ENTERGY NEW ORLEANS, LLC - Annual Report: 2020 (Form 10-K)
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, 2020
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) 670-3700 | |||||||||||||
| 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) 10055 Grogans Mill Road The Woodlands, Texas 77380 Telephone (409) 981-2000 | |||||||||||||
| 83-1918668 | 61-1435798 | |||||||||||||
| 1-32718 | ENTERGY LOUISIANA, LLC | 1-09067 | SYSTEM ENERGY RESOURCES, INC. | |||||||||||
(a Texas limited liability company) 4809 Jefferson Highway Jefferson, Louisiana 70121 Telephone (504) 576-4000 | (an Arkansas corporation) 1340 Echelon Parkway Jackson, Mississippi 39213 Telephone (601) 368-5000 | |||||||||||||
| 47-4469646 | 72-0752777 | |||||||||||||
| 1-31508 | ENTERGY MISSISSIPPI, LLC | |||||||||||||
(a Texas limited liability company) 308 East Pearl Street Jackson, Mississippi 39201 Telephone (601) 368-5000 | ||||||||||||||
| 83-1950019 | ||||||||||||||
Securities registered pursuant to Section 12(b) of the Act:
| Registrant | Title of Class | Trading Symbol | Name of Each Exchange on Which Registered | ||||||||
| Entergy Corporation | Common Stock, $0.01 Par Value | ETR | New York Stock Exchange | ||||||||
Common Stock, $0.01 Par Value | ETR | NYSE Chicago, Inc. | |||||||||
| Entergy Arkansas, LLC | Mortgage Bonds, 4.875% Series due September 2066 | EAI | New York Stock Exchange | ||||||||
| Entergy Louisiana, LLC | Mortgage Bonds, 4.875% Series due September 2066 | ELC | New York Stock Exchange | ||||||||
| Entergy Mississippi, LLC | Mortgage Bonds, 4.90% Series due October 2066 | EMP | New York Stock Exchange | ||||||||
| Entergy New Orleans, LLC | Mortgage Bonds, 5.0% Series due December 2052 | ENJ | New York Stock Exchange | ||||||||
Mortgage Bonds, 5.50% Series due April 2066 | ENO | New York Stock Exchange | |||||||||
| Entergy Texas, Inc. | 5.375% Series A Preferred Stock, Cumulative, No Par Value (Liquidation Value $25 Per Share) | ETI/PR | New York Stock Exchange | ||||||||
Securities registered pursuant to Section 12(g) of the Act:
| Registrant | Title of Class | ||||
| Entergy Texas, Inc. | Common Stock, no par value | ||||
Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.
| Yes | No | ||||||||||
| Entergy Corporation | ü | ||||||||||
| Entergy Arkansas, LLC | ü | ||||||||||
| Entergy Louisiana, LLC | ü | ||||||||||
| Entergy Mississippi, LLC | ü | ||||||||||
| Entergy New Orleans, LLC | ü | ||||||||||
| Entergy Texas, Inc. | ü | ||||||||||
| System Energy Resources, Inc. | ü | ||||||||||
Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
| Yes | No | ||||||||||
| Entergy Corporation | ü | ||||||||||
| Entergy Arkansas, LLC | ü | ||||||||||
| Entergy Louisiana, LLC | ü | ||||||||||
| Entergy Mississippi, LLC | ü | ||||||||||
| Entergy New Orleans, LLC | ü | ||||||||||
| Entergy Texas, Inc. | ü | ||||||||||
| System Energy Resources, Inc. | ü | ||||||||||
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files). Yes þ No o
Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Securities Exchange Act of 1934.
| Large Accelerated Filer | Accelerated Filer | Non-accelerated Filer | Smaller reporting company | Emerging growth company | |||||||||||||||||||||||||
| Entergy Corporation | ü | ||||||||||||||||||||||||||||
| Entergy Arkansas, LLC | ü | ||||||||||||||||||||||||||||
| Entergy Louisiana, LLC | ü | ||||||||||||||||||||||||||||
| Entergy Mississippi, LLC | ü | ||||||||||||||||||||||||||||
| Entergy New Orleans, LLC | ü | ||||||||||||||||||||||||||||
| Entergy Texas, Inc. | ü | ||||||||||||||||||||||||||||
| System Energy Resources, Inc. | ü | ||||||||||||||||||||||||||||
If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
| Entergy Corporation | ☑ | ||||||||||
| Entergy Arkansas, LLC | |||||||||||
| Entergy Louisiana, LLC | |||||||||||
| Entergy Mississippi, LLC | |||||||||||
| Entergy New Orleans, LLC | |||||||||||
| Entergy Texas, Inc. | |||||||||||
| System Energy Resources, Inc. | |||||||||||
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act.) Yes ☐ No þ
| Common Stock Outstanding | Outstanding at January 29, 2021 | |||||||
| Entergy Corporation | ($0.01 par value) | 200,479,995 | ||||||
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 2020 was $18.8 billion based on the reported last sale price of $93.81 per share for such stock on the New York Stock Exchange on June 30, 2020. 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 7, 2021, are incorporated by reference into Part III hereof.
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TABLE OF CONTENTS
| SEC Form 10-K Reference Number | Page Number | |||||||
| Entergy Corporation and Subsidiaries | ||||||||
| Part II. Item 7. | ||||||||
| Part II. Item 6. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Notes to Financial Statements | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Entergy’s Business | ||||||||
| Part I. Item 1. | ||||||||
| Part I. Item 1. | ||||||||
| Part I. Item 1. | ||||||||
i
| Part I. Item 1A. | ||||||||
Unresolved Staff Comments | Part I. Item 1B. | None | ||||||
Entergy Arkansas, LLC and Subsidiaries | ||||||||
| Part II. Item 7. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 6. | ||||||||
| Entergy Louisiana, LLC and Subsidiaries | ||||||||
| Part II. Item 7. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 6. | ||||||||
| Entergy Mississippi, LLC | ||||||||
| Part II. Item 7. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 6. | ||||||||
| Entergy New Orleans, LLC and Subsidiaries | ||||||||
| Part II. Item 7. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 6. | ||||||||
| Entergy Texas, Inc. and Subsidiaries | ||||||||
| Part II. Item 7. | ||||||||
| Part II. Item 8. | ||||||||
ii
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 6. | ||||||||
| System Energy Resources, Inc. | ||||||||
| Part II. Item 7. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 6. | ||||||||
| Part I. Item 2. | ||||||||
| Part I. Item 3. | ||||||||
| Part I. Item 4. | ||||||||
| Part I. and Part III. Item 10. | ||||||||
| Part II. Item 5. | ||||||||
| Part II. Item 6. | ||||||||
| Part II. Item 7. | ||||||||
| Part II. Item 7A. | ||||||||
| Part II. Item 8. | ||||||||
| Part II. Item 9. | ||||||||
| Part II. Item 9A. | ||||||||
| Part II. Item 9A. | ||||||||
| Part III. Item 10. | ||||||||
| Part III. Item 11. | ||||||||
| Part III. Item 12. | ||||||||
| Part III. Item 13. | ||||||||
| Part III. Item 14. | ||||||||
| Part IV. Item 15. | ||||||||
| Part IV. Item 16. | ||||||||
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 6, 7, and 8 sections are
iii
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 6, 7, and 8 are combined for the reporting companies.
iv
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,” “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, these registrants undertake 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;
•continuing long-term risks and uncertainties associated with the termination of the System Agreement in 2016, including the potential absence of federal authority to resolve certain issues among the Utility operating companies and their retail regulators;
•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 and market and system conditions in the MISO markets, the allocation of MISO system transmission upgrade costs, 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 nuclear generating facilities and nuclear materials and fuel, including with respect to the planned or actual shutdown and sale of each of the nuclear generating facilities owned or operated by Entergy Wholesale Commodities, and the effects of new or existing safety or environmental concerns regarding nuclear power plants and nuclear 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, emerging operating and industry issues, and the commitment of substantial human and capital resources required for the safe and reliable operation and maintenance of Entergy’s nuclear generating facilities;
•Entergy’s ability to develop and execute on a point of view regarding future prices of electricity, natural gas, and other energy-related commodities;
v
FORWARD-LOOKING INFORMATION (Continued)
•prices for power generated by Entergy’s merchant generating facilities and the ability to hedge, meet credit support requirements for hedges, sell power forward or otherwise reduce the market price risk associated with those facilities, including the Entergy Wholesale Commodities nuclear plants, especially in light of the planned shutdown and sale of each of these nuclear plants;
•the prices and availability of fuel and power Entergy must purchase for its Utility customers, 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, requirements for waste management and disposal and for the remediation of contaminated sites, wetlands protection and permitting, 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;
•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 (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta), ice storms, or other weather events and the recovery of costs associated with restoration, including accessing funded storm reserves, federal and local cost recovery mechanisms, securitization, and insurance, as well as any related unplanned outages;
•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, a utility industry mutual insurance company, and industry self-insurance programs;
•effects of climate change, including the potential for increases in extreme weather events and sea levels or coastal land and wetland loss;
•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 completion of projects timely and within budget and to obtain the anticipated performance or other benefits, and its operation and maintenance costs;
•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 the northern United States and events and circumstances that could influence economic conditions in those areas, including power prices, and the risk that anticipated load growth may not materialize;
•changes to federal income tax laws and regulations, including continued impact of the Tax Cuts and Jobs Act and its intended and unintended consequences on financial results and future cash flows;
•the effects of Entergy’s strategies to reduce tax payments;
•changes in the financial markets and regulatory requirements for the issuance of securities, particularly as they affect access to capital and Entergy’s ability to refinance existing securities, execute share repurchase programs, and fund investments and acquisitions;
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FORWARD-LOOKING INFORMATION (Concluded)
•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;
•the effects of litigation and government investigations or proceedings;
•changes in technology, including (i) Entergy’s ability to implement new or emerging technologies, (ii) 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 of the foregoing, and (iii) competition from other companies offering products and services to Entergy’s customers based on new or emerging technologies or alternative sources of generation;
•Entergy’s ability to effectively formulate and implement plans to reduce its carbon emission rate and aggregate carbon emissions, including its commitment to achieve net-zero carbon emissions by 2050, and the potential impact on its business of attempting to achieve such objectives;
•the effects, including increased security costs, of threatened or actual terrorism, cyber-attacks or data security breaches, 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;
•the effects of a global event or pandemic, such as the COVID-19 global pandemic, including economic and societal 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; 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;
•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 benefit plans;
•future wage and employee benefit 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 decision to cease merchant power generation at all Entergy Wholesale Commodities nuclear power plants by mid-2022, including the implementation of the planned shutdowns and sales of Indian Point 2, Indian Point 3, and Palisades;
•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;
•the potential for the factors listed herein to lead to the impairment of long-lived assets; and
•Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete strategic transactions that Entergy 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 | Entergy Corporation and its direct and indirect subsidiaries | ||||
Entergy Corporation | Entergy Corporation, a Delaware corporation | ||||
Entergy Gulf States, Inc. | Predecessor company for financial reporting purposes to Entergy Gulf States Louisiana that included the assets and business operations of both Entergy Gulf States Louisiana and Entergy Texas | ||||
Entergy Gulf States Louisiana | Entergy Gulf States Louisiana, L.L.C., a Louisiana limited liability company formally created as part of the jurisdictional separation of Entergy Gulf States, Inc. and the successor company to Entergy Gulf States, Inc. for financial reporting purposes. The term is also used to refer to the Louisiana jurisdictional business of Entergy Gulf States, Inc., as the context requires. Effective October 1, 2015, the business of Entergy Gulf States Louisiana was combined with Entergy Louisiana. | ||||
Entergy Louisiana | Entergy Louisiana, LLC, a Texas limited liability company formally created as part of the combination of Entergy Gulf States Louisiana and the company formerly known as Entergy Louisiana, LLC (Old Entergy Louisiana) into a single public utility company and the successor to Old Entergy Louisiana for financial reporting purposes. | ||||
Entergy Texas | Entergy Texas, Inc., a Texas corporation formally created as part of the jurisdictional separation of Entergy Gulf States, Inc. The term is also used to refer to the Texas jurisdictional business of Entergy Gulf States, Inc., as the context requires. | ||||
Entergy Wholesale Commodities | Entergy’s non-utility business segment 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 by an Entergy subsidiary in the Entergy Wholesale Commodities business segment, which was sold in March 2017 | ||||
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 | ||||
Independence | 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), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment, which ceased power production in April 2020 | ||||
Indian Point 3 | Unit 3 of Indian Point Energy Center (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment | ||||
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 | ||||
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 an Entergy subsidiary in the Entergy Wholesale Commodities business segment | ||||
Net debt to net capital ratio | Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents | ||||
Net MW in operation | Installed capacity owned and operated | ||||
NRC | Nuclear Regulatory Commission | ||||
NYPA | New York Power Authority | ||||
Palisades | Palisades Nuclear Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment | ||||
Parent & Other | The portions of Entergy not included in the Utility or Entergy Wholesale Commodities segments, primarily consisting of the activities of the parent company, Entergy Corporation | ||||
Pilgrim | Pilgrim Nuclear Power Station (nuclear), previously owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment, 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. | ||||
System Energy | System Energy Resources, Inc. | ||||
TWh | Terawatt-hour(s), which equals one billion kilowatt-hours | ||||
| Unit Power Sales Agreement | Agreement, dated as of June 10, 1982, as amended and approved by the FERC, among Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, relating to the sale of capacity and energy from System Energy’s share of Grand Gulf | ||||
Utility | Entergy’s business segment that generates, transmits, distributes, and sells electric power, with a small amount of natural gas distribution | ||||
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 by an Entergy subsidiary in the Entergy Wholesale Commodities business segment, 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 | ||||
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ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Entergy operates primarily through two business segments: Utility and Entergy Wholesale Commodities.
•The Utility business 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.
•The Entergy Wholesale Commodities business segment includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” below for discussion of the operation and planned shutdown and sale of each of the Entergy Wholesale Commodities nuclear power plants.
Following are the percentages of Entergy’s consolidated revenues generated by its operating segments and the percentage of total assets held by them. Net income or loss generated by the operating segments is discussed in the sections that follow.
| % of Revenue | % of Total Assets | ||||||||||||||||||||||
| Segment | 2020 | 2019 | 2018 | 2020 | 2019 | 2018 | |||||||||||||||||
| Utility | 91 | 88 | 87 | 96 | 96 | 93 | |||||||||||||||||
| Entergy Wholesale Commodities | 9 | 12 | 13 | 7 | 8 | 11 | |||||||||||||||||
| Parent & Other (a) | — | — | — | (3) | (4) | (4) | |||||||||||||||||
See Note 13 to the financial statements for further financial information regarding Entergy’s business segments.
(a)Parent & Other includes eliminations, which are primarily intersegment activity.
The COVID-19 Pandemic
The COVID-19 pandemic and the measures to control it have adversely affected economic activity and conditions worldwide and have affected the demand for the products and services of many businesses in Entergy’s service area. Entergy experienced a decline in sales volume in 2020 compared to 2019 due to the COVID-19 pandemic, especially in the commercial and industrial sectors. In addition, Entergy experienced negative changes to its customers’ payment patterns and its operating cash flow activity in 2020 compared to 2019 due to the COVID-19 pandemic. These negative changes include an increase in uncollectible accounts.
Entergy provides critical services to its customers and has implemented its comprehensive incident response plan, which contemplates major events such as storms or pandemics. Entergy’s focus during the COVID-19 pandemic has been on the safety and wellness of its employees; providing safe, reliable service for its customers; analyzing and addressing the financial effects of the COVID-19 pandemic; and continuing its plans for the future. Entergy implemented precautionary measures for safety on and off the job for employees and contractors working at plants and in the field and implemented telecommuting practices for employees who can work from home. Entergy temporarily suspended service disconnections for customers and is working with regulators to address routine and non-routine matters and allow continuation of capital spending plans. The Utility operating companies have received accounting orders to defer costs associated with COVID-19. To date, Entergy has not had material effects to its major projects or capital spending plans. Entergy is working with suppliers and contractors for continued availability of resources, equipment, and supplies to keep operations and major projects going forward and on schedule. Entergy implemented expense-related spending reductions in 2020, which did not affect safety or service reliability, in order to offset some of the financial effects of the COVID-19 pandemic.
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Although Entergy has taken these actions in response to the COVID-19 pandemic, uncertainty exists regarding the full depth and length of the effects of COVID-19 on Entergy’s sales volume, revenue, collections and cash flows, expenses, liquidity, and capital needs. Entergy will continue to monitor actively the COVID-19 pandemic and related developments affecting its workforce, customers, suppliers, operations, and financial condition.
Hurricane Laura, Hurricane Delta, and Hurricane Zeta
In August and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Utility’s service territories in Louisiana, including New Orleans, Texas, and to a lesser extent, in Arkansas and Mississippi. The storms resulted in widespread power 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. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.4 billion, including approximately $1.98 billion in capital costs and approximately $420 million in non-capital costs. The majority of the costs were incurred by Entergy Louisiana, with a substantial portion also incurred by Entergy Texas. The estimate includes all costs to restore power and repair or replace the damages from the hurricanes, except for the cost to repair or replace damage incurred to an Entergy Louisiana transmission line in southeast Louisiana, and the amount of that cost could be significant. The restoration plan for this transmission line and the related cost estimate is still being evaluated. Also, Utility revenues were adversely affected in 2020, primarily due to power outages resulting from the hurricanes.
Entergy recorded accounts payable and corresponding construction work in progress and regulatory assets for the estimated costs incurred that were necessary to return customers to service. Entergy recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. There are well-established mechanisms and precedent for addressing these catastrophic events and providing for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles. Because Entergy has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
The Utility operating companies are considering all available avenues to recover storm-related costs from Hurricane Laura, Hurricane Delta, and Hurricane Zeta, including accessing funded storm reserve escrows and securitization. In November 2020, Entergy Louisiana drew $257 million from its funded storm reserves. Each Utility operating company is responsible for its restoration cost obligations and for recovering or financing its storm-related costs. Storm cost recovery or financing will be subject to review by applicable regulatory authorities.
In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments to facilitate issuance of shorter-term 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 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.
In December 2020, Entergy Louisiana provided the LPSC with notification that it intends to initiate a storm cost recovery proceeding in the near future, which will permit the LPSC to retain any outside consultants and counsel needed to review the storm cost recovery application. In February 2021 the LPSC voted to retain outside
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counsel and consultants to assist in the review of Entergy Louisiana’s upcoming storm cost recovery application, which is expected to be filed in March 2021.
February 2021 Winter Storms
In February 2021, the United States experienced winter storms and extreme cold temperatures, including in Entergy’s service area. The impact of the storms and the extreme cold temperatures affected Entergy’s operational assets and the availability of generation across the area. In order to balance the system, MISO directed Entergy to conduct rolling power outages. Entergy’s system is now back to normal operations. The severe weather event also affected the market for natural gas due to the severe cold’s effects on the gas supply system and increased demand for gas to support electricity loads. Entergy’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $125 million to $140 million, primarily at Entergy Louisiana and Entergy Mississippi. Natural gas purchases for February 1st through 25th, 2021, for Entergy were approximately $510 million, including $105 million for Entergy Arkansas, $190 million for Entergy Louisiana, $45 million for Entergy Mississippi, $15 million for Entergy New Orleans, and $155 million for Entergy Texas. This compares to natural gas purchases for February 2020 for Entergy of $80 million, including $10 million for Entergy Arkansas, $39 million for Entergy Louisiana, $14 million for Entergy Mississippi, $7 million for Entergy New Orleans, and $10 million for Entergy Texas.
The Utility operating companies each have fuel recovery mechanisms in place to recover their natural gas costs. With the potential effect of the higher natural gas costs on customers, the Utility operating companies plan to work with their retail regulators to recover these costs in a manner that mitigates the effects on customer bills. The Utility operating companies also expect to work with their regulators as the regulators review other effects of the winter storm.
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Results of Operations
2020 Compared to 2019
Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2020 to 2019 showing how much the line item increased or (decreased) in comparison to the prior period.
| Utility | Entergy Wholesale Commodities | Parent & Other (a) | Entergy | ||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||
| 2019 Net Income (Loss) Attributable to Entergy Corporation | $1,410,813 | $146,682 | ($316,269) | $1,241,226 | |||||||||||||||||||
| Operating revenues | (413,271) | (351,850) | 84 | (765,037) | |||||||||||||||||||
| Fuel, fuel-related expenses, and gas purchased for resale | (434,394) | (30,900) | 27 | (465,267) | |||||||||||||||||||
| Purchased power | (297,505) | 8,940 | (27) | (288,592) | |||||||||||||||||||
| Other regulatory charges (credits) | 40,829 | — | — | 40,829 | |||||||||||||||||||
| Other operation and maintenance | (84,548) | (177,945) | (7,262) | (269,755) | |||||||||||||||||||
| Asset write-offs, impairments, and related charges | — | (263,404) | — | (263,404) | |||||||||||||||||||
| Taxes other than income taxes | 15,743 | (6,987) | 339 | 9,095 | |||||||||||||||||||
| Depreciation and amortization | 179,298 | (46,119) | (109) | 133,070 | |||||||||||||||||||
| Other income | (23,947) | (151,832) | 37,047 | (138,732) | |||||||||||||||||||
| Interest expense | 59,456 | (7,018) | (9,200) | 43,238 | |||||||||||||||||||
| Other expenses | (4,863) | (34,848) | — | (39,711) | |||||||||||||||||||
| Income taxes | (301,945) | 266,232 | 84,032 | 48,319 | |||||||||||||||||||
| Preferred dividend requirements of subsidiaries | 1,301 | — | — | 1,301 | |||||||||||||||||||
| 2020 Net Income (Loss) Attributable to Entergy Corporation | $1,800,223 | ($64,951) | ($346,938) | $1,388,334 | |||||||||||||||||||
(a)Parent & Other includes eliminations, which are primarily intersegment activity.
Refer to “SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES” which accompanies Entergy Corporation’s financial statements in this report for further information with respect to operating statistics.
Results of operations for 2020 include resolution of the 2014-2015 IRS audit, which resulted in a reduction in deferred income tax expense of $230 million that includes a $396 million reduction in deferred income tax expense at Utility related to the basis of assets contributed in the 2015 Entergy Louisiana and Entergy Gulf States Louisiana business combination, including the recognition of previously uncertain tax positions, and deferred income tax expense of $105 million at Entergy Wholesale Commodities and $61 million at Parent and Other resulting from the revaluation of net operating losses as a result of the release of the reserves. See Note 3 to the financial statements for further discussion of the IRS audit resolution.
Results of operations for 2019 include: 1) a loss of $190 million ($156 million net-of-tax) as a result of the sale of the Pilgrim plant in August 2019; 2) a $156 million reduction in income tax expense recognized by Entergy Wholesale Commodities as a result of an internal restructuring; and 3) impairment charges of $100 million ($79 million net-of-tax) due to costs being charged directly to expense as incurred as a result of the impaired value of the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining
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estimated operating lives associated with management’s strategy to exit the Entergy Wholesale Commodities’ merchant power business. See Note 3 to the financial statements for further discussion of the internal restructuring. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” below for discussion of management’s strategy to shut down and sell all of the remaining plants in Entergy Wholesale Commodities’ merchant nuclear fleet and see Note 14 to the financial statements for further discussion of the impairment and related charges and the sale of the Pilgrim plant.
Operating Revenues
Utility
Following is an analysis of the change in operating revenues comparing 2020 to 2019:
| Amount | |||||
| (In Millions) | |||||
| 2019 operating revenues | $9,584 | ||||
| Fuel, rider, and other revenues that do not significantly affect net income | (792) | ||||
| Volume/weather | (164) | ||||
| System Energy provision for rate refund | (25) | ||||
| Return of unprotected excess accumulated deferred income taxes to customers | 194 | ||||
| Retail electric price | 374 | ||||
| 2020 operating revenues | $9,171 | ||||
The Utility operating companies’ results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The volume/weather variance is primarily due to decreased commercial and industrial usage as a result of the COVID-19 pandemic and the effects of Hurricane Laura, Hurricane Delta, and Hurricane Zeta, in addition to the effect of less favorable weather on residential and commercial sales, partially offset by an increase in residential usage as a result of the COVID-19 pandemic. The decrease in industrial usage is partially offset by an increase in demand from expansion projects, primarily in the transportation and chemicals industries. See “The COVID-19 Pandemic” above for discussion of the COVID-19 pandemic. See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of the storms.
The System Energy provision for rate refund variance is due to a provision for rate refund recorded in 2020 to reflect a one-time credit of $25 million provided for in the Federal Power Act section 205 filing made by System Energy in December 2020. See Note 2 to the financial statements for further discussion of the proceedings involving System Energy at the FERC.
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 2020, $68 million was returned to customers through reductions in operating revenues as compared to $262 million in 2019. There is 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.
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The retail electric price variance is primarily due to:
•interim increases in Entergy Louisiana’s formula rate plan revenues effective June 2019 due to the inclusion of the first-year revenue requirement for the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and effective April 2020 due to the inclusion of the first-year revenue requirement for the Lake Charles Power Station and increases in formula rate plan revenues effective September 2019 and September 2020;
•increases in Entergy Mississippi’s formula rate plan rates effective with the first billing cycles of July 2019 and April 2020 and an interim capacity rate adjustment to the formula rate plan effective January 2020 to recover non-fuel related costs of acquiring and operating the Choctaw Generating Station;
•an increase in Entergy Arkansas’s formula rate plan rates effective with the first billing cycle of January 2020;
•the implementation of a vegetation management rider at Entergy Mississippi effective with the April 2020 billing cycle; and
•increases in Entergy Texas’s transmission cost recovery factor rider effective January 2020 and distribution cost recovery factor rider effective October 2020.
The increase was partially offset by the effects of Entergy New Orleans’s rate reduction implemented with April 2020 bills that was effective August 2019 in accordance with the City Council resolution and related agreement in principle reached in the 2018 base rate case.
See Note 2 to the financial statements for further discussion of the regulatory proceedings discussed above.
Entergy Wholesale Commodities
Operating revenues for Entergy Wholesale Commodities decreased from $1,295 million for 2019 to $943 million for 2020 primarily due to the shutdown of Indian Point 2 in April 2020 and the shutdown of Pilgrim in May 2019.
Following are key performance measures for Entergy Wholesale Commodities for 2020 and 2019:
| 2020 | 2019 | ||||||||||
| Owned capacity (MW) (a) | 2,246 | 3,274 | |||||||||
| GWh billed | 20,581 | 28,088 | |||||||||
| Entergy Wholesale Commodities Nuclear Fleet | |||||||||||
| Capacity factor | 93% | 93% | |||||||||
| GWh billed | 18,863 | 25,928 | |||||||||
| Average energy price ($/MWh) | $40.33 | $39.10 | |||||||||
| Average capacity price ($/kW-month) | $1.92 | $4.25 | |||||||||
| Refueling outage days: | |||||||||||
| Indian Point 3 | — | 29 | |||||||||
| Palisades | 52 | — | |||||||||
(a)The reduction in owned capacity is due to the shutdown of the 1,028 MW Indian Point 2 plant in April 2020.
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Other Income Statement Items
Utility
Other operation and maintenance expenses decreased from $2,563 million for 2019 to $2,478 million for 2020 primarily due to:
•a decrease of $42 million in nuclear generation expenses primarily due to lower nuclear labor costs, including contract labor, and a lower scope of work performed in 2020 as compared to 2019, in part as a result of the COVID-19 pandemic;
•a decrease of $25 million primarily due to contract costs in 2019 related to initiatives to explore new customer products and services;
•a decrease of $20 million in non-nuclear generation expenses due to a lower scope of work performed during plant outages in 2020 as compared to prior year, including a delay in plant outages as a result of the COVID-19 pandemic, and lower long-term service agreement expenses, partially offset by higher expenses associated with plants placed in service, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station), which began commercial operation in May 2019, the Choctaw Generating Station, which was purchased in October 2019, and the Lake Charles Power Station, which began commercial operation in March 2020;
•higher nuclear insurance refunds of $18 million; and
•an $11 million write-off in 2019 of specific costs related to the potential construction of scrubbers at the White Bluff plant at Entergy Arkansas. See Note 2 to the financial statements for discussion of the write-off.
The decrease was partially offset by:
•an increase of $10 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefits costs as a result of a decrease in the discount rate used to value the benefit liabilities, partially offset by lower incentive-based compensation accruals in 2020 as compared to prior year. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;
•an increase of $5 million primarily due to the 2019 deferral by Entergy New Orleans of costs related to its 2018 rate case and a system conversion for Algiers customers as a result of the 2018 combined rate case resolution approved by the City Council. See Note 2 to the financial statements for further discussion of the rate case resolution; and
•several individually insignificant items.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station), the Lake Charles Power Station, and the Choctaw Generating Station, and new depreciation rates at Entergy Mississippi, as approved by the MPSC.
Other regulatory charges (credits) - net for 2020 included a provision of $43.5 million to reflect the 2019 historical year netting adjustment included in the APSC’s December 2020 order in Entergy Arkansas’s 2020 formula rate plan proceeding. See Note 2 to the financial statements for discussion of Entergy Arkansas’s 2020 formula rate plan proceedings.
Other income decreased primarily due to:
•a decrease in the allowance for equity funds used during construction due to higher construction work in progress in 2019, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station) project and the Lake Charles Power Station project, partially offset by construction work in progress in 2020 related to the Montgomery County Power Station project; and
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•an increase in net periodic pension and other postretirement benefits non-service pension costs as a result of a decrease in the discount rate used to value the benefits liabilities. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.
The decrease was partially offset by changes in decommissioning trust fund activity.
Interest expense increased primarily due to:
•the issuances by Entergy Texas of $300 million in September 2019 and $175 million in March 2020 of 3.55% Series mortgage bonds;
•the issuances by Entergy Louisiana of $300 million of 4.20% Series mortgage bonds and $350 million of 2.90% Series mortgage bonds, each in March 2020, and $525 million of 4.20% Series mortgage bonds in March 2019;
•the issuances by Entergy Arkansas of $350 million of 4.20% Series mortgage bonds in March 2019 and $100 million of 4.0% Series mortgage bonds in March 2020; and
•the issuances by Entergy Mississippi of $135 million of 3.85% Series mortgage bonds in November 2019 and $170 million of 3.50% Series mortgage bonds in May 2020.
See Note 5 to the financial statements for a discussion of long-term debt.
Entergy Wholesale Commodities
Other operation and maintenance expenses decreased from $678 million for 2019 to $500 million for 2020 primarily due to:
•a decrease of $154 million resulting from the absence of expenses from the Pilgrim plant after it was shut down in May 2019 and the Indian Point 2 plant after it was shut down in April 2020; and
•a decrease of $23 million in severance and retention expenses. Severance and retention expenses were incurred in 2020 and 2019 due to management’s strategy to exit the Entergy Wholesale Commodities merchant power business.
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” below for a discussion of management’s strategy to shut down and sell all of the remaining plants in Entergy Wholesale Commodities’ merchant nuclear fleet. See Note 13 to the financial statements for further discussion of severance and retention expenses resulting from management’s strategy to shut down and sell all of the remaining plants in Entergy Wholesale Commodities’ merchant nuclear fleet. See Note 14 to the financial statements for further discussion of the sale of the Pilgrim plant.
Asset write-offs, impairments, and related charges for 2020 include impairment charges of $19 million ($15 million net-of-tax) primarily as a result of expenditures for capital assets. Asset write-offs, impairments, and related charges for 2019 include a loss of $190 million ($156 million net-of-tax) as a result of the sale of the Pilgrim plant in August 2019 and impairment charges of $100 million ($79 million net-of-tax) primarily related to nuclear refueling outage spending and expenditures for capital assets. These costs were charged to expense as incurred as a result of the impaired fair value of the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining estimated operating lives associated with management’s strategy to exit the Entergy Wholesale Commodities merchant power business. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” below for a discussion of management’s strategy to shut down and sell all of the remaining plants in Entergy Wholesale Commodities’ merchant nuclear fleet. See Note 14 to the financial statements for a discussion of the impairment of long-lived assets and the sale of the Pilgrim plant.
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Depreciation and amortization expenses decreased primarily due to the absence of depreciation expense from the Indian Point 2 plant, after it was shut down in April 2020.
Other income decreased primarily due to lower gains on decommissioning trust fund investments and a decrease in intercompany interest income resulting from repayment in second quarter 2020 of an intercompany loan to Entergy Corporation. See Notes 15 and 16 to the financial statements for a discussion of decommissioning trust fund investments.
Other expenses decreased primarily due to the absence of decommissioning expense from the Pilgrim plant, after it was sold in August 2019. See Note 14 to the financial statements for a discussion of the sale of the Pilgrim plant.
Parent and Other
Other income increased primarily due to the absence of the elimination of other income at Entergy Wholesale Commodities after repayment of an intercompany loan in second quarter 2020 and a $15 million charitable donation made in 2019 to fund the Entergy Charitable Foundation for three years.
Income Taxes
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.
The effective income tax rate for 2020 was (9.5%). The difference in the effective income tax rate versus the federal statutory rate of 21% was primarily due to completion of the 2014-2015 IRS audit effectively settling the tax positions for those years. See Note 3 to the financial statements for a discussion of the 2014-2015 IRS audit.
The effective income tax rate for 2019 was (15.6%). The difference in the effective income tax rate versus the federal statutory rate of 21% was primarily due to amortization of excess accumulated deferred income taxes, recognition of a deferred tax asset associated with a previously unrecognized net operating loss carryover, a charitable tax deduction, and the effects of restructuring transactions within Entergy Wholesale Commodities, partially offset by valuation allowances recorded against deferred tax assets associated with the disposition of Vermont Yankee and the carryover of business interest expense. See Notes 2 and 3 to the financial statements for a discussion of the effects and regulatory activity regarding the Tax Cuts and Jobs Act. See Note 3 to the financial statements for a discussion of the internal restructuring at Entergy Wholesale Commodities. See Note 14 to the financial statements for a discussion of the tax effects of the Vermont Yankee disposition.
2019 Compared to 2018
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, 2019 filed with the SEC on February 21, 2020 for discussion of results of operations for 2019 compared to 2018.
Entergy Wholesale Commodities Exit from the Merchant Power Business
Entergy Wholesale Commodities includes the ownership of the following nuclear reactors as of December 31, 2020:
| Location | Market | Capacity | Status | |||||||||||||||||||||||
| Indian Point 2 | Buchanan, NY | NYISO | 1,028 MW | Shut down in April 2020 | ||||||||||||||||||||||
| Indian Point 3 | Buchanan, NY | NYISO | 1,041 MW | Planned shutdown in April 2021 | ||||||||||||||||||||||
| Palisades | Covert, MI | MISO | 811 MW | Planned shutdown in May 2022 | ||||||||||||||||||||||
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Entergy sold its FitzPatrick plant to Exelon in March 2017 and, as discussed below, transferred its Vermont Yankee plant to NorthStar in January 2019 and sold its Pilgrim plant to Holtec in August 2019. The Palisades and Indian Point plants are under contract to be sold, subject to certain conditions, after they are shut down. Entergy also sold the Rhode Island State Energy Center, a natural gas-fired combined cycle generating plant, in December 2015.
These plant sales and contracts to sell are the result of a strategy that Entergy has undertaken to manage and reduce the risk of the Entergy Wholesale Commodities business, including exiting the merchant power business. Management evaluated the challenges for each of the plants based on a variety of factors such as their market for both energy and capacity, their size, their contracted positions, and the amount of investment required to continue to operate and maintain the safety and integrity of the plants, including the estimated asset retirement costs. Changes to current assumptions regarding the remaining operating life of a plant, the decommissioning timeline and process, or the length of time that Entergy will continue to own a plant could result in revisions to the asset retirement obligations and affect compliance with certain NRC minimum financial assurance requirements for meeting obligations to decommission the plants. Increases in the asset retirement obligations are likely to result in an increase in operating expense in the period of a revision. The possibility that a plant may have an operating life shorter than previously assumed could result in the need for additional contributions to decommissioning trust funds, or the posting of parent guarantees, letters of credit, or other surety mechanisms.
Entergy Wholesale Commodities also includes the ownership of two non-operating nuclear facilities, Big Rock Point in Michigan and Indian Point 1 in New York, that were acquired when Entergy purchased the Palisades and Indian Point 2 nuclear plants, respectively. Big Rock Point is under contract to be sold with the Palisades plant and Indian Point 1 is under contract to be sold with the Indian Point 2 and Indian Point 3 plants. In addition, Entergy Wholesale Commodities provides operations and management services, including decommissioning-related services, to nuclear power plants owned by non-affiliated entities in the United States. A relatively minor portion of the Entergy Wholesale Commodities business is the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.
Shutdown and Disposition of Vermont Yankee
On December 29, 2014, the Vermont Yankee plant ceased power production and entered its decommissioning phase. In November 2016, Entergy entered into an agreement to transfer 100% of the membership interests in Entergy Nuclear Vermont Yankee, LLC to a subsidiary of NorthStar. Entergy Nuclear Vermont Yankee was the owner of the Vermont Yankee plant. The transaction included the transfer of the nuclear decommissioning trust fund and the asset retirement obligation for the spent fuel management and decommissioning of the plant.
