel company VIEs. System Energy has obtained financing authorization from the FERC that extends through March 2025 for issuances by its nuclear fuel company VIEs.

 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, 2023 and 2022 consisted of:

 Type of Debt and Maturity
 Weighted-Average Interest Rate December 31, 2023
 Interest Rate Ranges at December 31,
 Outstanding at

 2023
 2022
 2023
 2022

 Mortgage Bonds

 2023-2027
 3.05 %
 0.95 % - 5.40 %

 0.62 % - 5.59 %

 $ 4,668,000
 $ 6,808,000

 2028-2032
 2.88 %
 1.60 %- 6.00 %

 1.60 % - 4.19 %

 3,590,000
 3,265,000

 2033-2041
 4.12 %
 2.55 % - 5.30 %

 2.55 % - 4.52 %

 3,122,000
 2,097,000

 2044-2066
 4.22 %
 2.65 % - 5.80 %

 2.65 % - 5.50 %

 8,355,000
 8,005,000

 Governmental Bonds (a)

 2023-2044
 2.43 %
 2.0 % - 2.5 %

 2.0 % - 2.5 %

 282,375
 282,375

 Securitization Bonds

 2023-2036
 3.61 %
 2.67 % - 3.697 %

 2.67 % - 3.697 %

 267,003
 297,363

 Variable Interest Entities Notes Payable (Note 4)

 2023-2027
 2.85 %
 1.84 % - 5.94 %

 1.84 % - 3.22 %

 320,000
 310,000

 Entergy Corporation Notes

 due September 2025
 n/a
 0.9 %
 0.9 %
 800,000
 800,000

 due September 2026
 n/a
 2.95 %
 2.95 %
 750,000
 750,000

 due June 2028
 n/a
 1.9 %
 1.9 %

 due June 2030
 n/a
 2.80 %
 2.80 %

 due June 2031
 n/a
 2.40 %
 2.40 %

 due June 2050
 n/a
 3.75 %
 3.75 %

 Entergy New Orleans Unsecured Term Loan due May 2023
 n/a
 —
 2.5 %
 —

 Entergy New Orleans Unsecured Term Loan due June 2024
 n/a
 6.25 %
 —
 85,000
 —

 Entergy Mississippi Unsecured Term Loan due December 2023
 n/a
 —
 4.082 %
 —

 System Energy Term Loan due November 2023 (b)
 n/a
 —
 3.721 %
 —
 50,000

 5 Year Credit Facility (Note 4)
 n/a
 —
 2.97 %
 —

 Entergy Louisiana Credit Facility (Note 4)
 n/a
 —
 7.75 %
 —
 50,000

 Vermont Yankee Credit Facility (Note 4)
 n/a
 6.61 %
 3.19 %
 139,000
 139,000

 Entergy Arkansas VIE Credit Facility (Note 4)
 n/a
 6.10 %
 2.62 %
 70,200
 —

 Entergy Louisiana River Bend VIE Credit Facility (Note 4)
 n/a
 6.17 %
 2.17 %
 46,600
 13,100

 Entergy Louisiana Waterford VIE Credit Facility (Note 4)
 n/a
 6.07 %
 2.74 %
 29,500
 60,800

 System Energy VIE Credit Facility (Note 4)
 n/a
 5.91 %
 2.77 %
 21,500
 72,600

 Long-term DOE Obligation (c)
 —
 —
 —
 205,151
 195,044

 Grand Gulf Sale-Leaseback Obligation
 n/a
 —
 —
 34,260
 34,297

 Unamortized Premium and Discount - Net

 ( 11,638)

 ( 171,475)
 ( 173,464)

 Other

 5,420
 5,474

 25,107,896
 25,932,549

 2,099,057
 2,309,037

 $ 23,008,839
 $ 23,623,512

 $ 22,489,174
 $ 22,573,837

 (a)Consists of pollution control revenue bonds and environmental revenue bonds, some of which are secured by collateral mortgage bonds.
 (b)The debt is secured by a series of collateral mortgage bonds.
 (c)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, 2023, for the next five years are as follows:

 2024
 $ 2,100,275

 2025
 $ 1,546,940

 2026
 $ 2,375,720

 2027
 $ 916,965

 2028
 $ 2,195,627

 Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas have obtained long-term financing authorizations from the FERC that extend through April 2025. The FERC-authorized long-term borrowing limit for System Energy is effective through March 2025. Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through December 2025. Entergy Arkansas has also obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2025.

 Long-term debt for the Registrant Subsidiaries as of December 31, 2023 and 2022 consisted of:

 2023
 2022

 3.05 % Series due June 2023

 $ —
 $ 250,000

 3.70 % Series due June 2024

 3.5 % Series due April 2026

 4.00 % Series due June 2028

 350,000
 350,000

 5.15 % Series due January 2033

 425,000
 —

 5.30 % Series due September 2033

 —

 4.95 % Series due December 2044

 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

 4.875 % Series due September 2066

 410,000
 410,000

 4,335,000
 3,860,000

 Variable Interest Entity Notes Payable and Credit Facility (Note 4):

 3.17 % Series M due December 2023

 —
 40,000

 1.84 % Series N due July 2026

 Credit Facility due June 2025, weighted-average rate 6.10 %

 70,200
 —

 Total variable interest entity notes payable and credit facility
 160,200
 130,000

 Long-term DOE Obligation (b)
 205,151
 195,044

 Unamortized Premium and Discount – Net
 7,508
 12,513

 ( 36,711)
 ( 33,009)

 Other
 1,932
 1,952

 4,673,080
 4,166,500

 290,000

 $ 4,298,080
 $ 3,876,500

 $ 4,166,941
 $ 3,538,930

 2023
 2022

 4.05 % Series due September 2023

 $ —
 $ 325,000

 0.62 % Series due November 2023

 —
 665,000

 5.59 % Series due October 2024

 —

 0.95 % Series due October 2024

 5.40 % Series due November 2024

 3.78 % Series due April 2025

 3.78 % Series due April 2025

 190,000
 190,000

 4.44 % Series due January 2026

 2.40 % Series due October 2026

 3.12 % Series due September 2027

 3.25 % Series due April 2028

 425,000
 425,000

 1.60 % Series due December 2030

 3.05 % Series due June 2031

 2.35 % Series due June 2032

 4.00 % Series due March 2033

 750,000
 750,000

 3.10 % Series due June 2041

 5 % Series due July 2044

 170,000
 170,000

 4.95 % Series due January 2045

 4.20 % Series due September 2048

 900,000
 900,000

 4.20 % Series due April 2050

 525,000
 525,000

 2.90 % Series due March 2051

 4.75 % Series due September 2052

 4.875 % Series due September 2066

 270,000
 270,000

 9,065,000
 10,355,000

 Governmental Bonds (a):

 2.00 % Series due June 2030, Louisiana Local Government Environmental Facilities and Community Development Authority (c)

 16,200
 16,200

 2.50 % Series due April 2036, Louisiana Local Government Environmental Facilities and Community Development Authority (c)

 182,480
 182,480

 Total governmental bonds
 198,680
 198,680

 Variable Interest Entity Notes Payable and Credit Facilities (Note 4):

 3.22 % Series I due December 2023

 —
 20,000

 5.94 % Series J due September 2026

 —

 2.51 % Series V due June 2027

 Credit Facility due June 2025, weighted-average rate 6.17 %

 46,600
 13,100

 Credit Facility due June 2025, weighted-average rate 6.07 %

 29,500
 60,800

 Total variable interest entity notes payable and credit facilities
 216,100
 163,900

 Credit Facility due June 2027, weighted-average rate 7.75 %

 —
 50,000

 Unamortized Premium and Discount - Net
 ( 6,478)
 ( 8,482)

 ( 56,101)
 ( 63,698)

 Other
 3,488
 3,522

 9,420,689
 10,698,922

 1,010,000

 $ 8,020,689
 $ 9,688,922

 $ 8,414,512
 $ 9,444,665

 2023
 2022

 3.10 % Series due July 2023

 $ —
 $ 250,000

 3.75 % Series due July 2024

 100,000
 100,000

 3.25 % Series due December 2027

 2.85 % Series due June 2028

 5.0 % Series due September 2033

 —

 2.55 % Series due December 2033

 200,000
 200,000

 4.52 % Series due December 2038

 55,000
 55,000

 3.85 % Series due June 2049

 435,000
 435,000

 3.50 % Series due June 2051

 370,000
 370,000

 4.90 % Series due October 2066

 260,000
 260,000

 2,245,000
 2,195,000

 Unsecured Term Loan due December 2023, weighted-average rate 4.082 %

 —

 Unamortized Premium and Discount – Net
 5,546
 5,803

 ( 21,036)
 ( 19,707)

 2,229,510
 2,331,096

 100,000

 $ 2,129,510
 $ 1,931,096

 $ 1,969,334
 $ 1,987,154

 2023
 2022

 3.90 % Series due July 2023

 $ —
 $ 100,000

 3.0 % Series due March 2025

 78,000
 78,000

 4.0 % Series due June 2026

 85,000
 85,000

 4.19 % Series due November 2031

 4.51 % Series due September 2033

 60,000
 60,000

 4.51 % Series due November 2036

 3.75 % Series due March 2040

 62,000
 62,000

 5.0 % Series due December 2052

 30,000
 30,000

 5.50 % Series due April 2066

 585,000
 685,000

 Securitization Bonds:

 2.67 % Series Senior Secured due June 2027

 6,245
 18,770

 Total securitization bonds
 6,245
 18,770

 2.5 % Unsecured Term Loan due May 2023

 —

 6.25 % Unsecured Term Loan due June 2024

 85,000
 —

 Payable to associated company due November 2035
 8,279
 9,585

 Unamortized Premium and Discount – Net
 ( 6)
 ( 25)

 ( 7,068)
 ( 7,698)

 677,450
 775,632

 86,275
 171,306

 $ 591,175
 $ 604,326

 $ 602,716
 $ 707,872

 2023
 2022

 1.50 % Series due September 2026

 $ 130,000
 $ 130,000

 3.45 % Series due December 2027

 4.0 % Series due March 2029

 1.75 % Series due March 2031

 4.5 % Series due March 2039

 5.15 % Series due June 2045

 3.55 % Series due September 2049

 475,000
 475,000

 5.00 % Series due September 2052

 5.80 % Series due September 2053

 350,000
 —

 2,980,000
 2,630,000

 Securitization Bonds:

 3.051 % Series Senior Secured, Series A Tranche A-1 due December 2028

 69,908
 87,743

 3.697 % Series Senior Secured, Series A Tranche A-2 due December 2036

 190,850
 190,850

 Total securitization bonds
 260,758
 278,593

 Unamortized Premium and Discount - Net
 10,199
 11,528

 ( 25,865)
 ( 24,208)

 3,225,092
 2,895,913

 —
 —

 $ 3,225,092
 $ 2,895,913

 $ 2,936,130
 $ 2,485,705

 2023
 2022

 4.10 % Series due April 2023

 $ —
 $ 250,000

 2.14 % Series due December 2025

 200,000
 200,000

 6.00 % Series due April 2028

 —

 525,000

 Governmental Bonds (a):

 2.375 % Series due June 2044, Mississippi Business Finance Corp. (c)

 83,695
 83,695

 Total governmental bonds
 83,695
 83,695

 Variable Interest Entity Notes Payable and Credit Facility (Note 4):

 2.05 % Series K due September 2027

 Credit Facility due June 2025, weighted-average rate 5.91 %

 21,500
 72,600

 Total variable interest entity notes payable and credit facility
 111,500
 162,600

 Term Loan due November 2023, weighted-average rate 3.721 % (c)

 —
 50,000

 Grand Gulf Sale-Leaseback Obligation
 34,260
 34,297

 Unamortized Premium and Discount – Net
 ( 10,451)
 ( 50)

 ( 5,545)
 ( 2,637)

 738,459
 777,905

 300,037

 $ 738,402
 $ 477,868

 $ 696,168
 $ 702,473

 (a)Consists of pollution control revenue bonds.

 (b)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.
 (c)The debt is secured by a series of collateral mortgage bonds.

 The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2023, for the next five years are as follows:

 2024
 $ 375,000
 $ 1,400,000
 $ 100,000
 $ 86,275
 $ —
 $ —

 2025
 $ 70,200
 $ 376,100
 $ —
 $ 79,140
 $ —
 $ 221,500

 2026
 $ 690,000
 $ 720,000
 $ —
 $ 85,720
 $ 130,000
 $ —

 2027
 $ —
 $ 520,000
 $ 150,000
 $ 6,965
 $ 150,000
 $ 90,000

 2028
 $ 350,000
 $ 425,000
 $ 375,000
 $ 719
 $ 69,908
 $ 325,000

 Securitization Bonds

 Entergy Louisiana Securitization Bonds – Little Gypsy

 In August 2011 the LPSC issued a financing order authorizing the issuance of bonds to recover Entergy Louisiana's investment recovery costs associated with the canceled Little Gypsy repowering project. In September 2011, Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, issued $ 207.2 million of senior secured investment recovery bonds. The bonds had an interest rate of 2.04 %. Although the principal amount was not due until September 2023, Entergy Louisiana Investment Recovery Funding made principal payments on the bonds in the amount of $ 11 million in 2021, after which the bonds were fully repaid.

 Entergy New Orleans Securitization Bonds - Hurricane Isaac

 In May 2015 the City Council issued a financing order authorizing the issuance of securitization bonds to recover Entergy New Orleans's Hurricane Isaac storm restoration costs of $ 31.8 million, including carrying costs, the costs of funding and replenishing the storm recovery reserve in the amount of $ 63.9 million, and approximately $ 3 million of up-front financing costs associated with the securitization. In July 2015, Entergy New Orleans Storm Recovery Funding I, L.L.C., a company wholly owned and consolidated by Entergy New Orleans, issued $ 98.7 million of storm cost recovery bonds. The bonds have a coupon of 2.67 %. Although the principal amount is not due until June 2027, Entergy New Orleans Storm Recovery Funding expects to make principal payments on the bonds in 2024 in the amount of $ 6.2 million, after which the bonds will be fully repaid. With the proceeds, Entergy New Orleans Storm Recovery Funding purchased from Entergy New Orleans the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy New Orleans balance sheet. The creditors of Entergy New Orleans do not have recourse to the assets or revenues of Entergy New Orleans Storm Recovery Funding, including the storm recovery property, and the creditors of Entergy New Orleans Storm Recovery Funding do not have recourse to the assets or revenues of Entergy New Orleans. Entergy New Orleans has no payment obligations to Entergy New Orleans Storm Recovery Funding except to remit storm recovery charge collections.

 Entergy Texas Securitization Bonds - Hurricane Rita

 In April 2007 the PUCT issued a financing order authorizing the issuance of securitization bonds to recover $ 353 million of Entergy Texas's Hurricane Rita reconstruction costs and up to $ 6 million of transaction costs, offset by $ 32 million of related deferred income tax benefits. In June 2007, Entergy Gulf States Reconstruction Funding I, LLC, a company that is now wholly-owned and consolidated by Entergy Texas, issued $ 329.5 million of senior secured transition bonds (securitization bonds). Although the principal amount was not due until June 2022, Entergy Gulf States Reconstruction Funding made principal payments on the bonds in the amount of $ 17.5 million in 2021, after which the bonds were fully repaid.

 Entergy Texas Securitization Bonds - Hurricane Ike and Hurricane Gustav

 In September 2009 the PUCT authorized the issuance of securitization bonds to recover $ 566.4 million of Entergy Texas's Hurricane Ike and Hurricane Gustav restoration costs, plus carrying costs and transaction costs, offset by insurance proceeds. In November 2009, Entergy Texas Restoration Funding, LLC (Entergy Texas Restoration Funding), a company wholly-owned and consolidated by Entergy Texas, issued $ 545.9 million of senior secured transition bonds (securitization bonds). Although the principal amount was not due until November 2023, Entergy Texas Restoration Funding made principal payments on the bonds in the amount of $ 54.3 million in 2022, after which the bonds were fully repaid.

 Entergy Texas Securitization Bonds - Hurricane Laura, Hurricane Delta, and Winter Storm Uri

 In January 2022 the PUCT authorized the issuance of securitization bonds to recover $ 242.9 million of Entergy Texas's Hurricane Laura, Hurricane Delta, and Winter Storm Uri restoration costs, plus carrying costs, plus approximately $ 13.3 million relating to a system restoration regulatory asset related to Hurricane Harvey, plus up-front qualified costs. In April 2022, Entergy Texas Restoration Funding II, LLC, a company wholly-owned and consolidated by Entergy Texas, issued $ 290.85 million of senior secured system restoration bonds (securitization bonds), as follows:

 Senior Secured System Restoration Bonds:

 Tranche A-1 ( 3.051 %) due December 2028

 $ 100,000

 Tranche A-2 ( 3.697 %) due December 2036

 190,850

 Total senior secured system restoration bonds
 $ 290,850

 Although the principal amount of each tranche is not due until the dates given above, Entergy Texas Restoration Funding II expects to make principal payments on the securitization bonds over the next four years in the amounts of $ 18.3 million for 2024, $ 18.8 million for 2025, $ 19.4 million for 2026, and $ 13.4 million for 2027 for Tranche A-1, after which Tranche A-1 will be fully repaid. Entergy Texas Restoration Funding II expects to begin principal payments for Tranche A-2 in 2027 with payments of $ 6.6 million in 2027 and $ 20.5 million in 2028.

 With the proceeds, Entergy Texas Restoration Funding II purchased from Entergy Texas the transition property, which is the right to recover from customers through a system restoration charge amounts sufficient to service the securitization bonds. Entergy Texas expects to use the proceeds to reduce its outstanding debt. The creditors of Entergy Texas do not have recourse to the assets or revenues of Entergy Texas Restoration Funding II, including the transition property, and the creditors of Entergy Texas Restoration Funding II do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to Entergy Texas Restoration Funding II except to remit system restoration charge collections.

 Grand Gulf Sale-Leaseback Transactions

 In 1988, in two separate but substantially identical transactions, System Energy sold and leased back undivided ownership interests in Grand Gulf for the aggregate sum of $ 500 million. The initial term of the leases expired in July 2015. System Energy renewed the leases in December 2013 for fair market value with renewal terms expiring in July 2036. At the end of the new lease renewal terms, System Energy has the option to repurchase the leased interests in Grand Gulf or renew the leases at fair market value. In the event that System Energy does not renew or purchase the interests, System Energy would surrender such interests and their associated entitlement of Grand Gulf's capacity and energy.

 System Energy is required to report the sale-leaseback as a financing transaction in its financial statements. As such, it has recognized debt for the lease obligation and retained the portion of the plant subject to the sale-leaseback on its balance sheet. For financial reporting purposes, System Energy has recognized interest expense on the debt balance and depreciation on the applicable plant balance. The lease payments are recognized as principal and interest payments on the debt balance.

 As of December 31, 2023, System Energy, in connection with the Grand Gulf sale and leaseback transactions, had future minimum lease payments that are recorded as long-term debt, as follows, which reflects the effect of the December 2013 renewal:

 2024
 $ 17,188

 2025
 17,188

 2026
 17,188

 2027
 17,188

 2028
 17,188

 Years thereafter
 137,500

 Total
 223,440

 Less: Amount representing interest
 189,180

 Present value of net minimum lease payments
 $ 34,260

 NOTE 6. PREFERRED EQUITY AND NONCONTROLLING INTERESTS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas)

 In May 2021, Entergy's certificate of incorporation was amended and restated to provide authority to issue up to 1,000,000 shares of preferred stock, no par value per share, and to decrease from 500,000,000 to 499,000,000 the number of shares of common stock, par value of $ 0.01 per share, authorized for issuance. As of December 31, 2023 and 2022, no preferred stock has been issued.

 The number of shares and units authorized and outstanding and dollar value of preferred stock, preferred membership interests, and noncontrolling interests for Entergy Corporation subsidiaries as of December 31, 2023 and 2022 are presented below.

 Shares/Units
Authorized
 Shares/Units
Outstanding

 2023
 2022
 2023
 2022
 2023
 2022

 (Dollars in Thousands)

 Preferred stock or preferred membership interests without sinking fund presented between liabilities and equity:

 Entergy Utility Holding Company, LLC, 7.5 % Series (a)

 $ 107,425
 $ 107,425

 Entergy Utility Holding Company, LLC, 6.25 % Series (b)

 14,366
 14,366

 Entergy Utility Holding Company, LLC, 6.75 % Series (c)

 73,370
 73,370

 Entergy Finance Holding, Inc. 8.75 % (d)

 24,249
 24,249

 Total preferred stock or preferred membership interests without sinking fund presented between liabilities and equity
 219,410
 219,410

 Preferred stock without sinking fund and noncontrolling interests presented as equity:

 Entergy Texas, 5.375 % Series

 35,000
 35,000

 Entergy Texas, 5.10 % Series (e)

 —
 —
 —
 —

 Entergy Arkansas Noncontrolling Interest
 —
 —
 —
 —
 21,599
 27,825

 Entergy Louisiana Noncontrolling Interests
 —
 —
 —
 —
 45,107
 31,735

 Entergy Mississippi Noncontrolling Interest
 —
 —
 —
 —
 18,753
 3,347

 Total preferred stock without sinking fund and noncontrolling interests presented as equity
 1,550,000
 1,550,000
 120,459
 97,907

 Total subsidiaries' preferred stock or preferred membership interests without sinking fund and noncontrolling interests
 2,000,000
 2,000,000
 1,850,000
 1,850,000
 $ 339,869
 $ 317,317

 (a)In October 2015, Entergy Utility Holding Company, LLC issued 110,000 units of $ 1,000 liquidation value 7.5 % Series A Preferred Membership Interests, all of which are outstanding as of December 31, 2023. The distributions are cumulative and payable quarterly. These units are redeemable on or after January 1, 2036, at Entergy Utility Holding Company, LLC's option, at the fixed redemption price of $ 1,000 per unit. Dollar amount outstanding is net of $ 2,575 thousand of preferred stock issuance costs.
 (b)In November 2017, Entergy Utility Holding Company, LLC issued 15,000 units of $ 1,000 liquidation value 6.25 % Series B Preferred Membership Interests, all of which are outstanding as of December 31, 2023. The distributions are cumulative and payable quarterly. These units are redeemable on or after February 28, 2038, at Entergy Utility Holding Company, LLC's option, at the fixed redemption price of $ 1,000 per unit. Dollar amount outstanding is net of $ 634 thousand of preferred stock issuance costs.
 (c)In November 2018, Entergy Utility Holding Company, LLC issued 75,000 units of $ 1,000 liquidation value 6.75 % Series C Preferred Membership Interests, all of which are outstanding as of December 31, 2023. The distributions are cumulative and payable quarterly. These units are redeemable on or after February 28, 2039, at Entergy Utility Holding Company, LLC's option, at the fixed redemption price of $ 1,000 per unit. Dollar amount outstanding is net of $ 1,630 thousand of preferred stock issuance costs.

 (d)In December 2013, Entergy Finance Holding, Inc. issued 250,000 shares of $ 100 par value 8.75 % Series Preferred Stock, all of which are outstanding as of December 31, 2023. The dividends are cumulative and payable quarterly. The preferred stock is redeemable on or after December 16, 2023, at Entergy Finance Holding, Inc.'s option, at the fixed redemption price of $ 100 per share. Dollar amount outstanding is net of $ 751 thousand of preferred stock issuance costs.
 (e)Currently, all shares are held by Entergy Corporation.

 The number of shares authorized and outstanding and dollar value of preferred stock for Entergy Texas as of December 31, 2023 and 2022 are presented below.

Authorized
and Outstanding
 Call Price per
Share as of

 2023
 2022
 2023
 2022
 2023

 Entergy Texas Preferred Stock

 (Dollars in Thousands)

 Without sinking fund:

 Cumulative, $ 25 par value:

 5.375 % Series (a)

 $ 35,000
 $ 35,000
 $ —

 5.10 % Series (b)

 3,750
 3,750
 $ 25.50

 Total without sinking fund
 1,550,000
 1,550,000

 (a)In September 2019, Entergy Texas issued $ 35 million of 5.375 % Series A Preferred Stock, a total of 1,400,000 shares with a liquidation value of $ 25 per share, all of which are outstanding as of December 31, 2023. The dividends are cumulative and payable quarterly. The preferred stock is redeemable on or after October 15, 2024 at Entergy Texas's option, at a fixed redemption price of $ 25 per share.
 (b)In November 2021, Entergy Texas issued $ 3.75 million of 5.10 % Series B Preferred Stock, a total of 150,000 shares with a liquidation value of $ 25 per share, all of which are outstanding and held by Entergy Corporation as of December 31, 2023. The dividends are cumulative and payable quarterly. The preferred stock is redeemable at Entergy Texas's option at a fixed redemption price of $ 25.50 per share prior to November 1, 2026 and at a fixed redemption price of $ 25 per share on or after November 1, 2026.

 Dividends and distributions paid on all of Entergy Corporation's subsidiaries' preferred stock and membership interests series may be eligible for the dividends received deduction.

 The dollar value of noncontrolling interest for Entergy Arkansas as of December 31, 2023 and 2022 is presented below.

 2023
 2022

 Entergy Arkansas Noncontrolling Interest

 AR Searcy Partnership, LLC (a)
 $ 21,599
 $ 27,825

 Total Noncontrolling Interest
 $ 21,599
 $ 27,825

 (a)AR Searcy Partnership, LLC is a tax equity partnership between Entergy Arkansas and a tax equity investor which was formed to acquire and own the Searcy Solar facility. Entergy Arkansas, as the managing member, consolidates AR Searcy Partnership, LLC and the tax equity investor's interest is presented as noncontrolling interest in the financial statements. Entergy Arkansas uses the HLBV method of accounting for income or loss allocation to the tax equity investor's noncontrolling interest. See Note 1 to the financial statements for further discussion on the presentation of the tax equity investor's noncontrolling interest and the HLBV method of accounting.

 The dollar value of noncontrolling interests for Entergy Louisiana as of December 31, 2023 and 2022 are presented below.

 2023
 2022

 Entergy Louisiana Noncontrolling Interests

 Restoration Law Trust I (a)
 $ 30,488
 $ 31,735

 Restoration Law Trust II (b)
 14,619
 —

 Total Noncontrolling Interests
 $ 45,107
 $ 31,735

 (a)Restoration Law Trust I (the storm trust I) was established in 2022 as part of the Act 293 securitization of Entergy Louisiana's Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri restoration costs, as well as to establish a storm reserve to fund a portion of Hurricane Ida storm restoration costs. The storm trust I holds preferred membership interests issued by Entergy Finance Company, and Entergy Finance Company is required to make annual distributions (dividends) on the preferred membership interests. These annual dividends paid on the Entergy Finance Company preferred membership interests are distributed 1 % to the LURC and 99 % to Entergy Louisiana. Entergy Louisiana, as the primary beneficiary, consolidates the storm trust I and the LURC's 1 % beneficial interest is presented as noncontrolling interest in the consolidated financial statements for Entergy Louisiana and Entergy. See Note 2 to the financial statements for a discussion of the Entergy Louisiana May 2022 storm cost securitization.
 (b)Restoration Law Trust II (the storm trust II) was established in 2023 as part of the Act 293 securitization of Entergy Louisiana's remaining Hurricane Ida storm restoration costs. The storm trust II holds preferred membership interests issued by Entergy Finance Company, and Entergy Finance Company is required to make annual distributions (dividends) on the preferred membership interests. These annual dividends paid on the Entergy Finance Company preferred membership interests are distributed 1 % to the LURC and 99 % to Entergy Louisiana. Entergy Louisiana, as the primary beneficiary, consolidates the storm trust II and the LURC's 1 % beneficial interest is presented as noncontrolling interest in the consolidated financial statements for Entergy Louisiana and Entergy. See Note 2 to the financial statements for a discussion of the Entergy Louisiana March 2023 storm cost securitization.

 The dollar value of noncontrolling interest for Entergy Mississippi as of December 31, 2023 and 2022 is presented below.

 2023
 2022

 Entergy Mississippi Noncontrolling Interest

 MS Sunflower Partnership, LLC (a)
 $ 18,753
 $ 3,347

 Total Noncontrolling Interest
 $ 18,753
 $ 3,347

 (a)MS Sunflower Partnership, LLC is a tax equity partnership between Entergy Mississippi and a tax equity investor which was formed to acquire and own the Sunflower Solar facility. Entergy Mississippi, as the managing member, consolidates MS Sunflower Partnership, LLC and the tax equity investor's interest is presented as noncontrolling interest in the consolidated financial statements for Entergy Mississippi and Entergy. Entergy Mississippi uses the HLBV method of accounting for income or loss allocation to the tax equity investor's noncontrolling interest. See Note 1 to the financial statements for further discussion on the presentation of the tax equity investor's noncontrolling interest and the HLBV method of accounting.

 Presentation of Preferred Stock without Sinking Fund

 Accounting standards regarding noncontrolling interests and the classification and measurement of redeemable securities require the classification of preferred securities between liabilities and shareholders' equity on the balance sheet if the holders of those securities have protective rights that allow them to gain control of the board

 of directors in certain circumstances. These rights would have the effect of giving the holders the ability to potentially redeem their securities, even if the likelihood of occurrence of these circumstances is considered remote. The outstanding preferred stock of Entergy Texas has protective rights with respect to unpaid dividends but provides for the election of board members that would not constitute a majority of the board, and the preferred stock of Entergy Texas is therefore classified as a component of equity.

 The outstanding preferred securities of Entergy Utility Holding Company, LLC (a Utility subsidiary) and Entergy Finance Holding, Inc. (an Entergy subsidiary in the non-utility operations business), whose preferred holders have protective rights, are presented between liabilities and equity on Entergy's consolidated balance sheets. The preferred dividends or distributions paid by all subsidiaries are reflected for all periods presented outside of consolidated net income.

 NOTE 7. COMMON EQUITY (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

 Common Stock

 Common stock and treasury stock shares activity for Entergy for 2023, 2022, and 2021 is as follows:

 2023
 2022
 2021

Issued

 Treasury

Issued

 Treasury

Issued

 Treasury

 Beginning Balance, January 1
 279,653,929
 68,477,429
 271,965,510
 69,312,326
 270,035,180
 69,790,346

 Issuances:

 Equity Distribution Program
 1,321,419
 —
 7,688,419
 —
 1,930,330
 —

 Employee Stock-Based Compensation Plans
 —
 ( 336,621)
 —
 ( 818,366)
 —
 ( 461,903)

 Directors' Plan
 —
 ( 14,030)
 —
 ( 16,531)
 —
 ( 16,117)

 Ending Balance, December 31
 280,975,348
 68,126,778
 279,653,929
 68,477,429
 271,965,510
 69,312,326

 Entergy Corporation reissues treasury shares to meet the requirements of the Stock Plan for Outside Directors (Directors' Plan), the three equity plans of Entergy Corporation and Subsidiaries, and certain other stock benefit plans. The Directors' Plan awards to non-employee directors a portion of their compensation in the form of a fixed dollar value of shares of Entergy Corporation common stock.

 In October 2010 the Board granted authority for a $ 500 million share repurchase program. As of December 31, 2023, $ 350 million of authority remains under the $ 500 million share repurchase program.

 Dividends declared per common share were $ 4.34 in 2023, $ 4.10 in 2022, and $ 3.86 in 2021.

 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 $ 2 billion. As of December 31, 2023, an aggregate gross sales price of approximately $ 1.5 billion has been sold under the at market equity distribution program.

 During the year ended December 31, 2021, Entergy Corporation issued 1,930,330 shares of common stock under the at the market equity distribution program. The net sales proceeds from these shares totaled $ 200.8 million, which includes the gross sales price of $ 204.2 million received by Entergy Corporation less $ 1.4 million of general issuance costs and $ 2.0 million of aggregate compensation to the agents with respect to such sales. During the years ended December 31, 2023 and 2022, there were no shares of common stock issued under the at the market equity distribution program.

 In June, August, and October 2021, Entergy Corporation entered into forward sale agreements for 416,853 shares, 1,692,555 shares, and 250,743 shares of common stock, respectively. No amounts were recorded on Entergy's balance sheet with respect to the equity offerings until settlements of the equity forward sale agreements occurred in November 2022. The forward sale agreements required Entergy Corporation to, at its election prior to September 29, 2023, either (i) physically settle the transactions by issuing the total of 416,853 shares, 1,692,555 shares, and 250,743 shares, respectively, 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 approximately $ 106.87, $ 111.16, and $ 100.35 per share, respectively) or (ii) net settle the transactions in whole or in part through the delivery or receipt of cash or shares. Each forward sale price was subject to adjustment on a daily basis based on a floating interest rate factor and decreased by other fixed amounts specified in the agreements. In connection with the forward sale agreements, the forward seller, or its affiliates, borrowed from third parties and sold 416,853 shares, 1,692,555 shares, and 250,743 shares, respectively, of Entergy Corporation's common stock. The gross sales price of these shares totaled approximately $ 45 million, $ 190.1 million, and $ 25.4 million, respectively. In connection with the sales of these shares, Entergy Corporation paid to the forward sellers fees of approximately $ 0.5 million, $ 1.9 million, and $ 0.3 million, respectively, which have not been deducted from the gross sales prices. Entergy Corporation did not receive any proceeds from such sales of borrowed shares.

 In March, June, and September 2022, Entergy Corporation entered into forward sale agreements for 1,538,010 shares, 2,124,086 shares, and 1,666,172 shares of common stock, respectively. No amounts were recorded on Entergy's balance sheet with respect to the equity offerings until settlements of the equity forward sale agreements occurred in November 2022. The forward sale agreements required Entergy Corporation to, at its election prior to September 29, 2023 for the March 2022 agreements and prior to December 29, 2023 for the June and September 2022 agreements, either (i) physically settle the transactions by issuing the total of 1,538,010 shares, 2,124,086 shares, and 1,666,172 shares, respectively, 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 approximately $ 108.12, $ 116.94, and $ 115.46 per share, respectively) or (ii) net settle the transactions in whole or in part through the delivery or receipt of cash or shares. Each forward sale price was subject to adjustment on a daily basis based on a floating interest rate factor and decreased by other fixed amounts specified in the agreements. In connection with the forward sale agreements, the forward seller, or its affiliates, borrowed from third parties and sold 1,538,010 shares, 2,124,086 shares, and 1,666,172 shares, respectively, of Entergy Corporation's common stock. The gross sales price of these shares totaled approximately $ 168 million, $ 250.9 million, and $ 194.2 million, respectively. In connection with the sales of these shares, Entergy Corporation paid the forward sellers fees of approximately $ 1.7 million, $ 2.5 million, and $ 1.9 million, respectively, which have not been deducted from the gross sales prices. Entergy Corporation did not receive any proceeds from such sales of borrowed shares.

 In November 2022, Entergy Corporation physically settled its obligations under the then-outstanding forward sale agreements by delivering 7,688,419 shares of common stock in exchange for cash proceeds of $ 853.3 million. The forward sale price used to determine the cash proceeds received by Entergy Corporation was calculated based on the initial forward sale price of $ 112.50 per share as adjusted in accordance with the forward sale agreements. Entergy Corporation incurred an aggregate amount of approximately $ 0.7 million of general

 issuance costs with the settlement. Entergy Corporation used the net proceeds for general corporate purposes, which included repayment of commercial paper, outstanding loans under Entergy Corporation's revolving credit facility, and other debt.

 In June 2023, Entergy Corporation entered into forward sale agreements for 102,995 shares and 365,307 shares of common stock, and in November 2023, Entergy Corporation entered into a forward sale agreement for 853,117 shares of common stock. No amounts were recorded on Entergy's balance sheet with respect to the equity offerings until settlements of the equity forward sale agreements occurred in November and December 2023. The forward sale agreements required Entergy Corporation to, at its election prior to May 31, 2024 and June 28, 2024, respectively, for the June 2023 agreements and prior to August 11, 2024 for the November 2023 agreement, either (i) physically settle the transactions by issuing the total of 102,995 shares, 365,307 shares, and 853,117 shares, respectively, 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 approximately $ 101.36, $ 101.39, and $ 97.48 per share, respectively) or (ii) net settle the transactions in whole or in part through the delivery or receipt of cash or shares. Each forward sale price was subject to adjustment on a daily basis based on a floating interest rate factor and decreased by other fixed amounts specified in the agreements. In connection with the forward sale agreements, the forward seller, or its affiliates, borrowed from third parties and sold 102,995 shares, 365,307 shares, and 853,117 shares, respectively, of Entergy Corporation's common stock. The gross sales price of these shares totaled approximately $ 10.5 million, $ 37.4 million, and $ 84 million, respectively. In connection with the sales of these shares, Entergy Corporation paid the forward sellers fees of approximately $ 0.1 million, $ 0.4 million, and $ 0.8 million, respectively, which have not been deducted from the gross sales prices. Entergy Corporation did not receive any proceeds from such sales of borrowed shares.

 In November 2023, Entergy Corporation physically settled its obligations under the June 2023 forward sale agreements, and in December 2023, Entergy Corporation physically settled its obligations under the November 2023 forward sale agreement, by delivering 468,302 shares and 853,117 shares of common stock, respectively, in exchange for cash proceeds of $ 47.8 million and $ 83.3 million, respectively. The forward sale price used to determine the cash proceeds received by Entergy was calculated based on the initial forward sale price of $ 101.38 and $ 97.48 per share, respectively, as adjusted in accordance with the forward sale agreements. Entergy Corporation incurred an aggregate amount of approximately $ 0.4 million of general issuance costs with the settlements. Entergy Corporation used the net proceeds for general corporate purposes, which included repayment of commercial paper, outstanding loans under Entergy Corporation's revolving credit facility, and other debt.

 In December 2023, Entergy Corporation entered into a forward sale agreement for 2,753,246 shares of common stock. No amounts have been or will be recorded on Entergy's balance sheet with respect to the equity offering until settlement of the equity forward sale agreement occurs. The forward sale agreement requires Entergy Corporation to, at its election prior to May 30, 2025, either (i) physically settle the transaction by issuing the total of 2,753,246 shares of its common stock to the forward counterparty in exchange for net proceeds at the then-applicable forward sale price specified by the agreement (initially approximately $ 101.11 per share) or (ii) net settle the transaction 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 agreement. In connection with the forward sale agreement, the forward seller, or its affiliates, borrowed from third parties and sold 2,753,246 shares of Entergy Corporation's common stock. The gross sales price of these shares totaled approximately $ 280.5 million. In connection with the sale of these shares, Entergy Corporation paid the forward sellers fees of approximately $ 2.8 million which have not been deducted from the gross sales price. Entergy Corporation did not receive any proceeds from such sales of borrowed shares.

 Until settlement of the forward sale agreements, earnings per share dilution resulting from the agreements, if any, were determined under the treasury stock method. Share dilution occurs when the average market price of Entergy Corporation's common stock is higher than the average forward sales price. At December 31, 2023, 1,762,709 shares under the forward sale agreement were not included in the calculation of diluted earnings per share because their effect would have been antidilutive, and at December 31, 2021, 1,158,917 shares under the then-

 outstanding forward sale agreements were not included in the calculation of diluted earnings per share because their effect would have been antidilutive. At December 31, 2022, there were no forward share agreements outstanding.

 Retained Earnings and Dividends

 Entergy Corporation received dividend payments and distributions from subsidiaries totaling $ 189 million in 2023, $ 301 million in 2022, and $ 136 million in 2021.

 Comprehensive Income

 Accumulated other comprehensive income (loss) is included in the equity section of the balance sheets of Entergy and Entergy Louisiana. The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 2023:

 Pension and Other Postretirement Liabilities

 Beginning balance, January 1, 2023
 ($ 191,754)

 Other comprehensive income (loss) before reclassifications
 36,404

 Amounts reclassified from accumulated other comprehensive income (loss)
 ( 7,110)

 Net other comprehensive income (loss) for the period

 Ending balance, December 31, 2023
 ($ 162,460)

 The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 2022 by component:

 Cash flow
hedges
net
unrealized
gain (loss)
and
other
postretirement
liabilities

Net
unrealized
investment
gain (loss)
 Total
Accumulated
Other
Comprehensive
Income (Loss)

 Beginning balance, January 1, 2022
 ($ 1,035)
 ($ 338,647)
 $ 7,154
 ($ 332,528)

 Other comprehensive income (loss) before reclassifications
 112,944
 ( 12,997)
 100,855

 Amounts reclassified from accumulated other comprehensive income (loss)
 33,949
 5,843
 39,919

 Net other comprehensive income (loss) for the period
 1,035
 146,893
 ( 7,154)
 140,774

 Ending balance, December 31, 2022
 $ —
 ($ 191,754)
 $ —
 ($ 191,754)

 The following table presents changes in accumulated other comprehensive income (loss) for Entergy Louisiana for the years ended December 31, 2023 and 2022:

 Pension and Other Postretirement Liabilities

 2023
 2022

 Beginning balance, January 1,

 $ 55,370
 $ 8,278

 Other comprehensive income (loss) before reclassifications
 5,603
 48,087

 Amounts reclassified from accumulated other comprehensive income (loss)

 ( 6,175)
 ( 995)

 Net other comprehensive income (loss) for the period

 Ending balance, December 31,

 $ 54,798
 $ 55,370

 Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy for the years ended December 31, 2023 and 2022 are as follows:

 Amounts reclassified from AOCI
 Income Statement Location

 2023
 2022

 Cash flow hedges net unrealized loss

 Interest rate swaps
 $ —
 ($ 161)

 Total realized loss on cash flow hedges
 —
 ( 161)

 —

 Total realized loss on cash flow hedges (net of tax)
 $ —
 ($ 127)

 Amortization of prior-service costs

 $ 13,586
 $ 15,337
 (a)

 Amortization of net gain (loss)
 6,590
 ( 33,859)
 (a)

 ( 10,848)
 ( 25,321)
 (a)

 Total amortization and settlement loss
 9,328
 ( 43,843)

 ( 2,218)
 9,894

 Total amortization and settlement loss (net of tax)
 $ 7,110
 ($ 33,949)

 Net unrealized investment gain (loss)

 Realized loss
 $ —
 ($ 9,245)

 —
 3,402

 Total realized investment loss (net of tax)
 $ —
 ($ 5,843)

 Total reclassifications for the period (net of tax)

 $ 7,110
 ($ 39,919)

 (a)These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension and other postretirement cost. See Note 11 to the financial statements for additional details.

 Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy Louisiana for the years ended December 31, 2023 and 2022 are as follows:

 Amounts reclassified from AOCI
 Income Statement Location

 2023

 2022

 Amortization of prior-service costs

 $ 3,804

 $ 4,630
 (a)

 Amortization of net gain (loss)
 6,263
 ( 927)
 (a)

 ( 1,617)
 ( 2,342)
 (a)

 Total amortization and settlement loss
 8,450
 1,361

 ( 2,275)
 ( 366)

 Total amortization and settlement loss (net of tax)
 6,175

 Total reclassifications for the period (net of tax)

 $ 6,175

 $ 995

 (a)These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension and other postretirement cost. See Note 11 to the financial statements for additional details.

 NOTE 8. COMMITMENTS AND CONTINGENCIES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

 Entergy and the Registrant Subsidiaries are involved in a number of legal, regulatory, and tax proceedings before various courts, regulatory authorities, and governmental agencies in the ordinary course of business. While management is unable to predict with certainty the outcome of such proceedings, management does not believe that the ultimate resolution of these matters will have a material adverse effect on Entergy's results of operations, cash flows, or financial condition. Entergy discusses regulatory proceedings in Note 2 to the financial statements and discusses tax proceedings in Note 3 to the financial statements.

 Vidalia Purchased Power Agreement

 Entergy Louisiana has an agreement extending through the year 2031 to purchase energy generated by a hydroelectric facility known as the Vidalia project. Entergy Louisiana made payments under the contract of approximately $ 100.4 million in 2023, $ 117.2 million in 2022, and $ 128.5 million in 2021. If the maximum percentage ( 94 %) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $ 137.4 million in 2024 and a total of $ 958.8 million for the years 2025 through 2031. Entergy Louisiana currently recovers the costs of the purchased energy through its fuel adjustment clause.

 In an LPSC-approved settlement related to tax benefits from the tax treatment of the Vidalia contract, Entergy Louisiana agreed to credit rates by $ 11 million each year for up to 10 years, beginning in October 2002. In October 2011 the LPSC approved a settlement under which Entergy Louisiana agreed to provide credits to customers by crediting billings an additional $ 20.235 million per year for 15 years beginning January 2012. Entergy Louisiana recorded a regulatory charge and a corresponding regulatory liability to reflect this obligation. The settlement agreement allowed for an adjustment to the credits if, among other things, there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35 % to 21 %, the Vidalia purchased power regulatory liability was reduced by $ 30.5 million, with a corresponding increase to Other regulatory credits on the income statement. See Note 3 to the financial statements for discussion of the effects of

 the Tax Cuts and Jobs Act and discussion of the resolution of the 2016-2018 IRS audit, which included the tax treatment of the Vidalia contract.

 ANO Damage, Outage, and NRC Reviews

 In March 2013, during a scheduled refueling outage at ANO 1, a contractor-owned and operated heavy-lifting apparatus collapsed while moving the generator stator out of the turbine building. The collapse resulted in the death of an ironworker and injuries to several other contract workers, caused ANO 2 to shut down, and damaged the ANO turbine building. The total cost of assessment, restoration of off-site power, site restoration, debris removal, and replacement of damaged property and equipment was approximately $ 95 million. Entergy Arkansas pursued its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. Entergy Arkansas collected $ 50 million in 2014 from Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the members' nuclear generating plants. Entergy Arkansas also collected a total of $ 21 million in 2018 as a result of stator-related settlements.

 In addition, Entergy Arkansas incurred replacement power costs for ANO 2 power during its outage and incurred incremental replacement power costs for ANO 1 power because the outage extended beyond the originally-planned duration of the refueling outage. In February 2014 the APSC authorized Entergy Arkansas to retain the $ 65.9 million in its deferred fuel balance with recovery to be reviewed in a later period after more information regarding various claims associated with the ANO stator incident was available.

 In March 2015, after several NRC inspections and regulatory conferences, arising from the stator incident, the NRC placed ANO into the "multiple/repetitive degraded cornerstone column," or Column 4, of the NRC's Reactor Oversight Process Action Matrix. Entergy Arkansas incurred incremental costs of approximately $ 53 million in 2015 to prepare for the NRC inspections that began in early 2016 in order to address the issues required to move ANO back to "licensee response" or Column 1 of the NRC's Reactor Oversight Process Action Matrix. Excluding remediation and response costs that resulted from the additional NRC inspection activities, Entergy Arkansas incurred approximately $ 44 million in 2016 and $ 7 million in 2017 in support of NRC inspection activities and to implement Entergy Arkansas's performance improvement initiatives developed in 2015. In June 2018 the NRC moved ANO 1 and 2 into the "licensee response column," or Column 1, of the NRC's Reactor Oversight Process Action Matrix.

 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 identified costs resulting from the ANO stator incident, specifically all incremental fuel and purchased energy expense, capital and incremental non-fuel operations and maintenance costs, and costs of any judgment that may be rendered against Entergy Arkansas in civil litigation that is not covered by insurance. As a result, in third quarter 2023, Entergy Arkansas recorded write-offs of its regulatory asset for deferred fuel of $ 68.9 million, which includes interest, and the undepreciated balance of $ 9.5 million in capital costs 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.

 Spent Nuclear Fuel Litigation

 Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic

 nuclear power reactors. Entergy's nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Following the defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit Court of Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014.

 Because the DOE has not begun accepting spent fuel, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and is in partial breach of its spent fuel disposal contracts. As a result of the DOE's failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy's nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. Beginning in November 2003 these subsidiaries have pursued litigation to recover the damages caused by the DOE's delay in performance. Following are details of final judgments recorded by Entergy in 2021, 2022, and 2023 related to Entergy's nuclear owner/licensee subsidiaries' litigation with the DOE.

 In January 2021 the U.S. Court of Federal Claims issued a final judgment in the amount of $ 23 million in favor of Entergy Nuclear Palisades and against the DOE in the second round Palisades damages case. Entergy received payment from the U.S. Treasury in February 2021. The effects of recording the judgment were reductions to plant, other operation and maintenance expenses, and taxes other than income taxes. The Palisades damages awarded included $ 16 million related to costs previously recorded as plant and $ 7 million related to costs previously recorded as other operation and maintenance expenses. Of the $ 16 million previously capitalized, Entergy recorded $ 9 million as a reduction to previously-recorded depreciation expense.

 In August 2021 the U.S. Court of Federal Claims issued a final judgment in the amount of $ 37.6 million in favor of Holtec Pilgrim, LLC against the DOE in the third round Pilgrim damages case. Holtec Pilgrim, LLC received the payment from the U.S. Treasury in September 2021. The judgment proceeds were subsequently transferred to Entergy pursuant to the terms of the Pilgrim sale. The receipt of the proceeds was recorded as a deferred credit because Entergy has an indemnity obligation to Holtec related to pre-sale DOE litigation involving Pilgrim that remains outstanding.

 In August 2021 the U.S. Court of Federal Claims issued a final judgment in the amount of $ 21 million in favor of Entergy Louisiana against the DOE in the third round River Bend damages case. Entergy Louisiana received the payment from the U.S. Treasury in September 2021. The effects of recording the judgment were reductions to plant, nuclear fuel expense, and other operation and maintenance expenses. The River Bend damages awarded included $ 9 million in costs previously recorded as plant, $ 8 million related to costs previously recorded as nuclear fuel expense, and $ 4 million related to costs previously recorded as other operation and maintenance expenses.

 In October 2021 the U.S. Court of Federal Claims issued a final judgment in the amount of $ 83 million in favor of Entergy Nuclear Indian Point 2, LLC and Entergy Nuclear Indian Point 3, LLC against the DOE in the Indian Point 2 third round and Indian Point 3 second round combined damages case. Entergy received payment from the U.S. Treasury in January 2022. The effect in 2021 of recording the judgment was a reduction to asset write-offs, impairments, and related charges (credits). The damages awarded included $ 32 million related to costs previously recorded as plant, $ 47 million related to costs previously recorded as other operation and maintenance expenses, and $ 4 million related to costs previously recorded as taxes other than income taxes.

 In March 2023 the DOE submitted an offer of judgment to resolve claims in the fourth round ANO damages case. The $ 41 million offer was accepted by Entergy Arkansas, and the U.S. Court of Federal Claims issued a judgment in that amount in favor of Entergy Arkansas and against the DOE. Entergy Arkansas received payment from the U.S. Treasury in April 2023. The effects of recording the judgment were reductions to plant, nuclear fuel expense, other operation and maintenance expenses, materials and supplies, and taxes other than income taxes. The ANO damages awarded included $ 18 million related to costs previously recorded as plant, $ 10 million related to costs previously recorded as other operation and maintenance expenses, $ 8 million related to costs previously recorded as nuclear fuel expense, $ 3 million related to costs previously recorded as materials and supplies, and $ 2 million related to costs previously recorded as taxes other than income taxes.

 In July 2023 the DOE submitted an offer of judgment to resolve claims in the Indian Point 2 fourth round and Indian Point 3 third round combined damages case. The $ 59 million offer was accepted by Entergy and Holtec International, as the current owner. The U.S. Court of Federal Claims issued a final judgment in that amount in favor of Holtec Indian Point 2, LLC and Holtec Indian Point 3, LLC (previously Entergy Nuclear Indian Point 2, LLC and Entergy Nuclear Indian Point 3, LLC) and against the DOE. Holtec received payment from the U.S. Treasury in July 2023. Consistent with certain terms agreed upon in connection with the sale of Indian Point Energy Center in May 2021, Holtec transferred $ 40 million to Entergy for its pro-rata share of the litigation proceeds in August 2023. The remainder of the judgment was retained by Holtec. The effect of recording Entergy's pro-rata share of the judgment was a reduction to asset write-offs, impairments, and related charges (credits). Entergy's pro-rata share of the damages awarded included $ 18 million related to costs previously recorded as spending on the asset retirement obligation, $ 15 million related to costs previously recorded as other operation and maintenance expenses, $ 6 million related to costs previously recorded as plant, and $ 1 million related to costs previously recorded as taxes other than income taxes.

 Management cannot predict the timing or amount of any potential recoveries on other claims filed by Entergy subsidiaries and cannot predict the timing of any eventual receipt from the DOE of the U.S. Court of Federal Claims damage awards.

 Nuclear Insurance

 Third Party Liability Insurance

 The Price-Anderson Act requires that reactor licensees purchase insurance and participate in a secondary insurance pool that provides insurance coverage for the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act requires nuclear power plants to show evidence of financial protection in the event of a nuclear accident. This protection must consist of two layers of coverage:

 1.The primary level is private insurance underwritten by American Nuclear Insurers (ANI) and provides public liability insurance coverage of $ 500 million, as of January 1, 2024, for each operating reactor. If this amount is not sufficient to cover claims arising from an accident, the second level, Secondary Financial Protection, applies.

 2.Secondary Financial Protection: Currently, 95 nuclear reactors participate in the Secondary Financial Protection program, which provides approximately $ 15.8 billion in secondary layer insurance coverage to compensate the public in the event of a nuclear power reactor accident. The Price-Anderson Act provides that all potential liability for a nuclear accident is limited to the amounts of insurance coverage available under the primary and secondary layers.

 Within the Secondary Financial Protection program, each nuclear reactor has a contingent obligation to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary level, regardless of proximity to the incident or fault, up to a maximum of approximately $ 165.9 million per reactor per incident (Entergy's maximum total contingent obligation per incident is $ 829.6 million). This retrospective premium is assessable at approximately $ 24.7 million per year per incident per nuclear power reactor.

 3.Total insurance coverage available is approximately $ 16.3 billion, among the primary ANI coverage and the Secondary Financial Protection program, to respond to a nuclear power plant accident that causes third-party damages (e.g., off-site property and environmental damage, off-site bodily injury, and on-site third-party bodily injury (i.e., contractors)). These coverages also respond to an accident caused by terrorism.

 Entergy Arkansas and Entergy Louisiana each have two licensed reactors. System Energy has one licensed reactor ( 10 % of Grand Gulf is owned by a non-affiliated company (Cooperative Energy) that would share on a pro-rata basis in any retrospective premium assessment to System Energy under the Price-Anderson Act).

 Property Insurance

 Entergy's nuclear owner/licensee subsidiaries are members of NEIL, a mutual insurance company that provides property damage coverage, including decontamination and reactor stabilization, to the members' nuclear generating plants. The property damage insurance limits procured by Entergy for its Utility plants are in compliance with the financial protection requirements of the NRC. These coverage limits, deductibles, and weekly indemnity periods are subject to change based on results of NEIL loss control inspections.

 The Utility plants' (ANO 1 and 2, Grand Gulf, River Bend, and Waterford 3) property damage insurance limits are $ 1.06 billion per occurrence at each plant. The property deductible is $ 20 million per site at the Utility plants, except for earth movement, flood, and windstorm. Property damage from earth movement is excluded from the first $ 500 million in coverage for all Utility plants. Property damage from flood is excluded from the first $ 500 million in coverage at ANO 1 and 2 and Grand Gulf. Property damage from flood for Waterford 3 and River Bend includes a deductible of $ 10 million plus an additional 10 % of the amount of the loss in excess of $ 10 million, up to a maximum deductible of $ 50 million. Property damage from a windstorm for all of the Utility nuclear plants includes a deductible of $ 10 million plus an additional 10 % of the amount of the loss in excess of $ 10 million, up to a total maximum deductible of $ 50 million.

 In addition, Waterford 3 and Grand Gulf are also covered under NEIL's Accidental Outage Coverage program. Accidental outage coverage provides indemnification for the actual cost incurred in the event of an unplanned outage resulting from property damage covered under the NEIL Primary Property Insurance policy, subject to a deductible period. The indemnification for the actual cost incurred is based on market power prices at the time of the loss. After the deductible period has passed, weekly indemnities for an unplanned nuclear outage, covered under NEIL's Accidental Outage Coverage program, would be paid according to the amounts listed below:

 • 100 % of the weekly indemnity for each week for the first payment period of 52 weeks (nuclear and non-nuclear loss); then
 • 80 % of the weekly indemnity for each week for the second payment period of 52 weeks (nuclear and non-nuclear loss); and thereafter
 • 80 % of the weekly indemnity for an additional 58 weeks for the third and final payment period (nuclear loss only).

 Under the property damage and accidental outage insurance programs, all NEIL insured plants could be subject to assessments should losses exceed the accumulated funds available from NEIL. Effective April 1, 2023, the maximum amounts of such possible assessments per occurrence were as follows:

 Assessments

 Utility:

 $ 19.4

 $ 36.6

 $ 0.1

 $ 0.1

 N/A

 $ 14.3

 NRC regulations provide that the proceeds of this insurance must be used, first, to render the reactor safe and stable, and second, to complete decontamination operations. Only after proceeds are dedicated for such use and regulatory approval is secured would any remaining proceeds be made available for the benefit of plant owners or their creditors.

 In the event that one or more acts of terrorism causes property damage from a nuclear event under one or more or all nuclear insurance policies issued by NEIL (including, but not limited to, those described above) within 12 months from the date the first property damage occurs, the maximum recovery under all such nuclear insurance policies shall be an aggregate not exceeding $ 3.24 billion plus the additional amounts recovered for such losses from reinsurance, indemnity, and any other sources applicable to such losses.

 Non-Nuclear Property Insurance

 Entergy's non-nuclear property insurance program provides coverage on a system-wide basis for Entergy's non-nuclear assets. The insurance program provides coverage for property damage up to $ 400 million per occurrence in excess of a $ 20 million self-insured retention except for property damage caused by the following: earthquake shock, flood, and named windstorm, including associated storm surge. For earthquake shock and flood, the insurance program provides coverage up to $ 400 million on an annual aggregate basis in excess of a $ 40 million self-insured retention. For named windstorm and associated storm surge, the insurance program provides coverage up to $ 125 million on an annual aggregate basis in excess of a $ 40 million self-insured retention. The coverage provided by the insurance program for the Entergy New Orleans gas distribution system is limited to $ 50 million per occurrence and is subject to the same annual aggregate limits and retentions listed above for earthquake shock, flood, and named windstorm, including associated storm surge.

 Covered property generally includes power plants, substations, facilities, inventories, and gas distribution-related properties. Excluded property generally includes transmission and distribution lines, poles, and towers. For substations valued at $ 5 million or less, coverage for named windstorm and associated storm surge is excluded. This coverage is in place for Entergy Corporation, the Registrant Subsidiaries, and certain other Entergy subsidiaries. Entergy also purchases $ 400 million in terrorism insurance coverage for its conventional property.

 Employment and Labor-related Proceedings

 The Registrant Subsidiaries and other Entergy subsidiaries and related entities are responding to various lawsuits in both state and federal courts and to other labor-related proceedings filed by current and former employees, recognized bargaining representatives, and certain third parties. Generally, the amount of damages being sought is not specified in these proceedings. These actions may include, but are not limited to, allegations of wrongful employment actions; wage disputes and other claims under the Fair Labor Standards Act or its state

 counterparts; claims of race, gender, age, and disability discrimination; disputes arising under collective bargaining agreements; unfair labor practice proceedings and other administrative proceedings before the National Labor Relations Board or concerning the National Labor Relations Act; claims of retaliation; claims of harassment and hostile work environment; and claims for or regarding benefits under various Entergy Corporation-sponsored employee benefit plans. Entergy and the Registrant Subsidiaries and related entities are responding to these lawsuits and proceedings and deny liability to the claimants. Management believes that loss exposure has been and will continue to be handled so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position, results of operation, or cash flows of Entergy or the Registrant Subsidiaries.

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

 Numerous lawsuits have been filed in state courts against primarily Entergy Texas and Entergy Louisiana by individuals alleging exposure to asbestos while working at Entergy facilities between 1955 and 1980. Entergy is being sued as a premises owner. Many other defendants are named in these lawsuits as well. Currently, there are approximately 195 lawsuits involving approximately 345 claimants. Management believes that adequate provisions have been established to cover any exposure. Additionally, negotiations continue with insurers to recover reimbursements. Management believes that loss exposure has been and will continue to be handled so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position, results of operation, or cash flows of the Utility operating companies.

 Grand Gulf - Related Agreements

 Unit Power Sales Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

 System Energy has agreed to sell all of its share of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans in accordance with specified percentages (Entergy Arkansas - 36 %, Entergy Louisiana - 14 %, Entergy Mississippi - 33 %, and Entergy New Orleans - 17 %) as ordered by the FERC. Charges under this agreement are paid in consideration for the purchasing companies' respective entitlement to receive capacity and energy and are payable irrespective of the quantity of energy delivered. In December 2016 the NRC granted the extension of Grand Gulf's operating license to 2044. Monthly obligations are based on actual capacity and energy costs. The average monthly payments for 2023 under the agreement were approximately $ 17.9 million for Entergy Arkansas, $ 6.7 million for Entergy Louisiana, $ 16.3 million for Entergy Mississippi, and $ 8.1 million for Entergy New Orleans. See Note 2 to the financial statements for discussion of the complaints filed with the FERC against System Energy seeking a reduction in the return on equity component of the Unit Power Sales Agreement and other complaints filed with the FERC regarding the rates charged by System Energy under the System Agreement.

 Availability Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

 Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans are individually obligated to make payments or subordinated advances to System Energy in accordance with stated percentages (Entergy Arkansas - 17.1 %, Entergy Louisiana - 26.9 %, Entergy Mississippi - 31.3 %, and Entergy New Orleans - 24.7 %) in amounts that, when added to amounts received under the Unit Power Sales Agreement or otherwise, are adequate to cover all of System Energy's operating expenses as defined, including expenses incurred in connection with a permanent shutdown of Grand Gulf. System Energy has assigned its rights to payments and advances to certain creditors as security for certain of its debt obligations. Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, no payments under the Availability Agreement have ever been required. However, if Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could

 become subject to claims or demands by System Energy or certain of its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their allocated shares under the Availability Agreement exceed their allocated shares under the Unit Power Sales Agreement. See discussion below of the Reallocation Agreement among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, pursuant to which Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans assumed all of Entergy Arkansas's responsibilities and obligations with respect to Grand Gulf under the Availability Agreement.

 Reallocation Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

 System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans entered into the Reallocation Agreement relating to the sale of capacity and energy from Grand Gulf and the related costs, in which Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans agreed to assume all of Entergy Arkansas's responsibilities and obligations with respect to Grand Gulf under the Availability Agreement. The FERC's decision allocating a portion of Grand Gulf capacity and energy to Entergy Arkansas supersedes the Reallocation Agreement as it relates to Grand Gulf. However, the Reallocation Agreement does not affect Entergy Arkansas's obligation to System Energy's lenders under the assignments referred to in the preceding paragraph. Entergy Arkansas would be liable for its share of such amounts if Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans were unable to meet their contractual obligations. No payments of any amortization amounts will be required so long as amounts paid to System Energy under the Unit Power Sales Agreement, including other funds available to System Energy, exceed amounts required under the Availability Agreement, which is expected to be the case for the foreseeable future.

 Nelson Industrial Steam Company (Entergy Louisiana)

 Entergy Louisiana is a partner in the Nelson Industrial Steam Company (NISCO) partnership which owns two petroleum coke generating units. In April 2023 these generating units suspended operations in the MISO market, and Entergy Louisiana currently is working to wind up the NISCO partnership, which will ultimately result in ownership of the generating units transferring to Entergy Louisiana. In November 2023 the FERC issued an order providing Section 203 of the Federal Power Act approval for any subsequent transfer of the facilities to Entergy Louisiana. Entergy Louisiana is evaluating the effect of the transaction on its results of operations, cash flows, and financial condition, but at this time does not expect the effect to be material.

 NOTE 9. ASSET RETIREMENT OBLIGATIONS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

 Accounting standards require companies to record liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of the assets. For Entergy, substantially all of its asset retirement obligations consist of its liability for decommissioning its nuclear power plants. In addition, an insignificant amount of removal costs associated with non-nuclear power plants is also included in the decommissioning and asset retirement costs line item on the balance sheets.

 These liabilities are recorded at their fair values (which are the present values of the estimated future cash outflows) in the period in which they are incurred, with an accompanying addition to the recorded cost of the long-lived asset. The asset retirement obligation is accreted each year through a charge to expense, to reflect the time value of money for this present value obligation. The accretion will continue through the completion of the asset retirement activity. The amounts added to the carrying amounts of the long-lived assets will be depreciated over the useful lives of the assets. The application of accounting standards related to asset retirement obligations is earnings neutral to the rate-regulated business of the Registrant Subsidiaries.

 In accordance with ratemaking treatment and as required by regulatory accounting standards, the depreciation provisions for the Registrant Subsidiaries include a component for removal costs that are not asset retirement obligations under accounting standards. In accordance with regulatory accounting principles, the Registrant Subsidiaries have recorded regulatory assets (liabilities) in the following amounts to reflect their estimates of the difference between estimated incurred removal costs and estimated removal costs expected to be recovered in rates:

 2023
 2022

 $ 319.7
 $ 267.1

 $ 262.3
 $ 418.8

 $ 188.0
 $ 159.4

 $ 61.1
 $ 56.3

 $ 77.5
 $ 62.9

 $ 102.1
 $ 94.4

 As of December 31, 2023 and 2022, the regulatory asset for removal costs for the Utility operating companies includes amounts related to storm restoration costs. See Note 2 to the financial statements for further discussion of storm restoration costs and requested recovery.

 The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2023 and 2022 by Entergy were as follows:

 Liabilities as of December 31, 2022

 Accretion

Estimate
 Liabilities as of December 31, 2023

 $ 4,271.5
 $ 219.4
 $ 14.9
 $ 4,505.8

 $ 1,472.7
 $ 87.4
 $ —
 $ 1,560.1

 $ 1,736.8
 $ 88.6
 $ 10.8
 $ 1,836.2

 $ 7.8
 $ 0.4
 $ —
 $ 8.2

 $ —
 $ 0.5
 $ 4.1
 $ 4.6

 $ 11.1
 $ 0.6
 $ —
 $ 11.7

 $ 1,042.5
 $ 41.7
 $ —
 $ 1,084.2

 Liabilities as
of December 31,
2021

 Accretion

Estimate

 Spending

 Dispositions
 Liabilities as
of December 31,
2022

 $ 4,757.1
 $ 236.0
 ($ 0.5)
 ($ 13.3)
 ($ 707.8)
 $ 4,271.5

 $ 1,390.4
 $ 82.3
 $ —
 $ —
 $ —
 $ 1,472.7

 $ 1,653.2
 $ 84.1
 $ 2.8
 ($ 3.3)
 $ —
 $ 1,736.8

 $ 0.6
 $ —
 ($ 3.1)
 $ —
 $ 7.8

 $ 4.0
 $ 0.1
 $ —
 ($ 4.1)
 $ —
 $ —

 $ 8.5
 $ 0.5
 $ 2.1
 $ —
 $ —
 $ 11.1

 $ 1,007.6
 $ 40.2
 ($ 5.4)
 $ —
 $ —
 $ 1,042.5

 Non-Utility Operations

 Big Rock Point
 $ 42.0
 $ 2.0
 $ —
 ($ 1.2)
 ($ 42.8)
 (b)
 $ —

 Palisades
 $ 640.4
 $ 31.0
 $ —
 ($ 1.6)
 ($ 669.8)
 (b)
 $ —

 Other (a)
 $ 0.6
 $ —
 $ —
 $ —
 $ —
 $ 0.6

 (a) See "Coal Combustion Residuals" below for additional discussion regarding the asset retirement obligations related to coal combustion residuals management.
 (b) See Note 14 to the financial statements for discussion of the sale of the Big Rock Point Site and Palisades in June 2022.

 Nuclear Plant Decommissioning

 Entergy periodically reviews and updates estimated decommissioning costs. The actual decommissioning costs may vary from the estimates because of the timing of plant decommissioning, regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment.

 In third quarter 2023, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for River Bend as a result of a revised decommissioning cost study. The revised estimate resulted in a $ 10.8 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining useful life of the unit.

 In the third quarter 2022, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $ 5.4 million reduction in its decommissioning cost liability, along with a corresponding reduction in the related asset retirement obligation cost asset that will be depreciated over the remaining life of the unit.

 NRC Filings Regarding Trust Funding Levels

 Plant owners are required to provide the NRC with a biennial report (annually for units that have shut down or will shut down within five years), based on values as of December 31, addressing the owners' ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, plant owners may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met.

 As nuclear plants individually approach and begin decommissioning, filings will be submitted to the NRC for planned shutdown activities. These filings with the NRC also determine whether financial assurance may be required in addition to the nuclear decommissioning trust fund.

 Coal Combustion Residuals

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

 In the third quarter 2022, revisions to the Big Cajun 2 CCR asset retirement obligations were made as a result of revised closure and post-closure cost estimates. The revised estimates resulted in increases of $ 2.8 million at Entergy Louisiana and $ 2.1 million at Entergy Texas in decommissioning cost liabilities, along with corresponding increases in related asset retirement obligations cost assets that will be depreciated over the remaining useful life of the unit.

 NOTE 10. LEASES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

 As of December 31, 2023 and 2022, Entergy and the Registrant Subsidiaries held operating and finance leases for fleet vehicles used in operations, real estate, and aircraft. Excluded are power purchase agreements not meeting the definition of a lease, nuclear fuel leases, and the Grand Gulf sale-leaseback which were determined not to be leases under the accounting standards.

 Leases have remaining terms of one year to 57 years. Real estate leases generally include at least one five-year renewal option; however, renewal is not typically considered reasonably certain unless Entergy or a Registrant Subsidiary makes significant leasehold improvements or other modifications that would hinder its ability to easily move. In certain of the lease agreements for fleet vehicles used in operations, Entergy and the Registrant Subsidiaries provide residual value guarantees to the lessor. Due to the nature of the agreements and Entergy's continuing relationship with the lessor, however, Entergy and the Registrant Subsidiaries expect to renegotiate or refinance the leases prior to conclusion of the lease. As such, Entergy and the Registrant Subsidiaries do not believe it is probable that they will be required to pay anything pertaining to the residual value guarantee, and the lease liabilities and right-of-use assets are measured accordingly.

 Entergy incurred the following total lease costs for the years ended December 31, 2023 and 2022:

 2023
 2022

 Operating lease cost
 $ 68,136
 $ 65,463

 Finance lease cost:

 Amortization of right-of-use assets
 $ 15,193
 $ 13,493

 Interest on lease liabilities
 $ 3,639
 $ 2,702

 Of the lease costs disclosed above, Entergy had $ 5.0 million and $ 5.4 million in short-term leases costs for the years ended December 31, 2023 and 2022, respectively.

 The Registrant Subsidiaries incurred the following lease costs for the year ended December 31, 2023:

New Orleans

 Operating lease cost
 $ 17,065
 $ 16,906
 $ 7,837
 $ 1,912
 $ 7,290

 Finance lease cost:

 Amortization of right-of-use assets
 $ 3,633
 $ 4,835
 $ 2,227
 $ 1,025
 $ 1,786

 Interest on lease liabilities
 $ 545
 $ 729
 $ 973
 $ 150
 $ 284

 Of the lease costs disclosed above, Entergy Arkansas had $ 1.7 million, Entergy Louisiana had $ 1.6 million, Entergy Mississippi had $ 1.1 million, Entergy New Orleans had $ 0.1 million, and Entergy Texas had $ 0.4 million in short-term lease costs for the year ended December 31, 2023.

 The Registrant Subsidiaries incurred the following lease costs for the year ended December 31, 2022:

New Orleans

 Operating lease cost
 $ 15,435
 $ 15,016
 $ 7,510
 $ 1,755
 $ 5,624

 Finance lease cost:

 Amortization of right-of-use assets
 $ 3,048
 $ 4,259
 $ 1,962
 $ 906
 $ 1,629

 Interest on lease liabilities
 $ 402
 $ 592
 $ 261
 $ 134
 $ 230

 Of the lease costs disclosed above, Entergy Arkansas had $ 1.7 million, Entergy Louisiana had $ 1.8 million, Entergy Mississippi had $ 0.9 million, Entergy New Orleans had $ 0.2 million, and Entergy Texas had $ 0.8 million in short-term lease costs for the year ended December 31, 2022.

 The lease costs for the years ended December 31, 2023 and 2022 disclosed above materially approximate the cash flows used by the Registrant Subsidiaries for leases with all costs included within operating activities on the respective Statements of Cash Flows, except for the finance lease costs which are included in financing activities.

 Entergy has elected to account for short-term leases in accordance with policy options provided by accounting guidance; therefore, there are no related lease liabilities or right-of-use assets for the costs recognized above by Entergy or by its Registrant Subsidiaries in the table below.

 Included within Property, Plant, and Equipment on Entergy's consolidated balance sheets at December 31, 2023 and 2022 are $ 207 million and $ 191 million related to operating leases, respectively, and $ 84 million and $ 64 million related to finance leases, respectively.

 Included within Utility Plant on the Registrant Subsidiaries' respective balance sheets at December 31, 2023 and 2022 are the following amounts:

 2023

 $ 61,718
 $ 54,047
 $ 25,470
 $ 6,119
 $ 21,321

 $ 17,622
 $ 21,438
 $ 22,661
 $ 4,779
 $ 8,714

 2022

 $ 56,000
 $ 46,137
 $ 23,624
 $ 5,906
 $ 17,076

 $ 13,493
 $ 18,540
 $ 8,578
 $ 4,342
 $ 8,094

 The following lease-related liabilities are recorded within the respective Other lines on Entergy's consolidated balance sheets as of December 31, 2023 and 2022:

 2023
 2022

 Current liabilities:

 $ 60,789
 $ 56,566

 $ 16,671
 $ 13,824

 Non-current liabilities:

 $ 146,627
 $ 134,886

 $ 72,215
 $ 54,875

 The following lease-related liabilities are recorded within the respective Other lines on the Registrant Subsidiaries' respective balance sheets at December 31, 2023:

 Current liabilities:

 $ 15,514
 $ 14,771
 $ 6,754
 $ 1,681
 $ 6,023

 $ 3,743
 $ 4,870
 $ 3,059
 $ 991
 $ 1,865

 Non-current liabilities:

 $ 46,211
 $ 39,282
 $ 18,722
 $ 4,377
 $ 15,304

 $ 13,879
 $ 16,568
 $ 19,602
 $ 3,788
 $ 6,849

 The following lease-related liabilities are recorded within the respective Other lines on the Registrant Subsidiaries' respective balance sheets at December 31, 2022:

 Current liabilities:

 $ 14,140
 $ 13,554
 $ 6,540
 $ 1,650
 $ 5,640

 $ 2,985
 $ 4,276
 $ 1,974
 $ 918
 $ 1,654

 Non-current liabilities:

 $ 41,874
 $ 32,588
 $ 17,098
 $ 4,217
 $ 11,441

 $ 10,508
 $ 14,264
 $ 6,604
 $ 3,424
 $ 6,440

 The following information contains the weighted-average remaining lease term in years and the weighted-average discount rate for the operating and finance leases of Entergy at December 31, 2023 and 2022:

 2023
 2022

 Weighted-average remaining lease terms:

 4.46
 4.32

 8.61
 5.63

 4.10
 %
 3.61
 %

 4.64
 %
 3.95
 %

 The following information contains the weighted-average remaining lease term in years and the weighted-average discount rate for the operating and finance leases of the Registrant Subsidiaries at December 31, 2023:

 Weighted-average remaining lease terms:

 4.62
 4.60
 5.34
 6.38
 4.44

 5.57
 5.40
 17.82
 5.73
 5.49

 4.04
 %
 4.01
 %
 4.08
 %
 4.02
 %
 4.43
 %

 3.77
 %
 3.85
 %
 5.08
 %
 3.69
 %
 3.76
 %

 The following information contains the weighted-average remaining lease term in years and the weighted-average discount rate for the operating and finance leases of the Registrant Subsidiaries at December 31, 2022:

 Weighted-average remaining lease terms:

 4.55
 4.26
 5.31
 6.08
 3.84

 5.32
 5.27
 5.15
 5.72
 5.67

 3.43
 %
 3.24
 %
 3.52
 %
 3.50
 %
 3.63
 %

 2.93
 %
 3.15
 %
 2.87
 %
 3.04
 %
 3.07
 %

 Maturity of the lease liabilities for Entergy as of December 31, 2023 are as follows:

 Operating Leases
 Finance Leases

 2024
 $ 67,411
 $ 19,937

 2025
 53,183
 18,243

 2026
 44,744
 16,392

 2027
 32,552
 13,920

 2028
 14,038
 11,342

 Years thereafter
 14,105
 33,409

 Minimum lease payments
 226,033
 113,243

 Less: amount representing interest
 18,617
 24,357

 Present value of net minimum lease payments
 $ 207,416
 $ 88,886

 Maturity of the lease liabilities for the Registrant Subsidiaries as of December 31, 2023 are as follows:

 Operating Leases

 2024
 $ 17,399
 $ 16,539
 $ 7,652
 $ 1,867
 $ 6,828

 2025
 15,716
 13,908
 6,846
 1,442
 5,892

 2026
 13,855
 11,374
 5,409
 1,080
 4,736

 2027
 10,587
 8,493
 4,105
 2,834

 2028
 4,597
 4,595
 2,212
 1,563

 Years thereafter
 4,598
 4,035
 2,421
 1,376
 1,672

 Minimum lease payments
 66,752
 58,944
 28,645
 6,945
 23,525

 Less: amount representing interest
 5,027
 4,891
 3,170
 2,198

 Present value of net minimum lease payments
 $ 61,725
 $ 54,053
 $ 25,475
 $ 6,058
 $ 21,327

 Finance Leases

 2024
 $ 4,600
 $ 5,692
 $ 3,388
 $ 1,148
 $ 2,139

 2025
 4,179
 5,037
 3,093
 1,016
 1,975

 2026
 3,747
 4,279
 2,775
 1,739

 2027
 3,088
 3,389
 2,322
 1,413

 2028
 2,245
 2,545
 1,908
 1,145

 Years thereafter
 2,918
 3,199
 23,562
 1,222

 Minimum lease payments
 20,777
 24,141
 37,048
 5,307
 9,633

 Less: amount representing interest
 3,155
 2,703
 14,387

 Present value of net minimum lease payments
 $ 17,622
 $ 21,438
 $ 22,661
 $ 4,779
 $ 8,714

 In allocating consideration in lease contracts to the lease and non-lease components, Entergy and the Registrant Subsidiaries have made the accounting policy election to combine lease and non-lease components related to fleet vehicles used in operations and to allocate the contract consideration to both lease and non-lease components for real estate leases.

 NOTE 11. RETIREMENT, OTHER POSTRETIREMENT BENEFITS, AND DEFINED CONTRIBUTION PLANS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

 Qualified Pension Plans

 Entergy has defined benefit qualified pension plans, including the Entergy Corporation Retirement Plan for Non-Bargaining Employees (Non-Bargaining Plan I), the Entergy Corporation Retirement Plan for Bargaining Employees (Bargaining Plan I), the Entergy Corporation Retirement Plan II for Non-Bargaining Employees (Non-Bargaining Plan II), the Entergy Corporation Retirement Plan II for Bargaining Employees (Bargaining Plan II), the Entergy Corporation Retirement Plan III (Plan III), the Entergy Corporation Retirement Plan IV for Bargaining Employees, and the Entergy Corporation Cash Balance Plan for Bargaining Employees (Bargaining Cash Balance Plan). The Entergy Corporation Cash Balance Plan for Non-Bargaining Employees (Non-Bargaining Cash Balance Plan) was merged with and into Non-Bargaining Plan I effective January 1, 2022. Effective January 1, 2024, Non-Bargaining Plan I was amended to spin-off predominately inactive participants into a new qualified pension plan, Entergy Corporation Retirement Plan VI for Non-Bargaining Employees (Non-Bargaining Plan VI). The Registrant Subsidiaries participate in these plans: Non-Bargaining Plan I, Bargaining Plan I, Plan III, Non-Bargaining Plan VI, and Bargaining Cash Balance Plan. Non-bargaining and bargaining employees whose most recent date of hire was prior to June 30, 2014 (or such later date provided for in their applicable collective bargaining agreement) participate in a noncontributory final average pay formula that provides pension benefits based on the employee's credited service and compensation during employment. Non-bargaining and bargaining employees whose most recent date of hire is after June 30, 2014 and before January 1, 2021 (or such later date provided for in their applicable collective bargaining agreement) do not participate in a final average pay formula, but instead participate in a cash balance formula. Effective January 1, 2021, the Non-Bargaining Cash Balance Plan and Bargaining Cash Balance Plan were amended to close participation in each plan to those employees whose most recent hire date is after December 31, 2020 (or such later date provided for in their applicable collective bargaining agreement). Employees hired after this date instead may be eligible to participate in and receive a discretionary employer contribution under an Entergy sponsored tax-qualified defined contribution plan that includes a 401(k) feature.

 The assets of the defined benefit qualified pension plans are held in a master trust established by Entergy. Each pension plan has an undivided beneficial interest in each of the investment accounts in the master trust that is maintained by a trustee. Use of the master trust permits the commingling of the trust assets of the pension plans of Entergy Corporation and its Registrant Subsidiaries for investment and administrative purposes. Although assets in the master trust are commingled, the trustee maintains supporting records for the purpose of allocating the trust level equity in net earnings (loss) and the administrative expenses of the investment accounts in the trust to the various participating pension plans in the trust. The fair value of the trust's assets is determined by the trustee and certain investment managers. The trustee calculates a daily earnings factor, including realized and unrealized gains or losses, collected and accrued income, and administrative expenses, and allocates earnings to each plan in the master trust on a pro rata basis.

 Within each pension plan, the record of each Registrant Subsidiary's beneficial interest in the plan assets is maintained by the plan's actuary and is updated quarterly. Assets for each Registrant Subsidiary are increased for investment net income and contributions and are decreased for benefit payments. A plan's investment net income/loss (i.e., interest and dividends, realized and unrealized gains and losses and expenses) is allocated to the Registrant Subsidiaries participating in that plan based on the value of assets for each Registrant Subsidiary at the beginning of the quarter adjusted for contributions and benefit payments made during the quarter.

 Entergy Corporation and its subsidiaries fund pension plans in an amount not less than the minimum required contribution under the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the plans include common and preferred stocks, fixed-income securities, interest in a money market fund, and insurance contracts. The Registrant Subsidiaries' pension costs are recovered from customers as a component of cost of service in each of their respective jurisdictions.

 Components of Qualified Net Pension Cost and Other Amounts Recognized as a Regulatory Asset and/or Accumulated Other Comprehensive Income (AOCI)

 Entergy Corporation and its subsidiaries' total 2023, 2022, and 2021 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:

 2023
 2022
 2021

 Net periodic pension cost:

 $ 101,182
 $ 138,085
 $ 165,278

 Interest cost on projected benefit obligation
 298,281
 235,805
 191,107

 ( 388,030)
 ( 402,504)
 ( 424,572)

 Recognized net loss
 81,919
 188,683
 334,124

 Settlement charges
 160,387
 230,389
 205,878

 Net pension cost
 $ 253,739
 $ 390,458
 $ 471,815

 Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)

 ($ 213,636)
 $ 6,113
 ($ 448,532)

 Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:

 Amortization of net loss
 ( 81,919)
 ( 188,683)
 ( 334,124)

 Settlement charge
 ( 160,387)
 ( 230,389)
 ( 205,878)

 Total
 ($ 455,942)
 ($ 412,959)
 ($ 988,534)

 Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)
 ($ 202,203)
 ($ 22,501)
 ($ 516,719)

 The Registrant Subsidiaries' total 2023, 2022, and 2021 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, for their current and former employees included the following components:

 2023

 Net periodic pension cost:

 $ 18,461
 $ 24,716
 $ 5,775
 $ 1,955
 $ 4,328
 $ 5,749

 Interest cost on projected benefit obligation
 56,026
 60,346
 15,402
 6,747
 12,726
 13,852

 ( 70,574)
 ( 75,757)
 ( 19,423)
 ( 8,798)
 ( 16,641)
 ( 17,585)

 Recognized net loss
 19,400
 19,797
 5,719
 1,694
 4,075
 4,236

 Settlement charges
 26,137
 40,437
 12,242
 2,080
 11,230
 6,375

 Net pension cost
 $ 49,450
 $ 69,539
 $ 19,715
 $ 3,678
 $ 15,718
 $ 12,627

 Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)

 ($ 30,674)
 ($ 71,016)
 ($ 20,220)
 ($ 3,183)
 ($ 16,759)
 ($ 3,268)

 Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:

 Amortization of net loss
 ( 19,400)
 ( 19,797)
 ( 5,719)
 ( 1,694)
 ( 4,075)
 ( 4,236)

 Settlement charge
 ( 26,137)
 ( 40,437)
 ( 12,242)
 ( 2,080)
 ( 11,230)
 ( 6,375)

 Total
 ($ 76,211)
 ($ 131,250)
 ($ 38,181)
 ($ 6,957)
 ($ 32,064)
 ($ 13,879)

 Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)
 ($ 26,761)
 ($ 61,711)
 ($ 18,466)
 ($ 3,279)
 ($ 16,346)
 ($ 1,252)

 2022

 Net periodic pension cost:

 $ 25,210
 $ 33,520
 $ 8,043
 $ 2,745
 $ 5,999
 $ 7,746

 Interest cost on projected benefit obligation
 45,378
 49,330
 12,979
 5,491
 10,729
 11,286

 ( 75,820)
 ( 82,478)
 ( 20,168)
 ( 9,920)
 ( 18,317)
 ( 18,173)

 Recognized net loss
 43,597
 41,711
 12,594
 4,787
 9,013
 10,938

 Settlement charges
 36,409
 58,550
 15,786
 6,676
 22,411
 9,905

 Net pension cost
 $ 74,774
 $ 100,633
 $ 29,234
 $ 9,779
 $ 29,835
 $ 21,702

 Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)

 $ 28,365
 ($ 15,604)
 ($ 4,743)
 $ 525
 $ 13,363
 ($ 7,063)

 Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:

 Amortization of net loss
 ( 43,597)
 ( 41,711)
 ( 12,594)
 ( 4,787)
 ( 9,013)
 ( 10,938)

 Settlement charge
 ( 36,409)
 ( 58,550)
 ( 15,786)
 ( 6,676)
 ( 22,411)
 ( 9,905)

 Total
 ($ 51,641)
 ($ 115,865)
 ($ 33,123)
 ($ 10,938)
 ($ 18,061)
 ($ 27,906)

 Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)
 $ 23,133
 ($ 15,232)
 ($ 3,889)
 ($ 1,159)
 $ 11,774
 ($ 6,204)

 2021

 Net periodic pension cost:

 $ 28,632
 $ 38,271
 $ 9,070
 $ 3,038
 $ 6,921
 $ 8,851

 Interest cost on projected benefit obligation
 35,683
 39,740
 10,446
 4,392
 8,381
 9,087

 ( 78,368)
 ( 89,821)
 ( 22,407)
 ( 10,598)
 ( 21,158)
 ( 19,254)

 Recognized net loss
 69,290
 67,015
 20,007
 7,596
 12,676
 18,404

 Settlement charges
 37,682
 61,945
 16,710
 5,431
 11,797
 12,260

 Net pension cost
 $ 92,919
 $ 117,150
 $ 33,826
 $ 9,859
 $ 18,617
 $ 29,348

 Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)

 ($ 96,066)
 ($ 89,534)
 ($ 29,675)
 ($ 16,159)
 ($ 18,217)
 ($ 27,617)

 Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:

 Amortization of net loss
 ( 69,290)
 ( 67,015)
 ( 20,007)
 ( 7,596)
 ( 12,676)
 ( 18,404)

 Settlement charge
 ( 37,682)
 ( 61,945)
 ( 16,710)
 ( 5,431)
 ( 11,797)
 ( 12,260)

 Total
 ($ 203,038)
 ($ 218,494)
 ($ 66,392)
 ($ 29,186)
 ($ 42,690)
 ($ 58,281)

 Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)
 ($ 110,119)
 ($ 101,344)
 ($ 32,566)
 ($ 19,327)
 ($ 24,073)
 ($ 28,933)

 Qualified Pension Obligations, Plan Assets, Funded Status, and Amounts Recognized in the Balance Sheet

 Qualified pension obligations, plan assets, funded status, and amounts recognized in the Consolidated Balance Sheets for Entergy Corporation and its Subsidiaries as of December 31, 2023 and 2022 are as follows:

 2023
 2022

 Change in Projected Benefit Obligation (PBO)

 $ 6,166,106
 $ 8,409,620

 101,182
 138,085

 298,281
 235,805

 Actuarial (gain)/loss
 123,237
 ( 1,660,463)

 Benefits paid (including settlement lump sum benefit payments of ($ 410,110) in 2023 and ($ 604,753) in 2022)

 ( 773,402)
 ( 956,941)

 $ 5,915,404
 $ 6,166,106

 $ 5,242,098
 $ 6,993,110

 724,903
 ( 1,264,071)

 267,002
 470,000

 Benefits paid (including settlement lump sum benefit payments of ($ 410,110) in 2023 and ($ 604,753) in 2022)

 ( 773,402)
 ( 956,941)

 $ 5,460,601
 $ 5,242,098

 ($ 454,803)
 ($ 924,008)

 Amount recognized in the balance sheet (funded status)

 ($ 454,803)
 ($ 924,008)

 Amount recognized as a regulatory asset

 $ 1,447,978
 $ 1,842,348

 Amount recognized as AOCI (before tax)

 $ 347,268
 $ 408,839

 Qualified pension obligations, plan assets, funded status, and amounts recognized in the Balance Sheets for the Registrant Subsidiaries as of December 31, 2023 and 2022 are as follows:

 2023

 Change in Projected Benefit Obligation (PBO)

 $ 1,168,098
 $ 1,256,422
 $ 320,994
 $ 140,436
 $ 265,565
 $ 288,302

 18,461
 24,716
 5,775
 1,955
 4,328
 5,749

 56,026
 60,346
 15,402
 6,747
 12,726
 13,852

 Actuarial (gain)/loss
 39,643
 1,925
 ( 328)
 4,590
 ( 1,416)
 14,522

 Benefits paid (a)
 ( 164,643)
 ( 170,126)
 ( 45,901)
 ( 19,778)
 ( 41,219)
 ( 35,867)

 $ 1,117,585
 $ 1,173,283
 $ 295,942
 $ 133,950
 $ 239,984
 $ 286,558

 $ 961,178
 $ 1,035,574
 $ 265,736
 $ 119,710
 $ 226,417
 $ 240,392

 140,891
 148,698
 39,315
 16,571
 31,984
 35,375

 54,468
 44,565
 21,110
 1,420
 5,314
 15,543

 Benefits paid (a)
 ( 164,643)
 ( 170,126)
 ( 45,901)
 ( 19,778)
 ( 41,219)
 ( 35,867)

 $ 991,894
 $ 1,058,711
 $ 280,260
 $ 117,923
 $ 222,496
 $ 255,443

 ($ 125,691)
 ($ 114,572)
 ($ 15,682)
 ($ 16,027)
 ($ 17,488)
 ($ 31,115)

 Amounts recognized in the balance sheet (funded status)

 ($ 125,691)
 ($ 114,572)
 ($ 15,682)
 ($ 16,027)
 ($ 17,488)
 ($ 31,115)

 Amounts recognized as regulatory asset

 $ 485,113
 $ 319,116
 $ 102,208
 $ 44,911
 $ 63,665
 $ 111,996

 Amounts recognized as AOCI (before tax)

 $ —
 $ 13,296
 $ —
 $ —
 $ —
 $ —

 (a) Including settlement lump sum benefit payments of ($ 68.7) million at Entergy Arkansas, ($ 103.1) million at Entergy Louisiana, ($ 31.4) million at Entergy Mississippi, ($ 5.3) million at Entergy New Orleans, ($ 29.4) million at Entergy Texas, and ($ 16.7) million at System Energy.

 2022

 Change in Projected Benefit Obligation (PBO)

 $ 1,579,346
 $ 1,736,396
 $ 448,858
 $ 195,380
 $ 371,802
 $ 394,794

 25,210
 33,520
 8,043
 2,745
 5,999
 7,746

 45,378
 49,330
 12,979
 5,491
 10,729
 11,286

 Actuarial gain
 ( 280,691)
 ( 357,572)
 ( 88,303)
 ( 40,462)
 ( 65,795)
 ( 81,504)

 Benefits paid (a)
 ( 201,145)
 ( 205,252)
 ( 60,583)
 ( 22,718)
 ( 57,170)
 ( 44,020)

 $ 1,168,098
 $ 1,256,422
 $ 320,994
 $ 140,436
 $ 265,565
 $ 288,302

 $ 1,302,588
 $ 1,446,658
 $ 356,424
 $ 172,366
 $ 341,915
 $ 312,060

 ( 233,236)
 ( 259,490)
 ( 63,392)
 ( 31,067)
 ( 60,841)
 ( 56,267)

 92,971
 53,658
 33,287
 1,129
 2,513
 28,619

 Benefits paid (a)
 ( 201,145)
 ( 205,252)
 ( 60,583)
 ( 22,718)
 ( 57,170)
 ( 44,020)

 $ 961,178
 $ 1,035,574
 $ 265,736
 $ 119,710
 $ 226,417
 $ 240,392

 ($ 206,920)
 ($ 220,848)
 ($ 55,258)
 ($ 20,726)
 ($ 39,148)
 ($ 47,910)

 Amounts recognized in the balance sheet (funded status)

 ($ 206,920)
 ($ 220,848)
 ($ 55,258)
 ($ 20,726)
 ($ 39,148)
 ($ 47,910)

 Amounts recognized as regulatory asset

 $ 561,323
 $ 445,116
 $ 140,389
 $ 51,868
 $ 95,729
 $ 125,876

 Amounts recognized as AOCI (before tax)

 $ —
 $ 18,546
 $ —
 $ —
 $ —
 $ —

 (a) Including settlement lump sum benefit payments of ($ 96) million at Entergy Arkansas, ($ 146.6) million at Entergy Louisiana, ($ 48) million at Entergy Mississippi, ($ 16.2) million at Entergy New Orleans, ($ 48.9) million at Entergy Texas, and ($ 23.5) million at System Energy.

 The qualified pension plans incurred net actuarial gains during 2023 primarily due to asset gains resulting from an actual return on assets much higher than the expected return on assets, offset by liability losses due to a decline in bond yields that resulted in decreases to the discount rates used to develop the benefit obligations. The qualified pension plans incurred a small net actuarial loss during 2022 primarily due to asset losses resulting from an actual return on assets much lower than the expected return on assets, substantially offset by liability gains due to a rise in bond yields that resulted in increases to the discount rates used to develop the benefit obligations.

 Accumulated Pension Benefit Obligation

 The accumulated benefit obligation for Entergy's qualified pension plans was $ 5.6 billion and $ 5.7 billion at December 31, 2023 and 2022, respectively.

 The qualified pension accumulated benefit obligation for each of the Registrant Subsidiaries for their current and former employees as of December 31, 2023 and 2022 was as follows:

 2023
 2022

 $ 1,048,901
 $ 1,008,152

 $ 1,085,318
 $ 1,146,561

 $ 273,338
 $ 292,596

 $ 125,878
 $ 128,499

 $ 225,379
 $ 245,428

 $ 267,432
 $ 269,583

 Other Postretirement Benefits

 Entergy also currently offers retiree medical, dental, vision, and life insurance benefits (other postretirement benefits) for eligible retired employees. Employees who commenced employment before July 1, 2014 and who satisfy certain eligibility requirements (including retiring from Entergy after a certain age and/or years of service with Entergy and immediately commencing their Entergy pension benefit), may become eligible for other postretirement benefits.

 In March 2020, Entergy announced changes to its other postretirement benefits. Effective January 1, 2021, certain retired, former non-bargaining employees age 65 and older who are eligible for Entergy-sponsored retiree welfare benefits, and their eligible spouses who are age 65 and older (collectively, Medicare-eligible participants), are eligible to participate in an Entergy-sponsored retiree health plan, and are no longer eligible for retiree coverage under the Entergy Corporation Companies' Benefits Plus Medical, Dental and Vision Plans. Under the Entergy-sponsored retiree health plan, Medicare-eligible participants are eligible to participate in a health reimbursement arrangement which they may use towards the purchase of various types of qualified insurance offered through a Medicare exchange provider and for other qualified medical expenses. The changes affecting active bargaining unit employees were negotiated with the unions prior to implementation, where necessary, and to the extent required by law.

 Effective January 1, 1993, Entergy adopted an accounting standard requiring a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, and Entergy Texas have received regulatory approval to recover accrued other postretirement benefits costs through rates. The LPSC ordered Entergy Louisiana to continue the use of the pay-as-you-go method for ratemaking purposes for postretirement benefits other than pensions. However, the LPSC retains the flexibility to examine individual companies' accounting for other postretirement benefits to determine if special exceptions to this order are warranted. Pursuant to regulatory directives, Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy contribute the other postretirement benefits costs collected in rates into external trusts. System Energy is funding, on behalf of Entergy Operations, other postretirement benefits associated with employees who work or worked at Grand Gulf.

 Trust assets contributed by participating Registrant Subsidiaries are in master trusts, established by Entergy Corporation and maintained by a trustee. Each participating Registrant Subsidiary holds a beneficial interest in the trusts' assets. The assets in the master trusts are commingled for investment and administrative purposes. Although assets are commingled, supporting records are maintained for the purpose of allocating the beneficial interest in net earnings/(losses) and the administrative expenses of the investment accounts to the various participating plans and participating Registrant Subsidiaries. Beneficial interest in an investment account's net income/(loss) is comprised of interest and dividends, realized and unrealized gains and losses, and expenses. Beneficial interest from these

 investments is allocated to the plans and participating Registrant Subsidiary based on their portion of net assets in the pooled accounts.

 Components of Net Other Postretirement Benefits Cost and Other Amounts Recognized as a Regulatory Asset and/or AOCI

 Entergy Corporation's and its subsidiaries' total 2023, 2022, and 2021 other postretirement benefits costs, including amounts capitalized and amounts recognized as a regulatory asset and/or other comprehensive income, included the following components:

 2023
 2022
 2021

 Other postretirement costs:

 $ 14,654
 $ 24,734
 $ 26,578

 Interest cost on accumulated postretirement benefits obligation (APBO)
 42,272
 27,306
 21,278

 ( 36,732)
 ( 43,420)
 ( 43,220)

 Amortization of prior service credit
 ( 22,558)
 ( 25,550)
 ( 33,069)

 Recognized net (gain)/loss
 ( 11,446)
 4,333
 2,853

 Net other postretirement benefits income
 ($ 13,810)
 ($ 12,597)
 ($ 25,580)

 Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)

 Prior service credit for the period
 ($ 4,434)
 ($ 858)
 ($ 3,168)

 ( 44,441)
 ( 131,524)
 6,210

 Amounts reclassified from regulatory asset and/or AOCI to net periodic benefit cost in the current year:

 Amortization of prior service credit
 22,558
 25,550
 33,069

 Amortization of net gain/(loss)
 11,446
 ( 4,333)
 ( 2,853)

 Total
 ($ 14,871)
 ($ 111,165)
 $ 33,258

 Total recognized as net periodic other postretirement (income)/cost, regulatory asset, and/or AOCI (before tax)
 ($ 28,681)
 ($ 123,762)
 $ 7,678

 Total 2023, 2022, and 2021 other postretirement benefits costs of the Registrant Subsidiaries, including amounts capitalized and deferred, for their current and former employees included the following components:

 2023

 Other postretirement costs:

 $ 2,965
 $ 3,379
 $ 878
 $ 235
 $ 809
 $ 754

 Interest cost on APBO
 8,002
 8,931
 2,170
 1,160
 2,597
 1,726

 ( 15,113)
 —
 ( 4,716)
 ( 5,263)
 ( 8,776)
 ( 2,535)

 Amortization of prior service cost/(credit)
 2,096
 ( 3,804)
 ( 955)
 ( 916)
 ( 4,371)
 ( 293)

 Recognized net (gain)/loss
 ( 7,057)
 —

 Net other postretirement benefits (income)/cost
 ($ 1,879)
 $ 1,449
 ($ 2,538)
 ($ 4,318)
 ($ 8,827)
 ($ 348)

 Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)

 Prior service credit for the period
 $ —
 ($ 4,434)
 $ —
 $ —
 $ —
 $ —

 ( 23,033)
 ( 458)
 ( 6,883)
 ( 7,606)
 ( 8,790)
 ( 3,942)

 Amounts reclassified from regulatory asset and/or AOCI to net periodic benefit cost in the current year:

 Amortization of prior service credit/(cost)
 ( 2,096)
 3,804
 4,371

 Amortization of net gain/(loss)
 ( 171)
 7,057
 ( 85)
 ( 466)
 ( 914)
 —

 Total
 ($ 25,300)
 $ 5,969
 ($ 6,013)
 ($ 7,156)
 ($ 5,333)
 ($ 3,649)

 Total recognized as net periodic other postretirement (income)/cost, regulatory asset, and/or AOCI (before tax)
 ($ 27,179)
 $ 7,418
 ($ 8,551)
 ($ 11,474)
 ($ 14,160)
 ($ 3,997)

 2022

 Other postretirement costs:

 $ 4,457
 $ 5,633
 $ 1,354
 $ 397
 $ 1,322
 $ 1,239

 Interest cost on APBO
 5,050
 5,770
 1,401
 1,596
 1,116

 ( 17,930)
 —
 ( 5,575)
 ( 5,997)
 ( 10,273)
 ( 3,162)

 Amortization of prior service cost/(credit)
 1,885
 ( 4,630)
 ( 1,772)
 ( 916)
 ( 4,371)
 ( 319)

 Recognized net (gain)/loss
 ( 744)
 ( 898)

 Net other postretirement benefits (income)/cost
 ($ 5,665)
 $ 6,029
 ($ 4,370)
 ($ 6,720)
 ($ 11,078)
 ($ 1,005)

 Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)

 Prior service cost/(credit) for the period
 $ 273
 $ 323
 ($ 1,300)
 $ —
 $ —
 $ 141

 12,894
 ( 65,501)
 6,629
 17,334
 22,323
 1,208

 Amounts reclassified from regulatory asset and/or AOCI to net periodic benefit cost in the current year:

 Amortization of prior service credit/(cost)
 ( 1,885)
 4,630
 1,772
 4,371

 Amortization of net gain/(loss)
 ( 873)
 ( 222)
 ( 648)
 ( 121)

 Total
 $ 10,409
 ($ 59,804)
 $ 6,879
 $ 19,148
 $ 26,046
 $ 1,547

 Total recognized as net periodic other postretirement (income)/cost, regulatory asset, and/or AOCI (before tax)
 $ 4,744
 ($ 53,775)
 $ 2,509
 $ 12,428
 $ 14,968
 $ 542

 2021

 Other postretirement costs:

 $ 4,135
 $ 6,174
 $ 1,448
 $ 437
 $ 1,384
 $ 1,340

 Interest cost on APBO
 3,726
 4,520
 1,110
 1,269

 ( 18,020)
 —
 ( 5,536)
 ( 5,750)
 ( 10,192)
 ( 3,156)

 Amortization of prior service credit
 ( 1,121)
 ( 4,920)
 ( 1,775)
 ( 916)
 ( 3,742)
 ( 436)

 Recognized net (gain)/loss
 ( 364)
 ( 712)

 Net other postretirement benefits (income)/cost
 ($ 11,084)
 $ 5,410
 ($ 4,677)
 ($ 6,420)
 ($ 10,883)
 ($ 1,313)

 Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)

 Prior service cost/(credit) for the period
 ($ 85)
 $ 357
 $ —
 $ —
 ($ 3,776)
 $ 69

 9,956
 ( 2,367)
 ( 2,823)
 ( 3,330)

 Amounts reclassified from regulatory asset and/or AOCI to net periodic benefit cost in the current year:

 Amortization of prior service credit
 1,121
 4,920
 1,775
 3,742

 Amortization of net gain/(loss)
 ( 196)
 ( 76)
 ( 398)
 ( 61)

 Total
 $ 10,796
 $ 3,274
 ($ 1,124)
 ($ 1,702)
 $ 507
 $ 654

 Total recognized as net periodic other postretirement (income)/cost, regulatory asset, and/or AOCI (before tax)
 ($ 288)
 $ 8,684
 ($ 5,801)
 ($ 8,122)
 ($ 10,376)
 ($ 659)

 Other Postretirement Benefits Obligations, Plan Assets, Funded Status, and Amounts Not Yet Recognized and Recognized in the Balance Sheet

 Other postretirement benefits obligations, plan assets, funded status, and amounts not yet recognized and recognized in the Consolidated Balance Sheets of Entergy Corporation and its Subsidiaries as of December 31, 2023 and 2022 are as follows:

 2023
 2022

 Change in APBO

 $ 865,854
 $ 1,189,682

 14,654
 24,734

 42,272
 27,306

 Plan amendments
 ( 4,434)
 ( 858)

 18,669
 22,486

 Actuarial gain
 ( 4,303)
 ( 297,128)

 ( 95,348)
 ( 100,632)

 Medicare Part D subsidy received

 $ 837,644
 $ 865,854

 $ 623,824
 $ 771,319

 76,870
 ( 122,184)

 49,126
 52,835

 18,669
 22,486

 ( 95,348)
 ( 100,632)

 $ 673,141
 $ 623,824

 ($ 164,503)
 ($ 242,030)

 Amounts recognized in the balance sheet

 ($ 45,706)
 ($ 42,484)

 ( 118,797)
 ( 199,546)

 ($ 164,503)
 ($ 242,030)

 Amounts recognized as a regulatory asset

 Prior service credit
 ($ 21,465)
 ($ 29,323)

 ( 33,617)
 16,956

 ($ 55,082)
 ($ 12,367)

 Amounts recognized as AOCI (before tax)

 Prior service credit
 ($ 34,899)
 ($ 45,167)

 ( 116,078)
 ( 133,656)

 ($ 150,977)
 ($ 178,823)

 Other postretirement benefits obligations, plan assets, funded status, and amounts not yet recognized and recognized in the Balance Sheets of the Registrant Subsidiaries as of December 31, 2023 and 2022 are as follows:

 2023

 Change in APBO

 $ 164,018
 $ 183,126
 $ 44,365
 $ 23,971
 $ 53,482
 $ 35,274

 2,965
 3,379

 8,002
 8,931
 2,170
 1,160
 2,597
 1,726

 Plan amendments
 —
 ( 4,434)
 —
 —
 —
 —

 3,131
 4,317
 1,386

 Actuarial (gain)/loss
 ( 6,403)
 ( 458)
 ( 1,650)
 ( 1,676)
 ( 1,075)

 ( 15,759)
 ( 24,768)
 ( 5,815)
 ( 2,384)
 ( 6,299)
 ( 3,908)

 Medicare Part D subsidy received

 $ 155,987
 $ 170,139
 $ 41,344
 $ 21,685
 $ 51,617
 $ 33,778

 $ 255,117
 $ —
 $ 79,496
 $ 91,140
 $ 148,799
 $ 42,434

 31,743
 —
 9,949
 11,193
 17,903
 5,402

 20,451

 3,131
 4,317
 1,386

 ( 15,759)
 ( 24,768)
 ( 5,815)
 ( 2,384)
 ( 6,299)
 ( 3,908)

 $ 274,814
 $ —
 $ 85,662
 $ 100,536
 $ 161,318
 $ 45,402

 $ 118,827
 ($ 170,139)
 $ 44,318
 $ 78,851
 $ 109,701
 $ 11,624

 Amounts recognized in the balance sheet

 $ —
 ($ 15,049)
 $ —
 $ —
 $ —
 $ —

 118,827
 ( 155,090)
 44,318
 78,851
 109,701
 11,624

 $ 118,827
 ($ 170,139)
 $ 44,318
 $ 78,851
 $ 109,701
 $ 11,624

 Amounts recognized in regulatory asset

 Prior service cost/(credit)
 $ 4,983
 $ —
 ($ 2,682)
 ($ 1,982)
 ($ 11,790)
 ($ 496)

 Net loss/(gain)
 ( 17,980)
 —
 ( 4,815)
 ( 5,843)
 14,542

 ($ 12,997)
 $ —
 ($ 7,497)
 ($ 7,825)
 $ 2,752
 ($ 384)

 Amounts recognized in AOCI (before tax)

 Prior service credit
 $ —
 ($ 12,645)
 $ —
 $ —
 $ —
 $ —

 —
 ( 75,709)
 —
 —
 —
 —

 $ —
 ($ 88,354)
 $ —
 $ —
 $ —
 $ —

 2022

 Change in APBO

 $ 221,183
 $ 253,031
 $ 61,001
 $ 31,866
 $ 71,961
 $ 47,875

 4,457
 5,633
 1,354
 1,322
 1,239

 5,050
 5,770
 1,401
 1,596
 1,116

 Plan amendments
 ( 1,300)
 —
 —

 5,521
 5,081
 1,443
 1,222

 Actuarial gain
 ( 54,923)
 ( 65,501)
 ( 14,465)
 ( 6,867)
 ( 16,291)
 ( 10,679)

 ( 17,585)
 ( 21,268)
 ( 5,075)
 ( 2,566)
 ( 6,046)
 ( 5,657)

 Medicare Part D subsidy received

 $ 164,018
 $ 183,126
 $ 44,365
 $ 23,971
 $ 53,482
 $ 35,274

 $ 315,495
 $ —
 $ 97,888
 $ 111,137
 $ 182,285
 $ 54,650

 ( 49,887)
 —
 ( 15,519)
 ( 18,204)
 ( 28,341)
 ( 8,725)

 1,573
 16,187
 ( 23)

 5,521
 5,081
 1,443
 1,222

 ( 17,585)
 ( 21,268)
 ( 5,075)
 ( 2,566)
 ( 6,046)
 ( 5,657)

 $ 255,117
 $ —
 $ 79,496
 $ 91,140
 $ 148,799
 $ 42,434

 $ 91,099
 ($ 183,126)
 $ 35,131
 $ 67,169
 $ 95,317
 $ 7,160

 Amounts recognized in the balance sheet

 $ —
 ($ 15,356)
 $ —
 $ —
 $ —
 $ —

 91,099
 ( 167,770)
 35,131
 67,169
 95,317
 7,160

 $ 91,099
 ($ 183,126)
 $ 35,131
 $ 67,169
 $ 95,317
 $ 7,160

 Amounts recognized in regulatory asset

 Prior service cost/(credit)
 $ 7,079
 $ —
 ($ 3,637)
 ($ 2,898)
 ($ 16,161)
 ($ 789)

 5,224
 —
 2,153
 2,229
 24,246
 4,054

 $ 12,303
 $ —
 ($ 1,484)
 ($ 669)
 $ 8,085
 $ 3,265

 Amounts recognized in AOCI (before tax)

 Prior service credit
 $ —
 ($ 12,015)
 $ —
 $ —
 $ —
 $ —

 —
 ( 82,308)
 —
 —
 —
 —

 $ —
 ($ 94,323)
 $ —
 $ —
 $ —
 $ —

 The other postretirement plans incurred net actuarial gains during 2023 primarily due to updated demographic assumptions and census data coupled with an actual return on assets much higher than the expected return on assets, partially offset by liability losses due to a decline in bond yields that resulted in decreases to the discount rates used to develop the benefit obligations. The other postretirement plans incurred net actuarial gains during 2022 primarily due to a rise in bond yields that resulted in increases to the discount rates used to develop the benefit obligations, partially offset by asset losses due to an actual return on assets much lower than the expected return on assets during 2022.

 Non-Qualified Pension Plans

 Entergy also sponsors non-qualified, non-contributory defined benefit pension plans that provide benefits to certain key employees. Entergy recognized net periodic pension cost related to these plans of $ 43.8 million in 2023, $ 30.9 million in 2022, and $ 28.6 million in 2021. In 2023, 2022, and 2021, Entergy recognized $ 27.9 million, $ 12.2 million, and $ 10.9 million, respectively, in settlement charges related to the payment of lump sum benefits out of the plan that is included in the non-qualified pension plan cost above.

 The projected benefit obligation was $ 88.6 million as of December 31, 2023 of which $ 13.8 million was a current liability and $ 74.8 million was a non-current liability. The projected benefit obligation was $ 152.4 million as of December 31, 2022 of which $ 62.4 million was a current liability and $ 90 million was a non-current liability. The accumulated benefit obligation was $ 77.9 million and $ 140 million as of December 31, 2023 and 2022, respectively. The unamortized prior service cost and net loss are recognized in regulatory assets ($ 29.7 million at December 31, 2023 and $ 56.8 million at December 31, 2022) and accumulated other comprehensive income before taxes ($ 3.9 million at December 31, 2023 and $ 8.7 million at December 31, 2022).

 A Rabbi Trust was established for the benefit of certain participants in Entergy's non-qualified, non-contributory defined benefit pension plans. The Rabbi Trust assets were invested in money-market funds which were recorded at fair value with all gains and losses recognized immediately in income. All of the investments were classified as Level 1 investments for purposes of Fair Value Measurements. At December 31, 2022, the fair value of the assets held in the Rabbi Trust was $ 35 million. In August 2023 the Rabbi Trust assets were used to pay benefits due under the non-qualified pension plans.

 The following Registrant Subsidiaries participate in Entergy's non-qualified, non-contributory defined benefit pension plans that provide benefits to certain key employees. The net periodic pension cost for their current and former employees for the non-qualified plans for 2023, 2022, and 2021, was as follows:

 2023
 $ 637
 $ 99
 $ 808
 $ 132
 $ 253

 2022
 $ 282
 $ 102
 $ 321
 $ 114
 $ 1,320

 2021
 $ 343
 $ 307
 $ 365
 $ 30
 $ 615

 Included in the 2023 net periodic pension cost above are settlement charges of $ 379 thousand and $ 453 thousand for Entergy Arkansas and Entergy Mississippi, respectively, related to the lump sum benefits paid out of the plan. Included in the 2022 net periodic pension cost above are settlement charges of $ 1 thousand, $ 2 thousand, and $ 1 million for Entergy Louisiana, Entergy Mississippi, and Entergy Texas, respectively, related to the lump sum benefits paid out of the plan. Included in the 2021 net periodic pension cost above are settlement charges of $ 155 thousand and $ 172 thousand for Entergy Louisiana and Entergy Texas, respectively, related to the lump sum benefits paid out of the plan.

 The projected benefit obligation for their current and former employees for the non-qualified plans as of December 31, 2023 and 2022 was as follows:

 2023
 $ 2,313
 $ 2,574
 $ 3,369
 $ 1,034
 $ 3,762

 2022
 $ 2,433
 $ 1,197
 $ 3,830
 $ 1,024
 $ 3,850

 The accumulated benefit obligation for their current and former employees for the non-qualified plans as of December 31, 2023 and 2022 was as follows:

 2023
 $ 1,935
 $ 2,494
 $ 3,187
 $ 814
 $ 3,701

 2022
 $ 2,192
 $ 1,197
 $ 3,594
 $ 719
 $ 3,776

 The following amounts were recorded on the balance sheet as of December 31, 2023 and 2022:

 2023

 ($ 276)
 ($ 308)
 ($ 474)
 ($ 106)
 ($ 448)

 ( 2,037)
 ( 2,266)
 ( 2,895)
 ( 928)
 ( 3,314)

 ($ 2,313)
 ($ 2,574)
 ($ 3,369)
 ($ 1,034)
 ($ 3,762)

 Regulatory asset/(liability)
 $ 857
 $ 1,604
 $ 1,303
 $ 5
 ($ 2,526)

 Accumulated other comprehensive income (before taxes)
 $ —
 $ 67
 $ —
 $ —
 $ —

 2022

 ($ 234)
 ($ 184)
 ($ 214)
 ($ 32)
 ($ 448)

 ( 2,199)
 ( 1,013)
 ( 3,616)
 ( 992)
 ( 3,402)

 ($ 2,433)
 ($ 1,197)
 ($ 3,830)
 ($ 1,024)
 ($ 3,850)

 Regulatory asset/(liability)
 $ 512
 $ 119
 $ 1,291
 $ 111
 ($ 2,615)

 Accumulated other comprehensive income (before taxes)
 $ —
 $ 5
 $ —
 $ —
 $ —

 The non-qualified pension plans incurred a small actuarial loss during 2023 primarily as a result of liability losses due to differences in recent retirement and lump sum experience relative to actuarial assumptions. The non-qualified pension plans incurred a small actuarial gain during 2022 primarily due to a rise in bond yields that resulted in increases to the discount rates used to develop the benefit obligations, partially offset by differences in recent retirement and lump sum experience relative to actuarial assumptions.

 Reclassification out of Accumulated Other Comprehensive Income (Loss)

 Entergy and Entergy Louisiana reclassified the following costs out of accumulated other comprehensive income (loss) (before taxes and including amounts capitalized) as of December 31, 2023:

 Qualified Pension Costs
 Other Postretirement Costs
 Non-Qualified Pension Costs
 Total

 Amortization of prior service cost
 $ —
 $ 14,038
 ($ 452)
 $ 13,586

 Amortization of gain (loss)
 ( 4,407)
 11,590
 ( 593)
 6,590

 ( 7,844)
 —
 ( 3,004)
 ( 10,848)

 ($ 12,251)
 $ 25,628
 ($ 4,049)
 $ 9,328

 Amortization of prior service cost
 $ —
 $ 3,804
 $ —
 $ 3,804

 Amortization of gain (loss)
 ( 792)
 7,057
 ( 2)
 6,263

 ( 1,617)
 —
 —
 ( 1,617)

 ($ 2,409)
 $ 10,861
 ($ 2)
 $ 8,450

 Entergy and Entergy Louisiana reclassified the following costs out of accumulated other comprehensive income (loss) (before taxes and including amounts capitalized) as of December 31, 2022:

 Qualified Pension Costs
 Other Postretirement Costs
 Non-Qualified Pension Costs
 Total

 Amortization of prior service cost
 $ —
 $ 16,052
 ($ 715)
 $ 15,337

 Amortization of loss
 ( 30,147)
 ( 2,381)
 ( 1,331)
 ( 33,859)

 ( 23,636)
 —
 ( 1,685)
 ( 25,321)

 ($ 53,783)
 $ 13,671
 ($ 3,731)
 ($ 43,843)

 Amortization of prior service cost
 $ —
 $ 4,630
 $ —
 $ 4,630

 Amortization of gain (loss)
 ( 1,669)
 ( 2)
 ( 927)

 ( 2,342)
 —
 —
 ( 2,342)

 ($ 4,011)
 $ 5,374
 ($ 2)
 $ 1,361

 Accounting for Pension and Other Postretirement Benefits

 Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. This is measured as the difference between plan assets at fair value and the benefit obligation. Entergy uses a December 31 measurement date for its pension and other postretirement plans. Employers are to record previously unrecognized gains and losses, prior service costs, and any remaining transition asset or obligation (that resulted from adopting prior pension and other postretirement benefits accounting standards) as comprehensive income and/or as a regulatory asset reflective of the recovery mechanism for pension and other postretirement benefits costs in the Registrant Subsidiaries' respective regulatory jurisdictions. For the portion of Entergy Louisiana that is not regulated, the unrecognized prior service cost, gains and losses, and transition asset/obligation for its pension and other postretirement benefits obligations are recorded as other comprehensive income. Entergy Louisiana recovers other postretirement benefits costs on a pay-as-you-go basis and records the unrecognized prior

 service cost, gains and losses, and transition obligation for its other postretirement benefits obligation as other comprehensive income. Accounting standards also require that changes in the funded status be recorded as other comprehensive income and/or a regulatory asset in the period in which the changes occur.

 With regard to pension and other postretirement costs, 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.

 In accordance with ASU No. 2017-07, "Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost", the other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations and are presented by Entergy in miscellaneous - net in other income.

 Qualified Pension Settlement Cost

 Year-to-date lump sum benefit payments from Non-Bargaining Plan I, Bargaining Plan I, Non-Bargaining Plan II, and Bargaining Plan II exceeded the sum of the Plans' service and interest cost, resulting in settlement costs during 2023, 2022, and 2021. In accordance with accounting standards, settlement accounting requires immediate recognition of the portion of previously unrecognized losses associated with the settled portion of the plans' pension liability. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy participate in one or both of Non-Bargaining Plan I and Bargaining Plan I and incurred settlement costs. Similar to other pension costs, the settlement costs were included with employee labor costs and charged to expense and capital in the same manner that labor costs were charged. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans received regulatory approval to defer the expense portion of settlement costs, with future amortization of the deferred settlement expense over the period in which the expense otherwise would be recorded had the immediate recognition not occurred.

 Entergy Texas Reserve

 In September 2020, Entergy Texas elected to establish a reserve, in accordance with PUCT regulations, to track the surplus or deficit in the annual amount of actuarially determined pension and other postretirement benefits chargeable to Entergy Texas's expense. The reserve amounts recorded for 2020 and 2021 were included in the base rate case that was filed with the PUCT in July 2022, and amortization of that amount began in 2023 when interim rates became effective. The reserve amounts recorded for 2022 and through December 2023 will be evaluated in the next rate case filed by Entergy Texas, and an amortization period will be determined at that time. At December 31, 2023, the balance in this reserve was approximately $ 32.7 million.

 Qualified Pension and Other Postretirement Plans' Assets

 The Plan Administrator's trust asset investment strategy is to invest the assets in a manner whereby long-term earnings on the assets (plus cash contributions) provide adequate funding for retiree benefit payments. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense.

 In the optimization studies, the Plan Administrator formulates assumptions about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes. The future market assumptions used in the optimization study are determined by examining historical

 market characteristics of the various asset classes and making adjustments to reflect future conditions expected to prevail over the study period.

 The target asset allocation for pension adjusts dynamically based on the funded status of each plan within the trust. The current targets are shown below. The expectation is that the allocation to fixed income securities will increase as the pension plans' funded status increases. The following ranges were established to produce an acceptable, economically efficient plan to manage around the targets.

 For postretirement assets the target and range asset allocations (as shown below) reflect recommendations made in the latest optimization study. The target asset allocations for postretirement assets adjust dynamically based on the funded status of each sub-account within each trust. The current weighted-average targets shown below represent the aggregate of all targets for all sub-accounts within all trusts.

 Entergy's qualified pension and postretirement weighted-average asset allocations by asset category at December 31, 2023 and 2022 and the target asset allocation and ranges for 2023 are as follows:

 Pension Asset Allocation
 Range
 Actual 2023
 Actual 2022

 Domestic Equity Securities
 32 %
 26 %
 to
 38 %
 33 %
 42 %

 International Equity Securities
 17 %
 14 %
 to
 20 %
 18 %
 22 %

 Intermediate Fixed Income Securities
 8 %
 7 %
 to
 9 %
 9 %
 11 %

 Long Duration Fixed Income Securities
 43 %
 39 %
 to
 47 %
 40 %
 22 %

 Other
 — %
 — %
 to
 10 %
 — %
 3 %

 Postretirement Asset Allocation
 Non-Taxable and Taxable

 Range
 Actual 2023
 Actual 2022

 Domestic Equity Securities
 25 %
 20 %
 to
 30 %
 28 %
 25 %

 International Equity Securities
 17 %
 12 %
 to
 22 %
 17 %
 18 %

 Fixed Income Securities
 58 %
 53 %
 to
 63 %
 55 %
 57 %

 Other
 — %
 — %
 to
 5 %
 — %
 — %

 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 investment managers.

 The expected long-term rate of return for the qualified pension plans' assets is based primarily on the geometric average of the historical annual performance of a representative portfolio weighted by the target asset allocation defined in the table above, along with other indications of expected return on assets. The time period reflected is a long-dated period spanning several decades.

 The expected long-term rate of return for the non-taxable postretirement trust assets is determined using the same methodology described above for pension assets, but the aggregate asset allocation specific to the non-taxable postretirement assets is used.

 For the taxable postretirement trust assets, the investment allocation includes tax-exempt fixed income securities. This asset allocation, in combination with the same methodology employed to determine the expected return for other postretirement assets (as described above), and with a modification to reflect applicable taxes, is used to produce the expected long-term rate of return for taxable postretirement trust assets.

 Concentrations of Credit Risk

 Entergy's investment guidelines mandate the avoidance of risk concentrations. Types of concentrations specified to be avoided include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, geographic area, and individual security issuance. As of December 31, 2023, all investment managers and assets were materially in compliance with the approved investment guidelines, therefore there were no significant concentrations (defined as greater than 10 percent of plan assets) of credit risk in Entergy's pension and other postretirement benefits plan assets.

 Fair Value Measurements

 Accounting standards provide the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

 The three levels of the fair value hierarchy are described below:

 • Level 1 - Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in active markets that the Plan has the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

 • Level 2 - Level 2 inputs are inputs other than quoted prices included in Level 1 that are, either directly or indirectly, observable for the asset or liability at the measurement date. Assets are valued based on prices derived by an independent party that uses inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads. Prices are reviewed and can be challenged with the independent parties and/or overridden if it is believed such would be more reflective of fair value. Level 2 inputs include the following:

 - quoted prices for similar assets or liabilities in active markets;
 - quoted prices for identical assets or liabilities in inactive markets;
 - inputs other than quoted prices that are observable for the asset or liability; or
 - inputs that are derived principally from or corroborated by observable market data by correlation or other means.

 If an asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability.

 • Level 3 - Level 3 refers to securities valued based on significant unobservable inputs.

 Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following tables set forth by level within the fair value hierarchy, measured at fair value on a recurring basis at December 31, 2023, and December 31, 2022, a summary of the investments held in the master trusts for Entergy's qualified pension and other postretirement plans in which the Registrant Subsidiaries participate.

 Qualified Defined Benefit Pension Plan Trusts

 2023

 Total

 Equity securities:

 Corporate stocks:

 Preferred
 $ 10,827
 (b)
 $ —
 $ —
 $ 10,827

 715,452
 (b)
 —
 —
 715,452

 Common collective trusts (c)

 2,066,247

 Fixed income securities:

 U.S. Government securities
 —
 1,085,231
 (a)
 —
 1,085,231

 Corporate debt instruments
 —

 924,904
 (a)
 —
 924,904

 Registered investment companies (e)
 34,364
 (d)
 2,718
 (d)
 —
 657,691

 Other
 (f)
 78,883
 (f)
 —
 79,657

 Insurance company general account (unallocated contracts)
 —

 5,899
 (g)
 —
 5,899

 Total investments
 $ 761,417

 $ 2,097,635

 $ —
 $ 5,545,908

 Cash

 1,488

 Other pending transactions

 ( 22,404)

 Less: Other postretirement assets included in total investments

 ( 64,391)

 Total fair value of qualified pension assets

 $ 5,460,601

 2022

 Total

 Equity securities:

 Corporate stocks:

 Preferred
 $ 12,178
 (b)
 $ —
 $ —
 $ 12,178

 807,437
 (b)
 —
 —
 807,437

 Common collective trusts (c)

 2,516,688

 Fixed income securities:

 U.S. Government securities
 —
 673,348
 (a)
 —
 673,348

 Corporate debt instruments
 —

 525,184
 (a)
 —
 525,184

 Registered investment companies (e)
 221,582
 (d)
 2,595
 (d)
 —
 750,454

 Other
 —
 15,395
 (f)
 —
 15,395

 Insurance company general account (unallocated contracts)
 —

 5,911
 (g)
 —
 5,911

 Total investments
 $ 1,041,197

 $ 1,222,433

 $ —
 $ 5,306,595

 Cash

 10,601

 Other pending transactions

 ( 13,813)

 Less: Other postretirement assets included in total investments

 ( 61,285)

 Total fair value of qualified pension assets

 $ 5,242,098

 Other Postretirement Trusts

 2023

 Total

 Equity securities:

 Common collective trust (c)

 $ 276,560

 Fixed income securities:

 U.S. Government securities
 $ 80,219
 (b)
 $ 84,521
 (a)
 $ —
 164,740

 Corporate debt instruments
 —

 106,523
 (a)
 —
 106,523

 Registered investment companies
 (d)
 —

 —

 Other
 —

 57,511
 (f)
 —
 57,511

 Total investments
 $ 80,767

 $ 248,555

 $ —
 $ 605,882

 Other pending transactions

 2,868

 Plus: Other postretirement assets included in the investments of the qualified pension trust

 64,391

 Total fair value of other postretirement assets

 $ 673,141

 2022

 Total

 Equity securities:

 Common collective trust (c)

 $ 241,676

 Fixed income securities:

 U.S. Government securities
 $ 69,503
 (b)
 $ 78,436
 (a)
 $ —
 147,939

 Corporate debt instruments
 —

 113,273
 (a)
 —
 113,273

 Registered investment companies
 3,016
 (d)
 —

 —
 3,016

 Other
 —

 56,149
 (f)
 —
 56,149

 Total investments
 $ 72,519

 $ 247,858

 $ —
 $ 562,053

 Other pending transactions

 Plus: Other postretirement assets included in the investments of the qualified pension trust

 61,285

 Total fair value of other postretirement assets

 $ 623,824

 (a)Certain fixed income debt securities (corporate, government, and securitized) are stated at fair value as determined by broker quotes.
 (b)Common stocks, preferred stocks, and certain fixed income debt securities (government) are stated at fair value determined by quoted market prices.
 (c)The common collective trusts hold investments in accordance with stated objectives. The investment strategy of the trusts is to capture the growth potential of equity markets by replicating the performance of a specified index. The issuer of these funds allows daily trading at the net asset value and trades settle at a later date, with no other trading restrictions. Net asset value per share of common collective trusts estimate fair value. Common collective trusts are not publicly quoted and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table, but are included in the total.

 (d)Registered investment companies are money market mutual funds with a stable net asset value of one dollar per share. Registered investment companies may hold investments in domestic and international bond markets or domestic equities valued at the daily closing price as reported by the fund. These funds are required to publish their daily net asset value and to transact at that price. The money market mutual funds held by the trusts are deemed to be actively traded. Certain registered investment companies are recorded at contract value, which approximates fair value.
 (e)Certain of these registered investment companies are not publicly quoted and are valued by the fund administrators using net asset value as a practical expedient. The issuer of these funds allows daily trading at the net asset value and trades settle at a later date, with no other trading restrictions. Accordingly, these funds are not assigned a level in the fair value table, but are included in the total.
 (f)The other remaining assets are U.S. municipal and foreign government bonds stated at fair value as determined by broker quotes.
 (g)The unallocated insurance contract investments are recorded at contract value, which approximates fair value. The contract value represents contributions made under the contract, plus interest, less funds used to pay benefits and contract expenses, and less distributions to the master trust.

 Estimated Future Benefit Payments

 Based upon the assumptions used to measure Entergy's qualified pension and other postretirement benefits obligations at December 31, 2023, and including pension and other postretirement benefits attributable to estimated future employee service, Entergy expects that benefits to be paid over the next ten years for Entergy Corporation and its subsidiaries will be as follows:

 Estimated Future Benefits Payments

 Qualified Pension
 Non-Qualified Pension
 Other Postretirement

 Year(s)

 2024
 $ 463,557
 $ 13,802
 $ 74,649

 2025
 $ 449,803
 $ 10,894
 $ 70,720

 2026
 $ 450,945
 $ 8,507
 $ 67,105

 2027
 $ 449,510
 $ 14,374
 $ 63,949

 2028
 $ 450,827
 $ 9,325
 $ 61,234

 2029 - 2033
 $ 2,222,959
 $ 36,584
 $ 283,477

 Based upon the same assumptions, Entergy expects that benefits to be paid over the next ten years for the Registrant Subsidiaries for their current and former employees will be as follows:

 Estimated Future Qualified Pension Benefits Payments

 Year(s)

 2024
 $ 90,682
 $ 95,706
 $ 25,534
 $ 11,300
 $ 21,807
 $ 24,163

 2025
 $ 89,113
 $ 92,420
 $ 24,816
 $ 10,799
 $ 21,019
 $ 22,053

 2026
 $ 88,427
 $ 92,499
 $ 25,210
 $ 10,910
 $ 21,268
 $ 21,612

 2027
 $ 87,845
 $ 91,485
 $ 24,686
 $ 10,566
 $ 20,407
 $ 22,665

 2028
 $ 87,719
 $ 91,450
 $ 24,147
 $ 10,458
 $ 20,074
 $ 22,107

 2029 - 2033
 $ 429,882
 $ 444,131
 $ 115,629
 $ 48,870
 $ 92,182
 $ 109,712

 Estimated Future Non-Qualified Pension Benefits Payments

 Year(s)

 2024
 $ 276
 $ 308
 $ 474
 $ 106
 $ 448

 2025
 $ 474
 $ 301
 $ 547
 $ 143
 $ 423

 2026
 $ 160
 $ 288
 $ 461
 $ 139
 $ 445

 2027
 $ 149
 $ 265
 $ 642
 $ 224
 $ 395

 2028
 $ 288
 $ 270
 $ 395
 $ 141
 $ 369

 2029 - 2033
 $ 938
 $ 941
 $ 1,326
 $ 529
 $ 1,524

 Estimated Future Other Postretirement Benefits Payments

 Year(s)

 2024
 $ 13,697
 $ 15,049
 $ 3,521
 $ 2,200
 $ 5,187
 $ 2,811

 2025
 $ 12,913
 $ 14,380
 $ 3,386
 $ 2,086
 $ 4,874
 $ 2,668

 2026
 $ 12,342
 $ 13,676
 $ 3,256
 $ 1,942
 $ 4,436
 $ 2,434

 2027
 $ 11,767
 $ 13,037
 $ 3,126
 $ 1,785
 $ 4,215
 $ 2,320

 2028
 $ 11,424
 $ 12,348
 $ 3,121
 $ 1,640
 $ 3,937
 $ 2,266

 2029 - 2033
 $ 54,789
 $ 57,264
 $ 14,563
 $ 7,297
 $ 17,857
 $ 11,270

 Contributions

 Entergy currently expects to contribute approximately $ 270 million to its qualified pension plans and approximately $ 45.9 million to other postretirement plans in 2024. The expected 2024 pension and other postretirement plan contributions of the Registrant Subsidiaries for their employees are shown below. The 2024 required pension contributions will be known with more certainty when the January 1, 2024 valuations are completed, which is expected by April 1, 2024.

 The Registrant Subsidiaries expect to contribute approximately the following to the qualified pension and other postretirement plans for their current and former employees in 2024:

 Pension Contributions
 $ 55,112
 $ 48,401
 $ 14,980
 $ 4,931
 $ 8,272
 $ 16,650

 Other Postretirement Contributions
 $ 529
 $ 15,049
 $ 178
 $ 205
 $ 156
 $ 34

 Actuarial Assumptions

 The significant actuarial assumptions used in determining the pension PBO and the other postretirement benefits APBO as of December 31, 2023 and 2022 were as follows:

 2023
 2022

 Qualified pension
 5.02 % - 5.10 %
 Blended 5.06 %

 5.21 % - 5.27 %
 Blended 5.24 %

 Other postretirement
 5.01 %
 5.20 %

 Non-qualified pension
 4.68 %
 4.98 %

 Weighted-average rate of increase in future compensation levels

 Interest crediting rate

 Assumed health care trend rate:

 Pre-65
 6.95 %
 6.65 %

 Post-65
 7.88 %
 7.50 %

 Ultimate health care cost trend rate

 Year ultimate health care cost trend rate is reached and beyond:

 Pre-65
 2032
 2032

 Post-65
 2032
 2032

 The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefits costs for 2023, 2022, and 2021 were as follows:

 2023
 2022
 2021

 Qualified pension:

 5.26 %
 3.07 %
 2.81 %

 5.16 %
 2.49 %
 2.08 %

 Other postretirement:

 5.00 %
 3.20 %
 2.98 %

 5.09 %
 2.31 %
 1.86 %

 Non-qualified pension:

 5.31 %
 4.94 %
 1.48 %

 5.30 %
 5.03 %
 2.14 %

 Weighted-average rate of increase in future compensation levels

 Expected long-term rate of return on plan assets:

 Pension assets
 7.00 %
 6.75 %
 6.75 %

 Other postretirement non-taxable assets
 6.00 % - 7.00 %

 5.75 % - 6.75 %

 6.00 % - 6.75 %

 Other postretirement taxable assets
 5.25 %
 5.00 %

 Assumed health care trend rate:

 Pre-65
 6.65 %
 5.65 %
 5.87 %

 Post-65
 7.50 %
 5.90 %
 6.31 %

 Ultimate health care cost trend rate

 Year ultimate health care cost trend rate is reached and beyond:

 Pre-65
 2032
 2032
 2030

 Post-65
 2032
 2032
 2028

 With respect to the mortality assumptions, Entergy used the Pri-2012 Employee and Healthy Annuitant Table, projected generationally using Scale MP-2021 with Aon's Endemic Adjustment, in determining its December 31, 2023 pension plans' PBOs and the Pri. H 2012 (headcount weighted) Employee and Healthy Annuitant Table, projected generationally using Scale MP-2021 with Aon's Endemic Adjustment, in determining its December 31, 2023 other postretirement benefits APBO. With respect to the mortality assumptions, Entergy used the Pri-2012 Employee and Healthy Annuitant Tables with a fully generational MP-2020 projection scale, in determining its December 31, 2022 pension plans' PBOs and the Pri. H 2012 (headcount weighted) Employee and Healthy Annuitant Tables with a fully generational MP-2020 projection scale, in determining its December 31, 2022 other postretirement benefits APBO.

 Defined Contribution Plans

 Entergy sponsors the Savings Plan of Entergy Corporation and Subsidiaries (System Savings Plan). The System Savings Plan is a defined contribution plan covering eligible employees of Entergy and certain of its subsidiaries. The participating Entergy subsidiary makes matching contributions to the System Savings Plan for all eligible participating employees in an amount equal to either 70 % or 100 % of the participants' basic contributions, up to 6 % of their eligible earnings per pay period. The matching contribution is allocated to investments as directed by the employee.

 Entergy also sponsors the Savings Plan of Entergy Corporation and Subsidiaries VI (Savings Plan VI) (established in April 2007) and the Savings Plan of Entergy Corporation and Subsidiaries VII (Savings Plan VII)

 (established in April 2007) to which matching contributions are also made. The plans are defined contribution plans that cover eligible employees, as defined by each plan, of Entergy and certain of its subsidiaries. Effective December 31, 2023, employees participating in Savings Plan VI and Savings Plan VII were transferred into the System Savings Plan when Savings Plan VI and Savings Plan VII merged into the System Savings Plan.

 Entergy also sponsors the Savings Plan of Entergy Corporation and Subsidiaries VIII (established January 2021) and the Savings Plan of Entergy Corporation and Subsidiaries IX (established January 2021) to which company contributions are made. The participating Entergy subsidiary makes matching contributions to these defined contribution plans for all eligible participating employees in an amount equal to 100 % of the participants' basic contributions, up to 5 % of their eligible earnings per pay period. Eligible participants may also receive a discretionary annual company contribution up to 4 % of the participant's eligible earnings (subject to vesting).

 Entergy's subsidiaries' contributions to defined contribution plans collectively were $ 65.1 million in 2023, $ 62.1 million in 2022, and $ 62.3 million in 2021. The majority of the contributions were to the System Savings Plan.

 The Registrant Subsidiaries' 2023, 2022, and 2021 contributions to defined contribution plans for their employees were as follows:

 Year

 2023
 $ 5,866
 $ 7,757
 $ 3,534
 $ 1,383
 $ 3,380

 2022
 $ 5,124
 $ 7,138
 $ 3,194
 $ 1,223
 $ 2,938

 2021
 $ 4,820
 $ 6,678
 $ 3,045
 $ 1,140
 $ 2,699

 NOTE 12. STOCK-BASED COMPENSATION (Entergy Corporation)

 Entergy grants stock options, restricted stock, performance units, and restricted stock units to key employees of the Entergy subsidiaries under its equity plans which are shareholder-approved stock-based compensation plans. Effective May 3, 2019, Entergy's shareholders approved the 2019 Omnibus Incentive Plan (2019 Plan). The maximum number of common shares that can be issued from the 2019 Plan for stock-based awards is 12,200,000 all of which are available for incentive stock option grants. The 2019 Plan applies to awards granted on or after May 3, 2019 and awards expire ten years from the date of grant. As of December 31, 2023, there were 7,546,825 authorized shares remaining for stock-based awards.

 Stock options are granted at exercise prices that equal the closing market price of Entergy Corporation common stock on the date of grant. Generally, stock options granted will become exercisable in equal amounts on each of the first three anniversaries of the date of grant. Unless they are forfeited previously under the terms of the grant, options expire 10 years after the date of the grant if they are not exercised.

 The following table includes financial information for stock options for each of the years presented:

 2023
 2022
 2021

 Compensation expense included in Entergy's consolidated net income
 $ 4.1
 $ 4.2
 $ 4.2

 Tax benefit recognized in Entergy's consolidated net income
 $ 1.1
 $ 1.1
 $ 1.1

 Compensation cost capitalized as part of fixed assets and materials and
 supplies

 $ 1.9
 $ 1.7
 $ 1.5

 Entergy determines the fair value of the stock option grants by considering factors such as lack of marketability, stock retention requirements, and regulatory restrictions on exercisability in accordance with accounting standards. The stock option weighted-average assumptions used in determining the fair values are as follows:

 2023
 2022
 2021

 Stock price volatility
 24.89 %
 24.27 %
 23.93 %

 Expected term in years
 6.89
 6.92
 6.93

 Risk-free interest rate
 3.51 %
 1.77 %
 0.74 %

 Dividend yield

 Dividend payment per share
 $ 4.34
 $ 4.10
 $ 3.86

 Stock price volatility is calculated based upon the daily public stock price volatility of Entergy Corporation common stock over a period equal to the expected term of the award. The expected term of the options is based upon historical option exercises and the weighted-average life of options when exercised and the estimated weighted-average life of all vested but unexercised options. In 2008, Entergy implemented stock ownership guidelines for its senior executive officers. These guidelines require an executive officer to own shares of Entergy Corporation common stock equal to a specified multiple of his or her salary. Until an executive officer achieves this ownership position the executive officer is required to retain 75 % of the net-of-tax net profit upon exercise of the option to be held in Entergy Corporation common stock. The reduction in fair value of the stock options due to this restriction is based upon an estimate of the call option value of the reinvested gain discounted to present value over the applicable reinvestment period.

 A summary of stock option activity for the year ended December 31, 2023 and changes during the year are presented below:

 of Options

 Weighted-
Average
Price

 Aggregate
 Intrinsic
 Value

 Weighted-
Average
Contractual Life

 Options outstanding as of January 1, 2023
 2,776,355
 $ 96.30

 Options granted
 281,874
 $ 108.47

 Options exercised
 ( 111,929)
 $ 85.69

 Options forfeited/expired
 ( 47,592)
 $ 110.40

 Options outstanding as of December 31, 2023
 2,898,708
 $ 97.66
 $ 31,447,529
 5.66

 Options exercisable as of December 31, 2023
 2,191,916
 $ 94.94
 $ 30,475,161
 4.83

 Weighted-average grant-date fair value of options granted during 2023
 $ 20.07

 The weighted-average grant-date fair value of options granted during the year was $ 16.25 for 2022 and $ 12.27 for 2021. The total intrinsic value of stock options exercised was $ 2 million during 2023, $ 20 million during 2022, and $ 2 million during 2021. The intrinsic value, which has no effect on net income, of the outstanding stock options exercised is calculated by the positive difference between the weighted-average exercise price of the stock options

 granted and Entergy Corporation's common stock price as of December 31, 2023. The aggregate intrinsic value of the stock options outstanding as of December 31, 2023 was $ 31.4 million. Stock options outstanding as of December 31, 2023 includes 1,153,596 out of the money options with an intrinsic value of zero. Entergy recognizes compensation cost over the vesting period of the options based on their grant-date fair value. The total fair value of options that vested was approximately $ 6 million during 2023, $ 6 million during 2022, and $ 5 million during 2021. Cash received from option exercises was $ 10 million for the year ended December 31, 2023. The tax benefits realized from options exercised was $ 0.5 million for the year ended December 31, 2023.

 The following table summarizes information about stock options outstanding as of December 31, 2023:

 Options Outstanding
 Options Exercisable

 Range of Exercise Price
 As of December 31, 2023
 Weighted-Average Remaining Contractual Life-Yrs.
 Weighted-Average Exercise Price
 Number Exercisable as of December 31, 2023
 Weighted-Average Exercise Price

 $ 63.17
 -
 $ 79.99
 772,974
 3.18
 $ 73.58
 772,974
 $ 73.58

 $ 80.00
 -
 $ 99.99
 972,138
 5.45
 $ 92.30
 814,286
 $ 91.61

 $ 100.00
 -
 $ 119.99
 685,327
 8.48
 $ 109.14
 136,387
 $ 109.59

 $ 120.00
 -
 $ 131.72
 468,269
 6.08
 $ 131.72
 468,269
 $ 131.72

 $ 63.17
 -
 $ 131.72
 2,898,708
 5.66
 $ 97.66
 2,191,916
 $ 94.94

 Stock-based compensation cost related to non-vested stock options outstanding as of December 31, 2023 not yet recognized is approximately $ 5 million and is expected to be recognized over a weighted-average period of 1.6 years.

 Restricted Stock Awards

 Entergy grants restricted stock awards earned under its stock benefit plans in the form of stock units. One-third of the restricted stock awards will vest upon each anniversary of the grant date and are expensed ratably over the three-year vesting period. Shares of restricted stock have the same dividend and voting rights as other common stock and are considered issued and outstanding shares of Entergy upon vesting. In January 2023 the Board approved and Entergy granted 345,983 restricted stock awards under the 2019 Plan. The restricted stock awards were made effective on January 26, 2023 and were valued at $ 108.47 per share, which was the closing price of Entergy Corporation's common stock on that date.

 The following table includes information about the restricted stock awards outstanding as of December 31, 2023:

 Weighted-Average Grant Date Fair Value Per Share

 Outstanding shares at January 1, 2023
 607,723
 $ 107.55

 Granted
 373,741
 $ 108.35

 ( 294,145)
 $ 110.54

 ( 60,546)
 $ 105.64

 Outstanding shares at December 31, 2023
 626,773
 $ 106.80

 The following table includes financial information for restricted stock for each of the years presented:

 2023
 2022
 2021

 Compensation expense included in Entergy's consolidated net income
 $ 22.2
 $ 23.2
 $ 24.7

 Tax benefit recognized in Entergy's consolidated net income
 $ 5.7
 $ 5.9
 $ 6.3

 Compensation cost capitalized as part of fixed assets and materials and
 supplies

 $ 9.7
 $ 9.2
 $ 9.3

 The total fair value of the restricted stock awards granted was $ 41 million, $ 39 million, and $ 40 million for the years ended December 31, 2023, 2022, and 2021, respectively.

 The total fair value of the restricted stock awards vested was $ 33 million, $ 34 million, and $ 32 million for the years ended December 31, 2023, 2022, and 2021, respectively.

 Long-Term Performance Unit Program

 Entergy grants long-term incentive awards earned under its stock benefit plans in the form of performance units, which represents the value of, and are settled with, one share of Entergy Corporation common stock at the end of the three-year performance period, plus dividends accrued during the performance period on the number of performance units earned. The Long-Term Performance Unit Program specifies a minimum, target, and maximum achievement level, the achievement of which will determine the number of performance units that may be earned. Entergy measures performance by assessing Entergy's total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index. To emphasize the importance of strong cash generation for the long-term health of its business, a credit measure – adjusted funds from operations/debt ratio – was selected as one of the performance measures for the 2023-2025 performance period. For the 2023-2025 performance period, performance will be measured based eighty percent on relative total shareholder return and twenty percent on the credit measure.

 In January 2023 the Board approved and Entergy granted 143,212 performance units under the 2019 Plan. The performance units were granted on January 26, 2023, and eighty percent were valued at $ 130.65 per share based on various factors, primarily market conditions; and twenty percent were valued at $ 108.47 per share, the closing price of Entergy Corporation's common stock on that date. Performance units have the same dividend and voting rights as other common stock, are considered issued and outstanding shares of Entergy upon vesting, and are expensed ratably over the 3-year vesting period, and compensation cost for the portion of the award based on the selected credit measure will be adjusted based on the number of units that ultimately vest.

 The following table includes information about the long-term performance units outstanding at the target level as of December 31, 2023:

 Weighted-Average Grant Date Fair Value Per Share

 Outstanding shares at January 1, 2023
 521,838
 $ 129.94

 Granted
 156,627
 $ 126.39

 ( 38,150)
 $ 162.14

 ( 159,314)
 $ 145.35

 Outstanding shares at December 31, 2023
 481,001
 $ 121.12

 The following table includes financial information for the long-term performance units for each of the years presented:

 2023
 2022
 2021

 Compensation expense included in Entergy's consolidated net income
 $ 11.1
 $ 16.0
 $ 14.5

 Tax benefit recognized in Entergy's consolidated net income
 $ 2.8
 $ 4.1
 $ 3.7

 Compensation cost capitalized as part of fixed assets and materials and
 supplies

 $ 5.2
 $ 6.7
 $ 5.8

 The total fair value of the long-term performance units granted was $ 20 million, $ 35 million, and $ 32 million for the years ended December 31, 2023, 2022, and 2021, respectively.

 In January 2023, Entergy issued 38,150 shares of Entergy Corporation common stock at a share price of $ 107.59 for awards earned and dividends accrued under the 2020-2022 Long-Term Performance Unit Program. In January 2022, Entergy issued 224,334 shares of Entergy Corporation common stock at a share price of $ 110.35 for awards earned and dividends accrued under the 2019-2021 Long-Term Performance Unit Program. In January 2021, Entergy issued 235,983 shares of Entergy Corporation common stock at a share price of $ 95.12 for awards earned and dividends accrued under the 2018-2020 Long-Term Performance Unit Program.

 Restricted Stock Unit Awards

 Entergy grants restricted stock unit awards earned under its stock benefit plans in the form of stock units that are subject to time-based restrictions. The restricted stock units may be settled in shares of Entergy Corporation common stock or the cash value of shares of Entergy Corporation common stock at the time of vesting. The costs of restricted stock unit awards are charged to income over the restricted period, which varies from grant to grant. The average vesting period for restricted stock unit awards granted is 38 months. As of December 31, 2023, there were 139,500 unvested restricted stock units that are expected to vest over an average period of 20 months.

 The following table includes information about the restricted stock unit awards outstanding as of December 31, 2023:

 Weighted-Average Grant Date Fair Value Per Share

 Outstanding shares at January 1, 2023
 132,407
 $ 105.75

 Granted
 22,547
 $ 102.05

 ( 6,142)
 $ 110.33

 ( 9,312)
 $ 103.37

 Outstanding shares at December 31, 2023
 139,500
 $ 105.11

 The following table includes financial information for restricted stock unit awards for each of the years presented:

 2023
 2022
 2021

 Compensation expense included in Entergy's consolidated net income
 $ 2.8
 $ 2.0
 $ 1.9

 Tax benefit recognized in Entergy's consolidated net income
 $ 0.7
 $ 0.5
 $ 0.5

 Compensation cost capitalized as part of fixed assets and materials and
 supplies

 $ 1.2
 $ 0.8
 $ 0.7

 The total fair value of the restricted stock unit awards granted was $ 2 million, $ 8 million, and $ 4 million for the years ended December 31, 2023, 2022, and 2021, respectively.

 The total fair value of the restricted stock unit awards vested was $ 1 million, $ 3 million, and $ 3 million for the years ended December 31, 2023, 2022, and 2021, respectively.

 NOTE 13. BUSINESS SEGMENT INFORMATION (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

 Entergy has a single reportable segment, Utility, which includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operation of a small natural gas distribution business in portions of Louisiana. The Utility segment reflects management's primary basis of organization with a predominant focus on its utility operations in the Gulf South. Parent & Other includes 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.

 Entergy's segment financial information was as follows:

 2023

 Eliminations

 Consolidated

 Operating revenues
 $ 12,022,944
 $ 124,509
 ($ 41)
 $ 12,147,412

 $ 79,962
 ($ 37,283)
 $ —
 $ 42,679

 Depreciation, amortization, and decommissioning
 $ 2,045,254
 $ 6,423
 $ —
 $ 2,051,677

 $ 443,751
 $ 18,660
 ($ 299,685)
 $ 162,726

 $ 816,643
 $ 190,468
 ($ 705)
 $ 1,006,406

 ($ 374,847)
 ($ 315,688)
 $ —
 ($ 690,535)

 Consolidated net income
 $ 2,510,904
 $ 150,385
 ($ 298,979)
 $ 2,362,310

 Total assets
 $ 63,887,038
 $ 836,598
 ($ 5,020,240)
 $ 59,703,396

 Cash paid for long-lived asset additions
 $ 4,745,918
 $ 801
 $ —
 $ 4,746,719

 2022

 Eliminations

 Consolidated

 Operating revenues
 $ 13,420,804
 $ 343,461
 ($ 28)
 $ 13,764,237

 $ —
 ($ 163,464)
 $ —
 ($ 163,464)

 Depreciation, amortization, and decommissioning
 $ 1,941,653
 $ 43,446
 $ —
 $ 1,985,099

 Interest and investment income (loss)
 $ 145,968
 ($ 35,293)
 ($ 186,256)
 ($ 75,581)

 $ 750,175
 $ 162,300
 ($ 238)
 $ 912,237

 ($ 34,263)
 ($ 4,715)
 $ —
 ($ 38,978)

 Consolidated net income (loss)
 $ 1,398,580
 ($ 115,425)
 ($ 186,017)
 $ 1,097,138

 Total assets
 $ 61,399,243
 $ 884,442
 ($ 3,688,494)
 $ 58,595,191

 Cash paid for long-lived asset additions
 $ 5,382,243
 $ 13,884
 $ —
 $ 5,396,127

 2021

 Eliminations

 Consolidated

 Operating revenues
 $ 11,044,674
 $ 698,251
 ($ 29)
 $ 11,742,896

 Asset write-offs, impairments, and related charges
 $ —
 $ 263,625
 $ —
 $ 263,625

 Depreciation, amortization, and decommissioning
 $ 1,823,389
 $ 167,308
 $ —
 $ 1,990,697

 $ 442,817
 $ 115,273
 ($ 127,624)
 $ 430,466

 $ 692,004
 $ 142,693
 ($ 3)
 $ 834,694

 $ 264,209
 ($ 72,835)
 $ —
 $ 191,374

 Consolidated net income (loss)
 $ 1,488,487
 ($ 242,146)
 ($ 127,622)
 $ 1,118,719

 Total assets
 $ 59,733,625
 $ 1,718,638
 ($ 1,998,021)
 $ 59,454,242

 Cash paid for long-lived asset additions
 $ 6,409,855
 $ 12,257
 $ —
 $ 6,422,112

 Eliminations are primarily intersegment activity. As of December 31, 2023, all of Entergy's goodwill is related to the Utility segment. As of December 31, 2022 and 2021, almost all of Entergy's goodwill was related to the Utility segment.

 Results of operations for 2023 include: (1) a $ 568 million reduction, recorded at Utility, and a $ 275 million reduction, recorded at Parent & Other, in income tax expense as a result of the resolution of the 2016-2018 IRS audit, partially offset by $ 98 million ($ 72 million net-of-tax) of regulatory charges, recorded at Utility, to reflect credits expected to be provided to customers by Entergy Louisiana and Entergy New Orleans as a result of the resolution of the 2016-2018 IRS audit; (2) the reversal of a $ 106 million regulatory liability, associated with the Hurricane Isaac securitization, recognized in 2017 as a result of the Tax Cuts and Jobs Act, recorded at Utility, as part of the settlement of Entergy Louisiana's test year 2017 formula rate plan filing; (3) a $ 129 million reduction in income tax expense as a result of the Hurricane Ida securitization in March 2023, which also resulted in a $ 103 million ($ 76 million net-of-tax) regulatory charge, recorded at Utility, to reflect Entergy Louisiana's obligation to provide credits to its customers as described in an LPSC ancillary order issued as part of the securitization regulatory proceeding; and (4) write-offs of $ 78 million ($ 59 million net-of-tax), recorded at Utility, as a result of Entergy Arkansas's approved motion to forgo recovery of identified costs resulting from the 2013 ANO stator incident. See Note 3 to the financial statements for discussion of the resolution of the 2016-2018 IRS audit. See Note 2 to the financial statements for discussion of the Entergy Louisiana formula rate plan global settlement. See Notes 2 and 3 to the financial statements for discussion of the Entergy Louisiana March 2023 storm cost securitization. See Note 8 to the financial statements for discussion of the ANO stator incident and the approved motion to forgo recovery.

 Results of operations for 2022 include: (1) a regulatory charge of $ 551 million ($ 413 million net-of-tax), recorded at Utility, as a result of System Energy's partial settlement agreement and offer of settlement related to pending proceedings before the FERC; (2) a $ 283 million reduction in income tax expense as a result of the Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida May 2022 securitization financing, which also resulted in a $ 224 million ($ 165 million net-of-tax) regulatory charge, recorded at Utility, to reflect Entergy Louisiana's obligation to provide credits to its customers as described in an LPSC ancillary order issued as part of the securitization regulatory proceeding; and (3) a gain of $ 166 million ($ 130 million net-of-tax), reflected in "Asset write-offs, impairments, and related charges (credits)," as a result of the sale of the Palisades plant in June 2022. See Note 2 to the financial statements for discussion of the System Energy settlement agreement with the MPSC. See Notes 2 and 3 to the financial statements for discussion of the Entergy Louisiana May 2022 storm cost securitization. See Note 14 to the financial statements for discussion of the sale of the Palisades plant.

 Results of operations for 2021 include a charge of $ 340 million ($ 268 million net-of-tax), reflected in "Asset write-offs, impairments, and related charges (credits)," as a result of the sale of the Indian Point Energy Center in May 2021. See Note 14 to the financial statements for discussion of the sale of the Indian Point Energy Center.

 Change in Reportable Segments Effective January 1, 2023

 Entergy completed its multi-year strategy to exit the merchant nuclear power business in 2022 and upon completion of all transition activities, effective January 1, 2023, Entergy Wholesale Commodities is no longer a reportable segment. Remaining business activity previously reported under Entergy Wholesale Commodities is now reported under Parent & Other. Historical segment financial information presented herein has been restated for 2022 and 2021 to reflect the change in reportable segments. The change in reportable segments had no effect on Entergy's consolidated financial statements or historical segment financial information for the Utility reportable segment.

 The Fitzpatrick plant was sold to Exelon in March 2017. The Vermont Yankee plant was sold to NorthStar in January 2019. The Pilgrim plant was sold to Holtec International in August 2019. The Indian Point 2 and Indian Point 3 plants were sold to Holtec International in May 2021. The Palisades plant was sold to Holtec International in June 2022.

 The decisions to shut down these plants and the related transactions resulted in asset impairments; employee retention and severance expenses and other benefits-related costs; and contracted economic development contributions. The employee retention and severance expenses and other benefits-related costs and contracted economic development contributions are included in "Other operation and maintenance" in Entergy's consolidated income statements.

 As the exit from the merchant nuclear power business was completed in 2022, there were no restructuring charges recorded in 2023. Total restructuring charges in 2022 and 2021 were comprised of the following:

 Employee retention and severance expenses and other benefits-related costs
 Contracted economic development costs
 Total

 Balance as of December 31, 2020
 $ 145
 $ 14
 $ 159

 Restructuring costs accrued

 Cash paid out

 Balance as of December 31, 2021
 $ 37
 $ —
 $ 37

 Restructuring costs accrued
 —

 Cash paid out
 —

 Balance as of December 31, 2022
 $ —
 $ —
 $ —

 In addition, a gain of $ 166 million was recorded in 2022 as a result of the sale of the Palisades plant and a charge of $ 340 million was recorded in 2021 as a result of the sale of the Indian Point Energy Center, both reflected in "Asset write-offs, impairments, and related charges (credits)" in Entergy's consolidated income statements. See Note 14 to the financial statements for discussion of the sale of the Palisades plant and the Indian Point Energy Center.

 Geographic Areas

 For the years ended December 31, 2023, 2022, and 2021, Entergy derived no revenue from outside of the United States. As of December 31, 2023 and 2022, Entergy had no long-lived assets located outside of the United States.

 Registrant Subsidiaries

 Each of the Registrant Subsidiaries has one reportable segment, which is an integrated utility business, except for System Energy, which is an electricity generation business. Each of the Registrant Subsidiaries' operations are managed on an integrated basis by that company because of the substantial effect of cost-based rates and regulatory oversight on the business process, cost structures, and operating results. Management allocates resources and assesses financial performance on a consolidated basis.

 NOTE 14. ACQUISITIONS AND DISPOSITIONS (Entergy Corporation, Entergy Arkansas, Entergy Mississippi, and Entergy Texas)

 Acquisitions

 Walnut Bend Solar

 In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Walnut Bend Solar facility, to be sited on approximately 1,000 acres in Lee County, Arkansas. Acquisition of the Walnut Bend Solar facility was initially approved by the APSC in July 2021. The agreement was amended by the parties in February 2023 and the revised agreement was approved by the APSC in July 2023. In February 2024, Entergy Arkansas made an initial payment of $ 170 million to acquire the facility. The project will achieve commercial operation once testing is completed and the project has achieved substantial completion. Entergy Arkansas currently expects the project to achieve commercial operation in the first half of 2024, at which time a substantial completion payment of approximately $ 20 million is expected.

 Sunflower Solar

 In November 2018, Entergy Mississippi entered into an agreement for the purchase of an approximately 100 MW solar photovoltaic facility to be sited on approximately 1,000 acres in Sunflower County, Mississippi. The project, Sunflower Solar facility, was being built by Sunflower County Solar Project, LLC, an indirect subsidiary of Recurrent Energy, LLC. In December 2018, Entergy Mississippi filed a joint petition with Sunflower County Solar Project with the MPSC for Sunflower County Solar Project to construct and for Entergy Mississippi to acquire and thereafter own, operate, improve, and maintain the solar facility. In March 2020, Entergy Mississippi filed supplemental testimony addressing questions and observations raised in August 2019 by consultants retained by the Mississippi Public Utilities Staff and proposing an alternative structure for the transaction that would reduce its cost. In April 2020 the MPSC issued an order approving certification of the Sunflower Solar facility, subject to certain conditions, including: (i) that Entergy Mississippi pursue a tax equity partnership structure through which the partnership would acquire and own the facility under the build-own-transfer agreement and (ii) that if Entergy Mississippi does not consummate the partnership structure under the terms of the order, there will be a cap of $ 136 million on the level of recoverable costs. In April 2022, Entergy Mississippi confirmed mechanical completion of the Sunflower Solar facility. Pursuant to the MPSC's April 2020 order, MS Sunflower Partnership, LLC was formed for the tax equity partnership with Entergy Mississippi as its managing member. In May 2022 both Entergy Mississippi and the tax equity investor made capital contributions to the tax equity partnership that were then used to make an initial payment of $ 105 million for acquisition of the facility. Substantial completion of the Sunflower Solar facility was accepted by Entergy Mississippi in September 2022. Commercial operation at the Sunflower Solar facility commenced in September 2022. In April 2023 both Entergy Mississippi and the tax equity

 investor made additional capital contributions to the tax equity partnership that were then used to make the substantial completion payment of $ 30 million for acquisition of the facility. The final payment of $ 5 million for acquisition of the facility was made in October 2023. See Note 1 to the financial statements for further discussion of the HLBV method of accounting used to account for the investment in MS Sunflower Partnership, LLC.

 Searcy Solar

 In March 2019, Entergy Arkansas entered into a build-own-transfer agreement for the purchase of an approximately 100 MW solar energy facility to be sited on approximately 800 acres in White County near Searcy, Arkansas. The project, Searcy Solar facility, was being constructed by a subsidiary of NextEra Energy Resources. In April 2020 the APSC issued an order approving Entergy Arkansas's acquisition of the Searcy Solar facility as being in the public interest. In May 2021, Entergy Arkansas filed with the APSC an application seeking to amend its certificate for the Searcy Solar facility to allow for the use of a tax equity partnership to acquire and own the facility. The tax equity partnership structure is expected to reduce costs and yield incremental net benefits to customers beyond those expected under the build-own-transfer structure alone. The APSC approved Entergy Arkansas's tax equity partnership request in September 2021. AR Searcy Partnership, LLC was formed for the tax equity partnership with Entergy Arkansas as its managing member. In November 2021 both Entergy Arkansas and the tax equity investor made capital contributions to the tax equity partnership that were then used to acquire the facility. Upon substantial completion of the facility in December 2021, the tax equity partnership completed the purchase of the Searcy Solar facility. The purchase price for the Searcy Solar facility was approximately $ 133 million, which included a final payment of $ 1 million made in 2022. See Note 1 to the financial statements for further discussion of the HLBV method of accounting used to account for the investment in AR Searcy Partnership, LLC.

 Hardin County Peaking Facility

 In June 2021, Entergy Texas purchased the Hardin County Peaking Facility, an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, from East Texas Electric Cooperative, Inc. In addition, also in June 2021, Entergy Texas sold a 7.56 % partial interest in the Montgomery County Power Station to East Texas Electric Cooperative, Inc. for approximately $ 68 million. The two interdependent transactions were approved by the PUCT in April 2021. The purchase price for the Hardin County Peaking Facility was approximately $ 37 million.

 Dispositions

 Palisades

 In July 2018, Entergy entered into a purchase and sale agreement with Holtec International to sell to a Holtec subsidiary 100 % of the equity interests in the subsidiary that owns Palisades and the Big Rock Point Site. In December 2020, Entergy and Holtec submitted a license transfer application to the NRC requesting approval to transfer the Palisades and Big Rock Point licenses from Entergy to Holtec. The NRC issued an order approving the application in December 2021. Palisades was shut down in May 2022 and defueled in June 2022. The Palisades transaction closed in June 2022 for a purchase price of $ 1,000 (subject to adjustment for net liabilities and other amounts). The sale included the transfer of the Palisades nuclear decommissioning trust and the asset retirement obligation for spent fuel management and plant decommissioning. The transaction resulted in a gain of $ 166 million ($ 130 million net-of-tax) in the second quarter 2022. The disposition-date fair value of the nuclear decommissioning trust fund was approximately $ 552 million, and the disposition-date fair value of the asset retirement obligation was approximately $ 708 million. The transaction also included property, plant, and equipment with a net book value of zero and materials and supplies.

 Indian Point Energy Center

 In April 2019, Entergy entered into an agreement to sell, directly or indirectly, 100 % of the equity interests in the subsidiaries that own Indian Point 1, Indian Point 2, and Indian Point 3, after Indian Point 3 had been shut down and defueled, to a Holtec International subsidiary. In November 2020 the NRC approved the sale of the plants to Holtec. Indian Point 3 was shut down in April 2021 and defueled in May 2021. In May 2021 the New York State Public Service Commission approved the sale of the plant to Holtec. The transaction closed in May 2021. The sale included the transfer of the licenses, spent fuel, decommissioning liabilities, and nuclear decommissioning trusts for the three units. The transaction resulted in a charge of $ 340 million ($ 268 million net-of-tax) in the second quarter of 2021. The disposition-date fair value of the nuclear decommissioning trust funds was approximately $ 2,387 million, and the disposition-date fair value of the asset retirement obligations was $ 1,996 million. The transaction also included materials and supplies and prepaid assets.

 NOTE 15. RISK MANAGEMENT AND FAIR VALUES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

 Market Risk

 In the normal course of business, Entergy is exposed to a number of market risks. Market risk is the potential loss that Entergy may incur as a result of changes in the market or fair value of a particular commodity or instrument. All financial and commodity-related instruments, including derivatives, are subject to market risk including commodity price risk, equity price, and interest rate risk. Entergy uses derivatives primarily to mitigate commodity price risk, particularly power price and fuel price risk.

 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 derivative 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 non-utility operations' core business as a wholesale generator was selling energy, measured in MWh, to its customers. The non-utility operations business entered into forward contracts with its customers and also sold energy and capacity in the day ahead or spot markets. In addition to its forward physical power and gas contracts, the non-utility operations business used a combination of financial contracts, including swaps, collars, and options, to mitigate commodity price risk. When the market price fell, the combination of financial contracts was expected to settle in gains that offset lower revenue from generation, which resulted in a more predictable cash flow. As a result of the completion of Entergy's strategy to exit the merchant nuclear power business, which included the shut down and sale of all non-utility nuclear plants, the portfolio of derivative instruments held by Entergy's non-utility operations business expired in April 2021, which was the settlement date for the last financial derivative contracts in the non-utility operations business' portfolio.

 Entergy's exposure to market risk is determined by a number of factors, including the size, term, composition, and diversification of positions held, as well as market volatility and liquidity. For instruments such as options, the time period during which the option may be exercised and the relationship between the current market price of the underlying instrument and the option's contractual strike or exercise price also affects the level of market risk. A significant factor influencing the overall level of market risk to which Entergy is exposed is its use of hedging techniques to mitigate such risk. Hedging instruments and volumes are chosen based on ability to mitigate risk associated with future energy and capacity prices; however, other considerations are factored into hedge product and volume decisions including corporate liquidity, corporate credit ratings, counterparty credit risk, hedging costs, firm settlement risk, and product availability in the marketplace. Entergy manages market risk by actively monitoring compliance with stated risk management policies as well as monitoring the effectiveness of its hedging policies and strategies. Entergy's risk management policies limit the amount of total net exposure and

 rolling net exposure during the stated periods. These policies, including related risk limits, are regularly assessed to ensure their appropriateness given Entergy's objectives.

 Derivatives

 Some derivative instruments are classified as cash flow hedges due to their financial settlement provisions while others are classified as normal purchase/normal sale transactions due to their physical settlement provisions. Normal purchase/normal sale risk management tools include power purchase and sales agreements, fuel purchase agreements, capacity contracts, and tolling agreements. Financially-settled cash flow hedges can include natural gas and electricity swaps and options. Entergy may enter into financially-settled swap and option contracts to manage market risk that may or may not be designated as hedging instruments.

 Entergy entered into derivatives to manage natural risks inherent in its physical or financial assets or liabilities. Electricity over-the-counter instruments and futures contracts that financially settled against day-ahead power pool prices were used to manage price exposure for the non-utility operations' generation.

 Entergy manages fuel price volatility for its Louisiana jurisdictions (Entergy Louisiana and Entergy New Orleans) and Entergy Mississippi through the purchase of natural gas swaps and options that financially settle against either the average Henry Hub Gas Daily prices or the NYMEX Henry Hub. These swaps and options are marked-to-market through fuel expense with offsetting regulatory assets or liabilities. All benefits or costs of the program are recorded in fuel costs. The notional volumes of these swaps are based on a portion of projected annual exposure to gas price volatility for electric generation at Entergy Louisiana and Entergy Mississippi and projected winter purchases for gas distribution at Entergy New Orleans. The maximum length of time over which Entergy has executed natural gas swaps and options as of December 31, 2023 is 3 months for Entergy Louisiana, 10 months for Entergy Mississippi, and 3 months for Entergy New Orleans. The total volume of natural gas swaps and options outstanding as of December 31, 2023 is 14,798,500 MMBtu for Entergy, including 1,820,000 MMBtu for Entergy Louisiana, 12,491,700 MMBtu for Entergy Mississippi, and 486,800 MMBtu for Entergy New Orleans. Credit support for these natural gas swaps and options is covered by master agreements that do not require Entergy to provide collateral based on mark-to-market value, but do carry adequate assurance language that may lead to requests for collateral.

 During the second quarter 2023, Entergy participated in the annual financial transmission rights auction process for the MISO planning year of June 1, 2023 through May 31, 2024. Financial transmission rights are derivative instruments that represent economic hedges of future congestion charges that will be incurred in serving Entergy's customer load. They are not designated as hedging instruments. Entergy initially records financial transmission rights at their estimated fair value and subsequently adjusts the carrying value to their estimated fair value at the end of each accounting period prior to settlement. Unrealized gains or losses on financial transmission rights held by the non-utility operations are included in operating revenues. The Utility operating companies recognize regulatory liabilities or assets for unrealized gains or losses on financial transmission rights. The total volume of financial transmission rights outstanding as of December 31, 2023 is 62,809 GWh for Entergy, including 15,385 GWh for Entergy Arkansas, 26,990 GWh for Entergy Louisiana, 8,250 GWh for Entergy Mississippi, 2,478 GWh for Entergy New Orleans, and 9,611 GWh for Entergy Texas. Credit support for financial transmission rights held by the Utility operating companies is covered by cash and/or letters of credit issued by each Utility operating company as required by MISO. Credit support for financial transmission rights held by the non-utility operations business is covered by cash. No cash or letters of credit were required to be posted for financial transmission rights exposure for the non-utility operations business as of December 31, 2023 and 2022. Letters of credit posted with MISO covered the financial transmission rights exposure for Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas as of December 31, 2023 and for Entergy Mississippi, Entergy New Orleans, and Entergy Texas as of December 31, 2022.

 The fair values of Entergy's derivative instruments not designated as hedging instruments on the consolidated balance sheets as of December 31, 2023 and 2022 are shown in the table below. Certain investments, including those not designated as hedging instruments, are subject to master netting agreements and are presented in the balance sheet on a net basis in accordance with accounting guidance for derivatives and hedging.

 Balance Sheet Location
 Gross Fair Value (a)
 Offsetting Position (b)
 Net Fair Value (c) (d)

 2023

 $ 21
 $ —
 $ 21

 $ 11

 $ —

 $ 11

 2022

 $ 13
 $ —
 $ 13

 Other deferred debits and other assets
 $ 3
 $ —
 $ 3

 $ 21
 ($ 2)
 $ 19

 $ 25
 $ —
 $ 25

 (a)Represents the gross amounts of recognized assets/liabilities
 (b)Represents the netting of fair value balances with the same counterparty
 (c)Represents the net amounts of assets/liabilities presented on the Entergy Corporation and Subsidiaries' Consolidated Balance Sheets
 (d)Excludes cash collateral in the amount of $ 8 million posted as of December 31, 2022. Also excludes letters of credit in the amount of $ 2 million posted as of December 31, 2023 and $ 3 million posted as of December 31, 2022.

 As discussed above, the non-utility operations business' portfolio of derivative instruments expired in April 2021, which was the settlement date for the last financial derivative contract in the portfolio. Prior to the expiration of the non-utility operations business' portfolio of derivative instruments, Entergy may have effectively liquidated a cash flow hedge instrument by entering into a contract offsetting the original hedge, and then de-designating the original hedge in this situation. Gains or losses accumulated in other comprehensive income prior to de-designation would have continued to be deferred in other comprehensive income until they were included in income as the original hedged transaction occurred. From the point of de-designation, the gains or losses on the original hedge and the offsetting contract were recorded as assets or liabilities on the balance sheet and offset as they flowed through to earnings. The non-utility operations business recognized a gain of $ 2 million in other comprehensive income and reclassified a gain of $ 40 million, before taxes of $ 8 million, from accumulated other comprehensive income into income, each resulting from the effect of Entergy's derivative instruments designated as cash flow hedges on the consolidated income statements for the year ended December 31, 2021.

 The effects of Entergy's derivative instruments not designated as hedging instruments on the consolidated income statements for the years ended December 31, 2023, 2022, and 2021 are as follows:

 Income Statement location
 Amount of gain (loss) recorded in the income statement

 2023

 (a)
 ($54)

 (b)
 $ 124

 2022

 Natural gas swaps and option
 (a)
 $ 74

 (b)
 $ 176

 2021

 (a)
 $ 32

 (b)
 $ 179

 Electricity swaps and options (c)
 Other operating revenues
 ($2)

 (a)Due to regulatory treatment, the natural gas swaps and options are marked-to-market through fuel, fuel-related expenses, and gas purchased for resale and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability. The gains or losses recorded as fuel expenses when the swaps and options are settled are recovered or refunded through fuel cost recovery mechanisms.
 (b)Due to regulatory treatment, the changes in the estimated fair value of financial transmission rights for the Utility operating companies are recorded through purchased power expense and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability. The gains or losses recorded as purchased power expense when the financial transmission rights for the Utility operating companies are settled are recovered or refunded through fuel cost recovery mechanisms.
 (c)There were no gains (losses) recognized in accumulated other comprehensive income from electricity swaps and options prior to the expiration of the non-utility operations business' portfolio of derivative instruments in April 2021.

 The fair values of derivative instruments not designated as hedging instruments on the Registrant Subsidiaries' balance sheets as of December 31, 2023 and 2022 are shown in the table below. Certain investments, including those not designated as hedging instruments, are subject to master netting agreements and are presented in the balance sheet on a net basis in accordance with accounting guidance for derivatives and hedging.

 Balance Sheet Location
 Gross Fair Value (a)
 Offsetting Position (b)
 Net Fair Value (c) (d)

 2023

 $ 6.0
 $ —
 $ 6.0

 $ 9.8
 $ —
 $ 9.8

 $ 1.4
 $ —
 $ 1.4

 $ 1.1
 $ —
 $ 1.1

 $ 2.7
 ($ 0.3)
 $ 2.4

 $ 0.4
 $ —
 $ 0.4

 $ 10.1
 $ —
 $ 10.1

 $ 0.6
 $ —
 $ 0.6

 Balance Sheet Location
 Gross Fair Value (a)
 Offsetting Position (b)
 Net Fair Value (c) (d)

 2022

 $ 13.1
 $ —
 $ 13.1

 Other deferred debits and other assets
 $ 3.4
 $ —
 $ 3.4

 $ —

 $ 7.7
 ($ 0.4)
 $ 7.3

 $ 0.6
 $ —
 $ 0.6

 $ 0.8
 $ —
 $ 0.8

 $ 1.2
 ($ 1.1)
 $ 0.1

 $ 24.0
 $ —
 $ 24.0

 $ 1.5
 $ —
 $ 1.5

 (a)Represents the gross amounts of recognized assets/liabilities
 (b)Represents the netting of fair value balances with the same counterparty
 (c)Represents the net amounts of assets/liabilities presented on the Registrant Subsidiaries' balance sheets
 (d)As of December 31, 2023, letters of credit posted with MISO covered financial transmission rights exposure of $ 1.2 million for Entergy Arkansas, $ 0.5 million for Entergy Louisiana, $ 0.3 million for Entergy Mississippi, and $ 0.1 million for Entergy Texas. As of December 31, 2022, letters of credit posted with MISO covered financial transmission rights exposure of $ 0.2 million for Entergy Mississippi, $ 0.2 million for Entergy New Orleans, and $ 2.4 million for Entergy Texas.

 The effects of derivative instruments not designated as hedging instruments on the Registrant Subsidiaries' income statements for the years ended December 31, 2023, 2022, and 2021 are as follows:

 Income Statement Location
 Amount of gain (loss) recorded in the income statement

 2023

 ($8.4)
 (a)

 ($42.9)
 (a)

 ($3.0)
 (a)

 $ 25.8
 (b)

 $ 60.4
 (b)

 $ 13.7
 (b)

 $ 6.4
 (b)

 $ 17.3
 (b)

 2022

 $ 21.4
 (a)

 $ 53.6
 (a)

 ($1.2)
 (a)

 $ 106.5
 (b)

 $ 48.5
 (b)

 $ 10.4
 (b)

 $ 3.7
 (b)

 $ 6.3
 (b)

 2021

 $ 12.6
 (a)

 $ 19.8
 (a)

 ($0.1)
 (a)

 $ 42.6
 (b)

 $ 31.6
 (b)

 $ 11.3
 (b)

 $ 4.3
 (b)

 $ 85.9
 (b)

 (a)Due to regulatory treatment, the natural gas swaps and options are marked-to-market through fuel, fuel-related expenses, and gas purchased for resale and then such amounts are simultaneously reversed and

 recorded as an offsetting regulatory asset or liability. The gains or losses recorded as fuel expenses when the swaps and options are settled are recovered or refunded through fuel cost recovery mechanisms.
 (b)Due to regulatory treatment, the changes in the estimated fair value of financial transmission rights for the Utility operating companies are recorded through purchased power expense and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability. The gains or losses recorded as purchased power expense when the financial transmission rights for the Utility operating companies are settled are recovered or refunded through fuel cost recovery mechanisms.

 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.

 Accounting standards define fair value as an exit price, or the price that would be received to sell an asset or the amount that would be paid to transfer a liability in an orderly transaction between knowledgeable market participants at the date of measurement. Entergy and the Registrant Subsidiaries use assumptions or market input data that market participants would use in pricing assets or liabilities at fair value. The inputs can be readily observable, corroborated by market data, or generally unobservable. Entergy and the Registrant Subsidiaries endeavor to use the best available information to determine fair value.

 Accounting standards establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy establishes the highest priority for unadjusted market quotes in an active market for the identical asset or liability and the lowest priority for unobservable inputs.

 The three levels of the fair value hierarchy are:

 • Level 1 - Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the entity has the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of individually owned common stocks, cash equivalents (temporary cash investments, securitization recovery trust account, and escrow accounts), debt instruments, and gas swaps traded on exchanges with active markets. Cash equivalents includes all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at the date of purchase.

 • Level 2 - Level 2 inputs are inputs other than quoted prices included in Level 1 that are, either directly or indirectly, observable for the asset or liability at the measurement date. Assets are valued based on prices derived by independent third parties that use inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads. Prices are reviewed and can be challenged with the independent parties and/or overridden by Entergy if it is believed such would be more reflective of fair value. Level 2 inputs include the following:

 –quoted prices for similar assets or liabilities in active markets;
 –quoted prices for identical assets or liabilities in inactive markets;
 –inputs other than quoted prices that are observable for the asset or liability; or
 –inputs that are derived principally from or corroborated by observable market data by correlation or other means.

 Level 2 consists primarily of individually-owned debt instruments and gas swaps and options valued using observable inputs.

 • Level 3 - Level 3 inputs are pricing inputs that are generally less observable or unobservable from objective sources. These inputs are used with internally developed methodologies to produce management's best estimate of fair value for the asset or liability. Level 3 consists primarily of financial transmission rights.

 As a result of the completion of Entergy's strategy to exit the merchant nuclear power business, which included the shut down and sale of all non-utility nuclear plants, the portfolio of derivative instruments held by Entergy's non-utility operations business expired in April 2021, which was the settlement date for the last financial derivative contracts in the non-utility operations business' portfolio.

 The values for power contract assets or liabilities prior to expiration in April 2021 were based on both observable inputs including public market prices and interest rates, and unobservable inputs such as implied volatilities, unit contingent discounts, expected basis differences, and credit adjusted counterparty interest rates. They were classified as Level 3 assets and liabilities. The valuations of these assets and liabilities were performed by the Office of Corporate Risk Oversight and the non-utility operations Accounting group. The primary related functions of the Office of Corporate Risk Oversight included: gathering, validating, and reporting market data, providing market risk analyses and valuations in support of the non-utility operations commercial transactions, developing and administering protocols for the management of market risks, and implementing and maintaining controls around changes to market data in the energy trading and risk management system. The Office of Corporate Risk Oversight was also responsible for managing the energy trading and risk management system, forecasting revenues, forward positions, and analysis. The non-utility operations Accounting group performed functions related to market and counterparty settlements, revenue reporting and analysis, and financial accounting. The Office of Corporate Risk Oversight reports to the Vice President and Treasurer while the non-utility operations Accounting group reports to the Chief Accounting Officer.