In March 2018, Entergy and NorthStar entered into a settlement agreement and a Memorandum of Understanding with State of Vermont agencies and other interested parties that set forth the terms on which the agencies and parties supported the Vermont Public Utility Commission’s approval of the transaction. The agreements provided additional financial assurance for decommissioning, spent fuel management and site restoration, and detailed the site restoration standards. In October 2018 the NRC issued an order approving the application to transfer Vermont Yankee’s license to NorthStar for decommissioning. In December 2018 the Vermont Public Utility Commission issued an order approving the transaction consistent with the Memorandum of Understanding’s terms. On January 11, 2019, Entergy and NorthStar closed the transaction.
Entergy Nuclear Vermont Yankee had an outstanding credit facility that was used to pay for dry fuel storage costs. This credit facility was guaranteed by Entergy Corporation. A subsidiary of Entergy assumed the obligations under the credit facility, and it remains outstanding. At the closing of the sale transaction, NorthStar caused Entergy Nuclear Vermont Yankee, renamed NorthStar Vermont Yankee, to issue a $139 million promissory note to the Entergy subsidiary that assumed the credit facility obligations. The amount of the note includes the
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balance outstanding on the credit facility, as well as borrowing fees and costs incurred by Entergy in connection with the credit facility.
With the receipt of the NRC and Vermont Public Utility Commission approvals and the resolution among the parties of the significant conditions of the sale, Entergy concluded that as of December 31, 2018 Vermont Yankee was in held for sale status. Entergy accordingly evaluated Vermont Yankee’s asset retirement obligation in light of the terms of the transaction and evaluated the remaining values of the Vermont Yankee assets. These evaluations resulted in an increase in the asset retirement obligation and $173 million of related asset impairment and other charges in the fourth quarter 2018. See Note 9 to the financial statements for additional discussion of the asset retirement obligation. See Note 14 to the financial statements for discussion of the closing of the Vermont Yankee transaction.
Shutdown and Sale of Pilgrim
In October 2015, Entergy determined that it would close the Pilgrim plant, and Pilgrim ceased operations in May 2019. See Note 14 to the financial statements for discussion of the impairment charges associated with the decision to cease operations earlier than expected.
On July 30, 2018, Entergy entered into a purchase and sale agreement with Holtec International to sell to a Holtec subsidiary 100% of the equity interests in Entergy Nuclear Generation Company, LLC, the owner of Pilgrim, for $1,000 (subject to adjustments for net liabilities and other amounts). On August 22, 2019, the NRC approved the transfer of Pilgrim’s facility licenses to Holtec. At that time, hearing requests filed by the Commonwealth of Massachusetts and Pilgrim Watch challenging Holtec’s financial qualifications and the sufficiency of the NRC’s review of the associated environmental impacts of the license transfer were pending with the NRC commissioners. The NRC approval order included a condition acknowledging the NRC’s longstanding authority to modify, condition, or rescind the license transfer order as a result of any hearing that may be conducted. On August 26, 2019, as permitted by the August 22 order, Entergy and Holtec closed the transaction.
On September 25, 2019, Massachusetts filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit, asking the court to vacate the NRC’s August 22 license transfer approval order and related approvals. On November 22, 2019, Entergy and Holtec filed a motion to dismiss Massachusetts’ petition; the NRC also filed a motion to dismiss on the same date. On January 22, 2020, Massachusetts filed a second petition with the D.C. Circuit asking the court to review the NRC’s December 17, 2019 order denying its stay motion. On June 16, 2020, Holtec and Massachusetts reached a settlement to resolve issues related to the Pilgrim transaction. Pursuant to the settlement agreement, Massachusetts withdrew its hearing request pending before the NRC and withdrew both of its petitions for review before the D.C. Circuit, thereby terminating Massachusetts’s pending legal challenges to the Pilgrim transfer. The NRC denied Pilgrim Watch’s hearing request in November 2020, and Pilgrim Watch did not file a judicial appeal of the NRC’s denial order.
The sale of Entergy Nuclear Generation Company, LLC to Holtec included the transfer of the nuclear decommissioning trust and obligation for spent fuel management and plant decommissioning. The transaction resulted in a loss of $190 million ($156 million net-of-tax) in 2019. See Note 14 to the financial statements for discussion of the closing of the Pilgrim transaction.
Planned Shutdown and Sale of Indian Point 2 and Indian Point 3
In April 2007, Entergy submitted to the NRC a joint application to renew the operating licenses for Indian Point 2 and Indian Point 3 for an additional 20 years. In January 2017, Entergy reached a settlement with New York State, several State agencies, and Riverkeeper, Inc., under which Indian Point 2 and Indian Point 3 would cease commercial operation by April 30, 2020 and April 30, 2021, respectively, subject to certain conditions, including New York State’s withdrawal of opposition to Indian Point’s license renewals and issuance of contested permits and similar authorizations. Operations could be extended up to four additional years for each unit by
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mutual agreement of Entergy and New York State based on an exigent reliability need for Indian Point generation. In September 2018 the NRC issued renewed operating licenses for Indian Point 2 through April 2024 and for Indian Point 3 through April 2025. Pursuant to the January 2017 settlement agreement, Indian Point 2 ceased commercial operations on April 30, 2020, and Indian Point 3 is expected to cease commercial operations on April 30, 2021. See Note 14 to the financial statements for discussion of the impairment charges associated with the decision to shut down the Indian Point plants.
Other provisions of the settlement include termination of all then-existing investigations of Indian Point by the parties to the agreement, which include the New York State Department of Environmental Conservation, the New York State Department of State, the New York State Department of Public Service, the New York State Department of Health, and the New York State Attorney General. The settlement recognizes the right of New York State agencies to pursue new investigations and enforcement actions with respect to new circumstances or existing conditions that become materially exacerbated.
Another provision of the settlement obligates Entergy to establish a $15 million fund for environmental projects and community support. Apportionment and allocation of funds to beneficiaries are to be determined by mutual agreement of New York State and Entergy. The settlement recognizes New York State’s right to perform an annual inspection of Indian Point, with scope and timing to be determined by mutual agreement.
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 has been shut down and defueled, to a Holtec subsidiary for decommissioning the plants. The sale will include the transfer of the licenses, spent fuel, decommissioning liabilities, and nuclear decommissioning trusts for the three units.
The transaction is subject to closing conditions, including approval from the NRC. In November 2019, Entergy and Holtec submitted a license transfer application to the NRC. The NRC issued an order approving the application in November 2020, subject to the NRC’s authority to condition, revise, or rescind the approval order based on the resolution of four pending hearing requests. A substantially identical condition was imposed in the NRC’s August 2019 order approving the license transfer for Pilgrim. In January 2021 the NRC issued an order denying all four hearing requests challenging the license transfer application. In January 2021, New York State filed a petition for review with the D.C. Circuit asking the court to vacate the NRC’s January 2021 order denying the State’s hearing request, as well as the NRC’s November 2020 order approving the license transfers. In January 2021 the D.C. Circuit issued a scheduling order, setting deadlines for initial procedural filings in March 2021. Any other petitioners seeking judicial review of the January 2021 NRC order must file their petitions by March 16, 2021.
Entergy and Holtec also submitted a petition to the New York State Public Service Commission in November 2019 seeking an order from the New York Public Service Commission disclaiming jurisdiction or abstaining from review of the transaction or, alternatively, approving the transaction. Closing is also conditioned on obtaining from the New York State Department of Environmental Conservation an agreement related to Holtec’s decommissioning plan as being consistent with applicable standards. The transaction closing is targeted for May 2021, following the defueling of Indian Point 3.
As consideration for the transfer to Holtec of its interest in Indian Point, Entergy will receive nominal cash consideration. The Indian Point transaction is expected to result in a loss based on the difference between Entergy’s adjusted net investment in the subsidiaries at closing and the sale price net of any agreed adjustments. As of December 31, 2020, Entergy’s adjusted net investment in the Indian Point units was $255 million. The primary variables in the ultimate loss that Entergy will incur are the values of the nuclear decommissioning trusts and the asset retirement obligations at closing, the financial results from plant operations until the closing, and the level of any unrealized deferred tax balances at closing. The terms of the transaction include limitations on withdrawals from the nuclear decommissioning trusts to fund decommissioning activities and controls on how Entergy manages the investment of nuclear decommissioning trust assets between signing and closing; however, the agreement does not require a minimum level of funding in the nuclear decommissioning trusts as a condition to closing.
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Planned Shutdown and Sale of Palisades
Almost all of the Palisades output is sold under a power purchase agreement with Consumers Energy, entered into when the plant was acquired in 2007, that is scheduled to expire in 2022. The PPA prices currently exceed market prices. In December 2016, Entergy reached an agreement with Consumers Energy to amend the existing PPA to terminate early, on May 31, 2018. Pursuant to the agreement to amend the PPA, Consumers Energy would pay Entergy $172 million for the early termination of the PPA. The PPA amendment agreement was subject to regulatory approvals, including approval by the Michigan Public Service Commission. Separately, Entergy intended to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle.
In September 2017 the Michigan Public Service Commission issued an order conditionally approving the PPA amendment transaction, but only granting Consumers Energy recovery of $136.6 million of the $172 million requested early termination payment. As a result, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy continues to operate Palisades under the existing PPA with Consumers Energy, instead of shutting down in the fall of 2018 as previously planned. Entergy intends to shut down the Palisades nuclear power plant permanently no later than May 31, 2022. As a result of the increase in the expected operating life of the plant, the expected probability-weighted undiscounted net cash flows as of September 30, 2017 exceeded the carrying value of the plant and related assets. Accordingly, nuclear fuel spending, nuclear refueling outage spending, and expenditures for capital assets incurred at Palisades after September 30, 2017 are no longer charged to expense as incurred, but recorded as assets and depreciated or amortized, subject to the typical periodic impairment reviews prescribed in the accounting rules.
On July 30, 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. The sale will include the transfer of the nuclear decommissioning trust and obligation for spent fuel management and plant decommissioning. In February 2020 the parties signed an amendment to the purchase and sale agreement to remove the closing condition that the nuclear decommissioning trust fund must have a specified amount and Entergy agreed to contribute $20 million to the nuclear decommissioning trust fund at closing, among other amendments. At the closing of the sale transaction, the Holtec subsidiary will pay $1,000 (subject to adjustment for net liabilities and other amounts) for the equity interests in the subsidiary that owns Palisades and the Big Rock Point Site.
The Palisades transaction is subject to certain closing conditions, including: the permanent shutdown of Palisades and the transfer of all nuclear fuel from the reactor vessel to the spent nuclear fuel pool; NRC regulatory approval for the transfer of the Palisades and Big Rock Point operating and independent spent fuel storage installation licenses; receipt of a favorable private letter ruling from the IRS; and, the Pilgrim transaction having closed. 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 has indicated that it expects to complete its review of the application by January 2022. In February 2021 the Michigan Attorney General; the Environmental Law & Policy Center; and Beyond Nuclear, Michigan Safe Energy Future, and Don’t Waste Michigan filed with the NRC petitions to intervene and requests for hearing challenging the license transfer application.
Subject to the above conditions, the Palisades transaction is expected to close by the end of 2022. As of December 31, 2020, Entergy’s adjusted net investment in Palisades was $75 million. The primary variables in the ultimate loss or gain that Entergy will incur on the transaction are the values of the nuclear decommissioning trust and the asset retirement obligations at closing, the financial results from plant operations until the closing, and the level of any unrealized deferred tax balances at closing. Palisades completed its final refueling outage in October 2020.
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Costs Associated with Exit of the Entergy Wholesale Commodities Business
Entergy incurred approximately $71 million in costs in 2020, $91 million in costs in 2019, and $139 million in costs in 2018 associated with management’s strategy to exit the Entergy Wholesale Commodities merchant power business, primarily employee retention and severance expenses and other benefits-related costs, and contracted economic development contributions. Entergy expects to incur employee retention and severance expenses of approximately $40 million in 2021 and $15 million in 2022 associated with the exit from the merchant power business. See Note 13 to the financial statements for further discussion of these costs.
Entergy Wholesale Commodities incurred $19 million in 2020, $100 million in 2019, and $532 million in 2018 of impairment charges related to nuclear fuel spending, nuclear refueling outage spending, expenditures for capital assets, and asset retirement obligation revisions. These costs were charged to expense as incurred as a result of the impaired value of certain of the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining estimated operating lives associated with management’s strategy to exit the Entergy Wholesale Commodities merchant power business. Entergy expects to continue to charge Indian Point Energy Center capital asset costs to expense as incurred because Entergy expects its value to continue to be impaired. See Note 14 to the financial statements for further discussion of the impairment charges.
Liquidity and Capital Resources
This section discusses Entergy’s capital structure, capital spending plans and other uses of capital, sources of capital, and the cash flow activity presented in the cash flow statement.
Capital Structure
Entergy’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio is primarily due to the net issuance of debt in 2020. See Note 5 to the financial statements for a discussion of long-term debt.
| December 31, 2020 | December 31, 2019 | ||||||||||
| Debt to capital | 68.3% | 65.5% | |||||||||
| Effect of excluding securitization bonds | (0.2%) | (0.4%) | |||||||||
| Debt to capital, excluding securitization bonds (a) | 68.1% | 65.1% | |||||||||
| Effect of subtracting cash | (1.7%) | (0.5%) | |||||||||
| Net debt to net capital, excluding securitization bonds (a) | 66.4% | 64.6% | |||||||||
(a)Calculation excludes the Arkansas, Louisiana, New Orleans, and Texas securitization bonds, which are non-recourse to Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas, respectively.
21.4% of the debt outstanding at December 31, 2020 is at the parent company, Entergy Corporation, 78.0% is at the Utility, and 0.6% is at Entergy Wholesale Commodities. 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, common shareholders’ equity, and subsidiaries’ preferred stock without sinking fund. Net capital consists of capital less cash and cash equivalents. 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.
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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, 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, 2020. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2020. 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 | 2021 | 2022 | 2023 | 2024-2025 | after 2025 | |||||||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||||||||
| Utility | $1,761 | $1,166 | $2,938 | $2,800 | $20,943 | |||||||||||||||||||||||||||
| Entergy Wholesale Commodities | 142 | — | — | — | — | |||||||||||||||||||||||||||
| Parent and Other | 99 | 737 | 73 | 1,102 | 2,589 | |||||||||||||||||||||||||||
| Total | $2,002 | $1,903 | $3,011 | $3,902 | $23,532 | |||||||||||||||||||||||||||
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 September 2024. 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, 2020 was 2.35% on the drawn portion of the facility.
As of December 31, 2020, amounts outstanding and capacity available under the $3.5 billion credit facility are:
| Capacity | Borrowings | Letters of Credit | Capacity Available | |||||||||||||||||
| (In Millions) | ||||||||||||||||||||
| $3,500 | $165 | $6 | $3,329 | |||||||||||||||||
A covenant in Entergy Corporation’s credit facility requires 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. One such difference is that it excludes the effects, among other things, of certain impairments related to the Entergy Wholesale Commodities nuclear generation assets. 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 or one of the Utility operating companies (except Entergy New Orleans) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the Entergy Corporation credit facility’s maturity date may occur.
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Entergy Corporation has a commercial paper program with a Board-approved program limit of up to $2 billion. As of December 31, 2020, Entergy Corporation had $1.627 billion of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2020 was 1.39%.
Finance lease obligations are a minimal part of Entergy’s overall capital structure. Following are Entergy’s payment obligations under those leases.
| 2021 | 2022 | 2023 | 2024-2025 | after 2025 | |||||||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||||||||
| Finance lease payments | $14 | $13 | $12 | $18 | $17 | ||||||||||||||||||||||||
Leases are discussed in Note 10 to the financial statements.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2020 as follows:
| Company | Expiration Date | Amount of Facility | Interest Rate (a) | Amount Drawn as of December 31, 2020 | Letters of Credit Outstanding as of December 31, 2020 | |||||||||||||||||||||||||||
| Entergy Arkansas | April 2021 | $25 million (b) | 1.27% | — | — | |||||||||||||||||||||||||||
| Entergy Arkansas | September 2024 | $150 million (c) | 1.27% | — | — | |||||||||||||||||||||||||||
| Entergy Louisiana | September 2024 | $350 million (c) | 1.27% | — | — | |||||||||||||||||||||||||||
| Entergy Mississippi | April 2021 | $10 million (d) | 1.65% | — | — | |||||||||||||||||||||||||||
| Entergy Mississippi | April 2021 | $35 million (d) | 1.65% | — | — | |||||||||||||||||||||||||||
| Entergy Mississippi | April 2021 | $37.5 million (d) | 1.65% | — | — | |||||||||||||||||||||||||||
| Entergy New Orleans | November 2021 | $25 million (c) | 1.42% | — | $0.8 million | |||||||||||||||||||||||||||
| Entergy Texas | September 2024 | $150 million (c) | 1.65% | — | $1.3 million | |||||||||||||||||||||||||||
(a)The interest rate is the estimated interest rate as of December 31, 2020 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.
(d)Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option.
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.
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In addition, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each entered into one or more uncommitted standby letter of credit facilities as a means to post collateral to support its obligations to MISO. Following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2020:
| Company | Amount of Uncommitted Facility | Letter of Credit Fee | Letters of Credit Issued as of December 31, 2020 (a) (b) | ||||||||||||||||||||
| Entergy Arkansas | $25 million | 0.78% | $1 million | ||||||||||||||||||||
| Entergy Louisiana | $125 million | 0.78% | $2.2 million | ||||||||||||||||||||
| Entergy Mississippi | $65 million | 0.78% | $1 million | ||||||||||||||||||||
| Entergy New Orleans | $15 million | 1.00% | $1 million | ||||||||||||||||||||
| Entergy Texas | $50 million | 0.70% | $6.2 million | ||||||||||||||||||||
(a)As of December 31, 2020, letters of credit posted with MISO covered financial transmission right exposure of $0.3 million for Entergy Louisiana, $0.2 million for Entergy Mississippi, $0.2 million for Entergy New Orleans, and $0.5 million for Entergy Texas. See Note 15 to the financial statements for discussion of financial transmission rights.
(b)As of December 31, 2020, in addition to the $1 million MISO letter of credit, Entergy Mississippi has $1 million of non-MISO letters of credit outstanding under this facility.
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, 2020 on non-cancelable operating leases with a term over one year:
| 2021 | 2022 | 2023 | 2024-2025 | after 2025 | |||||||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||||||||
| Operating lease payments | $66 | $57 | $47 | $59 | $21 | ||||||||||||||||||||||||
Leases are discussed in Note 10 to the financial statements.
Summary of Contractual Obligations of Consolidated Entities
| Contractual Obligations | 2021 | 2022-2023 | 2024-2025 | after 2025 | Total | |||||||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||||||||
| Long-term debt (a) | $2,002 | $4,914 | $3,902 | $23,532 | $34,350 | |||||||||||||||||||||||||||
| Finance lease payments (b) | $14 | $25 | $18 | $17 | $74 | |||||||||||||||||||||||||||
| Operating leases (b) (c) | $66 | $104 | $59 | $21 | $250 | |||||||||||||||||||||||||||
| Purchase obligations (d) | $1,182 | $2,076 | $1,651 | $3,541 | $8,450 | |||||||||||||||||||||||||||
(a)Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.
(b)Lease obligations are discussed in Note 10 to the financial statements.
(c)Does not include power purchase agreements that are accounted for as leases that are included in purchase obligations.
(d)Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. Almost all of the total are fuel and purchased power obligations.
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In addition to the contractual obligations stated above, Entergy currently expects to contribute approximately $356 million to its pension plans and approximately $39.9 million to other postretirement plans in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy has $979 million of unrecognized tax benefits and interest net of unused tax attributes 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.
Capital Expenditure Plans and Other Uses of Capital
Following are the amounts of Entergy’s planned construction and other capital investments by operating segment for 2021 through 2023.
| Planned construction and capital investments | 2021 | 2022 | 2023 | |||||||||||||||||
| (In Millions) | ||||||||||||||||||||
| Utility: | ||||||||||||||||||||
| Generation | $1,080 | $1,155 | $2,030 | |||||||||||||||||
| Transmission | 720 | 610 | 675 | |||||||||||||||||
| Distribution | 1,180 | 1,350 | 1,560 | |||||||||||||||||
| Utility Support | 495 | 440 | 335 | |||||||||||||||||
| Total | 3,475 | 3,555 | 4,600 | |||||||||||||||||
| Entergy Wholesale Commodities and Other | 10 | 5 | 5 | |||||||||||||||||
| Total | $3,485 | $3,560 | $4,605 | |||||||||||||||||
In addition to the planned spending in the table above, the Utility also expects to pay for $1,055 million of capital investments in 2021 related to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration work that have been accrued as of December 31, 2020.
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 renewables and other generation, including the Sunflower Solar Facility, Searcy Solar Facility, Walnut Bend Solar Facility, West Memphis Solar Facility, Liberty County Solar Facility, and Hardin County Peaking Facility, and potential construction of additional generation.
•Investments in Entergy’s Utility nuclear fleet.
•Transmission spending to enhance reliability, reduce congestion, and enable economic growth.
•Distribution spending to enhance reliability and improve service to customers, including investment to support advanced metering.
•Entergy Wholesale Commodities investments such as component replacements, software and security, and dry cask storage.
For the next several years, the Utility’s owned generating capacity is projected to be adequate to meet MISO reserve requirements; however, in the longer-term additional supply resources will be needed, and its supply plan initiative
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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 also subject to periodic review and modification and may vary based on the ongoing effects of business restructuring, regulatory constraints and requirements, environmental regulations, business opportunities, market volatility, economic trends, changes in project plans, and the ability to access capital.
Renewables
Sunflower Solar Facility
In November 2018, Entergy Mississippi announced that it signed an agreement for the purchase of an approximately 100 MW solar photovoltaic facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. The estimated base purchase price is approximately $138.4 million. The estimated total investment, including the base purchase price and other related costs, for Entergy Mississippi to acquire the Sunflower Solar Facility is approximately $153.2 million. The purchase is contingent upon, among other things, obtaining necessary approvals, including full cost recovery, from applicable federal and state regulatory and permitting agencies. The project is being built by Sunflower County Solar Project, LLC, an indirect subsidiary of Recurrent Energy, LLC. Entergy Mississippi will purchase the facility upon mechanical completion and after the other purchase contingencies have been met. In December 2018, Entergy Mississippi filed a joint petition with Sunflower Solar Project with the MPSC for Sunflower Solar Project to construct and for Entergy Mississippi to acquire and thereafter own, operate, improve, and maintain the solar facility. Entergy Mississippi proposed revisions to its formula rate plan that would provide for a mechanism, the interim capacity rate adjustment mechanism, in the formula rate plan to recover the non-fuel related costs of additional owned capacity acquired by Entergy Mississippi, including the annual ownership costs of the Sunflower Solar Facility. In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to provide for an interim capacity rate adjustment mechanism. Recovery through the interim capacity rate adjustment requires MPSC approval for each new resource. In August 2019 consultants retained by the Mississippi Public Utilities Staff filed a report expressing concerns regarding the project economics. In March 2020, Entergy Mississippi filed supplemental testimony addressing questions and observations raised by the consultants retained by the Mississippi Public Utilities Staff and proposing an alternative structure for the transaction that would reduce its cost. A hearing before the MPSC was held in March 2020. In April 2020 the MPSC issued an order approving certification of the Sunflower Solar Facility and its recovery through the interim capacity rate adjustment mechanism, subject to certain conditions including: (i) that Entergy Mississippi pursue a 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. Closing is targeted to occur by the end of 2021.
Searcy Solar Facility
In March 2019, Entergy Arkansas announced that it signed an agreement for the purchase of an approximately 100 MW solar energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. The purchase is contingent upon, among other things, obtaining necessary approvals from applicable federal and state regulatory and permitting agencies. The project is being constructed by a subsidiary of NextEra Energy Resources. Entergy Arkansas will purchase the facility upon mechanical completion and after the other purchase contingencies have been met. Closing is expected to occur by the end of 2021. In May 2019, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. In September 2019 other parties filed testimony largely supporting the resource acquisition but disputing Entergy Arkansas’s proposed method of cost recovery. Entergy Arkansas filed its rebuttal testimony in October 2019. In February 2020, Entergy Arkansas, the Attorney General, and the APSC general staff filed a partial settlement agreement asking the APSC to approve, based on the record in the proceeding, all issues except certain issues that are submitted to the APSC for determination. In April 2020 the APSC issued an order
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approving Entergy Arkansas’s acquisition of the Searcy Solar facility as being in the public interest, but declined to approve Entergy Arkansas’s preferred cost recovery rider mechanism, finding instead, based on the particular facts and circumstances presented, that the formula rate plan rider was a sufficient recovery mechanism for this resource.
Liberty County Solar Facility
In September 2020, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to acquire the 100 MW Liberty County Solar Facility and a determination that Entergy Texas’s acquisition of the facility through a tax equity partnership is in the public interest. In its preliminary order, the PUCT determined that, in considering Entergy Texas’s application, it would not specifically address whether Entergy Texas’s use of a tax equity partnership is in the public interest. A procedural schedule was established with a hearing on the merits scheduled in April 2021. Closing is expected to occur in 2023.
Walnut Bend Solar Facility
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 requested a decision by the APSC by June 15, 2021 and primarily requests cost recovery through the formula rate plan rider. A procedural schedule was established with a hearing scheduled in April 2021. Closing is expected to occur in 2022.
West Memphis Solar Facility
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. Entergy Arkansas requested a decision by the APSC by September 7, 2021 and primarily requests cost recovery through the formula rate plan rider. Closing is expected to occur in 2023.
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 operating segment and the Parent and Other portion of the business, financial strength, and future investment opportunities. At its January 2021 meeting, the Board declared a dividend of $0.95 per share. Entergy paid $748 million in 2020, $712 million in 2019, and $648 million in 2018 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, 2020, $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.
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Sources of Capital
Entergy’s sources to meet its capital requirements and to fund potential investments include:
•internally generated funds;
•cash on hand ($1,759 million as of December 31, 2020);
•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.
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, Entergy Texas, and System Energy are effective through July 2022. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2022. Entergy New Orleans also has obtained long-term financing authorization from the City Council that extends through July 2022. Entergy Arkansas, Entergy Louisiana, and System Energy each have obtained long-term financing authorization from the FERC that extends through July 2022 for issuances by the nuclear fuel company variable interest entities. 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 and the other internal borrowing arrangements are inter-company borrowing arrangements 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
Entergy Corporation currently expects to issue approximately $2.5 billion of equity through 2024. Entergy is considering various methods, including, among others, at the market distributions, block trades, and preferred equity issuances. In January 2021, Entergy entered into an equity distribution sales agreement with several counterparties establishing an at the market equity distribution program, pursuant to which Entergy 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 common stock, Entergy may also enter into forward sale agreements for the sale of its
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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 $1 billion.
Cash Flow Activity
As shown in Entergy’s Consolidated Statements of Cash Flows, cash flows for the years ended December 31, 2020, 2019, and 2018 were as follows:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Millions) | |||||||||||||||||
| Cash and cash equivalents at beginning of period | $426 | $481 | $781 | ||||||||||||||
| Net cash provided by (used in): | |||||||||||||||||
| Operating activities | 2,690 | 2,817 | 2,385 | ||||||||||||||
| Investing activities | (4,772) | (4,510) | (4,106) | ||||||||||||||
| Financing activities | 3,415 | 1,638 | 1,421 | ||||||||||||||
| Net increase (decrease) in cash and cash equivalents | 1,333 | (55) | (300) | ||||||||||||||
| Cash and cash equivalents at end of period | $1,759 | $426 | $481 | ||||||||||||||
2020 Compared to 2019
Operating Activities
Net cash flow provided by operating activities decreased by $127 million in 2020 primarily due to:
•an increase of $224 million in storm spending in 2020 as compared to 2019 primarily due to spending in 2020 on Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration. See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of storm restoration efforts;
•the timing of recovery of fuel and purchased power costs in 2020 as compared to the prior year. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;
•lower collections of receivables from customers, in part due to the COVID-19 pandemic;
•the effect of less favorable weather on billed Utility sales in 2020; and
•an increase of $32 million in incentive-based compensation payments in 2020.
The decrease was partially offset by:
•the decrease in the return of unprotected excess accumulated deferred income taxes to Utility customers. See Note 2 to the financial statements for a discussion of the regulatory activity regarding the Tax Cuts and Jobs Act;
•a decrease of $86 million in severance and retention payments in 2020 as compared to 2019. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” above for a discussion of management’s strategy to exit the Entergy Wholesale Commodities’ merchant power business;
•a decrease of $83 million in pension contributions in 2020 as compared to 2019. See “Critical Accounting Estimates” below and Note 11 to the financial statements for discussion of qualified pension and other postretirement benefits funding;
•an increase of $71 million in proceeds received from the DOE 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;
•a decrease of $34 million in spending on nuclear refueling outages; and
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•an increase of $25 million of nuclear insurance refunds.
Investing Activities
Net cash flow used in investing activities increased by $262 million in 2020 primarily due to:
•an increase of $942 million in storm spending in 2020, primarily on Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration. See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of storm restoration efforts;
•the purchase of Washington Parish Energy Center by Entergy Louisiana in November 2020 for approximately $222 million. See Note 14 to the financial statements for further discussion of the Washington Parish Energy Center purchase;
•an increase of $140 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of the distribution system, including increased spending on advanced metering infrastructure;
•an increase of $87 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;
•an increase of $43 million primarily due to changes in collateral posted to provide credit support to secure its obligations under agreements to sell power produced by Entergy Wholesale Commodities’ power plants; and
•$25 million in plant upgrades for the Choctaw Generating Station in March 2020. See Note 14 to the financial statements for discussion of the Choctaw Generating Station purchase.
The increase was partially offset by:
•a decrease of $309 million of non-nuclear generation construction expenditures primarily due to higher spending in 2019 on the Montgomery County Power Station, Lake Charles Power Station, and J. Wayne Leonard Power Station (formerly St. Charles Power Station) projects;
•the purchase of the Choctaw Generating Station in October 2019 for approximately $305 million;
•an increase of $303 million in net receipts from storm reserve escrow accounts;
•a decrease of $141 million in transmission construction expenditures primarily due to the timing of work performed in 2020 as compared to 2019;
•an increase of $70 million in proceeds received from the DOE in 2020 as compared to the prior year resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;
•a decrease of $44 million in information technology construction expenditures primarily due to decreased spending on various technology projects; and
•a decrease of $23 million in nuclear construction expenditures primarily due to a lower scope of work performed on various nuclear projects in 2020 as compared to 2019.
Financing Activities
Net cash flow provided by financing activities increased by $1,777 million in 2020 primarily due to:
•long-term debt activity providing approximately $4,467 million of cash in 2020 compared to providing approximately $1,685 million in 2019; and
•the repurchase in first quarter 2019 of $50 million of Class A mandatorily redeemable preferred membership units in Entergy Holdings Company LLC, a wholly-owned Entergy subsidiary, that were held by a third party.
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The increase was partially offset by:
•proceeds of $608 million from the issuance of common stock in May 2019 as a result of the settlement of equity forwards. See Note 7 to the financial statements for discussion of the equity forward sale agreements;
•an increase of $324 million in net repayments of commercial paper in 2020 compared to 2019;
•a decrease of $52 million in treasury stock issuances in 2020 due to a larger amount of previously repurchased Entergy Corporation common stock issued in 2019 to satisfy stock option exercises;
•an increase of $37 million in common stock dividends paid as a result of an increase in the number of shares outstanding and an increase in the dividend paid per share in 2020 compared to 2019; and
•the issuance of $35 million aggregate liquidation value 5.375% Series A preferred stock in September 2019 by Entergy Texas.
For the details of Entergy’s commercial paper program, see Note 4 to the financial statements. See Note 5 to the financial statements for details of long-term debt.
2019 Compared to 2018
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, 2019 filed with the SEC on February 21, 2020 for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
Rate, Cost-recovery, and Other Regulation
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that the Utility operating companies charge for their services significantly influence Entergy’s financial position, results of operations, and liquidity. These companies are regulated and the rates charged to their customers are determined in regulatory proceedings. Governmental agencies, including the APSC, the LPSC, the MPSC, the City Council, and the PUCT, are primarily responsible for approval of the rates charged to customers. Following is a summary of the Utility operating companies’ authorized returns on common equity:
| Company | Authorized Return on Common Equity | |||||||
| Entergy Arkansas | 9.25% - 10.25% | |||||||
| Entergy Louisiana | 9.2% - 10.4% Electric; 9.3% - 10.3% Gas | |||||||
| Entergy Mississippi | 8.89% - 10.93% | |||||||
| Entergy New Orleans | 8.85% - 9.85% | |||||||
| Entergy Texas | 9.65% | |||||||
The Utility operating companies’ base rate, fuel and purchased power cost recovery, and storm cost recovery proceedings are discussed in Note 2 to the financial statements.
Federal Regulation
The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including rates for System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy 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 operating companies’ retail regulators. The current return on equity under the Unit Power Sales Agreement is 10.94%. Prior to each operating company’s termination of participation in the System Agreement (Entergy
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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 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 challenging System Energy’s return on equity and capital structure, System Energy’s treatment of uncertain tax positions and the Grand Gulf sale leaseback arrangement, and a separate request for the FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement.
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 the Entergy Wholesale Commodities business.
•The interest rate and equity price risk associated with Entergy’s investments in pension and other postretirement benefit trust funds. See Note 11 to the financial statements for details regarding Entergy’s pension and other postretirement benefit trust funds.
•The interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds, particularly in the Entergy Wholesale Commodities business. 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.
Commodity Price Risk
Power Generation
As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy in the day ahead or spot markets. Entergy Wholesale Commodities also sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both. In addition to its forward physical power contracts, Entergy Wholesale Commodities may also use a combination of financial contracts,
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including swaps, collars, and options, to manage forward commodity price risk. The sensitivities may not reflect the total maximum upside potential from higher market prices. The information contained in the following table represents projections at a point in time and will vary over time based on numerous factors, such as future market prices, contracting activities, and generation. Following is a summary of Entergy Wholesale Commodities’ current forward capacity and generation contracts as well as total revenue projections based on market prices as of December 31, 2020.
Entergy Wholesale Commodities Nuclear Portfolio
| 2021 | 2022 | |||||||||||||
| Energy | ||||||||||||||
| Percent of planned generation under contract (a): | ||||||||||||||
| Unit-contingent (b) | 98% | 99% | ||||||||||||
| Planned generation (TWh) (c) (d) | 9.6 | 2.8 | ||||||||||||
| Average revenue per MWh on contracted volumes: | ||||||||||||||
| Expected based on market prices as of December 31, 2020 | $54.5 | $47.1 | ||||||||||||
| Capacity | ||||||||||||||
| Percent of capacity sold forward (e): | ||||||||||||||
| Bundled capacity and energy contracts (f) | 68% | 97% | ||||||||||||
| Capacity contracts (g) | 29% | —% | ||||||||||||
| Total | 97% | 97% | ||||||||||||
| Planned net MW in operation (average) (d) | 1,158 | 338 | ||||||||||||
| Average revenue under contract per kW per month (applies to capacity contracts only) | $0.1 | $— | ||||||||||||
| Total Energy and Capacity Revenues (h) | ||||||||||||||
| Expected sold and market total revenue per MWh | $54.0 | $46.8 | ||||||||||||
| Sensitivity: -/+ $10 per MWh market price change | $53.8 - $54.2 | $46.7 - $47.0 | ||||||||||||
(a)Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts, or options that mitigate price uncertainty. Positions that are not classified as hedges are netted in the planned generation under contract.
(b)Transaction under which power is supplied from a specific generation asset; if the asset is not operating, the seller is generally not liable to the buyer for any damages. Certain unit-contingent sales include a guarantee of availability. Availability guarantees provide for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of Entergy’s outstanding guarantees of availability provide for dollar limits on Entergy’s maximum liability under such guarantees.
(c)Amount of output expected to be generated by Entergy Wholesale Commodities nuclear resources considering plant operating characteristics and outage schedules.
(d)Assumes the planned shutdown of Indian Point 3 on April 30, 2021 and planned shutdown of Palisades on May 31, 2022. For a discussion regarding the planned shutdown of the Indian Point 3 and Palisades plants, see “Entergy Wholesale Commodities Exit from the Merchant Power Business” above.
(e)Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions.
(f)A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold.
(g)A contract for the sale of an installed capacity product in a regional market.
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(h)Includes assumptions on converting a portion of the portfolio to contracted with fixed price and excludes non-cash revenue from the amortization of the Palisades below-market purchased power agreement, mark-to-market activity, and service revenues.