 The amounts reflected as the fair value of electricity swaps were based on the estimated amount that the contracts were in-the-money at the balance sheet date (treated as an asset) or out-of-the-money at the balance sheet date (treated as a liability) and equaled the estimated amount receivable to or payable by Entergy if the contracts were settled at that date. These derivative contracts included cash flow hedges that swapped fixed for floating cash flows for sales of the output from the non-utility operations business. The fair values were based on the mark-to-market comparison between the fixed contract prices and the floating prices determined each period from quoted forward power market prices. The differences between the fixed price in the swap contract and these market-related prices multiplied by the volume specified in the contract and discounted at the counterparties' credit adjusted risk free rate were recorded as derivative contract assets or liabilities. For contracts that had unit contingent terms, a further discount was applied based on the historical relationship between contract and market prices for similar contract terms.

 The amounts reflected as the fair values of electricity options were valued based on a Black Scholes model and were calculated at the end of each month for accounting purposes. Inputs to the valuation included end of day forward market prices for the period when the transactions settled, implied volatilities based on market volatilities provided by a third-party data aggregator, and U.S. Treasury rates for a risk-free return rate. As described further below, prices and implied volatilities were reviewed and could be adjusted if it was determined that there was a better representation of fair value.

 On a daily basis, the Office of Corporate Risk Oversight calculated the mark-to-market for electricity swaps and options. The Office of Corporate Risk Oversight also validated forward market prices by comparing them to other sources of forward market prices or to settlement prices of actual market transactions. Significant differences were analyzed and potentially adjusted based on these other sources of forward market prices or settlement prices of actual market transactions. Implied volatilities used to value options were also validated using actual counterparty

 quotes for transactions by the non-utility operations business when available and compared with other sources of market implied volatilities. Moreover, on a quarterly basis, the Office of Corporate Risk Oversight confirmed the mark-to-market calculations and prepared price scenarios and credit downgrade scenario analysis. The scenario analysis was communicated to senior management within Entergy. Finally, for all proposed derivative transactions, an analysis was completed to assess the risk of adding the proposed derivative to the non-utility operations business' portfolio. In particular, the credit and liquidity effects were calculated for this analysis. This analysis was communicated to senior management within Entergy.

 The values of financial transmission rights are based on unobservable inputs, including estimates of congestion costs in MISO between applicable generation and load pricing nodes based on the 50th percentile of historical prices. They are classified as Level 3 assets and liabilities. The valuations of these assets and liabilities are performed by the Office of Corporate Risk Oversight. The values are calculated internally and verified against the data published by MISO. Entergy's Accounting group reviews these valuations for reasonableness, with the assistance of others within the organization with knowledge of the various inputs and assumptions used in the valuation. The Office of Corporate Risk Oversight reports to the Vice President and Treasurer. The Accounting group reports to the Chief Accounting Officer.

 The following tables set forth, by level within the fair value hierarchy, Entergy's assets and liabilities that are accounted for at fair value on a recurring basis as of December 31, 2023 and December 31, 2022. The assessment of the significance of a particular input to a fair value measurement requires judgment and may affect placement within the fair value hierarchy levels.

 2023
 Total

 $ 61
 $ —
 $ —
 $ 61

 —
 —

 1,159
 —
 1,770

 3,070

 —
 —

 Storm reserve escrow accounts
 —
 —

 —
 —

 $ 1,027
 $ 1,159
 $ 21
 $ 5,277

 $ 11
 $ —
 $ —
 $ 11

 2022
 Total

 $ 109
 $ —
 $ —
 $ 109

 —
 —

 1,122
 —
 1,656

 2,442

 —
 —

 Storm reserve escrow accounts
 —
 —

 —

 —
 —

 $ 1,095
 $ 1,125
 $ 19
 $ 4,681

 $ 25
 $ —
 $ —
 $ 25

 (a)The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices. Fixed income securities are held in various governmental and corporate securities. See Note 16 to the financial statements for additional information on the investment portfolios.
 (b)Common trust funds are not publicly quoted and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. The fund administrator of these investments allows daily trading at the net asset value and trades settle at a later date.

 The following table sets forth a reconciliation of changes in the net assets for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the years ended December 31, 2023, 2022, and 2021:

 2023
 2022
 2021

 Power Contracts

 Balance as of January 1,
 $ 19
 $ 4
 $ 38
 $ 9

 Total gains (losses) for the period

 Included in earnings
 —
 —
 ( 2)
 —

 Included in other comprehensive income
 —
 —
 —

 Included as a regulatory liability/asset
 —

 Issuances of financial transmission rights
 —

 Settlements
 ( 124)
 ( 176)
 ( 38)
 ( 179)

 Balance as of December 31,
 $ 21
 $ 19
 $ —
 $ 4

 The fair values of the Level 3 financial transmission rights are based on unobservable inputs calculated internally and verified against historical pricing data published by MISO.

 The following table sets forth an analysis of each of the types of unobservable inputs impacting the fair value of items classified as Level 3 within the fair value hierarchy, and the sensitivity to changes to those inputs:

 Significant Unobservable Input
 Transaction Type
 Change to Input
 Effect on Fair Value

 Unit contingent discount
 Electricity swaps
 Sell
 Increase (Decrease)
 Decrease (Increase)

 The following table sets forth, by level within the fair value hierarchy, the Registrant Subsidiaries' assets and liabilities that are accounted for at fair value on a recurring basis as of December 31, 2023 and December 31, 2022. The assessment of the significance of a particular input to a fair value measurement requires judgment and may affect placement within the fair value hierarchy levels.

 2023
 Total

 $ 3.1
 $ —
 $ —
 $ 3.1

 6.4
 —
 —
 6.4

 129.9
 367.0
 —
 496.9

 910.7

 —
 —
 6.0
 6.0

 $ 139.4
 $ 367.0
 $ 6.0
 $ 1,423.1

 2022
 Total

 $ 3.4
 $ —
 $ —
 $ 3.4

 4.5
 —
 —
 4.5

 126.8
 343.9
 —
 470.7

 724.7

 —
 —
 10.3
 10.3

 $ 134.7
 $ 343.9
 $ 1,213.6

 2023
 Total

 $ 0.5
 $ —
 $ —
 $ 0.5

 14.6
 —
 —
 14.6

 271.7
 516.4
 —
 788.1

 1,304.7

 243.8
 —
 —
 243.8

 —
 —
 9.8
 9.8

 $ 530.6
 $ 516.4
 $ 9.8
 $ 2,361.5

 $ 0.4
 $ —
 $ —
 $ 0.4

 2022
 Total

 $ 6.3
 $ —
 $ —
 $ 6.3

 16.8
 —
 —
 16.8

 209.4
 515.7
 —
 725.1

 1,037.2

 293.4
 —
 —
 293.4

 13.1
 3.4
 —
 16.5

 —
 —
 7.3
 7.3

 $ 539.0
 $ 519.1
 $ 7.3
 $ 2,102.6

 2023
 Total

 $ 6.6
 $ —
 $ —
 $ 6.6

 0.7
 —
 —
 0.7

 —
 —
 1.4
 1.4

 $ 7.3
 $ —
 $ 1.4
 $ 8.7

 $ 10.1
 $ —
 $ —
 $ 10.1

 2022
 Total

 $ 17.0
 $ —
 $ —
 $ 17.0

 33.5
 —
 —
 33.5

 —
 —
 0.6
 0.6

 $ 50.5
 $ —
 $ 0.6
 $ 51.1

 $ 24.0
 $ —
 $ —
 $ 24.0

 2023
 Total

 $ 2.4
 $ —
 $ —
 $ 2.4

 78.7
 —
 —
 78.7

 —
 —
 1.1
 1.1

 $ 81.1
 $ —
 $ 1.1
 $ 82.2

 $ 0.6
 $ —
 $ —
 $ 0.6

 2022
 Total

 $ 4.4
 $ —
 $ —
 $ 4.4

 2.2
 —
 —
 2.2

 75.0
 —
 —
 75.0

 —
 —
 0.8
 0.8

 $ 81.6
 $ —
 $ 0.8
 $ 82.4

 $ 1.5
 $ —
 $ —
 $ 1.5

 2023
 Total

 $ 20.5
 $ —
 $ —
 $ 20.5

 5.2
 —
 —
 5.2

 —
 —
 2.4
 2.4

 $ 25.7
 $ —
 $ 2.4
 $ 28.1

 2022
 Total

 $ 3.0
 $ —
 $ —
 $ 3.0

 10.9
 —
 —
 10.9

 —
 —
 0.1
 0.1

 $ 13.9
 $ —
 $ 0.1
 $ 14.0

 2023
 Total

 $ 2.7
 $ —
 $ —
 $ 2.7

 209.5
 275.7
 —
 485.2

 854.4

 $ 212.2
 $ 275.7
 $ —
 $ 1,342.3

 2022
 Total

 $ 2.9
 $ —
 $ —
 $ 2.9

 2.8
 —
 —
 2.8

 197.5
 262.2
 —
 459.7

 680.4

 $ 203.2
 $ 262.2
 $ —
 $ 1,145.8

 (a)The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices. Fixed income securities are held in various governmental and corporate securities. See Note 16 to the financial statements for additional information on the investment portfolios.
 (b)Common trust funds are not publicly quoted and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. The fund administrator of these investments allows daily trading at the net asset value and trades settle at a later date.

 The following table sets forth a reconciliation of changes in the net assets for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the year ended December 31, 2023.

 Balance as of January 1, 2023
 $ 7.3
 $ 0.6
 $ 0.8
 $ 0.1

 Issuances of financial transmission rights
 20.6
 18.1
 1.3
 1.4
 0.2

 Gains (losses) included as a regulatory liability/asset
 0.9
 44.8
 13.2
 5.3
 19.4

 Settlements
 ( 25.8)
 ( 60.4)
 ( 13.7)
 ( 6.4)
 ( 17.3)

 Balance as of December 31, 2023
 $ 6.0
 $ 9.8
 $ 1.4
 $ 1.1
 $ 2.4

 The following table sets forth a reconciliation of changes in the net assets for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the year ended December 31, 2022.

 Balance as of January 1, 2022
 $ 2.3
 $ 0.6
 $ 0.3
 $ 0.1
 $ 0.8

 Issuances of financial transmission rights
 5.4
 5.3
 0.8
 0.8
 3.9

 Gains (losses) included as a regulatory liability/asset
 109.1
 49.9
 9.9
 3.6
 1.7

 Settlements
 ( 106.5)
 ( 48.5)
 ( 10.4)
 ( 3.7)
 ( 6.3)

 Balance as of December 31, 2022
 $ 7.3
 $ 0.6
 $ 0.8
 $ 0.1

 NOTE 16. DECOMMISSIONING TRUST FUNDS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)

 The NRC requires certain of the Utility operating companies and System Energy to maintain nuclear decommissioning trusts to fund the costs of decommissioning ANO 1, ANO 2, River Bend, Waterford 3, and Grand Gulf. Entergy's nuclear decommissioning trust funds invest in equity securities, fixed-rate debt securities, and cash and cash equivalents.

 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 deferred credits for the unrealized trust earnings not currently expected to be needed to decommission the plant. Decommissioning trust funds for the nuclear plants previously owned by Entergy's non-utility operations, all of which have been sold as of June 2022, did not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains/(losses) recorded on the equity securities in the trust funds for these plants were recognized in earnings with no offsetting regulatory liability/asset amount. Unrealized gains/(losses) recorded on the available-for-sale debt securities in the trust funds were recognized in the accumulated other comprehensive income component of shareholders' equity. Generally, Entergy records gains and losses on its debt and equity securities using the specific identification method to determine the cost basis of its securities.

 As discussed in Note 14 to the financial statements, in June 2022, Entergy completed the sale of Palisades to Holtec. As part of the transaction, Entergy transferred the Palisades decommissioning trust fund to Holtec. The disposition-date fair value of the decommissioning trust fund was approximately $ 552 million.

 The unrealized gains/(losses) recognized during the year ended December 31, 2023 on equity securities still held as of December 31, 2023 were $ 591 million. The equity securities are generally held in funds that are designed to approximate or somewhat exceed the return of the Standard & Poor's 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index or the Russell 3000 Index. The debt securities are generally held in individual government and credit issuances.

 The available-for-sale securities held as of December 31, 2023 and 2022 are summarized as follows:

 Total Unrealized Gains
 Total Unrealized Losses

 2023

 $ 1,770
 $ 19
 $ 134

 2022

 $ 1,655
 $ 4
 $ 201

 As of December 31, 2023 and 2022, there were no deferred taxes on unrealized gains/(losses). The amortized cost of available-for-sale debt securities was $ 1,885 million as of December 31, 2023 and $ 1,852 million as of December 31, 2022. As of December 31, 2023, available-for-sale debt securities had an average coupon rate of approximately 3.48 %, an average duration of approximately 6.36 years, and an average maturity of approximately 10.82 years.

 The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities had been in a continuous loss position, were as follows as of December 31, 2023 and 2022:

 December 31, 2022

 Less than 12 months
 $ 134
 $ 6
 $ 840
 $ 63

 More than 12 months

 Total
 $ 1,133
 $ 134
 $ 1,506
 $ 201

 The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2023 and 2022 are as follows:

 2023
 2022

 Less than 1 year
 $ 82
 $ 62

 1 year - 5 years

 5 years - 10 years

 10 years - 15 years

 15 years - 20 years

 20 years+

 Total
 $ 1,770
 $ 1,655

 During the years ended December 31, 2023, 2022, and 2021, proceeds from the dispositions of available-for-sale securities amounted to $ 661 million, $ 889 million, and $ 1,465 million, respectively. During the year ended December 31, 2023, there were gross gains of $ 1 million and gross losses of $ 37 million related to available-for-sale securities reclassified out of other regulatory liabilities/assets into earnings. During the years ended December 31, 2022 and 2021, there were gross gains of $ 2 million and $ 29 million, respectively, and gross losses of $ 46 million and $ 17 million, respectively, related to available-for-sale securities reclassified out of other comprehensive income or other regulatory liabilities/assets into earnings.

 Entergy Arkansas holds equity securities and available-for-sale debt securities in nuclear decommissioning trust accounts. The available-for-sale securities held as of December 31, 2023 and 2022 are summarized as follows:

 Total Unrealized Gains
 Total Unrealized Losses

 2023

 $ 496.9
 $ 2.4
 $ 53.6

 2022

 $ 470.7
 $ 0.2
 $ 69.3

 The amortized cost of available-for-sale debt securities was $ 548.1 million as of December 31, 2023 and $ 539.8 million as of December 31, 2022. As of December 31, 2023, the available-for-sale debt securities had an average coupon rate of approximately 2.66 %, an average duration of approximately 6.02 years, and an average maturity of approximately 7.64 years.

 The unrealized gains/(losses) recognized during the year ended December 31, 2023 on equity securities still held as of December 31, 2023 were $ 175 million. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor's 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.

 The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities had been in a continuous loss position, were as follows as of December 31, 2023 and 2022:

 December 31, 2022

 Less than 12 months
 $ 22.5
 $ 0.4
 $ 197.6
 $ 18.8

 More than 12 months
 403.4
 53.2
 260.1
 50.5

 Total
 $ 425.9
 $ 53.6
 $ 457.7
 $ 69.3

 The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2023 and 2022 are as follows:

 2023
 2022

 Less than 1 year
 $ 45.3
 $ 21.2

 1 year - 5 years
 132.2
 159.7

 5 years - 10 years
 205.7
 191.7

 10 years - 15 years
 39.9
 38.0

 15 years - 20 years
 49.6
 42.6

 20 years+
 24.2
 17.5

 Total
 $ 496.9
 $ 470.7

 During the years ended December 31, 2023, 2022, and 2021, proceeds from the dispositions of available-for-sale securities amounted to $ 28.5 million, $ 42.1 million, and $ 57.6 million, respectively. During the year ended December 31, 2023, there were gross gains of $ 0.1 million and gross losses of $ 2 million related to available-for-sale securities reclassified out of other regulatory liabilities/assets into earnings. During the years ended December 31, 2022 and 2021, there were gross gains of $ 0.1 million and $ 2.5 million, respectively, and gross losses of $ 2.6 million and $ 0.6 million, respectively, related to available-for-sale securities reclassified out of other comprehensive income or other regulatory liabilities/assets into earnings.

 Entergy Louisiana holds equity securities and available-for-sale debt securities in nuclear decommissioning trust accounts. The available-for-sale securities held as of December 31, 2023 and 2022 are summarized as follows:

 Total Unrealized Gains
 Total Unrealized Losses

 2023

 $ 788.1
 $ 11.7
 $ 37.4

 2022

 $ 725.1
 $ 3.5
 $ 67.5

 The amortized cost of available-for-sale debt securities was $ 813.9 million as of December 31, 2023 and $ 789.1 million as of December 31, 2022. As of December 31, 2023, the available-for-sale debt securities had an

 average coupon rate of approximately 3.91 %, an average duration of approximately 6.53 years, and an average maturity of approximately 13.16 years.

 The unrealized gains/(losses) recognized during the year ended December 31, 2023 on equity securities still held as of December 31, 2023 were $ 251.3 million. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor's 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.

 The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities had been in a continuous loss position, were as follows as of December 31, 2023 and 2022:

 December 31, 2022

 Less than 12 months
 $ 69.8
 $ 0.9
 $ 409.9
 $ 24.6

 More than 12 months
 356.1
 36.5
 207.5
 42.9

 Total
 $ 425.9
 $ 37.4
 $ 617.4
 $ 67.5

 The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2023 and 2022 are as follows:

 2023
 2022

 Less than 1 year
 $ 31.4
 $ 33.6

 1 year - 5 years
 181.6
 159.1

 5 years - 10 years
 170.0
 161.7

 10 years - 15 years
 70.2
 67.1

 15 years - 20 years
 90.2
 83.3

 20 years+
 244.7
 220.3

 Total
 $ 788.1
 $ 725.1

 During the years ended December 31, 2023, 2022, and 2021, proceeds from the dispositions of available-for-sale securities amounted to $ 318.6 million, $ 362.2 million, and $ 303.4 million, respectively. During the year ended December 31, 2023, there were gross gains of $ 0.5 million and gross losses of $ 20.9 million related to available-for-sale securities reclassified out of other regulatory liabilities/assets into earnings. During the years ended December 31, 2022 and 2021, there were gross gains of $ 1.3 million and $ 6.8 million, respectively, and gross losses of $ 23 million and $ 4.1 million, respectively, related to available-for-sale securities reclassified out of other comprehensive income or other regulatory liabilities/assets into earnings.

 System Energy holds equity securities and available-for-sale debt securities in nuclear decommissioning trust accounts. The available-for-sale securities held as of December 31, 2023 and 2022 are summarized as follows:

 Total Unrealized Gains
 Total Unrealized Losses

 2023

 $ 485.2
 $ 4.5
 $ 42.5

 2022

 $ 459.7
 $ 0.7
 $ 63.7

 The amortized cost of available-for-sale debt securities was $ 523.2 million as of December 31, 2023 and $ 522.7 million as of December 31, 2022. As of December 31, 2023, the available-for-sale debt securities had an average coupon rate of approximately 3.63 %, an average duration of approximately 6.44 years, and an average maturity of approximately 10.27 years.

 The unrealized gains/(losses) recognized during the year ended December 31, 2023 on equity securities still held as of December 31, 2023 were $ 164.2 million. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor's 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.

 The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities had been in a continuous loss position, were as follows as of December 31, 2023 and 2022:

 December 31, 2022

 Less than 12 months
 $ 42.1
 $ 4.5
 $ 231.9
 $ 19.2

 More than 12 months
 239.1
 38.0
 198.0
 44.5

 Total
 $ 281.2
 $ 42.5
 $ 429.9
 $ 63.7

 The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2023 and 2022 are as follows:

 2023
 2022

 Less than 1 year
 $ 5.3
 $ 6.8

 1 year - 5 years
 203.4
 201.7

 5 years - 10 years
 128.6
 107.1

 10 years - 15 years
 10.7
 11.7

 15 years - 20 years
 38.8
 35.0

 20 years+
 98.4
 97.4

 Total
 $ 485.2
 $ 459.7

 During the years ended December 31, 2023, 2022, and 2021, proceeds from the dispositions of available-for-sale securities amounted to $ 314.3 million, $ 209.4 million, and $ 513.8 million, respectively. During the year ended December 31, 2023, there were gross gains of $ 0.6 million and gross losses of $ 14.2 million related to available-for-sale securities reclassified out of other regulatory liabilities/assets into earnings. During the years ended December 31, 2022 and 2021, there were gross gains of $ 0.2 million and $ 9.3 million, respectively, and gross losses of $ 10.7 million and $ 4 million, respectively, related to available-for-sale securities reclassified out of other comprehensive income or other regulatory liabilities/assets into earnings.

 NOTE 17. VARIABLE INTEREST ENTITIES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

 Under applicable authoritative accounting guidance, a variable interest entity (VIE) is an entity that conducts a business or holds property that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity holders do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations, and is required to consolidate a VIE if it is the VIE's primary beneficiary. The primary beneficiary of a VIE is the entity that has the power to direct the activities of the VIE that most significantly affect the VIE's economic performance and has the obligation to absorb losses or has the right to residual returns that would potentially be significant to the entity.

 Entergy Arkansas, Entergy Louisiana, and System Energy consolidate the respective companies from which they lease nuclear fuel, usually in a sale and leaseback transaction. This is because Entergy directs the nuclear fuel companies with respect to nuclear fuel purchases, assists the nuclear fuel companies in obtaining financing, and, if financing cannot be arranged, the lessee (Entergy Arkansas, Entergy Louisiana, or System Energy) is required to pay advance rent (Entergy Arkansas VIE, Entergy Louisiana Waterford VIE, and System Energy VIE) or special payments (Entergy Louisiana River Bend VIE) to allow the nuclear fuel company (the VIE) to meet its obligations. During the term of the arrangements, none of the Entergy operating companies have been required to provide financial support apart from their scheduled lease payments. See Note 4 to the financial statements for details of the nuclear fuel companies' credit facility and commercial paper borrowings and long-term debt that are reported by Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy. These amounts also represent Entergy's and the respective Registrant Subsidiary's maximum exposure to losses associated with their respective interests in the nuclear fuel companies.

 Entergy Texas Restoration Funding, LLC and Entergy Texas Restoration Funding II, LLC, companies wholly-owned and consolidated by Entergy Texas, are VIEs and Entergy Texas is the primary beneficiary. In November 2009, Entergy Texas Restoration Funding issued senior secured transition bonds (securitization bonds) to finance Entergy Texas's Hurricane Ike and Hurricane Gustav restoration costs. Although the principal amount was not due until November 2023, Entergy Texas Restoration Funding made principal payments on the bonds in 2022, after which the bonds were fully repaid. In April 2022, Entergy Texas Restoration Funding II issued senior secured system restoration bonds (securitization bonds) to finance Entergy Texas's Hurricane Laura, Hurricane Delta, and Winter Storm Uri restoration costs. With the proceeds, the VIEs purchased from Entergy Texas the transition property, which is the right to recover from customers through a system restoration charge amounts sufficient to service the securitization bonds. The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet. The creditors of Entergy Texas do not have recourse to the assets or revenues of the VIEs, including the transition property, and the creditors of the VIEs do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to the VIEs except to remit system restoration charge collections. See Note 5 to the financial statements for additional details regarding the securitization bonds.

 Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, is a VIE and Entergy Louisiana is the primary beneficiary. In September 2011, Entergy

 Louisiana Investment Recovery Funding issued investment recovery bonds to recover Entergy Louisiana's investment recovery costs associated with the canceled Little Gypsy repowering project. With the proceeds, Entergy Louisiana Investment Recovery Funding purchased from Entergy Louisiana the investment recovery property, which is the right to recover from customers through an investment recovery charge amounts sufficient to service the bonds. Although the principal amount was not due until September 2023, Entergy Louisiana Investment Recovery Funding made principal payments on the bonds in 2021, after which the bonds were fully repaid. See Note 5 to the financial statements for additional details regarding the investment recovery bonds.

 Entergy New Orleans Storm Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy New Orleans, is a VIE and Entergy New Orleans is the primary beneficiary. In July 2015, Entergy New Orleans Storm Recovery Funding issued storm cost recovery bonds to recover Entergy New Orleans's Hurricane Isaac storm restoration costs, including carrying costs, the costs of funding and replenishing the storm recovery reserve, and up-front financing costs associated with the securitization. With the proceeds, Entergy New Orleans Storm Recovery Funding purchased from Entergy New Orleans the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy New Orleans balance sheet. The creditors of Entergy New Orleans do not have recourse to the assets or revenues of Entergy New Orleans Storm Recovery Funding, including the storm recovery property, and the creditors of Entergy New Orleans Storm Recovery Funding do not have recourse to the assets or revenues of Entergy New Orleans. Entergy New Orleans has no payment obligations to Entergy New Orleans Storm Recovery Funding except to remit storm recovery charge collections. See Note 5 to the financial statements for additional details regarding the securitization bonds.

 Restoration Law Trust I (the storm trust I), a trust consolidated by Entergy Louisiana, is a VIE and Entergy Louisiana is the primary beneficiary. The storm trust I was established as part of the Act 293 securitization of Entergy Louisiana's Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri restoration costs, as well as to establish a storm reserve to fund a portion of Hurricane Ida storm restoration costs. Entergy Louisiana is the primary beneficiary of the storm trust I because it was created to facilitate the financing of Entergy Louisiana's storm restoration costs and Entergy Louisiana is entitled to receive a majority of the proceeds received by the storm trust I. As of December 31, 2023 and 2022, the primary asset held by the storm trust I was $ 3 billion and $ 3.2 billion, respectively, of outstanding Entergy Finance Company preferred membership interests, which is reflected as an investment in affiliate preferred membership interests on the consolidated balance sheets of Entergy Louisiana. The storm trust I's investment in affiliate preferred membership interests was purchased with the net bond proceeds of the securitization bonds issued by the LCDA. After the securitization bonds were issued, the LCDA loaned the net bond proceeds to the LURC, and pursuant to Act 293, the LURC contributed the net bond proceeds to the storm trust I. The holders of the securitization bonds do not have recourse to the assets or revenues of the trust or to any Entergy affiliate and the bonds are not reflected in the consolidated balance sheets of Entergy or Entergy Louisiana. The LURC's 1 % beneficial interest in the storm trust I is presented as noncontrolling interest on the consolidated balance sheets of Entergy and Entergy Louisiana, with balances of $ 30.5 million and $ 31.7 million as of December 31, 2023 and 2022, respectively. See Note 2 to the financial statements for additional discussion of the securitization bonds and the preferred membership interests.

 Restoration Law Trust II (the storm trust II), a trust consolidated by Entergy Louisiana, is a VIE and Entergy Louisiana is the primary beneficiary. The storm trust II was established as part of the March 2023 Act 293 securitization of Entergy Louisiana's Hurricane Ida restoration costs, less Hurricane Ida amounts previously financed in May 2022 in a prior securitization transaction. Entergy Louisiana is the primary beneficiary of the storm trust II because it was created to facilitate the financing of Entergy Louisiana's storm restoration costs and Entergy Louisiana is entitled to receive a majority of the proceeds received by the storm trust II. As of December 31, 2023, the primary asset held by the storm trust II is the $ 1.5 billion of outstanding Entergy Finance Company preferred membership interests, which is reflected as an investment in affiliate preferred membership interests on the consolidated balance sheets of Entergy Louisiana. The storm trust II's investment in affiliate preferred membership interests was purchased with the net bond proceeds of the securitization bonds issued by the LCDA. After the securitization bonds were issued, the LCDA loaned the net bond proceeds to the LURC, and pursuant to

 Act 293, the LURC contributed the net bond proceeds to the storm trust II. The holders of the securitization bonds do not have recourse to the assets or revenues of the storm trust II or to any Entergy affiliate and the bonds are not reflected in the consolidated balance sheets of Entergy or Entergy Louisiana. The LURC's 1 % beneficial interest in the storm trust II is presented as noncontrolling interest on the consolidated balance sheets of Entergy and Entergy Louisiana, with a balance of $ 14.6 million as of December 31, 2023. See Note 2 to the financial statements herein for additional discussion of the securitization bonds and the preferred membership interests.

 System Energy is considered to hold a variable interest in the lessor from which it leases an undivided interest in the Grand Gulf nuclear plant. System Energy is the lessee under this arrangement, which is described in more detail in Note 5 to the financial statements. System Energy made payments under this arrangement, including interest, of $ 17.2 million in 2023, $ 17.2 million in 2022, and $ 17.2 million in 2021. The lessor is a bank acting in the capacity of owner trustee for the benefit of equity investors in the transaction pursuant to trust agreement entered solely for the purpose of facilitating the lease transaction. It is possible that System Energy may be considered as the primary beneficiary of the lessor, but it is unable to apply the authoritative accounting guidance with respect to this VIE because the lessor is not required to, and could not, provide the necessary financial information to consolidate the lessor. Because System Energy accounts for this leasing arrangement as a capital financing, however, System Energy believes that consolidating the lessor would not materially affect the financial statements. In the event of default under a lease, remedies available to the lessor include payment by the lessee of the fair value of the undivided interest in the plant, payment of the present value of the basic rent payments, or payment of a predetermined casualty value. System Energy believes, however, that the obligations recorded on the balance sheet materially represent its potential exposure to loss.

 AR Searcy Partnership, LLC, is a tax equity partnership that qualifies as a VIE, which Entergy Arkansas is required to consolidate as it is the primary beneficiary. See Note 14 to the financial statements for additional discussion on the establishment of AR Searcy Partnership, LLC and the acquisition of the Searcy Solar facility. The entity is a VIE because the holders of the membership interests, as a group, lack the characteristics of a controlling financial interest, including substantive kick out rights. Entergy Arkansas is the primary beneficiary of the partnership because, as the managing member, it has the right to direct the operations and receive a majority of the operating income of the partnership. See Note 1 to the financial statements for discussion of the presentation of the third party tax equity partner's noncontrolling interest and the HLBV method of accounting used to account for Entergy Arkansas's investment in AR Searcy Partnership, LLC. As of December 31, 2023, AR Searcy Partnership, LLC recorded assets equal to $ 134 million, primarily consisting of property, plant, and equipment, and the carrying value of Entergy Arkansas's ownership interest in the partnership was approximately $ 111.2 million. As of December 31, 2022, AR Searcy Partnership, LLC recorded assets equal to $ 138.3 million, primarily consisting of property, plant, and equipment, and the carrying value of Entergy Arkansas's ownership interest in the partnership was approximately $ 109 million. The tax equity investor's ownership interest is recorded as noncontrolling interest.

 MS Sunflower Partnership, LLC, is a tax equity partnership that qualifies as a VIE, which Entergy Mississippi is required to consolidate as it is the primary beneficiary. See Note 14 to the financial statements for additional discussion on the establishment of MS Sunflower Partnership, LLC and the acquisition of the Sunflower Solar facility. The entity is a VIE because the holders of the membership interests, as a group, lack the characteristics of a controlling financial interest, including substantive kick out rights. Entergy Mississippi is the primary beneficiary of the partnership because, as the managing member, it has the right to direct the operations and receive a majority of the operating income of the partnership. See Note 1 to the financial statements for discussion of the presentation of the third party tax equity partner's noncontrolling interest and the HLBV method of accounting used to account for Entergy Mississippi's investment in MS Sunflower Partnership, LLC. As of December 31, 2023, MS Sunflower Partnership, LLC recorded assets equal to $ 163.2 million, primarily consisting of property, plant, and equipment, and the carrying value of Entergy Mississippi's ownership interest in the partnership was approximately $ 128.4 million. As of December 31, 2022, MS Sunflower Partnership, LLC recorded assets equal to $ 154.5 million, primarily consisting of property, plant, and equipment, and the carrying value of Entergy Mississippi's ownership interest in the partnership was approximately $ 117.2 million. The tax equity investor's ownership interest is recorded as noncontrolling interest.

 Entergy has also reviewed various lease arrangements, power purchase agreements, including agreements for renewable power, and other agreements that represent variable interests in other legal entities which have been determined to be VIEs. In these cases, Entergy has determined that it is not the primary beneficiary of the related VIE because it does not have the power to direct the activities of the VIE that most significantly affect the VIE's economic performance, or it does not have the obligation to absorb losses or the right to residual returns that would potentially be significant to the entity, or both.

 NOTE 18. TRANSACTIONS WITH AFFILIATES (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

 Each Registrant Subsidiary purchases electricity from or sells electricity to the other Registrant Subsidiaries, or both, under rate schedules filed with the FERC. The Registrant Subsidiaries receive management, technical, advisory, operating, and administrative services from Entergy Services; and receive management, technical, and operating services from Entergy Operations. These transactions are on an "at cost" basis.

 As described in Note 1 to the financial statements, all of System Energy's operating revenues consist of billings to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

 As described in Note 4 to the financial statements, the Registrant Subsidiaries participate in the Entergy system money pool and earn interest income from the money pool. As described in Note 2 to the financial statements, Entergy Louisiana received preferred membership interest distributions from Entergy Holdings Company through May 2022, at which point Entergy Holdings Company was dissolved. As a result of storm securitizations at Entergy Louisiana in 2022 and 2023, the Entergy Louisiana storm trust I purchased preferred membership interests issued by Entergy Finance Company in May 2022 and the Entergy Louisiana storm trust II purchased preferred membership interests issued by Entergy Finance Company in March 2023. The Entergy Louisiana storm trust I and storm trust II receive annual dividends on their respective preferred membership interests.

 The tables below contain the various affiliate transactions of the Utility operating companies, System Energy, and other Entergy affiliates.
 Intercompany Revenues

 2023
 $ 125.2
 $ 317.6
 $ 1.0
 $ —
 $ 0.7
 $ 588.4

 2022
 $ 127.5
 $ 354.0
 $ 1.0
 $ —
 $ 18.9
 $ 658.8

 2021
 $ 109.8
 $ 289.9
 $ 1.4
 $ —
 $ 64.3
 $ 545.6

 Intercompany Operating Expenses

 2023
 $ 585.8
 $ 719.8
 $ 345.2
 $ 302.5
 $ 316.8
 $ 179.0

 2022
 $ 617.4
 $ 770.2
 $ 356.1
 $ 341.7
 $ 321.4
 $ 215.0

 2021
 $ 559.7
 $ 755.2
 $ 299.8
 $ 287.8
 $ 275.0
 $ 190.8

 Intercompany Interest and Investment Income

 2023
 $ 0.7
 $ 303.2
 $ 0.2
 $ 1.0
 $ 1.8
 $ 0.6

 2022
 $ 0.1
 $ 186.1
 $ 0.1
 $ 0.1
 $ 0.3
 $ 0.3

 2021
 $ —
 $ 127.6
 $ —
 $ —
 $ —
 $ —

 NOTE 19. REVENUE (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

 Revenues from electric service and the sale of natural gas are recognized when services are transferred to the customer in an amount equal to what Entergy has the right to bill the customer because this amount represents the value of services provided to customers. Entergy's total revenues for the years ended December 31, 2023, 2022 and 2021 are as follows:

 2023
 2022
 2021

 Utility:

 $ 4,552,804
 $ 4,640,039
 $ 3,981,846

 2,997,888
 3,087,675
 2,610,207

 3,170,090
 3,716,058
 2,942,370

 270,640
 286,605
 245,685

 Total billed retail
 10,991,422
 11,730,377
 9,780,108

 Sales for resale (a)
 366,348
 858,743
 601,895

 Other electric revenues (b)
 352,056
 481,256
 375,312

 Revenues from contracts with customers
 11,709,826
 13,070,376
 10,757,315

 Other Utility revenues (c)
 132,628
 116,469
 116,680

 Electric revenues
 11,842,454
 13,186,845
 10,873,995

 Natural gas revenues
 180,490
 233,920
 170,610

 Other revenues (d)
 124,468
 343,472
 698,291

 Total operating revenues
 $ 12,147,412
 $ 13,764,237
 $ 11,742,896

 The Utility operating companies' total revenues for the year ended December 31, 2023 were as follows:

 2023
New
Texas

 $ 996,760
 $ 1,576,129
 $ 748,428
 $ 317,188
 $ 914,299

 584,304
 1,104,509
 604,343
 235,193
 469,539

 635,472
 1,720,298
 217,916
 31,831
 564,573

 20,409
 83,736
 60,477
 77,152
 28,866

 Total billed retail
 2,236,945
 4,484,672
 1,631,164
 661,364
 1,977,277

 Sales for resale (a)
 269,648
 357,900
 104,058
 63,360
 10,497

 Other electric revenues (b)
 121,425
 151,252
 49,752
 ( 992)
 35,988

 Revenues from contracts with customers
 2,628,018
 4,993,824
 1,784,974
 723,732
 2,023,762

 Other revenues (c)
 18,378
 79,415
 17,559
 14,242
 4,824

 Electric revenues
 2,646,396
 5,073,239
 1,802,533
 737,974
 2,028,586

 Natural gas revenues
 —
 74,531
 —
 105,959
 —

 Total operating revenues
 $ 2,646,396
 $ 5,147,770
 $ 1,802,533
 $ 843,933
 $ 2,028,586

 The Utility operating companies' total revenues for the year ended December 31, 2022 were as follows:

 2022
New
Texas

 $ 946,719
 $ 1,775,552
 $ 651,455
 $ 335,471
 $ 930,842

 530,512
 1,274,665
 508,996
 256,963
 516,539

 559,147
 2,275,978
 182,270
 36,970
 661,693

 20,186
 94,910
 52,861
 87,514
 31,134

 Total billed retail
 2,056,564
 5,421,105
 1,395,582
 716,918
 2,140,208

 Sales for resale (a)
 443,685
 555,640
 167,867
 120,851
 66,782

 Other electric revenues (b)
 159,178
 204,878
 51,554
 13,637
 57,379

 Revenues from contracts with customers
 2,659,427
 6,181,623
 1,615,003
 851,406
 2,264,369

 Other revenues (c)
 13,767
 65,310
 9,231
 3,842
 24,536

 Electric revenues
 2,673,194
 6,246,933
 1,624,234
 855,248
 2,288,905

 Natural gas revenues
 —
 91,835
 —
 142,085
 —

 Total operating revenues
 $ 2,673,194
 $ 6,338,768
 $ 1,624,234
 $ 997,333
 $ 2,288,905

 The Utility operating companies' total revenues for the year ended December 31, 2021 were as follows:

 2021
New
Texas

 $ 882,773
 $ 1,484,612
 $ 578,258
 $ 269,891
 $ 766,312

 480,401
 1,055,825
 439,950
 208,104
 425,927

 496,661
 1,771,311
 150,698
 30,751
 492,949

 19,112
 82,503
 46,248
 71,584
 26,238

 Total billed retail
 1,878,947
 4,394,251
 1,215,154
 580,330
 1,711,426

 Sales for resale (a)
 311,791
 391,424
 124,632
 88,349
 145,719

 Other electric revenues (b)
 130,443
 148,304
 58,357
 1,813
 41,805

 Revenues from contracts with customers
 2,321,181
 4,933,979
 1,398,143
 670,492
 1,898,950

 Other revenues (c)
 17,409
 60,480
 8,203
 1,739
 3,561

 Electric revenues
 2,338,590
 4,994,459
 1,406,346
 672,231
 1,902,511

 Natural gas revenues
 —
 73,989
 —
 96,621
 —

 Total operating revenues
 $ 2,338,590
 $ 5,068,448
 $ 1,406,346
 $ 768,852
 $ 1,902,511

 (a)Sales for resale includes day-ahead sales of energy in a market administered by an ISO. These sales represent financially binding commitments for the sale of physical energy the next day. These sales are adjusted to actual power generated and delivered in the real time market. Given the short duration of these transactions, Entergy does not consider them to be derivatives subject to fair value adjustments and includes them as part of customer revenues.
 (b)Other electric revenues consist primarily of transmission and ancillary services provided to participants of an ISO-administered market, unbilled revenue, and certain customer credits as directed by regulators.
 (c)Other Utility revenues include the equity component of carrying costs related to securitization, settlement of financial hedges, occasional sales of inventory, alternative revenue programs, provisions for revenue subject to refund, and late fees.
 (d)Other revenues include the sale of electric power and capacity to wholesale customers, day-ahead sales of energy in a market administered by an ISO, operation and management services fees, and amortization of a below-market power purchase agreement.

 Electric Revenues

 Entergy's primary source of revenue is from retail electric sales sold under tariff rates approved by regulators in its various jurisdictions. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy's Utility operating companies provide power to customers on demand throughout the month, measured by a meter located at the customer's property. Approved rates vary by customer class due to differing requirements of the customers and market factors involved in fulfilling those requirements. Entergy issues monthly bills to customers at rates approved by regulators for power and related services provided during the previous billing cycle.

 To the extent that deliveries have occurred, but a bill has not been issued, Entergy's Utility operating companies record an estimate for energy delivered since the latest billings. The Utility operating companies calculate the estimate based upon several factors including billings through the last billing cycle in a month, actual generation in the month, historical line loss factors, and market prices of power in the respective jurisdiction. The inputs are revised as needed to approximate actual usage and cost. Each month, estimated unbilled amounts are recorded as unbilled revenue and accounts receivable, and the prior month's estimate is reversed. Price and volume

 differences resulting from factors such as weather affect the calculation of unbilled revenues from one period to the other.

 Entergy may record revenue based on rates that are subject to refund. Such revenues are reduced by estimated refund amounts when Entergy believes refunds are probable based on the status of rate proceedings as of the date financial statements are prepared. Because these refunds will be made through a reduction in future rates, and not as a reduction in bills previously issued, they are presented as other revenues in the table above.

 System Energy's only source of revenue is the sale of electric power and capacity generated from its 90 % interest in the Grand Gulf nuclear plant to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. System Energy issues monthly bills to its affiliated customers equal to its actual operating costs plus a return on common equity approved by the FERC.

 Entergy's Utility operating companies also sell excess power not needed for their own customers, primarily through transactions with MISO, a regional transmission organization that maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. In the MISO market, Entergy offers its generation and bids its load into the market. MISO settles these offers and bids based on locational marginal prices. These represent pricing for energy at a given location based on a market clearing price that takes into account physical limitations on the transmission system, generation, and demand throughout the MISO region. MISO evaluates each market participant's energy offers and demand bids to economically and reliably dispatch the entire MISO system. Entergy nets purchases and sales within the MISO market and reports in operating revenues when in a net selling position and in operating expenses when in a net purchasing position.

 Natural Gas

 Entergy Louisiana and Entergy New Orleans also distribute natural gas to retail customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Gas transferred to customers is measured by a meter at the customer's property. Entergy issues monthly invoices to customers at rates approved by regulators for the volume of gas transferred to date.

 Other Revenues

 Entergy's revenues from its non-utility operations include the sale of electric power and capacity to wholesale customers, day-ahead sales of energy in a market administered by an ISO, operation and management services fees, and amortization of a below-market PPA. In 2022 and 2021, the majority of revenues were from the Palisades nuclear power plant located in Michigan, which was shut down in May 2022 and subsequently sold in June 2022. Almost all of the Palisades nuclear plant output was sold under a 15-year PPA with Consumers Energy, which was executed as part of the acquisition of the plant in 2007 and expired in April 2022. Prices under the original PPA ranged from $ 43.50 /MWh in 2007 to $ 61.50 /MWh in 2022, and the average price under the PPA was $ 51 /MWh. Entergy executed an additional PPA to cover the period from the expiration of the original PPA through final shutdown in May 2022 at a price of $ 24.14 /MWh. Entergy issued monthly invoices to Consumers Energy for electric sales based on the actual output of electricity and related services provided during the previous month at the contract price. The PPA was at below-market prices at the time of the acquisition and Entergy amortized a liability to revenue over the life of the agreement. The amount amortized each period was based upon the present value, calculated at the date of acquisition, of each year's difference between revenue under the agreement and revenue based on estimated market prices. Amounts amortized to revenue were $ 5 million in 2022 and $ 12 million in 2021. See Note 14 to the financial statements for discussion of the sale of the Palisades plant.

 Practical Expedients and Exceptions

 Entergy has elected not to disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less, or for revenue recognized in an amount equal to what Entergy has the right to bill the customer for services performed.

 Most of Entergy's contracts, except in a few cases where there are defined minimums or stated terms, are on demand. This results in customer bills that vary each month based on an approved tariff and usage. Entergy imposes monthly or annual minimum requirements on some customers primarily as credit and cost recovery guarantees and not as pricing for unsatisfied performance obligations. These minimums typically expire after the initial term or when specified costs have been recovered. The minimum amounts are part of each month's bill and recognized as revenue accordingly. Some Entergy subsidiaries in the non-utility operations business have services contracts that have fixed components and terms longer than one year. The total fixed consideration related to these unsatisfied performance obligations, however, is not material to Entergy revenues.

 Recovery of Fuel Costs

 Entergy's Utility operating companies' rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Where the fuel component of revenues is based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing. System Energy's operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are based on System Energy's common equity funds allocable to its net investment in Grand Gulf, plus System Energy's effective interest cost for its debt allocable to its investment in Grand Gulf.

 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.

 Allowance for Doubtful Accounts

 The allowance for doubtful accounts reflects Entergy's best estimate of expected losses on its accounts receivable balances. Due to the essential nature of utility services, Entergy has historically experienced a low rate of default on its accounts receivables. The following tables set forth a reconciliation of changes in the allowance for doubtful accounts for the years ended December 31, 2023 and 2022.

New
Texas

 Balance as of December 31, 2022
 $ 30.9
 $ 6.5
 $ 7.6
 $ 2.5
 $ 11.9
 $ 2.4

 Provisions
 38.7
 9.4
 13.9
 7.3
 3.4
 4.7

 Write-offs
 ( 83.1)
 ( 20.6)
 ( 31.3)
 ( 10.4)
 ( 10.7)
 ( 10.1)

 Recoveries
 39.4
 11.9
 15.9
 3.9
 3.2
 4.5

 Balance as of December 31, 2023
 $ 25.9
 $ 7.2
 $ 6.1
 $ 3.3
 $ 7.8
 $ 1.5

New
Texas

 Balance as of December 31, 2021
 $ 68.6
 $ 13.1
 $ 29.2
 $ 7.2
 $ 13.3
 $ 5.8

 Provisions (a)
 40.6
 14.9
 10.7
 3.2
 7.7
 4.1

 Write-offs
 ( 112.5)
 ( 31.2)
 ( 45.1)
 ( 12.1)
 ( 13.5)
 ( 10.6)

 Recoveries
 34.2
 9.7
 12.8
 4.2
 4.4
 3.1

 Balance as of December 31, 2022
 $ 30.9
 $ 6.5
 $ 7.6
 $ 2.5
 $ 11.9
 $ 2.4

 (a)Provisions include estimated incremental bad debt expenses, and revisions to those estimates, resulting from the COVID-19 pandemic of ($ 6.4) million for Entergy, $ 6.4 million for Entergy Arkansas, ($ 8.5) million for Entergy Louisiana, ($ 3.0) million for Entergy New Orleans, and ($ 1.3) million for Entergy Texas that have been deferred as regulatory assets. See Note 2 to the financial statements for information on regulatory assets recorded as a result of the COVID-19 pandemic and orders issued by retail regulators.
 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. The rate of customer write-offs has historically experienced minimal variation, although general economic conditions, such as the COVID-19 pandemic or other economic hardships, can affect the rate of customer write-offs. Management monitors the current condition of individual customer accounts to manage collections and ensure bad debt expense is recorded in a timely manner.

 Item 1. Business

 RISK FACTORS SUMMARY

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

 Utility Regulatory Risks

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

 Nuclear Operating, Shutdown, and Regulatory Risks

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

 Business Risks

 • Entergy and the Registrant Subsidiaries depend on access to the capital markets and, at times, may face potential liquidity constraints. Disruptions in the capital and credit markets or a downgrade in Entergy's or its Registrant Subsidiaries' credit ratings could, among other things, adversely affect their ability to meet liquidity needs, or to access capital to operate and grow their businesses, and the cost of capital.

 • The reputation of Entergy or its Registrant Subsidiaries may be materially adversely affected by negative publicity or the inability to meet their stated goals or commitments, among other potential causes.
 • Changes in tax legislation and taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy's and the Registrant Subsidiaries' results of operations, financial condition, and liquidity.
 • Entergy and its subsidiaries' ability to successfully execute on their business strategies, including their ability to complete capital projects, other capital improvements, and strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies.
 • Failure to attract, retain, and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries' results of operations.
 • Entergy and its subsidiaries, including the Utility operating companies and System Energy, may incur substantial costs (i) to fulfill their obligations related to environmental and other matters or (ii) related to reliability standards.
 • Entergy could be negatively affected by the effects of climate change, including physical risks, such as increased frequency and intensity of hurricanes, availability of water, droughts, and other severe weather and wildfires, and transition risks, such as environmental and regulatory obligations intended to combat the effects of climate change, including by compelling greenhouse gas emission reductions or reporting, or increasing clean or renewable energy requirements, or placing a price on greenhouse gas emissions.
 • Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding of such benefit plans and result in increased benefit plan costs.
 • The litigation environment in the states in which the Registrant Subsidiaries operate poses a significant risk to those businesses.
 • Terrorist attacks and sabotage, physical attacks, cyber attacks, system failures, data breaches or other disruptions of Entergy's and its subsidiaries' or their suppliers' physical infrastructure or technology systems may adversely affect Entergy's business and results of operations.
 • Entergy and the Registrant Subsidiaries are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.
 • Significant increases in commodity prices, other materials and supplies, and operation and maintenance expenses may adversely affect Entergy's results of operations, financial condition, and liquidity.
 • The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans's results of operations and liquidity.
 • System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings. The aggregate amount of refunds claimed in these proceedings, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of substantial additional refunds, System Energy would be required to seek financing to pay such refunds, which financing may not be available on terms acceptable to System Energy when required.
 • As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock, and has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its other financial obligations.
 • The hazardous activities associated with power generation could adversely impact our results of operations and financial condition.

 ENTERGY'S BUSINESS

 Entergy is an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with approximately 24,000 MW of electric generating capacity. Entergy delivers electricity to approximately 3 million Utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $12.1 billion in 2023 and had approximately 12,000 employees as of December 31, 2023.

 Entergy operates primarily through a single reportable segment, Utility. The Utility segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operation of a small natural gas distribution business in portions of Louisiana. See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Planned Sale of Gas Distribution Businesses" for discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana gas distribution businesses. Entergy completed its multi-year strategy to exit the merchant nuclear power business in 2022 and upon completion of all transition activities, effective January 1, 2023, Entergy Wholesale Commodities is no longer a reportable segment. See Note 13 to the financial statements for discussion of and financial information regarding Entergy's business segments.

 Strategy

 Entergy's strategy is to operate and grow its utility business through a customer-centric approach designed to understand and meet customer needs, creating value for all of its key stakeholders, including customers, communities, employees, and owners. As part of its strategy, Entergy invests significant capital to support customer growth and its customers' growing demands for greater reliability, resilience, and clean energy, while remaining focused on affordability. Entergy manages risks by ensuring its Utility investments are customer-driven, the result of robust analysis, supported by broad stakeholder outreach and progressive regulatory constructs, and executed with disciplined project management. Further, Entergy continues to integrate key sustainability elements, including social responsibility and good governance, into every decision it makes.

 The Utility segment includes five retail electric utility subsidiaries: Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. These companies generate, transmit, distribute, and sell electric power to retail and wholesale customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy Louisiana and Entergy New Orleans also provide natural gas utility services to customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Planned Sale of Gas Distribution Businesses" for discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana gas distribution businesses. Also included in the Utility is System Energy, a wholly-owned subsidiary of Entergy Corporation that owns or leases 90 percent of Grand Gulf. System Energy sells its power and capacity from Grand Gulf at wholesale to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The five retail utility subsidiaries are each regulated by the FERC and by state utility commissions, or, in the case of Entergy New Orleans, the City Council. System Energy is regulated by the FERC because all of its transactions are at wholesale. The Utility has a diverse power generation portfolio, including increasingly carbon-free energy sources, which is consistent with Entergy's strong support for the environment.

 Customers

 As of December 31, 2023, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:

 Electric Customers
 Gas Customers

 Area Served
 (%)
 (%)

 Portions of Arkansas

 Portions of Louisiana
 1,105

 Portions of Mississippi

 City of New Orleans

 Portions of Texas

 Total

 3,014

 Electric and Natural Gas Energy Sales

 Electric Energy Sales

 The total electric energy sales of the Utility operating companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On August 23, 2023, Entergy reached a 2023 peak demand of 23,319 MWh, compared to the 2022 peak of 22,301 MWh recorded on June 24, 2022. Selected electric energy sales data for 2023 is shown in the table below:

 Entergy (a)

 (GWh)

 Sales to retail customers
 22,481
 57,681
 12,854
 5,696
 21,146
 —
 119,858

 Affiliates
 2,218
 4,406
 —
 —
 —
 10,574
 —

 Others
 5,777
 1,534
 4,598
 2,818
 —
 15,189

 Total
 30,476
 63,621
 17,452
 8,514
 21,608
 10,574
 135,047

 Average use per residential customer (kWh)
 12,561
 14,893
 14,226
 12,610
 14,941
 —
 14,089

 (a)Includes the effect of intercompany eliminations.

 The following table illustrates the Utility operating companies' 2023 combined electric sales volume as a percentage of total electric sales volume, and 2023 combined electric revenues as a percentage of total 2023 electric revenue, each by customer class.

 Customer Class
 % of Sales Volume
 % of Revenue

 26.9
 38.4

 20.9
 25.3

 Industrial (a)
 39.1
 26.8

 1.8
 2.3

 Wholesale/Other
 11.3
 7.2

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

 Natural Gas Energy Sales

 Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 8,917,149 and 6,130,048 Mcf, respectively, of natural gas to retail customers in 2023. In 2023, 99% of Entergy Louisiana's operating revenue was derived from the electric utility business and only 1% from the natural gas distribution business. For Entergy New Orleans, 87% of operating revenue was derived from the electric utility business and 13% from the natural gas distribution business in 2023.

 Following is data concerning Entergy New Orleans's 2023 retail operating revenue sources:

 Customer Class
 % of Electric Operating Revenue
 % of Natural Gas Operating Revenue

 Governmental/Municipal

 Retail Rate Regulation

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

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

 Rate base (in billions)
 Current authorized return on common equity
 Weighted-average cost of capital (after-tax)
 Equity ratio
 Regulatory construct

 $10.1 (a)
 9.15% - 10.15%
 5.62%
 38.7% (b)
 - forward test year formula rate plan
 - riders: fuel and purchased power, MISO, capacity, Grand Gulf, energy efficiency

 Entergy Louisiana (electric)
 $15.7 (c)
 9.0% - 10.0%
 6.66%
 49.51%
 - formula rate plan through 2022 test year
 - riders/specific recovery: MISO, capacity, transmission, fuel, distribution, tax reform

 Entergy Louisiana (gas)
 $0.15 (d)
 9.3% - 10.3%
 6.93%
 51.83%
 - gas rate stabilization plan
 - rider: gas infrastructure

 $4.2 (e)
 9.74% - 11.88%
 7.06%
 46.76%
 - formula rate plan with forward-looking features
 - riders: fuel, Grand Gulf, MISO, unit power cost, storm damage, ad valorem tax adjustment, vegetation, grid modernization, restructuring credit, power management

 Rate base (in billions)
 Current authorized return on common equity
 Weighted-average cost of capital (after-tax)
 Equity ratio
 Regulatory construct

 Entergy New Orleans (electric)
 $1.2 (f)
 8.85% - 9.85%

 6.86%
 51% (g)
 - formula rate plan with forward-looking features
 - riders/specific recovery: fuel and purchased power, MISO, energy efficiency, environmental, capacity costs

 Entergy New Orleans (gas)
 $0.2 (f)
 8.85% - 9.85%

 6.86%
 51% (g)
 - formula rate plan with forward-looking features
 - rider: purchased gas

 $4.4 (h)
 9.57%
 6.61%
 51.2%
 - rate case and cost recovery riders
 - riders: fuel, capacity, cost recovery riders (distribution, transmission, and generation), rate case expenses, advanced metering infrastructure surcharge, and tax reform, among others

 $1.74 (i)
 10.94% (j)
 8.54%

 59.5% (j)
 - monthly cost of service

 (a)Based on 2024 test year.
 (b)Based on $1.9 billion in accumulated deferred income taxes at a 0% cost rate included in the weighted-average cost of capital calculation.
 (c)Based on December 31, 2022 test year and excludes approximately $300 million of transmission plant investment included in the transmission recovery mechanism and approximately $200 million of distribution plant investment included in the distribution recovery mechanism, as well as approximately $400 million of net accumulated deferred tax liability items included in the tax reform adjustment mechanism.
 (d)Based on September 30, 2022 test year.
 (e)Based on 2023 forward test year.
 (f)Based on December 31, 2022 test year and known and measurables through December 31, 2023.
 (g)In October 2023 the City Council approved a three-year extension of Entergy New Orleans's formula rate plan, modified to reflect a 55% fixed capital structure for rate setting purposes.
 (h)Based on December 31, 2021 test year.
 (i)Based on calculation as of December 31, 2023.
 (j)Effective July 2022, Entergy Mississippi's bills from System Energy reflect an authorized return on equity of 9.65%, a capital structure not to exceed 52% equity, and a rate base reduction for the advance collection of sale-leaseback rental costs. See Note 2 to the financial statements for discussion of ongoing proceedings at the FERC challenging System Energy's authorized return on common equity and capital structure.

 Formula Rate Plan

 Between base rate cases, Entergy Arkansas is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize a forward test year. Entergy Arkansas is subject to a maximum rate change of 4% of the filing year total retail revenue. In addition, Entergy Arkansas is subject to a true-up of projection to actuals netted with future projection. In response to Entergy Arkansas's application for a general change in rates in

 2015, the APSC approved the formula rate plan tariff proposed by Entergy Arkansas including its use of a projected year test period and an initial five-year term. The initial five-year term expired in 2021. As granted by Arkansas law, Entergy Arkansas obtained APSC approval of the extension of the formula rate plan tariff for an additional five-year term, through 2026. As part of the settlement of the 2023 formula rate plan proceeding, Entergy Arkansas agreed to file its next base rate case no later than February 2026. If Entergy Arkansas's formula rate plan were terminated, Entergy Arkansas could file an application for a general change in rates that may include a request for continued regulation under a formula rate review mechanism.

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

 Production Cost Allocation Rider

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

 Other

 In June 2022 the APSC approved Entergy Arkansas's compliance tariff filing for a proposed green tariff designed to help participating customers meet their renewable and sustainability goals and to enhance economic development efforts in Arkansas. The APSC approved an initial offering of 100 MW of solar capacity to be made available under this tariff.

 In June 2023 the APSC approved Entergy Arkansas's Go ZERO tariff, which provides participating industrial and commercial customers the opportunity to chose from a number of clean energy options to help them achieve their sustainability goals.

 Formula Rate Plan

 Entergy Louisiana historically sets electric base rates annually through a formula rate plan using a historic test year. The form of the formula rate plan, on a combined basis, was approved in connection with the business combination of Entergy Louisiana and Entergy Gulf States Louisiana and largely followed the formula rate plans that were approved by the LPSC in connection with the full electric base rate cases filed by those companies in February 2013. In 2021 the LPSC approved a settlement extending the formula rate plan for test years 2020, 2021 and 2022; certain modifications were made in that extension, including a decrease to the allowed return on equity, narrowing of the earnings "dead band" around the mid-point allowed return on equity, elimination of sharing above and below the earnings "dead band," and the addition of a distribution cost recovery mechanism. The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC, certain transmission investments, and certain distribution investments, among other items. In August

 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 contains a dual-path request to update rates through either: (1) extension of Entergy Louisiana's current formula rate plan (with certain modifications) for three years, test years 2023-2025, which is Entergy Louisiana's recommended path; or (2) implementation of rates resulting from a cost-of-service study, with a 2024-2026 test year formula rate plan. The application complies 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. See Note 2 to the financial statements for a discussion of Entergy Louisiana's application.

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

 To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Louisiana historically hedged approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity was reviewed on an annual basis. In January 2018, Entergy Louisiana filed an application with the LPSC to suspend these seasonal hedging programs and implement financial hedges with terms up to five years for a portion of its natural gas exposure, which was approved in November 2018.

 Entergy Louisiana's gas rates include a purchased gas adjustment clause based on estimated gas costs for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.

 Retail Rates - Gas

 In accordance with the settlement of Entergy Gulf States Louisiana's gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015. In April 2022 Entergy Louisiana submitted for consideration a proposal to extend the infrastructure rider to address replacement of an additional 187 miles of pipe. In December 2022 Entergy Louisiana and the LPSC staff submitted an uncontested settlement that extends the rider for an additional ten years beginning after the end of the current term of the rider in 2025. The extension is subject to the same customer safeguards and conditions as the original term of the rider. The extension

 allows for recovery of approximately $95 million over ten years. In February 2023, the uncontested settlement was approved by the LPSC.

 Storm Cost Recovery

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

 Other

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

 In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020. To date, the LPSC staff has requested multiple rounds of comments from stakeholders and conducted one technical conference. Topics on which comments have been filed include full and limited retail access, demand response, sleeved power purchase agreements, and energy efficiency. Neither the LPSC or the LPSC staff have made recommendations or adopted any rules.

 Formula Rate Plan

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

 In August 2012 the MPSC opened inquiries to review whether the then-current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi's formula rate plan and Mississippi Power Company's annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant's report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the

 return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi's formula rate plan rider schedule and Mississippi Power Company's Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities' formula rate plans. The docket remains open.

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

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

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

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

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

 Storm Cost Recovery

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

 Other

 In October 2022 the MPSC adopted the Distributed Generation Rule. The Distributed Generation Rule maintains the 3% net metering participation cap. The Distributed Generation Rule grandfathers a 2.5 cents per kWh distributed generation benefits adder for 25 years and expands eligibility for the 2 cents per kWh low-income benefits adder to households up to 225% of the federal poverty level and grandfathers that adder for 25 years. The Distributed Generation Rule also directs utilities to make rate filings implementing up-front incentives for distributed generating systems and demand response battery systems, and to establish a public K-12 solar for schools program. In August 2023 the MPSC approved Entergy Mississippi's proposed solar for schools rate schedule under the Distributed Generation Rule.

 Formula Rate Plan

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

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

 Entergy New Orleans's gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.

 To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council's stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.

 Storm Cost Recovery

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

 Base Rates

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

 Entergy Texas's rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included in base rates. Historically, semi-annual revisions of the fixed fuel factor have been made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas's fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable and makes a prudence finding for each of the fuel-related contracts entered into during the reconciliation period. In 2023 the Texas legislature modified the Texas Utilities Code to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation by the end of 2024.

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

 Transmission, Distribution, and Generation Cost Recovery

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

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

 In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The distribution cost recovery factor permitted utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect distribution-related depreciation expense, federal income tax and other taxes, and return on investment. In 2023, the Texas Legislature modified the Texas Utilities Code to permit utilities to update their

 distribution cost recovery factors up to twice per year and to require the PUCT to issue an order on such update applications within 60 days, with a 15-day extension permitted for good cause.

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

 Storm Cost Recovery

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

 Other

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

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

 Electric Industry Restructuring

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

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

 revenues or embedded generation costs. The amount of customer load that may be included in the competitive generation service program is limited to 115 MW.

 Cost of Service

 The rates of System Energy are established by the FERC, and the costs allowed to be charged pursuant to these rates are, in turn, passed through to the participating Utility operating companies through the Unit Power Sales Agreement, which has monthly billings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit), 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. Beginning in 2021, System Energy implemented billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings, and an adverse outcome in any of them could have a material adverse effect on Entergy's or System Energy's results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings.

 Franchises

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

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

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

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

 Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas and holds non-exclusive franchises to provide electric

 service in approximately 70 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas's electric franchises expire over the period 2024-2058.

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

 Property and Other Generation Resources

 Owned Generating Stations

 The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2023 is indicated below:

 Owned and Leased Capability MW(a)

 Total
 CT / CCGT (b)
 Legacy Gas/Oil
 Coal
 Hydro
 Solar

 5,036
 1,548
 1,825

 10,798
 5,594
 2,728
 2,137
 —
 —

 2,904
 1,744
 —
 —

 —
 —
 —
 —

 3,234
 1,994
 —
 —
 —

 1,245
 —
 —
 1,245
 —
 —
 —

 Total
 23,879
 10,511
 5,884
 5,207
 1,975

 (a)"Owned and Leased Capability" is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
 (b)Represents Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.

 Summer peak load for the Utility has averaged 21,775 MW over the previous decade.

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

 The Utility operating companies' long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 7,963 MW of new long-term resources and the deactivation of about 4,241 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO's Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.

 Other Generation Resources

 RFP Procurements

 The Utility operating companies from time-to-time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as long-term requirements through a broad range of wholesale power

 products, including long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:

 • Entergy Texas's construction of the 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
 • In December 2020, Entergy Texas selected the self-build alternative, Orange County Advanced Power Station, out of the 2020 Entergy Texas combined-cycle, gas turbine RFP. Regulatory approval was received in November 2022 and construction has commenced. The facility is expected to be in service by mid-2026;
 • In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Searcy Solar facility, sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020, and closed on the acquisition, through use of a tax equity partnership, in December 2021. The Searcy Solar facility was placed in service in January 2022;
 • In November 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Sunflower Solar facility, sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the Sunflower Solar facility began commercial operation in September 2022;
 • In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Walnut Bend Solar facility, that will be sited on approximately 1,000 acres in Lee County, Arkansas. In July 2021 the APSC issued an order approving the acquisition of the Walnut Bend Solar facility. The counterparty notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination, and in February 2023 an amendment to the agreement was executed by the parties. In July 2023 the APSC issued an order approving the revisions to the agreement and full notice to proceed was issued shortly thereafter. In February 2024, Entergy Arkansas made an initial payment of approximately $169.7 million to acquire the facility. The project will achieve commercial operation once testing is completed and the project has achieved substantial completion. Entergy Arkansas currently expects the project to achieve commercial operation in the first half of 2024;
 • In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility, West Memphis Solar facility, that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In October 2021 the APSC issued an order approving the acquisition of the West Memphis Solar facility. In March 2022 the counterparty notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC. Following the APSC's approval of the supplemental application in March 2023, full notice to proceed was issued in April 2023 and the project is currently expected to achieve commercial operation by the end of 2024;
 • In November 2021, Entergy Louisiana signed an agreement for the purchase of an approximately 150 MW to-be-constructed solar photovoltaic energy facility, St. Jacques facility, that will be sited in St. James Parish near Vacherie, Louisiana. In September 2022 the LPSC voted to issue an order approving the St. Jacques facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish's land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparty for the St. Jacques facility regarding amendments to the agreement to address the impact of the St. James Parish ordinance, and the facility is expected to reach commercial operation no sooner than 2027 dependent upon agreement by the parties on the terms of the amendments;
 • In August 2022, Entergy Arkansas signed an agreement for the purchase of an approximately 250 MW to-be-constructed solar photovoltaic energy facility, Driver Solar facility, that will be sited near Osceola, Arkansas. Also in August 2022, Entergy Arkansas received necessary approvals for the Driver Solar

 facility, and Entergy Arkansas has issued the counterparty full notice to proceed to begin construction. The project is expected to achieve commercial operation as early as mid-2024; and
 • Entergy Louisiana expects to start construction on the 49 MW Sterlington Solar project in the fourth quarter 2024, located in Sterlington, Louisiana. The facility is expected to achieve commercial operation in January 2026.

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

 • River Bend's 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana's unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
 • Entergy Arkansas's wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas's coal and nuclear base load resources (which had not been included in Entergy Arkansas's retail rates);
 • In September 2012, Entergy Gulf States Louisiana and Rain CII Carbon LLC executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from a petroleum coke calcining facility in Sulphur, Louisiana. The facility began commercial operation in May 2013. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with the facility;
 • In March 2013, Entergy Gulf States Louisiana and Agrilectric Power Partners, LP executed a 20-year agreement for 8.5 MW from a refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with Agrilectric;
 • In September 2013, Entergy Louisiana and TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, executed a 10-year agreement to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas;
 • Entergy Mississippi's cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas's share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013;
 • In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC approved the project and deliveries pursuant to that agreement commenced in June 2018;
 • In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. In November 2019, LS Power sold and transferred the Carville Energy Center and facility to Argo Infrastructure Partners, which included the power purchase agreement;
 • In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;
 • In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a to-be-constructed solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
 • In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
 • In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and the PPA began in February 2023 after the facility reached commercial operation in March 2023;

 • In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a 5-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
 • In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and achieved commercial operation in November 2022;
 • In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in Polk County, Texas. The facility achieved commercial operation in November 2023;
 • In June 2021, Entergy Louisiana and Sunlight Road Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project and in September 2023, Entergy Louisiana reported to the LPSC that it had entered into amended agreements related to the Sunlight Road facility. The facility is expected to reach commercial operation in December 2024;
 • In June 2021, Entergy Louisiana and Vacherie Solar Energy Center, LLC executed a 20-year PPA for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. In September 2022 the LPSC voted to issue an order approving the Vacherie facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish's land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparty for the Vacherie facility regarding amendments to the agreement to address the impact of the St. James Parish ordinance, and the facility is expected to reach commercial operation no sooner than 2027 dependent upon agreement by the parties on the terms of the amendments;
 • In December 2022, Entergy Mississippi and Hinds Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Hinds County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in June 2026;
 • In October 2022, Entergy Mississippi and Wildwood Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Tallahatchie County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in May 2026;
 • In October 2022, Entergy Mississippi and Greer Solar, LLC executed a 20-year PPA for approximately 170 MW from a to-be-constructed solar photovoltaic energy facility located in Washington County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in December 2026;
 • In October 2022, Entergy Arkansas and Flat Fork Solar, LLC executed a 20-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in St. Francis County, Arkansas. In September 2023 the APSC approved the PPA, and the facility is expected to reach commercial operation in September 2025;
 • In October 2022, Entergy Arkansas and Forgeview Solar, LLC executed a 15-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in Mississippi County, Arkansas. In September 2023 the APSC approved the PPA, and the facility is expected to reach commercial operation in September 2025;
 • In January 2023, Entergy Texas and Piney Woods Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Walker County, Texas. The facility is expected to reach commercial operation as early as June 2026;
 • In January 2023, Entergy Louisiana and Coastal Prairie Solar, LLC executed a 20-year PPA for approximately 175 MW from a to-be-constructed solar photovoltaic energy facility located in Iberville Parish, Louisiana. Following execution of the agreement, Entergy Louisiana filed a petition with the LPSC

 requesting all necessary approvals. The facility is expected to reach commercial operation as early as December 2025; and
 • In October 2023, Entergy Louisiana and Mondu Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Point Coupee Parish, Louisiana. Following execution of the agreement, Entergy Louisiana filed a petition with the LPSC requesting all necessary approvals. The facility is expected to reach commercial operation as early as June 2026.

 In July 2021, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar generation resources. Entergy Texas selected a combination of PPA and owned resources in March 2022. One PPA was executed in January 2023 and the certificate of convenience and necessity for the owned resource is expected to be filed with the PUCT in mid-2024.

 In April 2022, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. Entergy Arkansas selected a combination of PPA and build own transfer resources in February 2023, and negotiation of definitive agreements for the resources are in progress.

 In June 2022, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic and wind resources. Entergy Louisiana selected a combination of PPA and build own transfer resources in March 2023 some of which have been executed and are noted above, and negotiation of definitive agreements for the remaining resources are in progress.

 In October 2022, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar photovoltaic and wind resources. Entergy Texas selected a combination of PPA and owned resources in July 2023, and negotiation of definitive agreements are in progress for all resources.

 In November 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. Entergy Mississippi selected a combination of owned resources in May 2023, and negotiation of definitive agreements are in progress for all resources.

 Other Procurements From Third Parties

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

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

 to the LPSC that it had entered into amended agreements related to the Elizabeth Solar facility. The facility is expected to reach commercial operation in August 2024.

 Power Through Programs

 In February 2019, Entergy Mississippi proposed a new technologies pilot to the MPSC, which was approved in December 2019. The pilot further modernized the energy grid and met customers' evolving expectations by offering utility-owned, natural gas-fired backup generators to customers. Following conclusion of the three-year pilot, in October 2023, Entergy Mississippi proposed full-scale implementation of commercial scale, natural gas-fired resilient distributed generation, to be installed in front of the meter at commercial and industrial customer premises. The full-scale offering was approved by the MPSC in December 2023 along with an associated rate schedule, the Resiliency as a Service Rider Schedule. Entergy Mississippi can dispatch the units at times of peak demand, which can mitigate the typically higher energy and capacity costs borne by all customers during times of peak energy usage.

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

 In August 2021, Entergy Arkansas filed with the APSC an application seeking authority for a "Power Through" offering to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Arkansas customers. In December 2021 the APSC general staff requested briefing, which Entergy Arkansas opposed. In January 2022, Entergy Arkansas filed to support the establishment of a procedural schedule with a hearing in April 2022. Also in January 2022, the APSC granted the general staff's request for briefing but on an expedited schedule; briefing concluded in February 2022. Based on testimony filed to date the APSC general staff, Arkansas Electric Energy Consumers, Sierra Club, and Audubon opposed Entergy Arkansas's proposed Power Through offering, which was demonstrated to be in high demand by interested customers, some of which directly filed public comments encouraging the APSC to approve the application. A

 paper hearing was held in August and September 2022, and Entergy Arkansas responded to several written commissioner questions. In May 2023 the APSC issued an order approving the Power Through offering with some modifications, and in June 2023, Entergy Arkansas sought rehearing or clarification of several issues. In August 2023 the APSC denied Entergy Arkansas's rehearing petition. In December 2023 the APSC approved a streamlined approval process for the individual Power Through generators. Entergy Arkansas is developing tariff revisions to comply with the APSC's order.

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

 Interconnections

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

 Gas Property

 As of December 31, 2023, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2023, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Louisiana's financial position.

 Title

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

 Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages

 securing bonds issued by those companies. The Lewis Creek generating station of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.

 Fuel Supply

 The average fuel cost per kWh for the Utility operating companies and System Energy for the years 2021-2023 were:

 Year
 Natural Gas
 Coal
 Renewables (a)
 Purchased Power
 MISO Purchases (b)

 2023
 (Cents Per kWh)

 1.98
 0.50
 3.09
 1.98
 11.57
 0.77

 2.34
 0.60
 3.22
 10.38
 3.76
 2.50

 2.21
 —
 2.82
 0.03
 5.86
 1.84

 Entergy New Orleans (c)
 2.05
 —
 —
 3.24
 —
 2.33

 2.29
 —
 3.17
 2.25
 5.64
 3.18

 —
 0.68
 —
 —
 —
 —

 2.25
 0.58
 3.06
 6.14
 4.03
 2.61

 2022

 4.98
 0.52
 2.93
 2.11
 10.90
 (2.65)

 5.50
 0.57
 2.84
 10.70
 6.95
 6.45

 4.38
 —
 2.85
 0.04
 6.53
 6.68

 Entergy New Orleans (c)
 5.10
 —
 —
 (5.16)
 —
 7.21

 5.77
 —
 2.83
 6.26
 5.61
 6.68

 —
 0.65
 —
 —
 —
 —

 5.27
 0.57
 2.89
 7.00
 6.54
 5.95

 2021

 4.11
 0.56
 2.43
 2.85
 2.53
 3.87

 3.77
 0.56
 2.62
 10.87
 5.52
 4.04

 2.71
 —
 2.53
 1.22
 2.70
 4.16

 Entergy New Orleans (c)
 3.47
 —
 —
 (2.82)
 —
 4.50

 4.65
 —
 2.60
 3.97
 4.53
 4.10

 —
 0.55
 —
 —
 —
 —

 3.75
 0.56
 2.48
 9.07
 4.76
 4.08

 (a)Includes average fuel costs from both owned and purchased power resources.
 (b)Includes activity from financial transmission rights. See Note 15 to the financial statements for discussion of financial transmission rights.
 (c)Entergy New Orleans's renewables include liquidated damage payments of $0.1 million in 2023, $2.9 million in 2022, and $1 million in 2021 due to the delay of in-service dates related to purchased power agreements.

 Actual 2023 and projected 2024 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:

 2023

 CT / CCGT (b)
 Legacy Gas
 Coal
 Renewables (c)
 Purchased Power (d)
 MISO Purchases (e)

 %
 %
 %
 %
 %
 —
 %
 %

 %
 %
 %
 %
 %
 %
 %

 %
 %
 %
 %
 %
 —
 %
 %

 %
 %
 %
 %
 %
 %
 %

 %
 %
 %
 %
 —
 %
 %
 %

 System Energy (a)
 —
 %
 —
 %
 %
 —
 %
 —
 %
 —
 %
 —
 %

 %
 %
 %
 %
 %
 %
 %

 2024

 CT / CCGT (b)
 Legacy Gas
 Coal
 Renewables (c)
 Purchased Power (d)
 MISO Purchases (e)

 %
 —
 %
 %
 %
 %
 —
 %
 —
 %

 %
 %
 %
 %
 %
 %
 —
 %

 %
 —
 %
 %
 %
 %
 —
 %
 —
 %

 %
 %
 %
 %
 %
 %
 —
 %

 %
 %
 %
 %
 %
 —
 %
 —
 %

 System Energy (a)
 —
 %
 —
 %
 %
 —
 %
 —
 %
 —
 %
 —
 %

 %
 %
 %
 %
 %
 %
 —
 %

 (a)Capacity and energy from System Energy's interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
 (b)Represents natural gas sourced for Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
 (c)Includes generation from both owned and purchased power resources.
 (d)Excludes MISO purchases and renewables purchased through purchased power agreements.
 (e)In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. The MISO purchases metric provided for 2023 is not projected for 2024.

 Some of the Utility's gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2024, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.

 Natural Gas

 The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Over 70% of the Utility operating companies' power plants maintain some level of long-term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements.

 Entergy Texas owns a gas storage facility and Entergy Louisiana has a firm storage service agreement that provide reliable and flexible natural gas service to certain generating stations.

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

 Coal

 Entergy Arkansas has committed to six two- to three-year contracts that will supply at least 85% of the total coal supply needs in 2024. These contracts are staggered in term so that not all contracts have to be renewed the same year. If needed, additional Powder River Basin (PRB) coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. Based on the high cost of alternate sources, modes of transportation, and infrastructure improvements necessary for its delivery, no alternative coal consumption is expected at Entergy Arkansas during 2024. Coal will be transported to Arkansas via an existing Union Pacific transportation agreement that is expected to provide all of Entergy Arkansas's rail transportation requirements for 2024.

 Entergy Louisiana has committed to three two- to three-year contracts that will supply at least 90% of Nelson Unit 6 coal needs in 2024. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as the Entergy Arkansas plants, no alternative coal consumption is expected at Nelson Unit 6 during 2024. Coal will be transported to Nelson via an existing transportation agreement that is expected to provide all of Entergy Louisiana's rail transportation requirements for 2024.

 Coal transportation delivery rates to Entergy Arkansas- and Entergy Louisiana-operated coal-fired units were able to fully meet supply needs and obligations in 2023. While deliveries remained constrained through summer 2023, improvements were observed in the second half of the year and are expected to continue in 2024. Both Entergy Arkansas and Entergy Louisiana control enough railcars to satisfy the rail transportation requirement.

 The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2024, but is also currently experiencing delivery constraints. Entergy Louisiana's and Entergy Texas's coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.

 Nuclear Fuel

 The nuclear fuel cycle consists of the following:

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

 The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy's Utility nuclear units. These companies own the materials and services in this shared regulated

 uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.

 Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through 2027. Entergy's ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners, including their ability to work through supply disruptions caused by global events, such as the COVID-19 pandemic, or national events, such as political disruption. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy's inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.

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

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

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

 Natural Gas Purchased for Resale

 Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a "no-notice" service gas purchase contract with Symmetry Energy Solutions which ensures Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The Symmetry Energy Solutions gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.

 Entergy Louisiana purchased natural gas for resale in 2023 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.

 As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana's or Entergy New Orleans's suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.

 Federal Regulation of the Utility

 State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy's sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.

 Transmission and MISO Markets

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

 MISO administers a process governed by the MISO tariff and subject to the FERC regulation that governs the interconnection of new generation resources to the transmission system under MISO's functional control. This process generally involves parties that wish to interconnect new generation resources submitting to MISO requests to do so, which are then studied and analyzed by MISO, with the participation of its member transmission owners, to determine if the interconnection of such generators requires new transmission facilities to ensure the continued reliable operations of the grid. Under MISO's current tariff, these requests are studied and considered in clusters, generally in the order in which they are received – a system of priority known as the MISO interconnection queue.

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

 In addition, orders from each of the Utility operating companies' respective retail regulators generally require that the Utility operating companies make periodic filings, or generally allow the retail regulator to direct the making of such filings, setting forth the results of analysis of the costs and benefits realized from MISO

 membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO.

 System Energy and Related Agreements

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

 Unit Power Sales Agreement

 The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy's ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy's only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.

 In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in retail rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas's cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas's retained share of Grand Gulf to those companies. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted cost recovery with respect to costs associated with Entergy Louisiana's share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC's approval. The remainder of Entergy Arkansas's retained share is sold to Entergy Mississippi through a separate life-of-resource purchase power agreement with Entergy Mississippi. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas's non-retained share of Grand Gulf. Entergy Mississippi was granted cost recovery for those purchases by the MPSC through its annual unit power cost rate mechanism.

 Availability Agreement

 The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the original financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy

 Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy's share of Grand Gulf.

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

 The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of operating expense funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.

 System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for all of its outstanding series of first mortgage bonds, as well as for its outstanding term loan and the pollution control revenue refunding bonds issued on its behalf. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.

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

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

 Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, no payments under the Availability Agreement to System Energy have ever been required. However, if Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or certain of its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their allocated shares under the Availability Agreement exceed their allocated shares under the Unit Power Sales Agreement. See Note 8 to the financial statements for discussion of the Reallocation Agreement among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, pursuant to which Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans

 assumed all of Entergy Arkansas's responsibilities and obligations with respect to Grand Gulf under the Availability Agreement.

 The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.

 Service Companies

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

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

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

 Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend's nuclear and environmental liabilities that is identical to the share of the plant's output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.

 Entergy Louisiana and Entergy Gulf States Louisiana Business Combination

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

 completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana.

 Entergy Arkansas Internal Restructuring

 In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:

 • Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
 • Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
 • Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
 • Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

 In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.

 Entergy Mississippi Internal Restructuring

 In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:

 • Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
 • Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
 • Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
 • Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

 In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.

 Other Business Activities

 Entergy's non-utility operations business includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. Entergy's non-utility operations

 business also provides decommissioning-related services to nuclear power plants owned by non-affiliated entities in the United States.

 Property

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

 Plant
 Location
 Ownership
 Net Owned Capacity (a)
 Type

 Independence Unit 2; 842 MW
 Newark, AR
 14%
 121 MW(b)
 Coal

 Nelson Unit 6; 550 MW
 Westlake, LA
 11%
 60 MW(b)
 Coal

 (a)"Net Owned Capacity" refers to the nameplate rating on the generating unit.
 (b)The owned MW capacity is the portion of the plant capacity owned by Entergy's non-utility operations business. For a complete listing of Entergy's jointly-owned generating stations, refer to "Jointly-Owned Generating Stations" in Note 1 to the financial statements.

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

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

 Regulation of Entergy's Business

 Federal Power Act

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

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

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

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

 State Regulation

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

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

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

 Entergy Louisiana's electric and gas business is subject to regulation by the LPSC as to the following:

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

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

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

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

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

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

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

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

 Regulation of the Nuclear Power Industry

 Atomic Energy Act of 1954 and Energy Reorganization Act of 1974

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

 Nuclear Waste Policy Act of 1982

 Spent Nuclear Fuel

 Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy's nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2023 of $205.2 million for the one-time fee. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy's total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.7 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).

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

 Following the defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit Court of Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear

 Waste Policy Act or Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014.

 As a result of the DOE's failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy's nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE's delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2021, 2022, and 2023 related to Entergy's nuclear owner/licensee subsidiaries' litigation with the DOE. Through 2023, Entergy's subsidiaries have won and collected on judgments against the government totaling approximately $1 billion.

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

 Nuclear Plant Decommissioning

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

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

 In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking to adjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). Because of the ongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice. In July 2021, Entergy Louisiana made a filing with the LPSC to adjust Waterford

 3 and River Bend decommissioning collections based on the latest site-specific decommissioning cost estimates for those plants. The filing seeks to increase Waterford 3 decommissioning collections and decrease River Bend decommissioning collections. The procedural schedule in the case has been suspended pending settlement negotiations. In August 2023, Entergy Louisiana made another filing with the LPSC requesting to maintain the same total decommissioning funding collections as currently in effect for both Waterford 3 and River Bend combined, but also requesting to reallocate that same amount of funding by increasing the contributions for Waterford 3 and reducing the contributions for River Bend. In October 2023 a procedural schedule was adopted that includes a hearing date in August 2024. Management cannot predict the outcome of these proceedings.

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

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

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

 Plant owners are required to provide the NRC with a biennial report (annually for units that have shut down or will shut down within five years), based on values as of December 31, addressing the owners' ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, plant owners may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. In March 2023 filings with the NRC were made reporting on decommissioning funding for all of Entergy's subsidiaries' nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC's financial assurance requirements.

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

 Price-Anderson Act

 The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $165.9 million per reactor (with 95 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, or System Energy is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to

 nuclear generating units is also purchased. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.

 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, except River Bend, which is in Column 2.

 In July 2023 the NRC placed River Bend in Column 2, effective April 2023, based on failure to inspect wiring associated with the high pressure core spray system. In August 2023 the NRC issued a finding and notice of violation related to a radiation monitor calibration issue at River Bend. In December 2023, River Bend successfully completed the inspection on the high pressure core spray system issue and in February 2024, River Bend successfully completed the supplemental inspection for the radiation monitor calibration issue involving radiation monitor calibrations. River Bend will remain in Column 2 pending receipt of the formal report on the inspection, which is expected in first quarter 2024.

 Environmental Regulation

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

 Clean Air Act and Subsequent Amendments

 The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy's fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:

 • new source review and preconstruction permits for new sources of criteria air pollutants, greenhouse gases, and significant modifications to existing facilities;
 • acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx);
 • nonattainment area programs for control of criteria air pollutants, which could include fee assessments for air pollutant emission sources under Section 185 of the Clean Air Act if attainment is not reached in a timely manner;
 • hazardous air pollutant emissions reduction programs;

 • Interstate Air Transport;
 • operating permit programs and enforcement of these and other Clean Air Act programs;
 • Regional Haze programs; and
 • new and existing source standards for greenhouse gas and other air emissions.

 National Ambient Air Quality Standards

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

 Ozone Nonattainment

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

 Potential SO2 Nonattainment

 The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy's utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020, as monitors were installed to determine compliance. In March 2021 the EPA published a final rule designating East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. No challenges to these final designations were filed within the 60 day deadline. Entergy continues to monitor this situation.

 Hazardous Air Pollutants

 The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not "appropriate and necessary" to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA's previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. In February 2021 the D.C. Circuit granted the EPA's motion to hold the litigation in abeyance pending the agency's review of the appropriate and necessary rule. In February 2022 the EPA issued a proposed rule revoking the 2020 rule and determining, again, that it is "appropriate and necessary" to regulate hazardous air pollutants. In April 2023 the EPA issued a regulatory proposal to revise portions of the MATS rule, including a proposed reduction to the emission limit for filterable particulate matter. If finalized, the proposed lower filterable particulate matter emission limitation could require additional capital investment and/or additional other operation and maintenance costs at Entergy's coal-fired generating units. Entergy is closely monitoring this rulemaking, in part through its various trade associations.

 Good Neighbor Plan/Cross-State Air Pollution Rule

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

 In June 2023 the EPA published its final Federal Implementation Plan (FIP), known as the Good Neighbor Plan, to address interstate transport for the 2015 ozone NAAQS which would increase the stringency of the CSAPR program in all four of the states where the Utility operating companies operate. The FIP would significantly reduce ozone season NOx emission allowance budgets and allocations for electric generating units. Entergy is currently assessing its compliance options for the FIP. Prior to issuance of the FIP, in February 2023 the EPA issued related State Implementation Plan (SIP) disapprovals for many states, including the four states in which the Utility operating companies operate, and these SIP disapprovals are the subject of many legal challenges, including a petition for review filed by Entergy Louisiana challenging the disapproval of Louisiana's SIP. Stays of the SIP disapprovals have been granted in all four states in which the Utility operating companies operate, and the Good Neighbor Plan will not go into effect while the stays are in place. Decisions on the merits regarding the respective SIP disapprovals are expected in 2024. The final FIP also is subject to numerous legal challenges.

 Regional Haze

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

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

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

 The Texas Commission on Environmental Quality has completed its second-planning period SIP and submitted it to the EPA for review. There were no Entergy sources selected for additional emission controls. The

 Mississippi Department of Environmental Quality also did not meet the July 31, 2021 SIP submission deadline and continues to develop its SIP, but there are no Entergy sources that are expected to be impacted.

 In August 2022 the EPA issued findings of failure to submit regional haze SIPs to 15 states, including Louisiana and Mississippi. These findings were effective September 2022 and start the two-year period for the EPA to either approve a SIP submitted by the state or issue a final federal plan.

 Greenhouse Gas Emissions

 In April 2021, President Biden announced a target for the United States in connection with the United Nations' "Paris Agreement" on climate change. The target consists of a 50-52 percent reduction in economy-wide net greenhouse gas emissions from 2005 levels by 2030. President Biden has also stated that a goal of his administration is for the electric power industry to decarbonize fully by 2035.

 Consistent with the Biden administration's stated climate goals, in May 2023 the EPA proposed several rules regulating greenhouse gas emissions from new and existing coal and gas-fired power plants. If finalized, the proposed requirements for existing "large and frequently used" gas turbine generating units could require significant investments in CO2 emission reduction technologies at certain of Entergy's existing gas turbine units with a capacity of greater than 300 MW per combustion turbine and which operate at an annual capacity factor of greater than 50 percent. Comments on the proposed rules were submitted in August 2023 and Entergy is monitoring the rulemaking, in part through its trade associations.

 Entergy continues to support national legislation that would most efficiently reduce economy-wide greenhouse gas emissions and increase planning certainty for electric utilities. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission "intensity," or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020, which it ultimately outperformed by approximately 8% both cumulatively and on an annual basis. In 2019, in connection with a climate scenario analysis following the recommendations of the Task Force on Climate-related Financial Disclosures describing climate-related governance, strategy, risk management, and metrics and targets, Entergy announced a 2030 carbon dioxide emission rate goal focused on a 50% reduction from Entergy's base year - 2000. In September 2020, Entergy announced a commitment to achieve net-zero greenhouse gas emissions by 2050 inclusive of all businesses, all applicable gases, and all emission scopes. In 2022, Entergy enhanced its commitment to include an interim goal of 50% carbon-free energy generating capacity by 2030 and expanded its interim emission rate goal to include all purchased power. See "Risk Factors" in Part I, Item 1A for discussion of the risks associated with achieving these climate goals. Entergy's comprehensive, third party verified greenhouse gas inventory and progress against its voluntary goals are published on its website.