Some of the agreements to sell the power produced by Entergy Wholesale Commodities’ power plants contain provisions that require an Entergy subsidiary to provide credit support to secure its obligations under the agreements. The Entergy subsidiary is required to provide credit support based upon the difference between the current market prices and contracted power prices in the regions where Entergy Wholesale Commodities sells power. 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, 2020, based on power prices at that time, Entergy had liquidity exposure of $62 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $6 million of posted cash collateral. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2020, Entergy would have been required to provide approximately $30 million of additional cash or letters of credit under some of the agreements. As of December 31, 2020, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $22 million for a $1 per MMBtu increase in gas prices in both the short- and long-term markets.
As of December 31, 2020, substantially all the credit exposure associated with the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 2022 is with counterparties or their guarantors that have public investment grade credit ratings.
Nuclear Matters
Entergy’s Utility and Entergy Wholesale Commodities businesses include the ownership and operation of nuclear generating plants and are, 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 like stress corrosion cracking of certain materials within the plant systems 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 an expected challenge to the prudence of operations at Grand Gulf; the implementation of plans to exit the Entergy Wholesale Commodities merchant power business by 2022 and the post-shutdown decommissioning of these 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 and types of insurance commercially available 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, and “multiple/repetitive degraded cornerstone column,” or Column 4. 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. Nuclear generating
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plants owned and operated by Entergy’s Utility and Entergy Wholesale Commodities businesses are currently in Column 1, except for Grand Gulf, which is in Column 2.
In November 2020 the NRC placed Grand Gulf in Column 2 based on the incidence of three unplanned plant scrams during the second and third quarters of 2020. Two of the scram events related to new turbine control system components that failed, and a third related to a feedwater valve positioner that failed, all of which had been replaced in a refueling outage that ended in May 2020. The NRC plans to conduct a supplemental inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 2. As a consequence of two additional Grand Gulf scrams during the fourth quarter 2020, System Energy expects Grand Gulf to be placed into Column 3 based on plant performance indicators for the four quarters ended December 31, 2020. This will involve an additional supplemental NRC inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 3.
Critical Accounting Estimates
The preparation of Entergy’s financial statements in conformity with generally accepted accounting principles 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
Entergy subsidiaries own nuclear generation facilities in both the Utility and Entergy Wholesale Commodities operating segments. Regulations require 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 6% to 18%. 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
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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. For the non-rate-regulated portions of Entergy’s business for which the plant’s value is impaired, these reductions will immediately reduce operating expenses in the period of the revision if the reduction of the liability exceeds the amount of the undepreciated plant asset at the date of the revision. 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. For a plant in the non-rate-regulated portions of Entergy’s business for which the plant’s value is impaired, however, including a plant that is shutdown, or is nearing its shutdown date, the increase in the liability is likely to immediately increase operating expense in the period of the revision and not increase the asset retirement cost asset. See Note 14 to the financial statements for further discussion of impairment of long-lived assets and Note 9 to the financial statements for further discussion of asset retirement obligations.
Utility Regulatory Accounting
Entergy’s Utility operating companies and System Energy are subject to retail regulation by their respective state and local regulators and to wholesale regulation by the FERC. Because these regulatory agencies set the rates the Utility operating companies and System Energy are allowed to charge customers based on allowable costs, including a reasonable return on equity, the Utility operating companies and System Energy apply accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs that have been deferred because it is probable such amounts will be returned to customers through future regulated rates. 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
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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.
Impairment of Long-lived Assets
Entergy has significant investments in long-lived assets in both of its operating segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment when there are indications that an impairment may exist. This evaluation involves a significant degree of estimation and uncertainty. In the Entergy Wholesale Commodities business, Entergy’s investments in merchant generation assets are subject to impairment if adverse market or regulatory conditions arise, particularly if it leads to a decision or an expectation that Entergy will operate or own a plant for a shorter period than previously expected; if there is a significant adverse change in the physical condition of a plant; or, if capital investment in a plant significantly exceeds previously-expected amounts.
If an asset is considered held for use, and Entergy concludes that events and circumstances are present indicating that an impairment analysis should be performed under the accounting standards, the sum of the expected undiscounted future cash flows from the asset are compared to the asset’s carrying value. The carrying value of the asset includes any capitalized asset retirement cost associated with the decommissioning liability; therefore, changes in assumptions that affect the decommissioning liability can increase or decrease the carrying value of the asset subject to impairment. If the expected undiscounted future cash flows exceed the carrying value, no impairment is recorded. If the expected undiscounted future cash flows are less than the carrying value and the carrying value exceeds the fair value, Entergy is required to record an impairment charge to write the asset down to its fair value. If an asset is considered held for sale, an impairment is required to be recognized if the fair value (less costs to sell) of the asset is less than its carrying value.
The expected future cash flows are based on a number of key assumptions, including:
•Future power and fuel prices - Electricity and gas prices can be very volatile. This volatility increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows.
•Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets. While market transactions provide evidence for this valuation, these transactions are relatively infrequent, the market for such assets is volatile, and the value of individual assets is affected by factors unique to those assets.
•Future operating costs - Entergy assumes relatively minor annual increases in operating costs. Technological or regulatory changes that have a significant effect on operations could cause a significant change in these assumptions.
•Timing and the life of the asset - Entergy assumes an expected life of the asset. A change in the timing assumption, whether due to management decisions regarding operation of the plant, the regulatory process, or operational or other factors, could have a significant effect on the expected future cash flows and result in a significant effect on operations.
See Note 14 to the financial statements for a discussion of impairment conclusions related to the Entergy Wholesale Commodities nuclear plants.
Taxation and Uncertain Tax Positions
Management exercises significant judgment in evaluating the potential tax effects of Entergy’s operations, transactions, and other events. Entergy accounts for uncertain income tax positions using a recognition model under
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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. Entergy’s income taxes, including unrecognized tax benefits, open audits, and other significant tax matters are discussed in Note 3 to the financial statements.
Included in the IRS examination of Entergy’s 2015 tax returns is the tax effect of the October 2015 combination of two Entergy utility companies, Entergy Gulf States Louisiana and Entergy Louisiana. Entergy Louisiana maintained a carryover tax basis in the assets received and the tax consequences provided for an increase in tax basis as well. This resulted in recognition in 2015 of a $334 million permanent difference and income tax benefit, net of the uncertain tax position recorded on the transaction. As discussed in Note 3 to the financial statements, the IRS completed its examination of the 2014 and 2015 tax years and issued its 2014-2015 Revenue Agent Report in November 2020. Entergy Louisiana reversed the provision for uncertain tax positions with respect to the business combination. See additional discussion of the 2014 and 2015 IRS audit in Note 3 to the financial statements.
In addition, as discussed in Note 3 to the financial statements, in 2015, System Energy and Entergy Louisiana adopted a new method of accounting for income tax return purposes in which nuclear decommissioning liabilities are treated as production costs of electricity includable in cost of goods sold. The new method resulted in a reduction of taxable income of $1.2 billion for System Energy and $2.2 billion for Entergy Louisiana in 2015. In the third quarter 2020 the IRS issued Notices of Proposed Adjustment concerning this uncertain tax position allowing System Energy to include $102 million of its decommissioning liability in cost of goods sold and Entergy Louisiana to include $221 million of its decommissioning liability in cost of goods sold. The Notices of Proposed Adjustment will not be appealed.
As a result of System Energy being allowed to include part of its decommissioning liability in cost of goods sold, System Energy and Entergy recorded a deferred tax liability of $26 million. System Energy also recorded federal and state taxes payable of $402 million; on a consolidated basis, however, Entergy utilized tax loss carryovers to offset the federal taxable income adjustment and accordingly did not record federal taxes payable as a result of the outcome of this uncertain tax position.
As a result of Entergy Louisiana being allowed to include part of its decommissioning liability in cost of goods sold, Entergy Louisiana and Entergy recorded a deferred tax liability of $60 million. Both Entergy Louisiana and Entergy utilized tax loss carryovers to offset the taxable income adjustment and accordingly did not record taxes payable as a result of the outcome of this uncertain tax position.
The partial disallowance of the uncertain tax position to include the decommissioning liability in cost of goods sold resulted in a $1.5 billion decrease in the balance of unrecognized tax benefits related to federal and state taxes for Entergy. Additionally, both System Energy and Entergy Louisiana recorded a reduction to their balances of unrecognized tax benefits for federal and state taxes of $461 million and $1.1 billion, respectively.
The tax treatment of Entergy Louisiana’s accrued regulatory liabilities associated with the Vidalia purchased power agreement and business combination guaranteed customer credits, which are discussed in Note 2
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to the financial statements, has been resolved in a manner that results in a $190 million increase to previously reported taxable income. Entergy Louisiana and Entergy utilized tax loss carryovers to offset the taxable income adjustment, however, which allowed both Entergy Louisiana and Entergy to reduce their balances of federal and state unrecognized tax benefits by $74 million.
See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017.
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified, defined benefit pension plans that cover substantially all employees, including cash balance plans and final average pay plans. Additionally, Entergy currently provides other postretirement health care and life insurance benefits for substantially all 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 the Utility and Entergy Wholesale Commodities segments.
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 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 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
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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 2017, Entergy confirmed its liability-driven investment strategy for its pension assets, which recommended that the target asset allocation adjust dynamically over time, based on the funded status of the plan, to an ultimate allocation of 35% equity securities and 65% fixed income securities. The ultimate asset allocation is expected to be attained when the plan is 100% funded. The target pension asset allocation for 2020 was 58% equity and 42% fixed income securities.
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 2020 weighted average target postretirement asset allocation is 44% equity and 56% 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 2021 and actual 2020 qualified pension and other postretirement costs and related underlying assumptions and sensitivities are shown below:
| Costs | Estimated 2021 | 2020 | ||||||||||||
| (In millions) | ||||||||||||||
| Qualified pension cost | $360.1 | $373.8 (a) | ||||||||||||
| Other postretirement income | ($25.6) | ($17.2) | ||||||||||||
| Assumptions | 2021 | 2020 | ||||||||||||
| Discount rates | ||||||||||||||
| Qualified pension | ||||||||||||||
| Service cost | 2.81% | 3.42% | ||||||||||||
| Interest cost | 2.08% | 2.99% | ||||||||||||
| Other postretirement | ||||||||||||||
| Service cost | 2.98% | 3.27% | ||||||||||||
| Interest cost | 1.86% | 2.41% | ||||||||||||
| Expected long-term rates of return | ||||||||||||||
| Qualified pension assets | 6.75% | 7.00% | ||||||||||||
| Other postretirement - non-taxable assets | 6.00% - 6.75% | 6.25% - 7.00% | ||||||||||||
| Other postretirement - taxable assets - after tax rate | 5.00% | 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 | 5.87% | 6.13% | ||||||||||||
| Post-65 retirees | 6.31% | 6.25% | ||||||||||||
| Ultimate rate | 4.75% | 4.75% | ||||||||||||
| Year ultimate rate is reached and beyond | ||||||||||||||
| Pre-65 retirees | 2030 | 2027 | ||||||||||||
| Post-65 retirees | 2028 | 2027 | ||||||||||||
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(a) In 2020 qualified pension cost included settlement costs of $36.9 million.
Actual asset returns have an effect on Entergy’s qualified pension and other postretirement costs. In 2020, Entergy’s actual annual return on qualified pension assets was approximately 16% and for other postretirement assets was approximately 12%, as compared with the 2020 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):
| Actuarial Assumption | Change in Assumption | Impact on 2021 Qualified Pension Cost | Impact on 2020 Qualified Projected Benefit Obligation | |||||||||||||||||
| Increase/(Decrease) | ||||||||||||||||||||
| Discount rate | (0.25%) | $25 | $260 | |||||||||||||||||
| Rate of return on plan assets | (0.25%) | $16 | $— | |||||||||||||||||
| Rate of increase in compensation | 0.25% | $9 | $46 | |||||||||||||||||
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in millions):
| Actuarial Assumption | Change in Assumption | Impact on 2021 Postretirement Benefit Cost | Impact on 2020 Accumulated Postretirement Benefit Obligation | |||||||||||||||||
| Increase/(Decrease) | ||||||||||||||||||||
| Discount rate | (0.25%) | $2 | $39 | |||||||||||||||||
| Health care cost trend | 0.25% | $2 | $26 | |||||||||||||||||
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 or the average remaining life expectancy of plan participants if almost all are inactive. 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.
Entergy calculates the expected return on pension and other postretirement benefit plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets. In general, Entergy determines the MRV of its pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns and for its other postretirement benefit plan assets Entergy uses fair value.
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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 a further discussion of Entergy’s funded status.
Employer Contributions
Entergy contributed $316.3 million to its qualified pension plans in 2020. Entergy estimates pension contributions will be approximately $356 million in 2021; although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021.
Minimum required funding calculations as determined under Pension Protection Act guidance 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, under the Pension Protection Act, must be funded over a seven-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 in to 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 $48.2 million to its postretirement plans in 2020 and plans to contribute $39.9 million in 2021.
Other Contingencies
As a company with multi-state utility operations, Entergy is subject to a number of federal and state laws and regulations and other factors and conditions in the areas in which it operates, which potentially subjects it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a provision for those matters which are considered probable and estimable in accordance with generally accepted accounting principles.
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.
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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.
New Accounting Pronouncements
See Note 1 to the financial statements for discussion of new accounting pronouncements.
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ENTERGY CORPORATION AND SUBSIDIARIES
REPORT OF MANAGEMENT
Management of Entergy Corporation and its subsidiaries has prepared and is responsible for the financial statements and related financial information included in this document. To meet this responsibility, management establishes and maintains a system of internal controls over financial reporting designed to provide reasonable assurance regarding the preparation and fair presentation of financial statements in accordance with generally accepted accounting principles. This system includes communication through written policies and procedures, an employee Code of Entegrity, and an organizational structure that provides for appropriate division of responsibility and training of personnel. This system is also tested by a comprehensive internal audit program.
Entergy management assesses the design and effectiveness of Entergy’s internal control over financial reporting on an annual basis. In making this assessment, management uses the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. The 2013 COSO Framework was utilized for management’s assessment. Management acknowledges, however, that all internal control systems, no matter how well designed, have inherent limitations and can provide only reasonable assurance with respect to financial statement preparation and presentation.
Entergy Corporation’s independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the effectiveness of Entergy Corporation’s internal control over financial reporting as of December 31, 2020.
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, 2020. 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.
| LEO P. DENAULT Chairman of the Board and Chief Executive Officer of Entergy Corporation | ANDREW S. MARSH 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 | DAVID D. ELLIS Chairman of the Board, President, and Chief Executive Officer of Entergy New Orleans, LLC | ||||
| SALLIE T. RAINER Chair 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. | ||||
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| ENTERGY CORPORATION AND SUBSIDIARIES | |||||||||||||||||||||||||||||
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2017 | 2016 | |||||||||||||||||||||||||
| (In Thousands, Except Percentages and Per Share Amounts) | |||||||||||||||||||||||||||||
| Operating revenues | $10,113,636 | $10,878,673 | $11,009,452 | $11,074,481 | $10,845,645 | ||||||||||||||||||||||||
| Net income (loss) | $1,406,653 | $1,258,244 | $862,555 | $425,353 | ($564,503) | ||||||||||||||||||||||||
| Earnings (loss) per share: | |||||||||||||||||||||||||||||
| Basic | $6.94 | $6.36 | $4.68 | $2.29 | ($3.26) | ||||||||||||||||||||||||
| Diluted | $6.90 | $6.30 | $4.63 | $2.28 | ($3.26) | ||||||||||||||||||||||||
| Dividends declared per share | $3.74 | $3.66 | $3.58 | $3.50 | $3.42 | ||||||||||||||||||||||||
| Return on common equity | 13.13 | % | 13.02 | % | 10.08 | % | 5.12 | % | (6.73 | %) | |||||||||||||||||||
| Book value per share, year-end | $54.56 | $51.34 | $46.78 | $44.28 | $45.12 | ||||||||||||||||||||||||
| Total assets | $58,239,212 | $51,723,912 | $48,275,066 | $46,707,149 | $45,904,434 | ||||||||||||||||||||||||
| Long-term obligations (a) | $21,477,974 | $17,351,449 | $15,758,083 | $14,535,077 | $14,695,422 | ||||||||||||||||||||||||
(a) Includes long-term debt (excluding currently maturing debt), non-current finance lease obligations, and subsidiary preferred stock without sinking fund that is not presented as equity on the balance sheet. | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2017 | 2016 | |||||||||||||||||||||||||
| (Dollars In Millions) | |||||||||||||||||||||||||||||
| Utility electric operating revenues: | |||||||||||||||||||||||||||||
| Residential | $3,550 | $3,532 | $3,566 | $3,355 | $3,288 | ||||||||||||||||||||||||
| Commercial | 2,293 | 2,476 | 2,426 | 2,480 | 2,362 | ||||||||||||||||||||||||
| Industrial | 2,331 | 2,541 | 2,499 | 2,584 | 2,327 | ||||||||||||||||||||||||
| Governmental | 212 | 228 | 226 | 231 | 217 | ||||||||||||||||||||||||
| Total billed retail | 8,386 | 8,777 | 8,717 | 8,650 | 8,194 | ||||||||||||||||||||||||
| Sales for resale | 296 | 286 | 300 | 253 | 236 | ||||||||||||||||||||||||
| Other | 365 | 367 | 367 | 376 | 437 | ||||||||||||||||||||||||
| Total | $9,047 | $9,430 | $9,384 | $9,279 | $8,867 | ||||||||||||||||||||||||
| Utility billed electric energy sales (GWh): | |||||||||||||||||||||||||||||
| Residential | 35,173 | 36,094 | 37,107 | 33,834 | 35,112 | ||||||||||||||||||||||||
| Commercial | 26,466 | 28,755 | 29,426 | 28,745 | 29,197 | ||||||||||||||||||||||||
| Industrial | 47,117 | 48,483 | 48,384 | 47,769 | 45,739 | ||||||||||||||||||||||||
| Governmental | 2,414 | 2,579 | 2,581 | 2,511 | 2,547 | ||||||||||||||||||||||||
| Total retail | 111,170 | 115,911 | 117,498 | 112,859 | 112,595 | ||||||||||||||||||||||||
| Sales for resale | 13,658 | 13,210 | 11,715 | 11,550 | 11,054 | ||||||||||||||||||||||||
| Total | 124,828 | 129,121 | 129,213 | 124,409 | 123,649 | ||||||||||||||||||||||||
| Entergy Wholesale Commodities: | |||||||||||||||||||||||||||||
| Operating revenues | $943 | $1,295 | $1,469 | $1,657 | $1,850 | ||||||||||||||||||||||||
| Billed electric energy sales (GWh) | 20,581 | 28,088 | 29,875 | 30,501 | 35,881 | ||||||||||||||||||||||||
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of
Entergy Corporation and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2020 and 2019, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, 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, 2020, 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 26, 2021, expressed an unqualified opinion on the Corporation’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on the Corporation’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Rate and Regulatory Matters —Entergy Corporation and Subsidiaries—Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Corporation is subject to rate regulation by the Arkansas Public Service Commission, Louisiana Public Service Commission, Mississippi Public Service Commission, City Council of New Orleans, Louisiana, and Public Utility Commission of Texas (the “Commissions”), which have jurisdiction with respect to the rates of electric companies in Arkansas, Louisiana, Mississippi, Texas, and the City of New Orleans, 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
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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, such as property, plant, and equipment; regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
The Corporation’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the Commissions and the FERC 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 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 significant 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, (2) likelihood of refunds to customers, and (3) ongoing complaints filed with the FERC against System Energy. Auditing management’s judgments regarding the outcome of future decisions by the Commissions and the FERC involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate-setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions and the FERC 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 costs incurred as property, plant, and equipment and deferred as 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 property, plant, and equipment; 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 and the FERC for the Corporation and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ and the FERC’s 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 filings with the Commissions and the FERC, including the annual formula rate plan filings, base rate case filings, and open complaints filed with the FERC against System Energy, and considered the filings with the Commissions and the FERC by intervenors that may impact the Corporation’s future rates, 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, including the complaints filed with the FERC against System Energy, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
40
Uncertain Tax Positions—Entergy Wholesale Commodities—Refer to Note 3 to the financial statements
Critical Audit Matter Description
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 significant 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 events such as additional transactions contemplated or consummated by the Corporation as well as audits by taxing authorities of the tax positions. The net unrecognized tax benefit of $979 million at December 31, 2020, includes uncertain tax positions related to Entergy Wholesale Commodities.
Given the subjectivity of estimating these uncertain tax positions, auditing the uncertain tax positions involved especially subjective judgment.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertain tax positions included the following, among others:
•We tested the effectiveness of controls related to uncertain tax positions, including those over the recognition and measurement of the income tax benefits.
•We evaluated the Corporation’s disclosures, and the balances recorded, related to uncertain tax positions.
•We evaluated the methods and assumptions used by management to estimate the uncertain tax positions 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 uncertain tax positions and management’s key estimates and judgments made by:
◦Assessing the technical merits of the uncertain tax positions by comparing to similar cases filed with the Internal Revenue Service.
◦
◦Evaluating the reasonableness and consistency of the probabilities applied to the uncertain tax position by comparing to probabilities used on similar uncertain tax positions.
◦
◦Considering the impact of changes or settlements in the tax environment on management’s methods and assumptions used to estimate the uncertain tax positions.
Nuclear Decommissioning Costs—Entergy Wholesale Commodities—Refer to Note 9 to the financial statements
Critical Audit Matter Description
The Corporation owns nuclear generation facilities in the Entergy Wholesale Commodities operating segment where regulation requires the Corporation to decommission its nuclear power plants after each facility is taken out of service. The Corporation periodically conducts decommissioning cost studies, which requires management to make significant judgments and assumptions, specifically related to future dismantlement, site restoration, spent fuel management, and license termination costs. The liability for Entergy Wholesale Commodities nuclear decommissioning was $2.6 billion at December 31, 2020.
Auditing management’s judgments regarding the nuclear decommissioning costs, including estimates for future dismantlement, site restoration, spent fuel management, and license termination costs, involved especially subjective judgment in evaluating the appropriateness of the estimates and assumptions.
41
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the underlying costs for nuclear decommissioning included the following, among others:
•We tested the effectiveness of the control over nuclear decommissioning where management evaluates whether estimates and assumptions need to be updated for each of the nuclear power plants.
•We evaluated the Corporation’s disclosures related to the estimated nuclear decommissioning costs, including the balances recorded.
•We evaluated management’s ability to accurately estimate the costs for nuclear decommissioning by comparing the cost estimates to actual nuclear decommissioning costs of similar asset retirement obligations at the Corporation.
•With the assistance of our environmental specialists, we completed a search of environmental regulations to evaluate any regulatory changes that may affect the nuclear decommissioning cost estimates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2021
We have served as the Corporation’s auditor since 2001.
42
| ENTERGY CORPORATION AND SUBSIDIARIES | ||||||||||||||||||||
| CONSOLIDATED INCOME STATEMENTS | ||||||||||||||||||||
| For the Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
(In Thousands, Except Share Data) | ||||||||||||||||||||
| OPERATING REVENUES | ||||||||||||||||||||
| Electric | $9,046,643 | $9,429,978 | $9,384,111 | |||||||||||||||||
| Natural gas | 124,008 | 153,954 | 156,436 | |||||||||||||||||
| Competitive businesses | 942,985 | 1,294,741 | 1,468,905 | |||||||||||||||||
| TOTAL | 10,113,636 | 10,878,673 | 11,009,452 | |||||||||||||||||
| OPERATING EXPENSES | ||||||||||||||||||||
| Operation and Maintenance: | ||||||||||||||||||||
| Fuel, fuel-related expenses, and gas purchased for resale | 1,564,371 | 2,029,638 | 2,147,793 | |||||||||||||||||
| Purchased power | 904,268 | 1,192,860 | 1,658,799 | |||||||||||||||||
| Nuclear refueling outage expenses | 184,157 | 204,927 | 153,826 | |||||||||||||||||
| Other operation and maintenance | 3,002,626 | 3,272,381 | 3,346,397 | |||||||||||||||||
| Asset write-offs, impairments, and related charges | 26,623 | 290,027 | 532,321 | |||||||||||||||||
| Decommissioning | 381,861 | 400,802 | 388,508 | |||||||||||||||||
| Taxes other than income taxes | 652,840 | 643,745 | 641,952 | |||||||||||||||||
| Depreciation and amortization | 1,613,086 | 1,480,016 | 1,369,442 | |||||||||||||||||
| Other regulatory charges (credits) - net | 14,609 | (26,220) | 301,049 | |||||||||||||||||
| TOTAL | 8,344,441 | 9,488,176 | 10,540,087 | |||||||||||||||||
| OPERATING INCOME | 1,769,195 | 1,390,497 | 469,365 | |||||||||||||||||
| OTHER INCOME | ||||||||||||||||||||
| Allowance for equity funds used during construction | 119,430 | 144,974 | 129,602 | |||||||||||||||||
| Interest and investment income | 392,818 | 547,912 | 63,864 | |||||||||||||||||
| Miscellaneous - net | (210,633) | (252,539) | (129,754) | |||||||||||||||||
| TOTAL | 301,615 | 440,347 | 63,712 | |||||||||||||||||
| INTEREST EXPENSE | ||||||||||||||||||||
| Interest expense | 837,981 | 807,382 | 768,322 | |||||||||||||||||
| Allowance for borrowed funds used during construction | (52,318) | (64,957) | (60,974) | |||||||||||||||||
| TOTAL | 785,663 | 742,425 | 707,348 | |||||||||||||||||
| INCOME (LOSS) BEFORE INCOME TAXES | 1,285,147 | 1,088,419 | (174,271) | |||||||||||||||||
| Income taxes | (121,506) | (169,825) | (1,036,826) | |||||||||||||||||
| CONSOLIDATED NET INCOME | 1,406,653 | 1,258,244 | 862,555 | |||||||||||||||||
| Preferred dividend requirements of subsidiaries | 18,319 | 17,018 | 13,894 | |||||||||||||||||
| NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION | $1,388,334 | $1,241,226 | $848,661 | |||||||||||||||||
| Earnings per average common share: | ||||||||||||||||||||
| Basic | $6.94 | $6.36 | $4.68 | |||||||||||||||||
| Diluted | $6.90 | $6.30 | $4.63 | |||||||||||||||||
| Basic average number of common shares outstanding | 200,106,945 | 195,195,858 | 181,409,597 | |||||||||||||||||
| Diluted average number of common shares outstanding | 201,102,220 | 196,999,284 | 183,378,513 | |||||||||||||||||
See Notes to Financial Statements. | ||||||||||||||||||||
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44
| ENTERGY CORPORATION AND SUBSIDIARIES | |||||||||||||||||
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | |||||||||||||||||
| For the Years Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Thousands) | |||||||||||||||||
| Net Income | $1,406,653 | $1,258,244 | $862,555 | ||||||||||||||
| Other comprehensive income (loss) | |||||||||||||||||
| Cash flow hedges net unrealized gain (loss) | |||||||||||||||||
(net of tax expense (benefit) of ($14,776), $28,516, and $5,830) | (55,487) | 115,026 | 22,098 | ||||||||||||||
| Pension and other postretirement liabilities | |||||||||||||||||
(net of tax expense (benefit) of $5,600, ($6,539), and $30,299) | 22,496 | (25,150) | 90,143 | ||||||||||||||
| Net unrealized investment gains (losses) | |||||||||||||||||
(net of tax expense of $17,586, $14,023, and $6,393) | 30,704 | 27,183 | (28,771) | ||||||||||||||
| Other comprehensive income (loss) | (2,287) | 117,059 | 83,470 | ||||||||||||||
| Comprehensive Income | 1,404,366 | 1,375,303 | 946,025 | ||||||||||||||
| Preferred dividend requirements of subsidiaries | 18,319 | 17,018 | 13,894 | ||||||||||||||
| Comprehensive Income Attributable to Entergy Corporation | $1,386,047 | $1,358,285 | $932,131 | ||||||||||||||
| See Notes to Financial Statements. | |||||||||||||||||
45
| ENTERGY CORPORATION AND SUBSIDIARIES | ||||||||||||||||||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||||||||||||||||
| For the Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| OPERATING ACTIVITIES | ||||||||||||||||||||
| Consolidated net income | $1,406,653 | $1,258,244 | $862,555 | |||||||||||||||||
| Adjustments to reconcile consolidated net income to net cash flow provided by operating activities: | ||||||||||||||||||||
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | 2,257,750 | 2,182,313 | 2,040,555 | |||||||||||||||||
| Deferred income taxes, investment tax credits, and non-current taxes accrued | (131,114) | 193,950 | (256,848) | |||||||||||||||||
| Asset write-offs, impairments, and related charges | 26,379 | 226,678 | 491,739 | |||||||||||||||||
| Changes in working capital: | ||||||||||||||||||||
| Receivables | (139,296) | (101,227) | 98,546 | |||||||||||||||||
| Fuel inventory | (27,458) | (28,173) | 45,839 | |||||||||||||||||
| Accounts payable | 137,457 | (71,898) | 97,312 | |||||||||||||||||
| Taxes accrued | 207,556 | (20,784) | 39,272 | |||||||||||||||||
| Interest accrued | 7,662 | 937 | 5,220 | |||||||||||||||||
| Deferred fuel costs | (49,484) | 172,146 | (25,829) | |||||||||||||||||
| Other working capital accounts | (143,451) | (3,108) | (164,173) | |||||||||||||||||
| Changes in provisions for estimated losses | (291,193) | 19,914 | 35,706 | |||||||||||||||||
| Changes in other regulatory assets | (784,494) | (545,559) | 189,193 | |||||||||||||||||
| Changes in other regulatory liabilities | 238,669 | (14,781) | (803,323) | |||||||||||||||||
| Changes in pensions and other postretirement liabilities | 50,379 | 187,124 | (304,941) | |||||||||||||||||
| Other | (76,149) | (639,149) | 34,424 | |||||||||||||||||
| Net cash flow provided by operating activities | 2,689,866 | 2,816,627 | 2,385,247 | |||||||||||||||||
| INVESTING ACTIVITIES | ||||||||||||||||||||
| Construction/capital expenditures | (4,694,076) | (4,197,667) | (3,942,010) | |||||||||||||||||
| Allowance for equity funds used during construction | 119,430 | 144,862 | 130,195 | |||||||||||||||||
| Nuclear fuel purchases | (215,664) | (128,366) | (302,584) | |||||||||||||||||
| Payment for purchase of plant or assets | (247,121) | (305,472) | (26,623) | |||||||||||||||||
| Proceeds from sale of assets | — | 28,932 | 24,902 | |||||||||||||||||
| Insurance proceeds received for property damages | — | 7,040 | 18,270 | |||||||||||||||||
| Changes in securitization account | 5,099 | 3,298 | (5,844) | |||||||||||||||||
| Payments to storm reserve escrow account | (2,273) | (8,038) | (6,551) | |||||||||||||||||
| Receipts from storm reserve escrow account | 297,588 | — | — | |||||||||||||||||
| Decrease (increase) in other investments | (12,755) | 30,319 | (54,500) | |||||||||||||||||
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | 72,711 | 2,369 | 59,643 | |||||||||||||||||
| Proceeds from nuclear decommissioning trust fund sales | 3,107,812 | 4,121,351 | 6,484,791 | |||||||||||||||||
| Investment in nuclear decommissioning trust funds | (3,203,057) | (4,208,870) | (6,485,676) | |||||||||||||||||
| Net cash flow used in investing activities | (4,772,306) | (4,510,242) | (4,105,987) | |||||||||||||||||
See Notes to Financial Statements. | ||||||||||||||||||||
46
| ENTERGY CORPORATION AND SUBSIDIARIES | ||||||||||||||||||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||||||||||||||||
| For the Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| FINANCING ACTIVITIES | ||||||||||||||||||||
| Proceeds from the issuance of: | ||||||||||||||||||||
| Long-term debt | 12,619,201 | 9,304,396 | 8,035,536 | |||||||||||||||||
| Preferred stock of subsidiary | — | 33,188 | 73,330 | |||||||||||||||||
| Treasury stock | 42,600 | 93,862 | 103,315 | |||||||||||||||||
| Common stock | — | 607,650 | 499,272 | |||||||||||||||||
| Retirement of long-term debt | (8,152,378) | (7,619,380) | (6,965,738) | |||||||||||||||||
| Repurchase / redemptions of preferred stock | — | (50,000) | (53,868) | |||||||||||||||||
| Changes in credit borrowings and commercial paper - net | (319,238) | 4,389 | 364,031 | |||||||||||||||||
| Other | (7,524) | (7,732) | 26,453 | |||||||||||||||||
| Dividends paid: | ||||||||||||||||||||
| Common stock | (748,342) | (711,573) | (647,704) | |||||||||||||||||
| Preferred stock | (18,502) | (16,438) | (14,185) | |||||||||||||||||
| Net cash flow provided by financing activities | 3,415,817 | 1,638,362 | 1,420,442 | |||||||||||||||||
| Net increase (decrease) in cash and cash equivalents | 1,333,377 | (55,253) | (300,298) | |||||||||||||||||
| Cash and cash equivalents at beginning of period | 425,722 | 480,975 | 781,273 | |||||||||||||||||
| Cash and cash equivalents at end of period | $1,759,099 | $425,722 | $480,975 | |||||||||||||||||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||||||||||||||||
| Cash paid (received) during the period for: | ||||||||||||||||||||
| Interest - net of amount capitalized | $803,923 | $778,209 | $734,845 | |||||||||||||||||
| Income taxes | ($31,228) | ($40,435) | $19,825 | |||||||||||||||||
See Notes to Financial Statements. | ||||||||||||||||||||
47
| ENTERGY CORPORATION AND SUBSIDIARIES | ||||||||||||||
| CONSOLIDATED BALANCE SHEETS | ||||||||||||||
| ASSETS | ||||||||||||||
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| CURRENT ASSETS | ||||||||||||||
| Cash and cash equivalents: | ||||||||||||||
| Cash | $128,851 | $34,242 | ||||||||||||
| Temporary cash investments | 1,630,248 | 391,480 | ||||||||||||
| Total cash and cash equivalents | 1,759,099 | 425,722 | ||||||||||||
| Accounts receivable: | ||||||||||||||
| Customer | 833,478 | 595,509 | ||||||||||||
| Allowance for doubtful accounts | (117,794) | (7,404) | ||||||||||||
| Other | 135,208 | 219,870 | ||||||||||||
| Accrued unbilled revenues | 434,835 | 400,617 | ||||||||||||
| Total accounts receivable | 1,285,727 | 1,208,592 | ||||||||||||
| Deferred fuel costs | 4,380 | — | ||||||||||||
| Fuel inventory - at average cost | 172,934 | 145,476 | ||||||||||||
| Materials and supplies - at average cost | 962,185 | 824,989 | ||||||||||||
| Deferred nuclear refueling outage costs | 179,150 | 157,568 | ||||||||||||
| Prepayments and other | 196,424 | 283,645 | ||||||||||||
| TOTAL | 4,559,899 | 3,045,992 | ||||||||||||
| OTHER PROPERTY AND INVESTMENTS | ||||||||||||||
| Decommissioning trust funds | 7,253,215 | 6,404,030 | ||||||||||||
| Non-utility property - at cost (less accumulated depreciation) | 343,328 | 332,864 | ||||||||||||
| Other | 214,222 | 496,452 | ||||||||||||
| TOTAL | 7,810,765 | 7,233,346 | ||||||||||||
| PROPERTY, PLANT, AND EQUIPMENT | ||||||||||||||
| Electric | 59,696,443 | 54,271,467 | ||||||||||||
| Natural gas | 610,768 | 547,110 | ||||||||||||
| Construction work in progress | 2,012,030 | 2,823,291 | ||||||||||||
| Nuclear fuel | 601,281 | 677,181 | ||||||||||||
| TOTAL PROPERTY, PLANT, AND EQUIPMENT | 62,920,522 | 58,319,049 | ||||||||||||
| Less - accumulated depreciation and amortization | 24,067,745 | 23,136,356 | ||||||||||||
| PROPERTY, PLANT, AND EQUIPMENT - NET | 38,852,777 | 35,182,693 | ||||||||||||
| DEFERRED DEBITS AND OTHER ASSETS | ||||||||||||||
| Regulatory assets: | ||||||||||||||
Other regulatory assets (includes securitization property of $119,238 as of December 31, 2020 and $239,219 as of December 31, 2019) | 6,076,549 | 5,292,055 | ||||||||||||
| Deferred fuel costs | 240,422 | 239,892 | ||||||||||||
| Goodwill | 377,172 | 377,172 | ||||||||||||
| Accumulated deferred income taxes | 76,289 | 64,461 | ||||||||||||
| Other | 245,339 | 288,301 | ||||||||||||
| TOTAL | 7,015,771 | 6,261,881 | ||||||||||||
| TOTAL ASSETS | $58,239,212 | $51,723,912 | ||||||||||||
See Notes to Financial Statements. | ||||||||||||||
48
| ENTERGY CORPORATION AND SUBSIDIARIES | ||||||||||||||
| CONSOLIDATED BALANCE SHEETS | ||||||||||||||
| LIABILITIES AND EQUITY | ||||||||||||||
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| CURRENT LIABILITIES | ||||||||||||||
| Currently maturing long-term debt | $1,164,015 | $795,012 | ||||||||||||
| Notes payable and commercial paper | 1,627,489 | 1,946,727 | ||||||||||||
| Accounts payable | 2,739,437 | 1,499,861 | ||||||||||||
| Customer deposits | 401,512 | 409,171 | ||||||||||||
| Taxes accrued | 441,011 | 233,455 | ||||||||||||
| Interest accrued | 201,791 | 194,129 | ||||||||||||
| Deferred fuel costs | 153,113 | 197,687 | ||||||||||||
| Pension and other postretirement liabilities | 61,815 | 66,184 | ||||||||||||
| Current portion of unprotected excess accumulated deferred income taxes | 63,683 | 76,457 | ||||||||||||
| Other | 206,640 | 201,780 | ||||||||||||
| TOTAL | 7,060,506 | 5,620,463 | ||||||||||||
| NON-CURRENT LIABILITIES | ||||||||||||||
| Accumulated deferred income taxes and taxes accrued | 4,361,772 | 4,401,190 | ||||||||||||
| Accumulated deferred investment tax credits | 212,494 | 207,113 | ||||||||||||
| Regulatory liability for income taxes-net | 1,521,757 | 1,633,159 | ||||||||||||
| Other regulatory liabilities | 2,323,851 | 1,961,005 | ||||||||||||
| Decommissioning and asset retirement cost liabilities | 6,469,452 | 6,159,212 | ||||||||||||
| Accumulated provisions | 242,835 | 534,028 | ||||||||||||
| Pension and other postretirement liabilities | 2,853,013 | 2,798,265 | ||||||||||||
Long-term debt (includes securitization bonds of $174,635 as of December 31, 2020 and $297,981 as of December 31, 2019) | 21,205,761 | 17,078,643 | ||||||||||||
| Other | 807,219 | 852,749 | ||||||||||||
| TOTAL | 39,998,154 | 35,625,364 | ||||||||||||
| Commitments and Contingencies | ||||||||||||||
Subsidiaries’ preferred stock without sinking fund | 219,410 | 219,410 | ||||||||||||
| EQUITY | ||||||||||||||
Common stock, $0.01 par value, authorized 500,000,000 shares; issued 270,035,180 shares in 2020 and in 2019 | 2,700 | 2,700 | ||||||||||||
| Paid-in capital | 6,549,923 | 6,564,436 | ||||||||||||
| Retained earnings | 9,897,182 | 9,257,609 | ||||||||||||
| Accumulated other comprehensive loss | (449,207) | (446,920) | ||||||||||||
Less - treasury stock, at cost (69,790,346 shares in 2020 and 70,886,400 shares in 2019) | 5,074,456 | 5,154,150 | ||||||||||||
| Total common shareholders' equity | 10,926,142 | 10,223,675 | ||||||||||||
Subsidiaries’ preferred stock without sinking fund | 35,000 | 35,000 | ||||||||||||
| TOTAL | 10,961,142 | 10,258,675 | ||||||||||||
| TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $ | 58,239,212 | $ | 51,723,912 | ||||||||||
See Notes to Financial Statements. | ||||||||||||||
49
| ENTERGY CORPORATION AND SUBSIDIARIES | |||||||||||||||||||||||||||||||||||||||||
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY | |||||||||||||||||||||||||||||||||||||||||
| For the Years Ended December 31, 2020, 2019, and 2018 | |||||||||||||||||||||||||||||||||||||||||
| Common Shareholders’ Equity | |||||||||||||||||||||||||||||||||||||||||
| Subsidiaries’ Preferred Stock | Common Stock | Treasury Stock | Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total | |||||||||||||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2017 | $ | — | $ | 2,548 | $ | (5,397,637) | $ | 5,433,433 | $ | 7,977,702 | $ | (23,531) | $ | 7,992,515 | |||||||||||||||||||||||||||
| Implementation of accounting standards | 576,257 | (632,617) | (56,360) | ||||||||||||||||||||||||||||||||||||||
| Balance at January 1, 2018 | $— | $2,548 | ($5,397,637) | $5,433,433 | $8,553,959 | ($656,148) | $7,936,155 | ||||||||||||||||||||||||||||||||||
| Consolidated net income (a) | 13,894 | — | — | — | 848,661 | — | 862,555 | ||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | — | 83,470 | 83,470 | ||||||||||||||||||||||||||||||||||
| Settlement of equity forwards through common stock issuance | — | 68 | — | 499,932 | — | — | 500,000 | ||||||||||||||||||||||||||||||||||
| Common stock issuance costs | — | — | — | (728) | — | — | (728) | ||||||||||||||||||||||||||||||||||
| Common stock issuances related to stock plans | — | — | 123,918 | 18,794 | — | — | 142,712 | ||||||||||||||||||||||||||||||||||
| Common stock dividends declared | — | — | — | — | (647,704) | — | (647,704) | ||||||||||||||||||||||||||||||||||
| Subsidiaries' capital stock redemptions | — | — | — | — | (1,723) | — | (1,723) | ||||||||||||||||||||||||||||||||||
| Preferred dividend requirements of subsidiaries (a) | (13,894) | — | — | — | — | — | (13,894) | ||||||||||||||||||||||||||||||||||
| Reclassification pursuant to ASU 2018-02 | — | — | — | — | (32,043) | 15,505 | (16,538) | ||||||||||||||||||||||||||||||||||
| Balance at December 31, 2018 | — | 2,616 | (5,273,719) | 5,951,431 | 8,721,150 | (557,173) | 8,844,305 | ||||||||||||||||||||||||||||||||||
| Implementation of accounting standards | — | — | — | — | 6,806 | (6,806) | — | ||||||||||||||||||||||||||||||||||
| Balance at January 1, 2019 | — | 2,616 | (5,273,719) | 5,951,431 | 8,727,956 | (563,979) | 8,844,305 | ||||||||||||||||||||||||||||||||||
| Consolidated net income (a) | 17,018 | — | — | — | 1,241,226 | — | 1,258,244 | ||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | — | 117,059 | 117,059 | ||||||||||||||||||||||||||||||||||
| Settlement of equity forwards through common stock issuance | — | 84 | — | 607,566 | — | — | 607,650 | ||||||||||||||||||||||||||||||||||
| Common stock issuance costs | — | — | — | (7) | — | — | (7) | ||||||||||||||||||||||||||||||||||
| Common stock issuances related to stock plans | — | — | 119,569 | 5,446 | — | — | 125,015 | ||||||||||||||||||||||||||||||||||
| Common stock dividends declared | — | — | — | — | (711,573) | — | (711,573) | ||||||||||||||||||||||||||||||||||
| Subsidiary's preferred stock issuance | 35,000 | — | — | — | — | — | 35,000 | ||||||||||||||||||||||||||||||||||
| Preferred dividend requirements of subsidiaries (a) | (17,018) | — | — | — | — | — | (17,018) | ||||||||||||||||||||||||||||||||||
| Balance at December 31, 2019 | 35,000 | 2,700 | (5,154,150) | 6,564,436 | 9,257,609 | (446,920) | 10,258,675 | ||||||||||||||||||||||||||||||||||
| Implementation of accounting standards | — | — | — | — | (419) | (419) | |||||||||||||||||||||||||||||||||||
| Balance at January 1, 2020 | 35,000 | 2,700 | (5,154,150) | 6,564,436 | 9,257,190 | (446,920) | 10,258,256 | ||||||||||||||||||||||||||||||||||
| Consolidated net income (a) | 18,319 | — | — | — | 1,388,334 | — | 1,406,653 | ||||||||||||||||||||||||||||||||||
| Other comprehensive loss | — | — | — | — | — | (2,287) | (2,287) | ||||||||||||||||||||||||||||||||||
| Common stock issuances related to stock plans | — | — | 79,694 | (14,513) | — | — | 65,181 | ||||||||||||||||||||||||||||||||||
| Common stock dividends declared | — | — | — | — | (748,342) | — | (748,342) | ||||||||||||||||||||||||||||||||||
| Preferred dividend requirements of subsidiaries (a) | (18,319) | — | — | — | — | — | (18,319) | ||||||||||||||||||||||||||||||||||
| Balance at December 31, 2020 | $35,000 | $2,700 | ($5,074,456) | $6,549,923 | $9,897,182 | ($449,207) | $10,961,142 | ||||||||||||||||||||||||||||||||||
| See Notes to Financial Statements. | |||||||||||||||||||||||||||||||||||||||||
(a) Consolidated net income and preferred dividend requirements of subsidiaries include $16.5 million for 2020, $16.5 million for 2019, and $13.9 million for 2018 of preferred dividends on subsidiaries’ preferred stock without sinking fund that is not presented as equity. | |||||||||||||||||||||||||||||||||||||||||
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ENTERGY CORPORATION AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The accompanying consolidated financial statements include the accounts of Entergy Corporation and its subsidiaries. As required by generally accepted accounting principles 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. 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 generally accepted accounting principles 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.