 Potential Legislative, Regulatory, and Judicial Developments

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

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

 Clean Water Act

 The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System permit program, section 402, and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 of the Clean Water Act regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.

 Federal Jurisdiction of Waters of the United States

 In June 2020 the EPA's revised definition of waters of the United States in the Navigable Waters Protection Rule (NWPR) became effective, narrowing the scope of Clean Water Act jurisdiction, as compared to a 2015

 definition which had been stayed by several federal courts. In August 2021 a federal district court vacated and remanded the NWPR for further consideration. The EPA and the U.S. Army Corps of Engineers (Corps) subsequently issued a statement that the agencies would revert to pre-2015 regulations pending a new rulemaking. In December 2022 the EPA and the Corps released a final definition of waters of the United States (the 2022 Rule) that replaces the NWPR with a definition that is consistent with the pre-2015 regulatory regime as interpreted by several United States Supreme Court decisions. The 2022 Rule was subject to multiple legal challenges and was enjoined from implementation or enforcement throughout Entergy's utility service territory. In May 2023 the U.S. Supreme Court issued a decision limiting the scope of federal jurisdiction over wetlands, and in September 2023 the EPA and the Corps issued a final rule incorporating the Supreme Court decision. Most notably, the exclusion for waste treatment systems is retained.

 Comprehensive Environmental Response, Compensation, and Liability Act of 1980

 The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries have sent waste materials to various disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been sold to decommissioning companies. In addition, environmental laws now regulate certain of Entergy's operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the "Other Environmental Matters" section below.

 Coal Combustion Residuals

 In April 2015 the EPA published the final coal combustion residuals (CCR) rule regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes regulated under Resource Conservation and Recovery Act Subtitle D. The final regulations created new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria but excluded CCRs that are beneficially reused in certain processes. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed. As of December 31, 2023, Entergy has recorded asset retirement obligations related to CCR management of $28 million.

 Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site commenced closure of its two recycle ponds (four ponds total) prior to the April 11, 2021 deadline under the finalized CCR rule for unlined recycle ponds. Any potential requirements for corrective action or operational changes under the new CCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA's continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA's review.

 Additionally, all three sites are preparing to implement measures to meet the new and updated Effluent Limitation Guidelines (ELG). The nature, cost, and timing of those compliance measures depends on the guidance included in the final ELG rule, which is expected by mid-2024.

 In May 2023 the EPA released a proposed rule establishing management standards for legacy CCR surface impoundments (i.e., inactive surface impoundments at inactive power plants) and establishing a new class of units referred to as CCR management units (i.e., non-containerized CCR located at a regulated CCR facility). Entergy does not have any legacy impoundments; however, the proposed definition of CCR management units appears to regulate on-site areas where CCR was beneficially used. This is contrary to the current CCR rule which exempts beneficial uses that meet certain criteria. Comments on the proposed rule were submitted in July 2023 and Entergy is monitoring the rulemaking, in part through its trade associations.

 Other Environmental Matters

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

 The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils, and in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA's information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand letter seeking reimbursement for response costs totaling $4 million expended at the site. Liability and PRP allocation of response costs are yet to be determined. In December 2020, Entergy responded to the demand letter, without admitting liability or waiving any rights, indicating that it would engage in good faith negotiations with the EPA with respect to the demand. An initial meeting between the EPA and the PRPs took place in June 2021. Negotiations between the PRPs and the EPA are ongoing.

 Litigation

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

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

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

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

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

 Human Capital

 Employees

 Employees are an integral part of Entergy's commitment to serving customers. As of December 31, 2023, Entergy subsidiaries employed 12,177 people.

 Utility:

 1,302

 1,639

 —

 Entergy Operations
 3,349

 Entergy Services
 4,117

 Entergy Nuclear Operations

 Other subsidiaries

 Total Entergy
 12,177

 There are 3,104 employees represented by the International Brotherhood of Electrical Workers, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.

 Below is the breakdown of Entergy's employees by gender and race/ethnicity:

 Gender (%) (a)
 2023
 2022

 Female
 23.0
 22.2

 Male
 77.0
 77.8

 Race/Ethnicity (%) (a)
 2023
 2022

 White
 73.1
 74.8

 Black/African American
 18.2
 17.3

 Hispanic/Latino
 3.2
 3.0

 Asian
 3.2
 2.3

 Other
 2.3
 2.6

 (a)Based on employees who self-identify.

 Entergy's Approach to Human Resources

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

 Governance and Oversight

 Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Talent and Compensation Committee establishes priorities and each quarter reviews strategies and results on a range of topics covering diversity, culture, and commerce. It oversees Entergy's incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy's corporate objectives. Annually, it reviews executive performance, development, succession plans, and talent pipeline to align a high performing executive team with Entergy's priorities. The Talent and Compensation Committee also oversees Entergy's performance through regular briefings on a wide variety of human resources topics including Entergy's safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.

 The Talent and Compensation Committee is responsible for overseeing and monitoring the effectiveness of Entergy's human capital strategies, including its workforce diversity, inclusion, and organizational health and safety strategies, programs, and initiatives. In recognition of the importance that organizational health and diversity, inclusion, and belonging play in enabling Entergy to achieve its business strategies, the committee receives periodic reports on Entergy's organization health and diversity, inclusion, and belonging programs, strategies, and performance, including briefings at each of its regular meetings. The committee also receives updates on Entergy's performance to date on key diversity, culture, and commerce measures, including the representation of women and underrepresented minorities, both in the total workforce and in director level and above placements, progress in key diversity, inclusion, and belonging initiatives and diverse supplier spend.

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

 The Office of the Chief Executive, which includes the Senior Vice President and Chief Human Resources Officer, ensures annual business plans are designed to support Entergy's talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.

 Safety

 Entergy's safety objective is: Everyone Safe. All Day. Every Day. Entergy employees achieved a total recordable incident rate of 0.49 in 2023 as compared to 0.51 in 2022 and 0.46 in 2021. The results of 2021 unfortunately included an employee fatality. Entergy has enhanced dramatically leadership efforts and field presence to further its objective of zero fatalities, which it achieved in 2022 and 2023, although in early 2024 Entergy experienced a contractor fatality. Also in 2023, there was a significant decrease in the number of serious injuries. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions.

 Organizational Health, including Diversity, Inclusion and Belonging (DIB)

 Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2021 of 63 (third quartile), in 2022 of 61 (third quartile), and in 2023 of 62 (third quartile). Although the score is nearly the same in 2023 as in 2022, Entergy has maintained improvement from the 2014 baseline. Improvement in behavioral expectations, which are the leading indicators of outcome improvements, indicates that Entergy is moving in a positive direction.

 Entergy believes that creating a culture of diversity, inclusion, and belonging drives foundational engagement for all employees. Entergy is committed to developing and retaining a top-performing workforce that reflects the rich diversity of the communities it serves. In 2021, Entergy established a new Diversity and Workforce Strategies organization to serve as a center of excellence for workforce development, talent attraction/pipeline development, and organizational health and diversity. The organization supports Entergy's actions to strengthen our partnerships with colleges and vocational-technical schools for a more viable pipeline of future talent while expanding efforts to increase employee engagement and cultivate an inclusive culture with high performance. Entergy continues to focus its actions to engage a diverse workforce, infusing DIB into hiring policies, practices, and procedures, aligning Employee Resource Group goals to business objectives, growing its DIB Champion network, ensuring that Entergy's leadership development programs support all employees, and facilitating training from the executive leadership ranks down to the frontline. Through these efforts, Entergy aspires to create greater understanding and accountability regarding the behaviors and outcomes that are indicative of a premier utility.

 Talent Management

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

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

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

 Item 1A. Risk Factors

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

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

 Utility Regulatory Risks

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

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

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

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

 The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including, but not limited to, the operation and maintenance of their assets and infrastructure, including with respect to climate or environmental matters, their preparedness for major storms or other extreme weather events and/or the time it takes to restore service after such

 events, the quality of their customer service, including timely and accurate billing practices and ability to resolve customer complaints, and the reasonableness of the cost of their service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements or other legislation or regulatory actions that adversely affect the Utility operating companies.

 The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms, all of which could face resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation or high fuel prices or otherwise, and/or in periods of economic decline or hardship. Significant increases in costs could increase financing needs and otherwise adversely affect Entergy, the Utility operating companies, and System Energy's business, financial position, results of operation, or cash flows. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.

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

 If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies' exclusive rights to serve their regulated customers, such as through "retail open access" or otherwise, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and, together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales, due to the methodology used to determine cost of service rates or otherwise, could put upward pressure on rates, possibly resulting in adverse regulatory actions to mitigate such effects on rates. Further, the failure of regulatory structures to evolve to accommodate the changing needs and desires of customers with respect to the sourcing and use of electricity also could diminish sales by the operating companies. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.

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

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

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

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

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

 The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies' transmission assets that are under MISO's functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own, which could increase cash or financing needs. Further, FERC policies and regulation addressing cost responsibility for transmission projects, including transmission projects to interconnect new generation facilities, may potentially give rise to cash and financing-related risks as well as result in upward pressure on the retail rates of the Utility operating companies, which, in turn, may result in adverse actions by the Utility operating companies' retail regulators. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from transmission projects of others or changes in FERC policies or regulation related to cost responsibility for transmission projects, there is a risk that the Utility operating companies' business and financial position could be harmed as a result of lost investment opportunities and other effects that flow from an increased number of competitive projects being approved and constructed that are interconnected with their transmission systems.

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

 The MISO tariff provisions governing the rights and obligations associated with the resource adequacy construct provided under the MISO tariff are subject to change and have recently undergone significant changes, some of which are the subject of pending litigation and/or appeals. As an example, MISO recently has made

 changes to its capacity accreditation methodology for thermal resources which emphasizes performance during a very small subset of hours in which the supply of generation capacity needed to serve load is tightest. MISO is now embarking on a larger scale reassessment of its overall accreditation practices, including accreditation of renewable resources. Due to their magnitude and, with respect to the changes already made, the speed with which they have been implemented, these changes carry risk, including compliance risk, and may result in material additional costs being passed through to the Utility operating companies' customers in retail rates, including but not limited to additional capacity costs incurred in the annual MISO Planning Resource Auction. Also, by virtue of the Utility operating companies' participation in MISO and the design and terms of the MISO resource adequacy construct, other load-serving entities served by the Utility operating companies' transmission assets, which are under MISO's functional control, may be able to circumvent reasonable resource planning obligations and avoid, in whole or in part, the full cost of procuring the resources reasonably needed to reliably supply their respective loads. In particular, the design of the current MISO resource adequacy construct and the absence of a minimum capacity obligation in MISO create a risk of other load-serving entities engaging in "free ridership" through their strategy for participation in the MISO resource adequacy construct and energy and ancillary services markets – specifically, by using energy and ancillary services available from the Utility operating companies' owned and controlled generating units without paying a reasonable share of the cost of the capacity required to provide such energy and ancillary services. As a result, there are a variety of risks to the Utility operating companies and their customers, including the risk of bearing additional costs for resources needed to ensure reliable service, the risk of reduced reliability and the enhanced risk of outages and lost sales which, because of the methodology for establishing cost of service rates, presents the risk of upward pressure on the Utility operating companies' rates.

 In addition, a large volume of parties and individual generation resources are presently seeking to interconnect to the transmission system MISO administers and over which MISO exercises functional control. Due to the resources and time required to study and evaluate these numerous interconnection requests, including the effects of speculative requests and requests that are withdrawn at late stages of the process, the current MISO interconnection queue to review new requests is subject to significant delays or periods in which MISO does not accept new interconnection requests. These delays present risks to the Utility operating companies and their ability to develop and procure new generation resources to serve their respective loads.

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

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

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

 • supply chain, vendor, and contractor disruptions, including shortages or delays in the availability of key components, parts, and supplies such as electronic components and solar panels;
 • delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed refueling and maintenance outages;
 • adverse impacts on liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense;
 • delays in regulatory proceedings;
 • regulatory outcomes that require the Utility operating companies to postpone planned investments and otherwise reduce costs due to, for example, the impact of a public health crises or such other catastrophic events on their customers;

 • workforce availability challenges, including, for example, from infections, health, or safety issues resulting from a public health crisis;
 • increased storm recovery costs;
 • increased cybersecurity risks as a result of many employees telecommuting;
 • volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities on favorable terms), which could in turn, cause a decrease in the value of its defined benefit pension or decommissioning trust funds;
 • adverse impacts on Entergy's credit metrics or ratings;
 • governmental mandates in response to any such event; or
 • other adverse impacts on their ability to execute on business strategies and initiatives.

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

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

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

 Entergy's and its Utility operating companies' results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred, inability to securitize future storm restoration costs, or loss of revenues as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather, including lower credit ratings and, thus, higher costs for future debt issuances. The inability to recover losses either excluded by insurance or in excess of the insurance limits that can be secured economically also could have a material effect on Entergy and its Utility operating companies. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills, especially in a rising cost environment.

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

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

 Entergy's electricity sales volumes are affected by a number of factors including weather and economic conditions, trends in energy efficiency, new technologies, and self-generation alternatives, including the willingness

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

 The Utility operating companies also may face competition from other companies offering products and services to Entergy's customers. Electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy's and the Utility operating companies' results of operations, financial condition, and liquidity. The Utility operating companies also may not realize anticipated or expected growth in industrial sales, such as from electrification opportunities to help such customers achieve their environmental and sustainability goals. This could occur because of changes in customers' goals or business priorities, competition from other companies, or decisions by such customers to seek to achieve such goals through methods not offered by Entergy.

 Nuclear Operating, Shutdown, and Regulatory Risks

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

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

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

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

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

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

 Based upon currently planned fuel cycles, Entergy's nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through the end of 2027. Entergy's ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements, supply chain disruptions, limitations or bans on importation of uranium or uranium products from foreign countries, evolving geopolitical conditions such as the wars between Russia and Ukraine and Israel and Hamas, the Nigerien coup, or shifting trade arrangements or sanctions between countries. Although Entergy's nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to inherent market uncertainties, as well as uncertainties arising from geopolitical conflicts, and price changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.

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

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

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

 change in classification. For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, and System Energy, see "Regulation of Entergy's Business - Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process" in Part I, Item 1.

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

 Certain of the Utility operating companies and System Energy are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy's and their results of operations, financial condition, and liquidity.

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

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

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

 Certain of the Utility operating companies and System Energy incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of the Yucca Mountain repository and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are prolonging the time before spent fuel is removed from Entergy's plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and is in partial breach of its spent fuel disposal contracts, and Entergy has sued the DOE for such breach. Furthermore, Entergy is uncertain as to when the DOE will commence acceptance of

 spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies' nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the "Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal" section of Management's Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.

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

 Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. As required by the Price-Anderson Act, the Utility operating companies and System Energy carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which as of January 1, 2024 is $500 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. The Price-Anderson Act limits each reactor owner's public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool, which is referred to as Secondary Financial Protection, up to approximately $165.9 million per reactor. With 95 reactors currently participating, this translates to a total public liability cap of approximately $15.8 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy's Utility operating companies and System Energy, regardless of fault or proximity to the incident, will be required to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary insurance level, up to a maximum of approximately $165.9 million per reactor per incident (Entergy's maximum total contingent obligation per incident is approximately $830 million). The retrospective premium payment is currently limited to approximately $25 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $165.9 million cap.

 NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies and System Energy. NEIL provides onsite property and decontamination coverage. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the NEIL surplus (reserve) be significantly depleted due to insured losses. As of April 1, 2023, the maximum annual assessment amounts total approximately $70 million for the Utility plants.

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

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

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

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

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

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

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

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

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

 Business Risks

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

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

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

 The inability to raise capital on favorable terms, particularly during times of high interest rates and inflation, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries' ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital being unwilling to invest in offerings to fund fossil fuel projects or companies that are impacted by extreme weather events, that rely on fossil fuels, or that are impacted by risks related to climate change. Factors beyond Entergy's control may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. These factors include depressed economic conditions, a recession, increasing interest rates, inflation, sanctions, trade restrictions, political instability, war, terrorism, and extreme volatility in the debt, equity, or credit markets. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay

 raising capital, issue shorter-term securities, and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility, and/or limit Entergy Corporation's ability to sustain its current common stock dividend level.

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

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

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

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

 As with any company, Entergy's and its Registrant Subsidiaries' reputations are an important element of their ability to effectively conduct their businesses. Entergy's and its Registrant Subsidiaries' reputations could be harmed by a variety of factors, including: failure of a generating asset or supporting infrastructure; failure to restore power after a hurricane or other severe weather event in a manner perceived as timely by regulators or customers; the incurrence of storm restoration costs perceived as excessive by regulators or customers; failure to effectively manage land and other natural resources; real or perceived violations of environmental regulations, including those related to climate change; real or perceived issues with Entergy's safety culture or work environment; inability to meet their climate or human capital strategy goals, or failure to demonstrate meaningful progress toward such goals; inability to keep their electricity rates stable; inability to provide quality customer service, including timely and accurate billing; involvement in a class-action or other high-profile lawsuit; significant delays in construction projects; occurrence of or responses to cyber attacks, data breaches or physical- or cyber- security vulnerabilities; acts or omissions of Entergy management or acts or omissions of a contractor or other third party working with or for Entergy or its Registrant Subsidiaries, which actually or perceivably reflect negatively on Entergy or its Registrant Subsidiaries; measures taken to offset reductions in demand or to supply rising demand; a significant dispute with one of Entergy's or its Registrant Subsidiaries' customers or other stakeholders; or negative political and public sentiment resulting in a significant amount of adverse press coverage and other adverse statements affecting Entergy or its Registrant Subsidiaries.

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

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

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

 The Tax Cuts and Jobs Act of 2017 significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The Inflation Reduction Act of 2022 further significantly changed the U.S. Internal Revenue Code by, among other things, enacting a new corporate alternative minimum tax and expanding federal tax credits for clean energy production. The interpretive guidance issued by the IRS and state tax authorities may be inconsistent with Entergy's own interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation. Further, changes in tax legislation or guidance, or uncertainties regarding interpretation of such tax legislation or guidance, could impact interpretation of and negotiations around certain contractual arrangements with counterparties, which could result in unfavorable changes to such arrangements or delays. In addition, the retail regulatory treatment of the expanded tax credits and corporate alternative minimum tax included in the Inflation Reduction Act of 2022 could materially impact Entergy's future cash flows, and this legislation and pending interpretive guidance could result in unintended consequences not yet identified that could have a material adverse impact on Entergy's financial results and future cash flows.

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

 The tax rate decrease included in the Tax Cuts and Jobs Act required Entergy to record a regulatory liability for income taxes payable to customers. Such regulatory liability for income taxes is described in Note 3 to the financial statements. Depending on the outcome of IRS examinations or tax positions and elections that Entergy may make, Entergy and the Registrant Subsidiaries may be required to record additional charges or credits to income tax expense.

 See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act on 2023, 2022, and 2021 results of operations and financial condition, the provisions of the Tax Cuts and Jobs Act, and the uncertainties associated with accounting for the Tax Cuts and Jobs Act, and Note 2 to the financial statements for discussion of the regulatory proceedings that have considered the effects of the Tax Cuts and Jobs Act. For further discussion of the effects of the Inflation Reduction Act of 2022, see the "Income Tax Legislation and Regulation" section of Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis and Note 3 to the financial statements.

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

 Entergy and its subsidiaries make judgments regarding the potential tax effects of various transactions and results of operations to estimate their obligations to taxing authorities, which judgment may prove to be incorrect or may be disputed by regulators or taxing authorities. These tax obligations include income, franchise, real estate, sales and use, and employment-related taxes. These judgments include provisions for potential adverse outcomes

 regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws or interpretive guidance relating thereto, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy's and the Registrant Subsidiaries' results of operations, financial condition, and liquidity. The intended and unintended consequences of recently enacted legislation could have a material adverse impact on Entergy's financial results and future cash flows. For further information regarding Entergy's income taxes, see the "Income Tax Legislation and Regulation" section of Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis and Note 3 to the financial statements.

 Entergy and its subsidiaries' ability to successfully execute on their business strategies, including their ability to complete strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies, which could materially affect their future prospects, results of operations, and the realization of any anticipated benefits from such transactions.

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

 Additionally, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring, or other strategic transactions. For example, each of Entergy Louisiana and Entergy New Orleans have entered into purchase and sale agreements to sell their respective regulated natural gas local distribution company businesses to a third-party. Also, a significant portion of Entergy's utility business plan over the next several years includes the construction and/or purchase of a variety of solar facilities. These or other transactions and plans are or may become subject to regulatory approval and other material conditions or contingencies, including increased costs or delays resulting from supply chain disruptions, import tariffs, and other issues. The failure to complete these transactions or plans or any future strategic transaction successfully or on a timely basis could have an adverse effect on Entergy's or its subsidiaries' financial condition or results of operations and the market's perception of Entergy's ability to execute its strategy. Further, these transactions, and any completed or future strategic transactions, involve substantial risks, including the following:

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

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

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

 Entergy's and the Utility operating companies' ability to complete capital projects, including the construction of power generation facilities, or make other capital improvements, such as transmission and distribution infrastructure replacements or upgrades, in a timely and cost-effective manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, escalating costs for materials, labor, and environmental compliance, reliance on suppliers for timely and satisfactory performance, delays and cost increases, and supply chains and material constraints, including those that may result from major storm events, both within and outside of Entergy's service area. Delays in obtaining permits, challenges in securing sufficient land for the siting of solar panels and power generation facilities, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, further direct and indirect trade and tariff issues, including those associated with imported solar panels, supply chain delays or disruptions, and other events beyond the control of the Utility operating companies may occur that may materially affect the schedule, cost, and performance of these projects. If these projects or other capital improvements are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments or face increased risk of potential write-off of the investment in the project. In addition, the Utility operating companies could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.

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

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

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

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

 The businesses in which Entergy's subsidiaries, including the Utility operating companies and System Energy, operate are subject to extensive environmental regulation by local, state, and federal authorities. These laws and regulations affect the manner in which the Utility operating companies and System Energy conduct their operations and make capital expenditures. These laws and regulations also affect how Entergy's subsidiaries, including the Utility operating companies and System Energy, manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, certain migratory birds and eagles, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies and System Energy to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties' claims for alleged health or property damages or for violations of applicable permits or standards. In addition, Entergy and its subsidiaries, including the Utility operating companies and System Energy, are subject to potential liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies and System Energy and of property potentially contaminated by hazardous substances they generate. The Utility operating companies currently are involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. Entergy's subsidiaries, including the Utility operating companies and System Energy, have incurred and expect to incur significant costs related to environmental compliance.

 Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated emissions from generating plants potentially are subject to increased regulation, controls, and mitigation expenses. In addition, existing environmental regulations and programs promulgated by the EPA often are challenged legally, or are revised or withdrawn by the EPA, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to regulate, or otherwise compel reductions of greenhouse gas emissions, and water availability issues are discussed below.

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

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

 In an effort to address climate change concerns, some federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, the EPA, various environmental interest groups, and other organizations have focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. The EPA has promulgated regulations controlling greenhouse gas emissions from certain vehicles, and has proposed regulations for new,

 existing, and significantly modified stationary sources of emissions, including electric generating units. Such regulations continue to evolve. Various states and regions of the U.S. have taken action to establish greenhouse gas limitations and trading programs. In Louisiana, the former Office of the Governor announced in 2020 the creation of a Climate Initiatives Task Force and issued an executive order that established a path to net-zero emissions by 2050, while in 2021, the City Council of New Orleans passed a renewable and clean portfolio standard that sets a goal of net-zero emissions by 2040 and absolute zero emissions by 2050. The impact that continued changes in the governmental response to climate change risk and any judicial interpretation thereof will have on existing and pending environmental laws and regulations related to greenhouse gas emissions currently is unclear.

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

 Future changes in regulation or policies governing the reporting or emission of CO2 and other greenhouse gases or mix of generation sources could (i) result in significant additional costs to Entergy's Utility operating companies, their suppliers, or customers, (ii) make some of Entergy's electric generating units uneconomical to maintain or operate, (iii) result in the early retirement of generation facilities and stranded costs if Entergy's Utility operating companies are unable to fully recover the costs and investment in generation, and (iv) increase the difficulty that Entergy and its Utility operating companies have with obtaining or maintaining required environmental regulatory approvals, each of which could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.

 In March 2019, Entergy voluntarily set a climate goal to achieve a 50 percent reduction in its carbon emission rate from the year 2000 by 2030. In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. In November 2022, Entergy voluntarily set a climate goal to achieve 50 percent carbon-free energy capacity by 2030. Risks to achieving the 2030 and 2050 goals include, among other things, the ability to execute on renewable resource plans, regulatory approvals, customer demand for carbon-free energy that exceeds Entergy's or its Utility operating companies' ability to add lower carbon or carbon-free capacity, load growth, potential tariffs, carbon policy and regulation at the federal or state level, including mandates related to reliability standards, and supply chain costs and constraints. Technology research and development, innovation, and advancements in carbon-free generation are also critical to Entergy's ability to achieve its 2050 commitment. Entergy cannot predict the ultimate impact of achieving these objectives, or the various implementation aspects, on its system reliability, or its results of operations, financial condition, or liquidity.

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

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

 Due in part to the recent increase in frequency and intensity of major storm activity along the Gulf Coast, Entergy is pursuing plans to accelerate investments that would enhance the resilience of the electric systems of the Utility operating companies to enable them to better withstand major storms or other significant weather events, to mitigate the cost of restoration of the electric system after major storms or other significant events, to enable more rapid restoration of electricity after major storm or other significant adverse events, and to deliver electricity to critical customers more immediately after such events. These plans are generally subject to approval by the Utility operating companies' retail regulators and may not be approved in full or at all. The need for this investment and these expenditures could give rise to liquidity, capital or other financing-related risks as well as result in upward pressure on the retail rates of the Utility operating companies, which, particularly when combined with upward pressure resulting from the recovery of the costs of recent and future storms, may result in adverse actions by the Utility operating companies' retail regulators or effectively limit the ability to make other planned capital or other investments.

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

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

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

 Water is a vital natural resource that is also critical to Entergy and its subsidiaries. Entergy's and its subsidiaries' facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy's Utility operating companies also own and/or operate hydroelectric facilities. Accordingly, water

 availability and quality are critical to Entergy's and its subsidiaries' business operations. Impacts to water availability or quality could negatively impact both operations and revenues.

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

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

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

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

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

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

 Entergy's over-the-counter financial derivatives are subject to rules implementing the Dodd-Frank Wall Street Reform and Consumer Protection Act that are designed to promote transparency, mitigate systemic risk, and protect against market abuse. Entergy cannot predict the impact any proposed or not fully-implemented final rules will have on its ability to hedge its commodity price risk or on over-the-counter derivatives markets as a whole, but such rules and regulations could have a material effect on Entergy's risk exposure, as well as reduce market liquidity and further increase the cost of hedging activities.

 Entergy has guaranteed or indemnified the performance of a portion of the obligations relating to hedging and risk management activities. Reductions in Entergy's or its subsidiaries' credit quality or changes in the market prices of energy commodities could increase the cash or letter of credit collateral required to be posted in connection with hedging and risk management activities, which could materially affect Entergy's or its subsidiaries' liquidity and financial position.

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

 The hedging and risk management practices of the Utility operating companies and Entergy's non-utility business are exposed to the risk that counterparties that owe Entergy and its subsidiaries money, energy, or other commodities will not perform their obligations. Currently, some hedging agreements contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to Entergy or its subsidiaries. If the counterparties to these arrangements fail to perform, Entergy or its subsidiaries may enforce and recover the proceeds from the credit support provided and acquire alternative hedging arrangements, which credit support may not always be adequate to cover the related obligations. In such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties. In addition, the credit commitments of Entergy's lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially affect the adequacy of its liquidity sources.

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

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

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

 Entergy and its subsidiaries and related entities are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and customer matters, and injuries and damages issues, among other matters. The states in which Entergy and the Registrant Subsidiaries operate have

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

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

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

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

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

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

 Any such attacks, failures, or data breaches could have a material effect on Entergy's and the Registrant Subsidiaries' business, financial condition, results of operations or reputation. Although Entergy and the Registrant

 Subsidiaries purchase insurance for cyber attacks and data breaches, such insurance prices have increased substantially, and coverage may not be adequate to cover all losses that might arise in connection with these incidents. Such incidents may also expose Entergy to an increased risk of litigation (and associated damages and fines). For information on our cybersecurity risk management, strategy, and governance, see "Item 1C. Cybersecurity" in Part I, Item 1C.

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

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

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

 Entergy and its subsidiaries have observed and expect continued inflationary pressures related to commodity prices, other materials and supplies, and operation and maintenance expenses, including in the areas of labor, health care, and pension costs. The contracts for the construction of certain of the Utility operating companies' generation facilities also have included, and in the future may include, price adjustment provisions that, subject to certain limitations, may enable the contractor to increase the contract price to reflect increases in certain costs of constructing the facility. These inflationary pressures could impact the ability of Entergy and its subsidiaries to control costs and/or make substantial investments in their businesses, including their ability to recover costs and investments, and to earn their allowed return on equity within frameworks established by their regulators while maintaining affordability of their services for their customers, in addition to having unpredictable effects on Entergy's customers. Increases in commodity prices, other materials and supplies, and operation and maintenance expenses, including increasing labor costs and costs and funding requirements associated with Entergy's defined benefit retirement plans, health care plans, and other employee benefits, could increase their financing needs and otherwise adversely affect their results of operations, financial condition, and liquidity.

 (Entergy New Orleans)

 The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans's results of operations and liquidity.

 Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected by the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which, given its relatively smaller size, could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer's bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. Entergy New Orleans's cash flows can be affected by differences between the time when gas is purchased and the time when ultimate recovery from customers occurs.

 (Entergy Corporation and System Energy)

 System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to

 System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings. The aggregate amount of refunds claimed in these proceedings, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of substantial additional refunds, System Energy would be required to seek financing to pay such refunds which financing may not be available on terms acceptable to System Energy when required.

 System Energy's operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies (other than Entergy Texas) as consideration for their respective entitlements to receive capacity and energy. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which currently expires in November 2044. System Energy's financial condition depends both on the receipt of payments from the Utility operating companies (other than Entergy Texas) under the Unit Power Sales Agreement and on the continued commercial operation of Grand Gulf. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit), 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.

 The claims in these proceedings include claims for refunds and claims for rate adjustments. The aggregate amount of refunds claimed in these proceedings, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. Entergy Corporation is not obligated to provide funding to System Energy to enable it to pay any such refunds. In the event that an adverse decision in one or more of these proceedings required the payment of substantial additional refunds, System Energy would need to source additional financing to pay such refunds. Such financing may not be available on terms acceptable to System Energy when required. System Energy and its debt securities have been subject to downgrade by rating agencies in the past, most recently in May 2023. Any further downgrade by one or more rating agencies could adversely affect the market prices of System Energy's debt securities and otherwise adversely affect System Energy's financial condition.

 In addition, an order requiring System Energy to pay substantial additional refunds could result in a default and, in certain cases, acceleration under one or more of System Energy's existing bond indentures, credit agreements, or other financing arrangements. Certain events constituting events of default under System Energy's financing agreements may also result in defaults under, or acceleration with respect to, financing arrangements involving certain credit agreement and guarantee obligations of Entergy Corporation.

 These proceedings are pending before their respective adjudicators and no final decisions have been reached. Thus, Entergy cannot predict with certainty the outcome of any of these proceedings, or the magnitude of any refunds or rate adjustments, and an adverse outcome in any of them could have a material adverse effect on Entergy's or System Energy's results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. The Utility operating companies (other than Entergy Texas) have agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.

 For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to certain Entergy System companies' support of System Energy, see Notes 5 and 8 to the financial statements and the "Utility - System Energy and Related Agreements" section of Part I, Item 1.

 (Entergy Corporation)

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

 Entergy's non-utility operations are subject to regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause Entergy's non-utility operations to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.

 Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Entergy's non-utility operations include legal entities that meet the definition of a "public utility" under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted those entities the authority to sell electricity at market-based rates. The FERC's orders that grant those entities market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that those entities can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, market-based sales are subject to certain market behavior rules, and if one of those entities were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1.496 million per day per violation. If one of those entities were to lose their market-based rate authority, it would be required to obtain the FERC's acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates those entities charge for power from its facilities.

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

 The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on Entergy's non-utility operations. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, have raised claims that the competitive marketplace is not working, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, Entergy's non-utility operations' results of operations, financial condition, and liquidity could be materially affected.

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

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

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

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

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

 Item 1B. Unresolved Staff Comments

 None.

 Item 1C. Cybersecurity

 Risk Management and Strategy

 Entergy and the Registrant Subsidiaries maintain a security-risk-management system with defined roles, duties, governance, and accountability. Under this physical- and cyber-risk model, Entergy and the Registrant Subsidiaries streamline security into a centralized program. The Chief Security Officer (CSO) is responsible for

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

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

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

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

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

 Corporate Governance

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

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

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

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

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

 Net income increased $104 million primarily due to a $159.6 million reduction in income tax expense in 2023 as a result of the resolution of the 2016-2018 IRS audit, higher retail electric price, lower other operation and maintenance expenses, and higher other income. The increase was partially offset by write-offs of $78.4 million ($58.8 million net-of-tax) in third quarter 2023 as a result of Entergy Arkansas's approved motion to forgo recovery related to the 2013 ANO stator incident, higher interest expense, lower volume/weather, and higher depreciation and amortization expenses. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit. See Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.

 Following is an analysis of the change in operating revenues comparing 2023 to 2022:

 $2,673.2

 (75.0)

 (31.4)

 79.6

 $2,646.4

 Entergy Arkansas's results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. "Fuel, rider, and other revenues that do not significantly affect net income" includes the revenue variance associated with these items.

 The volume/weather variance is primarily due to the effect of less favorable weather on residential sales and a decrease in weather-adjusted residential usage, partially offset by an increase in industrial usage. The increase in industrial usage is primarily due to an increase in demand from small industrial customers and an increase in demand from expansion projects, primarily in the metals industry.

 The retail electric price variance is primarily due to an increase in formula rate plan rates effective January 2023. See Note 2 to the financial statements for further discussion of the 2022 formula rate plan filing.

 Total electric energy sales for Entergy Arkansas for the years ended December 31, 2023 and 2022 are as follows:

 2023
 2022

 (GWh)

 7,610
 8,147
 (7)

 5,584
 5,615
 (1)

 9,095
 8,493

 (12)

 22,481
 22,473
 —

 2,218
 1,906

 5,777
 6,520
 (11)

 Total
 30,476
 30,899
 (1)

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

 Other operation and maintenance expenses decreased primarily due to:

 • a decrease of $17.1 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits service costs as a result of an increase in the discount rates used to value the benefits liabilities, lower health and welfare costs, including higher prescription drug rebates in second quarter 2023, and a revision to estimated incentive compensation expense in first quarter 2023. See "Critical Accounting Estimates" below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;
 • a decrease of $10.5 million in transmission costs allocated by MISO;
 • the effects of recording a final judgment in first quarter 2023 to resolve claims in the ANO damages case against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $10.3 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expenses. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
 • a decrease of $9.6 million in non-nuclear generation expenses primarily due to a lower scope of work, including during plant outages, performed in 2023 as compared to 2022.

 • an increase of $10.4 million in contract costs related to operational performance, customer service, and organizational health initiatives;
 • an increase of $9.2 million in insurance expenses primarily due to lower nuclear insurance refunds received in 2023;
 • an increase of $5.2 million in nuclear generation expenses primarily due to a higher scope of work performed in 2023 as compared to 2022 and higher nuclear labor costs; and

 Asset write-offs includes the effects of Entergy Arkansas forgoing recovery of identified costs resulting from the 2013 ANO stator incident. In third quarter 2023, Entergy Arkansas recorded write-offs of its regulatory asset for deferred fuel of $68.9 million and the undepreciated balance of $9.5 million in capital costs related to the

 ANO stator incident. See Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.

 Depreciation and amortization expenses increased primarily due to additions to plant in service.

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

 Other income increased primarily due to:

 • higher interest earned on money pool investments;
 • an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2023; and
 • a decrease in charitable donations in 2023 as compared to 2022.

 Interest expense increased primarily due to the issuance of $425 million of 5.15% Series mortgage bonds in January 2023 and higher interest accrued on spent nuclear fuel disposal costs.

 The effective income tax rates were (33.3%) for 2023 and 21.6% for 2022. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.

 See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations" in Item 7 of Entergy Arkansas's Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.

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

 Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:

 2023
 2022
 2021

 $5,278
 $12,915
 $192,128

 941,021
 699,732
 549,216

 (1,032,952)
 (852,794)
 (898,193)

 90,285
 145,425
 169,764

 (1,646)
 (7,637)
 (179,213)

 $3,632
 $5,278
 $12,915

 Net cash flow provided by operating activities increased $241.3 million in 2023 primarily due to:

 • lower fuel costs and the timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;
 • higher collections from customers;
 • the refund of $41.7 million received from System Energy 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. The refund was subsequently applied to the under-recovered deferred fuel balance. See Note 2 to the financial statements for further discussion of the refund and the related proceedings;
 • a decrease of $38.5 million in pension contributions in 2023. 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; and
 •$23.2 million in proceeds received from the DOE in April 2023 resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

 • the timing of payments to vendors;
 • an increase of $25.4 million in storm spending in 2023 as compared to 2022; and
 • an increase of $22.1 million in interest paid.

 Net cash flow used in investing activities increased $180.2 million in 2023 primarily due to:

 • an increase of $122.9 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2023;
 • an increase of $86.6 million in transmission construction expenditures primarily due to increased investment in the reliability and infrastructure of Entergy Arkansas's transmission system; and
 • an increase of $43.2 million as a result of fluctuations in nuclear fuel activity due to variations from year to year in the timing and pricing of fuel reload requirements, materials and services deliveries, and the timing of cash payments during the nuclear fuel cycle.

 • a decrease of $38.3 million in nuclear construction expenditures primarily due to decreased spending on various nuclear projects in 2023;
 •$17.9 million in proceeds received from the DOE in April 2023 resulting from litigation regarding spent nuclear fuel storage costs that were previously recorded as plant. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
 • a decrease of $14.1 million in information technology capital expenditures primarily due to decreased spending on various technology projects in 2023.

 Net cash flow provided by financing activities decreased $55.1 million in 2023 primarily due to:

 • an increase of $331 million in common equity distributions paid in 2023 in order to maintain Entergy Arkansas's capital structure;
 • the repayment, at maturity, of $250 million of 3.05% Series mortgage bonds in June 2023;
 • the issuance of $200 million of 4.20% Series mortgage bonds in March 2022;
 • the repayment, at maturity, of $40 million of 3.17% Series M notes by the Entergy Arkansas nuclear fuel company variable interest entity in December 2023; and

 • the issuance of $425 million of 5.15% Series mortgage bonds in January 2023;
 • the issuance of $300 million of 5.30% Series mortgage bonds in August 2023;
 • net long-term borrowings of $70.2 million in 2023 as compared to net repayments of $4.8 million in 2022 on the nuclear fuel company variable interest entity's credit facility; and
 • an increase of $61.3 million in prepaid deposits related to contributions-in-aid-of-construction primarily for customer and generator interconnection agreements.

 Decreases in Entergy Arkansas's payable to the money pool are a use of cash flow, and Entergy Arkansas's payable to the money pool decreased $35.4 million in 2023 compared to increasing by $40.9 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries' dependence on external short-term borrowings.

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

 See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow" in Item 7 of Entergy Arkansas's Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.

 Entergy Arkansas's debt to capital ratio is shown in the following table. The increase in the debt to capital ratio for Entergy Arkansas is primarily due to the net issuance of long-term debt in 2023.

2023
2022

 55.5
 %
 52.5
 %

 —
 %
 —
 %

 Net debt to net capital (non-GAAP)
 55.5
 %
 52.5
 %

 Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas's financial condition. The net debt to net capital ratio is a non-GAAP measure.

 Entergy Arkansas also uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas's financial condition because net debt indicates Entergy Arkansas's outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

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

 Entergy Arkansas requires capital resources for:

 • working capital purposes, including the financing of fuel and purchased power costs; and
 • distribution and interest payments.

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

 2024
 2025
 2026

 $1,090
 $355
 $240

 Total
 $1,705
 $1,040
 $865

 In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes investments in generation projects to modernize, decarbonize, and diversify Entergy Arkansas's portfolio, including Walnut Bend Solar, West Memphis Solar, and Driver Solar; investments in ANO 1 and 2; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.

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

 2024
 2025
 2026

 $546
 $233
 $835
 $619
 $5,514

 $17
 $16
 $14
 $15
 $5

 $5
 $4
 $4
 $5
 $3

 Entergy Arkansas currently expects to contribute approximately $55.1 million to its qualified pension plans and approximately $529 thousand to its other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

 Entergy Arkansas has $34.5 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

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

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

 Renewables

 Walnut Bend Solar

 In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 100 MW Walnut Bend Solar facility is in the public interest. Entergy Arkansas primarily requested cost recovery through the formula rate plan rider. In July 2021 the APSC granted Entergy Arkansas's petition and approved the acquisition of the resource and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In January 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. The counterparty notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination. Negotiations were conducted, including with respect to cost and schedule and to updates arising as a result of the Inflation Reduction Act of 2022. In April 2023, Entergy Arkansas filed an application for an amended certificate of environmental compatibility and public need with the APSC seeking approval by June 2023 for the updates to the cost and schedule that were previously approved by the APSC. In June 2023, Entergy Arkansas, the APSC general staff, and the Arkansas Attorney General filed a unanimous settlement supporting that the approval of the Walnut Bend Solar facility is in the public interest based on the terms

 in the settlement, including the treatment for the production tax credits associated with the facility. In July 2023, after requesting further testimony and purporting to modify several terms in the settlement and upon rehearing, the APSC approved the settlement largely on the terms submitted, including a 30-year amortization period for the production tax credits. In February 2024, Entergy Arkansas made an initial payment of approximately $169.7 million to acquire the facility. The project will achieve commercial operation once testing is completed and the project has achieved substantial completion. Entergy Arkansas currently expects the project to achieve commercial operation in the first half of 2024, at which time a substantial completion payment of approximately $20 million is expected.

 West Memphis Solar

 In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 180 MW West Memphis Solar facility is in the public interest. In October 2021 the APSC granted Entergy Arkansas's petition and approved the acquisition of the West Memphis Solar facility and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In April 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. In March 2022 the counterparty notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC seeking approval for a change in the transmission route and updates to the cost and schedule that were previously approved by the APSC. In March 2023 the APSC approved Entergy Arkansas's supplemental application. The project is currently expected to achieve commercial operation by the end of 2024.

 Driver Solar

 In April 2022, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 250 MW Driver Solar facility is in the public interest and requested cost recovery through the formula rate plan rider. The APSC established a procedural schedule with a hearing scheduled in June 2022, but the parties later agreed to waive the hearing and submit the matter to the APSC for a decision consistent with the filed record. In August 2022 the APSC granted Entergy Arkansas's petition and approved the acquisition of Driver Solar and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to inform the APSC as to the status of a tax equity partnership once construction is commenced. The parties are evaluating the effects of certain matters related to the Inflation Reduction Act of 2022, including the viability of a tax equity partnership. The project is expected to achieve commercial operation as early as mid-2024.

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

 • debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;

 Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations,

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

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

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

 2023
 2022
 2021
 2020

 ($145,385)
 ($180,795)
 ($139,904)
 $3,110

 Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in June 2028. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2024. The $150 million credit facility includes fronting commitments for the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2023, there were no cash borrowings and no letters of credit outstanding under the credit facilities. In addition, Entergy Arkansas is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2023, $5.8 million in letters of credit were outstanding under Entergy Arkansas's uncommitted letter of credit facility. See Note 4 to the financial statements for further discussion of the credit facilities.

 The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $80 million scheduled to expire in June 2025. As of December 31, 2023, $70.2 million in loans were outstanding under the credit facility for the Entergy Arkansas nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of the nuclear fuel company variable interest entity credit facility.

 Entergy Arkansas obtained authorization from the FERC through April 2025 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and borrowings by its nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of Entergy Arkansas's short-term borrowing limits. The long-term securities issuances of Entergy Arkansas are limited to amounts authorized by the FERC. The APSC has concurrent jurisdiction over Entergy Arkansas's first mortgage bond/secured issuances. Entergy Arkansas has obtained long-term financing authorization from the FERC that extends through April 2025. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2025.

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

 2020 Formula Rate Plan Filing

 In July 2020, Entergy Arkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas's earnings for the projected year 2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The filing showed that Entergy Arkansas's earned rate of return on common equity for the 2021 projected year was 8.22% resulting in a revenue deficiency of $64.3 million. The earned rate of return on common equity for the 2019 historical year was 9.07% resulting in a $23.9 million netting adjustment. The total proposed revenue change for the 2021 projected year and 2019 historical year netting adjustment was $88.2 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 $74.3 million. As part of the formula rate plan tariff the calculation for the revenue constraint was updated based on actual revenues which had the effect of reducing the initially-proposed $74.3 million revenue requirement increase to $72.6 million. In October 2020, Entergy Arkansas filed with the APSC a unanimous settlement agreement reached with the other parties that resolved all but one issue. As a result of the settlement agreement, Entergy Arkansas's requested revenue increase was $68.4 million, including a $44.5 million increase for the projected 2021 year and a $23.9 million netting adjustment. The remaining issue litigated concerned the methodology used to calculate the netting adjustment within the formula rate plan. In December 2020 the APSC issued an order rejecting the netting adjustment method used by Entergy Arkansas. Applying the approach ordered by the APSC changed the netting adjustment for the 2019 historical year from a $23.9 million deficiency to $43.5 million excess. Overall, the decision reduced Entergy Arkansas's revenue adjustment for 2021 to $1 million. In December 2020, Entergy Arkansas filed a petition for rehearing of the APSC's decision in the 2020 formula rate plan proceeding regarding the 2019 netting adjustment, and in January 2021 the APSC granted further consideration of Entergy Arkansas's petition. Based on the progress of the proceeding at that point, in December 2020, Entergy Arkansas recorded a regulatory liability of $43.5 million to reflect the netting adjustment for 2019, as included in the APSC's December 2020 order, which would be returned to customers in 2021. Entergy Arkansas also requested an extension of the formula rate plan rider for a second five-year term. In March 2021 the Arkansas Governor signed HB1662 into law (Act 404). Act 404 clarified aspects of the original formula rate plan legislation enacted in 2015, including with respect to the extension of a formula rate plan, the methodology for the netting adjustment, and debt and equity levels; it also reaffirmed the customer protections of the original formula rate plan legislation, including the cap on annual formula rate plan rate changes. Pursuant to Act 404, Entergy Arkansas's formula rate plan rider was extended for a second five-year term. Entergy Arkansas filed a compliance tariff in its formula rate plan docket in April 2021 to effectuate the netting provisions of Act 404, which reflected a net change in required formula rate plan rider revenue of $39.8 million, effective with the first billing cycle of May 2021. In April 2021 the APSC issued an order approving the compliance tariff and recognizing the formula rate plan extension. Also in April 2021, Entergy Arkansas filed for approval of modifications to the formula rate plan tariff incorporating the provisions in Act 404, and the APSC approved the tariff modifications in April 2021. Given the APSC general staff's support for the expedited approval of these filings by the APSC, Entergy Arkansas supported an amendment to Act 404 to achieve a reduced return on equity from 9.75% to 9.65% to apply for years applicable to the extension term; that amendment was signed by the Arkansas Governor in April 2021 and is now Act 894. Based on the APSC's order issued in April 2021, in the first quarter 2021, Entergy Arkansas reversed the remaining regulatory liability for the netting adjustment for 2019. In June 2021, Entergy Arkansas filed another compliance tariff in its formula rate plan proceeding to effectuate the additional provisions of Act 894, and the APSC approved the second compliance tariff filing in July 2021.

 In July 2021, Entergy Arkansas filed with the APSC its 2021 formula rate plan filing to set its formula rate for the 2022 calendar year. The filing contained an evaluation of Entergy Arkansas's earnings for the projected year 2022 and a netting adjustment for the historical year 2020. The filing showed that Entergy Arkansas's earned rate

 of return on common equity for the 2022 projected year was 7.65% resulting in a revenue deficiency of $89.2 million. The earned rate of return on common equity for the 2020 historical year was 7.92% resulting in a $19.4 million netting adjustment. The total proposed revenue change for the 2022 projected year and 2020 historical year netting adjustment was $108.7 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 $72.4 million. In October 2021, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding. As a result of the settlement agreement, the total proposed revenue change was $82.2 million, including a $62.8 million increase for the projected 2022 year and a $19.4 million netting adjustment. Because Entergy Arkansas's revenue requirement exceeded the constraint, the resulting increase was limited to $72.1 million. In December 2021 the APSC approved the settlement as being in the public interest and approved Entergy Arkansas's compliance tariff effective with the first billing cycle of January 2022.

 In July 2022, Entergy Arkansas filed with the APSC its 2022 formula rate plan filing to set its formula rate for the 2023 calendar year. The filing contained an evaluation of Entergy Arkansas's earnings for the projected year 2023 and a netting adjustment for the historical year 2021. The filing showed that Entergy Arkansas's earned rate of return on common equity for the 2023 projected year was 7.40% resulting in a revenue deficiency of $104.8 million. The earned rate of return on common equity for the 2021 historical year was 8.38% resulting in a $15.2 million netting adjustment. The total proposed revenue change for the 2023 projected year and 2021 historical year netting adjustment was $119.9 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 $79.3 million. In October 2022 other parties filed their testimony recommending various adjustments to Entergy Arkansas's overall proposed revenue deficiency, and Entergy Arkansas filed a response including an update to actual revenues through August 2022, which raised the constraint to $79.8 million. In November 2022, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding. As a result of the settlement agreement, the total revenue change was $102.8 million, including a $87.7 million increase for the 2023 projected year and a $15.2 million netting adjustment. Because Entergy Arkansas's revenue requirement exceeded the constraint, the resulting increase was limited to $79.8 million. In December 2022 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 2023.

 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 is $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 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. Entergy Arkansas filed its rebuttal in October 2023. 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 cap 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.

 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 "ANO Damage, Outage, and NRC Reviews" in Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.

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

 In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas's annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Cuts and Jobs Act. Entergy Arkansas replied to the Attorney General's filing and stated that, to the extent there are questions pertaining to its

 load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Cuts and Jobs Act are appropriately considered in the APSC's separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General's filing and agreed that Entergy Arkansas's filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas's energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas's March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General's supplemental response, the APSC general staff filed a motion to strike the Attorney General's filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff's filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas's energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it has initiated an audit of the 2017 fuel costs. The time in which the audit will be complete is uncertain at this time.

 In March 2021, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01052 per kWh to $0.00959 per kWh. The redetermined rate calculation also included an adjustment to account for a portion of the increased fuel costs resulting from the February 2021 winter storms. The redetermined rate became effective with the first billing cycle in April 2021 through the normal operation of the tariff.

 In March 2022, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase from $0.00959 per kWh to $0.01785 per kWh. The primary reason for the rate increase was a large under-recovered balance as a result of higher natural gas prices in 2021, particularly in the fourth quarter 2021. At the request of the APSC general staff, Entergy Arkansas deferred its request for recovery of $32 million from the under-recovery related to the February 2021 winter storms until the 2023 energy cost rate redetermination, unless a request for an interim adjustment to the energy cost recovery rider is necessary. This resulted in a redetermined rate of $0.016390 per kWh, which became effective with the first billing cycle in April 2022 through the normal operation of the tariff. In February 2023 the APSC issued orders initiating proceedings with the utilities under its jurisdiction to address the prudence of costs incurred and appropriate cost allocation of the February 2021 winter storms. With respect to any prudence review of Entergy Arkansas fuel costs, as part of the APSC's draft report issued in its February 2021 winter storms investigation docket, the APSC included findings that the load shedding plans of the investor-owned utilities and some cooperatives were appropriate and comprehensive, and, further, that Entergy Arkansas's emergency plan was comprehensive and had a multilayered approach supported by a system-wide response plan, which is considered an industry standard. In September 2023 the APSC issued an order in Entergy Arkansas's company-specific proceeding and found that Entergy Arkansas's practices during the winter storms were prudent.

 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 from $0.01639 per kWh to $0.01883 per kWh. The primary reason for the rate increase is a large under-recovered balance as a result of higher natural gas prices in 2022 and a $32 million deferral related to the February 2021 winter storms consistent with the APSC general staff's request in 2022. The under-recovered balance included in the filing was partially offset by the proceeds of the $41.7 million refund that System Energy made to Entergy Arkansas in January 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy's January 2023 compliance report filed with the FERC. See "Complaints Against System Energy - Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue" in Note 2 to the financial statements for discussion of the compliance report filed by System Energy with the FERC in January 2023. The redetermined rate of $0.01883 per kWh became effective with the first billing cycle in April 2023 through the normal operation of the tariff.

 Opportunity Sales Proceeding

 In June 2009 the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas's sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocated the energy generated by Entergy System resources; (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity; and (c) violated the provision of the System Agreement that prohibited sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC's complaint challenged sales made beginning in 2002 and requested refunds. In July 2009 the Utility operating companies filed a response to the complaint arguing among other things that the System Agreement contemplates 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.

 After a hearing, the ALJ issued an initial decision in December 2010. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that "shareholders" should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ's initial decision and in January 2011 filed with the FERC exceptions to the decision.

 The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does 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 does 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. The LPSC, the APSC, the City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that the FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.

 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.

 In May 2016, Entergy Services filed a request for rehearing of the FERC's April 2016 order arguing that payments made by Entergy Arkansas should be reduced as a result of the timing of the LPSC's approval of certain contracts. Entergy Services also filed a request for clarification and/or rehearing of the FERC's April 2016 order

 addressing the ALJ's August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC's April 2016 order. In September 2017 the FERC issued an order denying the request for rehearing on the issue of whether any payments by Entergy Arkansas to the other Utility operating companies should be reduced due to the timing of the LPSC's approval of Entergy Arkansas's wholesale baseload contract with Entergy Louisiana. In November 2017 the FERC issued an order denying all of the remaining requests for rehearing of the April 2016 order. In November 2017, Entergy Services filed a petition for review in the D.C. Circuit of the FERC's orders in the first two phases of the opportunity sales case. In December 2017 the D.C. Circuit granted Entergy Services' request to hold the appeal in abeyance pending final resolution of the related proceeding before the FERC. In January 2018 the APSC and the LPSC filed separate petitions for review in the D.C. Circuit, and the D.C. Circuit consolidated the appeals with Entergy Services' appeal.

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

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

 In October 2018 the FERC issued an order addressing the ALJ's July 2017 initial decision. The FERC reversed the ALJ's decision to cap the reduction in Entergy Arkansas's payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ's decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas's payment. The FERC affirmed on other grounds the ALJ's rejection of the LPSC's claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas's payment. In November 2018 the LPSC requested rehearing of the FERC's October 2018 decision. In December 2019 the FERC denied the LPSC's request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.

 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. No protests were filed in response to the December 2018 compliance filing. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:

 Total refunds including interest

 Payment/(Receipt)

 Principal
 Interest
 Total

 $68
 $67
 $135

 ($30)
 ($29)
 ($59)

 ($18)
 ($18)
 ($36)

 ($3)
 ($4)
 ($7)

 ($17)
 ($16)
 ($33)

 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.

 As described above, 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 February 2019 the LPSC filed a new complaint relating to two issues that were raised in the opportunity sales proceeding, but that, in its October 2018 order, the FERC held were outside the scope of the proceeding. In March 2019, Entergy Services filed an answer and motion to dismiss the new complaint. In November 2019 the FERC issued an order denying the LPSC's complaint. The order concluded that the settlement agreement approved by the FERC in December 2015 terminating the System Agreement barred the LPSC's new complaint. In December 2019 the LPSC requested rehearing of the FERC's November 2019 order, and in July 2020 the FERC issued an order dismissing the LPSC's request for rehearing. In September 2020 the LPSC appealed to the D.C. Circuit the FERC's orders dismissing the new opportunity sales complaint. In November 2020 the D.C. Circuit issued an order establishing that briefing will occur in January 2021 through April 2021. Oral argument was held in September 2021. In December 2021 the D.C. Circuit denied the LPSC's Petition for Review of the new opportunity sales complaint. The opportunity sales cases are complete at FERC and at the D.C. Circuit and no additional refund amounts are owed by Entergy Arkansas.

 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. The application requested that the APSC approve the rider to take effect within 30 days or, if suspended by the APSC as allowed by commission rule, approve the rider to take effect in the first billing cycle of the first month occurring 30 days after issuance of the APSC's order approving the rider. In June 2019 the APSC suspended Entergy Arkansas's tariff and granted Entergy Arkansas's motion asking the APSC to establish the proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC's October 2018 order and related FERC orders in the opportunity sales proceeding. In January 2020 the APSC adopted a procedural schedule with a hearing in April 2020. In January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed a joint motion seeking to dismiss Entergy Arkansas's application alleging that the APSC, in a prior proceeding, ruled on the issues addressed in the application and determined that Entergy Arkansas's requested relief violates the filed rate doctrine and the prohibition against retroactive ratemaking. Entergy Arkansas responded to the joint motion in February 2020 rebutting these arguments, including demonstrating that the claims in this proceeding differ substantially from those the APSC addressed previously and that the payment resulting from a FERC tariff violation for which Entergy Arkansas seeks retail cost recovery in this proceeding differs materially from the refunds resulting from a FERC tariff amendment that the APSC previously rejected on filed rate doctrine and the retroactive ratemaking grounds. In addition, 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. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas's request for

 a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas's stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. 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 October 2020 the APSC filed a motion to dismiss Entergy Arkansas's complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary. In March 2022 the court denied the APSC's motion to dismiss, and, in April 2022, issued a scheduling order including a trial date in February 2023. In June 2022, Entergy Arkansas filed a motion asserting that it is entitled to summary judgment because Entergy Arkansas's position that the APSC's order is pre-empted by the filed rate doctrine and violates the Dormant Commerce Clause is premised on facts that are not subject to genuine dispute. In July 2022, Arkansas Electric Energy Consumers, Inc., an industrial customer association, filed a motion to intervene and to hold Entergy Arkansas's motion for summary judgment in abeyance pending a ruling on the motion to intervene. Entergy Arkansas filed a consolidated opposition to both motions. In August 2022 the APSC filed a motion for summary judgment arguing that there is no genuine issue as to any material fact and the APSC is entitled to judgment as a matter of law. In September 2022, Entergy Arkansas filed an opposition to the motion. In October 2022 the APSC filed a motion asking the court to hold further proceedings in abeyance pending a decision on the motions for summary judgment filed by Entergy Arkansas and the APSC. Also in October 2022, Entergy Arkansas filed an opposition to the motion, and the APSC filed a reply in support of its motion for summary judgment. In January 2023 the judge assigned to the case, on her own motion, identified facts that may present a conflict and recused herself; a new judge was assigned to the case, but he also recused due to a conflict. The case again was reassigned to a new judge. In January 2023 the court denied all pending motions (including those described above) except for a motion by the APSC to exclude certain testimony and further ruled that the matter would proceed to trial. In January 2023, Arkansas Electric Energy Consumers, Inc. filed a notice of appeal of the court's order denying its motion to intervene to the United States Court of Appeals for the Eighth Circuit and a motion with the district court to stay the proceedings pending the appeal, which was denied. In February 2023, Arkansas Electric Energy Consumers, Inc. filed a motion with the United States Court of Appeals for the Eighth District to stay the proceedings pending the appeal, which also was denied. The trial was held in February 2023. Following the trial, Entergy Arkansas filed a motion with the United States Court of Appeals for the Eighth District to expedite the appeal filed by Arkansas Electric Energy Consumers, Inc. The United States Court of Appeals for the Eighth District granted Entergy Arkansas's request, and oral arguments were held in June 2023. In August 2023 the United States Court of Appeals for the Eighth District affirmed the order of the court denying Arkansas Electric Energy Consumers, Inc.'s motion to intervene. An order from the district court is pending and is anticipated in 2024.

 Net Metering Legislation

 An Arkansas law was enacted effective July 2019 that, among other things, expands the definition of a "net metering customer" to include two additional types of customers: (1) customers that lease net metering facilities, subject to certain leasing arrangements, and (2) government entities or other entities exempt from state and federal income taxes that enter into a service contract for a net metering facility. The latter provision allows eligible entities, many of whom are small and large general service customers, to purchase renewable energy directly from third party providers and receive bill credits for these purchases. The APSC was given authority under this law to address certain matters, such as cost shifting and the appropriate compensation for net metered energy and initiated proceedings for this purpose. Because of the size and number of customers eligible under this new law, there is a risk of loss of load and the shifting of costs to customers. A hearing was held in December 2019, with utilities, including Entergy Arkansas, cooperatives, the Arkansas Attorney General, and industrial customers advocating the

 need for establishment of a reasonable rate structure that takes into account impacts to non-net metering customers; an additional hearing was conducted in February 2020 for purposes of public comment only. The APSC issued an order in June 2020, and in July 2020 several parties, including Entergy Arkansas, filed for rehearing on multiple grounds, including for the reasons that it imposes an unreasonable rate structure and allows facilities to net meter that do not meet the statutory definition of net metering facilities. After granting the rehearing requests, the APSC issued an order in September 2020 largely upholding its June 2020 order. In October 2020, Entergy Arkansas and several other parties filed an appeal of the APSC's September 2020 order. In January 2021, Entergy Arkansas, pursuant to an APSC order, filed an updated net metering tariff, which was approved in February 2021. In May 2021, Entergy Arkansas filed a motion to dismiss its pending judicial appeal of the APSC's September 2020 order on rehearing in the proceeding addressing its net metering rules. In June 2021 the Arkansas Court of Appeals granted the motion and dismissed Entergy Arkansas's appeal, although other appeals of the September 2020 APSC order remained before the court. In May 2022 the court issued an order affirming the APSC's decision in part and reversing in part. In June 2022 the APSC sought rehearing from the court with respect to the court's ruling on a grid charge, which the court of appeals denied in July 2022. One of the cooperative appellants filed a further appeal to the Arkansas Supreme Court in July 2022, which the court decided not to hear.

 Separately, as directed by the APSC general staff, the APSC opened a proceeding to compel utilities to amend their net metering tariffs to incorporate the provisions of the legislation that the APSC general staff considered "black letter law." Entergy Arkansas, the Arkansas Attorney General, and other intervenors opposed this directive pending the development of the rules for implementation that are being considered in the separate net metering rulemaking docket. Nevertheless, reserving its rights, Entergy Arkansas has complied with the directive to amend its tariffs. Asserting procedural and due process violations, in January 2020, Entergy Arkansas and the Arkansas Attorney General separately appealed certain APSC orders in the proceeding. In December 2021 the Arkansas Court of Appeals dismissed the appeal on procedural grounds and without prejudice.

 Since the enactment of the net metering legislation, the APSC has approved numerous applications allowing Entergy Arkansas customers to enter into purchase power agreements with third parties and to utilize these purchase power agreements to offset power usage by Entergy Arkansas, despite the lack of proximity between the purchase power agreement and the end-use customer. The APSC also has allowed the aggregation of accounts by net metering customers. These decisions by the APSC have created subsidies in favor of eligible net metering customers to the detriment of non-participating customers. The level of this subsidy continues to grow as additional net metering applications are approved by the APSC.

 In August 2022 the APSC opened a rulemaking concerning proposed amendments to the net metering rules to address the expiration on December 31, 2022 of the automatic grandfathering of the existing net metering rate structure. Entergy Arkansas and other utility parties filed initial briefs and comments setting forth that the statute imposing the expiration of the automatic grandfathering is not ambiguous and that the APSC does not have the authority to extend the grandfathering period, and the hearing was held in October 2022. In December 2022 the APSC issued an order attempting to modify the net metering rules and purporting to allow for the potential for grandfathering after December 31, 2022. More than thirty applicants filed individual net metering applications in December 2022 seeking to be considered under the APSC's order, although the APSC issued an order in January 2023 holding those applications in abeyance. Several parties, including Entergy Arkansas, sought rehearing, and the Arkansas's Governor's executive order limiting new rulemakings calls into question how the APSC's order to adopt new rules may be effectuated.

 In September 2022 the APSC opened another proceeding to investigate the issue of potential cost shifting arising as a result of net metering. Investor owned utilities and some cooperatives were required to make and did make filings in October 2022 with supporting documentation as to the amount and extent of cost shifting and the manner in which they would design tariffs to recover those costs on behalf of non-net metering customers. Responses to the utility and cooperative filings were filed in January 2023, and utilities filed their further responses in February 2023.

 An Arkansas law was enacted effective March 2023 that revises the billing arrangements for net metering facilities in order to reduce the cost shift to non-net metering customers. The new law also imposes a new limit of 5 MW for future net metering facilities, allows utilities to recover net metering credits in the same manner as fuel, and grandfathers certain net metering facilities that are online or in process to be online by September 2024. Entergy Arkansas joined other utilities in a motion in April 2023 to close the current APSC docket related to potential cost shifting in light of the new law, and the APSC also canceled the remaining procedural schedule in this docket in April 2023. Because of the new law, in May 2023, the APSC also closed the grandfathering rulemaking that it opened in August 2022. Under the new law, the APSC must approve revisions to the utilities' tariffs to conform to the new law no later than December 2023. The APSC opened a new rulemaking in April 2023 to consider implementation of the new law and tariffs. In October 2023 the APSC issued new net metering rules to conform to the new law, and utilities, including Entergy Arkansas, filed revised net metering tariffs to comply with the new rules on October 16, 2023. Entergy Arkansas's revised net metering tariff was approved by the APSC in December 2023.

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

 Entergy Arkansas owns and, through an affiliate, operates the ANO 1 and 2 nuclear generating plants and is, therefore, subject to the risks related to such ownership and operation. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, including the financial requirements to address emerging issues related to equipment reliability, to position Entergy Arkansas's nuclear fleet to meet its operational goals; the performance and capacity factors of these nuclear plants; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts of insurance recoveries for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of either ANO 1 or 2, Entergy Arkansas may be required to file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. ANO 1's operating license expires in 2034 and ANO 2's operating license expires in 2038.

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

 The preparation of Entergy Arkansas's financial statements in conformity with GAAP requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following

 accounting estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy Arkansas's financial position, results of operations, or cash flows.

 Nuclear Decommissioning Costs

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

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

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

 Entergy Arkansas's qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See "Qualified Pension and Other Postretirement Benefits" in the "Critical Accounting Estimates" section of Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.

 Costs Sensitivity

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

 $929
 $26,189

 $2,567
 $—

 0.25%
 $985
 $4,963

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

 ($56)
 $3,841

 0.25%
 $217
 $2,600

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

 Total qualified pension cost for Entergy Arkansas in 2023 was $49.5 million, including $26.1 million in settlement costs. Entergy Arkansas anticipates 2024 qualified pension cost to be $19.6 million. Entergy Arkansas contributed $54.5 million to its qualified pension plans in 2023 and estimates pension contributions will be approximately $55.1 million in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024 valuations are completed, which is expected by April 1, 2024.

 Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 2023 was $1.9 million. Entergy Arkansas expects 2024 postretirement health care and life insurance benefit income of approximately $5.5 million. Entergy Arkansas contributed $582 thousand to its other postretirement plans in 2023 and estimates 2024 contributions will be approximately $529 thousand.

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

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

 We have audited the accompanying consolidated balance sheets of Entergy Arkansas, LLC and Subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of income, cash flows and changes in equity (pages 336 through 340 and applicable items in pages 47 through 238), for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

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

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

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

 Critical Audit Matter

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

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

 The Company is subject to rate regulation by the Arkansas Public Service Commission (the "APSC"), which has jurisdiction with respect to the rates of electric companies in Arkansas, and to wholesale rate regulation by the Federal Energy Regulatory Commission ("FERC"). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

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

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

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

 • We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management's controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
 • We evaluated the Company's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
 • We read relevant regulatory orders issued by the APSC and the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the APSC's and the FERC's treatment of similar costs under similar circumstances. We evaluated external information and compared to management's recorded regulatory asset and liability balances for completeness.
 • For regulatory matters in process, we inspected the Company's filings with the APSC and the FERC and orders issued, and considered the filings with the APSC and the FERC by intervenors that may impact the Company's future rates, for any evidence that might contradict management's assertions.
 • We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management's assertion that amounts are probable of recovery or 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.

 2023
 2022
 2021

 $ 2,646,396
 $ 2,673,194
 $ 2,338,590

 514,885
 640,344
 347,166

 257,890
 201,726
 280,504

 Nuclear refueling outage expenses
 59,973
 53,438
 51,141

 737,649
 754,293
 687,418

 Asset write-offs
 78,434
 —
 —

 87,321
 82,326
 77,696

 141,502
 136,565
 127,249

 400,944
 386,272
 361,479

 ( 87,409)
 ( 89,418)
 ( 31,501)

 TOTAL
 2,191,189
 2,165,546
 1,901,152

 455,207
 507,648
 437,438

 OTHER INCOME

 20,587
 17,787
 15,273

 25,024
 19,554
 76,953

 ( 23,216)
 ( 27,348)
 ( 22,278)

 TOTAL
 22,395
 9,993
 69,948

 188,232
 150,928
 140,348

 ( 8,270)
 ( 7,070)
 ( 6,641)

 TOTAL
 179,962
 143,858
 133,707

 297,640
 373,783
 373,679

 ( 99,210)
 80,896
 75,195

 396,850
 292,887
 298,484

 Net loss attributable to noncontrolling interest
 ( 5,231)
 ( 4,358)
 ( 18,092)

 EARNINGS APPLICABLE TO MEMBER'S EQUITY
 $ 402,081
 $ 297,245
 $ 316,576

 2023
 2022
 2021

 $ 396,850
 $ 292,887
 $ 298,484

 Adjustments to reconcile net income to net cash flow provided by operating activities:

 Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 556,780
 532,291
 503,539

 ( 102,070)
 78,958
 100,459

 Asset write-offs
 78,434
 —
 —

 ( 84,428)
 ( 73,579)
 17,682

 ( 6,351)
 ( 252)
 ( 7,081)

 ( 69,947)
 64,944
 27,967

 4,625
 10,936
 7,753

 16,554
 1,708
 ( 5,637)

 228,021
 ( 31,009)
 ( 162,458)

 ( 29,690)
 ( 29,789)
 ( 53,343)

 Provisions for estimated losses
 ( 21,039)
 2,914
 6,915

 Regulatory assets
 ( 6,197)
 ( 120,603)
 142,706

 240,762
 ( 264,054)
 21,066

 ( 109,077)
 ( 67,783)
 ( 175,863)

 ( 152,206)
 302,163
 ( 172,973)

 941,021
 699,732
 549,216

 ( 946,244)
 ( 785,168)
 ( 722,628)

 20,587
 17,787
 15,273

 Nuclear fuel purchases
 ( 137,616)
 ( 98,635)
 ( 84,302)

 Proceeds from sale of nuclear fuel
 32,937
 37,198
 16,279

 Proceeds from nuclear decommissioning trust fund sales
 117,123
 248,191
 530,628

 Investment in nuclear decommissioning trust funds
 ( 139,280)
 ( 269,497)
 ( 524,783)

 Payment for purchase of assets
 —
 ( 1,044)
 ( 131,770)

 Change in money pool receivable - net
 —
 —
 3,110

 Litigation proceeds for reimbursement of spent nuclear fuel storage costs
 17,933
 —
 —

 1,608
 ( 1,626)
 —

 ( 1,032,952)
 ( 852,794)
 ( 898,193)

 1,093,253
 232,731
 719,284

 ( 597,720)
 ( 28,521)
 ( 728,917)

 —
 —

 ( 35,410)
 40,891
 139,904

 Common equity distributions paid
 ( 417,000)
 ( 86,000)
 ( 50,000)

 Other
 47,162
 ( 13,676)
 38,291

 Net cash flow provided by financing activities
 90,285
 145,425
 169,764

 ( 1,646)
 ( 7,637)
 ( 179,213)

 5,278
 12,915
 192,128

 $ 3,632
 $ 5,278
 $ 12,915

 $ 169,173
 $ 147,060
 $ 143,561

 $ 2,705
 ($ 2,753)
 ($ 18,933)

 $ 36,264
 $ 93,189
 $ 35,616

 2023
 2022

 Cash
 $ 520
 $ 1,911

 3,112
 3,367

 3,632
 5,278

 157,520
 140,513

 ( 7,182)
 ( 6,528)

 124,672
 45,336

 Other
 89,532
 101,096

 117,119
 116,816

 481,661
 397,233

 —
 139,739

 57,495
 51,144

 358,302
 288,260

 Deferred nuclear refueling outage costs
 35,463
 56,443

 40,866
 26,576

 TOTAL
 977,419
 964,673

 Decommissioning trust funds
 1,414,009
 1,199,860

 Other
 2,414

 TOTAL
 1,414,810
 1,202,274

 14,821,814
 14,077,844

 340,601
 417,244

 213,722
 176,174

 15,376,137
 14,671,262

 6,002,203
 5,729,304

 9,373,934
 8,941,958

 1,885,361
 1,810,281

 —
 68,883

 Other
 21,334
 18,507

 TOTAL
 1,906,695
 1,897,671

 $ 13,672,858
 $ 13,006,576

 2023
 2022

 $ 375,000
 $ 290,000

 225,344
 276,362

 Other
 215,502
 310,339

 113,186
 102,799

 105,151
 100,526

 35,370
 18,816

 88,282
 —

 Other
 55,683
 43,394

 TOTAL
 1,213,518
 1,142,236

 1,437,053
 1,498,234

 27,270
 28,472

 392,496
 435,157

 759,181
 475,758

 1,560,057
 1,472,736

 58,959
 79,998

 8,901
 118,020

 4,298,080
 3,876,500

 Other
 156,673
 97,650

 TOTAL
 8,698,670
 8,082,525

 Member's equity
 3,739,071
 3,753,990

 Noncontrolling interest
 21,599
 27,825

 TOTAL
 3,760,670
 3,781,815

 $ 13,672,858
 $ 13,006,576

 Noncontrolling Interest
 Member's Equity
 Total

 $ —
 $ 3,276,169
 $ 3,276,169

 ( 18,092)
 316,576
 298,484

 —
 ( 50,000)
 ( 50,000)

 —

 $ 33,110
 $ 3,542,745
 $ 3,575,855

 ( 4,358)
 297,245
 292,887

 —
 ( 86,000)
 ( 86,000)

 Distributions to noncontrolling interest
 ( 927)
 —
 ( 927)

 $ 27,825
 $ 3,753,990
 $ 3,781,815

 ( 5,231)
 402,081
 396,850

 —
 ( 417,000)
 ( 417,000)

 Distributions to noncontrolling interest
 ( 995)
 —
 ( 995)

 $ 21,599
 $ 3,739,071
 $ 3,760,670

 Net income increased $417.5 million primarily due to the net effects of Entergy Louisiana's storm cost securitization in March 2023, including a $133.4 million reduction in income tax expense, partially offset by a $103.4 million ($76.4 million net-of-tax) regulatory charge to reflect Entergy Louisiana's obligation to provide credits to its customers as described in an LPSC ancillary order issued as part of the securitization regulatory proceeding; a $179.1 million reduction in income tax expense in 2023 as a result of the resolution of the 2016-2018 IRS audit, partially offset by a $38 million regulatory charge ($27.8 million net-of-tax) to reflect credits expected to be provided to customers; the reversal of a $105.6 million regulatory liability, associated with the Hurricane Isaac securitization, recognized in 2017 as a result of the Tax Cuts and Jobs Act, recorded in fourth quarter 2023, as part of the settlement of Entergy Louisiana's test year 2017 formula rate plan filing; higher retail electric price; higher other income; lower other operation and maintenance expenses; and higher volume/weather. The net income increase was partially offset by the net effects of Entergy Louisiana's storm cost securitization in May 2022, including a $290 million reduction in income tax expense, partially offset by a $224.4 million ($165.4 million net-of-tax) regulatory charge to reflect Entergy Louisiana's obligation to provide credits to its customers as described in an LPSC ancillary order issued as part of the securitization regulatory proceeding, and higher depreciation and amortization expenses. See Note 2 to the financial statements for further discussion of the storm cost securitizations and the formula rate plan global settlement. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit.

 Following is an analysis of the change in operating revenues comparing 2023 to 2022:

 $6,338.8

 (1,368.1)

 Storm restoration carrying costs
 (6.9)

 Return of unprotected excess accumulated deferred income taxes to customers
 24.6

 40.8

 118.6

 $5,147.8

 Entergy Louisiana's results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. "Fuel, rider, and other revenues that do not significantly affect net income" includes the revenue variance associated with these items.

 Storm restoration carrying costs represent the equity component of storm restoration carrying costs recognized as part of the securitization of Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and

 Hurricane Ida restoration costs in May 2022 and the equity component of storm restoration carrying costs recognized as part of the securitization of Hurricane Ida restoration costs in March 2023. See Note 2 to the financial statements for discussion of the storm cost securitizations.

 The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through changes in the formula rate plan effective May 2018 in response to the enactment of the Tax Cuts and Jobs Act. In 2022, $24.6 million was returned to customers through reductions in operating revenues. There was no return of unprotected excess accumulated deferred income taxes to customers in 2023. There was no effect on net income as the reductions in operating revenues were offset by reductions in income tax expense. See Note 2 to the financial statements for discussion of regulatory activity regarding the Tax Cuts and Jobs Act.

 The volume/weather variance is primarily due to the effect of more favorable weather on residential and commercial sales.

 The retail electric price variance is primarily due to increases in formula rate plan revenues, including increases in the distribution and transmission recovery mechanisms, effective September 2022 and September 2023. See Note 2 to the financial statements for further discussion of the formula rate plan proceedings.

 Total electric energy sales for Entergy Louisiana for the years ended December 31, 2023 and 2022 are as follows:

 2023
 2022

 (GWh)

 14,207
 14,119

 11,074
 10,927

 31,599
 31,666
 —

 (2)

 57,681
 57,532
 —

 4,406
 5,416
 (19)

 1,534
 3,423
 (55)

 Total
 63,621
 66,371
 (4)

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

 Other operation and maintenance expenses decreased primarily due to:

 • a decrease of $27.9 million in compensation and benefits costs primarily due to lower health and welfare costs, including higher prescription drug rebates in second quarter 2023, a decrease in net periodic pension and other postretirement benefits service costs as a result of an increase in the discount rates used to value the benefits liabilities, and a revision to estimated incentive compensation expense in first quarter 2023. See "Critical Accounting Estimates" below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;
 • a decrease of $25.1 million in transmission costs allocated by MISO. See Note 2 to the financial statements for further information on the recovery of these costs;
 • a decrease of $12.3 million in non-nuclear generation expenses primarily due to a lower scope of work, including during plant outages, performed in 2023 as compared to 2022;

 • a decrease of $8.2 million in nuclear generation expenses primarily due to a lower scope of work performed in 2023 as compared to 2022, lower nuclear labor costs, and lower costs associated with materials and supplies in 2023 as compared to 2022; and
 • a decrease of $7.2 million in customer service center support costs primarily due to lower contract costs.

 • an increase of $15.9 million in contract costs related to operational performance, customer service, and organizational health initiatives;
 • an increase of $6.1 million in insurance expenses primarily due to lower nuclear insurance refunds received in 2023; and

 Depreciation and amortization expenses increased primarily due to additions to plant in service.

 Other regulatory charges (credits) - net includes:

 • a regulatory charge of $103.4 million, recorded in first quarter 2023, to reflect Entergy Louisiana's obligation to provide credits to its customers as described in an LPSC ancillary order issued in the Hurricane Ida securitization regulatory proceeding. See Note 2 to the financial statements for discussion of the March 2023 storm cost securitization;
 • a regulatory charge of $224.4 million, recorded in second quarter 2022, to reflect Entergy Louisiana's obligation to provide credits to its customers as described in an LPSC ancillary order issued in the Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida securitization regulatory proceeding. See Note 2 to the financial statements for discussion of the May 2022 storm cost securitization; and
 • a regulatory charge of $38 million, recorded in fourth quarter 2023, to reflect credits expected to be provided to customers as a result of the resolution of the 2016-2018 IRS audit. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit.

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

 Other income increased primarily due to:

 • an increase of $113 million in affiliated dividend income from affiliated preferred membership interests related to storm cost securitizations;
 • a $31.6 million charge, recorded in second quarter 2022, for the LURC's 1% beneficial interest in the storm trust I established as part of the Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida May 2022 storm cost securitization as compared to a $14.6 million charge, recorded in first quarter 2023, for the LURC's 1% beneficial interest in the storm trust II established as part of the Hurricane Ida March 2023 storm cost securitization. See Note 2 to the financial statements for discussion of the storm cost securitizations;
 • changes in decommissioning trust fund activity, including portfolio rebalancing of certain decommissioning trust funds in 2022; and
 • an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2023.

 • a decrease of $20.6 million in the amount of storm restoration carrying costs recognized in 2023 as compared to 2022, primarily related to Hurricane Ida. See Note 2 to the financial statements for discussion of the storm cost securitizations; and
 • lower interest income from carrying costs related to the deferred fuel balance.

 The effective income tax rates were (19.3%) for 2023 and (23.5%) for 2022. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.

 See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations" in Item 7 of Entergy Louisiana's Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.

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

 Planned Sale of Gas Distribution Business

 See the "Planned Sale of Gas Distribution Businesses" section of Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis for discussion of the purchase and sale agreement for the sale of Entergy Louisiana's gas distribution business.

 Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:

 2023
 2022
 2021

 $56,613
 $18,573
 $728,020

 2,032,120
 1,177,508
 1,052,526

 (3,039,456)
 (4,707,711)
 (3,700,199)

 953,495
 3,568,243
 1,938,226

 (53,841)
 38,040
 (709,447)

 $2,772
 $56,613
 $18,573

 Net cash flow provided by operating activities increased $854.6 million in 2023 primarily due to:

 • a decrease of $236.7 million in storm spending primarily due to Hurricane Ida restoration efforts in 2022;
 • an increase of $42.4 million in interest received primarily due to shorter-term financing interest earnings and interest on storm reserve escrow accounts. See Note 2 to the financial statements for a discussion of shorter-term financing interest earnings;
 • the refund of $27.8 million received from System Energy 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 Note 2 to the financial statements for further discussion of the refund and the related proceedings;
 • a decrease of $9.1 million in pension contributions in 2023. 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;
 • lower fuel costs and the timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery; and
 • the timing of payments to vendors.

 The increase was partially offset by lower collections from customers and an increase of $14.4 million in interest paid.

 Net cash flow used in investing activities decreased $1,668.3 million in 2023 primarily due to:

 • an increase in investment in affiliates in 2022 due to the $3,163.6 million purchase by the storm trust I of preferred membership interests issued by an Entergy affiliate, partially offset by the $1,390.6 million redemption of preferred membership interests. See Note 2 to the financial statements for a discussion of the May 2022 storm cost securitization;
 • a decrease of $727 million in distribution construction expenditures primarily due to lower capital expenditures for storm restoration in 2023. The decrease in storm restoration expenditures is primarily due to Hurricane Ida restoration efforts in 2022;
 • a decrease of $265.4 million in transmission construction expenditures primarily due to lower capital expenditures for storm restoration in 2023 and decreased spending on various transmission projects in 2023. The decrease in storm restoration expenditures is primarily due to Hurricane Ida restoration efforts in 2022;
 •$125 million of redemptions in 2023 of preferred membership interests held by the storm trust I, as part of periodic redemptions that are expected to occur, subject to certain conditions, for the preferred membership interests that were issued in connection with the May 2022 storm cost securitization. See Note 2 to the financial statements for a discussion of the May 2022 storm cost securitization and the storm trust I's investment in preferred membership interests; and
 • net receipts from storm reserve escrow accounts of $49.6 million in 2023 as compared to net payments to storm reserve escrow accounts of $293.4 million in 2022.

 • an increase in investment in affiliates in 2023 due to the $1,457.7 million purchase by the storm trust II of preferred membership interests issued by an Entergy affiliate. See Note 2 to the financial statements for a discussion of the March 2023 storm cost securitization and the storm trust II's investment in preferred membership interests;

 • an increase of $110.2 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2023;
 • an increase of $47.5 million as a result of fluctuations in nuclear fuel activity due to variations from year to year in the timing and pricing of fuel reload requirements, materials and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and

 Decreases in Entergy Louisiana's receivables from the money pool are a source of cash flow, and Entergy Louisiana's receivable from the money pool decreased $14.5 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries' dependence on external short-term borrowings.

 Net cash flow provided by financing activities decreased $2,614.7 million in 2023 primarily due to:

 • proceeds from securitization of $1.5 billion received by the storm trust II in 2023 as compared to proceeds from securitization of $3.2 billion received by the storm trust I in 2022;
 • the repayment, at maturity, of $665 million of 0.62% Series mortgage bonds in November 2023;
 • the issuance of $500 million of 4.75% Series mortgage bonds in August 2022;
 • the repayment, at maturity, of $325 million of 4.05% Series mortgage bonds in September 2023;
 • the repayment, prior to maturity, of $300 million of 5.59% Series mortgage bonds in December 2023;
 • an increase of $36.8 million in common equity distributions paid in 2023 in order to maintain Entergy Louisiana's capital structure;
 • the repayment, at maturity, of $20 million of 3.22% Series I notes by the Entergy Louisiana Waterford variable interest entity in December 2023; and

 • a capital contribution of approximately $1.5 billion in 2023 as compared to a capital contribution of approximately $1 billion in 2022, both received indirectly from Entergy Corporation and related to the March 2023 storm cost securitization and the May 2022 storm cost securitization, respectively;
 • the repayment, prior to maturity, of $435 million, a portion of the outstanding principal, of 0.62% Series mortgage bonds in May 2022;
 • the repayment, at maturity, of $200 million of 3.3% Series mortgage bonds in December 2022;
 • the issuance of $70 million of 5.94% Series J notes by the Entergy Louisiana Waterford variable interest entity in September 2023; and
 • a decrease of $25 million in 2023 in net repayments on Entergy Louisiana's revolving credit facility.

 Decreases in Entergy Louisiana's payable to the money pool are a use of cash flow, and Entergy Louisiana's payable to the money pool decreased $69.9 million in 2023 compared to increasing by $226.1 million in 2022.

 See Note 5 to the financial statements for details of long-term debt. See Note 2 to the financial statements for discussion of the storm cost securitizations.

 See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow" in Item 7 of Entergy Louisiana's Annual Report on Form 10-K for the year ended

 December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.

 Entergy Louisiana's debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio for Entergy Louisiana is primarily due to the $1.5 billion capital contribution received indirectly from Entergy Corporation in March 2023 and the net retirement of long-term debt in 2023.

2023
2022

 44.9
 %
 53.0
 %

 0.0
 %
 (0.1
 %)

 Net debt to net capital (non-GAAP)
 44.9
 %
 52.9
 %

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

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

 Entergy Louisiana requires capital resources for:

 • working capital purposes, including the financing of fuel and purchased power costs; and
 • distribution and interest payments.

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

 2024
 2025
 2026

 $435
 $805
 $780

 1,220

 Total
 $1,830
 $2,465
 $2,850

 In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana includes investments in generation projects to modernize, decarbonize, and diversify Entergy Louisiana's portfolio; investments in River Bend and Waterford 3; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting renewables expansion and customer growth; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.

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

 2024
 2025
 2026

 $1,719
 $659
 $983
 $1,419
 $9,635

 $17
 $14
 $11
 $13
 $4

 $6
 $5
 $4
 $6
 $3

 Entergy Louisiana currently expects to contribute approximately $48.4 million to its qualified pension plans and approximately $15 million to its other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See "Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits" below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

 Entergy Louisiana has $128.4 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

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

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

 2021 Solar Certification and the Geaux Green Option

 In November 2021, Entergy Louisiana filed an application with the LPSC seeking certification of and approval for the addition of four new solar photovoltaic resources with a combined nameplate capacity of 475 megawatts (the 2021 Solar Portfolio) and the implementation of a new green tariff, the Geaux Green Option (Rider GGO). The 2021 Solar Portfolio consists of four resources that are expected to provide $242 million in net benefits to Entergy Louisiana's customers. These resources, all of which would be constructed in Louisiana, include (i) the Vacherie Facility, a 150 megawatt resource in St. James Parish; (ii) the Sunlight Road Facility, a 50 megawatt resource in Washington Parish; (iii) the St. Jacques Facility, a 150 megawatt resource in St. James Parish; and (iv) the Elizabeth Facility, a 125 megawatt resource in Allen Parish. The St. Jacques Facility would be acquired through a build-own-transfer agreement; the remaining resources involve power purchase agreements. The Sunlight Road Facility and the Elizabeth Facility have estimated in service dates in 2024, and the Vacherie Facility and the St. Jacques Facility originally had estimated in service dates in 2025, but are now expected to be no sooner than 2027. The filing proposed to recover the costs of the power purchase agreements through the fuel adjustment clause and the formula rate plan and the acquisition costs through the formula rate plan.

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

 In March 2022 direct testimony from Walmart, the Louisiana Energy Users Group (LEUG), and the LPSC staff was filed. Each party recommended that the LPSC approve the resources proposed in Entergy Louisiana's application, and the LPSC staff witness indicated that the process through which Entergy Louisiana solicited or obtained the proposals for the resources complied with applicable LPSC orders. The LPSC staff and LEUG's witnesses made recommendations to modify the proposed Rider GGO and Entergy Louisiana's proposed rate relief. In April 2022 the LPSC staff and LEUG filed cross-answering testimony concerning each other's proposed modifications to Rider GGO and the proposed rate recovery. Entergy Louisiana filed rebuttal testimony in June 2022. In August 2022 the parties reached a settlement certifying the 2021 Solar Portfolio and approving implementation of Rider GGO. In September 2022 the LPSC approved the settlement. Following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities until the later of March 2023 or the completion of an environmental and economic impact study. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish's land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparties to the Vacherie and St. Jacques facilities regarding amendments to the respective agreements to address the impact of the St. James Parish ordinance, and the facilities are expected to reach commercial operation no sooner than 2027, depending upon agreement by the parties on the terms of the amendments. In September 2023, Entergy Louisiana reported to the LPSC that it also entered into amended agreements related to the Sunlight Road and Elizabeth facilities. Both facilities are still expected to achieve commercial operation in 2024.

 2022 Solar Portfolio and Expansion of the Geaux Green Option

 In February 2023, Entergy Louisiana filed an application with the LPSC seeking certification of the Iberville/Coastal Prairie facility, which will provide 175 MW of capacity through a PPA with a third party, and the Sterlington facility, a 49 MW self-build project located near the deactivated Sterlington power plant (the 2022 Solar Portfolio). Entergy Louisiana is seeking to include these resources within the portfolio supporting the Rider GGO

 rate schedule to help fulfill customer interest in access to renewable energy. Entergy Louisiana has requested the costs of these facilities, as offset by Rider GGO revenues, be deemed eligible for recovery in accordance with the terms of the formula rate plan and fuel adjustment clause rate mechanisms that exist at the time the facilities are placed into service. In January 2024, the parties filed an uncontested stipulated settlement agreement on the key issues in the case, which stated that the 2022 Solar Portfolio should be constructed, found that Entergy Louisiana's proposed cost recovery mechanisms were appropriate, and confirmed the resources' eligibility for inclusion in Rider GGO. The settlement was approved by the LPSC in January 2024. The Sterlington facility is expected to achieve commercial operation in January 2026.