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Net property, plant, and equipment for Entergy (including property under lease and associated accumulated amortization) by business segment and functional category, as of December 31, 2020 and 2019, is shown below:
| 2020 | Entergy | Utility | Entergy Wholesale Commodities | Parent & Other | ||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
| Production | ||||||||||||||||||||||||||
| Nuclear | $7,526 | $7,493 | $33 | $— | ||||||||||||||||||||||
| Other | 6,346 | 6,270 | 76 | — | ||||||||||||||||||||||
| Transmission | 8,758 | 8,758 | — | — | ||||||||||||||||||||||
| Distribution | 10,805 | 10,805 | — | — | ||||||||||||||||||||||
| Other | 2,804 | 2,792 | 5 | 7 | ||||||||||||||||||||||
| Construction work in progress | 2,012 | 2,008 | 4 | — | ||||||||||||||||||||||
| Nuclear fuel | 601 | 548 | 53 | — | ||||||||||||||||||||||
| Property, plant, and equipment - net | $38,853 | $38,674 | $171 | $7 | ||||||||||||||||||||||
| 2019 | Entergy | Utility | Entergy Wholesale Commodities | Parent & Other | ||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
| Production | ||||||||||||||||||||||||||
| Nuclear | $7,439 | $7,369 | $70 | $— | ||||||||||||||||||||||
| Other | 5,253 | 5,139 | 114 | — | ||||||||||||||||||||||
| Transmission | 7,383 | 7,383 | — | — | ||||||||||||||||||||||
| Distribution | 8,972 | 8,972 | — | — | ||||||||||||||||||||||
| Other | 2,636 | 2,620 | 8 | 8 | ||||||||||||||||||||||
| Construction work in progress | 2,823 | 2,814 | 9 | — | ||||||||||||||||||||||
| Nuclear fuel | 677 | 614 | 63 | — | ||||||||||||||||||||||
| Property, plant, and equipment - net | $35,183 | $34,911 | $264 | $8 | ||||||||||||||||||||||
Depreciation rates on average depreciable property for Entergy approximated 2.8% in 2020, 2.8% in 2019, and 2.8% in 2018. Included in these rates are the depreciation rates on average depreciable Utility property of 2.7% in 2020, 2.6% in 2019, and 2.6% in 2018, and the depreciation rates on average depreciable Entergy Wholesale Commodities property of 12.7% in 2020, 18.3% in 2019, and 18.6% in 2018. The depreciation rates for Entergy Wholesale Commodities reflect the significantly reduced remaining estimated operating lives associated with management’s strategy to shut down and sell all of the remaining plants in Entergy Wholesale Commodities’ merchant nuclear fleet. The decrease in the depreciation rate in 2020 for Entergy Wholesale Commodities is due to the shutdown of Indian Point 2 in April 2020.
Entergy amortizes nuclear fuel using a units-of-production method. Nuclear fuel amortization is included in fuel expense in the income statements. Because the values of their long-lived assets are impaired, and their remaining estimated operating lives significantly reduced, the Entergy Wholesale Commodities nuclear plants, except for Palisades, charge nuclear fuel costs directly to expense when incurred because their undiscounted cash flows are insufficient to recover the carrying amount of these capital additions.
Non-utility property - at cost (less accumulated depreciation) for Entergy is reported net of accumulated depreciation of $191 million as of December 31, 2020 and $184 million as of December 31, 2019.
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Construction expenditures included in accounts payable is $745 million as of December 31, 2020 and $406 million as of December 31, 2019.
Net property, plant, and equipment for the Registrant Subsidiaries (including property under lease and associated accumulated amortization) by company and functional category, as of December 31, 2020 and 2019, is shown below:
| 2020 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||||||||||||||
| Production | ||||||||||||||||||||||||||||||||||||||
| Nuclear | $1,622 | $3,980 | $— | $— | $— | $1,891 | ||||||||||||||||||||||||||||||||
| Other | 803 | 3,660 | 868 | 416 | 523 | — | ||||||||||||||||||||||||||||||||
| Transmission | 2,053 | 3,756 | 1,235 | 111 | 1,566 | 37 | ||||||||||||||||||||||||||||||||
| Distribution | 2,666 | 4,130 | 1,651 | 576 | 1,782 | — | ||||||||||||||||||||||||||||||||
| Other | 506 | 984 | 325 | 326 | 273 | 26 | ||||||||||||||||||||||||||||||||
| Construction work in progress | 234 | 667 | 135 | 12 | 880 | 60 | ||||||||||||||||||||||||||||||||
| Nuclear fuel | 163 | 210 | — | — | — | 175 | ||||||||||||||||||||||||||||||||
| Property, plant, and equipment - net | $8,047 | $17,388 | $4,214 | $1,441 | $5,023 | $2,189 | ||||||||||||||||||||||||||||||||
| 2019 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||||||||||||||
Production | ||||||||||||||||||||||||||||||||||||||
Nuclear | $1,611 | $4,042 | $— | $— | $— | $1,716 | ||||||||||||||||||||||||||||||||
Other | 785 | 2,789 | 845 | 192 | 528 | — | ||||||||||||||||||||||||||||||||
Transmission | 1,966 | 2,944 | 1,136 | 96 | 1,202 | 39 | ||||||||||||||||||||||||||||||||
Distribution | 2,457 | 3,078 | 1,489 | 505 | 1,443 | — | ||||||||||||||||||||||||||||||||
Other | 454 | 884 | 309 | 270 | 256 | 30 | ||||||||||||||||||||||||||||||||
Construction work in progress | 198 | 1,384 | 88 | 202 | 760 | 165 | ||||||||||||||||||||||||||||||||
Nuclear fuel | 196 | 268 | — | — | — | 150 | ||||||||||||||||||||||||||||||||
Property, plant, and equipment - net | $7,667 | $15,389 | $3,867 | $1,265 | $4,189 | $2,100 | ||||||||||||||||||||||||||||||||
Depreciation rates on average depreciable property for the Registrant Subsidiaries are shown below:
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||
| 2020 | 2.6% | 2.4% | 3.5% | 3.1% | 3.1% | 2.1% | |||||||||||||||||||||||||||||
| 2019 | 2.5% | 2.4% | 3.2% | 3.2% | 3.0% | 2.1% | |||||||||||||||||||||||||||||
| 2018 | 2.5% | 2.3% | 3.2% | 3.5% | 2.7% | 1.9% | |||||||||||||||||||||||||||||
Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $179.8 million as of December 31, 2020 and $168.5 million as of December 31, 2019. 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, 2020 and $0.5 million as of December 31, 2019. Non-utility
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property - at cost (less accumulated depreciation) for Entergy Texas is reported net of accumulated depreciation of $4.9 million as of December 31, 2019.
As of December 31, 2020, construction expenditures included in accounts payable are $59.7 million for Entergy Arkansas, $460.5 million for Entergy Louisiana, $31.4 million for Entergy Mississippi, $9.2 million for Entergy New Orleans, $116.8 million for Entergy Texas, and $17.7 million for System Energy. As of December 31, 2019, construction expenditures included in accounts payable are $67.9 million for Entergy Arkansas, $115.1 million for Entergy Louisiana, $34.2 million for Entergy Mississippi, $18.4 million for Entergy New Orleans, $88.1 million for Entergy Texas, and $23.2 million for System Energy.
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, 2020, the subsidiaries’ investment and accumulated depreciation in each of these generating stations were as follows:
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| Generating Stations | Fuel Type | Total Megawatt Capability (a) | Ownership | Investment | Accumulated Depreciation | ||||||||||||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||||||||||||||
| Utility business: | |||||||||||||||||||||||||||||||||||
| Entergy Arkansas - | |||||||||||||||||||||||||||||||||||
| Independence | Unit 1 | Coal | 822 | 31.50 | % | $142 | $105 | ||||||||||||||||||||||||||||
| Independence | Common Facilities | Coal | 15.75 | % | $43 | $30 | |||||||||||||||||||||||||||||
| White Bluff | Units 1 and 2 | Coal | 1,640 | 57.00 | % | $585 | $383 | ||||||||||||||||||||||||||||
| Ouachita (b) | Common Facilities | Gas | 66.67 | % | $173 | $154 | |||||||||||||||||||||||||||||
| Union (c) | Common Facilities | Gas | 25.00 | % | $29 | $7 | |||||||||||||||||||||||||||||
| Entergy Louisiana - | |||||||||||||||||||||||||||||||||||
| Roy S. Nelson | Unit 6 | Coal | 524 | 40.25 | % | $291 | $209 | ||||||||||||||||||||||||||||
| Roy S. Nelson | Unit 6 Common Facilities | Coal | 20.98 | % | $21 | $9 | |||||||||||||||||||||||||||||
| Big Cajun 2 | Unit 3 | Coal | 558 | 24.15 | % | $151 | $128 | ||||||||||||||||||||||||||||
| Big Cajun 2 | Unit 3 Common Facilities | Coal | 8.05 | % | $5 | $3 | |||||||||||||||||||||||||||||
| Ouachita (b) | Common Facilities | Gas | 33.33 | % | $90 | $77 | |||||||||||||||||||||||||||||
| Acadia | Common Facilities | Gas | 50.00 | % | $21 | $1 | |||||||||||||||||||||||||||||
| Union (c) | Common Facilities | Gas | 50.00 | % | $59 | $8 | |||||||||||||||||||||||||||||
| Entergy Mississippi - | |||||||||||||||||||||||||||||||||||
| Independence | Units 1 and 2 and Common Facilities | Coal | 1,664 | 25.00 | % | $284 | $173 | ||||||||||||||||||||||||||||
| Entergy New Orleans - | |||||||||||||||||||||||||||||||||||
| Union (c) | Common Facilities | Gas | 25.00 | % | $29 | $7 | |||||||||||||||||||||||||||||
| Entergy Texas - | |||||||||||||||||||||||||||||||||||
| Roy S. Nelson | Unit 6 | Coal | 524 | 29.75 | % | $206 | $119 | ||||||||||||||||||||||||||||
| Roy S. Nelson | Unit 6 Common Facilities | Coal | 15.52 | % | $7 | $3 | |||||||||||||||||||||||||||||
| Big Cajun 2 | Unit 3 | Coal | 558 | 17.85 | % | $113 | $82 | ||||||||||||||||||||||||||||
| Big Cajun 2 | Unit 3 Common Facilities | Coal | 5.95 | % | $4 | $1 | |||||||||||||||||||||||||||||
| System Energy - | |||||||||||||||||||||||||||||||||||
| Grand Gulf (d) | Unit 1 | Nuclear | 1,396 | 90.00 | % | $5,310 | $3,280 | ||||||||||||||||||||||||||||
| Entergy Wholesale Commodities: | |||||||||||||||||||||||||||||||||||
| Independence | Unit 2 | Coal | 842 | 14.37 | % | $74 | $55 | ||||||||||||||||||||||||||||
| Independence | Common Facilities | Coal | 7.18 | % | $20 | $14 | |||||||||||||||||||||||||||||
| Roy S. Nelson | Unit 6 | Coal | 524 | 10.90 | % | $117 | $67 | ||||||||||||||||||||||||||||
| Roy S. Nelson | Unit 6 Common Facilities | Coal | 5.68 | % | $3 | $1 | |||||||||||||||||||||||||||||
(a)“Total Megawatt 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.
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(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. Because the value of their long-lived assets are impaired, and their remaining estimated operating lives significantly reduced, the Entergy Wholesale Commodities nuclear plants, except for Palisades, charge nuclear refueling outage costs directly to expense when incurred because their undiscounted cash flows are insufficient to recover the carrying amount of these costs.
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. In September 2019, Entergy Utility Holding Company, LLC and its regulated wholly-owned subsidiaries including Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, LLC, and Entergy New Orleans, LLC became eligible to join and joined the Entergy Corporation consolidated federal income tax group. These changes do not affect the accrual or allocation of income taxes for the Registrant Subsidiaries. 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.
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Earnings (Loss) per Share
The following table presents Entergy’s basic and diluted earnings per share calculation included on the consolidated statements of operations:
| For the Years Ended December 31, | |||||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||||||||||||||||||||
| (In Millions, Except Per Share Data) | |||||||||||||||||||||||||||||||||||
| $/share | $/share | $/share | |||||||||||||||||||||||||||||||||
| Net income attributable to Entergy Corporation | $1,388.3 | $1,241.2 | $848.7 | ||||||||||||||||||||||||||||||||
| Basic shares and earnings per average common share | 200.1 | $6.94 | 195.2 | $6.36 | 181.4 | $4.68 | |||||||||||||||||||||||||||||
| Average dilutive effect of: | |||||||||||||||||||||||||||||||||||
| Stock options | 0.5 | (0.02) | 0.6 | (0.02) | 0.3 | (0.01) | |||||||||||||||||||||||||||||
| Other equity plans | 0.5 | (0.02) | 0.8 | (0.03) | 0.7 | (0.02) | |||||||||||||||||||||||||||||
| Equity forwards | — | — | 0.4 | (0.01) | 1.0 | (0.02) | |||||||||||||||||||||||||||||
| Diluted shares and earnings per average common shares | 201.1 | $6.90 | 197.0 | $6.30 | 183.4 | $4.63 | |||||||||||||||||||||||||||||
The calculation of diluted earnings per share excluded 523,999 options outstanding at December 31, 2020, 173,290 options outstanding at December 31, 2019, and 956,550 options outstanding at December 31, 2018 because they were 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 enterprises whose rates meet three criteria specified in accounting standards. The Utility operating companies and System Energy have rates that (i) are approved by a body (its regulator) empowered to set rates that bind customers; (ii) are cost-based; and (iii) can 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. Because the Utility operating companies and System Energy meet these criteria, each of them capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. Such capitalized costs are reflected as regulatory assets in the accompanying financial statements. When an enterprise concludes that recovery of a regulatory asset is no longer probable, the regulatory asset must be removed from the entity’s balance sheet.
An enterprise that ceases to meet the three criteria for all or part of its operations should report that event in its financial statements. In general, the enterprise no longer meeting the criteria should eliminate from its balance sheet all regulatory assets and liabilities related to the applicable operations. Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs, it is possible that an impairment may exist that could require further write-offs of plant assets.
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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, or its steam business, 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 returned 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 Arkansas, Entergy Louisiana, 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 losses on the 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. Utility operating company 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. Unrealized gains and losses on investments in equity securities held by the nuclear decommissioning trust funds are recorded in earnings as they occur rather than in other comprehensive income. 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, the Registrant Subsidiaries have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets. For the 30% interest in River Bend formerly owned by Cajun,
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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 Entergy Wholesale Commodities nuclear plants do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains/(losses) recorded on the equity securities in the trust funds are recognized in earnings. Unrealized gains recorded on the available-for-sale debt securities in the trust funds are recognized in the accumulated other comprehensive income component of shareholders’ equity. Unrealized losses (where cost exceeds fair market value) on the available-for-sale debt securities in the trust funds are also recorded in the accumulated other comprehensive income component of shareholders’ equity unless the unrealized loss is other than temporary and therefore recorded in earnings. A portion of Entergy’s decommissioning trust funds were held in a wholly-owned registered investment company, and unrealized gains and losses on both the equity and debt securities held in the registered investment company were recognized in earnings. In December 2020, Entergy liquidated its interest in the registered investment company. The assessment of whether an investment in an available-for-sale debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). Effective January 1, 2020, with the adoption of ASU 2016-13, Entergy estimates the expected credit losses for its available for sale securities based on the current credit rating and remaining life of the securities. To the extent an expected credit loss is realized, the individual security comprising the loss is written off against this allowance. 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.
Equity Method Investments
Entergy owns investments that are accounted for under the equity method of accounting because Entergy’s ownership level results in significant influence, but not control, over the investee and its operations. Entergy records its share of the investee’s comprehensive earnings and losses in income and as an increase or decrease to the investment account. Any cash distributions are charged against the investment account. Entergy discontinues the recognition of losses on equity investments when its share of losses equals or exceeds its carrying amount for an investee plus any advances made or commitments to provide additional financial support.
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
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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. Prior to 2019, the ineffective portions of all hedges are recognized in current-period earnings. Effective January 1, 2019 with the adoption of ASU 2017-12 there will no longer be separate recognition of the ineffective portion of highly effective hedges. 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 other than those instruments held by the Entergy Wholesale Commodities business 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 held in all of its business segments 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. Because the values of the long-lived assets are impaired, and the remaining estimated operating lives significantly reduced, the Entergy Wholesale Commodities nuclear plants, except for Palisades, are charging additional expenditures for capital assets directly to expense when incurred. See Note 14 to the financial statements for further discussions of the impairments of the Entergy Wholesale Commodities nuclear plants.
River Bend AFUDC
The River Bend AFUDC gross-up is a regulatory asset that represents the incremental difference imputed by the LPSC between the AFUDC actually recorded by Entergy Louisiana on a net-of-tax basis during the construction of River Bend and what the AFUDC would have been on a pre-tax basis. The imputed amount was only calculated on that portion of River Bend that the LPSC allowed in rate base and is being amortized through August 2025.
Reacquired Debt
The premiums and costs associated with reacquired debt of Entergy’s Utility operating companies and System Energy (except that portion allocable to the deregulated operations of Entergy Louisiana) are included in
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regulatory assets and are being amortized over the life of the related new issuances, or over the life of the original debt issuance if the debt is not refinanced, in accordance with ratemaking treatment.
Taxes Imposed on Revenue-Producing Transactions
Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues, unless required to report them differently by a regulatory authority.
New Accounting Pronouncements
In December 2019 the FASB issued ASU No. 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes.” The ASU removes certain exceptions for recognizing deferred taxes for investments, performing intra-period allocation, and calculating income taxes in interim periods. The ASU also adds guidance to reduce complexity in certain areas, including allocating taxes to members of a consolidated group. Entergy adopted ASU 2019-12 in the first quarter 2021 on a prospective basis. Entergy does not expect that the adoption of ASU 2019-12 will materially affect its results of operations, financial position, 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 probable future revenues associated with costs that Entergy expects to recover from customers through the regulatory ratemaking process under which the Utility business operates. Regulatory liabilities represent probable future reductions in revenues associated with amounts that Entergy expects to benefit customers through the regulatory ratemaking process under which the Utility business operates. 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, 2020 and 2019:
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Other Regulatory Assets
Entergy
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a) | $3,027.5 | $2,942.4 | |||||||||
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a) | 1,018.9 | 920.4 | |||||||||
Removal costs (Note 9) | 893.8 | 421.0 | |||||||||
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Hurricane Laura, Hurricane Delta, and Hurricane Zeta and Storm Cost Recovery Filings with Retail Regulators and Note 5 - Securitization Bonds) | 379.2 | 372.8 | |||||||||
Retired electric and gas meters - recovered through retail rates as determined by retail regulators | 192.1 | 205.6 | |||||||||
Opportunity Sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b) | 131.8 | 116.3 | |||||||||
Deferred COVID-19 costs recovery period to be determined (Note 2 - Retail Rate Proceedings) (b) | 105.7 | — | |||||||||
Unamortized loss on reacquired debt - recovered over term of debt | 79.2 | 66.6 | |||||||||
Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators | 66.0 | 15.7 | |||||||||
Attorney General litigation costs - recovered over a six-year period through March 2026 (b) | 25.3 | 29.5 | |||||||||
New nuclear generation development costs - recovery through formula rate plan December 2014 through November 2022 (b) | 14.2 | 21.6 | |||||||||
Little Gypsy costs – recovered through securitization (Note 5 - Entergy Louisiana Securitization Bonds - Little Gypsy) | 7.5 | 29.9 | |||||||||
| Other | 135.3 | 150.3 | |||||||||
| Entergy Total | $6,076.5 | $5,292.1 | |||||||||
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Entergy Arkansas
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a) | $831.5 | $796.5 | |||||||||
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a) | 479.3 | 433.0 | |||||||||
Removal costs (Note 9) | 212.6 | 168.9 | |||||||||
Opportunity sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding) (b) | 131.8 | 116.3 | |||||||||
Retired electric meters - recovered over 15-year period through March 2034 | 46.9 | 50.4 | |||||||||
Storm damage costs - recovered either through securitization or retail rates (Note 5 - Entergy Arkansas Securitization Bonds) | 42.7 | 46.1 | |||||||||
Unamortized loss on reacquired debt - recovered over term of debt | 24.7 | 18.3 | |||||||||
Retail rate deferrals - recovered through rate riders as rates are redetermined annually (b) | 12.6 | 2.3 | |||||||||
Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (b) | 10.5 | — | |||||||||
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (Note 2 - Retail Rate Proceedings) (b) | 9.1 | 10.9 | |||||||||
| Other | 30.7 | 24.2 | |||||||||
| Entergy Arkansas Total | $1,832.4 | $1,666.9 | |||||||||
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Entergy Louisiana
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Non-Qualified Pension Plans) (a) | $799.4 | $787.7 | |||||||||
Removal costs (Note 9) | 302.5 | — | |||||||||
Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a) | 299.0 | 262.5 | |||||||||
Retired electric meters - recovered over a 22-year period through July 2041 | 96.4 | 101.1 | |||||||||
Storm damage costs - recovered through retail rates (Note 2 - Hurricane Laura, Hurricane Delta, and Hurricane Zeta and Storm Cost Recovery Filings with Retail Regulators) | 94.0 | 45.7 | |||||||||
Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (b) | 48.8 | — | |||||||||
Unamortized loss on reacquired debt - recovered over term of debt | 26.6 | 20.4 | |||||||||
New nuclear generation development costs - recovery through formula rate plan December 2014 through November 2022 (b) | 14.0 | 21.2 | |||||||||
Business combination external costs deferral - recovery through formula rate plan December 2015 through November 2025 (b) | 9.2 | 10.8 | |||||||||
River Bend AFUDC - recovered through August 2025 (Note 1 - River Bend AFUDC) | 7.2 | 9.1 | |||||||||
Little Gypsy costs – recovered through securitization (Note 5 - Entergy Louisiana Securitization Bonds - Little Gypsy) | 5.1 | 27.6 | |||||||||
| Other | 23.9 | 29.1 | |||||||||
| Entergy Louisiana Total | $1,726.1 | $1,315.2 | |||||||||
Entergy Mississippi
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a) | $242.7 | $234.4 | |||||||||
Removal costs (Note 9) | 107.3 | 80.8 | |||||||||
Retail rate deferrals - returned through rate riders as rates are redetermined annually | 44.3 | 7.5 | |||||||||
Attorney General litigation costs - recovered over a six-year period through March 2026 (b) | 25.3 | 29.5 | |||||||||
Deferred COVID-19 costs - recovery period to be determined (Note 2 - Retail Rate Proceedings) (b) | 19.2 | — | |||||||||
Unamortized loss on reacquired debt - recovered over term of debt | 13.5 | 14.9 | |||||||||
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a) | 7.9 | 7.8 | |||||||||
| Other | 7.1 | 3.1 | |||||||||
| Entergy Mississippi Total | $467.3 | $378.0 | |||||||||
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Entergy New Orleans
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a) | $75.7 | $85.9 | |||||||||
Removal costs - (Note 9) | 63.2 | 52.9 | |||||||||
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Hurricane Laura, Hurricane Delta, and Hurricane Zeta and Note 5 - Entergy New Orleans Securitization Bonds - Hurricane Isaac) | 55.2 | 59.6 | |||||||||
Retired meters - recovered over a 12-year period through July 2031 (b) | 21.7 | 24.6 | |||||||||
Deferred COVID-19 costs recovery period to be determined (Note 2 - Retail Rate Proceedings) (b) | 14.3 | — | |||||||||
Rate case costs - recovered over a three-year period through July 2022 (Note 2 - Retail Rate Proceedings) | 5.7 | 7.0 | |||||||||
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a) | 5.2 | 4.9 | |||||||||
New Orleans Power Station deferral – recovered over a five-year period through October 2025 (Note 2 - Retail Rate Proceedings) | 5.0 | — | |||||||||
Algiers customer migration costs - recovered over a five-year period through July 2024 (Note 2 - Retail Rate Proceedings) | 3.9 | 4.9 | |||||||||
Unamortized loss on reacquired debt - recovered over term of debt | 1.9 | 2.3 | |||||||||
| Other | 15.0 | 17.3 | |||||||||
| Entergy New Orleans Total | $266.8 | $259.4 | |||||||||
Entergy Texas
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Hurricane Laura, Hurricane Delta, and Hurricane Zeta and Note 5 - Entergy Texas Securitization Bonds) | $187.3 | $221.4 | |||||||||
Pension & postretirement costs (Note 11 - Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a) | 140.1 | 167.7 | |||||||||
Removal costs (Note 9) | 115.3 | 42.5 | |||||||||
Retired electric meters - recovered over 13-year period through February 2032 | 26.0 | 28.4 | |||||||||
Neches and Sabine costs - recovered over a 10-year period through September 2028 (Note 2 - Retail Rate Proceedings) | 18.8 | 21.2 | |||||||||
Deferred COVID-19 costs recovery period to be determined (Note 2 - Retail Rate Proceedings) (b) | 12.9 | — | |||||||||
Unamortized loss on reacquired debt - recovered over term of debt | 10.5 | 7.7 | |||||||||
Transition to competition costs - recovered over a 15-year period through February 2021 | 2.1 | 14.9 | |||||||||
| Other | 11.7 | 8.8 | |||||||||
| Entergy Texas Total | $524.7 | $512.6 | |||||||||
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System Energy
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a) | $226.3 | $210.9 | |||||||||
Pension & postretirement costs (Note 11 - Qualified Pension Plans and Other Postretirement Benefits) (a) | 217.8 | 200.3 | |||||||||
Removal costs - recovered through depreciation rates (Note 9) | 92.9 | 75.9 | |||||||||
Unamortized loss on reacquired debt - recovered over term of debt | 2.0 | 3.0 | |||||||||
System Energy Total | $ | 539.0 | $ | 490.1 | |||||||
(a)Does not earn a return on investment, but is offset by related liabilities.
(b)Does not earn a return on investment.
Hurricane Laura, Hurricane Delta, and Hurricane Zeta
In August and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Utility’s service territories in Louisiana, including New Orleans, Texas, and, to a lesser extent, in Arkansas and Mississippi. The storms resulted in widespread power 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. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.4 billion, including $2.0 billion at Entergy Louisiana, $300 million at Entergy Texas, and $40 million at Entergy New Orleans. The estimate includes approximately $1.98 billion in capital costs, including $1.67 billion at Entergy Louisiana, $245 million at Entergy Texas, and $30 million at Entergy New Orleans and approximately $420 million in non-capital costs, including $330 million at Entergy Louisiana, $55 million at Entergy Texas, and $10 million at Entergy New Orleans. This estimate includes all costs to restore power and repair or replace the damages from the hurricanes, except for the cost to repair or replace damage incurred to an Entergy Louisiana transmission line in southeast Louisiana, and the amount of that cost could be significant. The restoration plan for this transmission line and the related cost estimate is still being evaluated.
Entergy recorded accounts payable and corresponding construction work in progress and regulatory assets for the estimated costs incurred that were necessary to return customers to service. Entergy recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. There are well-established mechanisms and precedent for addressing these catastrophic events and providing for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles. Because Entergy has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
The Utility operating companies are considering all available avenues to recover storm-related costs from Hurricane Laura, Hurricane Delta, and Hurricane Zeta including accessing funded storm reserve escrows and securitization. In November 2020, Entergy Louisiana drew $257 million from its funded storm reserves. Each Utility operating company is responsible for its restoration cost obligations and for recovering or financing its storm-related costs. Storm cost recovery or financing will be subject to review by applicable regulatory authorities.
In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments to facilitate issuance of shorter-term bonds to provide interim financing for restoration costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta. Subsequently, Entergy Louisiana and the LPSC staff
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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.
In December 2020, Entergy Louisiana provided the LPSC with notification that it intends to initiate a storm cost recovery proceeding in the near future, which will permit the LPSC to retain any outside consultants and counsel needed to review the storm cost recovery application. In February 2021 the LPSC voted to retain outside counsel and consultants to assist in the review of Entergy Louisiana’s upcoming storm cost recovery application, which is expected to be filed in March 2021.
Other Regulatory Liabilities
Entergy
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) | $1,694.1 | $1,300.1 | |||||||||
Louisiana Act 55 financing savings obligation (Note 3) (b) | 144.3 | 97.1 | |||||||||
Vidalia purchased power agreement (Note 8) (b) | 115.7 | 127.3 | |||||||||
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually | 75.1 | 62.3 | |||||||||
Grand Gulf sale-leaseback - (Note 5 - Grand Gulf Sale-Leaseback Transactions) | 55.6 | 55.6 | |||||||||
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 | |||||||||
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings) | 43.5 | 51.1 | |||||||||
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a) | 29.7 | 37.2 | |||||||||
Internal restructuring guaranteed tax credits (Note 2 - Internal Restructuring) | 26.4 | 33.0 | |||||||||
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 | 21.5 | 35.7 | |||||||||
Advanced metering system (AMS) surcharge - return to customers dependent upon AMS spend | 20.1 | 25.3 | |||||||||
Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions) | — | 21.2 | |||||||||
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement | 10.7 | 17.8 | |||||||||
Income tax rate change - returned to electric and gas customers through retail rates (Note 2 - Retail Rate Proceedings) | 7.3 | 13.9 | |||||||||
| Other | 35.5 | 39.0 | |||||||||
| Entergy Total | $2,323.9 | $1,961.0 | |||||||||
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Entergy Arkansas
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) | $597.4 | $460.3 | |||||||||
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings) | 43.5 | 46.6 | |||||||||
Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings) | 26.4 | 33.0 | |||||||||
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually | 19.6 | 19.7 | |||||||||
| Entergy Arkansas Total | $686.9 | $559.6 | |||||||||
Entergy Louisiana
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) | $567.7 | $436.5 | |||||||||
Louisiana Act 55 financing savings obligation (Note 3) | 144.3 | 97.1 | |||||||||
Vidalia purchased power agreement (Note 8) (b) | 115.7 | 127.3 | |||||||||
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a) | 29.7 | 37.1 | |||||||||
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 | 21.5 | 35.7 | |||||||||
Excess decommissioning recovery for Willow Glen - returned over one-year period through retail rates (Note 14 - Dispositions) | — | 21.2 | |||||||||
| Other | 39.4 | 39.2 | |||||||||
| Entergy Louisiana Total | $918.3 | $794.1 | |||||||||
Entergy Mississippi
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
Retail rate rider over-recovery - refunded through rate riders as rates are redetermined annually | $14.2 | $14.6 | |||||||||
Grand Gulf Over-Recovery - returned to customers through rate riders as rates are redetermined annually | 1.0 | 2.4 | |||||||||
Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings) | — | 4.5 | |||||||||
| Other | 0.6 | — | |||||||||
| Entergy Mississippi Total | $15.8 | $21.5 | |||||||||
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Entergy Texas
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
Advanced metering system (AMS) surcharge - returned to customers dependent upon AMS spend | $20.1 | $25.3 | |||||||||
Income tax rate change - refunded through a rate rider (Note 2 - Retail Rate Proceedings) | 6.5 | 10.4 | |||||||||
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically | 3.2 | 3.8 | |||||||||
| Other | 2.5 | 2.6 | |||||||||
| Entergy Texas Total | $32.3 | $42.1 | |||||||||
System Energy
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) | $529.0 | $403.3 | |||||||||
Grand Gulf sale-leaseback - (Note 5 - Grand Gulf Sale-Leaseback Transactions) | 55.6 | 55.6 | |||||||||
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 | |||||||||
Grand Gulf sale-leaseback accumulated deferred income taxes (a) | 25.7 | 12.3 | |||||||||
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement | 10.7 | 17.8 | |||||||||
| System Energy Total | $665.4 | $533.4 | |||||||||
(a)Offset by related asset.
(b)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% effective January 2018, the Vidalia purchased power agreement regulatory liability was reduced by $30.5 million and the Louisiana Act 55 financing savings obligation regulatory liabilities were reduced by $25 million, with corresponding increases 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.
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, including its effects on Entergy’s and the Registrant Subsidiaries’ regulatory asset/liability for income taxes.
Entergy Arkansas
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
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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.
As discussed below, 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; the tax adjustment rider will be closed after the credits are issued.
Entergy Louisiana
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 which, as discussed below, Entergy Louisiana filed in June 2018.
Entergy Mississippi
Entergy Mississippi filed its 2018 formula rate plan in March 2018 and included a proposal to return all of its unprotected excess accumulated deferred income taxes to customers through rates or in exchange for other assets, or a combination of both, by the end of 2018. In June 2018 the MPSC approved a stipulation filed by Entergy Mississippi and the Mississippi Public Utilities Staff in Entergy Mississippi’s formula rate plan filing that addressed Entergy Mississippi’s 2018 formula rate plan evaluation report and the ratemaking effects of the Tax Act. The stipulation provided for incorporating the reduction of the statutory federal income tax rate through Entergy Mississippi’s formula rate plan. The stipulation approved in June 2018 provided for the flow-back of protected excess accumulated deferred income taxes over the remaining lives of the assets through the formula rate plan. The stipulation also provided for the offset of unprotected excess accumulated deferred income taxes of $127.2 million against net utility plant and $2.2 million against other regulatory assets, and the return to customers of the remaining balance of unprotected excess accumulated deferred income taxes as recovery of a portion of fuel oil inventory and customer bill credits over a three-month period from July 2018 through September 2018, with an insignificant true-up reflected in the November 2018 power management rider filing. Entergy Mississippi recorded the reduction against net utility plant and other regulatory assets in June 2018. In third quarter 2018, Entergy Mississippi returned
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unprotected excess accumulated deferred income taxes of $25.8 million through customer bill credits and $5.8 million through the sale of fuel oil inventory.
Entergy New Orleans
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.
Entergy Texas
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 includes carrying charges and is in effect over a period of 12 months for larger customers and over a period of four years for other customers.
System Energy
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
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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.
The ALJ initial decision is an interim step in the FERC litigation process. 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. The FERC will review the case and issue an order in the proceeding, and the FERC may accept, reject, or modify the ALJ’s initial decision in whole or in part. Credits, if any, that might be required will only become due after the FERC issues its order reviewing the initial decision.
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 proposes 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 Cuts and Jobs 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. There is no formal deadline for FERC to rule on the motion.
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Fuel and purchased power cost recovery
The Utility operating companies are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements. The table below shows the amount of deferred fuel costs as of December 31, 2020 and 2019 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
| Entergy Arkansas (a) | $15.2 | $14.0 | |||||||||
| Entergy Louisiana (b) | $170.4 | $112.5 | |||||||||
| Entergy Mississippi | ($14.7) | ($70.4) | |||||||||
| Entergy New Orleans (b) | $6.2 | ($0.8) | |||||||||
| Entergy Texas | ($85.4) | ($13.0) | |||||||||
(a)Includes $68.2 million in 2020 and $67.7 million in 2019 of fuel and purchased power costs whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months.
(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.
Entergy Arkansas
Energy Cost Recovery Rider
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the prior calendar-year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over- or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.
In January 2014, Entergy Arkansas filed a motion with the APSC relating to its upcoming energy cost rate redetermination filing that was made in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude from the redetermination of its 2014 energy cost rate $65.9 million of incremental fuel and replacement energy costs incurred in 2013 as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information was available regarding various claims associated with the ANO stator incident. In February 2014 the APSC approved Entergy Arkansas’s request to retain that amount in its deferred fuel balance. In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that proceeding, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a regulatory proceeding for the purpose of recovering funds currently withheld from rates and related to the stator incident, including the $65.9 million of deferred fuel and purchased energy costs previously noted, subject to certain timelines and conditions set forth in the settlement agreement. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.
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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 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 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 2019, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01882 per kWh to $0.01462 per kWh and became effective with the first billing cycle in April 2019. In March 2019 the Arkansas Attorney General filed a response to Entergy Arkansas’s annual adjustment and included with its filing a motion for investigation of alleged overcharges to customers in connection with the FERC’s October 2018 order in the opportunity sales proceeding. Entergy Arkansas filed its response to the Attorney General’s motion in April 2019 in which Entergy Arkansas stated its intent to initiate a proceeding to address recovery issues related to the October 2018 FERC order. In May 2019, Entergy Arkansas initiated the opportunity sales recovery proceeding, discussed below, and requested that the APSC establish that proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC October 2018 order and related FERC orders in the opportunity sales proceeding. In June 2019 the APSC granted Entergy Arkansas’s request and also denied the Attorney General’s motion in the energy cost recovery proceeding seeking an investigation into Entergy Arkansas’s annual energy cost recovery rider adjustment and referred the evaluation of such matters to the opportunity sales recovery proceeding.
In March 2020, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01462 per kWh to $0.01052 per kWh. The redetermined rate became effective with the first billing cycle in April 2020 through the normal operation of the tariff.
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Entergy Louisiana
Entergy Louisiana recovers electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Louisiana’s purchased gas adjustments 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 July 2014 the LPSC authorized its staff to initiate an audit of the fuel adjustment clause filings by Entergy Gulf States Louisiana, whose business was combined with Entergy Louisiana in 2015. The audit includes a review of the reasonableness of charges flowed through Entergy Gulf States Louisiana’s fuel adjustment clause for the period from 2010 through 2013. In January 2019 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $900,000, plus interest, to customers based upon the imputation of a claim of vendor fault in servicing its nuclear plant. Entergy Louisiana recorded a provision in the first quarter 2019 for the potential outcome of the audit. In August 2019, Entergy Louisiana filed direct testimony challenging the basis for the LPSC staff’s recommended disallowance and providing an alternative calculation of replacement power costs should it be determined that a disallowance is appropriate. Entergy Louisiana’s calculation would require no refund to customers.
In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Louisiana through its fuel adjustment clause for the period from 2010 through 2013. In January 2019 the LPSC staff issued its audit report recommending that Entergy Louisiana refund approximately $7.3 million, plus interest, to customers based upon the imputation of a claim of vendor fault in servicing its nuclear plant. Entergy Louisiana recorded a provision in the first quarter 2019 for the potential outcome of the audit. In August 2019, Entergy Louisiana filed direct testimony challenging the basis for the LPSC staff’s recommended disallowance and providing an alternative calculation of replacement power costs should it be determined that a disallowance is appropriate. Entergy Louisiana’s calculation would require a refund to customers of approximately $4.3 million, plus interest, as compared to the LPSC staff’s recommendation of $7.3 million, plus interest. Responsive testimony was filed by the LPSC staff and intervenors in September 2019; all parties either agreed with or did not oppose Entergy Louisiana’s alternative calculation of replacement power costs.
In November 2019 the pending LPSC proceedings for the 2010-2013 Entergy Louisiana and Entergy Gulf States Louisiana audits were consolidated to facilitate a settlement of both fuel audits. In December 2019 an unopposed settlement was reached that requires a refund to legacy Entergy Louisiana customers of approximately $2.3 million, including interest, and no refund to legacy Entergy Gulf States Louisiana customers. The LPSC approved the settlement in January 2020. A one-time refund was made in February 2020.
In June 2016 the LPSC issued notice of audits of Entergy Louisiana’s fuel adjustment clause filings for the period 2014 through 2015 and purchased gas adjustment clause filings for the period 2012 through 2015. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and also includes a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audits include a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2014 through 2015 and charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2012 through 2015. Regarding the fuel adjustment clause filing, the LPSC staff issued a report in January 2021 that did not recommend a disallowance for the period 2014 through 2015 recoveries, but did propose various reporting requirements. Entergy Louisiana is currently reviewing the LPSC staff recommendations regarding reporting requirements. Regarding the purchased gas adjustment clause filings, the LPSC staff issued a report in February 2020 that did not recommend a disallowance for the period 2012 through 2015 recoveries. The LPSC issued an order in September 2020 accepting the LPSC staff’s report.
In May 2018 the LPSC staff provided notice of audits of Entergy Louisiana’s purchased gas adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s
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purchased gas adjustment clause for the period from 2016 through 2017. In February 2020 the LPSC staff issued an audit report recommending a disallowance of approximately $29 thousand. Entergy Louisiana submitted a letter disputing the basis of the proposed disallowance but indicated that due to the amount at issue it would not oppose the recommended refund. The LPSC staff and Entergy Louisiana submitted a joint report noting each party’s position on the substantive issues in the matter and recommending resolution of the matters. The LPSC issued an order in September 2020 resolving the matter and ordering a refund of approximately $29 thousand. In January 2021 the LPSC issued a notice closing the matter.
In March 2020 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2016 through 2019. Discovery commenced in September 2020 and is ongoing.
Entergy Mississippi
Entergy Mississippi’s rate schedules include an energy cost recovery rider that is adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
In January 2017 the MPSC certified to the Mississippi Legislature the audit reports of its independent auditors for the fuel year ending September 30, 2016. In November 2017 the Mississippi Public Utilities Staff separately engaged a consultant to review the September 2016 outage at the Grand Gulf Nuclear Station and to review ongoing operations at Grand Gulf. This engagement continues, and subsequently, was expanded to include all outages at Grand Gulf that occurred through 2019.
In November 2017, 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 $61.5 million as of September 30, 2017. In January 2018 the MPSC approved the proposed energy cost factors effective for February 2018 bills.
In November 2018, 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 $57 million as of September 30, 2018. In January 2019 the MPSC approved the proposed energy cost factor effective for February 2019 bills.
In November 2019, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation included $39.6 million of prior over-recovery flowing back to customers beginning February 2020. Entergy Mississippi’s balance in its deferred fuel account did not decrease as expected after implementation of the new factor. In an effort to assist customers during the COVID-19 pandemic, in May 2020, Entergy Mississippi requested an interim adjustment to the energy cost recovery rider to credit approximately $50 million from the over-recovered balance in the deferred fuel account to customers over four consecutive billing months. The MPSC approved this interim adjustment in May 2020 effective for June through September 2020 bills.
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.
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Entergy New Orleans
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy 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
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates. Semi-annual revisions of the fixed fuel factor are 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. A fuel reconciliation is required to be filed at least once every three years and outside of a base rate case filing.
In December 2017, Entergy Texas filed an application for a fuel refund of approximately $30.5 million for the months of May 2017 through October 2017. Also in December 2017, the PUCT’s ALJ approved the refund on an interim basis. For most customers, the refunds flowed through bills from January 2018 through March 2018. The fuel refund was approved by the PUCT in March 2018.
In September 2019, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period from April 2016 through March 2019. During the reconciliation period, Entergy Texas incurred approximately $1.6 billion in Texas jurisdictional eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. Entergy Texas estimated an under-recovery balance of approximately $25.8 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2019. In March 2020 an intervenor filed testimony proposing that the PUCT disallow: (1) $2 million in replacement power costs associated with generation outages during the reconciliation period; and (2) $24.4 million associated with the operation of the Spindletop natural gas storage facility during the reconciliation period. In April 2020, Entergy Texas filed rebuttal testimony refuting all points raised by the intervenor. In June 2020 the parties filed a stipulation and settlement agreement, which included a $1.2 million disallowance not associated with any particular issue raised by any party. The PUCT approved the settlement in August 2020.
In July 2020, Entergy Texas filed an application with the PUCT to implement an interim fuel refund of $25.5 million, including interest. Entergy Texas proposes that the interim fuel refund be implemented beginning with the first August 2020 billing cycle over a three-month period for smaller customers and in a lump sum amount in the billing month of August 2020 for transmission-level customers. The interim fuel refund was approved in July 2020, and Entergy Texas began refunds in August 2020.
In February 2021, Entergy Texas filed an application to implement a fuel refund for a cumulative over-recovery of approximately $75 million that is primarily attributable to settlements received by Entergy Texas from MISO related to Hurricane Laura. Entergy Texas planned to issue the refund over the period of March through August 2021. On February 22, 2021, Entergy Texas filed a motion to abate its fuel refund proceeding to assess how the February 2021 winter storm impacted Entergy Texas’s fuel over-recovery position.
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Retail Rate Proceedings
Filings with the APSC (Entergy Arkansas)
Retail Rates
2018 Formula Rate Plan Filing
In July 2018, Entergy Arkansas filed with the APSC its 2018 formula rate plan filing to set its formula rate for the 2019 calendar year. The filing showed Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2019 test period to be below the formula rate plan bandwidth. Additionally, the filing included the first netting adjustment under the current formula rate plan for the historical test year 2017, reflecting the change in formula rate plan revenues associated with actual 2017 results when compared to the allowed rate of return on equity. The filing included a projected $73.4 million revenue deficiency for 2019 and a $95.6 million revenue deficiency for the 2017 historical test year, for a total revenue requirement of $169 million for this filing. 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 four percent of total revenue, which originally was $65.4 million but was increased to $66.7 million based upon the APSC staff’s updated calculation of 2018 revenue. In October 2018, Entergy Arkansas and the parties to the proceeding filed joint motions to approve a partial settlement agreement as to certain factual issues and agreed to brief contested legal issues. In November 2018 the APSC held a hearing and was briefed on a contested legal issue. In December 2018 the APSC issued a decision related to the initial legal brief, approved the partial settlement agreement and $66.7 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan, with updated rates going into effect for the first billing cycle of January 2019.
2019 Formula Rate Plan Filing
In July 2019, Entergy Arkansas filed with the APSC its 2019 formula rate plan filing to set its formula rate for the 2020 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2020 and a netting adjustment for the historical year 2018. The total proposed formula rate plan rider revenue change designed to produce a target rate of return on common equity of 9.75% is $15.3 million, which is based upon a deficiency of approximately $61.9 million for the 2020 projected year, netted with a credit of approximately $46.6 million in the 2018 historical year netting adjustment. During 2018 Entergy Arkansas experienced higher-than expected sales volume, and actual costs were lower than forecasted. These changes, coupled with a reduced income tax rate resulting from the Tax Cuts and Jobs Act, resulted in the credit for the historical year netting adjustment. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflected the estimate of the historical year netting adjustment that was expected to be included in the 2019 filing. In 2019, Entergy Arkansas recorded additional provisions totaling $11.5 million to reflect the updated estimate of the historical year netting adjustment included in the 2019 filing. In October 2019 other parties in the proceeding filed their errors and objections requesting certain adjustments to Entergy Arkansas’s filing that would reduce or eliminate Entergy Arkansas’s proposed revenue change. Entergy Arkansas filed its response addressing the requested adjustments in October 2019. In its response, Entergy Arkansas accepted certain of the adjustments recommended by the General Staff of the APSC that would reduce the proposed formula rate plan rider revenue change to $14 million. Entergy Arkansas disputed the remaining adjustments proposed by the parties. In October 2019, Entergy Arkansas filed a unanimous settlement agreement with the other parties in the proceeding seeking APSC approval of a revised total formula rate plan rider revenue change of $10.1 million. In its July 2019 formula rate plan filing, Entergy Arkansas proposed to recover an $11.2 million regulatory asset, amortized over five years, associated with specific costs related to the potential construction of scrubbers at the White Bluff plant. Although Entergy Arkansas does not concede that the regulatory asset lacks merit, for purposes of reaching a settlement on the total formula rate plan rider amount, Entergy Arkansas agreed not to include the White Bluff scrubber regulatory asset cost in the 2019 formula rate plan filing or future filings. Entergy Arkansas recorded a write-off in 2019 of the $11.2 million White Bluff scrubber regulatory asset. In December 2019 the APSC approved the settlement as being
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in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2020.
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 is 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. In October 2020 other parties in the proceeding filed their errors and objections recommending certain adjustments, and Entergy Arkansas filed responsive testimony disputing these adjustments. 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, and in January 2021 the APSC granted further consideration of Entergy Arkansas’s petition. Based on the progress of the proceeding to date, 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. Also with the formula rate plan filing, Entergy Arkansas is requesting an extension of the formula rate plan rider for a second five-year term. Decisions by the APSC on the netting adjustment rehearing and the extension are expected in March 2021.
COVID-19 Orders
In April 2020, in light of the COVID-19 pandemic, the APSC issued an order requiring utilities, to the extent they had not already done so, to suspend service disconnections during the remaining pendency of the Arkansas Governor’s emergency declaration or until the APSC rescinds the directive. The order also authorizes utilities to establish a regulatory asset to record costs resulting from the suspension of service disconnections, directs that in future proceedings the APSC will consider whether the request for recovery of these regulatory assets is reasonable and necessary, and requires utilities to track and report the costs and any savings directly attributable to suspension of disconnects. In May 2020 the APSC approved Entergy Arkansas expanding deferred payment agreements to assist customers during the COVID-19 pandemic. Quarterly reporting began in August 2020 and the APSC ordered additional reporting in October 2020 regarding utilities’ transitional plans for ending the moratorium on service disconnects. In February 2021 the APSC issued an order finding that it is not in the public interest to immediately lift the moratorium on service disconnects, but to announce a target date of May 3, 2021. In March 2021 the APSC will issue an order either confirming the lifting of the moratorium on service disconnects or extending the moratorium. As of December 31, 2020, Entergy Arkansas recorded a regulatory asset of $10.5 million for costs associated with the COVID-19 pandemic.
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Internal Restructuring
In November 2017, Entergy Arkansas filed an application with the APSC seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy Arkansas to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. In July 2018, Entergy Arkansas filed a settlement, reached by all parties in the APSC proceeding, resolving all issues. The APSC approved the settlement agreement and restructuring in August 2018. Pursuant to the settlement agreement, Entergy Arkansas will credit retail customers $39.6 million over six years, beginning in 2019. Entergy Arkansas also received the required FERC and NRC approvals.
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.
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 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 and intervenors submitted their responses to Entergy Louisiana’s original formula rate plan evaluation report and supplemental compliance updates. The LPSC staff asserted objections/reservations
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regarding 1) Entergy Louisiana’s proposed rate adjustments associated with the return of excess accumulated deferred income taxes pursuant to the Tax Act and the treatment of accumulated deferred income taxes related to reductions of rate base; 2) Entergy Louisiana’s reservation regarding treatment of a regulatory asset related to certain special orders by the LPSC; and 3) test year expenses billed from Entergy Services to Entergy Louisiana. Intervenors also objected to Entergy Louisiana’s treatment of the regulatory asset related to certain special orders by the LPSC. A procedural schedule has not yet been established to resolve these issues.
Entergy Louisiana also included in its filing a presentation of an initial proposal to combine the legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana residential rates, which combination, if approved, would be accomplished on a revenue-neutral basis intended not to affect the rates of other customer classes.
Commercial operation at J. Wayne Leonard Power Station (formerly St. Charles Power Station) commenced in May 2019. In May 2019, Entergy Louisiana filed an update to its 2017 formula rate plan evaluation report to include the estimated first-year revenue requirement of $109.5 million associated with the J. Wayne Leonard Power Station. The resulting interim adjustment to rates became effective with the first billing cycle of June 2019. In June 2020, Entergy Louisiana submitted information to the LPSC to review the prudence of Entergy Louisiana’s management of the project. In August 2020 discovery commenced and a procedural schedule was established with a hearing in July 2021.
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 will decrease as a result of this filing, overall formula rate plan revenues will increase by approximately $118.7 million. This outcome is 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 is subject to review by the LPSC. Resulting rates were implemented in September 2019, subject to refund.
Entergy Louisiana also included in its filing a presentation of an initial proposal to combine the legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana residential rates, which combination, if approved, would be accomplished on a revenue-neutral basis intended not to affect the rates of other customer classes. Entergy Louisiana contemplates that any combination of residential rates resulting from this request would be implemented with the results of the 2019 test year formula rate plan filing.
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 its report the LPSC staff re-urged reservations with respect to the outstanding issues from the 2017 test year formula rate plan filing and disputed the inclusion of certain affiliate costs for test years 2017 and 2018. The LPSC staff objected to Entergy Louisiana’s proposal to combine residential rates but proposed the setting of a status conference to establish a procedural schedule to more fully address the issue. The LPSC staff also reserved its right to object to the treatment of the sale of Willow Glen reflected in the evaluation report and to the August 2019 compliance update, which was made primarily to update the capital additions reflected in the formula rate plan’s transmission recovery mechanism, based on limited time to review it. Additionally, since the completion of certain transmission projects, the LPSC staff issued supplemental data requests addressing the prudence of Entergy Louisiana’s expenditures in connection with those projects. Entergy Louisiana has responded to all such requests.
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.
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In an effort to narrow the remaining issues in formula rate plan test years 2017 and 2018, Entergy Louisiana provided notice to the parties in October 2020 that it was withdrawing its request to combine residential rates. Entergy Louisiana noted that the withdrawal is without prejudice to Entergy Louisiana’s right to seek to combine residential rates in a future proceeding.
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 will not change as a result of this filing, overall formula rate plan revenues will increase 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 is 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 the revenue neutral rider adjustment, and as updated in an August 2020 filing, were implemented in September 2020, subject to refund. Entergy Louisiana is in the process of providing additional information and details on the May 2020 filing as requested by the LPSC staff.
In November 2020, Entergy Louisiana accepted ownership of the Washington Parish Energy Center and filed an update to its 2019 formula rate plan evaluation report to include the estimated first-year revenue requirement of $35 million associated with the Washington Parish Energy Center. The resulting interim adjustment to rates became effective with the first billing cycle of December 2020. In January 2021, Entergy Louisiana filed an update to its 2019 formula rate plan evaluation report to include the implementation of a scheduled step-up in its nuclear decommissioning revenue requirement and a true-up for under-collections of nuclear decommissioning expenses. The total rate adjustment would increase formula rate plan revenues by approximately $1.2 million. The resulting interim adjustment to rates became effective with the first billing cycle of February 2021.
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 seeks 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. Entergy Louisiana also seeks to maintain its existing additional capacity mechanism, tax reform adjustment mechanism, transmission recovery mechanism, and the MISO cost recovery mechanism. Entergy Louisiana also seeks to add a distribution cost recovery mechanism which operates in substantially the same manner as the transmission recovery mechanism, seeks to utilize end of period rate base to calculate cost of service, and requests a deferral of certain expenses incurred for outside of right-of-way vegetation programs. Settlement discussions are ongoing.
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.
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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 have 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. As of December 31, 2020, Entergy Louisiana recorded a regulatory asset of $48.8 million for costs associated with the COVID-19 pandemic.
Filings with the MPSC (Entergy Mississippi)
Retail Rates
2018 Formula Rate Plan Filing
In March 2018, Entergy Mississippi submitted its formula rate plan 2018 test year filing and 2017 look-back filing showing Entergy Mississippi’s earned return for the historical 2017 calendar year and projected earned return for the 2018 calendar year, in large part as a result of the lower federal corporate income tax rate effective in 2018, to be within the formula rate plan bandwidth, resulting in no change in rates. In June 2018, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a stipulation that confirmed that Entergy Mississippi’s earned returns for both the 2017 look-back filing and 2018 test year were within the respective formula rate plan bandwidths. In June 2018 the MPSC approved the stipulation, which resulted in no change in rates. See “Regulatory activity regarding the Tax Cuts and Jobs Act” above for additional discussion regarding the treatment of the effects of the lower federal corporate income tax rate.
Formula Rate Plan Revisions
In October 2018, Entergy Mississippi proposed revisions to its formula rate plan that would 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, including the non-fuel annual ownership costs of the Choctaw Generating Station, as well as to allow similar cost recovery treatment for other future capacity acquisitions, such as the Sunflower Solar Facility, that are approved by the MPSC. In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to provide for an interim capacity rate adjustment mechanism to recover the $59 million first-year annual revenue requirement associated with the non-fuel ownership costs of the Choctaw Generating Station, which Entergy Mississippi began billing in January 2020. 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. Effective with the April 2020 billing cycle, Entergy Mississippi implemented a rider to recover $22 million in vegetation management costs.
2019 Formula Rate Plan Filing
In March 2019, Entergy Mississippi submitted its formula rate plan 2019 test year filing and 2018 look-back filing showing Entergy Mississippi’s earned return for the historical 2018 calendar year to be above the
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formula rate plan bandwidth and projected earned return for the 2019 calendar year to be below the formula rate plan bandwidth. The 2019 test year filing shows a $36.8 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.94% return on rate base, within the formula rate plan bandwidth. The 2018 look-back filing compares actual 2018 results to the approved benchmark return on rate base and shows a $10.1 million interim decrease in formula rate plan revenues is necessary. In the fourth quarter 2018, Entergy Mississippi recorded a provision of $9.3 million that reflected the estimate of the difference between the 2018 expected earned rate of return on rate base and an established performance-adjusted benchmark rate of return under the formula rate plan performance-adjusted bandwidth mechanism. In the first quarter 2019, Entergy Mississippi recorded a $0.8 million increase in the provision to reflect the amount shown in the look-back filing. In June 2019, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed that the 2019 test year filing showed that a $32.8 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.93% return on rate base, within the formula rate plan bandwidth. Additionally, pursuant to the joint stipulation, Entergy Mississippi’s 2018 look-back filing reflected an earned return on rate base of 7.81% in calendar year 2018 which is above the look-back benchmark return on rate base of 7.13%, resulting in an $11 million decrease in formula rate plan revenues on an interim basis through May 2020. In the second quarter 2019, Entergy Mississippi recorded an additional $0.9 million increase in the provision to reflect the $11 million shown in the look-back filing. In June 2019 the MPSC approved the joint stipulation with rates effective for the first billing cycle of July 2019.
2020 Formula Rate Plan Filing
In March 2020, Entergy Mississippi submitted its formula rate plan 2020 test year filing and 2019 look-back filing showing Entergy Mississippi’s earned return for the historical 2019 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2020 calendar year to be below the formula rate plan bandwidth. The 2020 test year filing shows a $24.6 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.51% return on rate base, within the formula rate plan bandwidth. The 2019 look-back filing compares actual 2019 results to the approved benchmark return on rate base and reflects the need for a $7.3 million interim increase in formula rate plan revenues. In accordance with the MPSC-approved revisions to the formula rate plan, Entergy Mississippi implemented a $24.3 million interim rate increase, reflecting a cap equal to 2% of 2019 retail revenues, effective with the April 2020 billing cycle, subject to refund. In June 2020, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed that the 2020 test year filing showed that a $23.8 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.51% return on rate base, within the formula rate plan bandwidth. Pursuant to the joint stipulation, Entergy Mississippi’s 2019 look-back filing reflected an earned return on rate base of 6.75% in calendar year 2019, which is within the look-back bandwidth. As a result, there is no change in formula rate plan revenues in the 2019 look-back filing. In June 2020 the MPSC approved the joint stipulation with rates effective for the first billing cycle of July 2020. In the June 2020 order the MPSC directed Entergy Mississippi to submit revisions to its formula rate plan to realign recovery of costs from its energy efficiency cost recovery rider to its formula rate plan. 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.
COVID-19 Orders
In March 2020 the MPSC issued an order suspending disconnections for a period of sixty days. The MPSC extended the order on disconnections through May 26, 2020. In April 2020 the MPSC issued an order authorizing utilities to defer incremental costs and expenses associated with COVID-19 compliance and to seek future recovery through rates of the prudently incurred incremental costs and expenses. In December 2020, Entergy Mississippi resumed disconnections to commercial, industrial, and governmental customers with past-due balances that have not made payment arrangements. In January 2021, Entergy Mississippi resumed disconnecting service for residential
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customers with past-due balances that have not made arrangements with the company. As of December 31, 2020, Entergy Mississippi recorded a regulatory asset of $19.2 million for costs associated with the COVID-19 pandemic.
Internal Restructuring
In March 2018, Entergy Mississippi filed an application with the MPSC seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy Mississippi to a new entity, which would ultimately be held by an existing Entergy subsidiary holding company. In September 2018, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed a joint stipulation regarding the restructuring filing. In September 2018 the MPSC issued an order accepting the stipulation in its entirety and approving the restructuring and credits of $27 million to retail customers over six years, consisting of annual payments of $4.5 million for the years 2019-2024. Entergy Mississippi also received the required FERC approval.
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.
In December 2018, Entergy Mississippi filed its notice of intent to implement the restructuring credit rider to allow Entergy Mississippi to return credits of $27 million to retail customers over six years. In January 2019 the MPSC approved the proposed restructuring credit adjustment factor, which is effective for bills rendered beginning February 2019.
Filings with the City Council (Entergy New Orleans)
Retail Rates
Energy Efficiency
In December 2019, Entergy New Orleans filed an application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022. Entergy New Orleans proposed to recover the costs of the program through mechanisms previously approved by the City Council or through the energy efficiency cost recovery rider, which was approved in the 2018 combined rate case resolution. In January 2020 the City Council’s advisors recommended that, beginning with Program Year 10, the City Council allow Entergy New Orleans to earn a utility performance incentive of 7% of Energy Smart costs for each year in
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which Entergy New Orleans achieves 100% of the City Council’s savings targets for Energy Smart. In February 2020 the City Council approved Entergy New Orleans’s application.
2018 Base Rate Case
In September 2018, Entergy New Orleans filed an electric and gas base rate case with the City Council. The filing requested a 10.5% return on equity for electric operations with opportunity to earn a 10.75% return on equity through a performance adder provision of the electric formula rate plan in subsequent years under a formula rate plan and requested a 10.75% return on equity for gas operations. The proposed electric rates in the revised filing reflect a net reduction of $20.3 million. The reduction in electric rates includes a base rate increase of $135.2 million, of which $131.5 million is associated with moving costs currently collected through fuel and other riders into base rates, plus a request for an advanced metering surcharge to recover $7.1 million associated with advanced metering infrastructure, offset by a net decrease of $31.1 million related to fuel and other riders. The filing also included a proposed gas rate decrease of $142 thousand. Entergy New Orleans’s rates reflected the inclusion of federal income tax reductions due to the Tax Act and the provisions of a previously-approved agreement in principle determining how the benefits of the Tax Act would flow. Entergy New Orleans included cost of service studies for electric and gas operations for the twelve months ended December 31, 2017 and the projected twelve months ending December 31, 2018. In addition, Entergy New Orleans included capital additions expected to be placed into service for the period through December 31, 2019. Entergy New Orleans based its request for a change in rates on the projected twelve months ending December 31, 2018.
The filing’s major provisions included: (1) a new electric rate structure, which realigns the revenue requirement associated with capacity and long-term service agreement expense from certain existing riders to base revenue, provides for the recovery of the cost of advanced metering infrastructure, and partially blends rates for Entergy New Orleans’s customers residing in Algiers with customers residing in the remainder of Orleans Parish through a three-year phase-in; (2) contemporaneous cost recovery riders for investments in energy efficiency/demand response, incremental changes in capacity/long-term service agreement costs, grid modernization investment, and gas infrastructure replacement investment; and (3) formula rate plans for both electric and gas operations. In February 2019 the City Council’s advisors and several intervenors filed testimony in response to Entergy New Orleans’s application. The City Council’s advisors recommended, among other things, overall rate reductions of approximately $33 million in electric rates and $3.8 million in gas rates. Certain intervenors recommended overall rate reductions of up to approximately $49 million in electric rates and $5 million in gas rates. An evidentiary hearing was held in June 2019, and the record and post-hearing briefs were submitted in July 2019.
In October 2019 the City Council’s Utility Committee approved a resolution for a change in electric and gas rates for consideration by the full City Council that included a 9.35% return on common equity, an equity ratio of the lesser of 50% or Entergy New Orleans’s actual equity ratio, and a total reduction in revenues that Entergy New Orleans initially estimated to be approximately $39 million ($36 million electric; $3 million gas). At its November 7, 2019 meeting, the full City Council approved the resolution that had previously been approved by the City Council’s Utility Committee. Based on the approved resolution, in the fourth quarter 2019 Entergy New Orleans recorded an accrual of $10 million that reflects the estimate of the revenue billed in 2019 to be refunded to customers in 2020 based on an August 2019 effective date for the rate decrease. Entergy New Orleans also recorded a total of $12 million in regulatory assets for rate case costs and information technology costs associated with integrating Algiers customers with Entergy New Orleans’s legacy system and records. Entergy New Orleans will also be allowed to recover $10 million of retired general plant costs over a 20-year period.