 Alternative RFP and Certification

 In March 2023, Entergy Louisiana made the first phase of a bifurcated filing to seek approval from the LPSC for an alternative to the requests for proposals (RFP) process that would enable the acquisition of up to 3 GW of solar resources on a faster timeline than the current RFP and certification process allows. The initial phase of the filing established the need for the acquisition of additional resources and the need for an alternative to the RFP process. The second phase of the filing, which contains the details of the proposal for the alternative competitive procurement process and the information necessary to support certification, was filed in May 2023. In addition to the acquisition of up to 3 GW of solar resources, the filing also seeks approval of a new renewable energy credits-based tariff, Rider Geaux ZERO. Several parties have intervened, and a procedural schedule was established in May 2023 with a hearing scheduled for March 2024. In October 2023 the LPSC staff and intervenors filed testimony, with the LPSC staff supporting the amount of solar resources to be acquired and the alternative RFP process. The LPSC staff also supported, subject to certain recommendations, the proposed framework for evaluation and certification of the solar resources by the LPSC and the proposed tariff.

 System Resilience and Storm Hardening

 In December 2022, Entergy Louisiana filed an application with the LPSC seeking a public interest finding regarding Phase I of Entergy Louisiana's Future Ready resilience plan and approval of a rider mechanism to recover the program's costs. Phase I reflects the first five years of a ten-year resilience plan and includes investment of approximately $5 billion, including hardening investment, transmission dead-end structures, enhanced vegetation management, and telecommunications improvement. In April 2023 a procedural schedule was established with a hearing scheduled for January 2024. The LPSC staff and certain intervenors filed direct testimony in August, September, and October 2023. The LPSC staff filed cross-answering testimony in October 2023. The testimony largely supports implementation of some level of accelerated investment in resilience, but raises various issues related to the magnitude of the investment, the cost recovery mechanism applicable to the investment, and the ratemaking for the investment. In January 2024 the hearing in this matter was rescheduled to April 2024.

 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.

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

 • storm reserve escrow accounts;
 • debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;

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

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

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

 2023
 2022
 2021
 2020

 ($156,166)
 ($226,114)
 $14,539
 $13,426

 Entergy Louisiana has a credit facility in the amount of $350 million scheduled to expire in June 2028. The credit facility includes fronting commitments for the issuance of letters of credit against $15 million of the borrowing capacity of the facility. As of December 31, 2023, there were no cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy Louisiana is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2023, $17.1 million in letters of credit were outstanding under Entergy Louisiana's uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

 The Entergy Louisiana nuclear fuel company variable interest entities have two separate credit facilities, each in the amount of $105 million and scheduled to expire in June 2025. As of December 31, 2023, $46.6 million in loans were outstanding under the credit facility for the Entergy Louisiana River Bend nuclear fuel company variable interest entity. As of December 31, 2023, $29.5 million in loans were outstanding under the Entergy Louisiana Waterford nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facilities.

 Entergy Louisiana obtained authorizations from the FERC through April 2025 for the following:

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

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

 Hurricane Ida

 As discussed in Note 2 to the financial statements, in August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana's service area. In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to Louisiana. 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 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 in Note 2 to the financial statements, 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 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 Louisiana Local Government Facilities and Community Development Authority (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, LLC, a majority owned indirect subsidiary of Entergy. 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 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.

 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.

 Nelson Industrial Steam Company

 Entergy Louisiana is a partner in the Nelson Industrial Steam Company (NISCO) partnership which owns two petroleum coke generating units. In April 2023 these generating units suspended operations in the MISO market, and Entergy Louisiana currently is working to wind up the NISCO partnership, which will ultimately result in ownership of the generating units transferring to Entergy Louisiana. In November 2023 the FERC issued an order providing Section 203 of the Federal Power Act approval for any subsequent transfer of the facilities to Entergy Louisiana. Entergy Louisiana is evaluating the effect of the transaction on its results of operations, cash flows, and financial condition, but at this time does not expect the effect to be material.

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

 Retail Rates - Electric

 Filings with the LPSC

 2017 Formula Rate Plan Filing

 In June 2018, Entergy Louisiana filed its formula rate plan evaluation report for its 2017 calendar year operations. The 2017 test year evaluation report produced an earned return on equity of 8.16%, due in large part to revenue-neutral realignments to other recovery mechanisms. Without these realignments, the evaluation report produces an earned return on equity of 9.88% and a resulting base rider formula rate plan revenue increase of $4.8 million. Excluding the Tax Cuts and Jobs Act credits provided for by the tax reform adjustment mechanisms, total formula rate plan revenues were further increased by a total of $98 million as a result of the evaluation report due to adjustments to the additional capacity and MISO cost recovery mechanisms of the formula rate plan, and implementation of the transmission recovery mechanism. In August 2018, Entergy Louisiana filed a supplemental formula rate plan evaluation report to reflect changes from the 2016 test year formula rate plan proceedings, a decrease to the transmission recovery mechanism to reflect lower actual capital additions, and a decrease to evaluation period expenses to reflect the terms of a new power sales agreement. Based on the August 2018 update, Entergy Louisiana recognized a total decrease in formula rate plan revenue of approximately $17.6 million. Results of the updated 2017 evaluation report filing were implemented with the September 2018 billing month subject to refund and review by the LPSC staff and intervenors. In accordance with the terms of the formula rate plan, in September 2018 the LPSC staff filed its report of objections/reservations and intervenors submitted their responses to Entergy Louisiana's original formula rate plan evaluation report and supplemental compliance updates. In August 2021 the LPSC staff issued a letter updating its objections/reservations for the 2017 test year formula rate plan evaluation report. In its letter, the LPSC staff reiterated its original objections/reservations. The LPSC staff further reserved its rights for future proceedings and to dispute future proposed adjustments to the 2017 test year formula rate plan evaluation report. The LPSC staff withdrew all other objections/reservations.

 In November 2023 the LPSC approved 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. See "Formula Rate Plan Global Settlement" below for further discussion of the settlement.

 2018 Formula Rate Plan Filing

 In May 2019, Entergy Louisiana filed its formula rate plan evaluation report for its 2018 calendar year operations. The 2018 test year evaluation report produced an earned return on common equity of 10.61% leading to a base rider formula rate plan revenue decrease of $8.9 million. While base rider formula rate plan revenue decreased as a result of this filing, overall formula rate plan revenues increased by approximately $118.7 million. This outcome was primarily driven by a reduction to the credits previously flowed through the tax reform adjustment mechanism and an increase in the transmission recovery mechanism, partially offset by reductions in the additional capacity mechanism revenue requirements and extraordinary cost items. The filing was subject to review by the LPSC. Resulting rates were implemented in September 2019, subject to refund.

 Several parties intervened in the proceeding and the LPSC staff filed its report of objections/reservations in accordance with the applicable provisions of the formula rate plan. In August 2021 the LPSC staff issued a letter updating its objections/reservations for the 2018 test year formula rate plan evaluation report. In its letter, the LPSC staff reiterated its original objection/reservation pertaining to test year expenses billed from Entergy Services to Entergy Louisiana and outstanding issues from the 2017 test year formula rate plan evaluation report. The LPSC staff withdrew all other objections/reservations.

 Commercial operation at Lake Charles Power Station commenced in March 2020. In March 2020, Entergy Louisiana filed an update to its 2018 formula rate plan evaluation report to include the estimated first-year revenue requirement of $108 million associated with the Lake Charles Power Station. The resulting interim adjustment to rates became effective with the first billing cycle of April 2020.

 In November 2023 the LPSC approved 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. See "Formula Rate Plan Global Settlement" below for further discussion of the settlement.

 2019 Formula Rate Plan Filing

 In May 2020, Entergy Louisiana filed with the LPSC its formula rate plan evaluation report for its 2019 calendar year operations. The 2019 test year evaluation report produced an earned return on common equity of 9.66%. As such, no change to base rider formula rate plan revenue is required. Although base rider formula rate plan revenue did not change as a result of this filing, overall formula rate plan revenues increased by approximately $103 million. This outcome is driven by the removal of prior year credits associated with the sale of the Willow Glen Power Station and an increase in the transmission recovery mechanism. Also contributing to the overall change was an increase in legacy formula rate plan revenue requirements driven by legacy Entergy Louisiana capacity cost true-ups and higher annualized legacy Entergy Gulf States Louisiana revenues due to higher billing determinants, offset by reductions in MISO cost recovery mechanism and tax reform adjustment mechanism revenue requirements. In August 2020 the LPSC staff submitted a list of items for which it needs additional information to confirm the accuracy and compliance of the 2019 test year evaluation report. The LPSC staff objected to a proposed revenue neutral adjustment regarding a certain rider as being beyond the scope of permitted formula rate plan adjustments. Rates reflected in the May 2020 filing, with the exception of a revenue neutral rider adjustment, and as updated in an August 2020 filing, were implemented in September 2020, subject to refund. In August 2021 the LPSC staff issued a letter updating its objections/reservations for the 2019 test year formula rate plan filing. In its letter, the LPSC staff disputed Entergy Louisiana's exclusion of approximately $251 thousand of interest income allocated from Entergy Operations and Entergy Services to Entergy Louisiana to the extent that there are other adjustments that would move Entergy Louisiana out of the formula rate plan deadband. The LPSC staff reserved the right to further contest the issue in future proceedings. The LPSC staff further reserved outstanding issues from the 2017 and 2018 formula rate plan evaluation reports and withdrew all other remaining objections/reservations.

 In November 2023 the LPSC approved 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. See "Formula Rate Plan Global Settlement" below for further discussion of the settlement.

 Request for Extension and Modification of Formula Rate Plan

 In May 2020, Entergy Louisiana filed with the LPSC its application for authority to extend its formula rate plan. In its application, Entergy Louisiana sought to maintain a 9.8% return on equity, with a bandwidth of 60 basis points above and below the midpoint, with a first-year midpoint reset. The parties reached a settlement in April 2021 regarding Entergy Louisiana's proposed formula rate plan extension. In May 2021 the LPSC approved the uncontested settlement. Key terms of the settlement include: a three year term (test years 2020, 2021, and 2022) covering a rate-effective period of September 2021 through August 2024; a 9.50% return on equity, with a smaller, 50 basis point deadband above and below (9.0%-10.0%); elimination of sharing if earnings are outside the deadband; a $63 million rate increase for test year 2020 (exclusive of riders); continuation of existing riders (transmission, additional capacity, etc.); addition of a distribution recovery mechanism permitting $225 million per year of distribution investment above a baseline level to be recovered dollar for dollar; modification of the tax mechanism to allow timely rate changes in the event the federal corporate income tax rate is changed from 21%; a cumulative rate increase limit of $70 million (exclusive of riders) for test years 2021 and 2022; and deferral of up to $7 million per year in 2021 and 2022 of expenditures on vegetation management for outside of right of way hazard trees.

 2020 Formula Rate Plan Filing

 In June 2021, Entergy Louisiana filed its formula rate plan evaluation report for its 2020 calendar year operations. The 2020 test year evaluation report produced an earned return on common equity of 8.45%, with a base formula rate plan revenue increase of $63 million. Certain reductions in formula rate plan revenue driven by lower sales volumes, reductions in capacity cost and net MISO cost, and higher credits resulting from the Tax Cuts and Jobs Act offset the base formula rate plan revenue increase, leading to a net increase in formula rate plan revenue of $50.7 million. The report also included multiple new adjustments to account for, among other things, the calculation of distribution recovery mechanism revenues. The effects of the changes to total formula rate plan revenue were different for each legacy company, primarily due to differences in the legacy companies' capacity cost changes, including the effect of true-ups. Legacy Entergy Louisiana formula rate plan revenues increased by $27 million and legacy Entergy Gulf States Louisiana formula rate plan revenues increased by $23.7 million. Subject to LPSC review, the resulting changes became effective for bills rendered during the first billing cycle of September 2021, subject to refund. Discovery commenced in the proceeding. In August 2021, Entergy Louisiana submitted an update to its evaluation report to account for various changes. Relative to the June 2021 filing, the total formula rate plan revenue increased by $14.2 million to an updated total of $64.9 million. Legacy Entergy Louisiana formula rate plan revenues increased by $32.8 million and legacy Entergy Gulf States Louisiana formula rate plan revenues increased by $32.1 million. The results of the 2020 test year evaluation report bandwidth calculation were unchanged as there was no change in the earned return on common equity of 8.45%. In September 2021 the LPSC staff filed a letter with a general statement of objections/reservations because it had not completed its review and indicated it would update the letter once its review was complete. Should the parties be unable to resolve any objections, those issues will be set for hearing, with recovery of the associated costs subject to refund.

 In November 2023 the LPSC approved 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. See "Formula Rate Plan Global Settlement" below for further discussion of the settlement.

 In May 2022, Entergy Louisiana filed its formula rate plan evaluation report for its 2021 calendar year operations. The 2021 test year evaluation report produced an earned return on common equity of 8.33%, with a base formula rate plan revenue increase of $65.3 million. Other increases in formula rate plan revenue driven by reductions in Tax Cut and Jobs Act credits and additions to transmission and distribution plant in service reflected through the transmission recovery mechanism and distribution recovery mechanism are partly offset by an increase in net MISO revenues, leading to a net increase in formula rate plan revenue of $152.9 million. The effects of the changes to total formula rate plan revenue are different for each legacy company, primarily due to differences in the legacy companies' capacity cost changes, including the effect of true-ups. Legacy Entergy Louisiana formula rate plan revenues increased by $86 million and legacy Entergy Gulf States Louisiana formula rate plan revenues increased by $66.9 million. In August 2022 the LPSC staff filed a list of objections/reservations, including outstanding issues from the test years 2017-2020 formula rate plan filings, utilizing the extraordinary cost mechanism to address one-time changes such as state tax rate changes, and failing to include an adjustment for revenues not received as a result of Hurricane Ida. Subject to LPSC review, the resulting changes to formula rate plan revenues became effective for bills rendered during the first billing cycle of September 2022, subject to refund.

 In November 2023 the LPSC approved 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. See "Formula Rate Plan Global Settlement" below for further discussion of the settlement.

 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 are only being 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 are 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 is 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, is $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.

 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 contains a dual-path request to update rates through either: (1) extension of Entergy Louisiana's current formula rate plan (with certain modifications) for three years (the Rate Mitigation Proposal), which is Entergy Louisiana's recommended path; or (2) implementation of rates resulting from a cost-of-service study (the Rate Case path). The application complies 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 supports the need to extend Entergy Louisiana's formula rate plan with credit supportive mechanisms to facilitate investment in the distribution, transmission, and generation functions.

 The Rate Case path proposes a 2024-2026 test year formula rate plan with an initial revenue requirement increase of $430 million, net of $17 million of one-time credits, and a return on common equity of 10.5%. Depreciation rates would be updated for all asset classes. The Rate Mitigation Proposal proposes a 2023-2025 test year formula rate plan with an expected initial revenue requirement increase of $173 million, also net of $17 million of one-time credits, based on a 2023 formula rate plan test year, and a return on common equity of 10.0%. Depreciation rates would be updated only for nuclear assets and would be phased in over three years.

 Under both paths, Entergy Louisiana's filing proposes removing the cap on amounts allowed to be recovered through the distribution recovery mechanism and continuing the distribution recovery mechanism performance accountability targets, which tie Entergy Louisiana's ability to fully recover its distribution recovery mechanism investments to its reliability performance. Entergy Louisiana's filing also includes new customer-centric programs specifically focused on affordability, including reducing late fees and certain other fees assessed to customers, lowering additional facilities charge rates, providing eligible low-income seniors with monthly discounts on their electric bill, and adding new voluntary customer options to support new transportation electrification technologies. A status conference was held in October 2023 at which a procedural schedule was adopted that includes three technical conferences, the last of which is in March 2024, and a hearing date in August 2024.

 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, associated with the Hurricane Isaac securitization, recognized in 2017 as a result of the Tax Cuts and Jobs Act. See Note 3 to the financial statements for further discussion of the reversal of the regulatory liability.

 Investigation of Costs Billed by Entergy Services

 In November 2018 the LPSC issued a notice of proceeding initiating an investigation into costs incurred by Entergy Services that are included in the retail rates of Entergy Louisiana. As stated in the notice of proceeding, the LPSC observed an increase in capital construction-related costs incurred by Entergy Services. Discovery was issued and included efforts to seek highly detailed information on a broad range of matters unrelated to the scope of the audit. There has been no further activity in the investigation since May 2019.

 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 include estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.

 In February 2021, Entergy Louisiana incurred extraordinary fuel costs associated with the February 2021 winter storms. To mitigate the effect of these costs on customer bills, in March 2021, Entergy Louisiana requested and the LPSC approved the deferral and recovery of $166 million in incremental fuel costs over five months beginning in April 2021. The incremental fuel costs remain subject to review for reasonableness and eligibility for recovery through the fuel adjustment clause mechanism. The final amount of incremental fuel costs is subject to

 change through the resettlement process. At its April 2021 meeting, the LPSC authorized its staff to review the prudence of the February 2021 fuel costs incurred by all LPSC-jurisdictional utilities, including both gas and electric utilities. At its June 2021 meeting, the LPSC approved the hiring of consultants to assist its staff in this review. In May 2022 the LPSC staff issued an audit report regarding Entergy Louisiana's fuel adjustment clause charges (for its electric operations) recommending no financial disallowances, but including several prospective recommendations. Responsive testimony was filed by one intervenor and the parties agreed to suspend any procedural schedule and move toward settlement discussions to close the matter. Also in May 2022 the LPSC staff issued an audit report regarding Entergy Louisiana's purchased gas adjustment charges (for its gas operations) that did not propose any financial disallowances. The LPSC staff and Entergy Louisiana submitted a joint report on the audit report and draft order to the LPSC concluding that Entergy Louisiana's gas distribution operations and fuel costs were not significantly adversely affected by the February 2021 winter storms and the resulting increase in natural gas prices. The LPSC issued an order approving the joint report in October 2022.

 In March 2021 the LPSC staff provided notice of an audit of Entergy Louisiana's purchased gas adjustment clause filings covering the period January 2018 through December 2020. The audit included a review of the reasonableness of charges flowed through Entergy Louisiana's purchased gas adjustment clause for that period. In August 2023 the LPSC submitted its audit report and found that materially all costs recovered through the purchased gas adjustment filings were reasonable and eligible for recovery through the purchased gas adjustment clause. The LPSC approved the report in December 2023.

 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 is 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 purchased gas adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana's purchased gas adjustment clause for the period from 2021 through 2022. Discovery is ongoing, and no audit report has been filed.

 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.

 COVID-19 Orders

 In April 2020 the LPSC issued an order authorizing utilities to record as a regulatory asset expenses incurred from the suspension of disconnections and collection of late fees imposed by LPSC orders associated with the COVID-19 pandemic. In addition, utilities may seek future recovery, subject to LPSC review and approval, of losses and expenses incurred due to compliance with the LPSC's COVID-19 orders. The suspension of late fees and disconnects for non-pay was extended until the first billing cycle after July 16, 2020. In January 2021, Entergy Louisiana resumed disconnections for customers in all customer classes with past-due balances that had not made payment arrangements. Utilities seeking to recover the regulatory asset must formally petition the LPSC to do so, identifying the direct and indirect costs for which recovery is sought. Any such request is subject to LPSC review and approval. In April 2023, Entergy Louisiana filed an application proposing to utilize approximately $1.6 billion in certain low interest debt to generate earnings to apply toward the reduction of the COVID-19 regulatory asset, as well as to conduct additional outside right-of-way vegetation management activities and fund the minor storm reserve account. In that filing, Entergy Louisiana proposed to delay repayment of certain shorter-term first mortgage bonds that were issued to finance storm restoration costs until the costs could be securitized, and to invest the funds that otherwise would be used to repay those bonds in the money pool to take advantage of the spread between prevailing interest rates on investments in the money pool and the interest rates on the bonds. The LPSC

 approved Entergy Louisiana's requested relief in June 2023. A subsequent filing will be required to permit the LPSC to review the COVID-19 regulatory asset. As of December 31, 2023, Entergy Louisiana had a regulatory asset of $47.8 million for costs associated with the COVID-19 pandemic and a regulatory liability of $36.8 million for the deferred earnings related to the approximately $1.6 billion in low interest debt.

 Net Metering Rulemaking

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

 Industrial and Commercial Customers

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

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

 Entergy Louisiana owns and, through an affiliate, operates the River Bend and Waterford 3 nuclear generating plants and is, therefore, subject to the risks related to such ownership and operation. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, including the financial requirements to address emerging issues related to equipment reliability, to position Entergy Louisiana's nuclear fleet to meet its operational goals; the performance and capacity factors of these nuclear plants; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts of insurance recoveries for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of River Bend or Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Waterford 3's operating license expires in 2044 and River Bend's operating license expires in 2045.

 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. Waterford 3 is currently in Column 1, and River Bend is currently in Column 2.

 In July 2023 the NRC placed River Bend in Column 2, effective April 2023, based on failure to inspect wiring associated with the high pressure core spray system. In August 2023 the NRC issued a finding and notice of violation related to a radiation monitor calibration issue at River Bend. In December 2023, River Bend successfully completed the inspection on the high pressure core spray system issue and in February 2024, River Bend successfully completed the supplemental inspection for the radiation monitor calibration issue involving radiation monitor calibrations. River Bend will remain in Column 2 pending receipt of the formal report on the inspection, which is expected in first quarter 2024.

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

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

 Nuclear Decommissioning Costs

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

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

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

 Entergy Louisiana's qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See "Qualified Pension and Other Postretirement Benefits" in the "Critical Accounting Estimates" section of Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.

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

 $1,016
 $28,165

 $2,739
 $—

 0.25%
 $1,143
 $6,017

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

 $324
 $4,287

 0.25%
 $559
 $2,905

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

 Total qualified pension cost for Entergy Louisiana in 2023 was $69.5 million, including $40.4 million in settlement costs. Entergy Louisiana anticipates 2024 qualified pension cost to be $10.7 million. Entergy Louisiana contributed $44.6 million to its qualified pension plans in 2023 and estimates pension contributions will be approximately $48.4 million in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024 valuations are completed, which is expected by April 1, 2024.

 Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 2023 were $1.4 million. Entergy Louisiana expects 2024 postretirement health care and life insurance benefit income of approximately $701 thousand. Entergy Louisiana contributed $20.5 million to its other postretirement plans in 2023 and estimates that 2024 contributions will be approximately $15 million.

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

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

 We have audited the accompanying consolidated balance sheets of Entergy Louisiana, LLC and Subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, cash flows, and changes in equity (pages 368 through 374 and applicable items in pages 47 through 238), for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

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

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

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

 Critical Audit Matters

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

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

 The Company is subject to rate regulation by the Louisiana Public Service Commission (the "LPSC"), which has jurisdiction with respect to the rates of electric companies in Louisiana, and to wholesale rate regulation by the Federal Energy Regulatory Commission ("FERC"). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

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

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

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

 • We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management's controls over the initial recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
 • We evaluated the Company's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
 • We read relevant regulatory orders issued by the LPSC and the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the LPSC's and the FERC's treatment of similar costs under similar circumstances. We evaluated external information and compared to management's recorded regulatory asset and liability balances for completeness.
 • For regulatory matters in process, we inspected the Company's filings with the LPSC and the FERC and orders issued, and considered the filings with the LPSC and the FERC by intervenors that may impact the Company's future rates, for any evidence that might contradict management's assertions.
 • We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order, to assess management's assertion that amounts are probable of recovery or 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.

 Securitization Financing — Storm Cost Recovery Filings with Retail Regulators — Entergy Louisiana, LLC and Subsidiaries — Refer to Note 2 to the financial statements

 Hurricane Ida in 2021 caused significant damage to portions of the Company's service area within the state of Louisiana. In January 2023, the LPSC issued a Financing Order authorizing financing of $1.491 billion of system restoration costs utilizing the securitization process authorized by Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature's Regular Session of 2021 ("Act 55, as supplemented by Act 293"). In March 2023, the securitization financing closed, resulting in the issuance of $1.491 billion principal amount bonds by

 Louisiana Local Government Environmental Facilities and Community Development Authority ("LCDA"), a political subdivision of the State of Louisiana. The LCDA loaned the proceeds to the Louisiana Utilities Restoration Corporation ("LURC"), and the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust II (the "storm trust II"). The Company and the LURC each hold beneficial interests in the storm trust II.

 The Company does not report the bonds issued by the LCDA on its balance sheet 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 Company collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. The Company does not report the collection of system restoration charges as revenue because the Company 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 II is required to liquidate Entergy Finance Company preferred interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial. The Company consolidates the storm trust II as a variable interest entity and the LURC's 1% beneficial interest is shown as a noncontrolling interest in the financial statements.

 We identified management's conclusion that the bonds issued by the LCDA are the obligation of the LCDA 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 securitization financing transactions.

 Our audit procedures related to the Act 55, as supplemented by Act 293, securitization financing included the following, among others:

 • We tested the effectiveness of management's controls over the evaluation of the accounting impact of this securitization financing transaction, including the conclusion that the bonds issued by the LCDA are the obligation of the LCDA.
 • We evaluated the Company's disclosures related to the impacts of the Act 55, as supplemented by Act 293, securitization financing, including the balances recorded.
 • We read relevant regulatory and financing orders issued by the LPSC for the Company, the LURC, and the LCDA, and evaluated the external information to compare to management's conclusions.
 • We obtained an analysis from management and support from the Company's internal and external legal counsel regarding the legal status of the bonds issued by the LCDA and the system restoration property granted to the LURC to assess management's assertion that the bonds issued by the LCDA are the obligation of the LCDA.
 • With the assistance of professionals in our firm having expertise and experience in addressing the accounting for securitization financing transactions by regulated utilities, we evaluated the Company's conclusion, including the conclusion that the bonds issued by the LCDA are the obligation of the LCDA.

 Uncertain Tax Positions — Entergy Louisiana, LLC and Subsidiaries — Refer to Note 3 to the financial statements

 The Company accounts for uncertain income tax positions 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 fifty percent likely of being realized upon settlement. The Company has uncertain tax positions which require management to make judgments and assumptions to determine whether available information supports the assertion that the recognition threshold is met, particularly related to the technical merits and facts and circumstances of each position, as well as the probability of different potential outcomes. These uncertain tax positions could be significantly affected by audits by taxing authorities of the tax positions and changes to relevant tax law. There is an uncertain tax position related to the March 2023 securitization financing that provided for a tax benefit in the first quarter of 2023 of approximately $129 million.

 Given the judgments made by management, we identified management's conclusion that the securitization uncertain tax position met the more-likely-than-not recognition threshold as a critical audit matter. Auditing management's

 judgments regarding this uncertain tax position involved specialized knowledge of uncertain tax positions and auditor judgment to evaluate the subjectivity of audit evidence.

 Our audit procedures related to the securitization uncertain tax position included the following, among others:

 • We tested the effectiveness of controls related to the securitization uncertain tax position, including those over the recognition and measurement of the income tax benefit.
 • We evaluated the Company's disclosures, and the balances recorded, related to the securitization uncertain tax position.
 • We evaluated the methods and assumptions used by management to estimate the uncertain tax position by testing the underlying data that served as the basis for the uncertain tax position.
 • With the assistance of our income tax specialists, we tested the technical merits of the securitization uncertain tax position and management's key estimates and judgments made by:
 • Assessing the technical merits of the uncertain tax position by comparing to similar cases filed with the Internal Revenue Service.
 • Obtaining an opinion from the Company's external legal counsel regarding certain federal income tax consequences related to the Act 55, as supplemented by Act 293, securitization financing and evaluating whether the analysis was consistent with our interpretation of the relevant laws and circumstances.
 • Considering the impact of changes or settlements in the tax environment on management's methods and assumptions used to estimate the uncertain tax position.

 2023
 2022
 2021

 $ 5,073,239
 $ 6,246,933
 $ 4,994,459

 74,531
 91,835
 73,989

 TOTAL
 5,147,770
 6,338,768
 5,068,448

 1,080,485
 2,002,456
 1,302,291

 654,721
 1,076,715
 768,546

 Nuclear refueling outage expenses
 63,429
 59,698
 49,373

 1,097,233
 1,139,605
 1,034,427

 75,962
 72,122
 68,575

 245,191
 241,908
 224,079

 726,389
 695,204
 656,132

 41,209
 148,871
 38,245

 TOTAL
 3,984,619
 5,436,579
 4,141,668

 1,163,151
 902,189
 926,780

 OTHER INCOME

 32,160
 26,252
 28,648

 Interest and investment income (loss)
 90,316
 ( 69,144)
 154,606

 Interest and investment income - affiliated
 303,233
 185,826
 127,594

 ( 160,972)
 9,824
 ( 125,886)

 TOTAL
 264,737
 152,758
 184,962

 375,295
 373,480
 350,227

 ( 14,996)
 ( 11,550)
 ( 12,878)

 TOTAL
 360,299
 361,930
 337,349

 1,067,589
 693,017
 774,393

 ( 205,781)
 ( 162,853)
 120,409

 1,273,370
 855,870
 653,984

 Net income attributable to noncontrolling interests
 2,988
 1,366
 —

 EARNINGS APPLICABLE TO MEMBER'S EQUITY
 $ 1,270,382
 $ 854,504
 $ 653,984

 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 2023
 2022
 2021

 $ 1,273,370
 $ 855,870
 $ 653,984

 Other comprehensive income (loss)

 (net of tax expense (benefit) of ($ 211), $ 17,351, and $ 1,523)

 3,951

 Other comprehensive income (loss)
 3,951

 Comprehensive Income
 1,272,798
 902,962
 657,935

 Net income attributable to noncontrolling interests
 2,988
 1,366
 —

 Comprehensive Income Applicable to Member's Equity
 $ 1,269,810
 $ 901,596
 $ 657,935

 2023
 2022
 2021

 $ 1,273,370
 $ 855,870
 $ 653,984

 Adjustments to reconcile net income to net cash flow provided by operating activities:

 Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 864,225
 852,521
 818,389

 ( 99,812)
 ( 70,379)
 175,700

 Changes in working capital:

 55,140
 ( 53,434)
 ( 58,466)

 ( 15,959)
 1,099
 7,722

 ( 100,321)
 ( 207,949)
 358,536

 30,459
 ( 28,244)
 21,631

 ( 9,680)
 8,284

 134,383
 ( 113,809)
 ( 43,124)

 ( 129,173)
 ( 103,571)
 ( 45,517)

 Changes in provisions for estimated losses
 ( 52,445)
 291,824
 ( 449)

 Changes in other regulatory assets
 407,327
 720,487
 ( 1,050,600)

 Changes in other regulatory liabilities
 225,645
 ( 4,783)
 ( 16,478)

 Effect of securitization on regulatory asset
 ( 491,150)
 ( 1,190,338)
 —

 Changes in pension and other postretirement liabilities
 ( 117,886)
 ( 139,067)
 ( 164,263)

 Other
 57,997
 358,997
 394,658

 2,032,120
 1,177,508
 1,052,526

 ( 1,624,181)
 ( 2,568,113)
 ( 3,621,775)

 32,160
 26,252
 28,648

 Nuclear fuel purchases
 ( 162,079)
 ( 122,020)
 ( 85,419)

 Proceeds from sale of nuclear fuel
 30,214
 37,648
 13,254

 Payments to storm reserve escrow account
 ( 14,449)
 ( 1,293,633)
 —

 Receipts from storm reserve escrow account
 64,036
 1,000,228
 —

 Purchase of preferred membership interests of affiliate
 ( 1,457,676)
 ( 3,163,572)
 —

 Redemption of preferred membership interests of affiliate
 125,002
 1,390,587
 —

 Changes in securitization account
 —
 —
 2,700

 Proceeds from nuclear decommissioning trust fund sales
 575,596
 633,100
 944,703

 Investment in nuclear decommissioning trust funds
 ( 633,029)
 ( 667,947)
 ( 1,004,888)

 —
 14,539
 ( 1,113)

 Proceeds from sale of assets
 —
 5,000

 Insurance proceeds received for property damages
 19,493
 —
 —

 Litigation proceeds from settlement agreement
 —
 5,695
 —

 Litigation proceeds for reimbursement of spent nuclear fuel storage costs
 —
 —
 8,691

 5,457
 ( 5,475)
 —

 ( 3,039,456)
 ( 4,707,711)
 ( 3,700,199)

 1,410,893
 2,942,771
 3,769,166

 ( 2,699,235)
 ( 3,167,832)
 ( 1,895,091)

 Proceeds received by storm trusts related to securitization
 3,163,572
 —

 Capital contributions from parent
 125,000

 ( 69,948)
 226,114
 —

 Common equity distributions paid
 ( 660,750)
 ( 624,000)
 ( 60,000)

 Other
 57,183
 27,618
 ( 849)

 Net cash flow provided by financing activities
 953,495
 3,568,243
 1,938,226

 ( 53,841)
 38,040
 ( 709,447)

 56,613
 18,573
 728,020

 $ 2,772
 $ 56,613
 $ 18,573

 $ 376,353
 $ 353,697
 $ 337,926

 ($ 141,143)
 ($ 82,463)
 ($ 18,453)

 Non-cash investing activities:

 $ 105,859
 $ 156,654
 $ 507,855

 2023
 2022

 Cash
 $ 2,255
 $ 50,318

 6,295

 2,772
 56,613

 264,776
 339,291

 ( 6,156)
 ( 7,595)

 82,292
 88,896

 Other
 74,685
 53,241

 202,173
 199,077

 617,770
 672,910

 24,800
 159,183

 57,818
 41,859

 652,180
 555,860

 Deferred nuclear refueling outage costs
 96,047
 53,833

 71,613
 76,646

 TOTAL
 1,523,000
 1,616,904

 Investment in affiliate preferred membership interests
 4,496,245
 3,163,572

 Decommissioning trust funds
 2,107,384
 1,779,090

 404,043
 350,723

 243,819
 293,406

 Other
 9,367
 19,679

 TOTAL
 7,260,858
 5,606,470

 27,800,467
 27,498,136

 315,658
 301,719

 592,803
 736,969

 333,472
 212,941

 29,042,400
 28,749,765

 10,570,707
 10,087,942

 18,471,693
 18,661,823

 1,648,852
 2,056,179

 168,122
 168,122

 Other
 36,945
 35,057

 TOTAL
 1,853,919
 2,259,358

 $ 29,109,470
 $ 28,144,555

 2023
 2022

 $ 1,400,000
 $ 1,010,000

 283,016
 356,688

 Other
 467,414
 589,355

 167,905
 161,666

 66,463
 36,004

 91,656
 101,336

 Other
 87,468
 72,525

 TOTAL
 2,563,922
 2,327,574

 2,391,442
 2,374,878

 93,242
 97,868

 193,754
 337,836

 1,407,689
 1,037,962

 1,836,240
 1,736,801

 263,869
 316,314

 271,928
 389,631

 8,020,689
 9,688,922

 Other
 493,176
 343,321

 TOTAL
 14,972,029
 16,323,533

 Member's equity

 11,473,614
 9,406,343

 Accumulated other comprehensive income
 54,798
 55,370

 Noncontrolling interests
 45,107
 31,735

 TOTAL
 11,573,519
 9,493,448

 $ 29,109,470
 $ 28,144,555

 Noncontrolling Interests
 Member's Equity

 Accumulated Other Comprehensive Income
 Total

 $ —
 $ 7,453,361
 $ 4,327
 $ 7,457,688

 —
 653,984
 —
 653,984

 —
 —
 3,951
 3,951

 —
 125,000
 —
 125,000

 —
 ( 60,000)
 —
 ( 60,000)

 Other
 —
 ( 51)
 —
 ( 51)

 $ —
 $ 8,172,294
 $ 8,278
 $ 8,180,572

 1,366
 854,504
 —
 855,870

 —
 —

 Beneficial interest in storm trust
 31,636
 —
 —
 31,636

 Non-cash contribution from parent
 —
 3,597
 —
 3,597

 —
 —

 —
 ( 624,000)
 —
 ( 624,000)

 Distribution to LURC
 ( 1,267)
 —
 —
 ( 1,267)

 Other
 —
 ( 52)
 —
 ( 52)

 $ 31,735
 $ 9,406,343
 $ 55,370
 $ 9,493,448

 2,988
 1,270,382
 —
 1,273,370

 Other comprehensive loss
 —
 —

 Beneficial interest in storm trust
 14,577
 —
 —
 14,577

 —
 —

 —
 ( 660,750)
 —
 ( 660,750)

 Distributions to LURC
 ( 4,193)
 —
 —
 ( 4,193)

 Other
 —
 ( 37)
 —
 ( 37)

 $ 45,107
 $ 11,473,614
 $ 54,798
 $ 11,573,519

 Earnings Applicable to Member's Equity

 Earnings decreased $5.4 million primarily due to higher depreciation and amortization expenses, lower volume/weather, higher interest expense, lower other income, higher other operation and maintenance expenses, and higher taxes other than income taxes. The decrease was partially offset by higher retail electric price.

 Following is an analysis of the change in operating revenues comparing 2023 to 2022.

 $1,624.2

 95.8

 58.9

 Retail one-time bill credit
 36.7

 (13.1)

 $1,802.5

 Entergy Mississippi's results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. "Fuel, rider, and other revenues that do not significantly affect net income" includes the revenue variance associated with these items.

 The retail electric price variance is primarily due to increases in formula rate plan rates effective August 2022, April 2023, and July 2023. See Note 2 to the financial statements for further discussion of the formula rate plan filings.

 The retail one-time bill credit represents the disbursement of settlement proceeds in the form of a one-time bill credit provided to retail customers during the September 2022 billing cycle as a result of the System Energy settlement agreement with the MPSC. There is no effect on net income as the reduction in operating revenues was offset by a reduction in fuel and purchased power expenses. See Note 2 to the financial statements for discussion of the settlement agreement and the MPSC directive related to the disbursement of settlement proceeds.

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

 Total electric energy sales for Entergy Mississippi for the years ended December 31, 2023 and 2022 are as follows:

 2023
 2022

 (GWh)

 5,460
 5,679
 (4)

 4,640
 4,586

 2,347
 2,359
 (1)

 (2)

 12,854
 13,038
 (1)

 4,598
 2,914

 Total
 17,452
 15,952

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

 Other operation and maintenance expenses increased primarily due to:

 • an increase of $6.6 million in contract costs related to operational performance, customer service, and organizational health initiatives;
 • an increase of $5.1 million in loss provisions;
 • an increase of $4.4 million in bad debt expense;
 • an increase of $3.1 million in power delivery expenses primarily due to higher vegetation maintenance costs, partially offset by a lower scope of work performed in 2023 as compared to 2022; and

 • a decrease of $5.8 million in transmission costs allocated by MISO;
 • a decrease of $5.3 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits service costs as a result of an increase in the discount rates used to value the benefits liabilities, lower health and welfare costs, including higher prescription drug rebates in second quarter 2023, and a revision to estimated incentive compensation expense in first quarter 2023. See "Critical Accounting Estimates" below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs; and
 • a decrease of $5.3 million in non-nuclear generation expenses primarily due to a lower scope of work, including during plant outages, performed in 2023 as compared to 2022.

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

 Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Sunflower Solar facility, which was placed in service in September 2022.

 Other regulatory charges (credits) - net includes regulatory credits of $22.6 million, recorded in third quarter 2022, to reflect the effects of the joint stipulation reached in the 2022 formula rate plan filing proceeding and regulatory credits of $18.2 million, recorded in fourth quarter 2022, to reflect that the 2022 estimated earned

 return was below the formula bandwidth. See Note 2 to the financial statements for discussion of the formula rate plan filings.

 Other income (deductions) decreased primarily due to lower interest income from carrying costs related to the deferred fuel balance and an increase in non-qualified pension settlement charges recorded in 2023 and other postretirement benefit non-service costs as a result of the amortization of 2022 trust asset losses. The decrease was partially offset by the timing of charitable donations and an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2023. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs.

 Interest expense increased primarily due to the issuance of $300 million of 5.0% Series mortgage bonds in May 2023 and the $150 million unsecured term loan drawn in June 2022, of which $50 million was repaid in May 2023 and $100 million was repaid in December 2023. The increase was partially offset by the repayment of $250 million of 3.10% Series mortgage bonds in June 2023.

 Net loss attributable to noncontrolling interest reflects the earnings or losses attributable to the noncontrolling partner of the tax equity partnership for the Sunflower Solar facility under HLBV accounting. Entergy Mississippi recorded regulatory charges of $9.1 million in 2023 and $21.4 million in 2022 to defer the difference between the losses allocated to the tax equity partner under the HLBV method of accounting and the earnings/losses that would have been allocated to the tax equity partner under its respective ownership percentage in the partnership. See Note 1 to the financial statements for discussion of the HLBV method of accounting.

 The effective income tax rates were 23.0% for 2023 and 23.7% for 2022. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.

 See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations" in Item 7 of Entergy Mississippi's Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.

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

 Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:

 2023
 2022
 2021

 $16,979
 $47,627
 $18

 559,391
 405,649
 350,960

 (527,978)
 (620,740)
 (686,654)

 (41,762)
 184,443
 383,303

 (10,349)
 (30,648)
 47,609

 $6,630
 $16,979
 $47,627

 Net cash flow provided by operating activities increased $153.7 million in 2023 primarily due to:

 • lower fuel costs and the timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;
 • higher collections from customers; and
 • a decrease of $12.2 million in pension contributions in 2023. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

 • the receipt of $235 million in settlement proceeds in 2022, of which $198.3 million was applied to the under-recovered deferred fuel balance. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery and the System Energy settlement agreement with the MPSC;
 • income tax payments of $50.9 million in 2023 as compared to income tax refunds of $5.4 million in 2022. Entergy Mississippi made income tax payments in 2023 and received income tax refunds in 2022, each in accordance with an intercompany income tax allocation agreement;
 • an increase of $13.9 million in storm spending in 2023; and
 • an increase of $10.7 million in interest paid.

 Net cash flow used in investing activities decreased $92.8 million in 2023 primarily due to:

 • the initial payment of approximately $105.1 million in May 2022 as compared to the substantial completion payment of approximately $30.4 million in April 2023 and the final payment of approximately $4.7 million in October 2023 for the purchase of the Sunflower Solar facility by a consolidated tax equity partnership. See Note 14 to the financial statements for discussion of the Sunflower Solar facility purchase;

 • the receipt of $34.5 million from the storm reserve escrow account in 2023. See Note 2 to the financial statements for discussion of the storm escrow disbursement;
 • a decrease of $20.2 million in non-nuclear generation construction expenditures primarily due to a lower scope of work, including during plant outages, performed in 2023 as compared to 2022;
 • a decrease of $17.8 million in information technology capital expenditures primarily due to decreased spending on various technology projects in 2023; and

 The decrease was partially offset by an increase of $46.8 million in transmission construction expenditures primarily due to increased investment in the reliability and infrastructure of Entergy Mississippi's transmission system in 2023 and an increase of $27.5 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2023.

 Decreases in Entergy Mississippi's receivable from the money pool are a source of cash flow, and Entergy Mississippi's receivable from the money pool decreased $26.9 million in 2023 compared to decreasing by $13.6 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, including to reduce the Registrant Subsidiaries' need for external short-term borrowings.

 Entergy Mississippi's financing activities used $41.8 million of cash in 2023 compared to providing $184.4 million of cash in 2022 primarily due to the following activity:

 • proceeds of $150 million received in June 2022 from an unsecured term loan due December 2023 as compared to repayments of $150 million on the unsecured term loan in 2023;
 • the repayment, prior to maturity, of $250 million of 3.10% Series mortgage bonds in June 2023;
 •$40 million in common equity distributions paid in 2023 in order to maintain Entergy Mississippi's capital structure;
 • money pool activity; and
 • the issuance of $300 million of 5.0% Series mortgage bonds in May 2023.

 Increases in Entergy Mississippi's payable to the money pool are a source of cash flow, and Entergy Mississippi's payable to the money pool increased $73.8 million in 2023.

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

 See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow" in Item 7 of Entergy Mississippi's Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.

 Entergy Mississippi's debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio for Entergy Mississippi is primarily due to the net retirement of long-term debt in 2023 and net income in 2023.

2023
2022

 50.5
 %
 53.4
 %

 (0.1
 %)
 (0.2
 %)

 Net debt to net capital (non-GAAP)
 50.4
 %
 53.2
 %

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

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

 Entergy Mississippi requires capital resources for:

 • working capital purposes, including the financing of fuel and purchased power costs; and
 • distributions and interest payments.

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

 2024
 2025
 2026

 $130
 $440
 $750

 Total
 $700
 $1,025
 $1,285

 In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Mississippi includes investments in generation projects to modernize, decarbonize, and diversify Entergy Mississippi's portfolio, as well as to support customer growth; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting renewables expansion and customer growth; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.

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

 2024
 2025
 2026

 $182
 $81
 $81
 $675
 $2,853

 $8
 $7
 $5
 $7
 $2

 $3
 $3
 $3
 $4
 $24

 Entergy Mississippi currently expects to contribute approximately $15 million to its qualified pension plans and approximately $178 thousand to other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

 Entergy Mississippi has $1.9 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

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

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

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

 • storm reserve escrow accounts;

 • debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;

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

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

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

 2023
 2022
 2021
 2020

 ($73,769)
 $26,879
 $40,456
 ($16,516)

 Entergy Mississippi has a credit facility in the amount of $150 million scheduled to expire in July 2025. As of December 31, 2023, there were no cash borrowings outstanding under the credit facility. In addition, Entergy Mississippi is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO and for other purposes. As of December 31, 2023, $20.0 million in MISO letters of credit and $1.0 million in a non-MISO letter of credit were outstanding under this facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

 Entergy Mississippi obtained authorization from the FERC through April 2025 for short-term borrowings, not to exceed an aggregate amount of $200 million at any time outstanding, and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Mississippi's short-term borrowing limits.

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

 Filings with the MPSC

 In March 2021, Entergy Mississippi submitted its formula rate plan 2021 test year filing and 2020 look-back filing showing Entergy Mississippi's earned return for the historical 2020 calendar year to be below the

 formula rate plan bandwidth and projected earned return for the 2021 calendar year to be below the formula rate plan bandwidth. The 2021 test year filing showed a $95.4 million rate increase was necessary to reset Entergy Mississippi's earned return on common equity to the specified point of adjustment of 6.69% return on rate base, within the formula rate plan bandwidth. The change in formula rate plan revenues, however, was capped at 4% of retail revenues, which equated to a revenue change of $44.3 million. The 2021 evaluation report also included $3.9 million in demand side management costs for which the MPSC approved realignment of recovery from the energy efficiency rider to the formula rate plan. These costs were not subject to the 4% cap and resulted in a total change in formula rate plan revenues of $48.2 million. The 2020 look-back filing compared actual 2020 results to the approved benchmark return on rate base and reflected the need for a $16.8 million interim increase in formula rate plan revenues. In addition, the 2020 look-back filing included an interim capacity adjustment true-up for the Choctaw Generating Station, which increased the look-back interim rate adjustment by $1.7 million. These interim rate adjustments totaled $18.5 million. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $22.1 million interim rate increase, reflecting a cap equal to 2% of 2020 retail revenues, effective with the April 2021 billing cycle, subject to refund, pending a final MPSC order. The $3.9 million of demand side management costs and the Choctaw Generating Station true-up of $1.7 million, which were not subject to the 2% cap of 2020 retail revenues, were included in the April 2021 rate adjustments.

 In June 2021, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2021 test year filing that resulted in a total rate increase of $48.2 million. Pursuant to the joint stipulation, Entergy Mississippi's 2020 look-back filing reflected an earned return on rate base of 6.12% in calendar year 2020, which was below the look-back bandwidth, resulting in a $17.5 million increase in formula rate plan revenues on an interim basis through June 2022. This included $1.7 million related to the Choctaw Generating Station and $3.7 million of COVID-19 non-bad debt expenses. The joint stipulation also included Entergy Mississippi's quantification and methodology for calculating incremental COVID-19 bad debt expenses and provided for Entergy Mississippi to continue to defer these incremental COVID-19 bad debt expenses through December 2021. In June 2021 the MPSC approved the joint stipulation with rates effective for the first billing cycle of July 2021. In June 2021, Entergy Mississippi recorded regulatory credits of $19.9 million to reflect the effects of the joint stipulation.

 In March 2022, Entergy Mississippi submitted its formula rate plan 2022 test year filing and 2021 look-back filing showing Entergy Mississippi's earned return for the historical 2021 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2022 calendar year to be below the formula rate plan bandwidth. The 2022 test year filing showed a $69 million rate increase was necessary to reset Entergy Mississippi's earned return on common equity to the specified point of adjustment of 6.70% return on rate base, within the formula rate plan bandwidth. The change in formula rate plan revenues, however, was capped at 4% of retail revenues, which equated to a revenue change of $48.6 million. The 2021 look-back filing compared actual 2021 results to the approved benchmark return on rate base and reflected the need for a $34.5 million interim increase in formula rate plan revenues. In fourth quarter 2021, Entergy Mississippi recorded a regulatory asset of $19 million to reflect the then-current estimate in connection with the look-back feature of the formula rate plan. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $24.3 million interim rate increase, reflecting a cap equal to 2% of 2021 retail revenues, effective in April 2022. With the implementation of the interim formula rate plan rates, Entergy Mississippi began recovery of the bad debt expense deferral resulting from the COVID-19 pandemic over a three-year period.

 In June 2022, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2022 test year filing that resulted in a total rate increase of $48.6 million. Pursuant to the joint stipulation, Entergy Mississippi's 2021 look-back filing reflected an earned return on rate base of 5.99% in calendar year 2021, which was below the look-back bandwidth, resulting in a $34.3 million increase in the formula rate plan revenues on an interim basis through June 2023. In July 2022 the MPSC approved the joint stipulation with rates effective in August 2022. In July 2022, Entergy Mississippi recorded regulatory credits of $22.6 million to reflect

 the effects of the joint stipulation. In August 2022 an intervenor filed a statutorily-authorized direct appeal to the Mississippi Supreme Court seeking review of the MPSC's July 2022 order approving the joint stipulation confirming Entergy Mississippi's 2022 formula rate plan filing. Formula rate plan rates are not stayed or otherwise impacted while the appeal is pending.

 In July 2022 the MPSC directed Entergy Mississippi to flow $14.1 million of the power management rider over-recovery balance to customers beginning in August 2022 through December 2022 to mitigate the bill impact of the increase in formula rate plan revenues.

 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 and will resume in 2024. In June 2023 the MPSC approved the joint stipulation with rates effective in July 2023.

 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.

 In November 2020, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an over-recovery of approximately $24.4 million as of September 30, 2020. In January 2021 the MPSC approved the proposed energy cost factor effective for February 2021 bills.

 In November 2021, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $80.6 million as of September 30, 2021. In December 2021, at the request of the MPSC, Entergy

 Mississippi submitted a proposal to mitigate the impact of rising fuel costs on customer bills during 2022. Entergy Mississippi proposed that the deferred fuel balance as of December 31, 2021, which was $121.9 million, be amortized over three years and that the MPSC authorize Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. In January 2022 the MPSC approved the amortization of $100 million of the deferred fuel balance over two years and authorized Entergy Mississippi to apply its weighted-average cost of capital as the carrying cost for the unamortized fuel balance. The MPSC approved the proposed energy cost factor effective for February 2022 bills.

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

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

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

 In November 2023 Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $142 million at the end of January 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $47 million

 at the end of January 2024. In January 2024 the MPSC approved the proposed energy cost factor and the proposed power management cost factor effective for February 2024 bills.

 RenewABLE Community Option

 In January 2022, Entergy Mississippi filed its RenewABLE Community Option (Schedule RCO), an offering for qualifying non-residential customers to subscribe to renewable resource capacity to satisfy their environmental, sustainability, and governance goals. The MPSC approved Schedule RCO in December 2022. Registration for the Schedule RCO launched in May 2023 and subscriptions as of December 31, 2023 totaled 17.9 MW of the 40 MW available.

 Storm Cost Recovery Filings with Retail Regulators

 Entergy Mississippi has 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 exceeds $15 million, the collection of the storm damage provision ceases until such time that the accumulated storm damage provision becomes less than $10 million. Entergy Mississippi's storm damage provision balance has been less than $10 million since May 2019, and Entergy Mississippi has 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 exceeds $15 million, in anticipation of a subsequent filing by Entergy Mississippi in this proceeding. The storm damage reserve 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.

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

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

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

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

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

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

 Entergy Mississippi's qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See "Qualified Pension and Other Postretirement Benefits" in the "Critical Accounting Estimates" section of Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.

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

 $256
 $6,670

 $723
 $—

 0.25%
 $264
 $1,383

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

 $20
 $1,031

 0.25%
 $60
 $701

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

 Total qualified pension cost for Entergy Mississippi in 2023 was $19.7 million, including $12.2 million in settlement costs. Entergy Mississippi anticipates 2024 qualified pension cost to be $3.3 million. Entergy Mississippi contributed $21.1 million to its qualified pension plans in 2023 and estimates 2024 pension contributions will be approximately $15 million, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024 valuations are completed, which is expected by April 1, 2024.

 Total postretirement health care and life insurance benefit income for Entergy Mississippi in 2023 was $2.5 million. Entergy Mississippi expects 2024 postretirement health care and life insurance benefit income of approximately $3.7 million. Entergy Mississippi contributed $646 thousand to its other postretirement plan in 2023 and estimates 2024 contributions will be approximately $178 thousand.

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

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

 We have audited the accompanying consolidated balance sheets of Entergy Mississippi, LLC and Subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of income, cash flows and changes in equity (pages 391 through 396 and applicable items in pages 47 through 238), for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

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

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

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

 Critical Audit Matter

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

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

 The Company is subject to rate regulation by the Mississippi Public Service Commission (the "MPSC"), which has jurisdiction with respect to the rates of electric companies in Mississippi, and to wholesale rate regulation by the Federal Energy Regulatory Commission ("FERC"). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

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

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

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

 • We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management's controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
 • We evaluated the Company's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
 • We read relevant regulatory orders issued by the MPSC and the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the MPSC's and FERC's treatment of similar costs under similar circumstances. We evaluated external information and compared to management's recorded regulatory asset and liability balances for completeness.
 • For regulatory matters in process, we inspected the Company's filings with the MPSC and the FERC and orders issued, and considered the filings with the MPSC and the FERC by intervenors that may impact the Company's future rates, for any evidence that might contradict management's assertions.
 • We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management's assertion that amounts are probable of recovery or 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.

 2023
 2022
 2021

 $ 1,802,533
 $ 1,624,234
 $ 1,406,346

 563,296
 252,760
 181,511

 281,761
 322,674
 298,034

 320,192
 314,902
 298,129

 150,921
 137,541
 111,712

 262,624
 246,063
 226,545

 ( 111,376)
 38,017
 5,913

 TOTAL
 1,467,418
 1,311,957
 1,121,844

 335,115
 312,277
 284,502

 OTHER INCOME (DEDUCTIONS)

 8,552
 6,125
 8,101

 2,275

 ( 13,231)
 ( 3,619)
 ( 8,791)

 TOTAL
 ( 2,404)
 3,014
 ( 637)

 99,857
 86,960
 75,124

 ( 3,479)
 ( 2,800)
 ( 3,416)

 TOTAL
 96,378
 84,160
 71,708

 236,333
 231,131
 212,157

 54,364
 54,864
 45,323

 181,969
 176,267
 166,834

 Net loss attributable to noncontrolling interest
 ( 10,302)
 ( 21,355)
 —

 EARNINGS APPLICABLE TO MEMBER'S EQUITY
 $ 192,271
 $ 197,622
 $ 166,834

 2023
 2022
 2021

 $ 181,969
 $ 176,267
 $ 166,834

 Adjustments to reconcile net income to net cash flow provided by operating activities:

 262,624
 246,063
 226,545

 28,990
 54,850
 64,868

 3,627
 ( 65,843)
 10,260

 ( 648)
 ( 5,237)
 6,806

 ( 41,101)
 49,101
 27,068

 ( 9,771)
 18,632
 ( 1,811)

 3,329
 ( 3,606)

 273,856
 ( 21,333)
 ( 136,569)

 ( 23,813)
 2,632
 ( 9,522)

 Provisions for estimated losses
 1,972
 ( 519)
 ( 8,476)

 ( 59,616)
 ( 57,028)
 4,909

 ( 59,513)
 20,165
 21,930

 ( 49,223)
 ( 35,299)
 ( 51,828)

 46,709
 22,273
 33,552

 559,391
 405,649
 350,960

 ( 562,118)
 ( 534,020)
 ( 654,352)

 8,552
 6,125
 8,101

 Payment for purchase of assets
 ( 35,094)
 ( 105,149)
 —

 26,879
 13,577
 ( 40,456)

 Receipt from storm reserve escrow account
 34,493
 —
 —

 ( 690)
 ( 1,273)

 ( 527,978)
 ( 620,740)
 ( 686,654)

 396,833
 249,266
 398,284

 ( 500,000)
 ( 100,000)
 —

 —

 73,769
 —
 ( 16,516)

 Common equity distributions paid
 ( 40,000)
 —
 —

 Other
 1,928
 10,475
 1,535

 Net cash flow provided by (used in) financing activities
 ( 41,762)
 184,443
 383,303

 ( 10,349)
 ( 30,648)
 47,609

 16,979
 47,627

 $ 6,630
 $ 16,979
 $ 47,627

 $ 93,961
 $ 83,291
 $ 76,245

 $ 50,869
 ($ 5,396)
 ($ 19,672)

 $ 16,342
 $ 59,474
 $ 26,498

 2023
 2022

 Cash
 $ 30
 $ 26

 6,600
 16,953

 6,630
 16,979

 121,389
 99,504

 ( 3,312)
 ( 2,472)

 4,997
 37,673

 Other
 17,697
 34,564

 71,465
 73,473

 212,236
 242,742

 —
 143,211

 16,196
 15,548

 95,526
 84,346

 12,740
 9,603

 TOTAL
 343,328
 512,429

 4,497
 4,512

 33,549

 Other
 —

 TOTAL
 5,153
 38,971

 7,455,145
 7,079,849

 139,635
 170,191

 7,594,780
 7,250,040

 2,346,327
 2,264,786

 5,248,453
 4,985,254

 579,076
 519,460

 Other
 51,996
 22,650

 TOTAL
 631,072
 542,110

 $ 6,228,006
 $ 6,078,764

 2023
 2022

 $ 100,000
 $ 400,000

 133,571
 60,532

 Other
 92,659
 176,162

 92,637
 89,668

 115,134
 124,905

 21,537
 18,208

 130,645
 —

 Other
 26,463
 38,908

 TOTAL
 712,646
 908,383

 821,744
 780,030

 13,811
 14,591

 188,714
 202,058

 33,696
 79,865

 Asset retirement cost liabilities
 8,229
 7,797

 39,481
 37,509

 —
 23,742

 2,129,510
 1,931,096

 Other
 71,961
 53,156

 TOTAL
 3,307,146
 3,129,844

 Member's equity
 2,189,461
 2,037,190

 Noncontrolling interest
 18,753
 3,347

 TOTAL
 2,208,214
 2,040,537

 $ 6,228,006
 $ 6,078,764

 Noncontrolling Interest
 Member's Equity
 Total

 $ —
 $ 1,672,734
 $ 1,672,734

 —
 166,834
 166,834

 $ —
 $ 1,839,568
 $ 1,839,568

 ( 21,355)
 197,622
 176,267

 —

 $ 3,347
 $ 2,037,190
 $ 2,040,537

 ( 10,302)
 192,271
 181,969

 —
 ( 40,000)
 ( 40,000)

 —

 $ 18,753
 $ 2,189,461
 $ 2,208,214

 Net income increased $164.8 million primarily due to a $198.4 million reduction in income tax expense in 2023 as a result of the resolution of the 2016-2018 IRS audit, partially offset by a $60 million regulatory charge ($43.8 million net-of-tax) to reflect credits expected to be provided to customers, and higher retail electric price. The increase was partially offset by higher other operation and maintenance expenses. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit.

 Following is an analysis of the change in operating revenues comparing 2023 to 2022:

 $997.3

 (174.6)

 0.5

 Storm restoration carrying costs
 5.2

 15.5

 $843.9

 Entergy New Orleans's results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. "Fuel, rider, and other revenues that do not significantly affect net income" includes the revenue variance associated with these items.

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

 Storm restoration carrying costs represent the equity component of storm restoration carrying costs, recorded in fourth quarter 2023, recognized as part of the City Council's approval of the Hurricane Ida storm cost certification report in December 2023. See Note 2 to the financial statements for further discussion of the storm cost certification.

 The retail electric price variance is primarily due to an increase in formula rate plan rates effective September 2022 in accordance with the terms of the 2022 formula rate plan filing. See Note 2 to the financial statements for further discussion of the formula rate plan filing.

 Total electric energy sales for Entergy New Orleans for the years ended December 31, 2023 and 2022 are as follows:

 2023
 2022

 (GWh)

 2,364
 2,410
 (2)

 2,126
 2,096

 (1)

 5,696
 5,706
 —

 2,818
 2,298

 Total
 8,514
 8,004

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

 Other operation and maintenance expenses increased primarily due to:

 • an increase of $4.6 million in non-nuclear generation expenses primarily due to a higher scope of work performed in 2023 as compared to 2022;
 • an increase of $4.5 million resulting from a gain on the sale of NOx allowances in 2022;
 • an increase of $3.9 million in power delivery expenses primarily due to higher reliability costs and higher vegetation maintenance costs in 2023 as compared to 2022; and
 • an increase of $3 million in contract costs related to operational performance, customer service, and organizational health initiatives.

 The increase was partially offset by a decrease of $3 million in energy efficiency expenses primarily due to the timing of recovery from customers and lower energy efficiency costs.

 Depreciation and amortization expenses increased primarily due to additions to plant in service.

 Other regulatory charges (credits) - net includes a regulatory charge of $60 million, recorded in fourth quarter 2023, to reflect credits expected to be provided to customers as a result of the resolution of the 2016-2018 IRS audit. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit.

 Other income increased primarily due to higher interest earned on money pool investments. The increase was partially offset by a decrease of $2.3 million due to the recognition of storm restoration carrying costs in 2022 related to Hurricane Ida and an increase in other postretirement benefit non-service costs as a result of the amortization of 2022 trust asset losses and non-qualified pension settlement charges. See Note 2 to the financial statements for further discussion of storm restoration costs. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs.

 Interest expense increased primarily due to a higher fixed interest rate on Entergy New Orleans's unsecured term loan and interest on the $34 million regulatory liability recorded when Entergy New Orleans received a refund from System Energy in January 2023 related to the sale-leaseback renewal costs and depreciation litigation. The

 increase was partially offset by the repayment of $100 million of 3.9% Series mortgage bonds in July 2023. See Note 2 to the financial statements for further discussion of the refund and the related proceedings.

 The effective income tax rates were (487.5%) for 2023 and 27.5% for 2022. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.

 See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations" in Item 7 of Entergy New Orleans's Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.

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

 Planned Sale of Gas Distribution Business

 See the "Planned Sale of Gas Distribution Businesses" section of Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis for discussion of the purchase and sale agreement for the sale of Entergy New Orleans's gas distribution business.

 Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:

 2023
 2022
 2021

 $4,464
 $42,862
 $26

 202,956
 363,763
 78,808

 (18,802)
 (403,790)
 (169,920)

 (188,592)
 1,629
 133,948

 (4,438)
 (38,398)
 42,836

 $26
 $4,464
 $42,862

 Net cash flow provided by operating activities decreased $160.8 million in 2023 primarily due to:

 • net proceeds of $201.8 million received from the LURC in December 2022 from securitization. See Note 2 to the financial statements for further discussion of the storm securitization;
 • lower receipts from associated companies in 2022;

 • an increase of $13.6 million in income taxes paid in 2023. Entergy New Orleans made net income tax payments in 2023 primarily related to the resolution of the 2016-2018 IRS audit and estimated federal and state income taxes. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit; and
 • lower collections from customers.

 • lower fuel costs and the timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;
 • the refund of $34 million received from System Energy 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 Note 2 to the financial statements for further discussion of the refund and the related proceedings; and
 • a decrease of $18.7 million in storm spending primarily due to Hurricane Ida restoration efforts in 2022.

 Net cash flow used in investing activities decreased $385 million in 2023 primarily due to:

 • money pool activity;
 • a decrease of $71.3 million in net payments to the storm reserve escrow account in 2023; and
 • a decrease of $42.9 million in distribution construction expenditures primarily due to higher capital expenditures for Hurricane Ida storm restoration efforts in 2022, partially offset by increased investment in the reliability and infrastructure of Entergy New Orleans's distribution system in 2023.

 Decreases in Entergy New Orleans's receivable from the money pool are a source of cash flow, and Entergy New Orleans's receivable from the money pool decreased $147.3 million in 2023 compared to increasing by $110.8 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries' dependence on external short-term borrowings.

 Entergy New Orleans's financing activities used $188.6 million of cash in 2023 compared to providing $1.6 million of cash in 2022 primarily due to the following activity:

 •$125 million in common equity distributions paid in 2023 in order to maintain Entergy New Orleans's capital structure;
 • the repayment, at maturity, of $100 million of 3.90% Series mortgage bonds in July 2023;
 • additional borrowings of $15 million in May 2023 on an unsecured term loan due June 2024; and

 Increases in Entergy New Orleans's payable to the money pool are a source of cash flow, and Entergy New Orleans's payable to the money pool increased $21.7 million in 2023.

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

 See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow" in Item 7 of Entergy New Orleans's Annual Report on Form 10-K for the year ended

 December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.

 Entergy New Orleans's debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio for Entergy New Orleans is primarily due to net income in 2023 and the net retirement of long-term debt in 2023, partially offset by common equity distributions of $125 million in 2023.

2023
2022

 45.8
 %
 52.6
 %

 Effect of excluding securitization bonds
 (0.2
 %)
 (0.6
 %)

 Debt to capital, excluding securitization bonds (non-GAAP) (a)
 45.6
 %
 52.0
 %

 —
 %
 (0.1
 %)

 Net debt to net capital, excluding securitization bonds (non-GAAP) (a)
 45.6
 %
 51.9
 %

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

 Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, long-term debt, including the currently maturing portion, and the long-term payable due to an associated company. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. The debt to capital ratio excluding securitization bonds and net debt to net capital ratio excluding securitization bonds are non-GAAP measures. Entergy New Orleans 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 New Orleans's financial condition because the securitization bonds are non-recourse to Entergy New Orleans, as more fully described in Note 5 to the financial statements. Entergy New Orleans 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 New Orleans's financial condition because net debt indicates Entergy New Orleans's outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

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

 Entergy New Orleans requires capital resources for:

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

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

 2024
 2025
 2026

 $5
 $15
 $10

 Total
 $165
 $160
 $165

 In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy New Orleans includes distribution and Utility support spending to deliver reliability, resilience, and customer experience; transmission spending to improve reliability and resilience; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.

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

 2024
 2025
 2026

 $119
 $101
 $106
 $39
 $748

 $2
 $2
 $1
 $1
 $1

 $1
 $1
 $1
 $1
 $1

 Entergy New Orleans currently expects to contribute approximately $4.9 million to its qualified pension plan and approximately $205 thousand to other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See "Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits" below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

 Entergy New Orleans has $7.6 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

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

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

 System Resilience and Storm Hardening

 In October 2021 the City Council passed a resolution and order establishing a docket and procedural schedule with respect to system resiliency and storm hardening. The docket will identify a plan for storm hardening and resiliency projects with other stakeholders. 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, with final comments on that filing due July 2023. 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 rider to recover from customers the costs of the infrastructure hardening plan. In July 2023, Entergy New Orleans filed comments in support of its application. 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 Department of Energy's Grid Resilience and Innovation Partnerships program. The resolution also requires Entergy New Orleans to submit, no later than July 2024, a revised resilience plan consisting of projects in three-year intervals. Entergy New Orleans continues to seek approval of its application.

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

 • storm reserve escrow accounts;
 • debt and preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;

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

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

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

 2023
 2022
 2021
 2020

 ($21,651)
 $147,254
 $36,410
 ($10,190)

 Entergy New Orleans has a credit facility in the amount of $25 million scheduled to expire in June 2024. The credit facility includes fronting commitments for the issuance of letters of credit against $10 million of the borrowing capacity of the facility. As of December 31, 2023, there were no cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy New Orleans is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2023, a $0.5 million letter of credit was outstanding under Entergy New Orleans's uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

 Entergy New Orleans obtained authorization from the FERC through April 2025 for short-term borrowings not to exceed an aggregate amount of $150 million at any time outstanding and long-term borrowings and securities issuances. See Note 4 to the financial statements for further discussion of Entergy New Orleans's short-term borrowing limits. The long-term securities issuances of Entergy New Orleans are limited to amounts authorized not only by the FERC, but also by the City Council, and the current City Council authorization extends through December 2025.

 State and Local Rate Regulation

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

 In July 2021, Entergy New Orleans submitted to the City Council its formula rate plan 2020 test year filing. The 2020 test year evaluation report produced an earned return on equity of 6.26% compared to the authorized return on equity of 9.35%. Entergy New Orleans sought approval of a $64 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula resulted in an increase in authorized electric revenues of $40 million and an increase in authorized gas revenues of $18.8 million. Entergy New Orleans also sought to commence collecting $5.2 million in electric revenues and $0.3 million in gas revenues that were previously approved by the City Council for collection through the formula rate plan. The filing was subject to review by the City Council and other parties over a 75-day review period, followed by a 25-day period to resolve any disputes among the parties. In October 2021 the City Council's advisors filed a 75-day report recommending a reduction of $10 million for electric revenues and a reduction of $4.5 million for gas revenues, along with one-time credits funded by certain electric regulatory liabilities currently held by Entergy New Orleans for customers. On October 26, 2021, Entergy New Orleans provided notice to the City Council that it intends to implement rates effective with the first billing cycle of November 2021, with such rates reflecting an amount agreed-upon by Entergy New Orleans including adjustments filed in the City Council's 75-day report, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $49.5 million, with an increase of $34.9 million in electric revenues and $14.6 million in gas revenues. Also, credits of $17.4 million funded by certain regulatory liabilities currently held by Entergy New Orleans for customers will be issued over a five-month period from November 2021 through March 2022. Resulting rates went into effect with the first billing cycle of November 2021 pursuant to the formula rate plan tariff.

 In April 2022, Entergy New Orleans submitted to the City Council its formula rate plan 2021 test year filing. The 2021 test year evaluation report, subsequently updated in a July 2022 filing, produced an earned return on equity of 6.88% compared to the authorized return on equity of 9.35%. Entergy New Orleans sought approval of

 a $42.1 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula resulted in an increase in authorized electric revenues of $34.1 million and an increase in authorized gas revenues of $3.3 million. Entergy New Orleans also sought to commence collecting $4.7 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2022 the City Council's advisors issued a report seeking a reduction to Entergy New Orleans's proposed increase of approximately $17.1 million in total for electric and gas revenues. Effective with the first billing cycle of September 2022, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council including adjustments filed in the City Council's advisors' report, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $24.7 million, which includes an increase of $18.2 million in electric revenues, $4.7 million in previously approved electric revenues, and an increase of $1.8 million in gas revenues. Additionally, credits of $13.9 million funded by certain regulatory liabilities currently held by Entergy New Orleans for customers were issued over an eight-month period beginning September 2022.

 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 provides 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 provides for a minor storm accrual of $0.5 million per year and the distribution of $8.9 million of currently 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% fixed capital structure for rate setting purposes.

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

 Entergy New Orleans's gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.

 Reliability Investigation

 In August 2017 the City Council established a docket to investigate the reliability of the Entergy New Orleans distribution system and to consider implementing certain reliability standards and possible financial penalties for not meeting any such standards. In April 2018 the City Council adopted a resolution directing Entergy New Orleans to demonstrate that it has been prudent in the management and maintenance of the reliability of its distribution system. The resolution also called for Entergy New Orleans to file a revised reliability plan addressing the current state of its distribution system and proposing remedial measures for increasing reliability. In June 2018, Entergy New Orleans filed its response to the City Council's resolution regarding the prudence of its management and maintenance of the reliability of its distribution system. In July 2018, Entergy New Orleans filed its revised reliability plan discussing the various reliability programs that it uses to improve distribution system reliability and discussing generally the positive effect that advanced meter deployment and grid modernization can have on future reliability. Entergy New Orleans retained a national consulting firm with expertise in distribution system reliability to conduct a review of Entergy New Orleans's distribution system reliability-related practices and procedures and to provide recommendations for improving distribution system reliability. The report was filed with the City Council in October 2018. The City Council also approved a resolution that opened a prudence investigation into whether Entergy New Orleans was imprudent for not acting sooner to address outages in New Orleans and whether fines should be imposed. In January 2019, Entergy New Orleans filed testimony in response to the prudence investigation asserting that it had been prudent in managing system reliability. In April 2019 the City Council advisors filed comments and testimony asserting that Entergy New Orleans did not act prudently in maintaining and improving its distribution system reliability in recent years and recommending that a financial penalty in the range of $1.5 million to $2 million should be assessed. Entergy New Orleans disagreed with the recommendation and submitted rebuttal testimony and rebuttal comments in June 2019. In November 2019 the City Council passed a resolution that penalized Entergy New Orleans $1 million for alleged imprudence in the maintenance of its distribution system. In December 2019, Entergy New Orleans filed suit in Louisiana state court seeking judicial review of the City Council's resolution. In June 2022 the Orleans Civil District Court issued a written judgment that the penalty be set aside, reversed, and vacated. In August 2022 the Orleans Civil District Court issued written reasons for its judgment and also granted a post-judgment motion to remand for the City Council to take actions consistent with its judgment.

 Also in August 2022 the City Council approved a resolution establishing a 30-day comment period on proposed minimum reliability standards and an associated penalty mechanism. In September 2022, Entergy New Orleans filed comments to the proposed plan including a request for an additional round of comments. In February 2023 the City Council approved a resolution adopting the proposed reliability standards, including a minimum annual performance level for Entergy New Orleans's distribution system, as well as associated penalty mechanisms. In April 2023, Entergy New Orleans filed the compliance filings required by the resolution for calendar year 2023. The first year for which the City Council may assess a penalty for distribution system reliability performance is calendar year 2024.

 In April 2023 the City Council approved a resolution that established a procedural schedule to allow for the submission of additional evidence regarding the penalty imposed in 2019. In May 2023, Entergy New Orleans filed with the Orleans Civil District Court a petition for judicial review and (or alternatively) declaratory judgment of, together with a request for injunctive relief from, the City Council's April 2023 resolution. In June 2023 the City Council filed exceptions requesting the Orleans Civil District Court dismiss the suit as premature, and a hearing date was set on the exceptions. In September 2023, Entergy New Orleans filed an unopposed motion to continue the hearing on the City Council's exceptions without date, which was granted. Entergy New Orleans expects to file its opposition to the City Council's exceptions by the applicable deadlines. In January 2024 the City Council approved

 a modified procedural schedule in which the hearing officer shall certify the record of the proceeding for City Council consideration no later than July 2024.

 Renewable Portfolio Standard Rulemaking

 In March 2019 the City Council initiated a rulemaking proceeding to consider whether to establish a renewable portfolio standard. The four components of the Renewable and Clean Portfolio Standard that the City Council expressed a desire to implement were: (1) a mandatory requirement that Entergy New Orleans achieve 100% net zero carbon emissions by 2040; (2) reliance on renewable energy credits purchased without the associated energy for compliance with the standard being phased out over the ten-year period from 2040 to 2050; (3) no carbon-emitting resources in the portfolio of resources Entergy New Orleans uses to serve New Orleans by 2050; and (4) a mechanism to limit costs in any one plan year to no more than one percent of plan year total utility retail sales revenues. The City Council adopted the Utility Committee resolution in April 2020. The City Council approved the rule in May 2021, establishing the Renewable and Clean Portfolio Standard.

 In March 2022 the City Council approved Entergy New Orleans's initial compliance plan and established an alternative compliance payment value of $8.45 per MWh, which Entergy New Orleans will pay if it is unable to comply with the Renewable and Clean Portfolio Standard for the 2022 compliance year. Such compliance payments are paid into a clean energy fund established by the City Council. The City Council also approved the electric vehicle credit calculation methodology for use in the compliance demonstration report for 2022, to be filed prior to May 1, 2023. Entergy New Orleans's proposal to create a 5% contingency reserve was considered reasonable for the initial compliance plan.

 In August 2022, Entergy New Orleans submitted its compliance plan covering compliance years 2023-2025. After receiving comments from intervenors and Entergy New Orleans, in December 2022 the City Council adopted a resolution that (a) approved Entergy New Orleans's proposal to purchase unbundled renewable energy credits, as needed; (b) denied Entergy New Orleans's request to treat the Sewerage and Water Board's 230 kV Sullivan substation electrification as a "qualified measure;" (c) approved the alternative compliance payment for years 2023-2025 at $8.45 per MWh; and (d) approved the Tier 3 credit calculations for electric vehicle charging infrastructure but denied the request to approve a Tier 3 credit for the Sewerage and Water Board substation electrification project at this time while the substation is not yet in service.

 In May 2023, Entergy New Orleans submitted its compliance demonstration report to the City Council for the 2022 compliance year, which describes and demonstrates Entergy New Orleans's compliance with the Renewable and Clean Portfolio Standard in 2022 and satisfies certain informational requirements. Entergy New Orleans requested, among other things, that the City Council determine that Entergy New Orleans achieved the target under the portfolio standard for 2022 and remains within the customer protection cost cap, and that the City Council approve a proposal to recover costs associated with 2022 compliance. In July 2023 intervenors filed comments on the compliance demonstration report, and Entergy New Orleans responded to those comments in August 2023.

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

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

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

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

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

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

 Entergy New Orleans's qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See "Qualified Pension and Other Postretirement Benefits" in the "Critical Accounting Estimates" section of Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.

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

 $93
 $3,124

 $305
 $—

 0.25%
 $132
 $538

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

 $32
 $494

 0.25%
 $49
 $282

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

 Total qualified pension cost for Entergy New Orleans in 2023 was $3.7 million, including $2.1 million in settlement costs. Entergy New Orleans anticipates 2024 qualified pension cost to be $1.1 million. Entergy New Orleans contributed $1.4 million to its qualified pension plans in 2023 and estimates 2024 pension contributions will be approximately $4.9 million, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024 valuations are completed, which is expected by April 1, 2024.

 Total postretirement health care and life insurance benefit income for Entergy New Orleans in 2023 was $4.3 million. Entergy New Orleans expects 2024 postretirement health care and life insurance benefit income of approximately $5.5 million. Entergy New Orleans contributed $213 thousand to its other postretirement plans in 2023 and estimates 2024 contributions will be approximately $205 thousand.

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

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

 We have audited the accompanying consolidated balance sheets of Entergy New Orleans, LLC and Subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of income, cash flows, and changes in member's equity (pages 412 through 416 and applicable items in pages 47 through 238), for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

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

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

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

 Critical Audit Matters

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

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

 The Company is subject to rate regulation by the Council of the City of New Orleans, Louisiana (the "City Council"), which has jurisdiction with respect to the rates of electric companies in the City of New Orleans, Louisiana, and to wholesale rate regulation by the Federal Energy Regulatory Commission ("FERC"). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based

 rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

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

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

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

 • We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management's controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
 • We evaluated the Company's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
 • We read relevant regulatory orders issued by the City Council and the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the City Council's and the FERC's treatment of similar costs under similar circumstances. We evaluated external information and compared to management's recorded regulatory asset and liability balances for completeness.
 • For regulatory matters in process, we inspected the Company's filings with the City Council and the FERC and orders issued, and considered the filings with the City Council and the FERC by intervenors that may impact the Company's future rates, for any evidence that might contradict management's assertions.
 • We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management's assertion that amounts are probable of recovery or 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.

 2023
 2022
 2021

 $ 737,974
 $ 855,248
 $ 672,231

 105,959
 142,085
 96,621

 TOTAL
 843,933
 997,333
 768,852

 122,400
 244,994
 150,018

 268,478
 314,283
 268,568

 167,719
 156,653
 145,377

 62,979
 63,743
 53,569

 81,282
 76,938
 73,480

 69,211
 19,596
 13,177

 TOTAL
 772,069
 876,207
 704,189

 71,864
 121,126
 64,663

 OTHER INCOME

 1,470
 2,371

 7,154

 ( 4,119)
 ( 21)
 ( 1,240)

 TOTAL
 4,505
 1,550
 1,179

 38,118
 34,829
 29,164

 ( 714)
 ( 531)
 ( 1,056)

 TOTAL
 37,404
 34,298
 28,108

 38,965
 88,378
 37,734

 ( 189,973)
 24,277
 5,936

 $ 228,938
 $ 64,101
 $ 31,798

 2023
 2022
 2021

 $ 228,938
 $ 64,101
 $ 31,798

 Adjustments to reconcile net income to net cash flow provided by operating activities:

 81,282
 76,938
 73,480

 ( 191,326)
 18,685
 12,573

 29,944
 6,128
 ( 42,612)

 2,574
 ( 2,927)
 ( 967)

 ( 11,924)
 22,457

 Prepaid taxes and taxes accrued
 ( 11,882)
 5,923
 ( 315)

 ( 104)

 4,005
 ( 17,760)
 9,737

 ( 9,184)
 ( 790)
 ( 3,233)

 Provisions for estimated losses
 1,076
 80,719
 ( 83,569)

 19,745
 46,505
 18,173

 66,022
 ( 8,639)
 4,985

 Effect of securitization on regulatory asset
 —
 95,920
 —

 ( 16,371)
 9,769
 ( 32,144)

 9,603
 ( 10,919)
 68,549

 202,956
 363,763
 78,808

 ( 164,279)
 ( 217,864)
 ( 220,284)

 1,470
 2,371

 147,254
 ( 110,844)
 ( 36,410)

 Payments to storm reserve escrow account
 ( 3,731)
 ( 200,000)
 ( 7)

 Receipts from storm reserve escrow account
 —
 125,000
 83,045

 Changes in securitization account
 ( 191)
 ( 236)
 1,365

 ( 675)
 —

 ( 18,802)
 ( 403,790)
 ( 169,920)

 14,610
 —
 183,403

 ( 112,525)
 ( 12,207)
 ( 36,873)

 Repayment of long-term payable due to associated company
 ( 1,306)
 ( 1,326)
 ( 1,618)

 Contributions from customer for construction
 —

 21,651
 —
 ( 10,190)

 Common equity distributions paid
 ( 125,000)
 —
 —

 Other
 ( 1,022)
 ( 774)

 Net cash flow provided by (used in) financing activities
 ( 188,592)
 1,629
 133,948

 ( 4,438)
 ( 38,398)
 42,836

 4,464
 42,862

 $ 26
 $ 4,464
 $ 42,862

 $ 36,263
 $ 33,343
 $ 28,009

 $ 14,120
 $ 499
 ($ 3,839)

 $ 7,068
 $ 11,152
 $ —

 2023
 2022

 Cash
 $ 26
 $ 27

 —
 4,437

 4,464

 2,426
 2,235

 67,258
 93,288

 ( 7,770)
 ( 11,909)

 1,657
 149,927

 Other
 5,270
 6,110

 31,087
 37,284

 97,502
 274,700

 6,148
 10,153

 3,298
 5,872

 30,019
 22,498

 Prepaid taxes
 1,574
 —

 11,482
 6,312

 TOTAL
 152,475
 326,234

 1,050

 78,731

 Other
 —

 TOTAL
 79,563
 76,725

 2,046,928
 1,934,837

 401,846
 390,252

 25,424
 39,607

 2,474,198
 2,364,696

 858,672
 808,224

 1,615,526
 1,556,472

 Other regulatory assets (includes securitization property of $ 506 as of December 31, 2023 and $ 13,363 as of December 31, 2022)

 182,367
 202,112

 4,080
 4,080

 Other
 63,964
 46,778

 TOTAL
 250,411
 252,970

 $ 2,097,975
 $ 2,212,401

 2023
 2022

 $ 85,000
 $ 170,000

 Payable due to associated company
 1,275
 1,306

 76,736
 53,258

 Other
 39,813
 57,291

 32,420
 31,826

 —
 10,308

 8,534
 8,080

 Other
 8,953
 6,560

 TOTAL
 252,731
 338,629

 195,615
 385,259

 16,457
 16,481

 36,061
 39,738

 90,434
 20,735

 88,124
 87,048

 Long-term debt (includes securitization bonds of $ 5,415 as of December 31, 2023 and $ 17,697 as of December 31, 2022)

 584,171
 596,047

 Long-term payable due to associated company
 7,004
 8,279

 Other
 20,624
 17,369

 TOTAL
 1,038,490
 1,170,956

 Member's equity
 806,754
 702,816

 TOTAL
 806,754
 702,816

 $ 2,097,975
 $ 2,212,401

 CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY

 Member's Equity

 $ 606,917

 31,798

 $ 638,715

 64,101

 $ 702,816

 228,938

 ( 125,000)

 $ 806,754

 Net income decreased $12.1 million primarily due to higher depreciation and amortization expenses, the recognition of the equity component of carrying costs as part of the securitization of the Hurricane Laura, Hurricane Delta, and Winter Storm Uri system restoration costs in April 2022, and higher taxes other than income taxes. The decrease was partially offset by higher retail electric price and higher other income.

 Following is an analysis of the change in operating revenues comparing 2023 to 2022.

 $2,288.9

 (331.8)

 System restoration carrying costs
 (21.7)

 8.4

 Return of unprotected excess accumulated deferred income taxes to customers
 26.6

 58.2

 $2,028.6

 Entergy Texas's results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. "Fuel, rider, and other revenues that do not significantly affect net income" includes the revenue variance associated with these items.

 System restoration carrying costs represent the equity component of system restoration carrying costs recognized as part of the securitization of the Hurricane Laura, Hurricane Delta, and Winter Storm Uri system restoration costs in April 2022. See Note 2 to the financial statements for a discussion of the securitization.

 The volume/weather variance is primarily due to an increase in weather-adjusted residential usage and an increase in commercial usage, partially offset by the effect of less favorable weather on residential sales and a decrease in demand from cogeneration customers. The increase in weather-adjusted residential usage was primarily due to an increase in customers.

 The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through a rider effective October 2018 in response to the enactment of the Tax Cuts and Jobs Act. There was no return of unprotected excess accumulated deferred income taxes to customers in 2023. In 2022, $26.6 million was returned to customers through reductions in operating revenues. There was no effect on net income as the reductions in operating revenues were offset by reductions in

 income tax expense. See Note 2 to the financial statements for discussion of regulatory activity regarding the Tax Cuts and Jobs Act.

 The retail electric price variance is primarily due to an increase in base rates, including the realignment of the costs previously being collected through the distribution and transmission cost recovery factor riders and the generation cost recovery rider to base rates, effective June 2023 on an interim basis and approved by the PUCT in August 2023. See Note 2 to the financial statements for discussion of the 2022 base rate case.

 Total electric energy sales for Entergy Texas for the years ended December 31, 2023 and 2022 are as follows:

 2023
 2022

 (GWh)

 6,731
 6,779
 (1)

 4,797
 4,758

 9,343
 9,572
 (2)

 21,146
 21,380
 (1)

 —
 (100)

 (43)

 Total
 21,608
 22,472
 (4)

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

 Other operation and maintenance expenses increased primarily due to:

 • an increase of $12.2 million in power delivery expenses primarily due to higher vegetation maintenance costs;
 • an increase of $7 million in contract costs related to operational performance, customer service, and organizational health initiatives;
 • an increase of $2.4 million in loss provisions; and

 The increase was partially offset by a decrease of $9.5 million in transmission costs allocated by MISO and a gain of $6.9 million on the partial sale of a service center in April 2023 as part of an eminent domain proceeding.

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

 Depreciation and amortization expenses increased primarily due to an increase in depreciation rates effective with an interim increase in base rates in June 2023, which was approved by the PUCT in August 2023, and additions to plant in service. See Note 2 to the financial statements for discussion of the 2022 base rate case.

 Other regulatory charges (credits) - net includes the reversal in third quarter 2023 of $21.9 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved. See Note 2 to the financial statements for discussion of the 2022 base rate case.

 Other income increased primarily due to an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2023, including the Orange County Advanced Power Station project, and higher interest earned on money pool investments.

 Interest expense increased primarily due to the issuance of $325 million of 5.00% Series mortgage bonds in August 2022 and the issuance of $350 million of 5.80% Series mortgage bonds in August 2023, partially offset by an increase in the allowance for borrowed funds used during construction due to higher construction work in progress in 2023, including the Orange County Advanced Power Station project.

 The effective income tax rates were 17.8% for 2023 and 14.3% for 2022. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.

 See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations" in Item 7 of Entergy Texas's Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.

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

 Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:

 2023
 2022
 2021

 $3,497
 $28
 $248,596

 641,691
 409,427
 356,933

 (1,125,948)
 (764,069)
 (647,271)

 502,746
 358,111
 41,770

 18,489
 3,469
 (248,568)

 $21,986
 $3,497
 $28

 Net cash flow provided by operating activities increased $232.3 million in 2023 primarily due to lower fuel costs and the timing of recovery of fuel and purchased power costs. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery. The increase was partially offset by:

 • lower collections from customers;

 • the timing of payments to vendors;
 • an increase of $27.1 million in income taxes paid in 2023 as a result of higher estimated income tax payments in comparison to 2022; and
 • an increase of $17.1 million in interest paid.

 Net cash flow used in investing activities increased $361.9 million in 2023 primarily due to:

 • an increase of $162.3 million in non-nuclear generation construction expenditures primarily due to higher spending on the Orange County Advanced Power Station project;
 • money pool activity;
 • an increase of $73.5 million in transmission construction expenditures primarily due to increased investment in the reliability and infrastructure of Entergy Texas's transmission system; and
 • an increase of $27.6 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2023.

 The increase was partially offset by the partial sale of a service center in April 2023 for $11 million as part of an eminent domain proceeding.

 Increases in Entergy Texas's receivable from the money pool are a use of cash flow, and Entergy Texas's receivable from the money pool increased $218.4 million in 2023 compared to increasing by $99.5 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries' dependence on external short-term borrowings.

 Net cash flow provided by financing activities increased $144.6 million in 2023 primarily due to:

 • the issuance of $350 million of 5.80% Series mortgage bonds in August 2023;
 • a capital contribution of $150 million received from Entergy Corporation in 2023 in order to maintain Entergy Texas's capital structure and in anticipation of various capital expenditures;
 • the payment of $105 million of common stock dividends in 2022. No common stock dividends were paid in 2023 in order to maintain Entergy Texas's capital structure;
 • money pool activity;
 • principal payments of $17.8 million on securitization bonds in 2023 as compared to principal payments of $66.5 million on securitization bonds in 2022; and
 • an increase of $22.8 million in prepaid deposits related to contributions-in-aid-of-construction primarily for customer and generator interconnection agreements.

 The increase was partially offset by the issuance of $325 million of 5.00% Series mortgage bonds in August 2022 and the issuance of $290.85 million of senior secured system restoration bonds in April 2022.

 Decreases in Entergy Texas's payable to the money pool are a use of cash flow, and Entergy Texas's payable to the money pool decreased $79.6 million in 2022.

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

 See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow" in Item 7 of Entergy Texas's Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.

 Entergy Texas's debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio is primarily due to net income in 2023 and the capital contribution of $150 million received from Entergy Corporation in 2023, partially offset by the issuance of long-term debt in 2023.