The resolution directed Entergy New Orleans to submit a compliance filing within 30 days of the date of the resolution to facilitate the eventual implementation of rates, including all necessary calculations and conforming rate schedules and riders. The electric formula rate plan rider includes, among other things, 1) a provision for forward-looking adjustments to include known and measurable changes realized up to 12 months after the evaluation period; 2) a decoupling mechanism; and 3) recognition that Entergy New Orleans is authorized to make an in-service adjustment to the formula rate plan to include the non-fuel cost of the New Orleans Power Station in
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rates, unless the two pending appeals in the New Orleans Power Station proceeding have not concluded. Under this circumstance, Entergy New Orleans shall be permitted to defer the New Orleans Power Station non-fuel costs, including the cost of capital, until Entergy New Orleans commences non-fuel cost recovery. After taking into account the requirements for submission of the compliance filing, the total annual revenue requirement reduction required by the resolution was refined to approximately $45 million ($42 million electric, including $29 million in rider reductions; $3 million gas). In January 2020 the City Council’s advisors found that the rates calculated by Entergy New Orleans and reflected in the December 2019 compliance filing should be implemented, except with respect to the City Council-approved energy efficiency cost recovery rider, which rider calculation should take into account events to be determined by the City Council in the future. Also in response to the resolution, Entergy New Orleans filed timely a petition for appeal and judicial review and for stay of or injunctive relief alleging that the resolution is unlawful in failing to produce just and reasonable rates. A hearing on the requested injunction was scheduled in Civil District Court for February 2020, but by joint motion of the City Council and Entergy New Orleans, the Civil District Court issued an order for a limited remand to the City Council to consider a potential agreement in principle/stipulation at its February 20, 2020 meeting. On February 17, 2020, Entergy New Orleans filed with the City Council an agreement in principle between Entergy New Orleans and the City Council’s advisors. On February 20, 2020, the City Council voted to approve the proposed agreement in principle and issued a resolution modifying the required treatment of certain accumulated deferred income taxes. As a result of the agreement in principle, the total annual revenue requirement reduction will be approximately $45 million ($42 million electric, including $29 million in rider reductions; and $3 million gas). Entergy New Orleans fully implemented the new rates in April 2020. In January 2021, pursuant to the agreement in principle approved by the City Council in October 2020, Entergy New Orleans filed with Civil District Court a motion seeking to dismiss its petition for judicial review of the City Council’s resolution in the 2018 combined rate case.
Commercial operation of the New Orleans Power Station commenced in May 2020. In accordance with the City Council resolution issued in the 2018 base rate case proceeding, Entergy New Orleans had been deferring the New Orleans Power Station non-fuel costs pending the conclusion of the appellate proceedings. In October 2020 the Louisiana Supreme Court denied all writ applications relating to the New Orleans Power Station. With those denials, Entergy New Orleans began recovering New Orleans Power Station costs in rates in November 2020. As of December 31, 2020 the regulatory asset for the deferral of New Orleans Power Station non-fuel costs was $5 million. Entergy New Orleans is recovering the costs over a five-year period that began in November 2020. In December 2020 the Alliance for Affordable Energy and Sierra Club filed a joint motion with the City Council to institute a prudence review to investigate the costs of the New Orleans Power Station. On January 28, 2021, the City Council passed a resolution giving parties 30 days to respond to the motion. Entergy New Orleans plans to respond to the motion.
2020 Formula Rate Plan Filing
Entergy New Orleans’s first annual filing under the three-year formula rate plan approved by the City Council in November 2019 was originally due to be filed in April 2020. The authorized return on equity under the approved three-year formula rate plan is 9.35% for both electric and gas operations. The City Council approved several extensions of the deadline to allow additional time to assess the effects of the COVID-19 pandemic on the New Orleans community, Entergy New Orleans customers, and Entergy New Orleans itself. In October 2020 the City Council approved an agreement in principle filed by Entergy New Orleans that results in Entergy New Orleans foregoing its 2020 formula rate plan filing and shifting the three-year formula rate plan to filings in 2021, 2022, and 2023. Key provisions of the agreement in principle include: changing the lower of actual equity ratio or 50% equity ratio approved in the rate case to a hypothetical capital structure of 51% equity and 49% debt for the duration of the three-year formula rate plan; changing the 2% depreciation rate for the New Orleans Power Station approved in the rate case to 3%; retention of over-recovery of $2.2 million in rider revenues; recovery of $1.4 million of certain rate case expenses outside of the earnings band; recovery of the New Orleans Solar Station costs upon commercial operation; and Entergy New Orleans’s dismissal of its 2018 rate case appeal.
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COVID-19 Orders
In March 2020, Entergy New Orleans voluntarily suspended customer disconnections for non-payment of utility bills through May 2020. Subsequently, the City Council ordered that the moratorium be extended to August 1, 2020. In May 2020 the City Council issued an accounting order authorizing Entergy New Orleans to establish a regulatory asset for incremental COVID-19-related expenses. In January 2021, Entergy New Orleans resumed disconnecting service to commercial and small business customers with past-due balances that have not made payment arrangements. In February 2021 the City Council adopted a resolution suspending residential customer disconnections for non-payment of utility bills and suspending the assessment and accumulation of late fees on residential customers with past-due balances through May 15, 2021. As of December 31, 2020, Entergy New Orleans recorded a regulatory asset of $14.3 million for costs associated with the COVID-19 pandemic.
In June 2020 the City Council established the City Council Cares Program and directed Entergy New Orleans to use the approximately $7 million refund received from the Entergy Arkansas opportunity sales FERC proceeding, currently being held in escrow, and approximately $15 million of non-securitized storm reserves to fund this program, which is intended to provide temporary bill relief to customers who become unemployed during the COVID-19 pandemic. The program became effective July 1, 2020, and offers qualifying residential customers bill credits of $100 per month for up to four months, for a maximum of $400 in residential customer bill credits. As of December 31, 2020, credits of $3.4 million have been applied to customer bills under the City Council Cares Program.
Filings with the PUCT and Texas Cities (Entergy Texas)
Retail Rates
2018 Base Rate Case
In May 2018, Entergy Texas filed a base rate case with the PUCT seeking an increase in base rates and rider rates of approximately $166 million, of which $48 million is associated with moving costs currently being collected through riders into base rates such that the total incremental revenue requirement increase is approximately $118 million. The base rate case was based on a 12-month test year ending December 31, 2017. In addition, Entergy Texas included capital additions placed into service for the period of April 1, 2013 through December 31, 2017, as well as a post-test year adjustment to include capital additions placed in service by June 30, 2018.
In October 2018 the parties filed an unopposed settlement resolving all issues in the proceeding and a motion for interim rates effective for usage on and after October 17, 2018. The unopposed settlement reflects the following terms: a base rate increase of $53.2 million (net of costs realigned from riders and including updated depreciation rates), a $25 million refund to reflect the lower federal income tax rate applicable to Entergy Texas from January 25, 2018 through the date new rates are implemented, $6 million of capitalized skylining tree hazard costs will not be recovered from customers, $242.5 million of protected excess accumulated deferred income taxes, which includes a tax gross-up, will be returned to customers through base rates under the average rate assumption method over the lives of the associated assets, and $185.2 million of unprotected excess accumulated deferred income taxes, which includes a tax gross-up, will be returned to customers through a rider. The unprotected excess accumulated deferred income taxes rider will include carrying charges and will be in effect over a period of 12 months for large customers and over a period of four years for other customers. The settlement also provides for the deferral of $24.5 million of costs associated with the remaining book value of the Neches and Sabine 2 plants, previously taken out of service, to be recovered over a ten-year period and the deferral of $20.5 million of costs associated with Hurricane Harvey to be recovered over a 12-year period, each beginning in October 2018. The settlement provides final resolution of all issues in the matter, including those related to the Tax Act. In October 2018 the ALJ granted the unopposed motion for interim rates to be effective for service rendered on or after October 17, 2018. In December 2018 the PUCT issued an order approving the unopposed settlement.
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Distribution Cost Recovery Factor (DCRF) Rider
In March 2019, Entergy Texas filed with the PUCT a request to set a new DCRF rider. The proposed new DCRF rider is designed to collect approximately $3.2 million annually from Entergy Texas’s retail customers based on its capital invested in distribution between January 1, 2018 and December 31, 2018. In September 2019 the PUCT issued an order approving rates, which had been effective on an interim basis since June 2019, at the level proposed in Entergy Texas’s application.
In March 2020, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $23.6 million annually, or $20.4 million in incremental annual DCRF revenue beyond Entergy Texas’s then-effective DCRF rider, based on its capital invested in distribution between January 1, 2019 and December 31, 2019. In May and June 2020 intervenors filed testimony recommending reductions in Entergy Texas’s annual revenue requirement of approximately $0.3 million and $4.1 million. The parties briefed the contested issues in this matter and a proposal for decision was issued in September 2020 recommending a $4.1 million revenue reduction related to non-Advanced Metering System meters included in the DCRF calculation. The parties filed exceptions to the proposal for decision and replies to those exceptions in September 2020. In October 2020 the PUCT issued a final order approving a $16.3 million incremental annual DCRF revenue increase.
In October 2020, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The proposed rider is 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 currently effective DCRF rider based on its capital invested in distribution between January 1, 2020 and August 31, 2020. In February 2021 the administrative law judge with the State Office of Administrative Hearings approved Entergy Texas's agreed motion for interim rates, which will go into effect in March 2021. The administrative law judge also adopted a procedural schedule setting a hearing on the merits, if necessary, in April 2021.
Transmission Cost Recovery Factor (TCRF) Rider
In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The proposed new TCRF rider is 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 August 2019, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended TCRF rider is designed to collect approximately $19.4 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and June 30, 2019, which is $16.7 million in incremental annual revenue above the $2.7 million approved in the prior pending TCRF proceeding. In January 2020 the PUCT issued an order approving an unopposed settlement providing for recovery of the requested revenue requirement. Entergy Texas implemented the amended rider beginning with bills covering usage on and after January 23, 2020.
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In October 2020, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $51 million annually, or $31.6 million in incremental annual revenues beyond Entergy Texas’s currently effective TCRF rider based on its capital invested in transmission between July 1, 2019 and August 31, 2020. A procedural schedule was established with a hearing scheduled in March 2021. In February 2021, Entergy Texas filed an agreed motion to abate the procedural schedule, noting that the parties had reached a settlement in principle, and the administrative law judge granted the motion to abate.
COVID-19 Orders
In March 2020 the PUCT authorized electric utilities to record as a regulatory asset expenses resulting from the effects of COVID-19. In future proceedings the PUCT will consider whether each utility's request for recovery of these regulatory assets is reasonable and necessary, the appropriate period of recovery, and any amount of carrying costs thereon. In March 2020 the PUCT ordered a moratorium on disconnections for nonpayment for all customer classes, but, in April 2020, revised the disconnect moratorium to apply only to residential customers. The PUCT allowed the moratorium to expire on June 13, 2020, but on July 17, 2020, the PUCT re-established the disconnect moratorium for residential customers until August 31, 2020. In January 2021, Entergy Texas resumed disconnections for customers with past-due balances that have not made payment arrangements. As of December 31, 2020, Entergy Texas recorded a regulatory asset of $12.9 million for costs associated with the COVID-19 pandemic.
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 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 is 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 retains 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. On January 14, 2021, the PUCT approved the generation cost recovery rider settlement rates on an interim basis and abated the proceeding. Within 60 days of Montgomery County Power Station being placed in service on January 1, 2021, Entergy Texas will file to update its generation cost recovery rider to include investment in Montgomery County Power Station after August 31, 2020. The current estimated cost of Montgomery County Power Station, including transmission interconnection and network upgrades, is approximately $921 million. Of this investment, approximately $765 million is eligible to begin being recovered through the generation cost recovery rider. Entergy Texas will address recovery of the remainder of its Montgomery County Power Station investment through other rate mechanisms.
In December 2020, Entergy Texas filed an application to amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which is expected to close in April 2021. The initial generation cost recovery rider rates proposed in the application represent no change from the generation cost recovery rider rates to be established in Entergy Texas’ previous generation cost recovery rider proceeding. Once Entergy Texas has acquired the Hardin County Peaking Facility, its investment in the facility will be reflected in the updated filing to Entergy Texas’ application, which will be made within 60 days of the acquisition’s closing.
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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
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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. The December 2018 compliance filing is pending FERC action. 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) | |||||||||||
| (In Millions) | |||||||||||
| Principal | Interest | Total | |||||||||
| Entergy Arkansas | $68 | $67 | $135 | ||||||||
| Entergy Louisiana | ($30) | ($29) | ($59) | ||||||||
| Entergy Mississippi | ($18) | ($18) | ($36) | ||||||||
| Entergy New Orleans | ($3) | ($4) | ($7) | ||||||||
| Entergy Texas | ($17) | ($16) | ($33) | ||||||||
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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 have been 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 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.
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
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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 scheduled a hearing for February 26, 2021 regarding issues addressed in the pre-trial conference report.
Complaints Against System Energy
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.
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 have been 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 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
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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 and the APSC and 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 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 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 Entergy 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 and the APSC and 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 MPSC recommend that 35.98% be set as the common equity ratio for System Energy. As an alternative, the APSC and 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.
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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
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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, and the initial decision is due in March 2021. System Energy recorded a provision against revenue for the potential outcome of this proceeding.
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, MPSC, and 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.
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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, MPSC, APSC and 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 $191 million through December 31, 2020. 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 an 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 System Energy’s rate base should have been reduced for those liabilities. If the ALJ’s initial decision is upheld, the estimated refund for this issue through December 31, 2020, is approximately $422 million, plus interest, which is approximately $110 million through December 31, 2020. 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. If the initial decision is affirmed on this issue, System Energy estimates refunds of approximately $19 million, which includes interest through December 31, 2020.
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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. The ALJ in the initial decision acknowledges that these are issues of first impression before the FERC. 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, MPSC, APSC, City Council, and the FERC trial staff opposed the exceptions filed by System Energy. Also in October 2020 the MPSC, APSC, and the City Council filed briefs adopting the exceptions of the LPSC and the FERC trial staff. The case is pending before the FERC, which will review the case and issue an order on the proceeding, and the FERC may accept, reject, or modify the ALJ’s initial decision in whole or in part. Refunds, if any, that might be required will only become due after the FERC issues its order reviewing the initial decision.
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, APSC, MPSC, and 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, APSC, MPSC, and 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, APSC, and City Council filed a protest in response to the amendments, reiterating their prior objections to the filings. In February 2021 the FERC issued an
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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.
LPSC Authorization of 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 notes 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 authorizes 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.”
The first of the additional complaints was filed at the FERC by the LPSC, the APSC, the MPSC, and the City Council in September 2020. The new 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 lease refinancing costs in rate base as prepayments; improperly included nuclear decommissioning outage costs in rate base; failed to include categories of accumulated deferred income taxes as a reduction 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: incentive and executive compensation, lack of an equity re-opener, lobbying, and private airplane travel. The new 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 new 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
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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.
The operational prudence-related complaint has not been filed as of this date, and the LPSC directive did not set a date for the filing.
Unit Power Sales Agreement
In August 2017, System Energy submitted to the FERC proposed amendments to 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. The filing proposes limited amendments to the Unit Power Sales Agreement to adopt (1) updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses and (2) updated nuclear decommissioning cost annual revenue requirements, both of which are recovered through the Unit Power Sales Agreement rate formula. The amendments result in lower charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. The changes were based on updated depreciation and nuclear decommissioning studies that take into account the renewal of Grand Gulf’s operating license for a term through November 1, 2044.
In September 2017 the FERC accepted System Energy’s proposed Unit Power Sales Agreement amendments, subject to further proceedings to consider the justness and reasonableness of the amendments. Because the amendments proposed a rate decrease, the FERC also initiated an investigation under section 206 of the Federal Power Act to determine if the rate decrease should be lower than proposed. The FERC accepted the proposed amendments effective October 1, 2017, subject to refund pending the outcome of the further settlement and/or hearing proceedings, and established a refund effective date of October 11, 2017 with respect to the rate decrease. In June 2018, System Energy filed with the FERC an uncontested settlement relating to the updated depreciation rates and nuclear decommissioning cost annual revenue requirements. In August 2018 the FERC issued an order accepting the settlement. In the third quarter 2018, System Energy recorded a reduction in depreciation expense of approximately $26 million, representing the cumulative difference in depreciation expense resulting from the depreciation rates used from October 11, 2017 through September 30, 2018 and the depreciation rates included in the settlement filing accepted by the FERC.
Storm Cost Recovery Filings with Retail Regulators
Entergy Louisiana
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 Louisiana Utilities Restoration Corporation (LURC) and the Louisiana State Bond Commission.
In August 2014 the Louisiana Local Government Environmental Facilities and Community Development Authority (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 LLC, a company wholly-owned and consolidated by Entergy, that carry a 7.5% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2014, and the membership interests have a liquidation price of $100 per unit. The preferred membership
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interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1.75 billion.
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.
In the first quarter 2020, Entergy and the IRS agreed upon and settled on the treatment of funds received by Entergy Louisiana in conjunction with the Act 55 financing of Hurricane Isaac storm costs, which resulted in a net reduction of income tax expense of approximately $32 million. As a result of the settlement, the position was partially sustained and Entergy Louisiana recorded a reduction of income tax expense of approximately $58 million primarily due to the reversal of liabilities for uncertain tax positions in excess of the agreed-upon settlement. Entergy recorded an increase to income tax expense of $26 million primarily resulting from the reduction of the deferred tax asset, associated with utilization of the net operating loss as a result of the settlement. This adjustment recorded by Entergy also accounted for the tax rate change of the Tax Cuts and Jobs Act. As a result of the IRS settlement, Entergy Louisiana recorded a $29 million ($21 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to customers pursuant to the LPSC Hurricane Isaac Act 55 financing order.
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 LLC, a company wholly-owned and consolidated by Entergy, that carry a 9% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2010, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.
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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 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 LLC, a company wholly-owned and consolidated by Entergy, 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 LLC that carry a 10% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2008 and have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.
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 are 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
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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
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.
NOTE 3. INCOME TAXES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Income taxes for 2020, 2019, and 2018 for Entergy Corporation and Subsidiaries consist of the following:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Thousands) | |||||||||||||||||
| Current: | |||||||||||||||||
| Federal | $5,807 | ($14,416) | $36,848 | ||||||||||||||
| State | 57,939 | 6,535 | 7,274 | ||||||||||||||
| Total | 63,746 | (7,881) | 44,122 | ||||||||||||||
| Deferred and non-current - net | (190,635) | (155,956) | (1,074,416) | ||||||||||||||
| Investment tax credit adjustments - net | 5,383 | (5,988) | (6,532) | ||||||||||||||
| Income taxes | ($121,506) | ($169,825) | ($1,036,826) | ||||||||||||||
Income taxes for 2020, 2019, and 2018 for Entergy’s Registrant Subsidiaries consist of the following:
| 2020 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Current: | ||||||||||||||||||||||||||||||||||||||
| Federal | ($44,627) | $62,728 | ($14,580) | $293 | ($5,603) | $372,206 | ||||||||||||||||||||||||||||||||
| State | (2,563) | 4,457 | (1,316) | (303) | 2,658 | 55,551 | ||||||||||||||||||||||||||||||||
| Total | (47,190) | 67,185 | (15,896) | (10) | (2,945) | 427,757 | ||||||||||||||||||||||||||||||||
| Deferred and non-current - net | 96,195 | (444,647) | 43,640 | (18,153) | 6,619 | (405,928) | ||||||||||||||||||||||||||||||||
| Investment tax credit adjustments - net | (1,228) | (4,862) | (554) | 13,956 | (632) | (1,286) | ||||||||||||||||||||||||||||||||
| Income taxes | $47,777 | ($382,324) | $27,190 | ($4,207) | $3,042 | $20,543 | ||||||||||||||||||||||||||||||||
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| 2019 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Current: | ||||||||||||||||||||||||||||||||||||||
| Federal | ($14,549) | ($20,173) | ($8,939) | ($5,822) | $16,035 | $16,256 | ||||||||||||||||||||||||||||||||
| State | (714) | (735) | 5,823 | 1,856 | 663 | (2,831) | ||||||||||||||||||||||||||||||||
| Total | (15,263) | (20,908) | (3,116) | (3,966) | 16,698 | 13,425 | ||||||||||||||||||||||||||||||||
| Deferred and non-current - net | (30,278) | 147,453 | 34,579 | 4,248 | (69,963) | 422 | ||||||||||||||||||||||||||||||||
| Investment tax credit adjustments - net | (1,228) | (4,922) | (597) | (96) | (631) | 1,502 | ||||||||||||||||||||||||||||||||
| Income taxes | ($46,769) | $121,623 | $30,866 | $186 | ($53,896) | $15,349 | ||||||||||||||||||||||||||||||||
| 2018 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Current: | ||||||||||||||||||||||||||||||||||||||
| Federal | ($23,638) | ($15,841) | ($11,275) | ($10,813) | $16,190 | ($9,786) | ||||||||||||||||||||||||||||||||
| State | (1,617) | (1,122) | (1,066) | 545 | 3,205 | (1,821) | ||||||||||||||||||||||||||||||||
| Total | (25,255) | (16,963) | (12,341) | (10,268) | 19,395 | (11,607) | ||||||||||||||||||||||||||||||||
| Deferred and non-current - net | (270,586) | (32,725) | (114,738) | 7,943 | (44,817) | (35,329) | ||||||||||||||||||||||||||||||||
| Investment tax credit adjustments - net | (1,226) | (4,923) | 1,306 | (111) | (821) | (739) | ||||||||||||||||||||||||||||||||
| Income taxes | ($297,067) | ($54,611) | ($125,773) | ($2,436) | ($26,243) | ($47,675) | ||||||||||||||||||||||||||||||||
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Total income taxes for Entergy Corporation and Subsidiaries 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 2020, 2019, and 2018 are:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Thousands) | |||||||||||||||||
| Net income attributable to Entergy Corporation | $1,388,334 | $1,241,226 | $848,661 | ||||||||||||||
| Preferred dividend requirements of subsidiaries | 18,319 | 17,018 | 13,894 | ||||||||||||||
| Consolidated net income | 1,406,653 | 1,258,244 | 862,555 | ||||||||||||||
| Income taxes | (121,506) | (169,825) | (1,036,826) | ||||||||||||||
| Income (loss) before income taxes | $1,285,147 | $1,088,419 | ($174,271) | ||||||||||||||
| Computed at statutory rate (21%) | $269,881 | $228,568 | ($36,597) | ||||||||||||||
| Increases (reductions) in tax resulting from: | |||||||||||||||||
| State income taxes net of federal income tax effect | 60,087 | 61,791 | 21,398 | ||||||||||||||
| Regulatory differences - utility plant items | (53,229) | (45,336) | (37,507) | ||||||||||||||
| Equity component of AFUDC | (25,080) | (30,444) | (27,216) | ||||||||||||||
| Amortization of investment tax credits | (8,386) | (8,093) | (8,304) | ||||||||||||||
| Flow-through / permanent differences | 11,099 | (2,059) | 439 | ||||||||||||||
| Amortization of excess ADIT (a) | (59,629) | (205,614) | (577,082) | ||||||||||||||
| Revisions of the 2017 tax legislation enactment regulatory liability accrual, including the effect of the Entergy Texas 2018 base rate proceeding | — | — | (40,494) | ||||||||||||||
| Utility restructuring (b) | — | — | (169,918) | ||||||||||||||
| Settlement on treatment of regulatory obligations (c) | — | — | (52,320) | ||||||||||||||
| State income tax audit conclusion | — | — | (23,425) | ||||||||||||||
| IRS audit adjustment (e) | (301,041) | — | (8,404) | ||||||||||||||
| Entergy Wholesale Commodities nuclear decommissioning trust restructuring (d) | — | — | (106,833) | ||||||||||||||
| Entergy Wholesale Commodities restructuring (d) | (9,223) | (173,725) | — | ||||||||||||||
| Stock compensation (f) | (25,591) | — | — | ||||||||||||||
| Charitable contribution (d) | — | (19,101) | — | ||||||||||||||
| Net operating loss recognition | — | (41,427) | — | ||||||||||||||
| Provision for uncertain tax positions | 15,208 | 7,332 | 24,569 | ||||||||||||||
| Valuation allowance | — | 59,345 | 2,211 | ||||||||||||||
| Other - net | 4,398 | (1,062) | 2,657 | ||||||||||||||
| Total income taxes as reported | ($121,506) | ($169,825) | ($1,036,826) | ||||||||||||||
| Effective Income Tax Rate | (9.5 | %) | (15.6) | % | 595.0 | % | |||||||||||
(a)See “Other Tax Matters - Tax Cuts and Jobs Act” below for discussion of the amortization of excess accumulated deferred income taxes (ADIT) in 2018, 2019, and 2020 and the tax legislation enactment in 2017.
(b)See “Other Tax Matters - Entergy Arkansas and Entergy Mississippi Internal Restructuring” below for discussion of the Utility restructuring.
(c)See “Income Tax Audits - 2012-2013 IRS Audit” below for discussion of the resolution of the audit.
(d)See “Other Tax Matters - Entergy Wholesale Commodities Restructuring” below for discussion of the Entergy Wholesale Commodities nuclear decommissioning trust restructuring in 2018, the Entergy Wholesale Commodities restructurings in 2017 and 2019, the ownership of Palisades restructuring in 2020, and the charitable contribution in 2019.
(e)See “Income Tax Audits - 2014-2015 IRS Audit” below for discussion of the resolution of the audit in 2020.
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(f)See “Other Tax Matters - Stock Compensation” below for discussion of excess tax deductions
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 2020, 2019, and 2018 are:
| 2020 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Net income | $245,232 | $1,082,352 | $140,583 | $49,338 | $215,073 | $99,131 | ||||||||||||||||||||||||||||||||
| Income taxes | 47,777 | (382,324) | 27,190 | (4,207) | 3,042 | 20,543 | ||||||||||||||||||||||||||||||||
| Pretax income | $293,009 | $700,028 | $167,773 | $45,131 | $218,115 | $119,674 | ||||||||||||||||||||||||||||||||
| Computed at statutory rate (21%) | $61,532 | $147,006 | $35,232 | $9,478 | $45,804 | $25,132 | ||||||||||||||||||||||||||||||||
| Increases (reductions) in tax resulting from: | ||||||||||||||||||||||||||||||||||||||
| State income taxes net of federal income tax effect | 16,256 | 38,182 | 6,917 | 2,606 | 1,460 | 5,524 | ||||||||||||||||||||||||||||||||
| Regulatory differences - utility plant items | (8,034) | (23,819) | (7,441) | (3,442) | (7,673) | (2,821) | ||||||||||||||||||||||||||||||||
| Equity component of AFUDC | (3,154) | (8,012) | (1,412) | (1,331) | (9,255) | (1,916) | ||||||||||||||||||||||||||||||||
| Amortization of investment tax credits | (1,201) | (4,811) | (540) | (61) | (617) | (1,155) | ||||||||||||||||||||||||||||||||
| Flow-through / permanent differences | (2,219) | 1,404 | (102) | 498 | 766 | (421) | ||||||||||||||||||||||||||||||||
| Amortization of excess ADIT (b) | (6,011) | (26,293) | 18 | (4,564) | (22,780) | — | ||||||||||||||||||||||||||||||||
| Stock compensation (e) | (4,952) | (9,004) | (2,763) | (1,526) | (2,842) | (1,300) | ||||||||||||||||||||||||||||||||
| IRS audit adjustment (d) | (6,351) | (471,702) | (3,768) | (6,819) | (2,091) | (2,925) | ||||||||||||||||||||||||||||||||
| Non-taxable dividend income | — | (26,795) | — | — | — | — | ||||||||||||||||||||||||||||||||
| Provision for uncertain tax positions | 1,200 | 300 | 800 | 800 | — | 300 | ||||||||||||||||||||||||||||||||
| Other - net | 711 | 1,220 | 249 | 154 | 270 | 125 | ||||||||||||||||||||||||||||||||
| Total income taxes as reported | $47,777 | ($382,324) | $27,190 | ($4,207) | $3,042 | $20,543 | ||||||||||||||||||||||||||||||||
| Effective Income Tax Rate | 16.3 | % | (54.6) | % | 16.2 | % | (9.3) | % | 1.4 | % | 17.2 | % | ||||||||||||||||||||||||||
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| 2019 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Net income | $262,964 | $691,537 | $119,925 | $52,629 | $159,397 | $99,120 | ||||||||||||||||||||||||||||||||
| Income taxes | (46,769) | 121,623 | 30,866 | 186 | (53,896) | 15,349 | ||||||||||||||||||||||||||||||||
| Pretax income | $216,195 | $813,160 | $150,791 | $52,815 | $105,501 | $114,469 | ||||||||||||||||||||||||||||||||
| Computed at statutory rate (21%) | $45,401 | $170,764 | $31,666 | $11,091 | $22,155 | $24,039 | ||||||||||||||||||||||||||||||||
| Increases (reductions) in tax resulting from: | ||||||||||||||||||||||||||||||||||||||
| State income taxes net of federal income tax effect | 15,954 | 42,854 | 5,563 | 3,443 | 360 | 5,134 | ||||||||||||||||||||||||||||||||
| Regulatory differences - utility plant items | (10,627) | (19,421) | (5,556) | (1,532) | (1,987) | (6,213) | ||||||||||||||||||||||||||||||||
| Equity component of AFUDC | (3,255) | (15,545) | (1,755) | (2,088) | (5,973) | (1,829) | ||||||||||||||||||||||||||||||||
| Amortization of investment tax credits | (1,201) | (4,871) | (160) | (88) | (617) | (1,155) | ||||||||||||||||||||||||||||||||
| Flow-through / permanent differences | 696 | 439 | 160 | (741) | 560 | (500) | ||||||||||||||||||||||||||||||||
| Amortization of excess ADIT (b) | (90,921) | (28,531) | 203 | (11,724) | (69,091) | (5,550) | ||||||||||||||||||||||||||||||||
| Non-taxable dividend income | — | (26,795) | — | — | — | — | ||||||||||||||||||||||||||||||||
| Provision for uncertain tax positions | (3,517) | 1,519 | 500 | 1,672 | 430 | 1,300 | ||||||||||||||||||||||||||||||||
| Other - net | 701 | 1,210 | 245 | 153 | 267 | 123 | ||||||||||||||||||||||||||||||||
| Total income taxes as reported | ($46,769) | $121,623 | $30,866 | $186 | ($53,896) | $15,349 | ||||||||||||||||||||||||||||||||
| Effective Income Tax Rate | (21.6 | %) | 15.0 | % | 20.5 | % | 0.4 | % | (51.1 | %) | 13.4 | % | ||||||||||||||||||||||||||
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| 2018 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Net income | $252,707 | $675,614 | $126,078 | $53,152 | $162,235 | $94,109 | ||||||||||||||||||||||||||||||||
| Income taxes | (297,067) | (54,611) | (125,773) | (2,436) | (26,243) | (47,675) | ||||||||||||||||||||||||||||||||
| Pretax income | ($44,360) | $621,003 | $305 | $50,716 | $135,992 | $46,434 | ||||||||||||||||||||||||||||||||
| Computed at statutory rate (21%) | ($9,316) | $130,411 | $64 | $10,650 | $28,558 | $9,751 | ||||||||||||||||||||||||||||||||
| Increases (reductions) in tax resulting from: | ||||||||||||||||||||||||||||||||||||||
| State income taxes net of federal income tax effect | (794) | 26,031 | (1,747) | 2,322 | 2,576 | 2,812 | ||||||||||||||||||||||||||||||||
| Regulatory differences - utility plant items | (14,916) | (12,604) | (4,103) | (1,502) | (1,872) | (2,510) | ||||||||||||||||||||||||||||||||
| Equity component of AFUDC | (3,477) | (16,784) | (1,829) | (1,248) | (2,042) | (1,837) | ||||||||||||||||||||||||||||||||
| Amortization of investment tax credits | (1,201) | (4,871) | (160) | (109) | (808) | (1,155) | ||||||||||||||||||||||||||||||||
| Flow-through / permanent differences | 570 | 3,203 | 1,893 | (4,222) | 1,038 | 2,815 | ||||||||||||||||||||||||||||||||
| Revisions of the 2017 tax legislation enactment regulatory liability accrual, including the effect of the Entergy Texas 2018 base rate proceeding (a) | 933 | (2,810) | (556) | 884 | (43,799) | (3,565) | ||||||||||||||||||||||||||||||||
| Amortization of excess ADIT (b) | (271,570) | (104,313) | (120,831) | (9,878) | (11,519) | (58,971) | ||||||||||||||||||||||||||||||||
| Settlement on treatment of regulatory obligations (c) | — | (52,320) | — | — | — | — | ||||||||||||||||||||||||||||||||
| IRS audit adjustment | 1,290 | 1,097 | 1,018 | (96) | 524 | (12) | ||||||||||||||||||||||||||||||||
| Non-taxable dividend income | — | (26,795) | — | — | — | — | ||||||||||||||||||||||||||||||||
| Provision for uncertain tax positions | 724 | 3,949 | 240 | 613 | 839 | 4,876 | ||||||||||||||||||||||||||||||||
| Other - net | 690 | 1,195 | 238 | 150 | 262 | 121 | ||||||||||||||||||||||||||||||||
| Total income taxes as reported | ($297,067) | ($54,611) | ($125,773) | ($2,436) | ($26,243) | ($47,675) | ||||||||||||||||||||||||||||||||
| Effective Income Tax Rate | 669.7 | % | (8.8 | %) | (41,237.0 | %) | (4.8 | %) | (19.3 | %) | (102.7 | %) | ||||||||||||||||||||||||||
(a)See Note 2 to the financial statements for discussion of the Entergy Texas rate case settlement.
(b)See “Other Tax Matters - Tax Cuts and Jobs Act” below for discussion of the amortization of excess accumulated deferred income taxes (ADIT) in 2018, 2019, and 2020 and the tax legislation enactment in 2017.
(c)See “Income Tax Audits - 2012-2013 IRS Audit” below for discussion of the resolution of the audit for Entergy Louisiana.
(d)See “Income Tax Audits - 2014-2015 IRS Audit” below for discussion of the resolution of the audit in 2020.
(e)See “Other Tax Matters - Stock Compensation” below for discussion of excess tax deductions
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Significant components of accumulated deferred income taxes and taxes accrued for Entergy Corporation and Subsidiaries as of December 31, 2020 and 2019 are as follows:
| 2020 | 2019 | ||||||||||
| (In Thousands) | |||||||||||
| Deferred tax liabilities: | |||||||||||
| Plant basis differences - net | ($4,795,422) | ($4,111,761) | |||||||||
| Regulatory assets | (429,996) | (389,573) | |||||||||
| Nuclear decommissioning trusts/receivables | (1,188,235) | (1,015,542) | |||||||||
| Pension, net funding | (327,445) | (348,260) | |||||||||
| Combined unitary state taxes | (7,723) | (11,519) | |||||||||
| Unbilled/deferred revenues | (9,152) | (10,218) | |||||||||
| Deferred fuel | (7,667) | (8,360) | |||||||||
| Other | (549,355) | (445,378) | |||||||||
| Total | (7,314,995) | (6,340,611) | |||||||||
| Deferred tax assets: | |||||||||||
| Nuclear decommissioning liabilities | 968,464 | 929,251 | |||||||||
| Regulatory liabilities | 791,927 | 806,777 | |||||||||
| Pension and other post-employment benefits | 278,486 | 297,272 | |||||||||
| Sale and leaseback | 102,477 | 102,420 | |||||||||
| Compensation | 89,279 | 87,355 | |||||||||
| Accumulated deferred investment tax credit | 57,379 | 56,013 | |||||||||
| Provision for allowances and contingencies | 71,598 | 126,886 | |||||||||
| Power purchase agreements | 352,019 | 231,502 | |||||||||
| Net operating loss carryforwards | 1,580,109 | 1,133,197 | |||||||||
| Capital losses and miscellaneous tax credits | 21,291 | 22,597 | |||||||||
| Valuation allowance | (328,581) | (303,307) | |||||||||
| Other | 230,291 | 289,557 | |||||||||
| Total | 4,214,739 | 3,779,520 | |||||||||
| Non-current accrued taxes (including unrecognized tax benefits) | (1,185,227) | (1,775,638) | |||||||||
| Accumulated deferred income taxes and taxes accrued | ($4,285,483) | ($4,336,729) | |||||||||
Entergy’s estimated tax attributes carryovers and their expiration dates as of December 31, 2020 are as follows:
| Carryover Description | Carryover Amount | Year(s) of expiration | ||||||||||||
| Federal net operating losses before 1/1/2018 | $6.1 billion | 2023-2037 | ||||||||||||
| Federal net operating losses - 1/1/2018 forward | $14.6 billion | N/A | ||||||||||||
| State net operating losses | $19.7 billion | 2021-2040 | ||||||||||||
| Federal and state charitable contributions | $449 million | 2021-2025 | ||||||||||||
| Miscellaneous federal and state credits | $77.5 million | 2021-2040 | ||||||||||||
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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 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 loss and other deferred tax assets will not be utilized, valuation allowances totaling $329 million as of December 31, 2020 and $303 million as of December 31, 2019 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.
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Significant components of accumulated deferred income taxes and taxes accrued for the Registrant Subsidiaries as of December 31, 2020 and 2019 are as follows:
| 2020 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Deferred tax liabilities: | ||||||||||||||||||||||||||||||||||||||
| Plant basis differences - net | ($1,117,948) | ($2,481,976) | ($623,796) | ($83,457) | ($620,669) | ($407,125) | ||||||||||||||||||||||||||||||||
| Regulatory assets | (188,284) | (95,135) | (22,381) | (20,276) | (47,684) | (56,496) | ||||||||||||||||||||||||||||||||
| Nuclear decommissioning trusts/receivables | (156,123) | (148,040) | — | — | — | (131,985) | ||||||||||||||||||||||||||||||||
| Pension, net funding | (93,486) | (95,854) | (24,922) | (11,564) | (19,481) | (20,330) | ||||||||||||||||||||||||||||||||
| Deferred fuel | — | (4,210) | (1,706) | (1,393) | — | (314) | ||||||||||||||||||||||||||||||||
| Other | (54,753) | (76,735) | (27,565) | (26,334) | (141) | (12,521) | ||||||||||||||||||||||||||||||||
| Total | (1,610,594) | (2,901,950) | (700,370) | (143,024) | (687,975) | (628,771) | ||||||||||||||||||||||||||||||||
| Deferred tax assets: | ||||||||||||||||||||||||||||||||||||||
| Regulatory liabilities | 273,774 | 218,278 | 56,022 | 31,248 | 47,991 | 163,534 | ||||||||||||||||||||||||||||||||
| Nuclear decommissioning liabilities | 123,319 | 7,767 | — | (419) | 121 | 29,916 | ||||||||||||||||||||||||||||||||
| Pension and other post-employment benefits | (24,747) | 72,724 | (6,763) | (13,997) | (17,132) | (1,344) | ||||||||||||||||||||||||||||||||
| Sale and leaseback | — | — | — | — | — | 102,477 | ||||||||||||||||||||||||||||||||
| Accumulated deferred investment tax credit | 7,971 | 31,155 | 2,261 | 4,197 | 2,088 | 9,706 | ||||||||||||||||||||||||||||||||
| Provision for allowances and contingencies | 22,179 | 7,071 | 16,799 | 24,529 | (4,094) | — | ||||||||||||||||||||||||||||||||
| Power purchase agreements | 9,662 | 3,381 | 1,140 | (5,324) | (30,932) | — | ||||||||||||||||||||||||||||||||
| Unbilled/deferred revenues | 4,242 | (23,382) | 2,989 | 877 | 5,909 | — | ||||||||||||||||||||||||||||||||
| Compensation | 2,264 | 3,240 | 1,670 | 761 | 1,308 | 48 | ||||||||||||||||||||||||||||||||
| Net operating loss carryforwards | 119,555 | 363,806 | 54,262 | 26,564 | 53,052 | — | ||||||||||||||||||||||||||||||||
| Capital losses and miscellaneous tax credits | — | 9,309 | — | 12,317 | — | 7,014 | ||||||||||||||||||||||||||||||||
| Other | 16,036 | 6,958 | 3,507 | 8,128 | 2,232 | 2 | ||||||||||||||||||||||||||||||||
| Total | 554,255 | 700,307 | 131,887 | 88,881 | 60,543 | 311,353 | ||||||||||||||||||||||||||||||||
| Non-current accrued taxes (including unrecognized tax benefits) | (229,784) | 63,121 | (78,191) | (284,571) | (11,990) | (42,417) | ||||||||||||||||||||||||||||||||
| Accumulated deferred income taxes and taxes accrued | ($1,286,123) | ($2,138,522) | ($646,674) | ($338,714) | ($639,422) | ($359,835) | ||||||||||||||||||||||||||||||||
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| 2019 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Deferred tax liabilities: | ||||||||||||||||||||||||||||||||||||||
| Plant basis differences - net | ($979,033) | ($1,987,025) | ($565,202) | ($133,073) | ($551,365) | ($380,594) | ||||||||||||||||||||||||||||||||
| Regulatory assets | (170,949) | (79,117) | (10,528) | (16,867) | (59,745) | (52,662) | ||||||||||||||||||||||||||||||||
| Nuclear decommissioning trusts/receivables | (120,306) | (113,830) | — | — | — | (100,621) | ||||||||||||||||||||||||||||||||
| Pension, net funding | (102,685) | (98,743) | (27,325) | (11,859) | (19,961) | (21,609) | ||||||||||||||||||||||||||||||||
| Deferred fuel | — | (2,637) | (609) | (666) | (4,380) | (55) | ||||||||||||||||||||||||||||||||
| Other | (82,682) | (94,139) | (27,905) | (25,909) | 2,059 | (7,350) | ||||||||||||||||||||||||||||||||
| Total | (1,455,655) | (2,375,491) | (631,569) | (188,374) | (633,392) | (562,891) | ||||||||||||||||||||||||||||||||
| Deferred tax assets: | ||||||||||||||||||||||||||||||||||||||
| Regulatory liabilities | 250,410 | 283,507 | 53,421 | 33,258 | 65,602 | 121,011 | ||||||||||||||||||||||||||||||||
| Nuclear decommissioning liabilities | 111,078 | 56,300 | — | — | — | 52,633 | ||||||||||||||||||||||||||||||||
| Pension and other post-employment benefits | (21,828) | 74,881 | (5,844) | (12,666) | (15,406) | (898) | ||||||||||||||||||||||||||||||||
| Sale and leaseback | — | — | — | — | — | 102,480 | ||||||||||||||||||||||||||||||||
| Accumulated deferred investment tax credit | 8,285 | 32,534 | 2,396 | 556 | 2,217 | 10,025 | ||||||||||||||||||||||||||||||||
| Provision for allowances and contingencies | 5,365 | 77,298 | 12,963 | 24,022 | 4,024 | — | ||||||||||||||||||||||||||||||||
| Power purchase agreements | (15,087) | 18,004 | 1,147 | 7,961 | 26 | — | ||||||||||||||||||||||||||||||||
| Unbilled/deferred revenues | 5,897 | (28,081) | 4,715 | 1,428 | 5,544 | — | ||||||||||||||||||||||||||||||||
| Compensation | 2,550 | 3,670 | 1,625 | 496 | 1,282 | 75 | ||||||||||||||||||||||||||||||||
| Net operating loss carryforwards | 112,658 | 65,178 | 21,492 | 5,056 | — | — | ||||||||||||||||||||||||||||||||
| Capital losses and miscellaneous tax credits | — | — | 45 | — | — | 7,857 | ||||||||||||||||||||||||||||||||
| Other | 12,541 | 35,401 | 999 | 9,027 | 2,004 | 3 | ||||||||||||||||||||||||||||||||
| Total | 471,869 | 618,692 | 92,959 | 69,138 | 65,293 | 293,186 | ||||||||||||||||||||||||||||||||
| Non-current accrued taxes (including unrecognized tax benefits) | (199,340) | (707,714) | (56,222) | (235,300) | (17,314) | (544,235) | ||||||||||||||||||||||||||||||||
| Accumulated deferred income taxes and taxes accrued | ($1,183,126) | ($2,464,513) | ($594,832) | ($354,536) | ($585,413) | ($813,940) | ||||||||||||||||||||||||||||||||
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The Registrant Subsidiaries’ estimated tax attributes carryovers and their expiration dates as of December 31, 2020 are as follows:
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | |||||||||||||||||||||||||||||||||
| Federal net operating losses before 1/1/2018 | $— billion | $1.7 billion | $— billion | $0.9 billion | $— billion | $— billion | ||||||||||||||||||||||||||||||||
| Year(s) of expiration | N/A | 2035-2037 | N/A | 2037 | N/A | N/A | ||||||||||||||||||||||||||||||||
| Federal net operating losses - 1/1/2018 forward | $4.4 billion | $1.4 billion | $1.9 billion | $0.3 billion | $2.7 billion | $— billion | ||||||||||||||||||||||||||||||||
| Year(s) of expiration | N/A | N/A | N/A | N/A | N/A | N/A | ||||||||||||||||||||||||||||||||
| State net operating losses | $4.5 billion | $4 billion | $2 billion | $1.3 billion | $— million | $— million | ||||||||||||||||||||||||||||||||
| Year(s) of expiration | 2023-2025 | 2035-2040 | 2038-2040 | 2037-2040 | N/A | N/A | ||||||||||||||||||||||||||||||||
| Misc. federal credits | $2.9 million | $9.3 million | $1.2 million | $14.8 million | $2.6 million | $1.3 million | ||||||||||||||||||||||||||||||||
| Year(s) of expiration | 2038-2040 | 2035-2040 | 2038-2040 | 2037-2040 | 2029-2040 | 2029-2040 | ||||||||||||||||||||||||||||||||
| State credits | $— million | $— million | $— million | $—million | $2.9 million | $13.1 million | ||||||||||||||||||||||||||||||||
| Year(s) of expiration | N/A | N/A | N/A | N/A | 2026 | 2021-2023 | ||||||||||||||||||||||||||||||||
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 and tax credit carryovers.
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:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Thousands) | |||||||||||||||||
| Gross balance at January 1 | $7,383,154 | $7,181,482 | $4,871,846 | ||||||||||||||
| Additions based on tax positions related to the current year | 669,207 | 731,276 | 2,276,614 | ||||||||||||||
| Additions for tax positions of prior years | 98,591 | 151,628 | 506,142 | ||||||||||||||
| Reductions for tax positions of prior years | (935,735) | (681,232) | (274,600) | ||||||||||||||
| Settlements | (1,515,878) | — | (198,520) | ||||||||||||||
| Gross balance at December 31 | 5,699,339 | 7,383,154 | 7,181,482 | ||||||||||||||
| Offsets to gross unrecognized tax benefits: | |||||||||||||||||
| Carryovers and refund claims | (4,710,214) | (5,831,587) | (5,957,992) | ||||||||||||||
| Cash paid to taxing authorities | (10,000) | (10,000) | (10,000) | ||||||||||||||
| Unrecognized tax benefits net of unused tax attributes, refund claims and payments (a) | $979,125 | $1,541,567 | $1,213,490 | ||||||||||||||
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(a)Potential tax liability above what is payable on tax returns
The balances of unrecognized tax benefits include $2,208 million, $2,421 million, and $2,161 million as of December 31, 2020, 2019, and 2018, 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 $3,491 million, $4,962 million, and $5,020 million as of December 31, 2020, 2019, and 2018, 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, 2020, 2019, and 2018 accrued balance for the possible payment of interest is approximately $44 million, $48 million, and $44 million, respectively. Interest (net-of-tax) of $(4) million, $4 million, and $7 million was recorded in 2020, 2019, and 2018, respectively.
A reconciliation of the Registrant Subsidiaries’ beginning and ending amount of unrecognized tax benefits for 2020, 2019, and 2018 is as follows:
| 2020 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Gross balance at January 1, 2020 | $1,341,242 | $2,381,653 | $566,287 | $716,773 | $21,406 | $473,331 | ||||||||||||||||||||||||||||||||
| Additions based on tax positions related to the current year | 9,403 | 35,681 | 5,619 | 2,430 | 504,362 | 4,013 | ||||||||||||||||||||||||||||||||
| Additions for tax positions of prior years | 13,400 | 10,508 | 1,156 | 294 | 799 | 4,606 | ||||||||||||||||||||||||||||||||
| Reductions for tax positions of prior years | (11,346) | (679,601) | (24,173) | (80,267) | (5,559) | (41,466) | ||||||||||||||||||||||||||||||||
| Settlements | 11,936 | (1,107,946) | 828 | 316 | 924 | (418,832) | ||||||||||||||||||||||||||||||||
| Gross balance at December 31, 2020 | 1,364,635 | 640,295 | 549,717 | 639,546 | 521,932 | 21,652 | ||||||||||||||||||||||||||||||||
| Offsets to gross unrecognized tax benefits: | ||||||||||||||||||||||||||||||||||||||
| Loss carryovers | (1,112,628) | (640,295) | (465,679) | (451,922) | (507,720) | (7,413) | ||||||||||||||||||||||||||||||||
| Unrecognized tax benefits net of unused tax attributes and payments | $252,007 | $— | $84,038 | $187,624 | $14,212 | $14,239 | ||||||||||||||||||||||||||||||||
| 2019 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Gross balance at January 1, 2019 | $1,298,662 | $2,400,171 | $508,765 | $686,687 | $17,802 | $467,487 | ||||||||||||||||||||||||||||||||
| Additions based on tax positions related to the current year (a) | 84,335 | 28,705 | 68,594 | 40,676 | 2,312 | 5,496 | ||||||||||||||||||||||||||||||||
| Additions for tax positions of prior years | 20,399 | 25,090 | 1,651 | 489 | 1,299 | 2,186 | ||||||||||||||||||||||||||||||||
| Reductions for tax positions of prior years | (62,154) | (72,313) | (12,723) | (11,079) | (7) | (1,838) | ||||||||||||||||||||||||||||||||
| Gross balance at December 31, 2019 | 1,341,242 | 2,381,653 | 566,287 | 716,773 | 21,406 | 473,331 | ||||||||||||||||||||||||||||||||
| Offsets to gross unrecognized tax benefits: | ||||||||||||||||||||||||||||||||||||||
| Loss carryovers | (1,134,187) | (1,573,257) | (506,976) | (445,430) | (3,944) | (8,392) | ||||||||||||||||||||||||||||||||
| Unrecognized tax benefits net of unused tax attributes and payments | $207,055 | $808,396 | $59,311 | $271,343 | $17,462 | $464,939 | ||||||||||||||||||||||||||||||||
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| 2018 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Gross balance at January 1, 2018 | ($117,716) | $2,518,457 | $15,122 | $679,544 | $16,399 | $445,511 | ||||||||||||||||||||||||||||||||
| Additions based on tax positions related to the current year (a) | 1,430,828 | 30,577 | 493,039 | 2,261 | 1,978 | 18,271 | ||||||||||||||||||||||||||||||||
| Additions for tax positions of prior years | 31,612 | 77,372 | 3,878 | 12,972 | 1,722 | 7,255 | ||||||||||||||||||||||||||||||||
| Reductions for tax positions of prior years | (21,619) | (158,510) | (3,253) | (8,081) | (2,262) | (3,253) | ||||||||||||||||||||||||||||||||
| Settlements | (24,443) | (67,725) | (21) | (9) | (35) | (297) | ||||||||||||||||||||||||||||||||
| Gross balance at December 31, 2018 | 1,298,662 | 2,400,171 | 508,765 | 686,687 | 17,802 | 467,487 | ||||||||||||||||||||||||||||||||
| Offsets to gross unrecognized tax benefits: | ||||||||||||||||||||||||||||||||||||||
| Loss carryovers | (1,173,839) | (1,597,826) | (478,268) | (420,813) | (3,199) | (42,228) | ||||||||||||||||||||||||||||||||
| Unrecognized tax benefits net of unused tax attributes and payments | $124,823 | $802,345 | $30,497 | $265,874 | $14,603 | $425,259 | ||||||||||||||||||||||||||||||||
(a)The primary additions for Entergy Texas in 2020 and Entergy Mississippi in 2018 are related to the mark-to-market treatment discussed in “Other Tax Matters - Tax Accounting Methods” below. The primary additions for Entergy Arkansas in 2018 are related to the nuclear decommissioning costs treatment and the mark-to-market treatment discussed in “Other Tax Matters - Tax Accounting Methods” below.
The Registrant Subsidiaries’ balances of unrecognized tax benefits included amounts which, if recognized, would have reduced income tax expense as follows:
| December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Millions) | |||||||||||||||||
| Entergy Arkansas | $259.3 | $203.3 | $85.4 | ||||||||||||||
| Entergy Louisiana | $63.8 | $556.3 | $594.0 | ||||||||||||||
| Entergy Mississippi | $50.7 | $1.9 | $1.5 | ||||||||||||||
| Entergy New Orleans | $203.5 | $242.7 | $246.2 | ||||||||||||||
| Entergy Texas | $6.1 | $5.7 | $5.1 | ||||||||||||||
| System Energy | $0.5 | $— | $— | ||||||||||||||
Accrued balances for the possible payment of interest related to unrecognized tax benefits are as follows:
| December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Millions) | |||||||||||||||||
| Entergy Arkansas | $2.3 | $3.1 | $1.7 | ||||||||||||||
| Entergy Louisiana | $3.4 | $14.2 | $17.9 | ||||||||||||||
| Entergy Mississippi | $1.9 | $1.7 | $1.2 | ||||||||||||||
| Entergy New Orleans | $3.9 | $4.7 | $2.7 | ||||||||||||||
| Entergy Texas | $0.9 | $1.1 | $0.9 | ||||||||||||||
| System Energy | $11.9 | $14.5 | $13.2 | ||||||||||||||
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The Registrant Subsidiaries record interest and penalties related to unrecognized tax benefits in income tax expense. No penalties were recorded in 2020, 2019, and 2018. Interest (net-of-tax) was recorded as follows:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Millions) | |||||||||||||||||
| Entergy Arkansas | ($0.8) | $1.4 | $0.2 | ||||||||||||||
| Entergy Louisiana | ($10.8) | ($3.7) | $3.8 | ||||||||||||||
| Entergy Mississippi | $0.2 | $0.5 | $0.2 | ||||||||||||||
| Entergy New Orleans | ($0.8) | $2.0 | $0.6 | ||||||||||||||
| Entergy Texas | ($0.2) | $0.2 | $0.5 | ||||||||||||||
| System Energy | ($2.6) | $1.3 | $4.7 | ||||||||||||||
Income Tax Audits
Entergy and its subsidiaries file U.S. federal and various state income tax returns. IRS examinations are complete for years before 2016. All state taxing authorities’ examinations are complete for years before 2015. 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.
2012-2013 IRS Audit
The IRS completed its examination of the 2012 and 2013 tax years and issued its 2012-2013 Revenue Agent Report (RAR) in June 2018. Entergy agreed to all proposed adjustments contained in the RAR. Entergy and the Registrant Subsidiaries recorded the effects of these adjustments in June 2018.
As a result of the issuance of the RAR, Entergy Louisiana was able to recognize previously unrecognized tax benefits of $52 million related to the Hurricane Katrina and Hurricane Rita contingent sharing obligation associated with the Louisiana Act 55 financing.
2014-2015 IRS Audit
The IRS completed its examination of the 2014 and 2015 tax years and issued its 2014-2015 RAR in November 2020. Entergy agreed to all proposed adjustments contained in the RAR. Entergy and the Registrant Subsidiaries recorded the effects of the adjustments associated with the audit in 2020.
In October 2015 two of Entergy’s Louisiana utilities, Entergy Gulf States Louisiana and Entergy Louisiana, combined their businesses into a legal entity which is identified as Entergy Louisiana herein. The structure of the business combination required Entergy to recognize a gain for income tax purposes which resulted in an increase in the tax basis of the assets for Entergy Louisiana. This resulted in recognition in 2015 of a $334 million permanent difference and income tax benefit, net of the uncertain tax position recorded on the transaction.
Primarily related to resolution of the business combination issues, completion of the 2014-2015 IRS audit in 2020 resulted in a $230 million reduction to deferred income tax expense for Entergy. This reduction to deferred income tax expense includes: Entergy Louisiana reversing its provision for uncertain tax position with respect to the business combination, which resulted in a reduction to deferred income tax expense of $383 million; Entergy Corporation recording an increase to deferred tax expense of $61 million and Entergy Wholesale Commodities recording an increase to deferred tax expense of $105 million from the re-measurement of deferred tax assets associated with the resolved uncertain tax position; and miscellaneous other individually insignificant benefits totaling $13 million.
The completion of the 2014-2015 tax audit also resulted in a $31 million reduction to income tax expense associated with Entergy Louisiana’s method of accounting related to the adoption of tangible property regulations.
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As a result of the settlement of the tangible property regulation tax position, Entergy Louisiana was required to record a $33 million ($24 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to customers pursuant to a prior regulatory settlement.
Finally, upon completion of the 2014-2015 tax audit, Entergy New Orleans recorded a reduction to income tax expense of $8 million associated with claims for mark-to-market deductions.
In the first quarter 2020, Entergy and the IRS agreed on the treatment of funds received by Entergy Louisiana in conjunction with the Act 55 financing of Hurricane Isaac storm costs, which resulted in a net reduction of income tax expense of approximately $32 million. As a result of the settlement, the position was partially sustained, and Entergy Louisiana recorded a reduction of income tax expense of approximately $58 million primarily due to the reversal of a provision for uncertain tax positions in excess of the agreed-upon settlement. As a result of the IRS settlement, Entergy Louisiana recorded a $29 million ($21 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to customers pursuant to the LPSC Hurricane Isaac Act 55 financing order.
Additional effects of the completion of the 2014-2015 IRS tax audit are discussed below within Tax Accounting Methods.
Other Tax Matters
Tax Cuts and Jobs Act (TCJA)
Deferred tax liabilities and assets have been adjusted for the effect of the enactment of the TCJA, signed by President Trump on December 22, 2017. 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. Other significant provisions and their effect on Entergy and the Registrant Subsidiaries are summarized below.
The TCJA limited the deduction for net business interest expense to 30 percent of adjusted taxable income, which is similar to earnings before interest, taxes, depreciation, and amortization. The limitation does not apply to interest expense that is properly allocable to a trade or business classified as a regulated public utility. This was further modified by a temporary provision of the CARES Act resulting in an increase of the adjusted taxable income limitation from 30% to 50% for tax years that begin in 2019 or 2020.
The IRS issued proposed regulations relating to this limitation in November 2018 and July 2020. The IRS issued certain final regulations in July 2020 and January 2021, which were published in the Federal Register in September 2020 and January 2021, respectively. The proposed regulations are generally to be effective for taxable years ending after the date Treasury adopted the regulations as final. The final regulations will be effective for Entergy beginning with the 2021 tax year. Taxpayers may apply the rules of the proposed regulations to a taxable year beginning after December 31, 2017, as long as taxpayers consistently apply the rules of the proposed regulations. The proposed and final regulations provide that if 90% of a tax group’s consolidated assets consist of regulated utility property, the entire consolidated tax group will be treated as a regulated public utility and all of the consolidated group’s interest expense will be currently tax deductible.
As a result of the limitation under TCJA, Entergy recorded limitations in 2018 and 2019 and recorded a deferred tax asset on the nondeductible portion, as it has an unlimited carryover period. Entergy recorded a valuation allowance of $24 million due to a lack of earnings from sources other than the Utility. No limitation was recorded in 2020.
The TCJA limited the net operating loss (NOL) deduction for a given year to 80% of taxable income, effective with respect to losses arising in tax years beginning after December 31, 2017. Only NOLs generated after December 31, 2017 are subject to the 80% limitation. A temporary provision of the CARES Act (discussed below) removes this limitation and allows corporate taxpayers to fully offset taxable income with NOLs carried to tax years
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beginning before 2021. Prior law generally provided a two-year carryback and 20-year carryforward for NOLs. The TCJA does not allow a carryback period but does provide for the indefinite carryforward of NOLs arising in tax years ending after December 31, 2017. However, with the enactment of the CARES Act, a temporary provision allows for a five-year carryback of 2018-2020 NOLs. Because of the indefinite carryforward, the new limitations on NOL utilization are not expected to have a material effect on Entergy or the Registrant Subsidiaries.
The TCJA also modified Internal Revenue Code section 162(m), which limits the deduction for compensation with respect to certain covered employees to no more than $1 million per year. The IRS issued proposed regulations relating to this limitation in December 2019 and final regulations in December 2020. The significant provisions of the TCJA and associated proposed and final regulations require inclusion of performance-based compensation and an expanded definition of “covered employees” in the annual computation of the section 162 limitation. The TCJA amendments and associated proposed regulations resulted in an increase in disallowed compensation expense, but this limitation does not have a material effect on Entergy or the Registrant Subsidiaries.
With respect to the federal corporate income tax rate change from 35% to 21% in 2017, Entergy and the Registrant Subsidiaries recorded a regulatory liability associated with the decrease in the net accumulated deferred income tax liability, which is often referred to as “excess ADIT,” a significant portion of which has been paid to customers in 2019 and 2020 in the form of lower rates. Entergy’s December 31, 2020 and December 31, 2019 balance sheets reflect a regulatory liability of $1.6 billion and $1.7 billion, respectively, as a result of the re-measurement of deferred tax assets and liabilities from the income tax rate change, amortization of excess ADIT, and payments to customers during 2019 and 2020. 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 a) the reduction of the net deferred tax liability resulting in excess ADIT, b) the tax gross-up of excess ADIT, and c) the effect of the new tax rate on the previous net regulatory asset for income taxes. For the same reasons, the Registrant Subsidiaries’ December 31, 2020 and December 31, 2019 balance sheets reflect net regulatory liabilities for income taxes as follows:
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
| Entergy Arkansas | $467 | $487 | |||||||||
| Entergy Louisiana | $479 | $531 | |||||||||
| Entergy Mississippi | $224 | $237 | |||||||||
| Entergy New Orleans | $59 | $59 | |||||||||
| Entergy Texas | $205 | $253 | |||||||||
| System Energy | $152 | $143 | |||||||||
Excess ADIT is generally classified into two categories: 1) the portion that is subject to the normalization requirements of the TCJA, i.e., “protected”, and 2) the portion that is not subject to such normalization provisions, referred to as “unprotected”. 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. The Registrant Subsidiaries’ net regulatory liability for income taxes as of December 31, 2020 and December 31, 2019, includes protected excess ADIT as follows:
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| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
| Entergy Arkansas | $490 | $490 | |||||||||
| Entergy Louisiana | $721 | $797 | |||||||||
| Entergy Mississippi | $248 | $261 | |||||||||
| Entergy New Orleans | $61 | $62 | |||||||||
| Entergy Texas | $215 | $228 | |||||||||
| System Energy | $173 | $186 | |||||||||
During the second quarter of 2018, the Registrant Subsidiaries began paying unprotected excess accumulated deferred income taxes, associated with the effects of the Act, to their customers through rate riders and other means approved by their respective regulatory commissions. Payment 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 has a significant effect on the effective tax rate for the period as compared to the statutory tax rate. The Registrant Subsidiaries’ net regulatory liability for income taxes as of December 31, 2020 and December 31, 2019, includes unprotected excess ADIT as follows:
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
| Entergy Arkansas | $11 | $9 | |||||||||
| Entergy Louisiana | $223 | $242 | |||||||||
| Entergy New Orleans | $3 | $9 | |||||||||
| Entergy Texas | $54 | $83 | |||||||||
| System Energy | $16 | $— | |||||||||
The return of unprotected excess accumulated deferred income taxes reduced Entergy’s and the Registrant Subsidiaries’ regulatory liability for income taxes as follows for 2020 and 2019:
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
| Entergy | $74 | $273 | |||||||||
| Entergy Arkansas | $8 | $126 | |||||||||
| Entergy Louisiana | $31 | $39 | |||||||||
| Entergy New Orleans | $6 | $14 | |||||||||
| Entergy Texas | $29 | $87 | |||||||||
| System Energy | $— | $7 | |||||||||
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 associated with AFUDC, which is described in Note 1 to the financial statements.
For a discussion of the proceedings commenced or other responses by Entergy’s regulators to the Act, see Note 2 to the financial statements.
Included in the effect of the computation of the changes in deferred tax assets and liabilities is the recognition threshold and measurement of uncertain tax positions resulting in unrecognized tax benefits. The final economic outcome of such unrecognized tax benefits is generally the result of a negotiated settlement with the IRS that often differs from the amount that is recorded as realizable under GAAP. The intrinsic uncertainty with respect to all such tax positions means that the difference between current estimates of such amounts likely to be realized
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and actual amounts realized upon settlement may have an effect on income tax expense and the regulatory liability for income taxes in future periods.
Entergy anticipates that the TCJA, including the federal corporate income tax rate change, may continue to have ramifications that require adjustments in the future as certain events occur. These events include: 1) the evaluation by regulators in all of Entergy’s jurisdictions regarding the ratemaking treatment of TCJA and excess ADIT; 2) IRS audit adjustments to or amendments of federal and state income tax returns that include modifications to the computation of taxable income resulting from TCJA; and 3) additional guidance, interpretations, or rulings by the U.S. Department of the Treasury or the IRS. The potential exists for these types of events to result in future tax expense adjustments because of the difference in the federal corporate income tax rate between past and future periods and the effect of the tax rate change on ratemaking. In turn, these items also could potentially affect the regulatory liability for income taxes.
Coronavirus Aid, Relief, and Economic Security Act
In response to the economic impacts of the COVID-19 pandemic, President Trump signed the Coronavirus Aid, Relief, and Economic Security Act (CARES Act) into law on March 27, 2020. The CARES Act provisions that result in the most significant opportunities for tax relief to Entergy and the Registrant Subsidiaries are (i) permitting a five-year carryback of 2018-2020 NOLs, (ii) removing the 80 percent limitation on NOLs carried to tax years beginning before 2021, (iii) increasing the limitation on interest expense deductibility for 2019 and 2020, (iv) accelerating available refunds for minimum tax credit carryforwards, modifying limitations on charitable contributions during 2020, and (v) delaying the payment of employer payroll taxes. Entergy deferred approximately $64 million of 2020 payroll tax payments, which will be payable in two installments of $32 million on December 31, 2021 and December 31, 2022.
Entergy Wholesale Commodities Restructuring
In the third quarter 2018, Entergy completed a restructuring of the investment holdings in one of the Entergy Wholesale Commodities nuclear plant decommissioning trusts that resulted in an adjustment to tax basis for the trust. The accounting standards provide that a taxable temporary difference does not exist if the tax law provides a means by which an amount can be recovered without incurrence of tax. The restructuring allows Entergy to recover assets from the trust without incurring tax. As such, the tax basis recognized resulted in the reversal of a deferred tax liability and reduction of income tax expense of approximately $107 million.
In the fourth quarter 2019, two separate events occurred resulting in a reduction of tax expense of $174 million. In November 2019 an Entergy Wholesale Commodities subsidiary recognized a reduction in income tax expense of $18 million in connection with the accounting method on power contracts associated with the Palisades nuclear power station. Additionally, Entergy’s ownership of Indian Point 2 and Indian Point 3 was restructured. The restructuring required Entergy to recognize Indian Point 2 and Indian Point 3 nuclear decommissioning liabilities for income tax purposes resulting in a tax accounting permanent difference that reduced income tax expense, net of unrecognized tax benefits, by $156 million. The accrual of the nuclear decommissioning liabilities 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.
Immediately prior to the restructuring, through its ownership of Indian Point 2 and Indian Point 3, Entergy donated property to Stony Brook University and recognized an associated tax deduction resulting in a decrease to tax expense of $19 million.
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
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$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.
Entergy Wholesale Commodities Tax Audit
A state income tax audit involving Entergy Wholesale Commodities was concluded during the third quarter 2018. Upon conclusion of the audit, subsidiaries within Entergy Wholesale Commodities reversed a portion of the provision for uncertain tax positions totaling approximately $23 million, net of tax and interest paid.
Tax Accounting Methods
In the fourth quarter 2015, System Energy and Entergy Louisiana adopted a new method of accounting for income tax return purposes in which their nuclear decommissioning costs will be treated as production costs of electricity includable in cost of goods sold. The new method resulted in a reduction of taxable income of $1.2 billion for System Energy and $2.2 billion for Energy Louisiana.
In conjunction with the 2014-2015 IRS audit discussed above, the IRS issued proposed adjustments concerning the nuclear decommissioning tax position allowing System Energy to include $102 million of its decommissioning liability in cost of goods sold, and Entergy Louisiana to include $221 million of its decommissioning liability in cost of goods sold. Entergy, System Energy, and Entergy Louisiana agreed to the proposed adjustments included in the RAR.
As a result of System Energy being allowed to include part of its decommissioning liability in cost of goods sold, System Energy and Entergy recorded a deferred tax liability of $26 million. System Energy also recorded federal and state taxes payable of $402 million. However, on a consolidated basis, Entergy utilized tax loss carryovers to offset the federal taxable income adjustment and did not record federal taxes payable as a result of the outcome of this uncertain tax position.
As a result of Entergy Louisiana being allowed to include part of its decommissioning liability in cost of goods sold, Entergy Louisiana and Entergy recorded a deferred tax liability of $60 million. Both Entergy Louisiana and Entergy utilized tax loss carryovers to offset the taxable income adjustment and accordingly did not record taxes payable as a result of the outcome of this uncertain tax position.
The partial disallowance of this uncertain tax position to include the decommissioning liability in cost of goods sold resulted in a $1.5 billion decrease in the balance of unrecognized tax benefits related to federal and state taxes for Entergy. Additionally, both System Energy and Entergy Louisiana recorded a reduction to their balances of unrecognized tax benefits for federal and state taxes of $461 million and $1.1 billion, respectively.
Entergy Arkansas adopted the same method of accounting for its nuclear decommissioning costs which resulted in a $1.8 billion reduction in taxable income on its 2018 tax return.
The tax treatment of Entergy Louisiana’s accrued regulatory liabilities associated with the Vidalia purchased power agreement and business combination guaranteed customer credits, which are discussed further in Note 2, has been resolved with the IRS in a manner that results in a $190 million increase to previously reported taxable income. Entergy Louisiana and Entergy utilized tax loss carryovers to offset the taxable income adjustment, however, which allowed both Entergy Louisiana and Entergy to reduce their balances of federal and state unrecognized tax benefits by $74 million.
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. The election resulted in a
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$2.2 billion deductible temporary difference. In 2017, Entergy New Orleans also elected mark-to-market income tax treatment for wholesale electric contracts which resulted in a $1.1 billion deductible temporary difference. In 2018, Entergy Arkansas and Entergy Mississippi accrued deductible temporary differences related to mark-to-market tax accounting for wholesale electric contracts of $2.1 billion and $1.9 billion, respectively. Additionally, 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.
Entergy Arkansas and Entergy Mississippi Internal Restructuring
In the fourth quarter 2018, Entergy Arkansas and Entergy Mississippi became 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 resulting in a tax accounting permanent difference that reduced income tax expense, net of unrecognized tax benefits, by $165 million. The accrual of the nuclear decommissioning liabilities 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. Additionally, Entergy recorded a $5 million reduction of income tax expense associated with state income tax effects resulting in a total reduction of income tax expense of $170 million from the restructuring. Entergy recorded a regulatory liability of $40 million ($30 million net-of-tax) which partially offsets the reduction of income tax expense. Entergy Arkansas’s member’s equity increased by $94 million as a result of the restructuring. See Note 2 to the financial statements for further discussion of the internal restructuring.
Arkansas Corporate Income Tax Rate Reduction
In April 2019 the State of Arkansas enacted corporate income tax law changes that phase in an Arkansas tax rate reduction from the current rate of 6.5% to 6.2% in 2021 and 5.9% in 2022. The rate reduction will eventually reduce Entergy Arkansas’s combined federal and state applicable tax rate by less than 0.5% once fully adopted. As a result of the rate reduction, Entergy Arkansas computed a final regulatory liability for income taxes of approximately $21 million, which includes a tax gross-up related to the treatment of income taxes in the retail and wholesale ratemaking formulas. During the first quarter of 2021, Entergy Arkansas refunded $7.5 million to Arkansas retail customers which represents the retail portion of the $21 million referenced above offset by the effect of adjustments to the regulatory liability for TCJA excess accumulated deferred income taxes. The Arkansas tax law enactment also phases in an increase to the net operating loss carryover period from five to ten years.
Consolidated Income Tax Return of Entergy Corporation
In September 2019, Entergy Utility Holding Company, LLC and its regulated, wholly-owned subsidiaries including Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, became eligible to and joined the Entergy Corporation consolidated federal income tax group. As a result of these four Utility operating companies re-joining the Entergy Corporation consolidated tax return group, Entergy was able to recognize a $41 million deferred tax asset associated with a previously unrecognized Arkansas net operating loss carryover.
Additionally, in September 2019, Entergy Texas issued $35 million of 5.375% Series A preferred stock with a liquidation value of $25 per share resulting in the disaffiliation and de-consolidation of Entergy Texas from the consolidated federal income tax return of Entergy Corporation. These changes will not affect the accrual or allocation of income taxes for the Registrant Subsidiaries. See Note 6 to the financial statements for discussion of the preferred stock issuance.
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Vermont Yankee
The Vermont Yankee transaction resulted in Entergy generating a net deferred tax asset in January 2019. The deferred tax asset could not be fully realized by Entergy in the first quarter 2019; accordingly, Entergy accrued a net tax expense of $29 million on the disposition of Vermont Yankee. See Note 14 to the financial statements for discussion of the Vermont Yankee transaction.
Stock Compensation
In accordance with stock compensation accounting rules, Entergy and the Registrant Subsidiaries recognized excess tax deductions as a reduction of income tax expense in the first quarter 2020. Due to the vesting and exercise of certain Entergy stock-based awards, Entergy recorded a permanent tax reduction of approximately $24.7 million, including $4.8 million for Entergy Arkansas, $8.6 million for Entergy Louisiana, $2.7 million for Entergy Mississippi, $1.5 million for Entergy New Orleans, $2.7 million for Entergy Texas, and $1.3 million for System Energy.
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 September 2024. 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, 2020 was 2.35% on the drawn portion of the facility. Following is a summary of the borrowings outstanding and capacity available under the facility as of December 31, 2020.
| Capacity | Borrowings | Letters of Credit | Capacity Available | |||||||||||||||||
| (In Millions) | ||||||||||||||||||||
| $3,500 | $165 | $6 | $3,329 | |||||||||||||||||
Entergy Corporation’s credit facility requires 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 Utility operating companies (except Entergy New Orleans) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the facility maturity date may occur.