2023
2022

 50.9
 %
 52.0
 %

 Effect of excluding securitization bonds
 (2.1
 %)
 (2.5
 %)

 Debt to capital, excluding securitization bonds (non-GAAP) (a)
 48.8
 %
 49.5
 %

 (0.2
 %)
 —
 %

 Net debt to net capital, excluding securitization bonds (non-GAAP) (a)
 48.6
 %
 49.5
 %

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

 Net debt consists of debt less cash and cash equivalents. Debt consists of finance lease obligations and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. The debt to capital ratio excluding securitization bonds and net debt to net capital ratio excluding securitization bonds are non-GAAP measures. Entergy Texas uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Texas's financial condition because the securitization bonds are non-recourse to Entergy Texas, as more fully described in Note 5 to the financial statements. Entergy Texas also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Texas's financial condition because net debt indicates Entergy Texas's outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

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

 Entergy Texas requires capital resources for:

 • working capital purposes, including the financing of fuel and purchased power costs; and
 • dividend and interest payments.

 Following are the amounts of Entergy Texas's planned construction and other capital investments.

 2024
 2025
 2026

 $445
 $935
 $1,205

 Total
 $1,290
 $1,630
 $1,980

 In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Texas includes investments in generation projects to modernize, decarbonize, and diversify Entergy Texas's portfolio, including Orange County Advanced Power Station; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting renewables expansion and customer growth; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.

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

 2024
 2025
 2026

 $141
 $141
 $270
 $422
 $4,537

 $7
 $6
 $5
 $4
 $2

 $2
 $2
 $2
 $3
 $1

 Entergy Texas expects to contribute approximately $8.3 million to its qualified pension plans and approximately $156 thousand to other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See "Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits" below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

 Entergy Texas has $33.6 million of unrecognized tax benefits net of unused tax attributes plus interest and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

 In addition, Entergy Texas enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Texas has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations.

 As a subsidiary, Entergy Texas dividends its earnings to Entergy Corporation at a percentage determined monthly.

 Orange County Advanced Power Station

 In September 2021, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas's certificate of convenience and necessity to construct, own, and operate the Orange County Advanced Power Station, a new 1,215 MW combined-cycle combustion turbine facility to be located in Bridge City, Texas at an initially-estimated expected total cost of $1.2 billion inclusive of the estimated costs of the generation facilities, transmission upgrades, contingency, an allowance for funds used during construction, and necessary regulatory expenses, among others. The project includes combustion turbine technology with dual fuel capability, able to co-fire up to 30% hydrogen by volume upon commercial operation and upgradable to support 100% hydrogen operations in the future. In December 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. In March 2022 certain intervenors filed testimony opposing the hydrogen co-firing component of the proposed project and others filed testimony opposing the project outright. Also in March 2022 the PUCT staff filed testimony opposing the hydrogen co-firing component of the proposed project, but otherwise taking no specific position on the merits of the project. The PUCT staff also proposed that the PUCT establish a maximum amount that Entergy Texas may recover in rates attributable to the project. In April 2022, Entergy Texas filed rebuttal testimony addressing and rebutting these various arguments. The hearing on the merits was held in June 2022, and post-hearing briefs were submitted in July 2022. In September 2022 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas's application for certification of Orange County Advanced Power Station subject to certain conditions, including a cap on cost recovery at $1.37 billion, the exclusion of investment associated with co-firing hydrogen, weatherization requirements, and customer receipt of any contractual benefits associated with the facility's guaranteed heat rate. In October 2022 the parties in the proceeding filed exceptions and replies to exceptions to the proposal for decision. Also in October 2022, Entergy Texas filed with the PUCT information regarding a new fixed pricing option for an estimated project cost of approximately $1.55 billion associated with Entergy Texas's issuance of limited notice to proceed by mid-November 2022. In November 2022 the PUCT issued a final order approving the requested amendment to Entergy Texas's certificate of convenience and necessity to construct, own, and operate the Orange County Advanced Power Station without the investment associated with hydrogen co-firing capability, without a cap on cost recovery, and subject to certain conditions, including weatherization requirements and customer receipt of any contractual benefits associated with the facility's guaranteed heat rate.

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

 Entergy Texas's sources to meet its capital requirements include:

 • debt or preferred stock issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;

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

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

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

 2023
 2022
 2021
 2020

 $317,882
 $99,468
 ($79,594)
 $4,601

 Entergy Texas has a credit facility in the amount of $150 million scheduled to expire in June 2028. The credit facility includes fronting commitments for the issuance of letters of credit against $30 million of the borrowing capacity of the facility. As of December 31, 2023, there were no cash borrowings and $1.1 million in letters of credit outstanding under the credit facility. In addition, Entergy Texas is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2023, $76.5 million in letters of credit were outstanding under Entergy Texas's uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

 Entergy Texas obtained authorizations from the FERC through April 2025 for short-term borrowings, not to exceed an aggregate amount of $200 million at any time outstanding, and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Texas's short-term borrowing limits.

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

 Filings with the PUCT and Texas Cities

 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 have been reset to zero 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 December 2022 the ALJs with the State Office of Administrative Hearings issued two orders, one adopting the parties' joint proposal that issues related to electric vehicle charging infrastructure be decided exclusively on written evidence and briefing, and one adopting a joint proposed briefing outline and schedule with deadlines in January 2023 for the parties to submit briefing on issues related to electric vehicle charging infrastructure and admitting evidence related to electric vehicle charging infrastructure issues. In January 2023 the parties filed initial and reply briefs addressing issues related to electric vehicle charging infrastructure.

 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, 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, except for the issues related to electric vehicle charging infrastructure, to the PUCT to consider the settlement. In June 2023 the ALJ issued a proposal for decision related to the electric vehicle charging infrastructure issues and which noted recent legislation enacted which permits electric utilities to own and operate such infrastructure. The ALJ's proposal for decision deferred to the PUCT regarding whether it is appropriate for any vertically integrated electric utility, or Entergy Texas specifically, to own electric vehicle charging infrastructure, and in the event that the PUCT decided ownership is permissible, the ALJ recommended approval of the proposed tariff to charge host customers for utility-owned and operated electric vehicle charging infrastructure sited on customer premises and denial of the proposed tariff to temporarily adjust billing demand charges for separately metered electric vehicle charging infrastructure, citing cost-shifting concerns. In July 2023 the parties filed exceptions and replies to exceptions to the proposal for decision. In August 2023 the PUCT issued an order approving the unopposed settlement and also issued an order severing the issues related to electric vehicle charging infrastructure addressed in the ALJ's proposal for decision to a separate proceeding. Concurrently, Entergy Texas recorded the reversal of $21.9 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved.

 Following the PUCT's approval of the unopposed settlement in August 2023, Entergy Texas recorded a regulatory liability of $10.3 million, which reflects 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 is 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 will also be 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.

 In December 2023 the PUCT referred the separate proceeding to resolve issues related to electric vehicle charging infrastructure to the State Office of Administrative Hearings. In January 2024, the ALJ with the State Office of Administrative Hearings adopted a procedural schedule setting a hearing on the merits for April 2024.

 Distribution Cost Recovery Factor (DCRF) Rider

 In October 2020, 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 $26.3 million annually, or $6.8 million in incremental annual revenues beyond Entergy Texas's then-effective DCRF rider based on its capital invested in distribution between January 1, 2020 and August 31, 2020. In February 2021 the ALJ with the State Office of Administrative Hearings approved Entergy Texas's agreed motion for interim rates, which went into effect in March 2021. In March 2021 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested DCRF revenue requirement and resolving all issues in the proceeding. In May 2021 the PUCT issued an order approving the settlement.

 In August 2021, 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 $40.2 million annually, or $13.9 million in incremental annual revenues beyond Entergy Texas's then-effective DCRF rider based on its capital invested in distribution between September 1, 2020 and June 30, 2021. In September 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. A procedural schedule was established with a hearing scheduled in December 2021. In December 2021 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested DCRF revenue requirement and resolving all issues in the proceeding, including a motion for interim rates to take effect for usage on and after January 24, 2022. Also, in December 2021, the ALJ with the State Office of Administrative Hearings issued an order granting the motion for interim rates, which went into effect in January 2022, admitting evidence, and remanding the proceeding to the PUCT to consider the settlement. In March 2022 the PUCT issued an order approving the settlement.

 Transmission Cost Recovery Factor (TCRF) Rider

 In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The new TCRF rider was designed to collect approximately $2.7 million annually from Entergy Texas's retail customers based on its capital invested in transmission between January 1, 2018 and September 30, 2018. In April 2019 parties filed testimony proposing a load growth adjustment, which would fully offset Entergy Texas's proposed TCRF revenue requirement. In July 2019 the PUCT granted Entergy Texas's application as filed to begin recovery of the requested $2.7 million annual revenue requirement, rejecting opposing parties' proposed adjustment; however, the PUCT found that the question of prudence of the actual investment costs should be determined in Entergy Texas's next rate case similar to the procedure used for the costs recovered through the DCRF rider. In October 2019 the PUCT issued an order on a motion for rehearing, clarifying and affirming its prior order granting Entergy Texas's application as filed. Also in October 2019 a second motion for rehearing was filed, and Entergy Texas filed a

 response in opposition to the motion. The second motion for rehearing was overruled by operation of law. In December 2019, Texas Industrial Energy Consumers filed an appeal to the PUCT order in district court alleging that the PUCT erred in declining to apply a load growth adjustment.

 In October 2020, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended rider was designed to collect from Entergy Texas's retail customers approximately $51 million annually, or $31.6 million in incremental annual revenues beyond Entergy Texas's then-effective TCRF rider based on its capital invested in transmission between July 1, 2019 and August 31, 2020. In March 2021 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested TCRF revenue requirement with interim rates effective March 2021 and resolving all issues in the proceeding. In March 2021 the ALJ granted the motion for interim rates, admitted evidence, and remanded the case to the PUCT for consideration of a final order at a future open meeting. In June 2021 the PUCT issued an order approving the settlement.

 In October 2021, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended rider was designed to collect from Entergy Texas's retail customers approximately $66.1 million annually, or $15.1 million in incremental annual revenues beyond Energy Texas's then-effective TCRF rider based on its capital invested in transmission between September 1, 2020 and July 31, 2021 and changes in approved transmission charges. In January 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In February 2022 the parties filed an unopposed settlement recommending that Entergy Texas be allowed to collect its full requested TCRF revenue requirement with interim rates effective March 2022. In February 2022 the ALJ granted the motion for interim rates, admitted evidence, and remanded the case to the PUCT for consideration of a final order at a future open meeting. In June 2022 the PUCT issued an order approving the settlement.

 Generation Cost Recovery Rider

 In October 2020, Entergy Texas filed an application to establish a generation cost recovery rider with an initial annual revenue requirement of approximately $91 million to begin recovering a return of and on its generation capital investment in the Montgomery County Power Station through August 31, 2020. In December 2020, Entergy Texas filed an unopposed settlement supporting a generation cost recovery rider with an annual revenue requirement of approximately $86 million. The settlement revenue requirement was based on a depreciation rate intended to fully depreciate Montgomery County Power Station over 38 years and the removal of certain costs from Entergy Texas's request. Under the settlement, Entergy Texas retained the right to propose a different depreciation rate and seek recovery of a majority of the costs removed from its request in its next base rate proceeding, and such depreciation rate was revised to fully depreciate Montgomery County Power Station over 40 years and all requested capital additions were approved as prudent in the 2022 base rate case proceeding discussed above. On January 14, 2021, the PUCT approved the generation cost recovery rider settlement rates on an interim basis and abated the proceeding. In March 2021, Entergy Texas filed to update its generation cost recovery rider to include its generation capital investment in Montgomery County Power Station after August 31, 2020. In April 2021 the ALJ issued an order unabating the proceeding and in May 2021 the ALJ issued an order finding Entergy Texas's application and notice of the application to be sufficient. In May 2021, Entergy Texas filed an amendment to the application to reflect the PUCT's approval of the sale of a 7.56% partial interest in the Montgomery County Power Station to East Texas Electric Cooperative, Inc., which closed in June 2021. In June 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2021 the ALJ with the State Office of Administrative Hearings adopted a procedural schedule setting a hearing on the merits for September 2021. In July 2021 the parties filed a motion to abate the procedural schedule noting they had reached an agreement in principle and to allow the parties time to finalize a settlement agreement, which motion was granted by the ALJ. In October 2021, Entergy Texas filed on behalf of the parties an unopposed settlement agreement that would adjust its generation cost recovery rider to recover an annual revenue requirement of approximately $88.3 million related to Entergy Texas's investment in the Montgomery County Power Station through January 1, 2021, with Entergy Texas able to seek recovery of the remainder of its investment in its next base rate case, and all requested capital additions were approved as prudent in the 2022 base rate case proceeding discussed above. Also in October 2021 the ALJ granted a motion to admit evidence and remand the proceeding to the PUCT. In January 2022 the PUCT issued an

 order approving the unopposed settlement. In February 2022, Entergy Texas filed a relate-back rider to collect over five months an additional approximately $5 million, which is the difference between the interim revenue requirement approved in January 2021 and the revenue requirement approved in January 2022 that reflects Entergy Texas's full generation capital investment and ownership in Montgomery County Power Station on January 1, 2021, plus carrying costs from January 2021 through January 2022 when the updated revenue requirement took effect. In April 2022, Entergy Texas and the PUCT staff filed a joint proposed order supporting approval of Entergy Texas's as-filed request. The PUCT approved the relate-back rider consistent with Entergy Texas's as-filed request, and rates became effective over a five-month period, in August 2022.

 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 Hardin 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. In September 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. A procedural schedule was established with a hearing scheduled in April 2022. 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 March 2022, Entergy Texas filed on behalf of the parties an unopposed motion, which motion was granted by the ALJ with the State Office of Administrative Hearings, to abate the procedural schedule indicating that the parties had reached an agreement in principle. 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 is $4.5 million in incremental annual revenue above the $88.3 million approved in January 2022, related to Entergy Texas's actual investment in the acquisition of the Hardin County Peaking Facility. Concurrently with filing of the unanimous settlement agreement, Entergy Texas submitted an agreed motion to admit evidence and remand the case to the PUCT for review and consideration of the settlement agreement, which motion was granted by the ALJ with the State Office of Administrative Hearings. 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. See Note 14 to the financial statements for discussion of the Hardin County Peaking Facility purchase.

 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 to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation by the end of 2024.

 In May 2022, Entergy Texas filed an application with the PUCT to implement an interim fuel surcharge to collect the cumulative under-recovery of approximately $51.7 million, including interest, of fuel and purchased power costs incurred from May 1, 2020 through December 31, 2021. The under-recovery balance is primarily attributable to the impacts of Winter Storm Uri, including historically high natural gas prices, partially offset by settlements received by Entergy Texas from MISO related to Hurricane Laura. Entergy Texas proposed that the interim fuel surcharge be assessed over a period of six months beginning with the first billing cycle after the PUCT

 issues a final order, but no later than the first billing cycle of September 2022. Also in May 2022, the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2022, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding. In addition, Entergy Texas filed on behalf of the parties a motion to admit evidence, to approve interim rates as requested in the initial application, and to remand the proceeding to the PUCT to consider the unopposed settlement. In August 2022 the ALJ with the State Office of Administrative Hearings issued an order granting Entergy Texas's motion, approving interim rates effective with the first billing cycle of September 2022, and remanding the case to the PUCT for final approval. The interim fuel surcharge was approved by the PUCT in January 2023.

 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 May 2023, Entergy Texas filed, and the ALJ with the State Office of Administrative Hearings granted, a joint motion to abate the proceeding to give parties additional time to finalize a settlement. 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.

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

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

 Industrial and Commercial Customers

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

 Entergy Texas's facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Texas is in substantial compliance with

 environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in "Regulation of Entergy's Business - Environmental Regulation" in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

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

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

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

 Entergy Texas's qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See "Qualified Pension and Other Postretirement Benefits" in the "Critical Accounting Estimates" section of Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.

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

 $182
 $5,266

 $577
 $—

 0.25%
 $196
 $953

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

 $7
 $1,188

 0.25%
 $59
 $755

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

 Total qualified pension cost for Entergy Texas in 2023 was $15.7 million, including $11.2 million in settlement costs. Entergy Texas anticipates 2024 qualified pension cost to be $436 thousand. Entergy Texas contributed $5.3 million to its qualified pension plans in 2023 and estimates 2024 pension contributions will be approximately $8.3 million, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024 valuations are completed, which is expected by April 1, 2024.

 Total postretirement health care and life insurance benefit income for Entergy Texas in 2023 was $8.8 million. Entergy Texas expects 2024 postretirement health care and life insurance benefit income to approximate $10.9 million. Entergy Texas contributed $235 thousand to its other postretirement plans in 2023 and estimates 2024 contributions will be approximately $156 thousand.

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

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

 We have audited the accompanying consolidated balance sheets of Entergy Texas, Inc. and Subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of income, cash flows, and changes in equity (pages 434 through 438 and applicable items in pages 47 through 238), for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

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

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

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

 Critical Audit Matter

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

 Rate and Regulatory Matters — Entergy Texas, Inc. and Subsidiaries — Refer to Note 2 to the financial statements

 The Company is subject to rate regulation by the Public Utility Commission of Texas (the "PUCT"), which has jurisdiction with respect to the rates of electric companies in Texas, and to wholesale rate regulation by the Federal Energy Regulatory Commission ("FERC"). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

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

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

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

 • We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management's controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
 • We evaluated the Company's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
 • We read relevant regulatory orders issued by the PUCT and the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the PUCT's and the FERC's treatment of similar costs under similar circumstances. We evaluated external information and compared to management's recorded regulatory asset and liability balances for completeness.
 • For regulatory matters in process, we inspected the Company's filings with the PUCT and the FERC and orders issued, and considered the filings with the PUCT and the FERC by intervenors that may impact the Company's future rates, for any evidence that might contradict management's assertions.
 • We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management's assertion that amounts are probable of recovery or 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.

 2023
 2022
 2021

 $ 2,028,586
 $ 2,288,905
 $ 1,902,511

 403,111
 443,765
 335,742

 468,511
 717,501
 588,941

 323,797
 312,340
 281,713

 117,852
 101,673
 94,989

 278,311
 230,692
 214,838

 7,324
 49,175
 59,581

 TOTAL
 1,598,906
 1,855,146
 1,575,804

 429,680
 433,759
 326,707

 OTHER INCOME

 28,193
 13,527
 9,892

 11,116
 4,141

 ( 10,411)
 ( 6,572)

 TOTAL
 28,898
 11,096
 11,450

 114,978
 95,454
 87,787

 ( 10,545)
 ( 4,547)
 ( 3,980)

 TOTAL
 104,433
 90,907
 83,807

 354,145
 353,948
 254,350

 62,872
 50,621
 25,526

 291,273
 303,327
 228,824

 Preferred dividend requirements
 2,072
 2,072
 1,909

 EARNINGS APPLICABLE TO COMMON STOCK
 $ 289,201
 $ 301,255
 $ 226,915

 2023
 2022
 2021

 $ 291,273
 $ 303,327
 $ 228,824

 Adjustments to reconcile net income to net cash flow provided by operating activities:

 278,311
 230,692
 214,838

 53,507
 41,648
 48,813

 24,249
 ( 35,131)
 ( 16,455)

 ( 24,097)
 15,962
 10,819

 ( 22,046)
 48,199
 ( 5,718)

 ( 14,146)
 44,015
 ( 3,420)

 7,357
 4,926
 ( 1,854)

 119,096
 ( 209,835)
 ( 133,636)

 ( 36,097)
 ( 19,574)
 ( 12,105)

 Provisions for estimated losses
 1,887
 ( 649)
 ( 140)

 ( 17,924)
 ( 157,349)
 103,380

 ( 20,122)
 ( 30,499)
 ( 28,747)

 Effect of securitization on regulatory asset
 —
 153,383
 —

 ( 36,131)
 20,656
 ( 42,502)

 36,574
 ( 344)
 ( 5,164)

 641,691
 409,427
 356,933

 ( 946,543)
 ( 696,879)
 ( 702,754)

 28,193
 13,527
 9,892

 Proceeds from sale of assets
 11,000
 —
 67,920

 Payment for purchase of assets
 —
 —
 ( 36,534)

 Litigation proceeds from settlement agreement
 —
 4,134
 —

 ( 218,414)
 ( 99,468)
 4,601

 Changes in securitization account
 5,684
 15,750
 9,604

 Increase in other investments
 ( 5,868)
 ( 1,133)
 —

 ( 1,125,948)
 ( 764,069)
 ( 647,271)

 344,895
 606,168
 127,931

 ( 17,835)
 ( 66,514)
 ( 269,435)

 Capital contributions from parent
 —
 95,000

 Proceeds from the issuance of preferred stock
 —
 —
 3,713

 —
 ( 79,594)
 79,594

 Dividends paid:

 Common stock
 —
 ( 105,000)
 —

 Preferred stock
 ( 2,060)
 ( 1,881)

 Other
 27,758
 5,111
 6,848

 Net cash flow provided by financing activities
 502,746
 358,111
 41,770

 18,489
 3,469
 ( 248,568)

 3,497
 248,596

 $ 21,986
 $ 3,497
 $ 28

 Cash paid during the period for:

 $ 104,766
 $ 87,682
 $ 87,094

 $ 28,969
 $ 1,864
 $ 17,594

 $ 257,467
 $ 68,893
 $ 73,105

 2023
 2022

 Cash
 $ 1,497
 $ 500

 20,489
 2,997

 21,986
 3,497

 5,195
 10,879

 88,468
 115,955

 ( 1,484)
 ( 2,352)

 329,941
 115,549

 Other
 24,416
 21,587

 72,771
 69,208

 514,112
 319,947

 139,019
 258,115

 50,847
 26,750

 123,020
 93,031

 35,232
 20,568

 TOTAL
 889,411
 732,787

 Investments in affiliates - at equity

 Other
 15,068
 18,975

 TOTAL
 15,658
 19,601

 7,931,340
 7,409,461

 857,707
 339,139

 8,789,047
 7,748,600

 2,363,919
 2,135,400

 6,425,128
 5,613,200

 Other regulatory assets (includes securitization property of $ 250,324 as of December 31, 2023 and $ 269,523 as of December 31, 2022)

 596,606
 578,682

 Other
 129,769
 99,694

 TOTAL
 726,375
 678,376

 $ 8,056,572
 $ 7,043,964

 2023
 2022

 $ 74,423
 $ 70,321

 Other
 195,703
 201,982

 39,999
 38,764

 78,887
 93,033

 31,285
 23,928

 Other
 16,237
 16,963

 TOTAL
 436,534
 444,991

 814,905
 744,227

 7,963
 8,711

 114,759
 132,647

 43,013
 45,247

 Asset retirement cost liabilities
 11,743
 11,121

 9,480
 7,593

 Long-term debt (includes securitization bonds of $ 257,592 as of December 31, 2023 and $ 275,064 as of December 31, 2022)

 3,225,092
 2,895,913

 Other
 274,421
 74,053

 TOTAL
 4,501,376
 3,919,512

 Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2023 and 2022

 49,452
 49,452

 Paid-in capital
 1,200,125
 1,050,125

 Retained earnings
 1,830,335
 1,541,134

 Total common shareholder's equity
 3,079,912
 2,640,711

 Preferred stock without sinking fund
 38,750
 38,750

 TOTAL
 3,118,662
 2,679,461

 $ 8,056,572
 $ 7,043,964

 Common Equity

 Preferred Stock
 Common Stock
 Paid-in Capital
 Retained Earnings
 Total

 $ 35,000
 $ 49,452
 $ 955,162
 $ 1,117,964
 $ 2,157,578

 —
 —
 —
 228,824
 228,824

 Capital contributions from parent
 —
 —
 95,000
 —
 95,000

 Preferred stock issuance
 3,750
 —
 ( 37)
 —
 3,713

 Preferred stock dividends
 —
 —
 —
 ( 1,909)
 ( 1,909)

 $ 49,452
 $ 1,050,125
 $ 1,344,879
 $ 2,483,206

 —
 —
 —
 303,327
 303,327

 Common stock dividends
 —
 —
 —
 ( 105,000)
 ( 105,000)

 Preferred stock dividends
 —
 —
 —

 $ 49,452
 $ 1,050,125
 $ 1,541,134
 $ 2,679,461

 —
 —
 —
 291,273
 291,273

 Capital contributions from parent
 —
 —
 —

 Preferred stock dividends
 —
 —
 —

 $ 49,452
 $ 1,200,125
 $ 1,830,335
 $ 3,118,662

 System Energy's principal asset consists of an ownership interest and a leasehold interest in Grand Gulf. The capacity and energy from its 90% interest is sold under the Unit Power Sales Agreement to its only four customers, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. System Energy's operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% interest in Grand Gulf pursuant to the Unit Power Sales Agreement. Payments under the Unit Power Sales Agreement are System Energy's only source of operating revenues. As discussed in "Complaints Against System Energy" below, System Energy and the Unit Power Sales Agreement are currently the subject of several litigation proceedings at the FERC (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit).

 System Energy had net income of $108.8 million in 2023 compared to a net loss of $276.6 million in 2022 primarily due to a regulatory charge of $551 million ($413 million net-of-tax) recorded in second quarter 2022 to reflect the effects of the partial settlement agreement and offer of settlement related to pending proceedings before the FERC. The increase was partially offset by the disallowance of the recovery of sale-leaseback lease renewal costs from Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans per the December 2022 FERC order related to the Grand Gulf sale-leaseback renewal complaint and the lower authorized rate of return on equity and capital structure limitations on monthly bills issued to Entergy Mississippi per the June 2022 settlement agreement with the MPSC. See Note 2 to the financial statements for discussion of the partial settlement agreement with the MPSC and discussion of the Grand Gulf sale-leaseback renewal complaint.

 Income Taxes

 The effective income tax rates were 22.7% for 2023 and 25.1% for 2022. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.

 See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations" in Item 7 of System Energy's Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.

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

 Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:

 2023
 2022
 2021

 $2,940
 $89,201
 $242,469

 273,572
 7,280
 201,211

 (75,806)
 (264,184)
 (193,392)

 (200,646)
 170,643
 (161,087)

 (2,880)
 (86,261)
 (153,268)

 $60
 $2,940
 $89,201

 Net cash flow provided by operating activities increased $266.3 million in 2023 primarily due to:

 • the refund of $235 million to Entergy Mississippi in 2022 as a result of the settlement with the MPSC. See Note 2 to the financial statements for discussion of the settlement agreement with the MPSC;
 •$40.5 million in recoupment payments received from Entergy Louisiana and Entergy New Orleans in October 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy's October 2023 compliance filing with the FERC. See Note 2 to the financial statements for further discussion of the Grand Gulf sale-leaseback renewal complaint;
 • income tax refunds of $19.8 million in 2023 as compared to income tax payments of $18.4 million in 2022. System Energy received income tax refunds in 2023 and made income tax payments in 2022, each in accordance with an intercompany income tax allocation agreement;
 • a decrease in spending of $36.4 million on nuclear refueling outage costs in 2023 as compared to 2022; and
 • a decrease of $13.1 million in pension contributions in 2023. 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.

 • aggregate refunds of $103.5 million made 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 Note 2 to the financial statements for further discussion of the refunds and the related proceedings;
 • refunds of $41.8 million included in September 2023 service month bills under the Unit Power Sales Agreement to reflect the revenue requirement effects of Grand Gulf's updated depreciation rates as approved by the FERC in August 2023. See Note 2 to the financial statements for discussion of the Unit Power Sales Agreement depreciation amendment proceeding; and
 • refunds of $19.3 million included in May 2023 service month bills under the Unit Power Sales Agreement to reflect the effects of the partial settlement agreement approved by the FERC in April 2023. See Note 2 to the financial statements for discussion of the Unit Power Sales Agreement complaint.

 Net cash flow used in investing activities decreased by $188.4 million in 2023 primarily due to:

 • money pool activity;
 • a decrease of $43.4 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and
 • a decrease of $41.8 million in nuclear construction expenditures primarily due to higher spending in 2022 on Grand Gulf outage projects and upgrades.

 Decreases in System Energy's receivable from the money pool are a source of cash flow, and System Energy's receivable from the money pool decreased $95 million in 2023 compared to increasing by $19.2 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries' dependence on external short-term borrowings.

 System Energy's financing activities used $200.6 million of cash in 2023 compared to providing $170.6 million of cash in 2022 primarily due to the following activity:

 • the repayment, at maturity, of $250 million of 4.10% Series mortgage bonds in April 2023;
 •$170 million in common stock dividends and distributions paid in 2023. No common stock dividends or distributions were made in 2022 in order to maintain System Energy's capital structure and in anticipation of the settlement with the MPSC. See Note 2 to the financial statements for discussion of the settlement with the MPSC;
 • a $135 million capital contribution from Entergy Corporation in 2022 primarily to fund the settlement payment to Entergy Mississippi;
 • the issuance of a $50 million term loan in May 2022, which was repaid, prior to maturity, in March 2023;
 • net repayments of $51.1 million in 2023 as compared to net long-term borrowings of $36.5 million in 2022 on the nuclear fuel company variable interest entity's credit facilities;
 • the repayment, at maturity, of $50.3 million of 2.5% Series governmental bonds in April 2022; and
 • the issuance of $325 million of 6.00% Series mortgage bonds in March 2023.

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

 See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow" in Item 7 of System Energy's Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.

 System Energy's debt to capital ratio is shown in the following table.

2023
2022

 45.4
 %
 45.0
 %

 —
 %
 (0.1
 %)

 Net debt to net capital (non-GAAP)
 45.4
 %
 44.9
 %

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

 System Energy seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend or a capital distribution, to the extent funds are legally available to do so, or a combination of the three, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments and other uses of cash such as the payment of expenses in the ordinary course, System Energy may issue incremental debt or reduce dividends, or both, to maintain its capital structure. In addition, System Energy may receive equity contributions to maintain its capital structure for certain circumstances that would materially alter the capital structure if financed entirely with debt and reduced dividends.

 System Energy requires capital resources for:

 • working capital purposes, including the financing of fuel costs and tax payments; and
 • dividend, distribution, and interest payments.

 Following are the amounts of System Energy's planned construction and other capital investments.

 2024
 2025
 2026

 $165
 $125
 $150

 Total
 $175
 $130
 $155

 In addition to routine spending to maintain operations, the planned capital investment estimate includes amounts associated with Grand Gulf investments and initiatives.

 Following are the amounts of System Energy's existing debt obligations (includes estimated interest payments).

 2024
 2025
 2026

 $46
 $266
 $41
 $479
 $252

 System Energy expects to contribute approximately $16.7 million to its qualified pension plans and approximately $34 thousand to other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

 System Energy has no unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

 In addition, System Energy enters into nuclear fuel purchase agreements that contain minimum purchase obligations. As discussed in Note 8 to the financial statements, System Energy recovers these costs through charges under the Unit Power Sales Agreement.

 As a wholly-owned subsidiary, System Energy dividends its earnings to Entergy Corporation at a percentage determined monthly.

 System Energy's sources to meet its capital requirements include:

 • debt issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
 • equity contributions; and

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

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

 System Energy's receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.

 2023
 2022
 2021
 2020

 ($12,246)
 $94,981
 $75,745
 $4,004

 The System Energy nuclear fuel company variable interest entity has a credit facility in the amount of $120 million scheduled to expire in June 2025. As of December 31, 2023, $21.5 million in loans were outstanding under the System Energy nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the variable interest entity credit facility.

 System Energy obtained authorizations from the FERC through March 2025 for the following:

 • short-term borrowings not to exceed an aggregate amount of $200 million at any time outstanding;
 • long-term borrowings and security issuances not to exceed an aggregate amount of $1.3 billion at any time outstanding; and
 • borrowings by its nuclear fuel company variable interest entity.

 See Note 4 to the financial statements for further discussion of System Energy's short-term borrowing limits.

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

 Complaints Against System Energy

 System Energy's operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. System Energy and the Unit Power Sales Agreement are currently the subject of several litigation proceedings at the FERC (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit), 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. The settlement with the MPSC described in "System Energy Settlement with the MPSC" below, and the settlement in principle with the APSC described in "System Energy Settlement with the APSC" below, if approved by the FERC, substantially reduce the aggregate amount of exposure resulting from these claims. The claims in these proceedings include claims for refunds and claims for rate adjustments; the aggregate amount of refunds claimed in these proceedings, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of additional refunds, System Energy may be required to seek financing to pay such refunds, the cost and availability of which are unknown. Following are discussions of these proceedings.

 Return on Equity and Capital Structure Complaints

 In January 2017 the APSC and MPSC filed a complaint with the FERC against System Energy. The complaint seeks 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 current return on equity under the Unit Power Sales Agreement is 10.94%, which was established in a rate proceeding that became final in July 2001. As discussed below in "System Energy Settlement with the MPSC," beginning with the July 2022 service month, bills issued to Entergy Mississippi under the Unit Power Sales Agreement reflect a return on equity of 9.65%.

 The APSC and MPSC complaint alleges that the return on equity is unjust and unreasonable because capital market and other considerations indicate that it is excessive. The complaint requests proceedings to investigate the return on equity and establish a lower return on equity, and also requests that the FERC establish January 23, 2017 as a refund effective date. The complaint includes return on equity analysis that purports to establish that the range of reasonable return on equity for System Energy is between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputes that a return on equity of 8.37% to 8.67% is 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 requests similar relief from the FERC with respect to System Energy's return on equity and also requests the FERC to investigate System Energy's capital structure. The APSC, MPSC, and 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 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 MPSC complaint for hearing. The parties 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, System Energy filed a request for rehearing and the LPSC filed a request for rehearing or reconsideration of the FERC's August 2018 order. The LPSC's request referenced an amended complaint that it filed on the same day raising 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 submitted a response 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. As noted below, in June 2019 settlement discussions were terminated 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.

 In January 2019 the LPSC, the APSC, and the MPSC filed direct testimony in the return on equity proceeding. For the refund period January 23, 2017 through April 23, 2018, the LPSC argues for an authorized return on equity for System Energy of 7.81% and the APSC and the MPSC argue for an authorized return on equity for System Energy of 8.24%. For the refund period April 27, 2018 through July 27, 2019, and for application on a

 prospective basis, the LPSC argues for an authorized return on equity for System Energy of 7.97% and the APSC and the MPSC argue for an authorized return on equity for System Energy of 8.41%. In March 2019, System Energy submitted answering testimony. For the first refund period, System Energy's testimony argues for a return on equity of 10.10% (median) or 10.70% (midpoint). For the second refund period, System Energy's testimony shows that the calculated returns on equity for the first period fall within the range of presumptively just and reasonable returns on equity, and thus the second complaint should be dismissed (and the first period return on equity used going forward). If the FERC nonetheless were to set a new return on equity for the second period (and going forward), System Energy argues the return on equity should be either 10.32% (median) or 10.69% (midpoint).

 In May 2019 the FERC trial staff filed its direct and answering testimony in the return on equity proceeding. For the first refund period, the FERC trial staff calculates an authorized return on equity for System Energy of 9.89% based on the application of FERC's proposed methodology. The FERC trial staff's direct and answering testimony noted that an authorized return on equity of 9.89% for the first refund period was within the range of presumptively just and reasonable returns on equity for the second refund period, as calculated using a study period ending January 31, 2019 for the second refund period.

 In June 2019, System Energy filed testimony responding to the testimony filed by the FERC trial staff. Among other things, System Energy's testimony rebutted arguments raised by the FERC trial staff and provided updated calculations for the second refund period based on the study period ending May 31, 2019. For that refund period, System Energy's testimony shows that strict application of the return on equity methodology proposed by the FERC staff indicates that the second complaint would not be dismissed, and the new return on equity would be set at 9.65% (median) or 9.74% (midpoint). System Energy's testimony argues that these results are insufficient in light of benchmarks such as state returns on equity and treasury bond yields, and instead proposes that the calculated returns on equity for the second period should be either 9.91% (median) or 10.3% (midpoint). System Energy's testimony also argues that, under application of its proposed modified methodology, the 10.10% return on equity calculated for the first refund period would fall within the range of presumptively just and reasonable returns on equity for the second refund period.

 Also in June 2019, the FERC's Chief ALJ issued an order terminating settlement discussions in the amended complaint addressing System Energy's capital structure. The ALJ consolidated the amended capital structure complaint with the ongoing return on equity proceeding and set new procedural deadlines for the consolidated hearing.

 In August 2019 the LPSC, the APSC, and the MPSC filed rebuttal testimony in the return on equity proceeding and direct and answering testimony relating to System Energy's capital structure. The LPSC re-argues for an authorized return on equity for System Energy of 7.81% for the first refund period and 7.97% for the second refund period. The APSC and MPSC argue for an authorized return on equity for System Energy of 8.26% for the first refund period and 8.32% for the second refund period. With respect to capital structure, the LPSC proposes that the FERC establish a hypothetical capital structure for System Energy for ratemaking purposes. Specifically, the LPSC proposes that System Energy's common equity ratio be set to Entergy Corporation's equity ratio of 37% equity and 63% debt. In the alternative, the LPSC argues that the equity ratio should be no higher than 49%, the composite equity ratio of System Energy and the other Entergy operating companies who purchase under the Unit Power Sales Agreement. The APSC and the MPSC recommend that 35.98% be set as the common equity ratio for System Energy. As an alternative, the APSC and the MPSC propose that System Energy's common equity be set at 46.75% based on the median equity ratio of the proxy group for setting the return on equity.

 In September 2019 the FERC trial staff filed its rebuttal testimony in the return on equity proceeding. For the first refund period, the FERC trial staff calculates an authorized return on equity for System Energy of 9.40% based on the application of the FERC's proposed methodology and an updated proxy group. For the second refund period, based on the study period ending May 31, 2019, the FERC trial staff rebuttal testimony argues for a return on equity of 9.63%. In September 2019 the FERC trial staff also filed direct and answering testimony relating to System Energy's capital structure. The FERC trial staff argues 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 calculates the average capital structure for its proposed proxy group of 46.74% common equity, and 53.26% debt.

 In October 2019, System Energy filed answering testimony disputing the FERC trial staff's, the LPSC's, and the APSC's and MPSC's arguments for the use of a hypothetical capital structure and arguing that the use of System Energy's actual capital structure is just and reasonable.

 In November 2019, in a proceeding that did not involve System Energy, the FERC issued an order addressing the methodology for determining the return on equity applicable to transmission owners in MISO. Thereafter, the procedural schedule in the System Energy proceeding was amended to allow the participants to file supplemental testimony addressing the order in the MISO transmission owner proceeding (Opinion No. 569).

 In February 2020 the LPSC, the MPSC and APSC, and the FERC trial staff filed supplemental testimony addressing Opinion No. 569 and how it would affect the return on equity evaluation for the two complaint periods concerning System Energy. For the first refund period, based on their respective interpretations and applications of the Opinion No. 569 methodology, the LPSC argues for an authorized return on equity for System Energy of 8.44%; the MPSC and APSC argue for an authorized return on equity of 8.41%; and the FERC trial staff argues for an authorized return on equity of 9.22%. For the second refund period and on a prospective basis, based on their respective interpretations and applications of the Opinion No. 569 methodology, the LPSC argues for an authorized return on equity for System Energy of 7.89%; the MPSC and APSC argue that an authorized return on equity of 8.01% may be appropriate; and the FERC trial staff argues for an authorized return on equity of 8.66%.

 In April 2020, System Energy filed supplemental answering testimony addressing Opinion No. 569. System Energy argues that the Opinion No. 569 methodology is conceptually and analytically defective for purposes of establishing just and reasonable authorized return on equity determinations and proposes an alternative approach. As its primary recommendation, System Energy continues to support the return on equity determinations in its March 2019 testimony for the first refund period and its June 2019 testimony for the second refund period. Under the Opinion No. 569 methodology, System Energy calculates a "presumptively just and reasonable range" for the authorized return on equity for the first refund period of 8.57% to 9.52%, and for the second refund period of 8.28% to 9.11%. System Energy argues that these ranges are not just and reasonable results. Under its proposed alternative methodology, System Energy calculates an authorized return on equity of 10.26% for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively.

 In May 2020 the FERC issued an order on rehearing of Opinion No. 569 (Opinion No. 569-A). In June 2020 the procedural schedule in the System Energy proceeding was further revised in order to allow parties to address the Opinion No. 569-A methodology. Pursuant to the revised schedule, in June 2020, the LPSC, MPSC and APSC, and the FERC trial staff filed supplemental testimony addressing Opinion No. 569-A and how it would affect the return on equity evaluation for the two complaint periods concerning System Energy. For the first refund period, based on their respective interpretations and applications of the Opinion No. 569-A methodology, the LPSC argues for an authorized return on equity for System Energy of 7.97%; the MPSC and APSC argue for an authorized return on equity of 9.24%; and the FERC trial staff argues 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 argues for an authorized return on equity for System Energy of 7.78%; the MPSC and APSC argue that an authorized return on equity of 9.15% may be appropriate if the second complaint is not dismissed; and the FERC trial staff argues for an authorized return on equity of 9.09% if the second complaint is not dismissed.

 Pursuant to the revised procedural schedule, in July 2020, System Energy filed supplemental testimony addressing Opinion No. 569-A. System Energy argues 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. As its primary recommendation, System Energy argues for the use of a methodology that incorporates four separate financial models, including the constant growth form of the discounted cash flow model and the empirical capital asset pricing model. Based on application of its recommended methodology, System Energy argues for an authorized return on equity of 10.12% for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively. Under the Opinion No. 569-A methodology, System Energy calculates an authorized return on equity of 9.44% for the first refund period, which also falls within the presumptively just and reasonable range calculated for the second refund period and prospectively.

 The parties and FERC trial staff filed final rounds of testimony in August 2020. The hearing before a FERC ALJ occurred in late-September through early-October 2020, post-hearing briefing took place in November and December 2020.

 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% is 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 System Energy's actual equity ratio is excessive and that the just and reasonable equity ratio is 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. If the ALJ's initial decision is upheld, the estimated refund for this proceeding is approximately $41 million, which includes interest through December 31, 2023, and the estimated resulting annual rate reduction would be approximately $25 million. As a result of the 2022 settlement agreement with the MPSC, both the estimated refund and rate reduction exclude Entergy Mississippi's portion. See "System Energy Settlement with the MPSC" below for discussion of the settlement. The estimated refund will continue to accrue interest until a final FERC decision is issued.

 The ALJ initial decision is an interim step in the FERC litigation process, and an ALJ's determinations made in an initial decision are not controlling on the FERC. 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. Refunds, if any, that might be required will only become due after the FERC issues its order reviewing the initial decision.

 As discussed in "System Energy Settlement with the MPSC" below, beginning with the July 2022 service month, bills issued to Entergy Mississippi under the Unit Power Sales Agreement were adjusted to reflect a capital structure not to exceed 52% equity.

 In August 2022 the D.C. Circuit Court of Appeals issued an order addressing appeals of FERC's Opinion No. 569 and 569-A, which established the methodology applied in the ALJ's initial decision in the proceeding against System Energy discussed above. The appellate order addressed the methodology for determining the return on equity applicable to transmission owners in MISO. The D.C. Circuit found the FERC's use of the Risk Premium model as part of the methodology to be arbitrary and capricious, and remanded the case back to the FERC. The remanded case is pending FERC action.

 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 alleges 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 is double-recovering costs by including both the lease payments and the capital additions in Unit Power Sales Agreement billings. The complaint also claims 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 alleges that System Energy violated various other reporting and accounting requirements and should have sought prior FERC approval of the lease renewal. The complaint seeks various forms of relief from the FERC. The complaint seeks 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. The complaint also asks that the FERC disallow and refund the lease costs of the sale-leaseback renewal on grounds of imprudence, investigate System Energy's treatment of a DOE litigation payment, and impose 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 is inconsistent with a FERC-approved settlement to which the LPSC is a party and that explicitly authorizes 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 fails 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. The FERC established 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. In March 2019 the LPSC, the MPSC, the APSC and the City Council filed direct testimony. The LPSC testimony sought refunds that include 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, and the cost of capital additions associated with the sale-leaseback interest, as well as interest on those amounts.

 In June 2019 System Energy filed answering testimony arguing that the FERC should reject all claims for refunds. Among other things, System Energy argued that claims for refunds of the costs of lease renewal payments and capital additions should be rejected because those costs were recovered consistent with the Unit Power Sales Agreement formula rate, System Energy was not over or double recovering any costs, and ratepayers will save costs over the initial and renewal terms of the leases. System Energy argued that claims for refunds associated with liabilities arising from uncertain tax positions should be rejected because the liabilities do not provide cost-free capital, the repayment timing of the liabilities is uncertain, and the outcome of the underlying tax positions is uncertain. System Energy's testimony also challenged the refund calculations supplied by the other parties.

 In August 2019 the FERC trial staff filed direct and answering testimony seeking refunds for rate base reductions for liabilities associated with uncertain tax positions. The FERC trial staff also argued that System Energy recovered $32 million more than it should have in depreciation expense for capital additions. In September 2019, System Energy filed cross-answering testimony disputing the FERC trial staff's arguments for refunds, stating that the FERC trial staff's position regarding depreciation rates for capital additions is not unreasonable, but

 explaining that 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 will also involve changes to accumulated depreciation, accumulated deferred income taxes, and other formula elements as needed. In October 2019 the LPSC filed rebuttal testimony increasing the amount of refunds sought for liabilities associated with uncertain tax positions. The LPSC seeks approximately $512 million plus interest, which is approximately $310 million through December 31, 2023. The FERC trial staff also filed rebuttal testimony in which it seeks refunds of a similar amount as the LPSC for the liabilities associated with uncertain tax positions. The LPSC testimony also argued that adjustments to depreciation rates should affect rate base on a prospective basis only.

 A hearing was held before a FERC ALJ in November 2019. In April 2020 the 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 is 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 is 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.

 In addition, in September 2020, the IRS issued a Notice of Proposed Adjustment (NOPA) and Entergy executed it. The NOPA memorializes 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 proposes 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 propose the inclusion of the RAR as support for the filings. In December 2020 the LPSC, the APSC, and the City Council filed a protest in response to the amendments, reiterating their prior objections to the filings. 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. The one-time credit was made 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 disallows 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 are 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 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 are 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. The $103.5 million in total refunds calculated in the compliance filing were reclassified from long-term other regulatory liabilities to a current regulatory liability as of December 31, 2022. 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 have been deemed denied by operation of law. The deemed denial of the rehearing request initiates a sixty-day period in which aggrieved parties may petition for federal appellate court review of the underlying FERC orders; however, the FERC may issue a substantive order on rehearing as long as it continues to have jurisdiction over the case. 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 August 2023 the FERC issued an order addressing arguments raised on rehearing and partially setting aside the prior order (rehearing order). The rehearing order addresses 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 directs 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 allows 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 allows 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 directs 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 has 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. On this issue, as reflected in its January 2023 compliance filing, System Energy believes it has already paid the refunds due under the remedy that the FERC outlined for the uncertain tax positions issue in its December 2022 order. In August 2023 the LPSC issued a media release in which it stated that it disagrees with System Energy's determination that the rehearing order requires no further refunds to be made on this issue.

 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 requests 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 requests 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 has been 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. In February 2024 the parties filed a proposed briefing schedule under which briefing will occur from March 2024 through July 2024.

 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. The LPSC directive authorized its staff to file complaints at the FERC "necessary to address these rate issues, to request a full investigation into the rates charged by System Energy for Grand Gulf power, and to seek rate refund, rate reduction, and such other remedies as may be necessary and appropriate to protect Louisiana ratepayers." The LPSC directive further stated that the LPSC has seen "information suggesting that the Grand Gulf plant has been significantly underperforming compared to other nuclear plants in the United States, has had several extended and unexplained outages, and has been plagued with serious safety concerns." The LPSC expressed concern that the costs paid by Entergy Louisiana's retail customers may have been detrimentally impacted, and authorized "the filing of a FERC complaint to address these performance issues and to seek appropriate refund, rate reduction, and other remedies as may be appropriate."

 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 raises 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 overlap with the previous complaints. The filed rate allegations not previously raised are 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 alleges are 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 requests 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 is warranted because all claims fall into one or more of the following categories: the claims have been raised and are being litigated in another proceeding; the claims do not present a prima facie case and do not satisfy the threshold burden to establish a complaint proceeding; the claims are 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 are barred or waived by the legal doctrine of laches; and/or the claims have 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 January 2021 the complainants filed a response to System Energy's November 2020 answer, and in February 2021, System Energy filed a response to the complainant's response.

 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

 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 subsequently 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. The appeal was initially stayed for a period of 90 days, but the stay expired. 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 include, 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 is also seeking a retroactive adjustment to retained earnings and capital structure in conjunction with the implementation of its proposed refunds. In addition, the LPSC seeks 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 argues 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 alleges 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 recommends a refund of approximately $98.8 million for the period 2004-September 2021 or other alternative relief. The City Council further recommends 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 argues, 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 has 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 has been correct. System Energy further responds that no retroactive adjustment to retained earnings or capital structure should be ordered because there is 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 are 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 have been included in rates for decades, is unjust and unreasonable. In response to the LPSC's proposed going-forward adjustments, System Energy presents evidence to show that none of the proposed adjustments are 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 argues that the Unit Power Sales Agreement does 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 are appropriate on those issues. In response to the City Council's claims, System Energy argues that it has reasonably managed its cash and

 that the City Council's theory of cash management is defective because it fails to adequately consider the relevant cash needs of System Energy and it makes faulty presumptions about the operation of the Entergy system money pool. System Energy further points out that the issue of its capital structure is 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 recommends 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 recommends refunds of $84.1 million, exclusive of any tax gross-up or FERC interest. In addition, the FERC trial staff recommends 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 concern the reasonableness of System Energy's rate of return, the FERC trial staff states that it is unnecessary to consider such issues in this 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 recommends 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 asserts 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 warrant historical refunds. The LPSC's rebuttal testimony argues that refunds for the alleged tariff violations and other claims must be calculated by rerunning the Unit Power Sales Agreement formula rate; however, it includes estimates of refunds associated with some, but not all, of its claims, totaling $286 million without interest. The City Council's rebuttal testimony also proposes 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 agrees with the LPSC's direct testimony that retained earnings should be adjusted in a comprehensive refund calculation. The testimony quantifies 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 are 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 are 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 seek more than $700 million in refunds and interest, based on charges to all Unit Power Sales Agreement purchasers including Entergy Mississippi.

 In June 2022 a new procedural schedule was adopted, providing for additional rounds of testimony and for the hearing to begin in September 2022. The hearing concluded in December 2022.

 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 agrees to the global settlement System Energy entered into with the MPSC (discussed below), and such global settlement includes a black-box refund amount, then the black-box refund for this settlement agreement shall 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. Based on this finding, the initial decision recommended refunds; System Energy estimates that those refunds for Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans would total approximately $116 million plus $152 million of interest through December 31, 2023. The initial decision also finds that the Unit Power Sales Agreement should be modified such that a cash working capital allowance of negative $36.4 million is applied prospectively. If the FERC ultimately orders these modifications to cash working capital be implemented, the estimated annual revenue requirement impact is expected to be immaterial. 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.

 The initial decision is an interim step in the FERC litigation process, and an ALJ's determination made in an initial decision is not controlling on the FERC. System Energy disagrees 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. The APSC's brief on exceptions challenges the ALJ's determinations on the money pool interest and retained earnings issues. The LPSC's brief on exceptions challenges the ALJ's determinations regarding the sale-leaseback transaction costs, legal fees, and retained earnings issues. The City Council's brief on exceptions challenges the ALJ's determinations on the money pool and cash management issues. The FERC trial staff's brief on exceptions challenges the ALJ's determinations on the cash working capital issue as well as certain of the accumulated deferred income taxes issues. In August 2023 all parties filed separate briefs opposing exceptions. System Energy filed a brief opposing the exceptions of the APSC, the LPSC, and the City Council. The APSC, the LPSC, and the City Council filed separate briefs opposing the exceptions raised by System Energy and the FERC trial staff. The FERC trial staff filed its own brief opposing certain exceptions raised by System Energy, the APSC, the LPSC, and the City Council. The case is now pending a decision by the FERC. Refunds, if any, that might be required will become due only after the FERC issues its order reviewing the initial decision.

 Grand Gulf Prudence Complaint

 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 contains two primary allegations. First, it alleges 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 seeks refunds of at least $360 million in alleged replacement energy costs, in addition to other costs, including those that can only be identified upon further investigation. Second, it alleges that the performance and/or management of the 2012 extended power uprate of Grand Gulf was imprudent, and it seeks refunds of all costs of the 2012 uprate that are determined to result from imprudent planning or management of the project. In addition to the requested refunds, the complaint asks that the FERC modify the Unit Power Sales Agreement to provide for full cost recovery only if certain performance indicators are met and to require pre-authorization of capital improvement projects in excess of $125 million before related costs may 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 argues that the complaint does not meet its legal burden because, among other reasons, it fails to allege any specific imprudent conduct. With respect to the claim concerning the uprate, System Energy argues that the complaint fails because, among other reasons, the complainants' own conduct prevents them from raising a serious doubt as to the prudence of the uprate. System Energy also requests that the FERC dismiss other elements of the complaint, including the proposed modifications to the Unit Power Sales Agreement, because they are not warranted. Additional responsive pleadings were filed by the complainants and System Energy during the period from March through July 2021. In November 2022 the FERC issued an order setting the complaint for settlement and hearing procedures. 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. Pursuant to that schedule, the complainant's testimony was filed in December 2023. System Energy's answering testimony is due April 2024, and additional rounds of testimony are due through October 2024. The hearing is scheduled to begin in January 2025, with the presiding ALJ's initial decision due in July 2025.

 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. As discussed below in "System Energy Settlement with the APSC", the APSC has settled all of its claims related to this proceeding. The amended complaint states that it is being filed for three primary purposes: (1) to include System Energy's performance in 2021-2022 in the scope of the hearing; (2) to explicitly allege that System Energy's inadequate performance, excessive costs, unplanned outages, and costs attributable to safety violations violate the contractual obligation to maintain and operate the plant in accordance with "good utility practice"; and (3) to provide and substantiate allegations concerning the damages attributable to the alleged breach of contractual obligations. The amended complaint alleges that potentially more than $1 billion in damages may be due. In November 2023, System Energy and the other Entergy respondents filed an answer and motion to dismiss the amended and supplemental complaint.

 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 memorializes 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 Unit Power Sales Agreement is a FERC-jurisdictional formula rate tariff for sales of energy and capacity from System Energy's owned and leased share of Grand Gulf to Entergy Mississippi, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans.

 Entergy Mississippi purchases the greatest single amount, nearly 40% of System Energy's share of Grand Gulf, after its additional purchases from affiliates are considered. The settlement therefore limits System Energy's overall refund exposure associated with the identified proceedings because they will be resolved completely as between the Entergy parties and the MPSC.

 The settlement provided for a black-box refund of $235 million from System Energy to Entergy Mississippi, which was to be paid within 120 days of the settlement's effective date (either the date of the FERC approval of the settlement without material modification, or the date that all settling parties agree to accept modifications or otherwise modify the settlement in response to a proposed material modification by the FERC). 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, 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 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. System Energy paid the black-box refund of $235 million to Entergy Mississippi in November 2022. See "System Energy Regulatory Liability for Pending Complaints" below for discussion of the regulatory liability related to complaints against System Energy as of December 31, 2023.

 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 covers the amended and supplemental complaint, discussed above in "Grand Gulf Prudence Complaint," filed at the FERC in October 2023. System Energy, Entergy Arkansas, additional Entergy parties, and the APSC filed the settlement agreement and supporting materials with the FERC in November 2023. The Unit Power Sales Agreement is a FERC-jurisdictional formula rate tariff for sales of energy and capacity from System Energy's owned and leased share of Grand Gulf to Entergy Mississippi, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. As discussed above in "System Energy Settlement with the MPSC," System Energy previously settled with the MPSC with respect to these complaints before the FERC. Entergy Mississippi has nearly 40% of System Energy's share of Grand Gulf's output, after its additional purchases from affiliates are considered. The settlements with both the APSC and the MPSC represent almost 65% of System Energy's share of the output of Grand Gulf.

 The terms of the settlement with the APSC align with the $588 million global black box settlement reached between System Energy and the MPSC in June 2022 and provide 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 November 2022 the FERC approved the System Energy settlement with the MPSC and stated that the settlement "appears to be fair and reasonable and in the public interest."

 In addition to the black box refund of $142 million described above, beginning with the November 2023 service month, the settlement provides 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.

 In December 2023 the FERC trial staff and the LPSC filed comments. The FERC trial staff commented that it "believes that the settlement is fair, and in the public interest," and neither it nor the LPSC oppose the settlement. In December 2023 the $93 million black box refund to Entergy Arkansas was reclassified from long-

 term other regulatory liabilities to accounts payable - associated companies on System Energy's balance sheet. If the FERC approves the filed settlement in accordance with its terms, it will become binding upon the Entergy parties and the APSC.

 System Energy Regulatory Liability for Pending Complaints

 Prior to June 2022, System Energy recorded a provision and associated liability of $37 million for elements of the complaints against System Energy. In June 2022, as discussed in "System Energy Settlement with the MPSC" above, System Energy recorded a regulatory charge of $551 million ($413 million net-of-tax), increasing System Energy's 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 New Orleans, and Entergy Louisiana. The $142 million of refunds for Entergy Arkansas, discussed above in "System Energy Settlement with the APSC" is covered within the $353 million previously recorded. System Energy paid the black-box refund of $235 million to Entergy Mississippi in November 2022. As discussed above in "Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue," in January 2023 System Energy paid refunds of $103.5 million as a result of the FERC's order in December 2022 in that proceeding and recouped $40.5 million of the $103.5 million from Entergy Louisiana and Entergy New Orleans in October 2023. In addition, as discussed above in "Unit Power Sales Agreement Complaint," a black-box refund of $18 million was made by System Energy in 2023 in connection with a partial settlement in that proceeding.

 Based on analysis of the pending complaints against System Energy and potential future settlement negotiations with the LPSC and the City Council, 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. As discussed above, in December 2023 the $93 million black box refund to Entergy Arkansas was reclassified from the regulatory liability to accounts payable - associated companies on System Energy's balance sheet. System Energy's remaining regulatory liability related to complaints against System Energy as of December 31, 2023 is $178 million. This regulatory liability is consistent with the settlement agreements reached with the MPSC and the APSC, as described above, taking into account amounts already or expected to be refunded.

 Unit Power Sales Agreement

 System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2020 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. The formal challenge alleges: (1) that it was imprudent for System Energy to accept the IRS's partial acceptance of a previously uncertain tax position; (2) that System Energy should have delayed recording the result of the IRS's partial acceptance of the previously uncertain tax position until after internal tax allocation payments were made; (3) that the equity ratio charged in rates was excessive; (4) that sale-leaseback rental payments should have been excluded from rates; and (5) that all issues in the ongoing Unit Power Sales Agreement complaint proceeding should also be reflected in calendar year 2020 bills. While System Energy disagrees that any refunds are owed for the 2020 calendar year bills, the formal challenge estimates that the financial impact of the first through fourth allegations is approximately $53 million; it does not provide an estimate of the financial impact of the fifth allegation. However, $17 million of the $53 million is attributable to the sale-leaseback rental payments. These were refunded to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans in January 2023 as a result of the FERC order received in the Grand Gulf sale-leaseback renewal complaint and uncertain tax position rate base issue. Entergy Mississippi's portion of the refund was included within the settlement with the MPSC, as discussed below.

 In March 2022, System Energy filed an answer to the formal challenge in which it requested that the FERC deny the formal challenge as a matter of law, or else hold the proceeding in abeyance pending the resolution of related dockets.

 System Energy Formula Rate Annual Protocols Formal Challenge Concerning 2021 Calendar Year Bills

 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. The formal challenge alleges: (1) that it was imprudent for System Energy to accept the IRS's partial acceptance of a previously uncertain tax position; (2) that System Energy used incorrect inputs for retained earnings that are used to determine the capital structure; (3) that the equity ratio charged in rates was excessive; and (4) that all issues in the ongoing Unit Power Sales Agreement complaint proceeding should also be reflected in calendar year 2021 bills. The first, third, and fourth allegations are identical to issues that were raised in the formal challenge to the calendar year 2020 bills. The formal challenge to the calendar year 2021 bills states that the impact of the first allegation is "tens of millions of dollars," but it does not provide an estimate of the financial impact of the remaining allegations.

 In May 2023, System Energy filed an answer to the formal challenge in which it requested that the FERC deny the formal challenge as a matter of law, or else hold the proceeding in abeyance pending the resolution of related dockets.

 Depreciation Amendment Proceeding

 In December 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to adopt updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses. The proposed amendments would result in higher charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. In February 2022 the FERC accepted System Energy's proposed increased depreciation rates with an effective date of March 1, 2022, subject to refund pending the outcome of the settlement and/or hearing procedures. In June 2023 System Energy filed with the FERC an unopposed offer of settlement that it had negotiated with intervenors to the proceeding. In August 2023 the FERC approved the settlement, which resolves the proceeding. In third quarter 2023, System Energy recorded a reduction in depreciation expense of $41 million representing the cumulative difference in depreciation expense resulting from the depreciation rates used from March 2022 through June 2023 and the depreciation rates included in the settlement filing approved by the FERC. In October 2023, System Energy filed a refund report with the FERC. The refund provided for in the refund report was included in the September 2023 service month bills under the Unit Power Sales Agreement. No comments or protests to the refund report were filed.

 Pension Costs Amendment Proceeding

 In October 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to include in rate base the prepaid and accrued pension costs associated with System Energy's qualified pension plans. Based on data ending in 2020, the increased annual revenue requirement associated with the filing is approximately $8.9 million. In March 2022 the FERC accepted System Energy's proposed amendments with an effective date of December 1, 2021, subject to refund pending the outcome of the settlement and/or hearing procedures. In August 2023 the FERC chief ALJ terminated settlement procedures and designated a presiding ALJ to oversee hearing procedures. In October 2023, System Energy filed direct testimony in support of its proposed amendments. Under the procedural schedule, testimony will be filed through April 2024, and the hearing is scheduled to begin in May 2024. The presiding ALJ's initial decision is expected to be due in September 2024.

 System Energy owns and, through an affiliate, operates the Grand Gulf nuclear generating plant and is, therefore, subject to the risks related to such ownership and operation. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, including the financial requirements to address emerging issues related to equipment reliability, to position Grand Gulf to meet its operational goals; the performance and capacity factors of Grand Gulf; the risk of an adverse outcome to a challenge to the prudence of operations at Grand Gulf; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of the site when required; and limitations on the amounts of insurance recoveries for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of Grand Gulf, System Energy may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Grand Gulf's operating license expires in 2044.

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

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

 Nuclear Decommissioning Costs

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

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

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

 System Energy's qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See "Qualified Pension and Other Postretirement Benefits" in the "Critical Accounting Estimates" section of Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.

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

 $235
 $6,886

 $659
 $—

 0.25%
 $247
 $1,227

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

 ($5)
 $909

 0.25%
 $56
 $663

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

 Total qualified pension cost for System Energy in 2023 was $12.6 million, including $6.4 million in settlement costs. System Energy anticipates 2024 qualified pension cost to be $5.2 million. System Energy contributed $15.5 million to its qualified pension plans in 2023 and estimates 2024 pension contributions will approximate $16.7 million, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024 valuations are completed, which is expected by April 1, 2024.

 Total postretirement health care and life insurance benefit income for System Energy in 2023 was $348 thousand. System Energy expects 2024 postretirement health care and life insurance benefit income to approximate $913 thousand. System Energy contributed $480 thousand to its other postretirement plans in 2023 and expects 2024 contributions to approximate $34 thousand.

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

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

 To the shareholder and Board of Directors of

 We have audited the accompanying balance sheets of System Energy Resources, Inc. (the "Company") as of December 31, 2023 and 2022, the related statements of operations, cash flows, and changes in common equity (pages 467 through 472 and applicable items in pages 47 through 238), for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

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

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

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

 Critical Audit Matter

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

 Rate and Regulatory Matters — System Energy Resources, Inc. — Refer to Note 2 to the financial statements

 The Company is subject to wholesale rate regulation by the Federal Energy Regulatory Commission ("FERC"). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

 The Company's rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the FERC sets the rates the Company is allowed to charge customers based on allowable costs, including a reasonable

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

 We identified the impact of rate regulation as a critical audit matter due to the judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the (1) likelihood of recovery in future rates of incurred costs and the (2) likelihood of refunds to customers. Auditing management's judgments regarding the outcome of future decisions by the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and auditor judgment to evaluate management estimates and the subjectivity of audit evidence.

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

 • We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management's controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
 • We evaluated the Company's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
 • We read relevant regulatory orders issued by the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the FERC's treatment of similar costs under similar circumstances. We evaluated external information and compared to management's recorded regulatory asset and liability balances for completeness.
 • For regulatory matters in process, we inspected the Company's and intervenors' filings with the FERC, initial Administrative Law Judge decisions and FERC orders issued, and settlement offers and agreements with the FERC for any evidence that might contradict management's assertions.
 • We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management's assertion that amounts are probable of recovery or 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.

 STATEMENTS OF OPERATIONS

 2023
 2022
 2021

 $ 586,603
 $ 658,812
 $ 570,848

 71,762
 50,216
 58,313

 Nuclear refueling outage expenses
 26,745
 24,482
 27,244

 207,765
 226,557
 214,322

 41,773
 40,235
 38,693

 29,224
 29,428
 27,842

 90,858
 111,889
 105,978

 ( 57,429)
 503,162
 26,214

 TOTAL
 410,698
 985,969
 498,606

 OPERATING INCOME (LOSS)
 175,905
 ( 327,157)
 72,242

 OTHER INCOME (DEDUCTIONS)

 7,531
 8,312
 6,188

 13,131
 5,096
 82,744

 ( 9,101)
 ( 19,616)
 ( 18,991)

 TOTAL
 11,561
 ( 6,208)
 69,941

 48,416
 37,381
 38,393

 ( 1,754)
 ( 1,325)
 ( 1,047)

 TOTAL
 46,662
 36,056
 37,346

 INCOME (LOSS) BEFORE INCOME TAXES
 140,804
 ( 369,421)
 104,837

 32,032
 ( 92,828)
 ( 1,977)

 NET INCOME (LOSS)
 $ 108,772
 ($ 276,593)
 $ 106,814

 STATEMENTS OF CASH FLOWS

 2023
 2022
 2021

 $ 108,772
 ($ 276,593)
 $ 106,814

 Adjustments to reconcile net income (loss) to net cash flow provided by operating activities:

 Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 195,045
 194,411
 198,067

 32,982
 ( 85,720)
 11,191

 8,359
 ( 19,530)
 6,054

 78,655
 ( 11,948)
 23,973

 19,804
 ( 25,321)
 ( 50,059)

 1,363
 ( 123)
 ( 1,008)

 20,749
 ( 38,764)
 25,096

 ( 31,239)
 ( 19,575)
 143,417

 11,009
 21,252
 40,884

 ( 21,259)
 ( 35,354)
 ( 49,308)

 ( 150,668)
 304,545
 ( 253,910)

 273,572
 7,280
 201,211

 ( 121,075)
 ( 164,797)
 ( 100,474)

 7,531
 8,312
 6,188

 Nuclear fuel purchases
 ( 80,663)
 ( 96,659)
 ( 45,180)

 Proceeds from sale of nuclear fuel
 46,242
 18,855
 21,724

 ( 3)
 ( 300)

 Proceeds from nuclear decommissioning trust fund sales
 390,004
 346,504
 1,022,170

 Investment in nuclear decommissioning trust funds
 ( 412,823)
 ( 357,463)
 ( 1,025,779)

 94,981
 ( 19,236)
 ( 71,741)

 ( 75,806)
 ( 264,184)
 ( 193,392)

 715,545
 1,022,472
 662,423

 ( 758,437)
 ( 986,829)
 ( 727,510)

 —
 135,000
 —

 Change in money pool payable - net
 12,246
 —
 —

 Common stock dividends and distributions paid
 ( 170,000)
 —
 ( 96,000)

 Net cash flow provided by (used in) financing activities
 ( 200,646)
 170,643
 ( 161,087)

 ( 2,880)
 ( 86,261)
 ( 153,268)

 2,940
 89,201
 242,469

 $ 60
 $ 2,940
 $ 89,201

 $ 45,196
 $ 39,848
 $ 39,340

 ($ 19,810)
 $ 18,413
 $ 54,959

 $ 25,301
 $ 28,960
 $ 23,388

 BALANCE SHEETS

 2023
 2022

 Cash
 $ 60
 $ 78

 —
 2,862

 2,940

 54,544
 158,601

 Other
 6,861
 6,145

 61,405
 164,746

 155,565
 135,346

 Deferred nuclear refueling outage costs
 8,603
 33,377

 3,373
 9,097

 TOTAL
 229,006
 345,506

 Decommissioning trust funds
 1,342,317
 1,142,914

 TOTAL
 1,342,317
 1,142,914

 5,495,728
 5,425,449

 130,866
 102,987

 160,655
 193,004

 5,787,249
 5,721,440

 3,493,299
 3,412,257

 2,293,950
 2,309,183

 446,360
 415,121

 Other
 1,422

 TOTAL
 447,090
 416,543

 $ 4,312,363
 $ 4,214,146

 BALANCE SHEETS

 2023
 2022

 $ 57
 $ 300,037

 118,523
 21,701

 Other
 73,580
 58,178

 27,401
 7,597

 12,954
 11,591

 Sale-leaseback/depreciation regulatory liability
 —
 103,497

 Other
 4,354
 4,071

 TOTAL
 236,869
 506,672

 405,744
 376,070

 46,960
 44,692

 107,458
 110,840

 782,912
 665,024

 1,084,234
 1,042,461

 19,491
 40,750

 738,402
 477,868

 Other
 1,754

 TOTAL
 3,186,955
 2,757,707

 COMMON EQUITY

 Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2023 and 2022

 916,850
 1,086,850

 Accumulated deficit
 ( 28,311)
 ( 137,083)

 TOTAL
 888,539
 949,767

 $ 4,312,363
 $ 4,214,146

 STATEMENTS OF CHANGES IN COMMON EQUITY

 Common Stock
 Retained Earnings (Accumulated Deficit)
 Total

 $ 951,850
 $ 128,696
 $ 1,080,546

 —
 106,814
 106,814

 Common stock dividends and distributions
 —
 ( 96,000)
 ( 96,000)

 $ 951,850
 $ 139,510
 $ 1,091,360

 —
 ( 276,593)
 ( 276,593)

 135,000
 —
 135,000

 $ 1,086,850
 ($ 137,083)
 $ 949,767

 —
 108,772
 108,772

 Common stock dividends and distributions
 ( 170,000)
 —
 ( 170,000)

 $ 916,850
 ($ 28,311)
 $ 888,539

 Item 2. Properties

 Information regarding the registrant's properties is included in Part I, Item 1. - Entergy's Business under the sections titled "Utility - Property and Other Generation Resources" and "Other Business Activities - Property" in this report.

 Item 3. Legal Proceedings

 Details of the registrant's material environmental regulation and proceedings and other regulatory proceedings and litigation that are pending or those terminated in the fourth quarter of 2023 are discussed in Part I, Item 1. - Entergy's Business under the sections titled "Retail Rate Regulation," "Environmental Regulation," and "Litigation."

 Item 4. Mine Safety Disclosures

 Not applicable.

 INFORMATION ABOUT EXECUTIVE OFFICERS OF ENTERGY CORPORATION

 Executive Officers

 Name
 Age

 Andrew S. Marsh (a)
 Chief Executive Officer of Entergy Corporation

 Chairman of the Board of Entergy Corporation
 2023-Present

 Executive Vice President and Chief Financial Officer of Entergy Corporation
 2013-2022

 Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
 2013-2022

 Executive Vice President and Chief Financial Officer of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
 2014-2022

 Marcus V. Brown (a)
 Executive Vice President and General Counsel of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
 2013-Present

 Kimberly A. Fontan (a)
 Executive Vice President and Chief Financial Officer of Entergy Corporation

 Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy

 Executive Vice President and Chief Financial Officer of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy

 Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
 2019-2022

 Vice President, System Planning of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas
 2017-2019

 Name
 Age

 Roderick K. West (a)
 Group President Utility Operations of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas
 2017-Present

 President, Chief Executive Officer, and Director of System Energy
 2017-Present

 Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
 2017-Present

 Jason Chapman (a)

 Senior Vice President, Chief Technology and Business Services Officer of Entergy Corporation

 2023-Present

 Acting Senior Vice President, Corporate Business Services of Entergy Services
 2023

 Vice President, Enterprise Shared Services of Entergy Services
 2019-2023

 Vice President, Global Business Services, Xylem, Inc.
 2016-2019

 Kathryn A. Collins
 Senior Vice President and Chief Human Resources Officer of Entergy Corporation
 2020-Present

 Chief Human Resources Officer, Arcosa, Inc.
 2018-2020

 Vice President, Human Resources, Trinity, Inc.
 2014-2018

 Kimberly Cook-Nelson (a)
 Executive Vice President and Chief Nuclear Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy

 Director of System Energy

 Chief Operating Officer, Nuclear Operations of Entergy Services
 2021-2022

 Vice President, System Planning of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas
 2019-2021

 Vice President, Operations Support of Entergy Services
 2016-2019

 Anastasia Minor
 Chief Transformation Officer of Entergy Services
 2023-Present

 Senior Vice President, Strategy and Financial Planning of Entergy Services
 2022-2023

 Vice President, Financial Business Partners of Entergy Services
 2017-2022

 Peter S. Norgeot, Jr. (a)
 Executive Vice President and Chief Operating Officer of Entergy Corporation

 Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas

 Senior Vice President, Operations and Development of Entergy Corporation
 2022

 Senior Vice President, Sustainable Planning, Development and Operations of Entergy Corporation
 2021-2022

 Senior Vice President, Transformation of Entergy Corporation
 2018-2021

 Name
 Age

 Reginald T. Jackson (a)
 Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy

 Vice President, Internal Audit and General Auditor of Entergy Services
 2020-2022

 Director, Real Estate and Security of Entergy Services
 2014-2020

 (a)In addition, this officer is an executive officer and/or director of various other wholly owned subsidiaries of Entergy Corporation and its operating companies.

 Each officer of Entergy Corporation is elected yearly by the Board of Directors. Each officer's age and title are provided as of December 31, 2023.

 Item 5. Market for Registrants' Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

 The shares of Entergy Corporation's common stock are listed on the New York Stock and Chicago Stock Exchanges under the ticker symbol ETR. As of January 31, 2024, there were 19,887 stockholders of record of Entergy Corporation. See "Dividends and Stock Repurchases" in the "Capital Expenditure Plans and Other Uses of Capital" section of Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis and Note 7 to the financial statements for details of Entergy Corporation's payment of dividends.

 Issuer Purchases of Equity Securities (1)

 Total Number of Shares Purchased
 Average Price Paid per Share
 Total Number of Shares Purchased as Part of a Publicly Announced Plan
 Maximum $ Amount of Shares that May Yet be Purchased Under a Plan (2)

 10/01/2023 - 10/31/2023
 —
 $—
 —
 $350,052,918

 11/01/2023 - 11/30/2023
 —
 $—
 —
 $350,052,918

 12/01/2023 - 12/31/2023
 —
 $—
 —
 $350,052,918

 Total
 —
 $—
 —

 In accordance with Entergy's stock-based compensation plans, Entergy periodically grants stock options to key employees, which may be exercised to obtain shares of Entergy's common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy's management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans. In addition to this authority, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2010 the Board granted authority for a $500 million share repurchase program. The amount of share repurchases under these programs may vary as a result of material changes in business results or capital spending or new investment opportunities. In addition, in the first quarter 2023, Entergy withheld 71,722 shares of its common stock at $108.71 per share, 27,533 shares of its common stock at $107.69 per share, 12,265 shares of its common stock at $107.59 per share, 551 shares of its common stock at $103.72 per share, 232 shares of its common stock at $106.07 per share, and 100 shares of its common stock at $105.79 per share to pay income taxes due upon vesting of restricted stock granted and payout of performance units as part of its long-term incentive program.

 (1)See Note 12 to the financial statements for additional discussion of the stock-based compensation plans.
 (2)Maximum amount of shares that may yet be repurchased relates only to the $500 million share repurchase program plan and does not include an estimate of the amount of shares that may be purchased to fund the exercise of grants under the stock-based compensation plans.

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

 There is no market for the common equity of the Registrant Subsidiaries.

 Item 6. Reserved

 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

 Refer to "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS" of each of ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, LLC AND SUBSIDIARIES, ENTERGY LOUISIANA, LLC AND SUBSIDIARIES, ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES, ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES, ENTERGY TEXAS, INC. AND SUBSIDIARIES, and SYSTEM ENERGY RESOURCES, INC.

 Item 7A. Quantitative and Qualitative Disclosures About Market Risk

 Refer to "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES - Market and Credit Risk Sensitive Instruments."

 Item 8. Financial Statements and Supplementary Data

 Refer to "TABLE OF CONTENTS - Entergy Corporation and Subsidiaries, Entergy Arkansas, LLC and Subsidiaries, Entergy Louisiana, LLC and Subsidiaries, Entergy Mississippi, LLC and Subsidiaries, Entergy New Orleans, LLC and Subsidiaries, Entergy Texas, Inc. and Subsidiaries, and System Energy Resources, Inc."

 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 No event that would be described in response to this item has occurred with respect to Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, or System Energy.

 Item 9A. Controls and Procedures

 Disclosure Controls and Procedures

 As of December 31, 2023, evaluations were performed under the supervision and with the participation of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (each individually a "Registrant" and collectively the "Registrants") management, including their respective Principal Executive Officers (PEO) and Principal Financial Officers (PFO). The evaluations assessed the effectiveness of the Registrants' disclosure controls and procedures. Based on the evaluations, each PEO and PFO has concluded that, as to the Registrant or Registrants for which they serve as PEO or PFO, the Registrant's or Registrants' disclosure controls and procedures are effective to ensure that information required to be disclosed by each Registrant in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in Securities and Exchange Commission rules and forms; and that the Registrant's or Registrants' disclosure controls and procedures are also effective in reasonably assuring that such information is accumulated and communicated to the Registrant's or Registrants' management, including their respective PEOs and PFOs, as appropriate to allow timely decisions regarding required disclosure.

 Internal Control over Financial Reporting (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

 The managements of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (each individually a "Registrant" and collectively the "Registrants") are responsible for establishing and maintaining adequate internal control over financial reporting for the Registrants. Each Registrant's internal control system is designed to provide reasonable assurance regarding the preparation and fair presentation of each Registrant's financial statements presented in accordance with generally accepted accounting principles.

 All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

 Each Registrant's management assessed the effectiveness of each Registrant's internal control over financial reporting as of December 31, 2023. In making this assessment, each Registrant's management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. The 2013 COSO Framework was utilized for management's assessment.

 Based on each management's assessment and the criteria set forth by the 2013 COSO Framework, each Registrant's management believes that each Registrant maintained effective internal control over financial reporting as of December 31, 2023.

 The report of Deloitte & Touche LLP, Entergy Corporation's independent registered public accounting firm, regarding Entergy Corporation's internal control over financial reporting is included herein. The report of Deloitte & Touche LLP is not applicable to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy because these Registrants are non-accelerated filers.

 Changes in Internal Control over Financial Reporting

 Under the supervision and with the participation of each Registrant's management, including its respective PEO and PFO, each Registrant evaluated changes in internal control over financial reporting that occurred during the quarter ended December 31, 2023 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

 Attestation Report of Registered Public Accounting Firm

 Opinion on Internal Control over Financial Reporting

 We have audited the internal control over financial reporting of Entergy Corporation and Subsidiaries (the "Corporation") as of December 31, 2023, based on criteria established in Internal Control —Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.

 We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2023 of the Corporation and our report dated February 23, 2024 expressed an unqualified opinion on those consolidated financial statements.

 The Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Item 9A, Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

 Definition and Limitations of Internal Control over Financial Reporting

 A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 Item 9B. Other Information

 Rule 10b5-1 Trading Agreements

 During the three months ended December 31, 2023, no director or officer of Entergy or any of the Registrant Subsidiaries adopted, modified, or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement" as each term is defined in Item 408(a) of Regulation S-K.

 Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

 Not applicable.

 Item 10. Directors, Executive Officers, and Corporate Governance of the Registrants (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

 Information required by this item concerning directors of Entergy Corporation is set forth under the heading "Proposal 1 – Election of Directors" contained in the Proxy Statement of Entergy Corporation, to be filed in connection with its Annual Meeting of Stockholders to be held May 3, 2024 (the "2024 Entergy Proxy Statement"), and is incorporated herein by reference.

 All officers and directors listed below held the specified positions with their respective companies as of the date of filing this report, unless otherwise noted.

 Name
 Age

 President and Chief Executive Officer of Entergy Arkansas
 2018-Present

 Director of Entergy Arkansas
 2018-Present

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 Kimberly Cook-Nelson
 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Entergy Arkansas Directors Section above.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 ENTERGY LOUISIANA, LLC

 President and Chief Executive Officer of Entergy Louisiana
 2013-Present

 Director of Entergy Louisiana
 2013-Present

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 Kimberly Cook-Nelson
 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Entergy Louisiana Directors Section above.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 ENTERGY MISSISSIPPI, LLC

 President and Chief Executive Officer of Entergy Mississippi
 2008-Present

 Director of Entergy Mississippi
 2008-Present

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Entergy Mississippi Directors Section above.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 ENTERGY NEW ORLEANS, LLC

 President and Chief Executive Officer of Entergy New Orleans
 2021-Present

 Director of Entergy New Orleans
 2021-Present

 Vice President, Regulatory and Public Affairs of Entergy Texas
 2014-2021

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Entergy New Orleans Directors Section above.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 ENTERGY TEXAS, INC.

 President and Chief Executive Officer of Entergy Texas
 2021-Present

 Director of Entergy Texas
 2021-Present

 Vice President, Utility Distribution Operations of Entergy Services
 2020-2021

 Senior Director of Labor Relations and Corporate Safety, Florida Power and Light Corporation
 2018-2020

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 See information under the Entergy Texas Directors Section above.

 See information under the Information about Executive Officers of Entergy Corporation in Part I.

 The directors and officers of Entergy Texas are elected annually to serve by the unanimous consent of its sole common stockholder. The directors and officers of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans are elected annually to serve by the unanimous consent of the sole common membership owner, Entergy Utility Holding Company, LLC. Entergy Corporation's directors are elected annually at the annual meeting of shareholders. Entergy Corporation's officers are elected annually at a meeting of its Board of Directors, which immediately follows the annual meeting of shareholders. The age of each officer and director for whom information is presented above is as of December 31, 2023.

 Directors, Director Nomination Process and Audit Committee

 The information required under Item 10 concerning directors and nominees for election as directors of Entergy Corporation at the annual meeting of shareholders (Item 401 of Regulation S-K), the director nomination process (Item 407(c)(3) of Regulation S-K), the audit committee (Item 407(d)(4) and (d)(5) of Regulation S-K), and the compliance with the reporting requirements of Section 16 ("Section 16") of the Securities Exchange Act of 1934, as amended (the "Exchange Act") (Item 405 of Regulation S-K) is incorporated herein by reference to information to be contained in the 2024 Entergy Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.

 Code of Ethics

 Entergy Corporation's Code of Business Conduct and Ethics (Code of Business Conduct) is the code of ethics that applies to Entergy's Chief Executive Officer and other senior financial officers, including those of the Registrant Subsidiaries. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on

 Entergy Corporation's website at www.entergy.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Entergy Corporation's Corporate Secretary at Entergy Corporation, 639 Loyola Avenue, New Orleans, Louisiana 70113.

 If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct, for any director or executive officer of Entergy Corporation, Entergy will disclose the nature of such amendment or waiver on Entergy's website, www.entergy.com. Entergy is providing the address to its internet site solely for the information of investors and does not intend the address to be an active link. Notwithstanding this reference or any references to the website in this report, the contents of the website are not incorporated into this report.

 Item 11. Executive Compensation

 ENTERGY CORPORATION

 Information concerning compensation earned by the directors and officers of Entergy Corporation is set forth in the 2024 Entergy Proxy Statement, to be filed in connection with the Annual Meeting of Shareholders to be held May 3, 2024, under the headings "Compensation Discussion and Analysis," "Annual Compensation Programs Risk Assessment," "Compensation Tables," "Pay Ratio Disclosure," and "2023 Non-Employee Director Compensation," all of which information is incorporated herein by reference. In this section, Entergy Corporation is also referred to as "Entergy" or the "Company."

 ENTERGY ARKANSAS, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND ENTERGY TEXAS

 COMPENSATION DISCUSSION AND ANALYSIS

 This Compensation Discussion and Analysis ("CD&A") describes the executive compensation policies, programs, philosophy, and decisions regarding the Named Executive Officers ("NEOs") for 2023. It also explains how and why the Talent and Compensation Committee of Entergy Corporation's Board of Directors arrived at the compensation decisions involving the NEOs in 2023 who were:

 Name(1)

 Title

 Executive Vice President and General Counsel

 President and Chief Executive Officer, Entergy Mississippi

 Executive Vice President and Chief Financial Officer, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas

 President and Chief Executive Officer, Entergy Arkansas

 Chair of the Board and Chief Executive Officer

 President and Chief Executive Officer, Entergy Louisiana

 President and Chief Executive Officer, Entergy New Orleans

 President and Chief Executive Officer, Entergy Texas

 Group President, Utility Operations, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas

 (1)Messrs. Brown, Marsh, and West and Ms. Fontan hold the positions referenced above as executive officers of Entergy Corporation and are members of Entergy Corporation's Office of the Chief Executive ("OCE"). No additional compensation was paid in 2023 to any of these officers for their service as NEOs of the Utility operating companies.

 All of Entergy Arkansas's, Entergy Louisiana's, Entergy Mississippi's, Entergy New Orleans's, and Entergy Texas's directors are employees of Entergy or its subsidiaries and do not receive any additional compensation for their services as director.

 Entergy Corporation's Compensation Principles and Philosophy

 Entergy Corporation's executive compensation programs are based on a philosophy of pay for performance aimed at achieving the Company's strategy and business objectives. Entergy Corporation believes its executive compensation programs advance the interests of all of its stakeholders, as they are thoughtfully designed to:

 • Motivate and reward the achievement of results that are deemed by the Talent and Compensation Committee to be consistent with the overall goals and strategic direction that the Board has approved for the Company.
 • Attract and retain a highly experienced, diverse, and successful management team.
 • Create sustainable value for the benefit of all of Entergy Corporation's stakeholders, including its customers, employees, communities, and owners.
 • Align the interests of Entergy Corporation's executives with the Company's long-term business strategy by tying equity-based awards to performance metrics designed to focus Entergy Corporation's executives on driving continuous improvement in operational and financial results to the benefit of all stakeholders, including Entergy Corporation's customers, employees, communities, and owners.

 Compensation Best Practices

 The Talent and Compensation Committee reviews Entergy's executive compensation programs on an ongoing basis to evaluate whether they support the Company's executive compensation principles and philosophy and are aligned with the interests of our stakeholders. The Company's executive compensation practices include the following, each of which the Talent and Compensation Committee believes reinforces our executive compensation principles and philosophy:

 Practice

 Pay for Performance
 The executive compensation programs yield pay outcomes that the Company believes are highly correlated with performance and drive long-term value creation.

 Annual and Long-Term Incentive Measures Drive Desired Employee Behaviors

 Performance measures for the annual and long-term incentive programs are designed to incentivize employee behaviors that serve the Company's key stakeholders:

 • Customers – Net Promoter Score (NPS).

 • Employees – Diversity, Inclusion, & Belonging (DIB) and Safety.

 • Communities – Environmental Stewardship, DIB.

 • Owners – Adjusted Earnings Per Share, Credit measure, TSR.

 Double Trigger Change-in-Control
 The Company requires both a change-in-control and an involuntary termination without cause or voluntary termination with good reason for cash severance payments and immediate vesting of unvested equity awards.

 Long-Term Incentives Paid in Stock
 All long-term incentives are settled in shares of Entergy common stock.

 Stock Ownership Guidelines
 The Company requires executive officers to own a significant amount of Entergy stock.

 Cap on Incentive Awards for OCE Members

 The maximum payout for members of the OCE is capped at 200% of the target opportunity for the annual incentive and long-term Performance Unit Program (PUP) awards.

 Rigorous Goals
 The Company sets financial goals based on externally disclosed annual and multi-year guidance and outlooks and non-financial goals based on a rigorous internal review.

 Practice

 Clawback Policy
 We have a recoupment policy that complies with and, in certain respects, goes beyond, the requirements of the new SEC rules and NYSE Listing Standards for Entergy's officers as defined under Section 16 for the recovery of any erroneously awarded performance-based incentive compensation. In 2024, we also adopted a discretionary recoupment policy applicable to all of our officers, including the NEOs, that allows for recovery of incentive compensation, including time-based awards, from an officer who engages in certain detrimental conduct. See section of this CD&A discussing "Recoupment of Compensation (Clawback Provisions)" for additional information about these policies.

 No Hedging of Company Stock
 Directors, executive officers, and employees of Entergy and its subsidiaries may not directly or indirectly engage in transactions intended to hedge or offset the market value of the Company's common stock owned by them.

 No Pledging of Company Stock
 Directors and executive officers of Entergy and its subsidiaries may not directly or indirectly pledge Entergy common stock as collateral for any obligation.

 No Excessive Perquisites
 Executive officers receive limited ongoing perquisites that make up a small portion of total compensation.

 No Tax Reimbursements

 The Company does not provide tax reimbursements to OCE members, other than certain relocation benefits.

 No Dividends on Unearned Performance Awards

 The Company does not pay dividends on unearned performance awards.

 No Repricing or Exchange of Underwater Stock Options
 The Company's equity incentive plan does not permit repricing or the exchange of underwater stock options without the approval of its shareholders.

 No Employment Agreements
 The Company does not have employment contracts with its executive officers.

 Independent Compensation Consultant

 The Talent and Compensation Committee retains an independent compensation consultant to advise on the executive compensation programs and practices.

 Annual Say-on-Pay
 The Company values the input of its shareholders on the executive compensation programs and holds annual say-on-pay votes.

 Annual Compensation Risk Assessment
 A risk assessment of the compensation programs is performed on an annual basis to ensure that the programs and policies do not incentivize unnecessary or excessive risk-taking behavior.

 2023 Incentive Program Awards

 Performance measures and targets for the 2023 annual incentive program awards were determined by the Talent and Compensation Committee in December 2022 and January 2023, respectively. Performance measures and targets for the 2021 – 2023 performance period for the long-term PUP awards were established in December 2020 and January 2021, respectively. In January 2024 the Talent and Compensation Committee certified the results for the Entergy Achievement Multiplier ("EAM"), the payout factor that determines the funding available for the 2023 annual incentive program awards, and certified the results for the long-term PUP awards for the 2021 – 2023 performance period.

 Annual Incentive Program Awards

 In December 2022 the Talent and Compensation Committee determined that the EAM would be based on financial and non-financial measures with the financial measure weighted 60% and the four non-financial measures, which address key aspects of our performance on strategies designed to ensure the long-term health and success of the Company, collectively accounting for the remaining 40%.

 Of the four non-financial measures, two are solely quantitative measures and two are based on qualitative assessments that are informed by quantitative measures. As a result, under the program design, the performance assessments for 80% of the overall annual incentive program funding are purely formulaic.

 Financial Measure: Keeping with the Talent and Compensation Committee's goal of aligning performance measures with financial results that link to externally communicated investor guidance, Entergy Tax Adjusted Earnings Per Share ("ETR Tax Adjusted EPS") - a non-GAAP financial measure that is based on the Adjusted EPS that Entergy reports to investors - was used as the financial measure to determine the EAM.

 Non-Financial Measures: To demonstrate Entergy's strong commitment to creating long-term sustainable value for its key stakeholders - customers, communities, employees, and owners - and to link executive compensation more directly to the achievement of those objectives, the Talent and Compensation Committee decided that 40% of the EAM would be determined on the basis of results achieved in the following areas, each of which would be weighted equally: Safety; Customer Net Promoter Score, or NPS; DIB; and Environmental Stewardship.

 The 2023 annual incentive targets and results determined by the Talent and Compensation Committee were:

 Annual Incentive Performance Goals(1)

 2023 Percentage of EAM
 2023 Results

 ETR Tax Adjusted EPS ($)(2)

 60%
 6.70
 8.83
 200%

 Safety (SIF Rate)(3)

 10%
 0.04
 0.03
 150%

 Customer NPS(4)

 10%
 Residential: 5
Business: 28
 Residential: -4.5
Business: 17
 —%

 DIB

 10%
 Qualitative(5)

 110%

 Environmental Stewardship
 10%
 Qualitative(5)

 105%

 EAM as a percentage of target, per annual incentive program

 100%
 157%

 EAM as a percentage of target following discretionary adjustment(6)

 138%

 (1)See "What Entergy Corporation Pays and Why – 2023 Compensation Decisions – 2023 Annual Incentive Program Performance Assessment" for the minimum and maximum achievement levels.
 (2)ETR Tax Adjusted EPS is a non-GAAP financial measure. See "What Energy Corporation Pays and Why - 2023 Compensation Decisions - Annual Incentive Program Financial Measure and Target" for information regarding this non-GAAP financial measure.
 (3)SIF Rate refers to the rate of serious injuries and fatalities per 100 employees or contractors. The employee and contractor targets and results are averaged to arrive at reported results. The 2023 target was top quartile performance among electric utilities for 2023, as reported by the Edison Electric Institute.
 (4)The Customer NPS measure for 2023 was calculated based on equally weighted categories of residential and business customer NPS scores.
 (5)See "What Entergy Corporation Pays and Why – 2023 Compensation Decisions – Annual Incentive Program Non-Financial Measures and Targets" for a discussion of the performance assessment of the DIB and Environmental Stewardship performance measures.
 (6)In recognition of the substantial impact on the calculated EAM of the adjustment for 50% of the net benefit of tax strategy items for 2023 and the fact that those items did not produce any current year cash benefit, the Talent and Compensation Committee exercised its discretion to reduce the EAM from 157% to 138%. The Talent and Compensation Committee concluded that this result represented an appropriate recognition of management's strong performance over the course of 2023, including its important role in securing the significant tax benefits reflected in the tax strategy adjustment.

 After consideration of individual performance, the Talent and Compensation Committee awarded the NEOs who are members of the OCE payouts averaging 138% of target, with a payout of 138% of target to Mr. Marsh.

 Long-Term Performance Unit Program Awards

 In January 2021 the Talent and Compensation Committee chose relative TSR and Adjusted FFO/Debt Ratio, a non-GAAP financial measure, as the performance measures for the 2021 – 2023 performance period, with relative TSR weighted 80% and Adjusted FFO/Debt Ratio weighted 20%.

 The targets and results for the 2021 – 2023 performance period as determined by the Talent and Compensation Committee were:

 Long-Term PUP Measures
 Weighting
 2021-2023 PUP Target
 2021-2023 PUP Results

 Relative TSR(1)

 80%
 Median
 2rd Quartile

 115%

 Adjusted FFO/Debt Ratio(2)

 20%
 16%
 2021: 10.74%
2022: 14.30%
2023: 16.95%
 66%

 Payout (as a percentage of target)
 100%
 105%

 (1)The Company ranked 10th of the 20 companies comprising the Philadelphia Utility Index, the industry peer group used by the Talent and Compensation Committee for determining relative TSR performance levels, for the performance period
 (2)The Adjusted FFO/Debt Ratio, a non-GAAP financial measure, is the ratio of: (i) adjusted funds from operations calculated as consolidated operating cash flow adjusted for allowance for funds used during construction, working capital and the effects of securitization revenue, and the Pre-Determined Exclusions (as defined later in this CD&A) to (ii) total consolidated debt, excluding outstanding or pending securitization debt. The Adjusted FFO/Debt Ratio is evaluated on an annual basis against the target set for each year, which for the 2021-2023 performance period was 15.5%. The annual results are then averaged to determine the Adjusted FFO/Debt Ratio payout percentage. The Adjusted FFO/Debt Ratio FFO/ Debt was below the minimum performance achievement level of 14.5% for 2021 and 2022 and near the maximum achievement level of 17.0% for 2023, resulting in an overall payout of 66% for that measure.

 What Entergy Corporation Pays and Why

 How Entergy Corporation Makes Compensation Decisions

 Role of the Talent and Compensation Committee

 The Talent and Compensation Committee, which is composed solely of independent directors, determines the compensation for each member of the OCE and oversees the design and administration of Entergy's executive compensation programs. Each year, the Talent and Compensation Committee reviews and considers a comprehensive assessment and analysis of the executive compensation programs, including the elements of each OCE member's compensation, with input from the committee's independent compensation consultant. When establishing the compensation programs for the NEOs, the Talent and Compensation Committee also considers input and recommendations from management, including Entergy's Chief Executive Officer and Entergy's Chief Human Resources Officer, who attend the Talent and Compensation Committee meetings as appropriate.

 Role of the Independent Compensation Consultant

 In 2023, the Talent and Compensation Committee continued to retain Pay Governance, LLC ("Pay Governance") as its independent compensation consultant. Pay Governance attends all Talent and Compensation Committee meetings and provides advice, including reviewing and commenting on market compensation data used

 to establish the compensation of the executive officers and Entergy Corporation's directors, the terms and performance goals applicable to incentive plan awards, the process for certifying achievement of the incentive goals, and analysis with respect to specific projects and information regarding trends and competitive practices. Pay Governance also meets with the Talent and Compensation Committee members without management present. The committee annually conducts an independence assessment of its advisors including the compensation consultant, consistent with NYSE listing standards and SEC rules governing proxy disclosure.

 Competitive Positioning

 1. Market Data for Compensation Comparison

 Annually, the Talent and Compensation Committee reviews:

 • published and private compensation survey data analyzed and provided by Pay Governance;
 • both utility and general industry data to help determine total direct compensation (base salary, annual, and long-term incentive) for non-industry specific roles; and
 • data from utility companies to help determine total direct compensation for management roles that are utility-specific, such as Group President, Utility Operations.

 2.How the Talent and Compensation Committee Uses Market Data

 The Talent and Compensation Committee uses this survey data to develop compensation opportunities that are designed to deliver total direct compensation within a targeted range of approximately the 50th percentile of the surveyed companies in the aggregate. In general, compensation levels for an executive officer who is new to a position tend to be closer to the 25th percentile of surveyed companies, while seasoned executive officers whose experience and skill set are viewed as critical to retain may be positioned at or somewhat above the market median.

 3.Proxy Peer Group

 Although the survey data described above is the primary data used in benchmarking compensation, the Talent and Compensation Committee used compensation information from the companies included in the Philadelphia Utility Index to evaluate the overall reasonableness of the Company's executive compensation programs and to determine relative TSR performance levels for the 2023 – 2025 PUP performance period. The Talent and Compensation Committee identified the Philadelphia Utility Index as the appropriate industry peer group for determining relative TSR performance levels because the companies included in this index, in the aggregate, are viewed as comparable to the Company in terms of business and scale.

 The Talent and Compensation Committee approved the 2023 compensation model and framework based on compensation information from the companies included in the Philadelphia Utility Index as of December 31, 2022, which were:

 AES Corporation
 Consolidated Edison Inc.
 Edison International
 Pinnacle West Capital Corporation

 Ameren Corporation
 Constellation Energy Corporation
 Eversource Energy
 Public Service Enterprise Group, Inc.

 American Electric Power Co. Inc.
 Dominion Energy
 Exelon Corporation
 Southern Company

 American Water Works Company, Inc.
 DTE Energy Company
 FirstEnergy Corporation
 WEC Energy, Inc.

 CenterPoint Energy Inc.
 Duke Energy Corporation
 NextEra Energy, Inc.
 Xcel Energy, Inc.

 2023 Compensation Structure and Incentive Metrics

 In 2023, the executive compensation programs consisted of base salary and annual and long-term incentives as outlined in the table below:

 Compensation Element
 Form
 Objective
 Metrics/Performance Period

 Base Salary
 Cash
 Provides a base level of competitive cash compensation for executive talent.
 N/A

 Annual Incentive Program Awards
 Cash
 Motivates and rewards executives for performance on both key financial and non-financial measures during the year; incentivizes behaviors that serve the Company's four stakeholders - customers, employees, communities, and owners.

 • ETR Tax Adjusted EPS

 • Safety

 • Customer NPS

 • DIB

 • Environmental Stewardship

 Measured over a one-year performance period

 PUP Awards
 Provides market competitive compensation designed to retain skills and knowledge while increasing our executives' ownership in the Company further enhancing their focus on driving continuous improvement in operational results to the benefit of all stakeholders. Designed to focus our executives on driving utility growth, building long-term shareholder value, and a strong balance sheet.
 • Relative TSR

 • Adjusted FFO/Debt Ratio

Measured over a 3-year performance period

 Enhances management's focus on driving continuous improvement in operational results to the benefit of all stakeholders. Designed to align interests of management with long-term shareholder value as demonstrated by increases in our share price, provide market competitive compensation, retain talent, and increase management's ownership in the Company.
 Share price appreciation with 3-year pro rata vesting

 Enhances management's focus on driving continuous improvement in operational results to the benefit of all stakeholders. Designed to provide market competitive compensation, retain talent, and increase management's ownership in the Company.
 Service-based with 3-year pro rata vesting

 2023 Compensation Decisions

 Base Salary

 The salary for each NEO is based on the outcome of an annual merit review, the need to retain an experienced team, job promotion, individual performance, scope of responsibility, leadership skills and values, current compensation, and internal equity. For the NEOs who are members of the OCE, the Talent and Compensation Committee also considers the results of the annual market assessment of OCE compensation as provided by its independent compensation consultant. The Talent and Compensation Committee considers changes in the base salaries of the NEOs at least annually, and in 2023, all of the NEOs, other than Ms. Fontan and Mr. Marsh, received increases in their base salaries ranging from approximately 4% to 5.63% effective April 1, 2023. Ms. Fontan and Mr. Marsh did not receive compensation increases in April 2023 as each had received compensation increases in November 2022 in connection with their promotions to their current positions. These adjustments were made after considering the competitive market data described above as well as their previous compensation levels and the compensation paid to their predecessors.

 The following table sets forth the 2022 and 2023 year-end base salaries for the NEOs. Changes in base salaries for 2023 were effective in April.

 2022 Base Salary
 2023 Base Salary

 $732,021
 $761,302

 $414,840
 $438,206

 $625,000
 $625,000

 $394,204
 $411,351

 $1,100,000
 $1,100,000

 $435,643
 $454,593

 $347,172
 $362,274

 $350,154
 $365,385

 $776,434
 $807,491

 Annual Incentive Compensation

 The NEOs are eligible for annual incentive awards under our 2019 Omnibus Incentive Plan ("2019 OIP"). The maximum funding available for the annual incentive program is determined by the EAM performance measure. At the beginning of each year, after a review of the Company's strategic plan, the Talent and Compensation Committee engages in a rigorous process to determine the financial and non-financial measures and the targets for each measure that will be used to determine the EAM. The Talent and Compensation Committee also annually establishes target opportunities for each NEO who is a member of the OCE. For the other NEOs, target award opportunities are determined based on their management level (ML) within the Entergy organization. Executive management levels at Entergy Corporation range from ML level 1 through ML level 4. Accordingly, their respective incentive award opportunities differ from one another based on either their management level or the external market data developed by Pay Governance. The 2023 target opportunities for each of the NEOs remained at the same level as those established for 2022 or, in the case of Mr. Marsh and Ms. Fontan, remained at the same level as those established in 2022 in conjunction with their promotions.

 Each January, after the end of the fiscal year, the Finance and Talent and Compensation Committees jointly review the Company's results, and the Talent and Compensation Committee determines the EAM based on the level of achievement of the performance measures established. The Talent and Compensation Committee retains discretion to modify the EAM based on its assessment of the degree of management's success in achieving the Company's strategic objectives during the year taking into account the business and operating environment.

 Individual executive officer awards are determined based on the Talent and Compensation Committee's or management's consideration of each executive officer's role in executing the Company's strategies and delivering the financial and operational performance achieved, but also the individual's accountability for any challenges and achievements the Company experienced during the year.

 2023 Annual Incentive Program Performance Measures and Methodology

 For 2023, and consistent with the 2022 program design, the Talent and Compensation Committee decided that the EAM would be based on both financial and non-financial measures, with the financial measure weighted 60% and four non-financial measures each weighted 10%. Targets and ranges of performance were established for each of the measures, with no payout for results less than the designated minimum, a 25% payout opportunity for results at the minimum, a 100% payout opportunity for results at target, and a 200% payout opportunity for results equal to or exceeding the maximum. Payout opportunities for results between the minimum and maximum performance achievement levels were determined by straight line interpolation, with the EAM result being determined by the weighted-average of the payout opportunities for each of the performance measures.

 Annual Incentive Program Financial Measure and Target

 For the EAM financial measure, the Talent and Compensation Committee decided to use ETR Tax Adjusted EPS, a non-GAAP financial measure. This measure is based on ETR Adjusted EPS, a non-GAAP financial measure which is the earnings measure by which the Company provides external guidance, and excludes the effects of certain adjustments, which are unusual or non-recurring items or events or other items or events that management believes do not reflect the ongoing business of Entergy, such as significant tax items, and other items such as certain costs, expenses, or other specified items. ETR Adjusted EPS is then adjusted to add back the net effect (positive or negative) of significant tax strategy items and to eliminate the effect of: (i) major storms, including the impact on total debt of pending securitizations, (ii) resolutions during the year of certain unresolved regulatory litigation matters, (iii) unrealized gains or losses on equity securities, (iv) effects of federal income tax law changes, and (v) any adjustments to contributions to pension investments or trusts related to post-retirement benefits that are elective and deviate from original plan assumptions (collectively, the "Pre-Determined Exclusions"). The Talent and Compensation Committee determined that target performance for this metric would equal management's expectation for ETR Adjusted EPS as reflected in its financial plan, or $6.70 per share, with minimum performance determined to be $6.35 per share and maximum performance being $7.05 per share.

 ETR Tax Adjusted EPS was used as the financial measure for the EAM because:

 • It is based on an objective financial measure that the Company and its investors consider to be important in evaluating financial performance.
 • It is based on the same measure used for internal and external financial reporting.
 • It provides both discipline and transparency.

 The Talent and Compensation Committee considered it appropriate to use ETR Tax Adjusted EPS, which adds back 50% of the net effect of significant tax strategy items that may have been excluded from ETR Adjusted EPS, as the earnings measure because of the significant financial impact to the Company resulting from such tax strategy items.

 The Talent and Compensation Committee also considered, both at the time it chose ETR Tax Adjusted EPS as the EAM financial measure and when it established the targets for this measure, the appropriateness of excluding the effect of each of the specific Pre-Determined Exclusions it had identified from the financial measure. It viewed the exclusion of major storms as appropriate because although the Company includes estimates for storm costs in its financial plan, it does not include estimates for a major storm event, such as a hurricane, given management's inability to control or predict acts of nature. The Talent and Compensation Committee considered the exclusion of the effects of any unanticipated changes in federal income tax law to be appropriate because of the inability of management to impact those results. It approved the exclusion of elective adjustments to Company contributions to

 pension and post-retirement benefit plan trusts because such elective adjustments are not viewed as reflective of the underlying performance of the business. The Talent and Compensation Committee approved the other Pre-Determined Exclusions from reported results — for the impact of certain legacy unresolved regulatory litigation and unanticipated unrealized gains and losses on securities — primarily because of management's inability to influence either of the related outcomes.

 Annual Incentive Program Non-Financial Measures and Targets

 To demonstrate Entergy's strong commitment to creating long-term sustainable value for its key stakeholders - customers, communities, employees, and owners - and to link executive compensation to successful execution on those strategies to achieve those objectives, the Talent and Compensation Committee decided to use the measures described below to collectively determine 40% of the EAM, with each of the measures weighted at 10%. These measures were selected because the Talent and Compensation Committee considered them to represent key measures of the Company's success in advancing strategies to create sustainable value for its stakeholders that may not be fully captured in its quarterly and annual financial results. The non-financial performance measures remained fundamentally consistent with the measures used in the 2022 annual incentive program.

 Following is a summary description of each of these measures, including the metric or methodology used for determining the level of achievement and the rationale for each of the selected measures:

 Measure
 Metrics and Targets
 Objective

 Safety
 Quantitative safety metric based on rate of serious injuries and fatalities per 100 employees or contractors (SIF rate). Minimum performance = second quartile, target = top quartile, and maximum performance = top decile of published Edison Electric Institute (EEI) member SIF rate data as published in 2023, with no payout in the event of any fatalities during the reporting year.
 Supports Entergy's goal of maintaining a safe and incident-free workplace for all of its employees and contractors.

 Customer Net Promoter Score (NPS)
 Quantitative customer NPS metric is determined through a blind survey of residential and business customers who are asked how likely they are to recommend Entergy, on a scale of 1 to 10. The NPS is the percentage of promoters (scores 9-10) less the percentage of detractors (scores less than 6).

 Residential: minimum performance =.5; target = 5; and maximum performance = 10.

 Business: minimum performance = 21; target = 28; and maximum performance = 35.

 • Incentivizes actions that drive positive customer outcomes (as measured through customer feedback), including impacts on reliability improvements, responsiveness, continuous improvement, and innovation.

 • Signals overall health and loyalty of our customer relationship.

 Measure
 Metrics and Targets
 Objective

 Diversity, Inclusion, & Belonging (DIB)
 Overall qualitative assessment of DIB key performance indicators assessed in the areas of diversity, culture, and commerce, informed by quantitative measures in the areas of female, racially, and ethnically diverse representation in the employee population and in director and above placements, inclusive climate survey scores, and diverse supplier managed spend; progress on DIB initiatives; and responsiveness to emergent issues.

 • Reinforces Entergy's commitment to be a fair and equitable work environment that is welcoming to all and allows us to attract and retain superb talent, allowing the Company to execute on its strategy.

 • Rewards progress toward meeting Entergy's commitment to develop and retain a workforce that reflects the rich diversity of the communities Entergy serves, while maintaining its commitment to hiring the most qualified candidates.

 • Drives an engaged workforce; customer-centric service and solutions; enhancement of owner value; and community partnerships.

 Environmental Stewardship
 Assessment of progress toward environmental commitments through performance on publicly announced goals and other key initiatives. Goals set for 2023 included carbon dioxide emission rate and carbon-free energy capacity targets, advancement of our resilience strategy as demonstrated by regulatory filings made, approved, and implemented, and customer engagement, electrification, and emission reductions.

 • Reinforces Entergy's commitment to long-term sustainability and a reduced impact on the environment, in particular by advancing Entergy's climate goals and commitments.

 • Provides accountability for accelerating completion of Entergy's resilience investments and advancing Entergy's customer electrification initiatives.

 In determining the targets to set for 2023, the Talent and Compensation Committee reviewed anticipated drivers and risks to the Company's expectations for ETR Adjusted EPS for 2023 as set forth in the Company's financial plan, as well as factors driving the strong financial performance achieved in 2022. The Talent and Compensation Committee noted that the proposed plan targets for ETR Tax Adjusted EPS reflected year-to-year growth in the core earnings measure underlying the annual incentive target consistent with Entergy's stated objective of a steady, predictable ETR Adjusted EPS compound annual growth rate of 6%-8%. The Talent and Compensation Committee also considered the potential impact of a wide range of identified risks and opportunities and confirmed that both the financial and non-financial annual incentive targets reflected a reasonable balancing of such risks and opportunities and an appropriate degree of challenge. The goals were designed to be achievable, but also to require the strong coordinated performance of the management team.

 2023 Annual Incentive Program Performance Assessment

 In January 2024, the Finance and Talent and Compensation Committees jointly reviewed the Company's financial and operational results and assessed management's performance against the performance objectives and targets described above in order to determine the EAM. Based on the plan design and targets set at the beginning of the year and prior to any discretionary adjustments, the committees determined that the EAM was 157%. The following table summarizes the annual incentive targets and performance results for 2023:

 Performance Measure
 Targets and Results

 Weighting
 Minimum
 2023 Results

 ETR Tax Adjusted EPS ($)(1)

 60%
 6.35
 6.70
 7.05
 8.83
 200%

 Safety (SIF Rate)
 10%
 0.09
 0.04
 0.02
 0.03(2)

 150%

 Customer NPS
 10%
 Residential: 0.5
Business: 21
 Residential: 5
Business: 28
 Residential: -4.5
Business: 17
 0%

 DIB
 10%
 Qualitative assessment(3)

 110%

 Environmental Stewardship
 10%
 Qualitative assessment(3)

 105%

 Calculated EAM(4)

 100%
 25%
 100%
 200%
 157%

 (1)ETR Tax Adjusted EPS is a non-GAAP financial measure. See "What Energy Corporation Pays and Why - 2023 Compensation Decisions - Annual Incentive Program Financial Measure and Target" for information regarding this non-GAAP financial measure.
 (2)2023 SIF results were 0.03 for employees and 0.03 for contractors. The employee and contractor targets and results were averaged to arrive at target and reported results. The 2023 target was top quartile employee SIF performance among electric utilities for 2023, as reported by the EEI, the maximum was top decile performance, and the minimum was 2nd quartile performance.
 (3)This qualitative assessment is informed by quantitative measures and is discussed below.
 (4)Reflects the EAM as a percentage of target and as calculated in accordance with the annual incentive plan prior to the Talent and Compensation's discretionary adjustment noted earlier in this CD&A and discussed further below.

 In assessing 2023 performance, the Finance and Talent and Compensation Committees reviewed management's performance under each of the performance measures referenced above. In assessing financial performance, the committees evaluated various factors explaining how the 2023 ETR Tax Adjusted EPS result compared to the 2023 business plan and annual incentive target set in January 2023. ETR Tax Adjusted EPS exceeded the ETR Tax Adjusted EPS target of $6.70 per share by $2.13. This outperformance resulted in part from the fact that ETR Adjusted EPS exceeded the midpoint of the guidance set at the beginning of the year by $0.07 per share. The ETR Tax Adjusted EPS result also reflected a positive adjustment of $2.13 to ETR Adjusted EPS for 50% of the net benefit of tax strategy items impacting net income which had been excluded from ETR Adjusted EPS, as well as a negative adjustment of $0.07 to reflect the additional expense accrual that would be associated with funding anticipated payouts to employees at a level commensurate with the calculated EAM.

 In recognition of the substantial impact on the calculated EAM of the adjustment for 50% of the net benefit of tax strategy items for 2023 and the fact that those items did not produce any current year cash benefit, the Talent and Compensation Committee exercised its discretion to reduce the EAM from 157% to 138%. The Talent and Compensation Committee concluded that this result represented an appropriate recognition of management's strong performance over the course of 2023, including its important role in securing the significant tax benefits reflected in the tax strategy adjustment.

 In assessing management's 2023 performance on the non-financial measures, the Finance and Talent and Compensation Committees noted that the DIB and Environmental Stewardship measures were qualitative measures that were informed in each case by certain quantitative measures. In each area, the committees reviewed certain key performance indicators and assessed progress on strategies and initiatives that had been identified at the beginning of the performance period as important to achieving the Company's strategic objectives.

 The following chart provides selected performance milestones and highlights considered as part of the assessments of the DIB and Environmental Stewardship measures:

 Performance Measure
 2023 Developments

 Diversity, Inclusion, & Belonging
 • Increased representation of women and underrepresented racial and ethnic groups in the employee population and at the director level and above in management from 2022

 • Held the "All In" five-month cohort development experience to increase inclusive leadership behaviors at all levels for the second year in a row, with over 200 employees in attendance

 •

 110%
 • Inclusive climate score increased from third quartile in 2022 to second quartile, with increases in all outcomes and continuing to score first quartile in our areas of focus (such as mentorship and idea integration)

 • Launched an enterprise-wide HBCU strategy with a differentiated Power of Prosperity Generational Wealth pilot, providing 1,500 freshmen students from Dillard University, Southern University, and Xavier University with $100 seeded investment accounts along with financial aid counseling / case management for students and families

 • Entergy's Employee Resource Groups (ERGs) placed fifth in the Enterprise-Wide ERG category of the Diversity Impact Awards during the 2023 Global ERG Summit; LeadERG placed second in the Top 25 ERG Award category

 • Received Top Workplace Awards from Times-Picayune and Houston Chronicle for New Orleans and Texas, respectively

 • Received for the sixth consecutive year the U.S. Department of Labor Platinum Vets Medallion Award for veteran talent pipeline development, recruitment, retention, and a Veteran's ERG

 • Named on Forbes' Best Employers for Diversity List for 2023; Newsweek's America's Greatest Workplaces for 2023; Time's World's Best Companies for 2023; and Black Enterprise's Best Companies for DEI

 • Decreased diverse supplier managed spend from 2022 levels

 Environmental Stewardship
 • CO2 emission rate estimate of 670 lbs/MWh, which was slightly better than the emission rate representing minimum performance, with the increased rate partially attributable to higher summer load served by fossil fuel and coal generation due to extreme heat and adjustments in the energy mix based on generation resource availability

 •23% carbon-free energy capacity, which is maximum performance

 •

 105%
 • Initiated efforts and made fundamental progress on most of the targeted, resilience-related objectives of the New Orleans and Louisiana operating companies, including:

 Entergy New Orleans filed its definitive accelerated resilience plan with the City Council for approval
 Entergy Louisiana filed its accelerated resilience plan with the LPSC for approval

 • Developed implementation plan for Entergy's 2023 commercial and industrial growth objectives

 • Executed on continued outreach to customers and commercial plan development for customer growth objectives

 • Demonstrated significant progress toward serving expected customer growth, such as through execution of various agreements with key customers and partners

 In addition to the foregoing financial and operational results, the Talent and Compensation Committee considered management's degree of success in achieving various strategic operational and regulatory objectives and in overcoming certain challenges that arose in the business during the course of the year.

 Under the annual incentive program, NEOs could earn a payout ranging from 0% to 200% of the NEO's target opportunity, subject to the overall funding limitation determined by the EAM. To determine individual NEO annual incentive program awards for members of the OCE, the Talent and Compensation Committee considered individual performance in executing on the Company's strategies and delivering the strong financial performance and operational successes achieved in 2023, as well as the executive's success in achieving individual goals within the executive's scope of responsibilities. The committee also considered certain challenges the Company experienced during the year and each officer's accountabilities and accomplishments in addressing those external challenges.

 With these considerations in mind, the Talent and Compensation Committee approved the following annual incentive payouts to each of the NEOs who are members of the OCE ranging from 120% to 156% of target.

 After the EAM was established to determine overall funding for the annual incentive awards, Entergy's Chief Executive Officer allocated incentive award funding to individual business units based on business unit results. Individual awards were determined for the remaining NEOs who are not members of the OCE by their immediate supervisor based on the individual officer's key accountabilities, accomplishments, and performance. This resulted in payouts that ranged from 125% of target to 135% of target for the NEOs who are not members of the OCE.

 Based on the foregoing evaluation of management performance, the NEOs received the following annual incentive payouts:

 Year-End Base Salary
 Target as Percentage of Year-End Base Salary
 2023 Target Award
 Payout as Percentage of Target
 2023 Annual
Incentive Award

 $761,302
 80%
 $609,041
 156%
 $950,104

 $438,206
 55%
 $241,013
 135%
 $325,368

 $625,000
 75%
 $468,750
 138%
 $646,875

 $411,351
 55%
 $226,243
 135%
 $305,428

 $1,100,000
 120%
 $1,320,000
 138%
 $1,821,600

 $454,593
 60%
 $272,756
 125%
 $340,945

 $362,274
 50%
 $181,137
 125%
 $226,421

 $365,385
 55%
 $200,962
 125%
 $251,202

 $807,491
 80%
 $645,993
 120%
 $775,192

 Long-Term Incentive Compensation

 Overview

 Long-term incentive compensation delivered in shares of Entergy common stock represents the largest portion of executive officer compensation. The Company believes the combination of long-term incentives it employs provides a compelling performance-based compensation opportunity, is effective at retaining a strong senior management team, and aligns the interests of the executive officers with the interests of Entergy's customers and shareholders by enhancing executive officers' focus on the Company's long-term goals.

 For each NEO, a dollar value is established to determine that NEO's long-term incentive awards. The target award value for each NEO is determined based on market median compensation data for the officer's role,

 adjusted to reflect individual performance and internal equity. In the case of Mr. Marsh and Ms. Fontan, their target long-term incentive awards increased as compared to the prior year to reflect their promotions and the market data for their new roles.

 2023 Long-Term Compensation Incentive Program Awards

 In January 2023 the Talent and Compensation Committee approved the 2023 long-term incentive award target amounts for each NEO. This amount for each NEO was then converted into the number of performance units, stock options, and shares of restricted stock granted to each NEO based on an allocation of 60% performance units, 20% stock options, and 20% restricted stock.

 NEO
 Long-Term Incentive
Grant Date Value
(As of January 26, 2023)
 2023-2025 Target PUP Performance Units
 Shares of Restricted Stock

 $1,516,828
 7,345
 14,459
 2,762

 $560,947
 2,716
 5,346
 1,022

 $1,440,733
 6,977
 13,733
 2,623

 $466,273
 2,258
 4,444

 $6,379,927
 30,895
 60,815
 11,616

 $568,160
 2,751
 5,415
 1,035

 $334,508
 1,620
 3,188

 $411,779
 1,994
 3,924

 $1,913,023
 9,264
 18,235
 3,483

 All the performance units, shares of restricted stock and stock options granted to the NEOs in 2023 were granted pursuant to the 2019 OIP. The 2019 OIP requires a "double trigger," meaning both a change in control of Entergy and an involuntary job loss without cause or a resignation by the NEO for good reason within 24 months following the change in control (a "double trigger"), for the acceleration of these awards upon a change in control.

 2023 Long-Term Incentive Award Mix

 Long-Term Performance Units

 The NEOs are issued performance unit awards under the PUP with payout opportunities established by the Talent and Compensation Committee at the beginning of each three-year performance period.

 The PUP specifies minimum, target, and maximum performance levels, the achievement of which determines the number of performance units that may be earned by each participant. For the 2023 – 2025 PUP performance period, the Talent and Compensation Committee chose the performance measures, which were the same measures as used in the 2022-2024 PUP performance period, and established the targets set forth below.

 2023-2025 PUP Performance Period: Measures and Goals
 Performance Measures(1)

 PUP
Measure Weight
 Goals(2)

 Relative TSR
 80%
 Minimum (25%) - Bottom of 3rd Quartile
 Target (100%) - Median Percentile
 Maximum (200%) - Top Quartile

 Adjusted FFO/Debt Ratio(3)

 20%
 Minimum (25%) - 14.0%
Target (100%) - 2023: 14.5%; 2024: 15.0%; 2025: 15.0%
Maximum (200%) - 2023: 15.5%; 2024: 16.0%; 2025: 16.0%

 (1)Payouts for performance between achievement levels are calculated using straight-line interpolation, between minimum and target and between target and maximum, with no payouts for performance below the minimum achievement level with respect to the applicable performance measure, and payouts capped at the maximum achievement level with respect to the applicable performance measure.
 (2)There is no payout if the relative TSR falls within the lowest quartile of the peer companies in the Philadelphia Utility Index and the Adjusted FFO/Debt Ratio is below the minimum achievement level.
 (3)The Adjusted FFO/Debt Ratio, a non-GAAP financial measure, is the ratio of: (i) adjusted funds from operations calculated as consolidated operating cash flow adjusted for allowance for funds used during construction, working capital and the effects of securitization revenue, and the Pre-Determined Exclusions to (ii) total consolidated debt, excluding outstanding or pending securitization debt. The Adjusted FFO/Debt Ratio is evaluated on an annual basis against the target set for each year. The annual results are converted into payout percentages based on the annual minimum, target and maximum targets, and those percentages are then averaged to determine the Adjusted FFO/Debt Ratio payout percentage. The calculated PUP result will then be adjusted by 10 basis points for a change in Entergy Corporation's corporate credit outlook and 20 basis points for an upgrade or downgrade in the corporate credit rating for Entergy Corporation. The maximum increase or decrease from adjustments made under this modifier is 20 basis points, and performance may not be reduced below zero or increased beyond 200%.

 Performance Measures

 Relative TSR:

 • The Talent and Compensation Committee chose relative TSR as a performance measure because it reflects the Company's creation of shareholder value relative to other electric utilities included in the Philadelphia Utility Index over the performance period. By measuring performance in relation to an industry benchmark, this measure is intended to isolate and reward management for the creation of shareholder value that is not driven by events that affect the industry as a whole.

 • Minimum, target, and maximum performance levels are determined by reference to the ranking of Entergy's TSR in relation to the TSR of the companies in the Philadelphia Utility Index. The Talent and Compensation Committee identified the Philadelphia Utility Index as the appropriate industry peer group for determining relative TSR because the companies included in this index, in the aggregate, are viewed as comparable to the Company in terms of business and scale.

 Adjusted FFO/Debt Ratio:

 • To emphasize the importance of strong credit for the long-term health of our business, for the 2023 – 2025 PUP performance period we used the Adjusted FFO/Debt Ratio credit measure.

 • The Talent and Compensation Committee decided to use this measure because it emphasizes financial stability, noting that a financially healthy utility creates the capacity to make investments on behalf of customers, addresses the needs of our communities, provides low-cost access to capital markets, and promotes employee confidence.

 • To further underscore the importance of this measure, the calculated PUP result will be adjusted as described above for a change in the corporate credit outlook and corporate credit rating for Entergy Corporation.

 Stock Options and Restricted Stock

 The Company grants stock options and shares of restricted stock as part of its long-term incentive award mix because it aligns the interests of the executive officers with long-term shareholder value, provides competitive compensation, and increases the executives' ownership in Entergy's common stock. Generally, stock options are

 granted annually on a pre-established schedule with a maximum term of ten years and vest one-third on each of the first three anniversaries of the date of grant. The date of grant for annual equity award grants is the date of the Talent and Compensation Committee meeting at which they are approved, which is regularly scheduled each year in late January or the first week of February. The Talent and Compensation Committee does not take material nonpublic information into account when determining the timing and terms of option awards. The exercise price for each option granted in January 2023 was $108.47, which was the closing price of Entergy's common stock on the date of grant. Shares of restricted stock vest one-third on each of the first three anniversaries of the date of grant, are paid dividends which are reinvested in shares of Entergy stock and have full voting rights. The dividend reinvestment shares are subject to forfeiture similar to the terms of the original grant.

 Payouts for the 2021 – 2023 PUP Performance Period

 In December 2020, the Talent and Compensation Committee chose relative TSR and Adjusted FFO/Debt Ratio as the performance measures for the 2021 – 2023 PUP performance period, with relative TSR weighted 80% and Adjusted FFO/Debt Ratio weighted 20%. The payout was determined based on the achievement of the following performance goals established for both performance measures by the committee at the beginning of the performance period:

 2021 – 2023 PUP Performance Period: Measure and Goals
 Performance Measure(1)

 PUP
Measure Weight
 Payout(2)

 Relative TSR
 80%
 Minimum (25%) - Bottom of 3rd Quartile
 Target (100%) - Median
 Maximum (200%) - Top Quartile

 Adjusted FFO/Debt Ratio(3)

 20%
 Minimum (25%) - 14.50%
Target (100%) - 15.50%
Maximum (200%) - 17.00%

 (1)Payouts for performance between achievement levels are calculated using straight-line interpolation. There is no payout for performance below the minimum achievement level and payouts are capped for performance at or above the maximum achievement level.
 (2)There is no payout if the TSR falls within the lowest quartile of the peer companies in the Philadelphia Utility Index and the FFO/Debt Ratio is below the minimum achievement level.
 (3)The Adjusted FFO/Debt Ratio, a non-GAAP financial measure, is the ratio of: (i) adjusted funds from operations calculated as consolidated operating cash flow adjusted for allowance for funds used during construction, working capital and the effects of securitization revenue, and the Pre-Determined Exclusions to (ii) total consolidated debt, excluding outstanding or pending securitization debt. The Adjusted FFO/Debt Ratio is evaluated on an annual basis against the target set for each year. The annual results are converted into payout percentages based on the annual minimum, target and maximum targets, and those percentages are then averaged to determine the Adjusted FFO/Debt Ratio payout percentage.

 In January 2024, the Talent and Compensation Committee reviewed the Company's relative TSR and the Adjusted FFO/Debt Ratio for the 2021 – 2023 PUP performance period in order to determine the payout to participants based upon the performance measures and range of potential payouts for the 2021 – 2023 PUP performance period as provided above. The Talent and Compensation Committee compared the Company's TSR against the TSR of the companies that were included in the Philadelphia Utility Index as of the last day of the year preceding the three-year performance period, which were:

 • AES Corporation

 • Eversource Energy

 • Ameren Corporation

 • Exelon Corporation

 • American Electric Power Co. Inc.

 • FirstEnergy Corporation

 • American Water Works Company, Inc.

 • NextEra Energy, Inc.

 • CenterPoint Energy Inc.

 • Pinnacle West Capital Corporation

 • Consolidated Edison Inc.

 • PG&E Corporation

 • Dominion Energy

 • Public Service Enterprise Group, Inc.

 • DTE Energy Company

 • Southern Company

 • Duke Energy Corporation

 • Xcel Energy, Inc.

 • Edison International

 As recommended by the Finance Committee, the Talent and Compensation Committee concluded that Entergy Corporation's relative TSR for the 2021 – 2023 PUP performance period was in the second quartile, resulting in an achievement level of 115% of target, and that the Adjusted FFO/Debt Ratio was 10.74% for 2021, 14.30% for 2022 and 16.95% for 2023, resulting in an achievement level of 66% of target. These results yielded an overall payout of 105% of target for the NEOs.

 2021 - 2023 Target PUP Performance Units
 Number of Shares Issued(1)

 Value of Shares Actually Issued(2)

 Grant Date Fair Value(3)

 8,784
 10,344
 $1,022,608
 $946,617

 Haley R. Fisackerly(4)

 1,889
 2,209
 $218,447
 $203,570

 Kimberly A. Fontan(4)

 4,179
 4,777
 $472,254
 $450,354

 Laura R. Landreaux(4)

 1,841
 2,149
 $212,593
 $198,397

 Andrew S. Marsh(4)

 20,866
 23,917
 $2,364,435
 $2,248,645

 2,162
 2,546
 $251,701
 $232,990

 Deanna D. Rodriguez(4)

 1,609
 1,849
 $182,927
 $173,395

 Eliecer Viamontes(4)

 1,938
 2,269
 $224,410
 $208,851

 10,727
 12,632
 $1,248,800
 $1,156,006

 (1)Includes accrued dividends.
 (2)Value determined based on the closing price of Entergy Corporation common stock on January 18, 2024 ($98.86), the date the Talent and Compensation Committee certified the 2021 – 2023 performance period results.
 (3)Represents the aggregate grant date fair value calculated in accordance with applicable accounting rules as reflected in the 2021 Summary Compensation Table in the Form 10-K filed for the year ended December 31, 2021, except for NEOs whose target award opportunities were increased in 2022, as discussed in footnote 4.
 (4)Mses. Fontan, Landreaux, and Rodriguez and Messrs. Fisackerly, Marsh, and Viamontes each experienced a change in officer status in 2022, and accordingly, their target award opportunities were increased for the 2021 – 2023 performance period as follows: from 11,706 to 20,866 for Mr. Marsh; from 2,184 to 4,179 for

 Ms. Fontan; from 1,645 to 1,889 for Mr. Fisackerly; from 1,553 to 1,841 for Ms. Landreaux; from 1,301 to 1,609 for Ms. Rodriguez; and from 1,737 to 1,938 for Mr. Viamontes.

 Benefits and Perquisites

 The NEOs are eligible to participate in or receive the following benefits:

 Plan Type

 Retirement Plans
 Entergy Corporation-sponsored:

 Entergy Retirement Plan - a tax-qualified final average pay defined benefit pension plan that covers a broad group of employees hired before July 1, 2014. As used in this CD&A, "Entergy Retirement Plan" refers to the final average pay defined benefit pension plan benefit provided to eligible employees pursuant to the Entergy Corporation Retirement Plan for Non-Bargaining Employees.
 Cash Balance Plan - a tax-qualified cash balance defined benefit pension plan that covers a broad group of employees hired on or after July 1, 2014 and before January 1, 2021. Effective January 1, 2022, the Cash Balance Plan was merged with and into the Entergy Retirement Plan as Appendix J of the Entergy Corporation Retirement Plan for Non-Bargaining Employees, while maintaining the same cash balance pension benefit formula. As used in this CD&A, "Cash Balance Plan" refers to the cash balance defined benefit pension plan benefit provided to eligible employees pursuant to Appendix J of the Entergy Corporation Retirement Plan for Non-Bargaining Employees.
 Pension Equalization Plan (PEP) - a non-qualified pension restoration plan for certain highly compensated non-bargaining employees who participate in the Entergy Retirement Plan.
 Cash Balance Equalization Plan (CBEP) - a non-qualified restoration plan for a certain highly compensated non-bargaining employees who participate in the Cash Balance Plan.
 System Executive Retirement Plan (SERP) - a non-qualified supplemental retirement plan for a select group of individuals who became executive officers before July 1, 2014.

 See "2023 Pension Benefits" for additional information regarding the operation of the plans described above.

 Savings Plan
 Entergy Corporation-sponsored 401(k) Savings Plan that covers a broad group of employees and provides for an employer matching contribution.

 Health & Welfare Benefits
 Medical, dental and vision coverage, health care and dependent care reimbursement plans, life and accidental death and dismemberment insurance, business travel accident insurance, and basic long-term disability insurance.

Eligibility, coverage levels, potential employee contributions, and other plan design features are the same for the NEOs as for the broad employee population.

 2023 Perquisites
 Corporate aircraft usage and annual mandatory physical exams. The NEOs who are members of the OCE do not receive tax gross ups on any benefits, except for relocation benefits.

In 2023, the NEOs who are not members of the OCE also were provided with club dues, relocation assistance, and tax gross up payments on these perquisites.

For additional information regarding perquisites, see the "All Other Compensation" column in the 2023 Summary Compensation Table.

 Plan Type

 Deferred Compensation
 The NEOs are eligible to defer up to 100% of their base salary and annual incentive awards into the Entergy Corporation sponsored Executive Deferred Compensation Plan.

 Executive Disability Plan
 This plan pays eligible individuals a supplemental long-term disability (LTD) benefit if they are disabled and receiving LTD benefits from the broad-based LTD Plan. The benefit payable under this plan is equal to 65% of the difference between their annual base salary and the annual base salary that produces the maximum disability payment under our broad-based LTD plan, which is $15,000.

 Entergy Corporation provides these benefits to the NEOs as part of its effort to provide a competitive executive compensation program and because it believes that these benefits are important retention and recruitment tools since many of the companies with which it competes for executive talent provide similar arrangements to their senior executive officers.

 Severance and Retention Arrangements

 The Talent and Compensation Committee believes that retention and transitional compensation arrangements are an important part of overall compensation as they help to secure the continued employment and dedication of the NEOs, notwithstanding any concern that they might have at the time of a change in control regarding their own continued employment. In addition, the Talent and Compensation Committee believes that these arrangements are important as recruitment and retention devices, as many of the companies with which Entergy Corporation competes for executive talent have similar arrangements in place for their senior employees.

 To achieve these objectives, Entergy Corporation has established a System Executive Continuity Plan ("Continuity Plan") under which each of our NEOs is entitled to receive "change in control" payments and benefits if such officer's employment is involuntarily terminated without cause or if the officer resigns for good reason, in each case, in connection with a change in control of the Company. Entergy strives to ensure that the benefits and payment levels under the Continuity Plan are consistent with market practices. Entergy's executive officers, including the NEOs, are not entitled to any tax gross up payments on any severance benefits received under this plan. For more information regarding our severance arrangements, see "Potential Payments Upon Termination or Change in Control."

 Risk Mitigation and Other Pay Practices

 Entergy Corporation strives to ensure that its compensation philosophy and practices are in line with the best practices of companies in its industry as well as other companies in the S&P 500. Some of these practices include the following:

 Policy for Recoupment of Compensation (Clawback Provisions)

 In October 2023 the Talent and Compensation Committee approved and recommended that the Entergy Board adopt an amended and restated clawback policy to comply with the final rules required by the SEC and the NYSE (the "new clawback rules"). On October 27, 2023, the Board adopted the amended and restated policy regarding the recoupment of certain compensation (the "Clawback Policy"), with an effective date of October 2, 2023. Any incentive compensation award granted or paid on or after this effective date is subject to the terms of the Clawback Policy. The board of directors of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas also adopted the Clawback Policy, effective October 2, 2023.

 The Clawback Policy updates Entergy's prior clawback policy to comply with the new clawback rules and incorporate the terminology of the new clawback rules, but retains the provisions of Entergy's prior clawback policy that were more stringent than the new clawback rules, including:

 • Mandatory recoupment of incentive compensation for a material miscalculation of a performance measure, regardless of whether it results in a financial restatement;
 • Recoupment of incentive compensation received by an executive officer in respect of the three-year lookback period, regardless of whether the recipient was an executive officer at the time of receipt of the incentive compensation or during the performance period to which it relates;
 • A broader definition of incentive compensation that includes compensation based on attainment of market performance metrics, as well as financial reporting measures; and
 • Discretionary recoupment of some or all incentive compensation if an executive officer engages in fraud resulting in a financial restatement or material miscalculation of a performance measure.

 Under the Clawback Policy, Entergy will seek reimbursement of certain compensation from current or former executive officers subject to Section 16, including all of the NEOs, where:

 • Entergy is required to restate its financial statements due to noncompliance with any financial reporting requirement under securities laws; or
 • there is a material miscalculation of a performance measure related to incentive compensation, regardless of whether Entergy's financial statements are restated.

 In addition, Entergy may seek reimbursement of certain compensation from current or former executive officers subject to Section 16, including all of the NEOs, if the Board determines that such executive officer engaged in fraud that resulted in either a restatement of Entergy's financial statements or a material miscalculation of a performance measure relative to incentive compensation.

 The Clawback Policy applies to incentive compensation, including cash or equity-based bonus or incentive or profit-sharing awards paid in respect of the three-year period prior to the year in which Entergy is required to prepare such restatement or in respect of the three-year period preceding the material miscalculation. The amount required to be reimbursed is equal to the excess of the gross incentive payment actually paid over the gross payment that would have been paid if the original payment had been determined based on the restated financial results or correct calculation. Entergy may enforce all or part of any executive officer's repayment obligation under the policy by reducing any amounts that may be owed from time-to-time by Entergy or any of its subsidiaries to such individual, whether as wages, severance, vacation pay or in the form of any other benefit or for any other reason. In addition, Entergy will seek to recover any compensation received by its Chief Executive Officer and Chief Financial Officer that is required to be reimbursed under the Sarbanes-Oxley Act of 2002 following a material restatement of our financial statements.

 In addition to the above-described recoupment policy, in January 2024, the Entergy Board adopted an additional discretionary recoupment policy applicable to all officers of Entergy System companies, including the NEOs, that allows recoupment of incentive compensation from an officer who engages in certain detrimental conduct, including (i) commission of a felony or other crime that affects the officer's ability to perform their duties, (ii) fraud in contravention of the officer's duties to the enterprise, (iii) unauthorized disclosure of confidential or proprietary information of an Entergy System company or material violation of a material written Entergy System company policy or material agreement between the officer and an Entergy System company in either case that results in, or could have resulted in, termination for cause as defined in the 2019 OIP or that results in significant financial or operational loss, or significant reputational harm to Entergy; and (iv) other conduct that the officer knew or should have known could result in termination for Cause as defined in the 2019 OIP (regardless whether it does) and that results in significant financial or operational loss or significant reputational harm to Entergy. The new discretionary recoupment policy for detrimental conduct applies to all incentive compensation, including time-based awards, and allows for the claw back of compensation received after the detrimental conduct and within the three-year period preceding the detrimental conduct, provided the recoupment efforts are commenced within five years

 after the detrimental conduct and before a change in control. The additional discretionary recoupment policy applies to detrimental conduct committed on or after January 26, 2024, the effective date of the additional discretionary recoupment policy.

 Stock Ownership Guidelines and Share Retention Requirements

 Entergy Corporation requires its NEOs to own Entergy stock to further align their interests with Entergy's shareholders' interests. Stock ownership levels are achieved through ownership of any Entergy shares held by the officer, including shares held in the 401(k) plan, restricted stock, and dividends earned on restricted shares during the period of restriction. Performance units held under the PUP, stock options, whether vested or unvested, do not count toward achievement of stock ownership levels. Annually, the Talent and Compensation Committee monitors the executive officers' compliance with these guidelines with all of the NEOs in compliance with the applicable ownership guidelines at the time of the annual review. The ownership guidelines are as follows:

 Role
 Value of Common Stock to be Owned

 Chief Executive Officer
 6 x base salary

 Executive Vice Presidents
 3 x base salary

 Senior Vice Presidents
 2 x base salary

 Vice Presidents
 1 x base salary

 Further, to facilitate compliance with the guidelines, until an executive officer satisfies the stock ownership guidelines, the officer must retain:

 • all net after-tax shares paid out under the PUP;
 • all net after-tax shares of our restricted stock and all net after-tax shares received upon the vesting of restricted stock units; and
 • at least 75% of the after-tax net shares received upon the exercise of Entergy Corporation stock options.

 Trading Controls

 Executive officers, including the NEOs, are required to receive permission from the Company's General Counsel or his designee prior to entering into any transaction involving Company securities, including gifts, other than an exercise of employee stock options that is not funded through a sale in the market. Trading is generally permitted only during specified open trading windows beginning shortly after the release of earnings. Employees who are subject to trading restrictions, including the NEOs, may enter into trading plans under Rule 10b5-1 of the Exchange Act, but these trading plans or any amendment to an existing plan may be entered into only during an open trading window and must be approved by the Company.

 No Pledging/Hedging

 Entergy Corporation also prohibits directors and executive officers, including the NEOs, from pledging any Entergy Corporation securities or entering into margin accounts involving Entergy Corporation securities. Entergy Corporation prohibits these transactions because of the potential that sales of Entergy Corporation securities could occur outside trading periods and without the required approval of the General Counsel. In addition, Entergy Corporation prohibits directors and executive officers, including the NEOs, from engaging in any hedging transactions with respect to Entergy securities.

 Compensation Consultant Independence

 Annually, the Talent and Compensation Committee reviews the relationship with its compensation consultant to determine whether any conflicts of interest exist that would prevent the consultant from independently advising the Talent and Compensation Committee. When assessing the independence of Pay Governance, its current compensation consultant, in 2023, the committee considered the following factors, among others:

 • Pay Governance has policies in place to prevent conflicts of interest;
 • No member of Pay Governance's consulting team serving the committee has a business relationship with any member of the committee or any of Entergy Corporation's executive officers;
 • Neither Pay Governance nor any of its principals own any shares of Entergy Corporation's common stock; and
 • The amount of fees paid to Pay Governance is less than 1% of Pay Governance's total consulting income.

 Based on these factors, the Talent and Compensation Committee concluded that Pay Governance is independent in accordance with SEC and NYSE rules and that no conflicts of interest exist that would prevent Pay Governance from independently advising the committee.

 In addition, Pay Governance has agreed that it will not accept any engagement with management without prior approval from the Talent and Compensation Committee, and Entergy Corporation's Board has adopted a policy that prohibits a compensation consultant from providing other services to it if the aggregate amount for those services would exceed $120,000 in any year. During 2023, Pay Governance did not provide any services to Entergy Corporation other than the services it performed on behalf of the Talent and Compensation and Corporate Governance Committees, and it worked with Entergy Corporation's management only as directed by those committees.

 TALENT AND COMPENSATION COMMITTEE REPORT

 The Talent and Compensation Committee Report included in the 2024 Entergy Proxy Statement is incorporated by reference, but will not be deemed to be "filed" in this Annual Report on Form 10-K. None of the Registrant Subsidiaries has a compensation committee or other board committee performing equivalent functions. The board of directors of each of the Registrant Subsidiaries is comprised of individuals who are officers or employees of Entergy Corporation or one of the Registrant Subsidiaries. These boards do not make determinations regarding the compensation paid to executive officers of the Registrant Subsidiaries.

 EXECUTIVE COMPENSATION TABLES

 2023 Summary Compensation Table

 The following table summarizes the total compensation paid or earned by each of the NEOs for the fiscal year ended December 31, 2023, and to the extent required by SEC executive compensation disclosure rules, the fiscal years ended December 31, 2022 and 2021. For information on the principal positions held by each of the NEOs, see Item 10, "Directors, Executive Officers, and Corporate Governance of the Registrants."

 The compensation set forth in the table represents the aggregate compensation paid by all Entergy System companies. For additional information regarding the material terms of the awards reported in the following table, including a general description of the formula or criteria to be applied in determining the amounts payable, see "Compensation Discussion and Analysis."

 (a)
 (b)
 (c)
 (e)
 (f)
 (g)
 (h)
 (i)
 (j)
 (k)

 Name and
 Principal Position
 (1)

 Year

 Salary
 (2)

 (3)

 Awards
 (4)

 Non-Equity
 Plan
 (5)

 Value and
 Non-qualified
 Deferred
 Earnings
 (6)

 All
 Other
 (7)

 Total

 Total
 Without
 Value
 (8)

 2023
 $753,419
 $1,226,636
 $290,192
 $950,104
 $731,700
 $77,328
 $4,029,379
 $3,297,679

 Executive Vice

 2022
 $726,363
 $1,144,238
 $273,358
 $761,302
 $976,700
 $93,793
 $3,975,754
 $2,999,054

 President and

 2021
 $705,286
 $2,738,613
 $268,787
 $852,840
 $491,400
 $60,135
 $5,117,061
 $4,625,661

 General Counsel -

 Entergy Corp.

 2023
 $431,421
 $453,653
 $107,294
 $325,368
 $247,800
 $47,415
 $1,612,951
 $1,365,151

 2022
 $410,557
 $752,209
 $62,595
 $319,427
 $—
 $46,281
 $1,591,069
 $1,591,069

 2021
 $396,604
 $231,921
 $50,319
 $216,186
 $190,000
 $41,723
 $1,126,753
 $936,753

 2023
 $625,000
 $1,165,112
 $275,621
 $646,875
 $409,600
 $31,860
 $3,154,068
 $2,744,468

 Executive Vice
 2022
 $404,809
 $1,034,293
 $80,519
 $379,688
 $—
 $29,720
 $1,929,029
 $1,929,029

 President and CFO -

 Entergy Corp.,

 Entergy Arkansas,

 Entergy Louisiana,

 Entergy Mississippi,

 Entergy New

 Orleans, and

 2023
 $406,405
 $377,082
 $89,191
 $305,428
 $175,600
 $23,719
 $1,377,425
 $1,201,825

 2022
 $390,161
 $341,381
 $62,595
 $271,015
 $—
 $25,313
 $1,090,465
 $1,090,465

 2021
 $350,660
 $219,035
 $47,522
 $220,093
 $125,000
 $20,683
 $982,993
 $857,993

 2023
 $1,100,000
 $5,159,370
 $1,220,557
 $1,821,600
 $982,400
 $89,281
 $10,373,208
 $9,390,808

 Chair of the

 2022
 $781,560
 $4,598,890
 $414,050
 $960,700
 $—
 $106,560
 $6,861,760
 $6,861,760

 Board and CEO -
 2021
 $705,286
 $1,650,645
 $358,235
 $906,143
 $213,000
 $56,018
 $3,889,327
 $3,676,327

 Entergy Corp.

 (a)
 (b)
 (c)
 (e)
 (f)
 (g)
 (h)
 (i)
 (j)
 (k)

 Name and
 Principal Position
 (1)

 Year

 Salary
 (2)

 (3)

 Awards
 (4)

 Non-Equity
 Plan
 (5)

 Value and
 Non-qualified
 Deferred
 Earnings
 (6)

 All
 Other
 (7)

 Total

 Total
 Without
 Value
 (8)

 2023
 $449,491
 $459,481
 $108,679
 $340,945
 $114,400
 $36,586
 $1,509,582
 $1,395,182

 2022
 $430,676
 $957,246
 $121,176
 $326,732
 $—
 $39,225
 $1,875,055
 $1,875,055

 2021
 $413,752
 $304,893
 $66,160
 $333,205
 $2,000
 $25,261
 $1,145,271
 $1,143,271

 2023
 $358,208
 $270,525
 $63,983
 $226,421
 $270,200
 $23,671
 $1,213,008
 $942,808

 2022
 $342,565
 $260,189
 $48,328
 $217,320
 $—
 $27,087
 $895,489
 $895,489

 New Orleans
 2021
 $314,450
 $339,833
 $—
 $144,662
 $144,900
 $59,161
 $1,003,006
 $858,106

 2023
 $361,284
 $333,024
 $78,755
 $251,202
 $28,700
 $25,846
 $1,078,811
 $1,050,111

 2022
 $347,459
 $296,861
 $53,528
 $240,731
 $11,800
 $168,309
 $1,118,688
 $1,106,888

 Texas
 2021
 $324,120
 $245,000
 $53,154
 $134,793
 $22,300
 $102,190
 $881,557
 $859,257

 2023
 $799,130
 $1,547,047
 $365,976
 $775,192
 $204,800
 $112,338
 $3,804,483
 $3,599,683

 Group President
 2022
 $770,432
 $3,682,723
 $402,025
 $776,434
 $—
 $101,107
 $5,732,721
 $5,732,721

 Utility Operations -
 2021
 $748,087
 $1,512,547
 $328,247
 $844,277
 $77,500
 $75,540
 $3,586,198
 $3,508,698

 Entergy Corp.

 (1)Mr. Marsh was named Chief Executive Officer, effective November 1, 2022, and Ms. Fontan was named Executive Vice President and Chief Financial Officer, on such date. Effective January 31, 2023, Mr. Marsh was elected Chair of the Board.
 (2)The amounts in column (c) represent the actual base salary paid to the NEOs in the applicable year. The 2023 changes in base salaries noted in the CD&A were effective in April 2023.
 (3)The amounts in column (e) represent the aggregate grant date fair value of restricted stock and performance units granted under the 2019 OIP, each calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures. The grant date fair value of the restricted stock, restricted stock units, and the portion of the performance units with vesting based on the Adjusted FFO/Debt Ratio is based on the closing price of Entergy Corporation common stock on the date of grant. The grant date fair value of the portion of the performance units attributable to relative TSR was measured using a Monte Carlo simulation valuation model. The simulation model applies a risk-free interest rate and an expected volatility assumption. The risk-free interest rate is assumed to equal the yield on a three-year treasury bond on the grant date. Volatility is based on historical volatility for the 36-month period preceding the grant date. The performance units in the table are also valued based on the probable outcome of the applicable performance condition at the time of grant. The maximum value of shares that would be received if the highest achievement level is attained with respect to both the relative TSR and Adjusted FFO/Debt Ratio, for performance units granted in 2023 are as follows: Mr. Brown, $1,593,424; Mr. Fisackerly, $589,209; Ms. Fontan, $1,513,590; Ms. Landreaux, $489,851; Mr. Marsh, $6,702,361; Mr. May, $596,802; Ms. Rodriguez, $351,443; Mr. Viamontes, $432,578; and Mr. West, $2,009,732.
 (4)The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the 2019 OIP calculated in accordance with FASB ASC Topic 718. For a discussion of the relevant assumptions used in valuing these awards, see Note 12 to the financial statements.
 (5)The amounts in column (g) represent annual incentive award cash payments made under the 2019 OIP.
 (6)The amounts in column (h) include the annual actuarial change in the present value of these NEOs' benefits under all pension plans established by Entergy Corporation using interest rate and mortality rate assumptions consistent with those used in Entergy Corporation's financial statements and include amounts which the NEOs may not currently be entitled to receive because such amounts are not vested. None of the increases for any of

 the NEOs are attributable to above-market or preferential earnings on non-qualified deferred compensation. See "2023 Pension Benefits."
 (7)The amounts in column (i) for 2023 include (a) matching contributions by Entergy Corporation under the Savings Plan to each of the NEOs; (b) dividends paid on restricted stock and performance units when vested; (c) life insurance premiums; (d) tax reimbursements on club dues; and (e) perquisites and other compensation as described further below. The 2023 amounts are listed in the following table:

 Company Matching Contribution – Savings Plan
 Dividends Paid on Restricted Stock and PUP Awards
 Life Insurance Premium
 Tax Reimbursement
 Perquisites and Other Compensation

 Total

 $48,042
 $11,484
 $—
 $3,942
 $77,328

 $8,335
 $6,441
 $5,148
 $13,631
 $47,415

 $11,613
 $1,587
 $—
 $4,800
 $31,860

 $—
 $8,226
 $2,113
 $4,094
 $9,286
 $23,719

 $62,421
 $7,737
 $—
 $5,263
 $89,281

 $12,424
 $10,302
 $—
 $—
 $36,586

 $8,215
 $1,596
 $—
 $—
 $23,671

 $19,800
 $5,237
 $809
 $—
 $—
 $25,846

 $55,542
 $7,482
 $—
 $35,454
 $112,338

 (8)In order to show the effect that the year-over-year change in pension value had on total compensation, as determined under applicable SEC rules, we have included an additional column to show total compensation minus the change in pension value. The amounts reported in the Total Without Change in Pension Value column may differ substantially from the amounts reported in the Total column required under SEC rules and are not a substitute for total compensation. Total Without Change in Pension Value represents total compensation, as determined under applicable SEC rules, minus the change in pension value reported in the Change in Pension Value and Nonqualified Deferred Compensation Earnings column. The change in pension value is subject to many external variables, such as interest rates, assumptions about life expectancy, and changes in the discount rate determined at each year end, which are functions of economic factors and actuarial calculations that are not related to Entergy Corporation's performance and are outside of the control of the Talent and Compensation Committee.

 Perquisites and Other Compensation

 The amounts set forth in column (i) also include perquisites and other personal benefits that Entergy Corporation provides to its NEOs as part of providing a competitive executive compensation program and for employee retention. The following perquisites were provided to the NEOs in 2023.

 Personal Use of Corporate Aircraft
 Club Dues
 Executive Physical Exams

 X

 X
 X

 X

 X

 X

 X

 X
 X

 For security and business reasons, Entergy Corporation's Chief Executive Officer is permitted to use its corporate aircraft for personal use at the expense of Entergy Corporation. The other NEOs may use the corporate aircraft for personal travel subject to the approval of Entergy Corporation's Chief Executive Officer. Annually, the Talent and Compensation Committee reviews the level of usage. Entergy Corporation believes that its officers' ability to use its plane for limited personal use saves time and helps to ensure their safety and security while traveling, thereby benefiting the Company. The amounts included in column (i) for the personal use of corporate aircraft, reflect the incremental cost to Entergy Corporation for use of the corporate aircraft, determined on the basis of the variable operational costs of each flight, including fuel, maintenance, flight crew travel expense, catering, communications, and fees, including flight planning, ground handling, and landing permits. The aggregate incremental aircraft usage cost associated with Mr. West's personal use of the corporate aircraft was $32,773 for fiscal year 2023. In addition, Entergy Corporation offers its executives comprehensive annual physical exams at Entergy Corporation's expense. None of the other perquisites referenced above exceeded $25,000 for any of the other NEOs.

 2023 Grants of Plan-Based Awards

 The following table summarizes award grants during 2023 to the NEOs.

 Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1)

 Estimated Future Payouts under Equity Incentive Plan Awards (2)

 (a)
 (b)
 (c)
 (d)
 (e)
 (f)
 (g)
 (h)
 (i)
 (j)
 (k)
 (l)

 Name
 Grant Date
 Thresh-
 old

 Thresh-
 old

 All Other Stock Awards: Number of Shares of Stock or Units
 All Other Option Awards: Number of Securities Under-lying Options
 Exercise or Base Price of Option Awards
 Grant Date Fair Value of Stock and Option Awards

 ($)
 ($)
 ($)
 (#)

 (#)

 (#)

 (#)
 (3)

 (#)
 (4)

 ($/Sh)
 ($)
 (5)

 Marcus V.
 $-
 $609,041
 $1,218,082

 Brown
 1,836
 7,345
 14,690
 $927,042

 2,762
 $299,594

 14,459
 $290,192

 Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1)

 Estimated Future Payouts under Equity Incentive Plan Awards (2)

 (a)
 (b)
 (c)
 (d)
 (e)
 (f)
 (g)
 (h)
 (i)
 (j)
 (k)
 (l)

 Name
 Grant Date
 Thresh-
 old

 Thresh-
 old

 All Other Stock Awards: Number of Shares of Stock or Units
 All Other Option Awards: Number of Securities Under-lying Options
 Exercise or Base Price of Option Awards
 Grant Date Fair Value of Stock and Option Awards

 ($)
 ($)
 ($)
 (#)

 (#)

 (#)

 (#)
 (3)

 (#)
 (4)

 ($/Sh)
 ($)
 (5)

 Haley R.
 $-
 $241,014
 $482,028

 Fisackerly

 2,716
 5,432

 $342,797

 1,022

 $110,856

 5,346
 $107,294

 Kimberly A.
 $-
 $468,750
 $937,500

 Fontan
 1,744
 6,977
 13,954
 $880,595

 2,623
 $284,517

 13,733
 $275,621

 Laura R.
 $-
 $226,243
 $452,486

 Landreaux
 2,258
 4,516
 $284,991

 $92,091

 4,444
 $89,191

 Andrew S.
 $-
 $1,320,000
 $2,640,000

 Marsh
 7,724
 30,895
 61,790
 $3,899,382

 11,616
 $1,259,988

 60,815
 $1,220,557

 Phillip R.
 $-
 $272,756
 $545,512

 May, Jr.
 2,751
 5,502
 $347,215

 1,035
 $112,266

 5,415
 $108,679

 Deanna D.
 $-
 $181,137
 $362,274

 Rodriguez
 1,620
 3,240
 $204,467

 $66,058

 3,188
 $63,983

 Eliecer
 $-
 $200,962
 $401,924

 Viamontes
 1,994
 3,988
 $251,671

 $81,353

 3,924
 $78,755

 Roderick K.
 $-
 $645,993
 $1,291,986

 West
 2,316
 9,264
 18,528
 $1,169,246

 3,483
 $377,801

 18,235
 $365,976

 (1)The amounts in columns (c), (d), and (e) represent minimum, target, and maximum payment levels under the annual incentive program. The actual amounts awarded are reported in column (g) of the 2023 Summary Compensation Table.
 (2)The amounts in columns (f), (g), and (h) represent the minimum, target, and maximum payment levels under the PUP. Performance under the program is measured by Entergy Corporation's TSR relative to the TSR of the companies included in the Philadelphia Utility Index and Adjusted FFO/Debt Ratio with TSR weighted eighty percent and Adjusted FFO/Debt Ratio weighted twenty percent. There is no payout under the program if Entergy Corporation's TSR falls within the lowest quartile of the peer companies in the Philadelphia Utility Index and Adjusted FFO/Debt Ratio is below the minimum performance goal. Subject to the achievement of performance targets, each unit will be converted into one share of Entergy Corporation's common stock on the last day of the performance period for the 2023 - 2025 long-term PUP cycle (December 31, 2025). Accrued dividends on the shares earned will also be paid in Entergy Corporation common stock.
 (3)The amounts in column (i) represent shares of restricted stock granted under the 2019 OIP. Shares of restricted stock vest one-third on each of the first through third anniversaries of the grant date, have voting rights, and accrue dividends during the vesting period.
 (4)The amounts in column (j) represent options to purchase shares of Entergy Corporation's common stock granted under the 2019 OIP. The options vest one-third on each of the first through third anniversaries of the grant date and have a ten-year term from the date of grant.
 (5)The amounts in column (l) are valued based on the aggregate grant date fair value of the award calculated in accordance with FASB ASC Topic 718 and, in the case of the performance units, are based on the probable outcome of the applicable performance conditions. See footnotes 4 and 5 to the 2023 Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value.

 2023 Outstanding Equity Awards at Fiscal Year-End

 The following table summarizes, for each NEO, unexercised options, restricted stock that has not vested, and equity incentive plan awards outstanding as of December 31, 2023.

 Option Awards

 (a)
 (b)
 (c)
 (d)
 (e)
 (f)
 (g)
 (h)
 (i)
 (j)

 Name
 Exercisable

 Unexercisable

 Plan
 Unexer-
 cised

 Price

 Expiration
 Date

 of Shares
 or Units
 of Stock
 That
 Have
 Not

 Market
 Shares or
 Units of
 Stock
 That Have
 Not

 Plan
 of
 Other
 Rights
 That

 Plan
 Market or
 Payout
 Other
 Rights That

 (#)
 (#)
 (#)
 ($)
 (#)
 ($)
 (#)
 ($)

 Marcus V.
 —
 14,459(1)

 Brown
 5,607
 11,215(2)

 —
 7,302(3)

 28,574
 —

 14,690(4)

 $1,486,481

 6,477(5)

 $655,408

 2,762(6)

 $279,487

 1,716(7)

 $173,642

 1,015(8)

 $102,708

 14,126(9)

 $1,438,517

 Option Awards

 (a)
 (b)
 (c)
 (d)
 (e)
 (f)
 (g)
 (h)
 (i)
 (j)

 Name
 Exercisable

 Unexercisable

 Plan
 Unexer-
 cised

 Price

 Expiration
 Date

 of Shares
 or Units
 of Stock
 That
 Have
 Not

 Market
 Shares or
 Units of
 Stock
 That Have
 Not

 Plan
 of
 Other
 Rights
 That

 Plan
 Market or
 Payout
 Other
 Rights That

 (#)
 (#)
 (#)
 ($)
 (#)
 ($)
 (#)
 ($)

 Haley R.
 —
 5,346(1)

 Fisackerly
 1,284
 2,568(2)

 2,734
 1,367(3)

 4,300
 —

 4,134
 —

 5,432(4)

 $549,664

 1,510(5)

 $152,797

 1,022(6)

 $103,416

 394(7)

 $39,869

 190(8)

 $19,226

 4,053(10)

 $410,123

 Kimberly A.
 —
 13,733(1)

 Fontan
 1,651
 3,304(2)

 3,630
 1,815(3)

 6,400
 —

 6,000
 —

 2,500
 —
 $78.08
 1/25/2028

 13,954 (4)

 $1,412,005

 5,302(5)

 $536,509

 2,623(6)

 $265,421

 506(7)

 $51,202

 253(8)

 $25,601

 Laura R.
 —
 4,444(1)

 Landreaux
 1,284
 2,568(2)

 2,582
 1,291(3)

 4,300
 —

 5,100
 —

 4,516(4)

 $456,974

 1,769(5)

 $179,005

 849(6)

 $85,910

 394(7)

 $39,869

 180(8)

 $18,214

 Option Awards

 (a)
 (b)
 (c)
 (d)
 (e)
 (f)
 (g)
 (h)
 (i)
 (j)

 Name
 Exercisable

 Unexercisable

 Plan
 Unexer-
 cised

 Price

 Expiration
 Date

 of Shares
 or Units
 of Stock
 That
 Have
 Not

 Market
 Shares or
 Units of
 Stock
 That Have
 Not

 Plan
 of
 Other
 Rights
 That

 Plan
 Market or
 Payout
 Other
 Rights That

 (#)
 (#)
 (#)
 ($)
 (#)
 ($)
 (#)
 ($)

 Andrew S.
 —
 60,815(1)

 Marsh
 8,493
 16,987(2)

 19,464
 9,732(3)

 36,079
 —

 45,182
 —

 49,000
 —
 $78.08
 1/25/2028

 44,000
 —
 $70.53
 1/26/2027

 45,000
 —
 $70.56
 1/28/2026

 24,000
 —
 $89.90
 1/29/2025

 61,790(4)

 $6,252,530

 23,118(5)

 $2,339,310

 11,616(6)

 $1,175,423

 2,599(7)

 $262,993

 1,353(8)

 $136,910

 Phillip R.
 —
 5,415(1)

 May, Jr.
 2,485
 4,972(2)

 3,594
 1,798(3)

 7,300
 —

 6,200
 —

 5,502(4)

 $556,747

 2,871(5)

 $290,516

 1,035(6)

 $104,732

 761(7)

 $77,006

 250(8)

 $25,298

 4,053(10)

 $410,123

 Deanna D.
 —
 3,188(1)

 Rodriguez
 1,983(2)

 3,240(4)

 $327,856

 1,254(5)

 $126,892

 609(6)

 $61,625

 304(7)

 $30,762

 412(8)

 $41,690

 Option Awards

 (a)
 (b)
 (c)
 (d)
 (e)
 (f)
 (g)
 (h)
 (i)
 (j)

 Name
 Exercisable

 Unexercisable

 Plan
 Unexer-
 cised

 Price

 Expiration
 Date

 of Shares
 or Units
 of Stock
 That
 Have
 Not

 Market
 Shares or
 Units of
 Stock
 That Have
 Not

 Plan
 of
 Other
 Rights
 That

 Plan
 Market or
 Payout
 Other
 Rights That

 (#)
 (#)
 (#)
 ($)
 (#)
 ($)
 (#)
 ($)

 Eliecer

 —
 3,924(1)

 Viamontes
 1,098
 2,196(2)

 2,888
 1,444(3)

 3,988(4)

 $403,546

 1,577(5)

 $159,577

 750(6)

 $75,893

 336(7)

 $34,000

 201(8)

 $20,339

 Roderick K.
 —
 18,235(1)

 West
 8,246
 16,494(2)

 17,834
 8,918(3)

 31,705
 —

 25,564
 —

 14,167
 —
 $78.08
 1/25/2028

 18,528(4)

 $1,874,848

 9,525(5)

 $963,835

 3,483(6)

 $352,445

 2,524(7)

 $255,404

 1,240(8)

 $125,476

 18,012(11)

 $1,822,634

 (1)Consists of options granted under the 2019 OIP; 1/3 of the options vested on January 26, 2024 and 1/3 of the remaining options will vest on each of January 26, 2025 and January 26, 2026.
 (2)Consists of options granted under the 2019 OIP; 1/2 of the options vested on January 27, 2024 and the remaining options will vest on January 27, 2025.
 (3)Consists of options granted under the 2019 OIP that vested on January 28, 2024.
 (4)Consists of performance units granted under the 2019 OIP that will vest on December 31, 2025 based on two performance measures- Entergy Corporation's relative TSR performance and Adjusted FFO/Debt Ratio over the 2023 - 2025 performance period with relative TSR weighted eighty percent and Adjusted FFO/Debt Ratio weighted twenty percent, as described under "What Entergy Corporation Pays and Why - Long-Term Incentive Compensation - 2023 Long-Term Incentive Award Mix - Long-Term Performance Units" in the CD&A.
 (5)Consists of performance units granted under the 2019 OIP that will vest on December 31, 2024 based on two performance measures - Entergy Corporation's relative TSR performance and Adjusted FFO/Debt Ratio over the 2022 - 2024 performance period with relative TSR weighted eighty percent and Adjusted FFO/Debt Ratio weighted twenty percent.
 (6)Consists of shares of restricted stock granted under the 2019 OIP; 1/3 of the shares of restricted stock vested on January 26, 2024 and 1/2 of the remaining shares will vest on each of January 26, 2025 and January 26, 2026.

 (7)Consists of shares of restricted stock granted under the 2019 OIP; 1/2 of the shares of restricted stock vested on January 27, 2024 and the remaining shares of restricted stock will vest on January 27, 2025.
 (8)Consists of shares of restricted stock granted under the 2019 OIP that vested on January 28, 2024.
 (9)Consists of restricted stock units granted under the 2019 OIP which will vest on May 17, 2024.
 (10)Consists of restricted stock units granted under the 2019 OIP which will vest on October 1, 2025.
 (11)Consists of restricted stock units granted under the 2019 OIP which will vest in three equal installments on June 1, 2024, June 1, 2025, and June 1, 2026.

 2023 Option Exercises and Stock Vested

 The following table provides information concerning each exercise of stock options and each vesting of stock during 2023 for the NEOs.

 Options Awards

 (a)
 (b)
 (c)
 (d)
 (e)

 Name
 Number of Shares Acquired on Exercise
 Value Realized on Exercise
 Number of Shares Acquired on Vesting
 Value Realized on Vesting (1)

 (#)
 ($)
 (#)
 ($)

 51,917
 $610,505
 13,450
 $1,359,144

 2,200
 $66,815
 2,894
 $292,630

 —
 $—
 5,682
 $570,316

 —
 $—
 2,824
 $285,580

 —
 $—
 28,140
 $2,822,123

 —
 $—
 3,617
 $367,713

 —
 $—
 2,765
 $282,075

 —
 $—
 2,993
 $302,141

 —
 $—
 16,522
 $1,670,452

 (1)Represents the value of performance units for the 2021 – 2023 performance period (payable solely in shares based on the closing stock price of Entergy Corporation on the date of vesting) under the PUP and the vesting of restricted stock and restricted stock units in 2023.

 2023 Pension Benefits

 The following table shows the present value as of December 31, 2023, of accumulated benefits payable to each of the NEOs, including the number of years of service credited to each NEO, under the retirement plans sponsored by Entergy Corporation, determined using interest rate and mortality rate assumptions set forth in Note 11 to the financial statements. Additional information regarding these retirement plans follows this table.

 Name
 Plan Name
 Number of Years Credited Service
 Present Value of Accumulated Benefit
 Payments During 2023

 Marcus V. Brown(1)(2)

 28.74
 $10,108,100
 $—

 28.74
 $1,366,100
 $—

 Haley R. Fisackerly(1)

 28.08
 $2,414,900
 $—

 28.08
 $1,145,200
 $—

 Pension Equalization Plan
 27.56
 $1,019,800
 $—

 27.56
 $808,600
 $—

 Pension Equalization Plan
 16.48
 $422,200
 $—

 16.48
 $476,100
 $—

 25.37
 $6,186,700
 $—

 25.37
 $754,800
 $—

 Phillip R. May, Jr. (1)(3)

 30.00
 $3,022,800
 $—

 36.56
 $1,723,200
 $—

 Deanna D. Rodriguez(1)

 Pension Equalization Plan
 29.19
 $743,100
 $—

 29.19
 $1,277,600
 $—

 Cash Balance Equalization Plan
 3.95
 $28,300
 $—

 Cash Balance Plan
 3.95
 $46,600
 $—

 Roderick K. West(1)

 24.75
 $5,794,600
 $—

 24.75
 $855,700
 $—

 (1)As of December 31, 2023, Mr. Brown, Mr. Fisackerly, Mr. May, Ms. Rodriguez, and Mr. West were retirement eligible.
 (2)In 2022, the Company entered into an agreement with Mr. Brown and amended the PEP and the SERP, pursuant to which agreement and amendments if certain contingencies are met, the benefit payable to Mr. Brown (or to his surviving spouse) under the SERP when he separates from employment with the Company is fixed and will be determined as if such separation from employment occurred as of November 30, 2022 (including the use of final average monthly compensation, service and actuarial assumptions applicable to separations as of such date). If Mr. Brown separates from service and the contingencies are not met, then Mr. Brown (or his surviving spouse) will receive the lesser of the previously described benefit amount under the SERP or the benefit that would have been payable to Mr. Brown under the PEP without regard to the above-described amendments to the SERP and PEP.
 (3)Service under the SERP is granted from the date of hire. Service under the qualified Entergy Retirement Plan is granted from the later of the date of hire or the plan participation date. The SERP amounts reflected in the table for Mr. May is calculated based on 30 years of service pursuant to the terms of the SERP.

 Retirement Benefits

 The tables below contain summaries of the pension benefit plans sponsored by Entergy that the NEOs participated in during 2023. Benefits for the NEOs who participate in these plans are determined using the same formulas as for other eligible employees.

 Qualified Retirement Benefits

 All of our NEOs, except Mr. Viamontes participate in the Entergy Retirement Plan, a tax-qualified final average pay defined benefit pension plan sponsored by Entergy. Mr. Viamontes participates in the Cash Balance Plan, which is a tax-qualified cash balance defined benefit pension plan Entergy sponsors for employees hired after June 30, 2014 and before January 1, 2021. Summaries of these plans are provided below. Benefits for the NEOs are determined using the same formulas as for other eligible employees:

 Cash Balance Plan(1)

 Eligible Named Executive Officers

 Eligibility
 Non-bargaining employees hired before July 1, 2014
 Non-bargaining employees hired on or after July 1, 2014 and before January 1, 2021.

 Vesting
 A participant becomes vested in the Entergy Retirement Plan upon attainment of at least 5 years of vesting service or upon attainment of age 65 while actively employed by an Entergy system company.
 A participant becomes vested in the Cash Balance Plan upon attainment of at least 3 years of vesting service or upon attainment of age 65 while actively employed by an Entergy system company.

 Form of Payment Upon Retirement

 Benefits are payable as an annuity. For employees who separate from service on or after January 1, 2018, a single lump sum distribution may be elected by the participant if eligibility criteria are met.
 Benefits are payable as an annuity or single lump sum distribution.

 Cash Balance Plan(1)

 Retirement Benefit Formula
 Benefits are calculated as a single life annuity payable at age 65 and generally are equal to 1.5% of a participant's Final Average Monthly Earnings (FAME) multiplied by years of service (not to exceed 40).

 Earnings for the purpose of calculating FAME generally includes the employee's base salary and eligible annual incentive awards subject to limitations imposed by the Internal Revenue Code of 1986, as amended (the Code), and excludes all other bonuses. Executive annual incentive awards are not eligible for inclusion in earnings under this plan.

 FAME is calculated using the employee's average monthly earnings for the 60 consecutive months in which the employee's earnings were highest during the 120 month period immediately preceding the employee's retirement and includes up to 5 eligible annual incentive awards paid during the 60 month period, except that executive annual incentive awards are not included in the FAME calculation.

 The normal retirement benefit at age 65 is determined by converting the sum of an employee's annual pay credits and his or her annual interest credits into an actuarially equivalent annuity.

 Pay credits ranging from 4-8% of an employee's eligible earnings are allocated annually to a notional account for the employee based on an employee's age and years of service. Earnings for purposes of calculating an employee's pay credit include the employee's base salary and annual incentive awards, subject to Code limitations, and exclude all other bonuses. Executive annual incentive program awards are eligible for inclusion in earnings under this plan.

 Interest credits are calculated based upon the annual rate of interest on 30-year U.S. Treasury securities, as specified by the Internal Revenue Service, for the month of August preceding the first day of the applicable calendar year subject to a minimum rate of 2.6% and a maximum rate of 9%.

 Benefit Timing(2)

 Normal retirement age under the plan is 65.

A reduced terminated vested benefit may be commenced as early as age 55. The amount of this benefit is determined by reducing the normal retirement benefit by 7% per year for the first 5 years commencement precedes age 65 and 6% per year for each additional year commencement precedes age 65.

A subsidized early retirement benefit may be commenced by employees who are at least age 55 with 10 years of service at the time they separate from service. The amount of this benefit is determined by reducing the normal retirement benefit by 2% per year for each year that early retirement precedes age 65.
 Normal retirement age under the plan is 65.

A vested cash balance benefit may be commenced as early as the first day of the month following separation from service. The amount of the benefit is determined in the same manner as the normal retirement benefit described above in the "Retirement Benefit Formula" section.

 (1)Effective January 1, 2022, the Entergy Corporation Cash Balance Plan for Non-Bargaining Employees merged into and became Appendix J of the Entergy Corporation Retirement Plan for Non-Bargaining Employees, but retained its eligibility, benefit formula, and all benefits, rights, and features.
 (2)As of December 31, 2023, Messrs. Brown, Fisackerly, May, and West and Ms. Rodriguez were eligible for early retirement under the Entergy Retirement Plan.

 Non-qualified Retirement Benefits

 The NEOs are eligible to participate in certain non-qualified retirement benefit plans that provide retirement income in addition to the benefit provided under the qualified retirement plans, including the PEP, the CBEP, and the SERP. Each of these plans is an unfunded non-qualified defined benefit pension plan that provides benefits to key management employees. Upon separation from the Company, those NEOs who participate in both the PEP and the SERP will be paid only the greater of the benefit under the PEP or the SERP. Each of the SERP, PEP, and Cash Balance Equalization Plan is an unfunded non-qualified defined benefit pension plan that provides benefits to key management employees. In general, upon disability, participants in the PEP and the SERP remain eligible for

 continued service credits until the earliest of recovery, separation from service due to disability, or retirement eligibility. Generally, spouses of participants who die before commencement of benefits may be eligible for a portion of the participant's accrued benefit under these plans.

 Pension Equalization Plan
 Cash Balance Equalization Plan

 Eligible Named Executive Officers

 Eligibility(1)

 Management or highly compensated employees who participate in the Entergy Retirement Plan
 Management or highly compensated employees who participate in the Cash Balance Plan
 Certain individuals who became executive officers before July 1, 2014

 Form of Payment Upon Retirement
 Single lump sum distribution
 Single lump sum distribution
 Single lump sum distribution

 Retirement Benefit Formula
 Benefits generally are equal to the actuarial present value of the difference between (1) the amount that would have been payable as an annuity under the Entergy Retirement Plan, including executive annual incentive program awards as eligible earnings and without applying limitations of the Code on pension benefits and earnings that may be considered in calculating tax-qualified pension benefits, and (2) the amount actually payable as an annuity under the Entergy Retirement Plan.

 Executive annual incentive awards are taken into account as eligible earnings under this plan.

 Benefits generally are equal to the difference between the amount that would have been payable as a lump sum under the Cash Balance Plan, but for the Code limitations on pension benefits and earnings that may be considered in calculating tax-qualified cash balance plan benefits, and the amount actually payable as a lump sum under the Cash Balance Plan.
 Benefits generally are equal to the actuarial present value of a specified percentage, based on the participant's years of service (including supplemental service granted under the plan) and management level of the participant's "Final Average Monthly Compensation" (which is generally 1/36th of the sum of the participant's base salary and annual incentive plan award for the three highest years during the last 10 years preceding separation from service), after first being reduced by the value of the participant's Entergy Retirement Plan benefit.

 Benefit timing(2)

 Payable at age 65

 Benefits payable prior to age 65 are subject to the same reduced terminated vested or early retirement reduction factors as benefits payable under the Entergy Retirement Plan as described above.

 An employee with supplemental credited service who terminates employment prior to age 65 must receive prior written consent of the Entergy employer in order to receive the portion of their benefit attributable to their supplemental credited service agreement.

 Payable upon separation from service subject to six month delay if the participant is a "specified employee" under Code Section 409A.

 Payable upon separation from service subject to six month delay required under the Code Section 409A.
 Payable at age 65

Prior to age 65, vesting is conditioned on the prior written consent of the officer's Entergy employer.

Benefits payable prior to age 65 are subject to the same reduced terminated vested or subsidized early retirement reduction factors as benefits payable under the Entergy Retirement Plan as described above.

Payable upon separation from service subject to six month delay if the participant is a "specified employee" under Code Section 409A.

 (1)The SERP was closed to new executive officers effective July 1, 2014. Effective July 1, 2014, (a) no new grants of supplemental service may be provided to participants in the PEP; (b) supplemental credited service granted prior to July 1, 2014 was grandfathered; and (c) participants in Entergy Corporation's Cash Balance Plan are not eligible to participate in the PEP and instead may be eligible to participate in the Cash Balance Equalization Plan.
 (2)Benefits accrued under the SERP, PEP, and CBEP, if any, will become fully vested if a participant is involuntarily terminated without cause or terminates his or her employment for good reason in connection with a change in control with payment generally made in a lump-sum payment as soon as reasonably practicable following the first day of the month after the termination of employment, unless delayed six months under Internal Revenue Code Section 409A.

 2023 Non-Qualified Deferred Compensation

 As of December 31, 2023, Mr. May had a deferred account balance under a frozen Defined Contribution Restoration Plan. The amount is deemed invested, as chosen by Mr. May, in certain T. Rowe Price investment funds that are also available to participants under the Savings Plan. Mr. May has elected to receive the deferred account balance after he retires. The Defined Contribution Restoration Plan, until it was frozen in 2005, credited eligible employees' deferral accounts with employer contributions to the extent contributions under the qualified savings plan in which the employee participated were subject to limitations imposed by the Internal Revenue Code.

 Defined Contribution Restoration Plan
 Name
 Executive Contributions in 2023
 Registrant Contributions in 2023
 Aggregate Earnings in 2023(1)

 Aggregate Withdrawals/Distributions
 Aggregate Balance at December 31, 2023

 (a)
 (b)
 (c)
 (d)
 (e)
 (f)

 $—
 $—
 $369
 $—
 $3,623

 (1)Amounts in this column are not included in the Summary Compensation Table.

 2023 Potential Payments Upon Termination or Change in Control

 Entergy has plans and other arrangements that provide compensation to a NEO if his or her employment terminates under specified conditions, including following a change in control of Entergy.
 Change in Control

 Entergy does not have any plans or agreements that provide for payments or benefits to any of our NEOs solely upon a Change in Control (as defined below). Under the System Executive Continuity Plan (the "Continuity Plan"), executive officers, including each of the NEOs are eligible to receive the cash severance payment and welfare plan benefits described below if their employment is terminated by their Entergy System employer other than for Cause (as defined below) or if they terminate their employment for Good Reason during a period beginning with a potential change in control and ending 24 months following the effective date of a Change in Control (a "Qualifying Termination"). A participant will not be eligible for benefits under the Continuity Plan if such participant: accepts employment with Entergy or any of its subsidiaries; elects to receive the benefits of another severance or separation program; removes, copies, or fails to return any property belonging to Entergy Corporation or any of its subsidiaries or violates the non-compete provision of the Continuity Plan (which generally runs for two years but extends to three years if permissible under applicable law). The Continuity Plan does not include any provisions for the waiver of a breach of any of these restrictive covenants.

 In addition, under the 2019 OIP or an applicable equity award agreement issued under the 2019 OIP, upon a Qualifying Termination, our executive officers, including the NEOs, are eligible for the payments and benefits described in the table below under "Performance Units" and "Equity Awards." Further, in the event of a Qualifying

 Termination, our executive officers, including our NEOs, are eligible for the benefits described in the table below for "Retirement Benefits" under the terms of the SERP, PEP, and/or CBEP, as applicable.

 In the event of a Qualifying Termination, the executive officers, including the NEOs would receive lump sum severance payments and welfare benefits described below. In the event of a Qualifying Termination, all of the NEOs would receive the treatment described below for their retirement benefits and their outstanding performance units and equity awards:

 Compensation Element
 Payment and/or Benefit

 Severance*
 A lump sum severance payment equal to a multiple of the sum of: (a) the participant's annual base salary as in effect at any time within one year prior to the commencement of a change in control period or, if higher, immediately prior to a circumstance constituting good reason, plus (b) the participant's annual incentive award, calculated using the average annual target opportunity derived under the annual incentive program for the two calendar years immediately preceding the calendar year in which termination occurs.

 Performance Units
 For outstanding performance units, participants would receive a number of shares of Entergy common stock equal to the greater of (1) the target number of performance units subject to the performance unit agreement or (2) the number of units that would vest under the performance unit agreement calculated based on Company performance through the participant's termination date, in either case pro-rated based on the portion of the performance period that occurs through the termination date.

 Equity Awards
 All unvested stock options and restricted stock units will vest immediately, and restrictions will lift on restricted shares, upon a Qualifying Termination pursuant to the terms of Entergy's equity plans.

 Retirement Benefits
 Benefits already accrued under the SERP, PEP, and CBEP, if any, will become fully vested.

 Welfare Benefits
 Participants who are not retirement-eligible would be eligible to receive Entergy-subsidized COBRA benefits for a period ranging from 12 to 18 months.

 * Cash severance payments are capped at 2.99 times the sum of (a) an executive's annual base salary in effect at any time within one year before commencement of the change in control period, or, if higher, immediately prior to a circumstance constituting Good Reason under the Continuity Plan in effect at any time within one year before commencement of the change in control period or, if higher, immediately prior to a circumstance constituting Good Reason under the Continuity Plan, plus (b) the higher of the executive's actual annual incentive payment under the annual incentive program for the year immediately preceding the calendar year in which termination occurs or the average of the executive's target annual incentive award for the two calendar years preceding the year in which termination occurs. Any cash severance payments to be paid under the Continuity Plan in excess of this cap will be forfeited by the participant.
 To protect shareholders and Entergy Corporation's business model, executives are required to comply with non-compete provisions (which generally run for two years but extends to three years if permissible under applicable law) and confidentiality provisions, as discussed above. If an executive discloses non-public data or information concerning Entergy Corporation or any of its subsidiaries or violates his or her non-compete provision, he or she will be required to repay any benefits previously received under the Continuity Plan.

 For purposes of the Continuity Plan, the following events are generally defined as:

 • Change in Control: (a) the purchase of 30% or more of either Entergy Corporation's common stock or the combined voting power of Entergy Corporation's voting securities; (b) the merger or consolidation of Entergy Corporation (unless its Board members constitute at least a majority of the board members of the surviving entity); (c) the liquidation, dissolution, or sale of all or substantially all of Entergy Corporation's assets; or (d) a change in the composition of Entergy Corporation's Board such that, during any two-year period, the individuals serving at the beginning of the period no longer constitute a majority of Entergy Corporation's Board at the end of the period.

 • Potential Change in Control: (a) Entergy Corporation or an affiliate enters into an agreement, the consummation of which would constitute a Change in Control; (b) the Entergy Corporation Board adopts resolutions determining that, for purposes of the Continuity Plan, a potential Change in Control has occurred; (c) a System Company or other person or entity publicly announces an intention to take actions that would constitute a Change in Control; or (d) any person or entity becomes the beneficial owner (directly or indirectly) of Entergy Corporation's outstanding shares of common stock constituting 20% or more of the voting power or value of the Entergy Corporation's outstanding common stock.

 • Cause: The participant's (a) willful and continuous failure to perform substantially his or her duties after written demand for performance; (b) engagement in conduct that is materially injurious to Entergy Corporation or any of its subsidiaries; (c) conviction or guilty or nolo contendere plea to a felony or other crime that materially and adversely affects the participant's ability to perform his or her duties or Entergy Corporation's reputation; (d) material violation of any agreement with Entergy Corporation or any of its subsidiaries; or (e) disclosure of any of Entergy Corporation's confidential information without authorization.

 • Good Reason: The participant's (a) nature or status of duties and responsibilities is substantially altered or reduced; (b) salary is reduced by 5% or more; (c) primary work location is relocated outside the continental United States; (d) compensation plans are discontinued without an equitable replacement; (e) benefits or number of vacation days are substantially reduced; or (f) employment is terminated by an Entergy employer for reasons other than in accordance with the Continuity Plan.

 Other Termination Events

 For termination events, other than in connection with a Change in Control, the executive officers, including the NEOs, generally will receive the benefits set forth below:

 Termination Event
 Compensation Element

 Severance
 Annual Incentive
 Restricted Stock(2)

 Performance Units

 Voluntary Resignation
 None
 Forfeited(1)

 Unvested options are forfeited. Vested options expire on the earlier of (i) 90 days from the last day of active employment and (ii) the option's normal expiration date.
 Forfeited(3)

 Termination for Cause
 None

 Retirement
 None
 Pro-rated based on number of days employed during the performance period
 Unvested stock options continue to vest following retirement, in accordance with the original vesting schedule and expire the earlier of (i) five years from the retirement date and (ii) the option's normal expiration date.
 Officers with a minimum of 12 months of participation are eligible for a pro-rated award based on actual performance and full months of service during the performance period

 Death/Disability
 None
 Pro-rated based on number of days employed during the performance period

 Unvested stock options vest on the termination date and expire on the earlier of (i) five years from the termination date and (ii) the option's normal expiration date
 Fully Vest
 Officers are eligible for pro-rated award based on actual performance and full months of service during the performance period

 (1)If an officer resigns after the completion of an annual incentive plan, he or she may receive, at Entergy's discretion, an annual incentive payment.
 (2)This column refers solely to restricted stock awards. Certain officers are occasionally granted restricted stock units for retention purposes, to offset forfeited compensation from a previous employer or for other limited purposes. The treatment of restricted stock units depends on the terms of the individual restricted stock unit agreement, which terms can vary. The standard off-cycle restricted stock unit agreement approved by the Talent and Compensation Committee provides that the units are forfeited if employment is terminated for any reason before the vesting date, except in the case of a termination other than for cause or voluntary termination for Good Reason during a Change in Control period. However, individual restricted stock unit agreements may provide for accelerated vesting in certain events, such as death or disability. Messrs. Brown, Fisackerly, May, and West each have outstanding restricted stock units, the treatment of which upon various events of termination is disclosed in connection with the table below.
 (3)If an officer resigns after the completion of a PUP performance period, he or she will receive a payout under the PUP based on the outcome of the performance period.

 Aggregate Termination Payments

 The tables below reflect the amount of compensation each of the NEOs would have received if his or her employment had been terminated as of December 31, 2023 under the various scenarios described above. For purposes of these tables, a stock price of $101.19 was used, which was the closing market price of Entergy Corporation stock on December 29, 2023, the last trading day of the year.

 Benefits and Payments Upon
 Termination

 Voluntary
 Resignation

 For
 Cause

 Termination for
 Good Reason or
 Not for Cause

 Retirement
 Disability
 Death
 Termination
 Related to a
 Control

 Marcus V. Brown(2)

 —
 —
 —
 —
 —
 —
 $4,111,030

 —
 —
 —
 $684,752
 $684,752
 $684,752
 $684,752

 —
 —
 —
 —
 $38,847
 $38,847
 $38,847

 —
 —
 —
 —
 $595,530
 $595,530
 $595,530

 —
 —
 —
 —
 —
 —
 —

 Unvested Restricted Stock Units(6)

 —
 —
 $1,257,387
 —
 $1,257,387
 $1,257,387
 $1,438,517

 Haley R. Fisackerly(1)

 —
 —
 —
 —
 —
 —
 $1,292,709

 —
 —
 —
 $193,576
 $193,576
 $193,576
 $193,576

 —
 —
 —
 —
 $21,817
 $21,817
 $21,817

 —
 —
 —
 —
 $172,833
 $172,833
 $172,833

 —
 —
 —
 —
 —
 —
 —

 Unvested Restricted Stock Units(7)

 —
 —
 —
 —
 —
 —
 $410,123

 Kimberly A. Fontan(2)

 —
 —
 —
 —
 —
 —
 $3,130,156

 —
 —
 —
 —
 $593,075
 $593,075
 $593,075

 —
 —
 —
 —
 $28,967
 $28,967
 $28,967

 —
 —
 —
 —
 $361,522
 $361,522
 $361,522

 Welfare Benefits(5)

 —
 —
 —
 —
 —
 —
 $33,129

 Laura R. Landreaux(2)

 —
 —
 —
 —
 —
 —
 $1,213,486

 —
 —
 —
 —
 $195,600
 $195,600
 $195,600

 —
 —
 —
 —
 $20,604
 $20,604
 $20,604

 —
 —
 —
 —
 $153,407
 $153,407
 $153,407

 Welfare Benefits(5)

 —
 —
 —
 —
 —
 —
 $33,129

 Benefits and Payments Upon
 Termination

 Voluntary
 Resignation

 For
 Cause

 Termination for
 Good Reason or
 Not for Cause

 Retirement
 Disability
 Death
 Termination
 Related to a
 Control

 Andrew S. Marsh(2)

 —
 —
 —
 —
 —
 —
 $6,660,225

 —
 —
 —
 —
 $2,601,696
 $2,601,696
 $2,601,696

 —
 —
 —
 —
 $155,323
 $155,323
 $155,323

 —
 —
 —
 —
 $1,666,722
 $1,666,722
 $1,666,722

 Welfare Benefits(5)

 —
 —
 —
 —
 —
 —
 $33,129

 Phillip R. May, Jr.(1)

 —
 —
 —
 —
 —
 —
 $1,454,698

 —
 —
 —
 $286,469
 $286,469
 $286,469
 $286,469

 —
 —
 —
 —
 $28,685
 $28,685
 $28,685

 —
 —
 —
 —
 $221,249
 $221,249
 $221,249

 —
 —
 —
 —
 —
 —
 —

 Unvested Restricted Stock Units(8)

 —
 —
 —
 —
 —
 —
 $410,123

 Deanna D. Rodriguez(1)

 —
 —
 —
 —
 —
 —
 $1,050,595

 —
 —
 —
 $139,238
 $139,238
 $139,238
 $139,238

 —
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 $144,585
 $144,585
 $144,585

 —
 —
 —
 —
 —
 —
 —

 Eliecer Viamontes(2)

 —
 —
 —
 —
 —
 —
 $1,077,886

 —
 —
 —
 —
 $173,743
 $173,743
 $173,743

 —
 —
 —
 —
 $23,046
 $23,046
 $23,046

 —
 —
 —
 —
 $138,979
 $138,979
 $138,979

 Welfare Benefits(5)

 —
 —
 —
 —
 —
 —
 $33,129

 Roderick K. West(1)

 —
 —
 —
 —
 —
 —
 $4,360,453

 —
 —
 —
 $955,032
 $955,032
 $955,032
 $955,032

 —
 —
 —
 —
 $142,321
 $142,321
 $142,321

 —
 —
 —
 —
 $785,888
 $785,888
 $785,888

 —
 —
 —
 —
 —
 —
 —

 Unvested Restricted Stock Units(9)

 —
 —
 —
 —
 —
 —
 $1,822,634

 (1)As of December 31, 2023, Mr. Brown, Mr. Fisackerly, Mr. May, Mr. West, and Ms. Rodriguez were retirement eligible and would retire rather than voluntarily resign, and in addition to the payments and benefits in the table, each also would be entitled to receive their vested pension benefits under the Entergy Retirement Plan and their benefit under the PEP or the SERP, to the extent applicable, the latter of which requires the prior written consent of the officer's Entergy employer to separate prior to age 65. As previously discussed, Ms. Rodriguez does not participate in the SERP. For a description of these benefits, see "2023 Pension Benefits."

 (2)See "2023 Pension Benefits" for a description of the pension benefits Ms. Fontan, Ms. Landreaux, Mr. Marsh, and Mr. Viamontes may receive upon the occurrence of certain termination events since they are not yet retirement eligible.

 (3)For purposes of the table, in the event of a qualifying termination related to a change in control, each NEO would receive a number of performance units for the 2022 – 2024 performance period and a number of performance units for the 2023 – 2025 performance period, calculated as follows:

 The greater of (1) the target number of performance units subject to the performance unit agreements or (2) the number of performance units that would vest under the performance unit agreements calculated based on Entergy Corporation's actual performance through the NEO's termination date, in either case pro-rated based on the portion of the performance periods that occurs through the termination date.

 For purposes of the table, the values of the performance unit awards for the performance periods for each NEO were calculated as follows, based on the assumption that the target number of performance units was the greater number:

 Mr. Brown's:

 2022 – 2024 PUP Performance Period: 4,318 (24/36x6,477) performance units at target, assuming a stock price of $101.19 = $436,938

 2023 – 2025 PUP Performance Period: 2,449 (12/36x7,345) performance units at target, assuming a stock price of $101.19 = $247,814

 Total: $684,752

 Mr. Fisackerly's:

 2022 – 2024 PUP Performance Period: 1,007 (24/36x1,510) performance units at target, assuming a stock price of $101.19 = $101,898

 2023 – 2025 PUP Performance Period: 906 (12/36x2,716) performance units at target, assuming a stock price of $101.19 = $91,678

 Total: $193,576

 Ms. Fontan's:

 2022 – 2024 PUP Performance Period: 3,535 (24/36x5,302)) performance units at target, assuming a stock price of $101.19 = $357,707

 2023 – 2025 PUP Performance Period: 2,326 (12/36x6,977) performance units at target, assuming a stock price of $101.19 = $235,368

 Total: $593,075

 Ms. Landreaux's:

 2022 – 2024 PUP Performance Period: 1,180 (24/36x1,769) performance units at target, assuming a stock price of $101.19 = $119,404

 2023 – 2025 PUP Performance Period: 753 (12/36x2,258) performance units at target, assuming a stock price of $101.19 = $76,196

 Total: $195,600

 Mr. Marsh's:

 2022 – 2024 PUP Performance Period: 15,412 (24/36x23,118) performance units at target, assuming a stock price of $101.19 = $1,559,540

 2023 – 2025 PUP Performance Period: 10,299 (12/36x30,895) performance units at target, assuming a stock price of $101.19 = $1,042,156

 Total: $2,601,696

 Mr. May's:

 2022 – 2024 PUP Performance Period: 1,914 (24/36x2,871) performance units at target, assuming a stock price of $101.19 = $193,678

 2023 – 2025 PUP Performance Period: 917 (12/36x2,751) performance units at target, assuming a stock price of $101.19 = $92,791

 Total: $286,469

 Ms. Rodriguez's:

 2022 – 2024 PUP Performance Period: 836 (24/36x1,254) performance units at target, assuming a stock price of $101.19 = $84,595

 2023 – 2025 PUP Performance Period: 540 (12/36x1,620) performance units at target, assuming a stock price of $101.19 = $54,643

 Total: $139,238

 Mr. Viamontes':

 2022 – 2024 PUP Performance Period: 1,052 (24/36x1,577) performance units at target, assuming a stock price of $101.19 = $106,452

 2023 – 2025 PUP Performance Period: 665 (12/36x1,994) performance units at target, assuming a stock price of $101.19 = $67,291

 Total: $173,743

 Mr. West's:

 2022 – 2024 PUP Performance Period: 6,350 (24/36x9,525) performance units at target, assuming a stock price of $101.19 = $642,557

 2023 – 2025 PUP Performance Period: 3,088 (12/36x9,264) performance units at target, assuming a stock price of $101.19 = $312,475

 Total: $955,032

 In the event of retirement, in the case of Mr. Brown, Mr. Fisackerly, Mr. May, Mr. West, or Ms. Rodriguez each would receive a prorated portion of the applicable Achievement Level of PUP Performance Units for each open

 PUP Performance Period, based on his or her full months of participation in such PUP Performance Period, provided he or she has completed a minimum of 12 months of full-time employment in the applicable PUP Performance Period. For purposes of calculating for the above table the number of performance units Mr. Brown, Mr. Fisackerly, Mr. May, Mr. West, and Ms. Rodriguez would receive in the event of retirement, it is assumed the achievement levels for the 2022 – 2024 PUP Performance Period and the 2023 – 2025 PUP Performance Period are at target. The resulting number of performance units and values are the same as calculated above for a qualifying termination related to a change in control.

 In the event of death or disability of any NEO, the NEO or his or her estate would receive a prorated portion of the applicable Achievement Level of PUP Performance Units for each open PUP Performance Period, based on his or her full months of participation in such PUP Performance Period, with no required minimum amount of full-time employment in the applicable PUP Performance Period.

 (4)Upon retirement, Mr. Brown, Mr. Fisackerly, Mr. May, Mr. West, and Ms. Rodriguez would be eligible for retiree medical and dental benefits, the same as all other retirees who are eligible for post-retirement benefits.

 (5)Pursuant to the Executive Continuity Plan, in the event of a termination related to a Change in Control, Ms. Fontan, Ms. Landreaux, Mr. Marsh, and Mr. Viamontes would be eligible to receive Entergy-subsidized COBRA benefits for 18 months.

 (6)Mr. Brown's 14,216 restricted stock units are scheduled to vest 100% on May 17, 2024. Pursuant to his restricted stock unit agreement, any unvested restricted stock units will vest in a pro rata portion in the event of his termination of employment due to Mr. Brown's total disability, death, or termination without cause (each, an Accelerated Vesting Event). The pro rata portion is determined by multiplying the total number of restricted stock units by a fraction, the numerator of which the number of days between May 17, 2021 and the Accelerated Vesting Event and the denominator of which is 1,096. In the event of a Change in Control, the unvested restricted stock units will fully vest upon Mr. Brown's Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. Brown is subject to certain restrictions on his ability to compete with Entergy and its affiliates during and for 12 months after his employment with Entergy, or to solicit its employees or customers during and for 24 months after his employment with Entergy. In addition, the restricted stock unit agreement limits Mr. Brown's ability to disparage Entergy and its affiliates. In the event of a breach of these restrictions, other than following certain constructive terminations of his employment, Mr. Brown must repay to Entergy any shares of Entergy stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares.

 (7)Mr. Fisackerly's 4,053 restricted stock units are scheduled to vest 100% on October 1, 2025. In the event of a Change in Control, the unvested restricted stock units will fully vest upon Mr. Fisackerly's Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. Fisackerly is subject to certain restrictions on his ability to compete with Entergy and its affiliates during and for 12 months after his employment with Entergy, or to solicit its employees or customers during and for 24 months after his employment with Entergy. In addition, the restricted stock unit agreement limits Mr. Fisackerly's ability to disparage Entergy and its affiliates. In the event of a breach of these restrictions, other than following certain constructive terminations of his employment, Mr. Fisackerly must repay to Entergy any shares of Entergy stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares.

 (8)Mr. May's 4,053 restricted stock units are scheduled to vest 100% on October 1, 2025. In the event of a Change in Control, the unvested restricted stock units will fully vest upon Mr. May's Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. May is subject to certain restrictions on his ability to compete with Entergy and its affiliates during and for 12 months after his employment with Entergy, or to solicit its employees or customers during and for 24 months after his employment with Entergy. In addition, the restricted stock unit agreement limits Mr. May's ability to disparage Entergy and its affiliates. In the event of a breach of these restrictions, other than following certain constructive

 terminations of his employment, Mr. May must repay to Entergy any shares of Entergy stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares.

 (9)Mr. West's 18,012 restricted stock units are scheduled to vest in three equal installments on June 1, 2024, June 1, 2025, and June 1, 2026. In the event of a Change in Control, the unvested restricted stock units will fully vest upon Mr. West's Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. West is subject to certain restrictions on his ability to compete with Entergy and its affiliates during and for 12 months after his employment with Entergy, or to solicit its employees or customers during and for 24 months after his employment with Entergy. In addition, the restricted stock unit agreement limits Mr. West's ability to disparage Entergy and its affiliates. In the event of a breach of these restrictions, other than following certain constructive terminations of his employment, Mr. West must repay to Entergy any shares of Entergy stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares.

 Pay Ratio

 As required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, the following disclosure is being provided about the relationship of the annual total compensation of the employees of each of the Utility operating companies to the annual total compensation of their respective Presidents and Chief Executive Officers. The pay ratio estimate for each of the Utility operating companies has been calculated in a manner consistent with Item 402(u) of Regulation S-K.

 Identification of Median Employee

 For each of the Utility operating companies, October 20, 2023 was selected as the date on which to determine the median employee. This date is different from the date used in the prior year; however, the methodology used to determine the date is consistent with that used in the prior year. Both dates correspond to the first day of the three month period prior to fiscal year-end for which information can be obtained about employees and all subsidiaries have the same number of pay cycles. To identify the median employee from each of the Utility operating companies' employee population base, all compensation included in Box 5 of Form W-2 was considered with all before-tax deductions added back to this compensation ("Box 5 Compensation"). For purposes of determining the median employee of each Utility operating company, Box 5 Compensation was selected as it is believed to be representative of the compensation received by the employees of each respective Utility operating company and is readily available. The calculation of annual total compensation of the median employee for each Utility operating company is the same calculation used to determine total compensation for purposes of the 2023 Summary Compensation Table with respect to each of the NEOs.

 Entergy Arkansas Ratio

 • The median of the annual total compensation of all of Entergy Arkansas's employees, other than Ms. Landreaux, was $132,296.
 • Ms. Landreaux's annual total compensation, as reported in the Total column of the 2023 Summary Compensation Table, was $1,377,425.
 • Based on this information, the ratio of the annual total compensation of Mrs. Landreaux to the median of the annual total compensation of all employees is estimated to be 10:1.

 Entergy Louisiana Ratio

 • The median of the annual total compensation of all of Entergy Louisiana's employees, other than Mr. May, was $143,608.
 • Mr. May's annual total compensation, as reported in the Total column of the 2023 Summary Compensation Table, was $1,509,582.
 • Based on this information, the ratio of the annual total compensation of Mr. May to the median of the annual total compensation of all employees is estimated to be 11:1.

 Entergy Mississippi Ratio

 • The median of the annual total compensation of all of Entergy Mississippi's employees, other than Mr. Fisackerly, was $146,022.
 • Mr. Fisackerly's annual total compensation, as reported in the Total column of the 2023 Summary Compensation Table, was $1,612,951.
 • Based on this information, the ratio of the annual total compensation of Mr. Fisackerly to the median of the annual total compensation of all employees is estimated to be 11:1.

 Entergy New Orleans Ratio

 • The median of the annual total compensation of all of Entergy New Orleans's employees, other than Ms. Rodriguez, was $115,593.
 • Ms. Rodriguez's annual total compensation, as reported in the Total column of the 2023 Summary Compensation Table, was $1,213,008.
 • Based on this information, the ratio of the annual total compensation of Ms. Rodriguez to the median of the annual total compensation of all employees is estimated to be 10:1.

 Entergy Texas Ratio

 • The median of the annual total compensation of all of Entergy Texas's employees, other than Mr. Viamontes, was $153,165.
 • Mr. Viamontes' annual total compensation, as reported in the Total column of the 2023 Summary Compensation Table, was $1,078,811.
 • Based on this information, the ratio of the annual total compensation of Mr. Viamontes to the median of the annual total compensation of all employees is estimated to be 7:1.

 Item 12. Security Ownership of Certain Beneficial Owners and Management

 Entergy Corporation owns 100% of the outstanding common stock of Entergy Texas and indirectly 100% of the outstanding common membership interests of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The information with respect to (i) the beneficial ownership of Entergy Corporation's directors and NEOs is included under the heading "Entergy Share Ownership - Directors and Executive Officers;" and (ii) persons known by Entergy Corporation to be beneficial owners of more than 5% of Entergy Corporation's outstanding common stock is included under the heading "Entergy Share Ownership - Beneficial Owners of More Than Five Percent of Entergy Common Stock" in the 2024 Entergy Proxy Statement, which information is incorporated herein by reference. The registrants know of no contractual arrangements that may, at a subsequent date, result in a change in control of any of the registrants.

 The following table sets forth the beneficial ownership of common stock of Entergy Corporation and stock-based units as of January 31, 2024 for the directors and NEOs of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. Unless otherwise noted, each person had sole voting and investment power over the number of shares of common stock and stock-based units of Entergy Corporation set forth across from his or her name.

 Name
 Shares (1)

 Options Exercisable Within 60 Days
 Stock Units (2)

 —

 Kimberly A. Fontan***
 —

 Laura R. Landreaux***
 9,028
 17,322
 —

 —

 —

 —

 All directors and executive officers as a group (8 persons)
 319,670
 622,834
 —

 —

 Kimberly A. Fontan***
 —

 —

 Phillip R. May, Jr.***
 24,299
 25,668

 —

 —

 All directors and executive officers as a group (8 persons)
 334,940
 631,180

 —

 Haley R. Fisackerly***
 8,672
 16,885
 —

 Kimberly A. Fontan***
 —

 —

 —

 —

 All directors and executive officers as a group (7 persons)
 301,277
 596,840
 —

 Name
 Shares (1)

 Options Exercisable Within 60 Days
 Stock Units (2)

 —

 Kimberly A. Fontan**
 —

 —

 —

 Deanna D. Rodriguez***
 8,974
 3,044
 —

 —

 All directors and executive officers as a group (7 persons)
 301,579
 582,999
 —

 —

 Kimberly A. Fontan***
 —

 —

 —

 Eliecer Viamontes***
 9,677
 7,836
 —

 —

 All directors and executive officers as a group (7 persons)
 302,281
 587,791
 —

 *
 Director of the respective company

 **
 NEO of the respective company

 ***
 Director and NEO of the respective company

 (1)The number of shares of Entergy Corporation common stock owned by each individual and by all non-employee directors and executive officers as a group does not exceed one percent of the outstanding shares of Entergy Corporation common stock. This column also includes shares of Entergy Corporation common stock held in the Entergy Savings Plan (401(k)) by Messrs. Brown, Fisackerly, Marsh, May, Viamontes, and West and Mses. Fontan and Rodriguez. For Mr. Viamontes, this column includes shares of Entergy Corporation common stock held by him indirectly through his spouse.
 (2)Represents the balances of phantom units each director or executive holds under the defined contribution restoration plan and the deferral provisions of Entergy Corporation's equity ownership plans. These units will be paid out in either Entergy Corporation common stock or cash equivalent to the value of one share of Entergy Corporation common stock per unit on the date of payout, including accrued dividends. The deferral period is determined by the individual and is at least two years from the award of the bonus.

 Equity Compensation Plan Information

 The following table summarizes the equity compensation plan information as of December 31, 2023. Information is included for equity compensation plans approved by the shareholders. There are no shares authorized for issuance under equity compensation plans not approved by the shareholders.

 Plan Category
 Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants, and Rights (a)
 Weighted-Average Exercise Price of Outstanding Options, Warrants, and Rights
 (b)(2)

 Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (excluding securities reflected in column (a))
(c)

 Equity compensation plans approved by security holders (1)

 2,898,708
 $97.66
 7,546,825

 Equity compensation plans not approved by security holders
 —
 —
 —

 Total
 2,898,708
 $97.66
 7,546,825

 (1)Includes the 2011 Equity Ownership Plan, the 2015 EOP, and the 2019 OIP (collectively, the "Plans"). The 2011 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 6, 2011 and only applies to awards granted between May 6, 2011 and May 7, 2015. The 2015 EOP was approved by Entergy Corporation shareholders on May 8, 2015 and only applies to awards granted between May 8, 2015 and May 3, 2019. The Entergy Corporation shareholders approved the 2019 OIP on May 3, 2019 and approved the issuance of 7,300,000 shares of Entergy Corporation common stock from the 2019 OIP for equity-based incentive awards. On May 5, 2023, the Entergy Corporation shareholders approved Amendment No. 1 to the 2019 OIP, which increased the aggregate number of shares available for equity-based incentive awards under the 2019 OIP by 4,900,000 shares of Entergy Corporation common stock, and extended the term of the 2019 OIP by approximately four years to January 27, 2033. The Plans are administered by the Talent and Compensation Committee of the Entergy Corporation Board of Directors (other than with respect to awards granted to non-employee directors, which awards are administered by the entire Board of Directors). Eligibility under the Plans is limited to the non-employee directors and to the officers and employees of an Entergy employer or an affiliate of Entergy Corporation. The Plans provide for the issuance of stock options, restricted stock, equity awards (units whose value is related to the value of shares of the common stock but do not represent actual shares of common stock), performance awards (performance shares or units valued by reference to shares of common stock or performance units valued by reference to financial measures or property other than common stock), restricted stock unit awards, and other stock-based awards.
 (2)The weighted-average exercise price reported in this column does not include outstanding performance awards.

 Item 13. Certain Relationships and Related Party Transactions and Director Independence

 The additional information required by this item will be set forth under Director Independence and Review and Approval of Related Party Transactions in the 2024 Entergy Proxy Statement, to be filed in connection with the Annual Meeting of Shareholders to be held May 3, 2024, which is incorporated herein by reference.

 Item 14. Principal Accountant Fees and Services (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

 Aggregate fees billed to Entergy Corporation (consolidated), Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy for the years ended December 31, 2023 and 2022 by Deloitte & Touche LLP (PCAOB ID No. 34) were as follows:

 2023
 2022

 Entergy Corporation (consolidated)

 $9,850,000
 $9,335,000

 2,235,668
 3,018,228

 12,085,668
 12,353,228

 —
 —

 All Other Fees (c)
 1,895
 1,895

 $12,087,563
 $12,355,123

 $1,221,014
 $1,215,943

 —
 —

 1,221,014
 1,215,943

 —
 —

 —
 —

 $1,221,014
 $1,215,943

 $2,172,029
 $2,136,886

 1,209,547
 1,472,751

 3,381,576
 3,609,637

 —
 —

 —
 —

 $3,381,576
 $3,609,637

 $1,246,014
 $1,025,943

 —
 —

 1,246,014
 1,025,943

 —
 —

 —
 —

 $1,246,014
 $1,025,943

 $1,121,014
 $1,110,943

 576,121
 785,477

 1,697,135
 1,896,420

 —
 —

 —
 —

 $1,697,135
 $1,896,420

 2023
 2022

 $1,296,014
 $1,410,943

 —

 1,296,014
 1,710,943

 —
 —

 —
 —

 $1,296,014
 $1,710,943

 $1,136,014
 $1,025,943

 —
 —

 1,136,014
 1,025,943

 —
 —

 —
 —

 $1,136,014
 $1,025,943

 (a)Audit Fees include fees for the audit of the registrant's annual financial statements and internal control over financial reporting, reviews of financial statements including in the registrant's quarterly reports, services that are normally provided in connection with statutory and regulatory filings or engagements, and services associated with securities filings, such as comfort letters and consents.
 (b)Audit-Related Fees includes fees for employee benefit plan audits, consultation on financial accounting and reporting, storm examination services in 2022, accounting due diligence services related to the gas business in 2023, agreed upon procedures for storm securitizations in 2023 and 2022, and other attestation services.
 (c)Includes the license fee for the accounting research tool.
 (d)100% of fees in 2023 and 2022 were pre-approved by the Entergy Corporation Audit Committee in accordance with the policy described below.

 Entergy Audit Committee Guidelines for Pre-approval of Independent Auditor Services

 The Audit Committee has adopted the following guidelines regarding the engagement of Entergy's independent auditor to perform services for Entergy:

 1.The independent auditor will provide the Audit Committee, for approval, an annual engagement letter outlining the scope of services proposed to be performed during the fiscal year, including audit services and other permissible non-audit services (e.g. audit-related services, tax services, and all other services).
 2.For other permissible services not included in the engagement letter, Entergy management will submit a description of the proposed service, including a budget estimate, to the Audit Committee for pre-approval. Management and the independent auditor must agree that the requested service is consistent with the SEC's rules on auditor independence prior to submission to the Audit Committee. The Audit Committee, at its discretion, will pre-approve permissible services and has established the following additional guidelines for permissible non-audit services provided by the independent auditor:
 aAggregate non-audit service fees are targeted at fifty percent or less of the approved audit service fee.
 b All other services should only be provided by the independent auditor if it is a highly qualified provider of that service or if the Audit Committee pre-approves the independent audit firm to provide the service.
 3.The Audit Committee will be informed quarterly as to the status of pre-approved services actually provided by the independent auditor.
 4.To ensure prompt handling of unexpected matters, the Audit Committee delegates to the Audit Committee Chair or its designee the authority to approve permissible services and fees. The Audit Committee Chair or designee will report action taken to the Audit Committee at the next scheduled Audit Committee meeting.

 5.The Vice President and General Auditor will be responsible for tracking all independent auditor fees and will report quarterly to the Audit Committee.

 Item 15. Exhibits and Financial Statement Schedules

 (a)1.
 Financial Statements and Independent Auditors' Reports for Entergy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are listed in the Table of Contents.

 (a)2.
 Financial Statement Schedules

 Reports of Independent Registered Public Accounting Firm (see page 565)

 Financial Statement Schedules are listed in the Index to Financial Statement Schedules (see page S-1)

 (a)3.
 Exhibits

 Exhibits for Entergy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are listed in the Exhibit Index (see page 541 and are incorporated by reference herein). Each management contract or compensatory plan or arrangement required to be filed as an exhibit hereto is identified as such by footnote in the Exhibit Index.

 Item 16. Form 10-K Summary (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

 None.

 EXHIBIT INDEX

 The following exhibits indicated by an asterisk preceding the exhibit number are filed herewith. The balance of the exhibits have previously been filed with the SEC as the exhibits and in the file numbers indicated and are incorporated herein by reference. The exhibits marked with a (+) are management contracts or compensatory plans or arrangements required to be filed herewith and required to be identified as such by Item 15 of Form 10-K.

 Some of the agreements included or incorporated by reference as exhibits to this Form 10-K contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties were made solely for the benefit of the other parties to the applicable agreement and (i) were not intended to be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate; (ii) may have been qualified in such agreement by disclosures that were made to the other party in connection with the negotiation of the applicable agreement; (iii) may apply contract standards of "materiality" that are different from the standard of "materiality" under the applicable securities laws; and (iv) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement.

 Entergy acknowledges that, notwithstanding the inclusion of the foregoing cautionary statements, it is responsible for considering whether additional specific disclosures of material information regarding material contractual provisions are required to make the statements in this Form 10-K not misleading.

 (2) Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession

 (a) 1 --
 Plan of Merger of Entergy Arkansas, Inc. and Entergy Arkansas Power, LLC (2.1 to Form 8-K12B filed December 3, 2018 in 1-10764).

 (b) 1 --
 Plan of Merger of Entergy Gulf States Power, LLC and Entergy Gulf States Louisiana, LLC (2.1 to Form 8-K12B filed October 1, 2015 in 1-32718).

 (b) 2 --
 Plan of Merger of Entergy Louisiana, LLC and Entergy Louisiana Power, LLC (2.2 to Form 8-K12B filed October 1, 2015 in 1-32718).

 (b) 3 --
 Plan of Merger of Entergy Gulf States Power, LLC and Entergy Louisiana Power, LLC (2.3 to Form 8-K12B filed October 1, 2015 in 1-32718).

 (c) 1 --
 Plan of Merger of Entergy Mississippi, Inc. and Entergy Mississippi Power and Light, LLC (2.1 to Form 8-K12B filed December 3, 2018 in 1-31508).

 (d) 1 --
 Plan of Merger of Entergy New Orleans, Inc. and Entergy New Orleans Power, LLC (2.1 to Form 8-K12B filed December 1, 2017 in 1-35747).

 (3) Articles of Incorporation and Bylaws

 (a) 1--
 Restated Certificate of Incorporation of Entergy Corporation, dated July 28, 2023 (3(b) to Form 10-Q for the quarter ended June 30, 2023 in 1-11299).

 (a) 2--
 Amended and Restated Bylaws of Entergy Corporation, effective as of December 8, 2023 (3.1 to Form 8-K filed December 8, 2023 in 1-11299).

 (b) 1 --
 Amended and Restated Articles of Incorporation of System Energy effective April 28, 1989 (3(b)1 to Form 10-K for the year ended December 31, 2017 in 1-9067).

 (b) 2 --
 By-Laws of System Energy effective July 6, 1998 (3(f) to Form 10-Q for the quarter ended June 30, 1998 in 1-9067).

 (c) 1 --
 Amended and Restated Certificate of Formation of Entergy Arkansas effective December 1, 2018 (3.3 to Form 8-K12B filed December 3, 2018 in 1-10764).

 (c) 2 --
 Amended and Restated Company Agreement of Entergy Arkansas effective December 1, 2018 (3.4 to Form 8-K12B filed December 3, 2018 in 1-10764).

 (d) 1 --
 Certificate of Formation of Entergy Louisiana Power, LLC (including Certificate of Amendment to Certificate of Formation to change the company name to Entergy Louisiana, LLC) effective July 7, 2015 (3.3 to Form 8-K12B filed October 1, 2015 in 1-32718).

 (d) 2 --
 Company Agreement of Entergy Louisiana Power, LLC (including First Amendment to Company Agreement to change the company name to Entergy Louisiana, LLC) effective July 7, 2015 (3.4 to Form 8-K12B filed October 1, 2015 in 1-32718).

 (e) 1 --
 Amended and Restated Certificate of Formation of Entergy Mississippi effective December 1, 2018 (3(e)1 to Form 10-K for the year ended December 31, 2018 in 1-31508).

 (e) 2 --
 Amended and Restated Company Agreement of Entergy Mississippi effective December 1, 2018 (3.4 to Form 8-K12B filed December 3, 2018 in 1-31508).

 (f) 1 --
 Composite Certificate of Formation of Entergy New Orleans effective December 1, 2017 (3.3 to Form 8-K12B filed December 1, 2017 in 1-35747).

 (f) 2 --
 Composite Company Agreement of Entergy New Orleans effective December 1, 2017 (3.4 to Form 8-K12B filed December 1, 2017 in 1-35747).

 (g) 1 --
 Amended and Restated Certificate of Formation of Entergy Texas effective August 21, 2019 (3.1 to Form 8-K filed August 21, 2019 in 1-34360), as amended by Statement of Resolution Establishing the 5.375% Series A Preferred Stock, Cumulative, No Par Value (Liquidation Value $25 Per Share) of Entergy Texas (3.3 to Form 8-A filed September 4, 2019 in 1-34360) and by Statement of Resolution Establishing the 5.10% Series B Preferred Stock, Cumulative, No Par Value (Liquidation Value $25 Per Share) of Entergy Texas (3.1 to Form 8-K filed November 9, 2021 in 1-34360).

 (g) 2 --
 Amended and Restated Bylaws of Entergy Texas effective August 19, 2019 (3.2 to Form 8-K filed August 21, 2019 in 1-34360).

 (4)Instruments Defining Rights of Security Holders, Including Indentures

 (a) 1 --
 See (4)(b) through (4)(g) below for instruments defining the rights of security holders of System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas.

 (a) 2 --
 Indenture (For Unsecured Debt Securities), dated as of September 1, 2010, between Entergy Corporation and Wells Fargo Bank, National Association (4.01 to Form 8-K filed September 16, 2010 in 1-11299).

 (a) 3 --
 Officer's Certificate for Entergy Corporation relating to 2.95% Senior Notes due September 1, 2026 (4.02 to Form 8-K filed August 19, 2016 in 1-11299).

 (a) 4 --
 Officer's Certificate for Entergy Corporation relating to 4.50% Senior Note due December 16, 2028 (4(a)7 to Form 10-K for the year ended December 31, 2013 in 1-11299).

 (a) 5 --
 Officer's Certificate for Entergy Corporation relating to 2.80% Senior Notes due June 15, 2030 (4.02(a) to Form 8-K filed May 19, 2020 in 1-11299).

 (a) 6 --
 Officer's Certificate for Entergy Corporation relating to 3.75% Senior Notes due June 15, 2050 (4.02(b) to Form 8-K filed May 19, 2020 in 1-11299).

 (a) 7 --
 Officer's Certificate for Entergy Corporation relating to 0.90% Senior Notes due September 15, 2025 (4.02 to Form 8-K filed August 26, 2020 in 1-11299).

 (a) 8 --
 Officer's Certificate for Entergy Corporation relating to 1.90% Senior Notes due June 15, 2028 (4.02(a) to Form 8-K filed March 5, 2021 in 1-11299).

 (a) 9 --
 Officer's Certificate for Entergy Corporation relating to 2.40% Senior Notes due June 15, 2031 (4.02(b) to Form 8-K filed March 5, 2021 in 1-11299).

 (a) 10 --
 Third Amended and Restated Credit Agreement dated as of June 3, 2021, among Entergy Corporation, as Borrower, the banks and other financial institutions listed on the signatures pages thereof, as Lenders, Citibank, N.A., as Administrative Agent and LC Issuing Bank, MUFG Bank, Ltd., as LC Issuing Bank, and the other LC Issuing Banks from time to time parties thereto (4.1 to Form 8-K filed June 3, 2021 in 1-11299).

 (a) 11 --
 First Extension and Amendment Agreement, dated as of June 3, 2022, amending the Third Amended and Restated Credit Agreement, dated as of June 3, 2021, among Entergy Corporation, as Borrower, the Lenders and LC Issuing Banks parties thereto and Citibank, N.A., as Administrative Agent, as set forth in Exhibit A to the First Extension and Amendment Agreement (4(c) to Form 10-Q for the quarter ended June 30, 2022 in 1-11299).

 (a) 12 --
 First Amendment to Credit Agreement, dated as of June 29, 2023, by and among Entergy Corporation, as Borrower, the Lender parties thereto, and Citibank, N.A., as Administrative Agent (4(d) to Form 10-Q for the quarter ended June 30, 2023 in 1-11299).

 (a) 13 --
 Second Extension to Credit Agreement, dated as of June 29, 2023, by and among Entergy Corporation, as Borrower, the Lender parties thereto, each LC Issuing Bank, and Citibank, N.A., as Administrative Agent (4(e) to Form 10-Q for the quarter ended June 30, 2023 in 1-11299).

 (a) 14 --
 Description of Entergy Corporation's securities registered under Section 12 of the Securities Exchange Act of 1934 (4(a)12 to Form 10-K for the year ended December 31, 2021 in 1-11299).

 (b) 1 --
 Mortgage and Deed of Trust, dated as of June 15, 1977, as amended and restated by the following Supplemental Indenture: (4.42 to Form 8-K filed September 25, 2012 in 1-9067 (Twenty-fourth)).

 (b) 2 --
 Officer's Certificate No. 1-B-1 for System Energy relating to First Mortgage Bonds, 2.14% Series due December 9, 2025 (4.58 to Form 8-K filed December 9, 2020 in 1-09067).

 (b) 3 --
 Officer's Certificate No. 2-B-2 for System Energy relating to First Mortgage Bonds, MBFC Series due 2044 (4(a) to Form 8-K filed June 15, 2021 in 1-09067).

 (b) 4 --
 Officer's Certificate No. 4-B-4 for System Energy relating to First Mortgage Bonds, 6.00% Series due April 15, 2028 (4.75 to Form 8-K filed March 14, 2023 in 1-09067).

 (b) 5 --
 Fuel Lease, dated as of February 24, 1989, between River Fuel Funding Company #3, Inc. and System Energy (4(b)3 to Form 10-K for the year ended December 31, 2017 in 1-9067).

 (b) 6 --
 Trust Indenture, dated as of June 1, 2021, between the Mississippi Business Finance Corporation and The Bank of New York Mellon, as Indenture Trustee, authorizing Revenue Refunding Bonds (System Energy Resources, Inc. Project) Series 2021 (4(c) to Form 8-K filed June 15, 2021 in 1-09067).

 (b) 7 --
 Loan Agreement, dated as of June 1, 2021, between the Mississippi Business Finance Corporation and System Energy relating to Revenue Refunding Bonds (System Energy Resources, Inc. Project) Series 2021 (4(d) to Form 8-K filed June 15, 2021 in 1-09067).

 (c) 1 --
 Mortgage and Deed of Trust, dated as of October 1, 1944, as amended by the following Supplemental Indentures: (7(d) in 2-5463 (Mortgage); 7(b) in 2-7121 (First); 4(a)-7 in 2-10261 (Seventh); 2(b)-10 in 2-15767 (Tenth); 2(c) in 2-28869 (Sixteenth); 2(c) in 2-35107 (Eighteenth); 2(d) in 2-36646 (Nineteenth); 2(c) in 2-39253 (Twentieth); 4(c)1 to Form 10-K for the year ended December 31, 2017 in 1-10764 (Thirtieth); 4(c)1 to Form 10-K for the year ended December 31, 2017 in 1-10764 (Thirty-first); 4(c)1 to Form 10-K for the year ended December 31, 2017 in 1-10764 (Thirty-ninth); 4(c)1 to Form 10-K for the year ended December 31, 2017 in 1-10764 (Forty-first); 4(d)(2) in 33-54298 (Forty-sixth); C-2 to Form U5S for the year ended December 31,1995 (Fifty-third); 4(c)1 to Form 10-K for the year ended December 31, 2008 in 1-10764 (Sixty-eighth); 4.06 to Form 8-K filed October 8, 2010 in 1-10764 (Sixty-ninth); 4.06 to Form 8-K filed December 13, 2012 in 1-10764 (Seventy-first); 4(e) to Form 8-K filed January 9, 2013 in 1-10764 (Seventy-second); 4.05 to Form 8-K filed March 14, 2014 in 1-10764 (Seventy-sixth); 4.05 to Form 8-K filed December 9, 2014 in 1-10764 (Seventy-seventh); 4.05 to Form 8-K filed January 8, 2016 in 1-10764 (Seventy-eighth); 4.05 to Form 8-K filed August 16, 2016 in 1-10764 (Seventy-ninth); 4(a) to Form 10-Q for the quarter ended September 30, 2018 (Eightieth); 4.1 to Form 8-K12B filed December 3, 2018 in 1-10764 (Eighty-first); 4.39 to Form 8-K filed March 19, 2019 in 1-10764 (Eighty-second); 4.49 to Form 8-K filed September 11, 2020 in 1-10764 (Eighty-third); 4.49 to Form 8-K filed March 30, 2021 in 1-10764 (Eighty-fourth); 4.66 to Form 8-K filed January 6, 2023 in 1-1-764 (Eighty-fifth); and 4.66 to Form 8-K filed August 17, 2023 in 1-10764 (Eighty-sixth)).

 (c) 2 --
 Third Amended and Restated Credit Agreement dated as of June 3, 2021, among Entergy Arkansas, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Citibank, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., as LC Issuing Bank, and the other LC Issuing Banks from time to time parties thereto (4.2 to Form 8-K filed June 3, 2021 in 1-10764).

 (c) 3 --
 First Extension and Amendment Agreement, dated as of June 3, 2022, amending the Third Amended and Restated Credit Agreement, dated as of June 3, 2021, among Entergy Arkansas, as Borrower, the Lenders and LC Issuing Banks parties thereto and Citibank, N.A., as Administrative Agent, as set forth in Exhibit A to the First Extension and Amendment Agreement (4(d) to Form 10-Q for the quarter ended June 30, 2022 in 1-10764).

 (c) 4 --
 Second Extension to Credit Agreement, dated as of June 29, 2023, by and among Entergy Arkansas, as Borrower, the Lender parties thereto, each LC Issuing Bank, and Citibank, N.A., as Administrative Agent (4(f) to Form 10-Q for the quarter ended June 30, 2023 in 1-10764).

 (c) 5 --
 Fuel Lease, dated as of December 22, 1988, between River Fuel Trust #1 and Entergy Arkansas (4(c)9 to Form 10-K for the year ended December 31, 2017 in 1-10764).

 *(c) 6 --
 Description of Entergy Arkansas's securities registered under Section 12 of the Securities Exchange Act of 1934.

 (d) 1 --
 Mortgage and Deed of Trust, dated as of April 1, 1944, as amended by the following Supplemental Indentures: (7(d) in 2-5317 (Mortgage); 7(b) in 2-7408 (First); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Sixth); 2(c) in 2-34659 (Twelfth); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Thirteenth); 2(b)-2 in 2-38378 (Fourteenth); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Twenty-first); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Twenty-fifth); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Twenty-ninth); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Forty-second); A-2(a) to Rule 24 Certificate filed April 4, 1996 in 70-8487 (Fifty-first); B-4(i) to Rule 24 Certificate filed January 10, 2006 in 70-10324 (Sixty-third); B-4(ii) to Rule 24 Certificate filed January 10, 2006 in 70-10324 (Sixty-fourth); 4(a) to Form 10-Q for the quarter ended September 30, 2008 in 1-32718 (Sixty-fifth); 4(e)1 to Form 10-K for the year ended December 31, 2009 in 1-132718 (Sixty-sixth); 4.08 to Form 8-K filed September 24, 2010 in 1-32718 (Sixty-eighth); 4(a) to Form 10-Q for the quarter ended June 30, 2011 in 1-32718 (Seventy-second); 4.08 to Form 8-K filed August 23, 2013 in 1-32718 (Seventy-eighth); 4.08 to Form 8-K filed June 24, 2014 in 1-32718 (Seventy-ninth); 4.08 to Form 8-K filed July 1, 2014 in 1-32718 (Eightieth); 4.08 to Form 8-K filed November 21, 2014 (Eighty-first); 4.1 to Form 8-K12B filed October 1, 2015 (Eighty-second); 4.33 to Form 8-K filed March 24, 2016 in 1-32718 (Eighty-fourth); 4.33 to Form 8-K filed August 17, 2016 in 1-32718 (Eighty-sixth); 4.43 to Form 8-K filed October 4, 2016 in 1-32718 (Eighty-seventh); 4.43 to Form 8-K filed May 23, 2017 in 1-32718 (Eighty-eighth); 4.43 to Form 8 K filed March 23, 2018 in 1-32718 (Eighty-ninth); 4.43 to Form 8-K filed August 14, 2018 in 1-32718 (Ninetieth); 4.43 to Form 8-K filed March 12, 2019 in 1-32718 (Ninety-first); 4.53 to Form 8-K filed March 6, 2020 in 1-32718 (Ninety-second); 4.53(b) to Form 8-K filed November 13, 2020 in 1-32718 (Ninety-third); 4.53 to Form 8-K filed March 10, 2021 in 1-32718 (Ninety-fifth); 4.53 to Form 8-K filed October 1, 2021 in 1-32718 (Ninety-sixth); and 4.70 to Form 8-K filed August 24, 2022 in 1-32718 (Ninety-seventh)).

 (d) 2 --
 Third Amended and Restated Credit Agreement dated as of June 3, 2021, among Entergy Louisiana, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Citibank, N.A., as Administrative Agent, Wells Fargo Bank, National Association and BNP Paribas, as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.3 to Form 8-K filed June 3, 2021 in 1-32718).

 (d) 3 --
 First Extension and Amendment Agreement, dated as of June 3, 2022, amending the Third Amended and Restated Credit Agreement, dated as of June 3, 2021, among Entergy Louisiana, as Borrower, the Lenders and LC Issuing Banks parties thereto and Citibank, N.A., as Administrative Agent, as set forth in Exhibit A to the First Extension and Amendment Agreement (4(e) to Form 10-Q for the quarter ended June 30, 2022 in 1-32718).

 (d) 4 --
 Second Extension to Credit Agreement, dated as of June 29, 2023, by and among Entergy Louisiana, as Borrower, the Lender parties thereto, each LC Issuing Bank, and Citibank, N.A., as Administrative Agent (4(g) to Form 10-Q for the quarter ended June 20, 2023 in 1-32718).

 (d) 5 --
 Fuel Lease, dated as of January 31, 1989, between River Fuel Company #2, Inc., and Entergy Louisiana (4(d)10 to Form 10-K for the year ended December 31, 2017 in 1-32718).

 (d) 6 --
 Nuclear Fuel Lease Agreement between Entergy Gulf States, Inc. and River Bend Fuel Services, Inc. to lease the fuel for River Bend Unit 1, dated February 7, 1989 (4(d)11 to Form 10-K for the year ended December 31, 2017 in 1-32718).

 (d) 7 --
 Exhibit A to Trust Indenture dated as of February 7, 1989 between River Bend Fuel Services, Inc. and U.S. Bank National Association (as successor Trustee) (4(d)12 to Form 10-K for the year ended December 31, 2017 in 1-32718).

 (d) 8 --
 Loan Agreement, dated as of April 1, 2021, between the Louisiana Local Government Environmental Facilities and Community Development Authority and Entergy Louisiana relating to Revenue Refunding Bonds (Entergy Louisiana, LLC Project) Series 2021A (4(c) to Form 8-K filed April 1, 2021 in 1-32718).

 (d) 9 --
 Trust Indenture, dated as of April 1, 2021, between the Louisiana Local Government Environmental Facilities and Community Development Authority and The Bank of New York Mellon authorizing Revenue Refunding Bonds (Entergy Louisiana, LLC Project) Series 2021A (4(d) to Form 8-K filed April 1, 2021 in 1-32718).

 (d) 10 --
 Loan Agreement, dated as of April 1, 2021, between the Louisiana Local Government Environmental Facilities and Community Development Authority and Entergy Louisiana relating to Revenue Refunding Bonds (Entergy Louisiana, LLC Project) Series 2021B (4(e) to Form 8-K filed April 1, 2021 in 1-32718).

 (d) 11 --
 Trust Indenture, dated as of April 1, 2021, between the Louisiana Local Government Environmental Facilities and Community Development Authority and The Bank of New York Mellon authorizing Revenue Refunding Bonds (Entergy Louisiana, LLC Project) Series 2021B (4(f) to Form 8-K filed April 1, 2021 in 1-32718).

 (d) 12 --
 Indenture of Mortgage, dated September 1, 1926, as amended by the following Supplemental Indentures: (7-A-9 in Registration No. 2-6893 (Seventh); 4(d)15 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Eighteenth); 2-A-8 in Registration No. 2-66612 (Thirty-eighth); 4(b) to Form 10-Q for the quarter ended March 31,1999 in 1-27031 (Fifty-eighth); 4(a) to Form 10-Q for the quarter ended September 30, 2009 in 0-20371 (Seventy-seventh); 4.07 to Form 8-K filed July 1, 2014 in 0-20371 (Eighty-first); 4.2 to Form 8-K12B filed October 1, 2015 in 1-32718 (Eighty-second); 4.3 to Form 8-K12B filed October 1, 2015 in 1-32718 (Eighty-third); 4.42 to Form 8-K filed March 24, 2016 in 1-32718 (Eighty-fourth); 4.42 to Form 8-K filed May 19, 2016 in 1-32718 (Eighty-fifth); 4.42 to Form 8-K filed August 17, 2016 in 1-32718 (Eighty-sixth); 4.42 to Form 8-K filed October 4, 2016 in 1-32718 (Eighty-seventh); 4.42 to Form 8-K filed May 23, 2017 in 1-32718 (Eighty-eighth); 4.42 to Form 8-K filed March 23, 2018 in 1-32718 (Eighty-ninth); 4.42 to Form 8-K filed August 14, 2018 in 1-32718 (Ninetieth); 4.42 to Form 8-K filed March 12, 2019 in 1-32718 (Ninety-first); 4.52 to Form 8-K filed March 6, 2020 in 1-32718 (Ninety-second); 4.52(b) to Form 8-K filed November 13, 2020 in 1-32718 (Ninety-third); 4.52 to Form 8-K filed March 10, 2021 in 1-32718 (Ninety-fourth); 4.52 to Form 8-K filed October 1, 2021 in 1-32718 (Ninety-fifth); and 4.69 to Form 8-K filed August 24, 2022 in 1-32718 (Ninety-sixth)).

 (d) 13 --
 Agreement of Resignation, Appointment and Acceptance, dated as of October 3, 2007, among Entergy Gulf States, Inc., JPMorgan Chase Bank, National Association, as resigning trustee, and The Bank of New York, as successor trustee (4(a) to Form 10-Q for the quarter ended September 30, 2007 in 1-27031).

 (d) 14 --
 Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015, as amended by the following Supplemental Indentures: (4.38 in Registration No. 333-190911-07 (Mortgage); 4.40 to Form 8-K filed March 24, 2016 in 1-32718 (Second); 4(h) to Form 10-Q for the quarter ended March 31, 2016 in 1-32718 (Fourth); 4.40 to Form 8-K filed May 19, 2016 in 1-32718 (Fifth); 4.40 to Form 8-K filed August 17, 2016 in 1-32718 (Sixth); 4.41 to Form 8-K filed October 4, 2016 in 1-32718 (Seventh); 4.41 to Form 8-K filed May 23, 2017 in 1-32718 (Eighth); 4.41 to Form 8-K filed March 23, 2018 in 1-32718 (Ninth); 4.41 to Form 8-K filed August 14, 2018 in 1-32718 (Tenth); 4.41 to Form 8-K filed March 12, 2019 in 1-32718 (Eleventh); 4.51 to Form 8-K filed March 6, 2020 in 1-32718 (Twelfth); 4.51(b) to Form 8-K filed November 13, 2020 in 1-32718 (Thirteenth); 4.51 to Form 8-K filed March 10, 2021 in 1-32718 (Fifteenth); 4(b) to Form 8-K filed April 1, 2021 in 1-32718 (Sixteenth); 4.51 to Form 8-K filed October 1, 2021 in 1-32718 (Seventeenth); and 4.68 to Form 8-K filed August 24, 2022 in 1-32718 (Eighteenth)).

 (d) 15 --
 Officer's Certificate No. 2-B-2, dated March 17, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.39 to Form 8-K filed March 24, 2016 in 1-32718).

 (d) 16 --
 Officer's Certificate No. 4-B-4, dated May 16, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.39 to Form 8-K filed May 19, 2016 in 1-32718).

 (d) 17 --
 Officer's Certificate No. 6-B-5, dated August 10, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.39 to Form 8-K filed August 17, 2016 in 1-32718).

 (d) 18 --
 Officer's Certificate No. 7-B-6, dated September 28, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.40 to Form 8-K filed October 4, 2016 in 1-32718).

 (d) 19 --
 Officer's Certificate No. 8-B-7, dated May 17, 2017, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.40 to Form 8-K filed May 23, 2017 in 1-32718).

 (d) 20 --
 Officer's Certificate No. 10-B-8, dated March 20, 2018, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.40 to Form 8-K filed March 23, 2018 in 1-32718).

 (d) 21 --
 Officer's Certificate No. 12-B-9, dated August 8, 2018, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.40 to Form 8-K filed August 14, 2018 in 1-32718).

 (d) 22 --
 Officer's Certificate No. 14-B-10, dated March 6, 2019, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.40 to Form 8-K filed March 12, 2019 in 1-32718).

 (d) 23 --
 Officer's Certificate No. 16-B-11, dated March 3, 2020, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.50 to Form 8-K filed March 6, 2020 in 1-32718).

 (d) 25 --
 Officer's Certificate No. 19-B-13, dated November 9, 2020, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.50(b) to Form 8-K filed November 13, 2020 in 1-32718).

 (d) 26 --
 Officer's Certificate No. 21-B-15, dated March 4, 2021, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.50(a) to Form 8-K filed March 10, 2021 in 1-32718).

 (d) 27 --
 Officer's Certificate No. 21-B-16, dated March 4, 2021, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.50(b) to Form 8-K filed March 10, 2021 in 1-32718).

 (d) 28 --
 Officer's Certificate No. 22-B-17, dated March 23, 2021, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4(a) to Form 8-K filed April 1, 2021 in 1-32718).

 (d) 29 --
 Officer's Certificate No. 24-B-18, dated September 28, 2021, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.50 to Form 8-K filed October 1, 2021 in 1-32718).

 (d) 30 --

 Officer's Certificate No. 25-B-19, dated August 18, 2022, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015, establishing the terms of Entergy Louisiana's Collateral Trust Mortgage Bonds, 4.75% Series (4.67 to Form 8-K filed August 24, 2022 in 1-32718).

 *(d) 31 --
 Description of Entergy Louisiana's securities registered under Section 12 of the Securities Exchange Act of 1934.

 (e) 1 --
 Mortgage and Deed of Trust, dated as of February 1, 1988, as amended by the following Supplemental Indentures: (4(e)1 to Form 10-K for the year ended December 31, 2017 in 1-31508 (Mortgage); 4(e)1 to Form 10-K for the year ended December 31, 2017 in 1-31508 (Sixth); A-2(c) to Rule 24 Certificate filed May 14, 1999 in 70-8719 (Thirteenth); 4(b) to Form 10-Q for the quarter ended June 30, 2009 in 1-31508 (Twenty-sixth); 4.38 to Form 8-K filed December 11, 2012 in 1-31508 (Thirtieth); 4.05 to Form 8-K filed March 21, 2014 in 1-31508 (Thirty-first); 4.05 to Form 8-K filed May 13, 2016 in 1-31508 (Thirty-second); 4.16 to Form 8-K filed September 15, 2016 in 1-31508 (Thirty-third); 4.16 to Form 8-K filed November 14, 2017 in 1-31508 (Thirty-fourth); 4.1 to Form 8-K filed November 21, 2018 in 1-31508 (Thirty-fifth); 4.1 to Form 8-K12B filed December 3, 2018 in 1-31508 (Thirty-sixth); 4(a) to Form 8-K filed December 12, 2018 in 1-31508 (Thirty-seventh); 4.46 to Form 8-K filed June 5, 2019 in 1-31508 (Thirty-eighth); 4.56 to Form 8-K filed May 22, 2020 in 1-31508 (Thirty-ninth); 4.56 to Form 8-K filed November 16, 2021 in 1-31508 (Fortieth); 4.73 to Form 8-K filed May 12, 2023 in 1-31508 (Forty-first)).

 (e) 2 --
 Credit Agreement dated as of April 14, 2022, among Entergy Mississippi, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, and Citibank, N.A., as Administrative Agent (4.1 to Form 8-K filed April 14, 2022 in 1-31508).

 (e) 3 --
 Extension to Credit Agreement, dated as of June 29, 2023, by and among Entergy Mississippi, as Borrower, the Lender parties thereto, and Citibank, N.A., as Administrative Agent (4(h) to Form 10-Q for the quarter ended June 30, 2023 in 1-31508).

 (e) 4 --
 Term Loan Credit Agreement, dated as of June 29, 2022, among Entergy Mississippi, as Borrower, the Lenders party thereto, and The Bank of Nova Scotia, as Administrative Agent (Exhibit 4.1 to Form 8-K filed July 5, 2022 in 1-31508).

 *(e) 5 --
 Description of Entergy Mississippi's securities registered under Section 12 of the Securities Exchange Act of 1934.

 (f) 1 --
 Mortgage and Deed of Trust, dated as of May 1, 1987, as amended by the following Supplemental Indentures: (4(f)1 to Form 10-K for the year ended December 31, 2017 in 1-35747 (Mortgage); 4(f)1 to Form 10-K for the year ended December 31, 2017 in 1-35747 (Third); 4(b) to Form 10-Q for the quarter ended June 30, 1998 in 0-5807 (Seventh); 4.02 to Form 8-K filed November 23, 2010 in 0-5807 (Fifteenth); 4.02 to Form 8-K filed November 29, 2012 in 1-35747 (Sixteenth); 4.02 to Form 8-K filed June 21, 2013 in 1-35747 (Seventeenth); 4(m) to Form 10-Q for the quarter ended March 31, 2016 in 1-35747 (Eighteenth); 4.02 to Form 8-K filed March 22, 2016 in 1-35747 (Nineteenth); 4.02 to Form 8-K filed May 24, 2016 in 1-35747 (Twentieth); 4.1 to Form 8-K12B filed December 1, 2017 in 1-35747 (Twenty-first); 4(a) to Form 8-K filed September 27, 2018 in 1-35747 (Twenty-second); 4(a) to Form 8-K filed March 26, 2020 in 1-35747 (Twenty-third); and 4(a) to Form 8-K filed November 19, 2021 in 1-35747 (Twenty-fourth)).

 (f) 2 --
 Third Amended and Restated Credit Agreement dated as of June 22, 2021, among Entergy New Orleans, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Bank of America, N.A., as Administrative Agent and LC Issuing Bank, and the other LC Issuing Banks from time to time parties thereto (4 to Form 8-K filed June 22, 2021 in 1-35747).

 (f) 3 --
 Early Opt-In and Conforming Changes Amendment, dated as of June 27, 2023, by and between Entergy New Orleans, as Borrower, and Bank of America, N.A. as Administrative Agent and LC Issuing Bank (4(c) to Form 10-Q for the quarter ended June 30, 2023 in 1-35747).

 (f) 4 --
 First Amendment to Credit Agreement, dated as of May 31, 2023, by and among Entergy New Orleans, as Borrower, the Lenders party thereto, and Bank of America, N.A., as Administrative Agent (4(a) to Form 8-K filed June 1, 2023 in 1-35747).

 *(f) 5 --
 Description of Entergy New Orleans's securities registered under Section 12 of the Securities Exchange Act of 1934.

 (g) 1 --
 Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee, as amended by the following Supplemental Indenture: (4(h)2 to Form 10-K for the year ended December 31, 2008 in 0-53134 (Indenture) and 4.61 to Form 8-K filed September 20, 2019 in 1-34360 (First)).

 (g) 2 --
 Officer's Certificate No. 8-B-6 dated May 18, 2015, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4.40 to Form 8-K filed May 21, 2015 in 1-34360).

 (g) 3 --
 Officer's Certificate No. 10-B-8 dated November 14, 2017, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4.48 to Form 8-K filed November 17, 2017 in 1-34360).

 (g) 4 --
 Officer's Certificate No. 12-B-9 dated January 3, 2019, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4.47(a) to Form 8-K filed January 8, 2019 in 1-34360).

 (g) 5 --
 Officer's Certificate No. 12-B-10 dated January 3, 2019, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4.47(b) to Form 8-K filed January 8, 2019 in 1-34360).

 (g) 6 --
 Officer's Certificate No. 13-B-11 dated September 16, 2019, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4.57 to Form 8-K filed September 20, 2019 in 1-34360).

 (g) 7 --
 Officer's Certificate No. 16-B-13 dated September 28, 2020, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4.57 to Form 8-K filed October 1, 2020 in 1-34360).

 (g) 8 --
 Officer's Certificate No. 18-B-14 dated August 11, 2021, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4.57 to Form 8-K filed August 17, 2021 in 1-34360).

 (g) 9 --
 Officer's Certificate No. 20-B-15, dated August 22, 2022, supplemental to Indenture, Deed of Trust and Security Agreement, dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4.74 to Form 8-K filed August 25, 2022 in 1-34360).

 (g) 10 --
 Officer's Certificate No. 21-B-16, dated August 8, 2023, supplemental to Indenture, Deed of Trust and Security Agreement, dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4.74 to Form 8-K filed August 11, 2023 in 1-34360).

 (g) 11 --
 Third Amended and Restated Credit Agreement dated as of June 3, 2021, among Entergy Texas, as Borrower, the banks and other financial institutions listed on the signature pages thereof, as Lenders, Citibank, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., BNP Paribas, Mizuho Bank, Ltd., and The Bank of Nova Scotia, as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.4 to Form 8-K filed June 3, 2021 in 1-34360).

 (g) 12 --
 First Extension and Amendment Agreement, dated as of June 3, 2022, amending the Third Amended and Restated Credit Agreement, dated as of June 3, 2021, among Entergy Texas, as Borrower, the Lenders and LC Issuing Banks parties thereto and Citibank, N.A., as Administrative Agent, as set forth in Exhibit A to the First Extension and Amendment Agreement (4(f) to Form 10-Q for the quarter ended June 30, 2022 in 1-34360).

 (g) 13 --

 Second Extension to Credit Agreement, dated as of June 29, 2023, by and among Entergy Texas, as Borrower, the Lender parties thereto, each LC Issuing Bank, and Citibank, N.A., as Administrative Agent (4(i) to Form 10-Q for the quarter ended June 30, 2023 in 1-34360).

 (g) 14 --

 Statement of Resolution Establishing the 5.375% Series A Preferred Stock, Cumulative, No Par Value (Liquidation Value $25 Per Share) of Entergy Texas (3.3 to Form 8-A filed September 4, 2019 in 1-34360).

 (g) 15 --
 Statement of Resolution Establishing the 5.10% Series B Preferred Stock, Cumulative, No Par Value (Liquidation Value $25 Per Share) of Entergy Texas (3.1 to Form 8-K filed November 9, 2021 in 1-34360).

 (g) 16 --
 Description of Entergy Texas's securities registered under Section 12 of the Securities Exchange Act of 1934 (4(g)12 to Form 10-K for the year ended December 31, 2021 in 1-34360).

 (10) Material Contracts

 +(a) 1--
 2011 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (Annex A to Entergy Corporation's Definitive Proxy Statement filed on March 24, 2011 in 1-11299).

 +(a) 2 --
 2015 Equity Ownership Plan of Entergy Corporation and Subsidiaries (Appendix C to 2015 Entergy Corporation's Definitive Proxy Statement filed on March 20, 2015 in 1-11299).

 +(a) 3 --
 Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)57 to Form 10-K for the year ended December 31, 2010 in 1-11299).

 +(a) 4 --
 First Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)58 to Form 10-K for the year ended December 31, 2010 in 1-11299).

 +(a) 5 --
 Second Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)57 to Form 10-K for the year ended December 31, 2011 in 1-11299).

 +(a) 6 --
 Third Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(b) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299).

 +(a) 7 --
 Fourth Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(c) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299).

 +(a) 8 --
 Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)59 to Form 10-K for the year ended December 31, 2010 in 1-11299).

 +(a) 9 --
 First Amendment of the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)60 to Form 10-K for the year ended December 31, 2010 in 1-11299).

 +(a) 10 --
 Second Amendment of the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)60 to Form 10-K for the year ended December 31, 2011 in 1-11299).

 *+(a) 11 --
 Third Amendment of the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, effective January 1, 2024.

 +(a) 12 --
 Executive Disability Plan of Entergy Corporation and Subsidiaries (10(a)74 to Form 10-K for the year ended December 31, 2001 in 1-11299).

 +(a) 13 --
 Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)62 to Form 10-K for the year ended December 31, 2010 in 1-11299).

 +(a) 14 --
 First Amendment of the Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)63 to Form 10-K for the year ended December 31, 2010 in 1-11299).

 +(a) 15 --
 Second Amendment of the Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)64 to Form 10-K for the year ended December 31, 2011 in 1-11299).

 *+(a) 16 --
 Third Amendment of the Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, effective January 1, 2024.

 +(a) 17 --
 System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective January 1, 2009 (10(a)77 to Form 10-K for the year ended December 31, 2009 in 1-11299).

 +(a) 18 --
 First Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective January 1, 2010 (10(a)78 to Form 10-K for the year ended December 31, 2009 in 1-11299).

 +(a) 19 --
 Second Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)69 to Form 10-K for the year ended December 31, 2010 in 1-11299).

 +(a) 20 --
 Third Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)71 to Form 10-K for the year ended December 31, 2011 in 1-11299).

 *+(a) 21 --
 Fourth Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective January 1, 2024.

 +(a) 22 --
 Pension Equalization Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)74 to Form 10-K for the year ended December 31, 2010 in 1-11299).

 +(a) 23 --
 First Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)75 to Form 10-K for the year ended December 31, 2010 in 1-11299).

 +(a) 24 --
 Second Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)76 to Form 10-K for the year ended December 31, 2011 in 1-11299).

 +(a) 25--
 Third Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective June 19, 2013 (10(b) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299).

 +(a) 26 --
 Fourth Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(c) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299).

 +(a) 27 --
 Fifth Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(a) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299).

 +(a) 28 --
 Sixth Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective December 1, 2014 (10(a)25 to Form 10-K for the year ended December 31, 2021 in 1-11299).

 +(a) 29 --
 Seventh Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective August 25, 2021 (10(a)26 to Form 10-K for the year ended December 31, 2021 in 1-11299).

 +(a) 30 --
 Eighth Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective November 2, 2021 (10(a)27 to Form 10-K for the year ended December 31, 2021 in 1-11299).

 +(a) 31 --
 Ninth Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective December 1, 2022 (10(a)28 to Form 10-K for the year ended December 31, 2022 in 1-11299).

 *+(a) 32 --
 Tenth Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective January 1, 2024.

 +(a) 33 --
 Cash Balance Equalization Plan of Entergy Corporation effective July 1, 2014 (10(a)31 to Form 10-K for the year ended December 31, 2019 in 1-11299).

 *+(a) 34 --
 First Amendment of the Cash Balance Equalization Plan of Entergy Corporation effective January 1, 2021.

 *+(a) 35 --
 Second Amendment of the Cash Balance Equalization Plan of Entergy Corporation effective January 1, 2021.

 *+(a) 36 --
 Third Amendment of the Cash Balance Equalization Plan of Entergy Corporation effective January 1, 2022.

 *+(a) 37 --
 Fourth Amendment of the Cash Balance Equalization Plan of Entergy Corporation effective January 1, 2024.

 +(a) 38 --
 System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 1, 2009 (10(a)78 to Form 10-K for the year ended December 31, 2010 in 1-11299).

 +(a) 39 --
 First Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)79 to Form 10-K for the year ended December 31, 2010 in 1-11299).

 +(a) 40 --
 Second Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)81 to Form 10-K for the year ended December 31, 2011 in 1-11299).

 +(a) 41 --
 Third Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 1, 2009 (10(a)81 to Form 10-K for the year ended December 31, 2013 in 1-11299).

 +(a) 42 --
 Fourth Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(d) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299).

 +(a) 43 --
 Fifth Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(d) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299).

 +(a) 44 --
 Sixth Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective November 2, 2021 (10(a)35 to Form 10-K for the year ended December 31, 2021 in 1-11299).

 +(a) 45 --
 Seventh Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective December 14, 2021 (10(a)37 to Form 10-K for the year ended December 31, 2022 in 1-11299).

 +(a) 46 --
 Eighth Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective December 1, 2022 (10(a)38 to Form 10-K for the year ended December 31, 2022 in 1-11299).

 *+(a) 47 --
 Ninth Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, executed December 13, 2023.

 +(a) 48 --
 Shareholder Approval of Future Severance Agreements Policy, effective March 8, 2004 (10(f) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).

 +(a) 49 --
 Entergy Nuclear Retention Plan, as amended and restated effective January 1, 2007 (10(a)107 to Form 10-K for the year ended December 31, 2007 in 1-11299).

 +(a) 50 --
 First Amendment to the Entergy Nuclear Retention Plan, effective May 2, 2019 (10(a)47 to Form 10-K for the year ended December 31, 2022 in 1-11299).

 +(a) 51 --
 Second Amendment to the Entergy Nuclear Retention Plan, effective June 27, 2022 (10(a)48 to Form 10-K for the year ended December 31, 2022 in 1-11299).

 +(a) 52 --
 Third Amendment to the Entergy Nuclear Retention Plan, effective December 15, 2022 (10(a)49 to Form 10-K for the year ended December 31, 2022 in 1-11299).

 +(a) 53 --
 2019 Entergy Corporation Omnibus Incentive Plan (Appendix B to 2019 Proxy Statement, dated March 22, 2019 in 1-11299).

 +(a) 54 --
 Form of Stock Option Grant Agreement (10(a)45 to Form 10-K for the year ended December 31, 2019 in 1-11299).

 +(a) 55 --
 Form of Long Term Incentive Program Performance Unit Agreement (10(a)46 to Form 10-K for the year ended December 31, 2021 in 1-11299).

 +(a) 56 --
 Form of Restricted Stock Grant Agreement (10(a)47 to Form 10-K for the year ended December 31, 2019 in 1-11299).

 +(a) 57 --
 Form of Restricted Stock Units Grant Agreement (10(a)48 to Form 10-K for the year ended December 31, 2019 in 1-11299).

 +(a) 58 --
 Restricted Stock Units Agreement by and between A. Christopher Bakken, III and Entergy Corporation effective April 6, 2016 (10(a)54 to Form 10-K for the year ended December 31, 2016 in 1-11299).

 +(a) 59 --
 Defined Contribution Restoration Plan for the Savings Plan of Entergy Corporation and Subsidiaries VIII effective as of January 1, 2021 (10(a)46 to Form 10-K for the year ended December 31, 2020 in 1-11299).

 *+(a) 60
 First Amendment of the Defined Contribution Restoration Plan for the Savings Plan of Entergy Corporation and Subsidiaries VIII effective January 1, 2024.

 +(a) 61 --
 Restricted Stock Units Agreement Under The Entergy Corporation 2019 Omnibus Incentive Plan by and between Marcus V. Brown and Entergy Corporation effective May 17, 2021 (10(c) to Form 10-Q for the quarter ended June 30, 2021 in 1-11299).

 +(a) 62 --
 First Amended and Restated 2019 Entergy Corporation Non-Employee Director Service Recognition Program effective as of December 3, 2021 (10(a)52 to Form 10-K for the year ended December 31, 2021 in 1-11299).

 +(a) 63 --
 First Amended and Restated 2019 Entergy Corporation Non-Employee Director Stock Program effective as of December 3, 2021 (10(a)53 to Form 10-K for the year ended December 31, 2021 in 1-11299).

 +(a) 64 --
 Second Amended and Restated 2019 Entergy Corporation Non-Employee Director Stock Program effective as of June 1, 2022 (10(b) to Form 10-Q for the quarter ended September 30, 2022 in 1-11299).

 +(a) 65 --
 Entergy Corporation Non-Employee Director Cash Deferral Plan effective as of December 3, 2021 (10(a)54 to Form 10-K for the year ended December 31, 2021 in 1-11299).

 +(a) 66 --
 First Amended and Restated Entergy Corporation Non-Employee Director Cash Deferral Plan effective July 29, 2022 (10(a) to Form 10-Q for the quarter ended September 30, 2022 in 1-11299).

 +(a) 67 --
 Restricted Stock Units Agreement Under the Entergy Corporation 2019 Omnibus Incentive Plan by and between Haley Fisackerly and Entergy Corporation effective November 10, 2022 (10(a)63 to Form 10-K for the year ended December 31, 2022 in 1-11299).

 +(a) 68 --
 Restricted Stock Units Agreement Under the Entergy Corporation 2019 Omnibus Incentive Plan by and between Phillip May and Entergy Corporation effective November 10, 2022 (10(a)64 to Form 10-K for the year ended December 31, 2022 in 1-11299).

 +(a) 69 --
 Restricted Stock Units Agreement Under the Entergy Corporation 2019 Omnibus Incentive Plan by and between Roderick West and Entergy Corporation effective November 10, 2022 (10(a)65 to Form 10-K for the year ended December 31, 2022 in 1-11299).

 +(a) 70 --
 Retirement Benefit Agreement, dated as of November 30, 2022, between Marcus V. Brown and Entergy Corporation (10(a)66 to Form 10-K for the year ended December 31, 2022 in 1-11299).

 +(a) 71 --
 Amendment No. 1 to 2019 Entergy Corporation Omnibus Incentive Plan, dated May 5, 2023 (99.2 to Form 8-K filed May 10, 2023 in 1-11299).

 *+(a) 72 --

 Form of Long Term Incentive Program Performance Unit Agreement.

 (b) 1 --
 Availability Agreement, dated June 21, 1974, among System Energy and certain other System companies (10(b)1 to Form 10-K for the year ended December 31, 2017 in 1-9067).

 (b) 2 --
 First Amendment to Availability Agreement, dated as of June 30, 1977 (10(b)2 to Form 10-K for the year ended December 31, 2017 in 1-9067).

 (b) 3 --
 Second Amendment to Availability Agreement, dated as of June 15, 1981 (10(b)3 to Form 10-K for the year ended December 31, 2017 in 1-9067).

 (b) 4 --
 Third Amendment to Availability Agreement, dated as of June 28, 1984 (10(b)4 to Form 10-K for the year ended December 31, 2017 in 1-9067).

 (b) 5 --
 Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (10(b)5 to Form 10-K for the year ended December 31, 2017 in 1-9067).

 (b) 6 --
 Thirty-eighth Assignment of Availability Agreement, Consent and Agreement, dated as of December 9, 2020, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and The Bank of New York Mellon, as successor trustee (4.60 to Form 8-K filed December 9, 2020 in 1-09067).

 (b) 7 --
 Thirty-ninth Assignment of Availability Agreement, Consent and Agreement, dated as of June 15, 2021, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, The Bank of New York Mellon, as Mortgage Trustee and The Bank of New York Mellon, as Indenture Trustee (4(b) to Form 8-K filed June 15, 2021 in 1-09067).

 (b) 8 --
 Forty-first Assignment of Availability Agreement, Consent and Agreement, dated as of March 14, 2023, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and The Bank of New York Mellon, as successor trustee (4.77 to Form 8-K filed March 14, 2023 in 1-09067).

 (b) 9 --
 Facility Lease No. 1, dated as of December 1, 1988, between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (10(b)11 to Form 10-K for the year ended December 31, 2017 in 1-9067).

 (b) 10 --
 Lease Supplement No. 4, dated as of January 15, 2014, to Facility Lease No. 1 (10(b)12 to Form 10-K for the year ended December 31, 2016 in 1-11299).

 (b) 11 --
 Facility Lease No. 2, dated as of December 1, 1988 between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (10(b)13 to Form 10-K for the year ended December 31, 2017 in 1-9067).

 (b) 12 --
 Lease Supplement No. 4, dated as of May 28, 2014, to Facility Lease No. 2 (10(b)14 to Form 10-K for the year ended December 31, 2016 in 1-11299).

 (b) 13 --
 Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (10(b)15 to Form 10-K for the year ended December 31, 2017 in 1-9067).

 (b) 14 --
 Unit Power Sales Agreement among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans dated as of June 10, 1982, as amended and revised (10(b)16 to Form 10-K for the year ended December 31, 2018 in 1-9067).

 (c) 1 --
 Purchase and Sale Agreement, between Entergy New Orleans, LLC, as Seller, and Delta States Utilities NO, LLC, as Buyer, dated October 28, 2023 (1.01 to Form 8-K filed October 30, 2023 in 1-11299).

 (14) Code of Ethics

 (a)
 Entergy Corporation Code of Business Conduct and Ethics (14(a) to Form 10-K for the year ended December 31, 2020 in 1-32718).

 *(21) Subsidiaries of the Registrants

 (23) Consents of Experts and Counsel
 *(a)
 The consents of Deloitte & Touche LLP are contained herein at page 5 64.

 *(24) Powers of Attorney

 (31) Rule 13a-14(a)/15d-14(a) Certifications
 *(a)
 Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation.

 *(b)
 Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation.

 *(c)
 Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas.

 *(d)
 Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas.

 *(e)
 Rule 13a-14(a)/15d-14(a) Certification for Entergy Louisiana.

 *(f)
 Rule 13a-14(a)/15d-14(a) Certification for Entergy Louisiana.

 *(g)
 Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi.

 *(h)
 Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi.

 *(i)
 Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans.

 *(j)
 Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans.

 *(k)
 Rule 13a-14(a)/15d-14(a) Certification for Entergy Texas.

 *(l)
 Rule 13a-14(a)/15d-14(a) Certification for Entergy Texas.

 *(m)
 Rule 13a-14(a)/15d-14(a) Certification for System Energy.

 *(n)
 Rule 13a-14(a)/15d-14(a) Certification for System Energy.

 (32) Section 1350 Certifications
 **(a)
 Section 1350 Certification for Entergy Corporation.

 **(b)
 Section 1350 Certification for Entergy Corporation.

 **(c)
 Section 1350 Certification for Entergy Arkansas.

 **(d)
 Section 1350 Certification for Entergy Arkansas.

 **(e)
 Section 1350 Certification for Entergy Louisiana.

 **(f)
 Section 1350 Certification for Entergy Louisiana.

 **(g)
 Section 1350 Certification for Entergy Mississippi.

 **(h)
 Section 1350 Certification for Entergy Mississippi.

 **(i)
 Section 1350 Certification for Entergy New Orleans.

 **(j)
 Section 1350 Certification for Entergy New Orleans.

 **(k)
 Section 1350 Certification for Entergy Texas.

 **(l)
 Section 1350 Certification for Entergy Texas.

 **(m)
 Section 1350 Certification for System Energy.

 **(n)
 Section 1350 Certification for System Energy.

 *(97) Entergy System Policy Regarding Recoupment of Certain Compensation adopted separately by each of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans and Entergy Texas, effective October 2, 2023.

 (101) Interactive Data File
 *INS -

 *SCH -

 *CAL -

 *DEF -

 *LAB -

 *PRE -

 _________________
 *
 Filed herewith.

 **
 Furnished, not filed, herewith.

 +
 Management contracts or compensatory plans or arrangements.

 ENTERGY CORPORATION

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 ENTERGY CORPORATION

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Title
 Date

 Andrew S. Marsh (Chair of the Board, Chief Executive Officer and Director; Principal Executive Officer); Kimberly A. Fontan (Executive Vice President and Chief Financial Officer; Principal Financial Officer); Gina F. Adams, John H. Black, John R. Burbank, Patrick J. Condon, Kirkland H. Donald, Brian W. Ellis, Philip L. Frederickson, M. Elise Hyland, Stuart L. Levenick, Blanche L. Lincoln, and Karen A. Puckett (Directors).

 ENTERGY ARKANSAS, LLC

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 ENTERGY ARKANSAS, LLC

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Title
 Date

 Laura R. Landreaux (Chair of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Kimberly A. Fontan (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Peter S. Norgeot, Jr. and Roderick K. West (Directors).

 ENTERGY LOUISIANA, LLC

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 ENTERGY LOUISIANA, LLC

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Title
 Date

 Phillip R. May, Jr. (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Kimberly A. Fontan (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Peter S. Norgeot, Jr. and Roderick K. West (Directors).

 ENTERGY MISSISSIPPI, LLC

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 ENTERGY MISSISSIPPI, LLC

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Title
 Date

 Haley R. Fisackerly (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Kimberly A. Fontan (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Peter S. Norgeot, Jr. and Roderick K. West (Directors).

 ENTERGY NEW ORLEANS, LLC

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 ENTERGY NEW ORLEANS, LLC

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Title
 Date

 Deanna D. Rodriguez (Chair of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Kimberly A. Fontan (Executive Vice President and Chief Financial Officer; Principal Financial Officer); Peter S. Norgeot, Jr. and Roderick K. West (Directors).

 ENTERGY TEXAS, INC.

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 ENTERGY TEXAS, INC.

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Title
 Date

 Eliecer Viamontes (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Kimberly A. Fontan (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Peter S. Norgeot, Jr. and Roderick K. West (Directors).

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Title
 Date

 Roderick K. West (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Kimberly A. Fontan (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Kimberly Cook-Nelson and Barrett E. Green (Directors).

 EXHIBIT 23(a)

 CONSENTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 We consent to the incorporation by reference in Registration Statement No. 333-266624 on Form S-3 and in Registration Statements Nos. 333-174148, 333-204546, 333-231800, 333-251819, and 333-275398 on Form S-8 of our reports dated February 23, 2024, relating to the financial statements and financial statement schedule of Entergy Corporation and Subsidiaries, and the effectiveness of Entergy Corporation and Subsidiaries' internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Corporation for the year ended December 31, 2023.

 We consent to the incorporation by reference in Registration Statement No. 333-266624-05 on Form S-3 of our reports dated February 23, 2024, relating to the financial statements and financial statement schedule of Entergy Arkansas, LLC and Subsidiaries appearing in this Annual Report on Form 10-K of Entergy Arkansas, LLC for the year ended December 31, 2023.

 We consent to the incorporation by reference in Registration Statement No. 333-266624-04 on Form S-3 of our reports dated February 23, 2024, relating to the financial statements and financial statement schedule of Entergy Louisiana, LLC and Subsidiaries appearing in this Annual Report on Form 10 K of Entergy Louisiana, LLC for the year ended December 31, 2023.

 We consent to the incorporation by reference in Registration Statement No. 333-266624-03 on Form S-3 of our reports dated February 23, 2024, relating to the financial statements and financial statement schedule of Entergy Mississippi, LLC and Subsidiaries appearing in this Annual Report on Form 10 K of Entergy Mississippi, LLC for the year ended December 31, 2023.

 We consent to the incorporation by reference in Registration Statement No. 333-266624-02 on Form S-3 of our reports dated February 23, 2024, relating to the financial statements and financial statement schedule of Entergy Texas, Inc. and Subsidiaries appearing in this Annual Report on Form 10-K of Entergy Texas, Inc. for the year ended December 31, 2023.

 We consent to the incorporation by reference in Registration Statement No. 333-266624-01 on Form S-3 of our report dated February 23, 2024, relating to the financial statements of System Energy Resources, Inc. appearing in this Annual Report on Form 10-K of System Energy Resources, Inc. for the year ended December 31, 2023.

 Opinion on the Financial Statement Schedule

 We have audited the consolidated financial statements of Entergy Corporation and Subsidiaries (the "Corporation") as of December 31, 2023 and 2022, and for each of the three years in the period ended December 31, 2023, and the Corporation's internal control over financial reporting as of December 31, 2023, and have issued our reports thereon dated February 23, 2024. Our audits also included the consolidated financial statement schedule of the Corporation listed in Item 15. This consolidated financial statement schedule is the responsibility of the Corporation's management. Our responsibility is to express an opinion on the Corporation's consolidated financial statement schedule based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

 Opinion on the Financial Statement Schedules

 We have audited the consolidated financial statements of Entergy Arkansas, LLC and Subsidiaries, Entergy Louisiana, LLC and Subsidiaries, Entergy Mississippi, LLC and Subsidiaries, Entergy New Orleans, LLC and Subsidiaries, and Entergy Texas, Inc. and Subsidiaries (collectively the "Companies") as of December 31, 2023 and 2022, and for each of the three years in the period ended December 31, 2023, and have issued our reports thereon dated February 23, 2024. Our audits also included the financial statement schedules of the respective Companies listed in Item 15. These financial statement schedules are the responsibility of the respective Companies' management. Our responsibility is to express an opinion on the Companies' financial statement schedules based on our audits. In our opinion, such financial statement schedules, when considered in relation to the financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

 INDEX TO FINANCIAL STATEMENT SCHEDULES

 Schedule

 Page

 II
 Valuation and Qualifying Accounts 2023, 2022, and 2021:

 S-2

 S-3

 S-4

 S-5

 S-6

 S-7

 Schedules other than those listed above are omitted because they are not required, not applicable, or the required information is shown in the financial statements or notes thereto.

 Columns have been omitted from schedules filed because the information is not applicable.
 S-1

 Other

(1)
 (2)

 2023
 $ 30,856
 $ 38,508
 $ 43,459
 $ 25,905

 2022
 $ 68,608
 $ 40,307
 $ 78,059
 $ 30,856

 2021
 $ 117,794
 $ 57,517
 $ 106,703
 $ 68,608

 (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

 S-2

 Other

(1)
 (2)

 2023
 $ 6,528
 $ 9,428
 $ 8,774
 $ 7,182

 2022
 $ 13,072
 $ 14,947
 $ 21,491
 $ 6,528

 2021
 $ 18,334
 $ 30,433
 $ 35,695
 $ 13,072

 (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

 S-3

 Other

(1)
 (2)

 2023
 $ 7,595
 $ 13,876
 $ 15,315
 $ 6,156

 2022
 $ 29,231
 $ 10,574
 $ 32,210
 $ 7,595

 2021
 $ 45,693
 $ 17,219
 $ 33,681
 $ 29,231

 (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

 S-4

 Other

(1)
 (2)

 2023
 $ 2,472
 $ 7,275
 $ 6,435
 $ 3,312

 2022
 $ 7,209
 $ 3,052
 $ 7,789
 $ 2,472

 2021
 $ 19,527
 $ 850
 $ 13,168
 $ 7,209

 (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

 S-5

 Other

(1)
 (2)

 2023
 $ 11,909
 $ 3,350
 $ 7,489
 $ 7,770

 2022
 $ 13,282
 $ 7,691
 $ 9,064
 $ 11,909

 2021
 $ 17,430
 $ 6,850
 $ 10,998
 $ 13,282

 (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

 S-6

 Other

(1)
 (2)

 2023
 $ 2,352
 $ 4,579
 $ 5,447
 $ 1,484

 2022
 $ 5,814
 $ 4,042
 $ 7,504
 $ 2,352

 2021
 $ 16,810
 $ 2,166
 $ 13,162
 $ 5,814

 (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

 S-7