Entergy Corporation has a commercial paper program with a Board-approved program limit of up to $2 billion. As of December 31, 2020, Entergy Corporation had $1.627 billion of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2020 was 1.39%.
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Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2020 as follows:
| Company | Expiration Date | Amount of Facility | Interest Rate (a) | Amount Drawn as of December 31, 2020 | Letters of Credit Outstanding as of December 31, 2020 | |||||||||||||||||||||||||||
| Entergy Arkansas | April 2021 | $25 million (b) | 1.27% | — | — | |||||||||||||||||||||||||||
| Entergy Arkansas | September 2024 | $150 million (c) | 1.27% | — | — | |||||||||||||||||||||||||||
| Entergy Louisiana | September 2024 | $350 million (c) | 1.27% | — | — | |||||||||||||||||||||||||||
| Entergy Mississippi | April 2021 | $10 million (d) | 1.65% | — | — | |||||||||||||||||||||||||||
| Entergy Mississippi | April 2021 | $35 million (d) | 1.65% | — | — | |||||||||||||||||||||||||||
| Entergy Mississippi | April 2021 | $37.5 million (d) | 1.65% | — | — | |||||||||||||||||||||||||||
| Entergy New Orleans | November 2021 | $25 million (c) | 1.42% | — | $0.8 million | |||||||||||||||||||||||||||
| Entergy Texas | September 2024 | $150 million (c) | 1.65% | — | $1.3 million | |||||||||||||||||||||||||||
(a)The interest rate is the estimated interest rate as of December 31, 2020 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.
(d)Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option.
The commitment fees on the credit facilities range from 0.075% to 0.275% of the undrawn commitment amount. 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 entered into one or more uncommitted standby letter of credit facilities as a means to post collateral to support its obligations to MISO. Following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2020:
| Company | Amount of Uncommitted Facility | Letter of Credit Fee | Letters of Credit Issued as of December 31, 2020 (a) (b) | |||||||||||||||||
| Entergy Arkansas | $25 million | 0.78% | $1 million | |||||||||||||||||
| Entergy Louisiana | $125 million | 0.78% | $2.2 million | |||||||||||||||||
| Entergy Mississippi | $65 million | 0.78% | $1 million | |||||||||||||||||
| Entergy New Orleans | $15 million | 1.00% | $1 million | |||||||||||||||||
| Entergy Texas | $50 million | 0.70% | $6.2 million | |||||||||||||||||
(a) As of December 31, 2020, letters of credit posted with MISO covered financial transmission right exposure of $0.3 million for Entergy Louisiana, $0.2 million for Entergy Mississippi, $0.2 million for Entergy New Orleans, and $0.5 million for Entergy Texas. See Note 15 to the financial statements for discussion of financial transmission rights.
(b) As of December 31, 2020, in addition to the $1 million MISO letter of credit, Entergy Mississippi has $1 million of non-MISO letters of credit outstanding under this facility.
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The short-term borrowings of the Registrant Subsidiaries are limited to amounts authorized by the FERC. The current FERC-authorized limits for Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are effective through July 14, 2022. 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 and the other internal borrowing arrangements are inter-company borrowing arrangements designed to reduce the Utility 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, 2020 (aggregating both internal and external short-term borrowings) for the Registrant Subsidiaries:
| Authorized | Borrowings | ||||||||||
| (In Millions) | |||||||||||
| Entergy Arkansas | $250 | $— | |||||||||
| Entergy Louisiana | $450 | $— | |||||||||
| Entergy Mississippi | $175 | $17 | |||||||||
| Entergy New Orleans | $150 | $10 | |||||||||
| Entergy Texas | $200 | $— | |||||||||
| System Energy | $200 | $— | |||||||||
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 2021. The commitment fee is currently 0.20% of the undrawn commitment amount. As of December 31, 2020, $139 million in cash borrowings were outstanding under the credit facility. The weighted average interest rate for the year ended December 31, 2020 was 2.46% on the drawn portion of the facility. See Note 14 to the financial statements for discussion of the transfer of Entergy Nuclear Vermont Yankee to NorthStar.
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 (VIE). 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, 2020:
| Company | Expiration Date | Amount of Facility | Weighted Average Interest Rate on Borrowings (a) | Amount Outstanding as of December 31, 2020 | ||||||||||||||||||||||
| (Dollars in Millions) | ||||||||||||||||||||||||||
| Entergy Arkansas VIE | September 2022 | $80 | 1.94% | $12.2 | ||||||||||||||||||||||
| Entergy Louisiana River Bend VIE | September 2022 | $105 | 1.95% | $18.9 | ||||||||||||||||||||||
| Entergy Louisiana Waterford VIE | September 2022 | $105 | 1.72% | $39.3 | ||||||||||||||||||||||
| System Energy VIE | September 2022 | $120 | 1.63% | $— | ||||||||||||||||||||||
(a)Includes letter of credit fees and bank fronting fees on commercial paper issuances by the nuclear fuel company variable interest entities for Entergy Arkansas, Entergy Louisiana, and System Energy. The
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nuclear fuel company variable interest entity 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 0.125% 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 variable interest entities had notes payable that are included in debt on the respective balance sheets as of December 31, 2020 as follows:
| Company | Description | Amount | ||||||||||||
| Entergy Arkansas VIE | 3.65% Series L due July 2021 | $90 million | ||||||||||||
| Entergy Arkansas VIE | 3.17% Series M due December 2023 | $40 million | ||||||||||||
| Entergy Louisiana River Bend VIE | 2.51% Series V due June 2027 | $70 million | ||||||||||||
| Entergy Louisiana Waterford VIE | 3.92% Series H due February 2021 (a) | $40 million | ||||||||||||
| Entergy Louisiana Waterford VIE | 3.22% Series I due December 2023 | $20 million | ||||||||||||
| System Energy VIE | 3.42% Series J due April 2021 (a) | $100 million | ||||||||||||
| System Energy VIE | 2.05% Series K due September 2027 | $90 million | ||||||||||||
(a) Redeemed in February 2021.
In accordance with regulatory treatment, interest on the nuclear fuel company variable interest entities’ credit facilities, commercial paper, and long-term notes payable is reported in fuel expense.
Entergy Arkansas, Entergy Louisiana, and System Energy each have obtained financing authorizations from the FERC that extend through July 14, 2022 for issuances by its nuclear fuel company variable interest entities.
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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 Corporation and subsidiaries as of December 31, 2020 and 2019 consisted of:
| Type of Debt and Maturity | Weighted Average Interest Rate December 31, 2020 | Interest Rate Ranges at December 31, | Outstanding at December 31, | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||
| Mortgage Bonds | ||||||||||||||||||||||||||||||||
| 2020-2024 | 3.23% | 0.62% - 5.59% | 2.55% - 5.59% | $4,400,000 | $3,575,000 | |||||||||||||||||||||||||||
| 2025-2029 | 3.35% | 2.14% - 4.44% | 2.4% - 4.44% | 4,113,000 | 3,735,000 | |||||||||||||||||||||||||||
| 2030-2040 | 3.38% | 1.6% - 4.52% | 3.05% - 4.52% | 2,552,000 | 1,590,000 | |||||||||||||||||||||||||||
| 2044-2066 | 4.12% | 2.65% - 5.5% | 3.55% - 5.625% | 6,380,000 | 5,170,000 | |||||||||||||||||||||||||||
| Governmental Bonds (a) | ||||||||||||||||||||||||||||||||
| 2021-2022 | 2.50% | 2.375% - 2.5% | 2.375% - 2.5% | 179,000 | 179,000 | |||||||||||||||||||||||||||
| 2028-2030 | 3.45% | 3.375% - 3.5% | 3.375% - 3.5% | 198,680 | 198,680 | |||||||||||||||||||||||||||
| Securitization Bonds | ||||||||||||||||||||||||||||||||
| 2022-2027 | 3.59% | 2.04% - 5.93% | 2.04% - 5.93% | 177,522 | 302,145 | |||||||||||||||||||||||||||
| Variable Interest Entities Notes Payable (Note 4) | ||||||||||||||||||||||||||||||||
| 2021-2027 | 2.45% | 2.05% - 3.92% | 3.17% - 3.92% | 450,000 | 360,000 | |||||||||||||||||||||||||||
| Entergy Corporation Notes | ||||||||||||||||||||||||||||||||
| due September 2020 | n/a | —% | 5.125% | — | 450,000 | |||||||||||||||||||||||||||
| due July 2022 | n/a | 4.00% | 4.00% | 650,000 | 650,000 | |||||||||||||||||||||||||||
| due September 2025 | n/a | 0.9% | — | 800,000 | — | |||||||||||||||||||||||||||
| due September 2026 | n/a | 2.95% | 2.95% | 750,000 | 750,000 | |||||||||||||||||||||||||||
| due June 2030 | n/a | 2.80% | — | 600,000 | — | |||||||||||||||||||||||||||
| due June 2050 | n/a | 3.75% | — | 600,000 | — | |||||||||||||||||||||||||||
| Entergy New Orleans Unsecured Term Loan due May 2022 | n/a | 3.00% | 3.00% | 70,000 | 70,000 | |||||||||||||||||||||||||||
| 5 Year Credit Facility (Note 4) | n/a | 2.35% | 3.77% | 165,000 | 440,000 | |||||||||||||||||||||||||||
| Entergy New Orleans Credit Facility (Note 4) | n/a | — | 2.92% | — | 20,000 | |||||||||||||||||||||||||||
| Vermont Yankee Credit Facility (Note 4) | n/a | 2.46% | 3.93% | 139,000 | 139,000 | |||||||||||||||||||||||||||
| Entergy Arkansas VIE Credit Facility (Note 4) | n/a | 1.94% | 3.33% | 12,200 | 15,100 | |||||||||||||||||||||||||||
| Entergy Louisiana River Bend VIE Credit Facility (Note 4) | n/a | 1.95% | 3.23% | 18,900 | 70,300 | |||||||||||||||||||||||||||
| Entergy Louisiana Waterford VIE Credit Facility (Note 4) | n/a | 1.72% | 3.30% | 39,300 | 49,900 | |||||||||||||||||||||||||||
| System Energy VIE Credit Facility (Note 4) | n/a | 1.63% | 3.34% | — | 31,600 | |||||||||||||||||||||||||||
| Long-term DOE Obligation (b) | — | — | — | 192,018 | 191,114 | |||||||||||||||||||||||||||
| Grand Gulf Sale-Leaseback Obligation | n/a | — | — | 34,336 | 34,346 | |||||||||||||||||||||||||||
| Unamortized Premium and Discount - Net | 3,665 | (16,124) | ||||||||||||||||||||||||||||||
| Unamortized Debt Issuance Costs | (160,420) | (143,502) | ||||||||||||||||||||||||||||||
| Other | 5,575 | 12,096 | ||||||||||||||||||||||||||||||
| Total Long-Term Debt | 22,369,776 | 17,873,655 | ||||||||||||||||||||||||||||||
| Less Amount Due Within One Year | 1,164,015 | 795,012 | ||||||||||||||||||||||||||||||
| Long-Term Debt Excluding Amount Due Within One Year | $21,205,761 | $17,078,643 | ||||||||||||||||||||||||||||||
| Fair Value of Long-Term Debt | $24,813,818 | $19,059,950 | ||||||||||||||||||||||||||||||
128
(a)Consists of pollution control revenue bonds and environmental revenue bonds, some of which are secured by collateral mortgage 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.
The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2020, for the next five years are as follows:
| Amount | |||||
| (In Thousands) | |||||
| 2021 | $1,164,000 | ||||
| 2022 | $1,141,878 | ||||
| 2023 | $2,452,194 | ||||
| 2024 | $1,340,000 | ||||
| 2025 | $1,378,000 | ||||
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through July 2022. Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through July 2022. Entergy Arkansas has also obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2022.
129
Long-term debt for the Registrant Subsidiaries as of December 31, 2020 and 2019 consisted of:
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| Entergy Arkansas | ||||||||||||||
| Mortgage Bonds: | ||||||||||||||
3.75% Series due February 2021 | $350,000 | $350,000 | ||||||||||||
3.05% Series due June 2023 | 250,000 | 250,000 | ||||||||||||
3.7% Series due June 2024 | 375,000 | 375,000 | ||||||||||||
3.5% Series due April 2026 | 600,000 | 600,000 | ||||||||||||
4.0% Series due June 2028 | 350,000 | 250,000 | ||||||||||||
4.95% Series due December 2044 | 250,000 | 250,000 | ||||||||||||
4.20% Series due April 2049 | 350,000 | 350,000 | ||||||||||||
2.65% Series due June 2051 | 675,000 | — | ||||||||||||
4.90% Series due December 2052 | — | 200,000 | ||||||||||||
4.75% Series due June 2063 | — | 125,000 | ||||||||||||
4.875% Series due September 2066 | 410,000 | 410,000 | ||||||||||||
| Total mortgage bonds | 3,610,000 | 3,160,000 | ||||||||||||
| Governmental Bonds (a): | ||||||||||||||
2.375% Series due 2021, Independence County (c) | 45,000 | 45,000 | ||||||||||||
| Total governmental bonds | 45,000 | 45,000 | ||||||||||||
| Variable Interest Entity Notes Payable and Credit Facility (Note 4): | ||||||||||||||
3.65% Series L due July 2021 | 90,000 | 90,000 | ||||||||||||
3.17% Series M due December 2023 | 40,000 | 40,000 | ||||||||||||
Credit Facility due September 2022, weighted avg rate 1.94% | 12,200 | 15,100 | ||||||||||||
| Total variable interest entity notes payable and credit facility | 142,200 | 145,100 | ||||||||||||
| Securitization Bonds: | ||||||||||||||
2.30% Series Senior Secured due August 2021 | — | 7,259 | ||||||||||||
| Total securitization bonds | — | 7,259 | ||||||||||||
| Other: | ||||||||||||||
| Long-term DOE Obligation (b) | 192,018 | 191,114 | ||||||||||||
| Unamortized Premium and Discount – Net | 6,938 | 1,664 | ||||||||||||
| Unamortized Debt Issuance Costs | (30,638) | (34,936) | ||||||||||||
| Other | 1,989 | 2,007 | ||||||||||||
| Total Long-Term Debt | 3,967,507 | 3,517,208 | ||||||||||||
| Less Amount Due Within One Year | 485,000 | — | ||||||||||||
| Long-Term Debt Excluding Amount Due Within One Year | $3,482,507 | $3,517,208 | ||||||||||||
| Fair Value of Long-Term Debt | $4,355,632 | $3,747,914 | ||||||||||||
130
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| Entergy Louisiana | ||||||||||||||
| Mortgage Bonds: | ||||||||||||||
3.95% Series due October 2020 | $— | $250,000 | ||||||||||||
4.8% Series due May 2021 | 200,000 | 200,000 | ||||||||||||
3.3% Series due December 2022 | 200,000 | 200,000 | ||||||||||||
4.05% Series due September 2023 | 325,000 | 325,000 | ||||||||||||
0.62% Series due November 2023 | 1,100,000 | — | ||||||||||||
5.59% Series due October 2024 | 300,000 | 300,000 | ||||||||||||
5.40% Series due November 2024 | 400,000 | 400,000 | ||||||||||||
3.78% Series due April 2025 | 110,000 | 110,000 | ||||||||||||
3.78% Series due April 2025 | 190,000 | 190,000 | ||||||||||||
4.44% Series due January 2026 | 250,000 | 250,000 | ||||||||||||
2.40% Series due October 2026 | 400,000 | 400,000 | ||||||||||||
3.12% Series due September 2027 | 450,000 | 450,000 | ||||||||||||
3.25% Series due April 2028 | 425,000 | 425,000 | ||||||||||||
1.60% Series due December 2030 | 300,000 | — | ||||||||||||
3.05% Series due June 2031 | 325,000 | 325,000 | ||||||||||||
4.0% Series due March 2033 | 750,000 | 750,000 | ||||||||||||
5.0% Series due July 2044 | 170,000 | 170,000 | ||||||||||||
4.95% Series due January 2045 | 450,000 | 450,000 | ||||||||||||
4.20% Series due September 2048 | 900,000 | 600,000 | ||||||||||||
4.20% Series due April 2050 | 525,000 | 525,000 | ||||||||||||
2.90% Series due March 2051 | 650,000 | — | ||||||||||||
5.25% Series due July 2052 | — | 200,000 | ||||||||||||
4.70% Series due June 2063 | — | 100,000 | ||||||||||||
4.875% Series due September 2066 | 270,000 | 270,000 | ||||||||||||
| Total mortgage bonds | 8,690,000 | 6,890,000 | ||||||||||||
| Governmental Bonds (a): | ||||||||||||||
3.375% Series due 2028, Louisiana Public Facilities Authority (c) | 83,680 | 83,680 | ||||||||||||
3.50% Series due 2030, Louisiana Public Facilities Authority (c) | 115,000 | 115,000 | ||||||||||||
| Total governmental bonds | 198,680 | 198,680 | ||||||||||||
| Variable Interest Entity Notes Payable and Credit Facilities (Note 4): | ||||||||||||||
3.38% Series R due August 2020 | — | 70,000 | ||||||||||||
3.92% Series H due February 2021 | 40,000 | 40,000 | ||||||||||||
3.22% Series I due December 2023 | 20,000 | 20,000 | ||||||||||||
2.51% Series V due June 2027 | 70,000 | — | ||||||||||||
Credit Facility due September 2022, weighted avg rate 1.95% | 18,900 | 70,300 | ||||||||||||
Credit Facility due September 2022, weighted avg rate 1.72% | 39,300 | 49,900 | ||||||||||||
| Total variable interest entity notes payable and credit facilities | 188,200 | 250,200 | ||||||||||||
| Securitization Bonds: | ||||||||||||||
2.04% Series Senior Secured due September 2023 | 10,980 | 34,185 | ||||||||||||
| Total securitization bonds | 10,980 | 34,185 | ||||||||||||
| Other: | ||||||||||||||
| Unamortized Premium and Discount - Net | (2,863) | (17,372) | ||||||||||||
| Unamortized Debt Issuance Costs | (61,132) | (58,089) | ||||||||||||
| Other | 3,586 | 6,065 | ||||||||||||
| Total Long-Term Debt | 9,027,451 | 7,303,669 | ||||||||||||
| Less Amount Due Within One Year | 240,000 | 320,002 | ||||||||||||
| Long-Term Debt Excluding Amount Due Within One Year | $8,787,451 | $6,983,667 | ||||||||||||
| Fair Value of Long-Term Debt | $10,258,294 | $7,961,168 | ||||||||||||
131
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| Entergy Mississippi | ||||||||||||||
| Mortgage Bonds: | ||||||||||||||
3.1% Series due July 2023 | $250,000 | $250,000 | ||||||||||||
3.75% Series due July 2024 | 100,000 | 100,000 | ||||||||||||
3.25% Series due December 2027 | 150,000 | 150,000 | ||||||||||||
2.85% Series due June 2028 | 375,000 | 375,000 | ||||||||||||
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 | 170,000 | — | ||||||||||||
4.90% Series due October 2066 | 260,000 | 260,000 | ||||||||||||
| Total mortgage bonds | 1,795,000 | 1,625,000 | ||||||||||||
| Other: | ||||||||||||||
| Unamortized Premium and Discount – Net | 3,685 | 6,127 | ||||||||||||
| Unamortized Debt Issuance Costs | (18,108) | (16,998) | ||||||||||||
| Total Long-Term Debt | 1,780,577 | 1,614,129 | ||||||||||||
| Less Amount Due Within One Year | — | — | ||||||||||||
| Long-Term Debt Excluding Amount Due Within One Year | $1,780,577 | $1,614,129 | ||||||||||||
| Fair Value of Long-Term Debt | $2,021,432 | $1,709,505 | ||||||||||||
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| Entergy New Orleans | ||||||||||||||
| Mortgage Bonds: | ||||||||||||||
5.10% Series due December 2020 | $— | $25,000 | ||||||||||||
3.9% Series due July 2023 | 100,000 | 100,000 | ||||||||||||
3.0% Series due March 2025 | 78,000 | — | ||||||||||||
4.0% Series due June 2026 | 85,000 | 85,000 | ||||||||||||
4.51% Series due September 2033 | 60,000 | 60,000 | ||||||||||||
3.75% Series due March 2040 | 62,000 | — | ||||||||||||
5.0% Series due December 2052 | 30,000 | 30,000 | ||||||||||||
5.50% Series due April 2066 | 110,000 | 110,000 | ||||||||||||
| Total mortgage bonds | 525,000 | 410,000 | ||||||||||||
| Securitization Bonds: | ||||||||||||||
2.67% Series Senior Secured due June 2027 | 42,850 | 54,443 | ||||||||||||
| Total securitization bonds | 42,850 | 54,443 | ||||||||||||
| Other: | ||||||||||||||
3.0% Unsecured Term Loan due May 2022 | 70,000 | 70,000 | ||||||||||||
Credit Facility due November 2021, weighted avg rate 2.92% | — | 20,000 | ||||||||||||
| Payable to associated company due November 2035 | 12,529 | 14,367 | ||||||||||||
| Unamortized Premium and Discount – Net | (91) | (129) | ||||||||||||
| Unamortized Debt Issuance Costs | (8,055) | (7,775) | ||||||||||||
| Total Long-Term Debt | 642,233 | 560,906 | ||||||||||||
| Less Amount Due Within One Year | 1,618 | 26,838 | ||||||||||||
| Long-Term Debt Excluding Amount Due Within One Year | $640,615 | $534,068 | ||||||||||||
| Fair Value of Long-Term Debt | $620,634 | $523,846 | ||||||||||||
132
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| Entergy Texas | ||||||||||||||
| Mortgage Bonds: | ||||||||||||||
2.55% Series due June 2021 | $125,000 | $125,000 | ||||||||||||
4.1% Series due September 2021 | 75,000 | 75,000 | ||||||||||||
3.45% Series due December 2027 | 150,000 | 150,000 | ||||||||||||
4.0% Series due March 2029 | 300,000 | 300,000 | ||||||||||||
1.75% Series due March 2031 | 600,000 | — | ||||||||||||
4.5% Series due March 2039 | 400,000 | 400,000 | ||||||||||||
5.15% Series due June 2045 | 250,000 | 250,000 | ||||||||||||
3.55% Series due September 2049 | 475,000 | 300,000 | ||||||||||||
5.625% Series due June 2064 | — | 135,000 | ||||||||||||
| Total mortgage bonds | 2,375,000 | 1,735,000 | ||||||||||||
| Securitization Bonds: | ||||||||||||||
5.93% Series Senior Secured, Series A due June 2022 | 17,478 | 50,289 | ||||||||||||
4.38% Series Senior Secured, Series A due November 2023 | 106,214 | 155,969 | ||||||||||||
| Total securitization bonds | 123,692 | 206,258 | ||||||||||||
| Other: | ||||||||||||||
| Unamortized Premium and Discount - Net | 14,064 | (4,814) | ||||||||||||
| Unamortized Debt Issuance Costs | (19,048) | (17,510) | ||||||||||||
| Other | — | 4,022 | ||||||||||||
| Total Long-Term Debt | 2,493,708 | 1,922,956 | ||||||||||||
| Less Amount Due Within One Year | 200,000 | — | ||||||||||||
| Long-Term Debt Excluding Amount Due Within One Year | $2,293,708 | $1,922,956 | ||||||||||||
| Fair Value of Long-Term Debt | $2,765,193 | $2,090,215 | ||||||||||||
133
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| System Energy | ||||||||||||||
| Mortgage Bonds: | ||||||||||||||
4.1% Series due April 2023 | $250,000 | $250,000 | ||||||||||||
2.14% Series due December 2025 | 200,000 | — | ||||||||||||
| Total mortgage bonds | 450,000 | 250,000 | ||||||||||||
| Governmental Bonds (a): | ||||||||||||||
2.5% Series due 2022, Mississippi Business Finance Corp. | 134,000 | 134,000 | ||||||||||||
| Total governmental bonds | 134,000 | 134,000 | ||||||||||||
| Variable Interest Entity Notes Payable and Credit Facility (Note 4): | ||||||||||||||
3.42% Series J due April 2021 | 100,000 | 100,000 | ||||||||||||
2.05% Series K due September 2027 | 90,000 | — | ||||||||||||
Credit Facility due September 2022, weighted avg rate 1.63% | — | 31,600 | ||||||||||||
| Total variable interest entity notes payable and credit facility | 190,000 | 131,600 | ||||||||||||
| Other: | ||||||||||||||
| Grand Gulf Sale-Leaseback Obligation | 34,336 | 34,346 | ||||||||||||
| Unamortized Premium and Discount – Net | (165) | (144) | ||||||||||||
| Unamortized Debt Issuance Costs | (2,897) | (1,697) | ||||||||||||
| Other | — | 2 | ||||||||||||
| Total Long-Term Debt | 805,274 | 548,107 | ||||||||||||
| Less Amount Due Within One Year | 100,015 | 10 | ||||||||||||
| Long-Term Debt Excluding Amount Due Within One Year | $705,259 | $548,097 | ||||||||||||
| Fair Value of Long-Term Debt | $840,540 | $565,209 | ||||||||||||
(a)Consists of pollution control revenue bonds and environmental 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 bonds are 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, 2020, for the next five years are as follows:
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||||||||
| 2021 | $485,000 | $240,000 | $— | $1,618 | $200,000 | $100,000 | |||||||||||||||||||||||||||||
| 2022 | $12,200 | $258,200 | $— | $71,326 | $17,478 | $134,000 | |||||||||||||||||||||||||||||
| 2023 | $290,000 | $1,455,980 | $250,000 | $101,306 | $106,214 | $250,000 | |||||||||||||||||||||||||||||
| 2024 | $375,000 | $700,000 | $100,000 | $1,275 | $— | $— | |||||||||||||||||||||||||||||
| 2025 | $— | $300,000 | $— | $79,140 | $— | $200,000 | |||||||||||||||||||||||||||||
134
Securitization Bonds
Entergy Arkansas Securitization Bonds
In June 2010 the APSC issued a financing order authorizing the issuance of bonds to recover Entergy Arkansas’s January 2009 ice storm damage restoration costs, including carrying costs of $11.5 million and $4.6 million of up-front financing costs. In August 2010, Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, issued $124.1 million of storm cost recovery bonds, with a coupon of 2.30%. Although the principal amount was not due until August 2021, Entergy Arkansas Restoration Funding made principal payments on the bonds in the amount of $7.3 million in 2020, after which the bonds were fully repaid.
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 have an interest rate of 2.04%. Although the principal amount is not due until September 2023, Entergy Louisiana Investment Recovery Funding expects to make principal payments on the bonds in the amount of $11 million for 2021, after which the bonds will be fully repaid. 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. In accordance with the financing order, Entergy Louisiana will apply the proceeds it received from the sale of the investment recovery property as a reimbursement for previously-incurred investment recovery costs. The investment recovery property is reflected as a regulatory asset on the consolidated Entergy Louisiana balance sheet. The creditors of Entergy Louisiana do not have recourse to the assets or revenues of Entergy Louisiana Investment Recovery Funding, including the investment recovery property, and the creditors of Entergy Louisiana Investment Recovery Funding do not have recourse to the assets or revenues of Entergy Louisiana. Entergy Louisiana has no payment obligations to Entergy Louisiana Investment Recovery Funding except to remit investment recovery charge collections.
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 over the next four years in the amounts of $11.9 million for 2021, $12.2 million for 2022, $12.5 million for 2023, and $6.2 million for 2024. 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.
135
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). As of December 31, 2020, $17.5 million at 5.93% remain outstanding. Entergy Gulf States Reconstruction Funding expects to make principal payments on the bonds in the amount of $17.5 million for 2021.
With the proceeds, Entergy Gulf States Reconstruction Funding purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition 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 Entergy Gulf States Reconstruction Funding, including the transition property, and the creditors of Entergy Gulf States Reconstruction Funding do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to Entergy Gulf States Reconstruction Funding except to remit transition charge collections.
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). As of December 31, 2020, $106.2 million at 4.38% remain outstanding. Entergy Texas Restoration Funding expects to make principal payments on the bonds over the next two years in the amount of $52 million for 2021 and $54.3 million for 2022.
With the proceeds, Entergy Texas Restoration Funding purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition 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 Entergy Texas Restoration Funding, including the transition property, and the creditors of Entergy Texas Restoration Funding do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to Entergy Texas Restoration Funding except to remit transition 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 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. However, operating revenues include the recovery of the lease payments because the transactions are accounted for as a sale and leaseback for ratemaking purposes. Consistent
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with a recommendation contained in a FERC audit report, System Energy initially recorded as a net regulatory asset the difference between the recovery of the lease payments and the amounts expensed for interest and depreciation and continues to record this difference as a regulatory asset or liability on an ongoing basis, resulting in a zero net balance for the regulatory asset at the end of the lease term. The amount was a net regulatory liability of $55.6 million as of December 31, 2020 and 2019.
As of December 31, 2020, 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:
| Amount | |||||
| (In Thousands) | |||||
| 2021 | $17,188 | ||||
| 2022 | 17,188 | ||||
| 2023 | 17,188 | ||||
| 2024 | 17,188 | ||||
| 2025 | 17,188 | ||||
| Years thereafter | 189,063 | ||||
| Total | 275,003 | ||||
| Less: Amount representing interest | 240,667 | ||||
| Present value of net minimum lease payments | $34,336 | ||||
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NOTE 6. PREFERRED EQUITY (Entergy Corporation and Entergy Texas)
The number of shares and units authorized and outstanding and dollar value of preferred stock, preferred membership interests, and non-controlling interest for Entergy Corporation subsidiaries as of December 31, 2020 and 2019 are presented below.
| Shares/Units Authorized | Shares/Units Outstanding | |||||||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||||||||||||||||
| Entergy Corporation | (Dollars in Thousands) | |||||||||||||||||||||||||||||||||||||
| Utility: | ||||||||||||||||||||||||||||||||||||||
| Preferred Stock or Preferred Membership Interests without sinking fund: | ||||||||||||||||||||||||||||||||||||||
Entergy Utility Holding Company, LLC, 7.5% Series (a) | 110,000 | 110,000 | 110,000 | 110,000 | $107,425 | $107,425 | ||||||||||||||||||||||||||||||||
Entergy Utility Holding Company, LLC, 6.25% Series (b) | 15,000 | 15,000 | 15,000 | 15,000 | 14,366 | 14,366 | ||||||||||||||||||||||||||||||||
Entergy Utility Holding Company, LLC, 6.75% Series (c) | 75,000 | 75,000 | 75,000 | 75,000 | 73,370 | 73,370 | ||||||||||||||||||||||||||||||||
Entergy Texas, 5.375% Series | 1,400,000 | 1,400,000 | 1,400,000 | 1,400,000 | 35,000 | 35,000 | ||||||||||||||||||||||||||||||||
| Total Utility Preferred Stock or Preferred Membership Interests without sinking fund | 1,600,000 | 1,600,000 | 1,600,000 | 1,600,000 | 230,161 | 230,161 | ||||||||||||||||||||||||||||||||
| Entergy Wholesale Commodities: | ||||||||||||||||||||||||||||||||||||||
| Preferred Stock without sinking fund: | ||||||||||||||||||||||||||||||||||||||
Entergy Finance Holding, Inc. 8.75% (d) | 250,000 | 250,000 | 250,000 | 250,000 | 24,249 | 24,249 | ||||||||||||||||||||||||||||||||
| Total Subsidiaries’ Preferred Stock or Preferred Membership Interests without sinking fund | 1,850,000 | 1,850,000 | 1,850,000 | 1,850,000 | $254,410 | $254,410 | ||||||||||||||||||||||||||||||||
(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, 2020. 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, 2020. 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, 2020. 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, 2020. 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.
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The number of shares authorized and outstanding and dollar value of preferred stock for Entergy Texas as of December 31, 2020 and 2019 are presented below.
| Shares Authorized and Outstanding | Call Price per Share as of December 31, | |||||||||||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | 2020 | ||||||||||||||||||||||||||||
| Entergy Texas Preferred Stock | (Dollars in Thousands) | |||||||||||||||||||||||||||||||
| Without sinking fund: | ||||||||||||||||||||||||||||||||
| Cumulative, $25 par value: | ||||||||||||||||||||||||||||||||
5.375% Series (a) | 1,400,000 | 1,400,000 | $35,000 | $35,000 | $— | |||||||||||||||||||||||||||
| Total without sinking fund | 1,400,000 | 1,400,000 | $35,000 | $35,000 | ||||||||||||||||||||||||||||
(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, 2020. 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.
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.
Presentation of Preferred Stock without Sinking Fund
Accounting standards regarding non-controlling 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 (a Utility subsidiary) and Entergy Finance Holding (an Entergy Wholesale Commodities subsidiary), 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.
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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 2020, 2019, and 2018 is as follows:
| 2020 | 2019 | 2018 | |||||||||||||||||||||||||||||||||
| Common Shares Issued | Treasury Shares | Common Shares Issued | Treasury Shares | Common Shares Issued | Treasury Shares | ||||||||||||||||||||||||||||||
| Beginning Balance, January 1 | 270,035,180 | 70,886,400 | 261,587,009 | 72,530,866 | 254,752,788 | 74,235,135 | |||||||||||||||||||||||||||||
| Issuances: | |||||||||||||||||||||||||||||||||||
| Equity forwards settled | — | — | 8,448,171 | — | 6,834,221 | — | |||||||||||||||||||||||||||||
| Employee Stock-Based Compensation Plans | — | (1,076,511) | — | (1,624,358) | — | (1,683,174) | |||||||||||||||||||||||||||||
| Directors’ Plan | — | (19,543) | — | (20,108) | — | (21,095) | |||||||||||||||||||||||||||||
| Ending Balance, December 31 | 270,035,180 | 69,790,346 | 270,035,180 | 70,886,400 | 261,587,009 | 72,530,866 | |||||||||||||||||||||||||||||
Entergy Corporation reissues treasury shares to meet the requirements of the Stock Plan for Outside Directors (Directors’ Plan), the four 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, 2020, $350 million of authority remains under the $500 million share repurchase program.
Dividends declared per common share were $3.74 in 2020, $3.66 in 2019, and $3.58 in 2018.
(System Energy)
System Energy paid its parent, Entergy Corporation, distributions out of its common stock of $56.5 million in 2018.
Equity Forward Sale Agreements
In June 2018, Entergy marketed an equity offering of 15.3 million shares of common stock. In lieu of issuing equity at the time of the offering, Entergy entered into forward sale agreements with various investment banks. The equity forwards required Entergy to, at its election prior to June 7, 2019, either (i) physically settle the transactions by issuing the total of 15.3 million shares of its common stock to the investment banks in exchange for net proceeds at the then-applicable forward sale price specified by the agreements (initially $74.45 per share) or (ii) net settle the transactions in whole or in part through the delivery or receipt of cash or shares. The 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 December 2018, Entergy physically settled a portion of its obligations under the forward sale agreements by delivering 6,834,221 shares of common stock in exchange for cash proceeds of $500 million. The forward sale price used to determine the cash proceeds received by Entergy was calculated based on the initial forward sale price of $74.45 per share as adjusted in accordance with the forward sale agreements. Entergy incurred approximately $728 thousand of common stock issuance costs with the settlement.
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In May 2019, Entergy physically settled its remaining obligations under the forward sale agreements by delivering 8,448,171 shares of common stock in exchange for cash proceeds of $608 million. The forward sale price used to determine the cash proceeds received by Entergy was calculated based on the initial forward sale price of $74.45 per share as adjusted in accordance with the forward sale agreements. Entergy incurred approximately $7 thousand of common stock issuance costs with the settlement.
Entergy used the net proceeds for general corporate purposes, which included repayment of commercial paper, outstanding loans under Entergy’s revolving credit facility, and other debt.
Retained Earnings and Dividends
Entergy implemented ASU No. 2016-01 “Financial Instruments (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities” effective January 1, 2018. The ASU requires investments in equity securities, excluding those accounted for under the equity method or resulting in consolidation of the investee, to be measured at fair value with changes recognized in net income. Entergy implemented this standard using a modified retrospective method, and recorded an adjustment increasing retained earnings and reducing accumulated other comprehensive income by $633 million as of January 1, 2018 for the cumulative effect of the unrealized gains and losses on investments in equity securities held by the decommissioning trust funds that do not meet the criteria for regulatory accounting treatment. See Note 16 to the financial statements for further discussion of effects of the new standard.
Entergy implemented ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory” effective January 1, 2018. The ASU requires entities to recognize the income tax consequences of intra-entity asset transfers, other than inventory, at the time the transfer occurs. Entergy implemented this standard using a modified retrospective method, and recorded an adjustment decreasing retained earnings by $56 million as of January 1, 2018 for the cumulative effect of recording deferred tax assets on previously-recognized intra-entity asset transfers.
Entergy adopted ASU No. 2018-02, “Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income,” in the first quarter 2018. The ASU allows a one-time reclassification from accumulated other comprehensive income to retained earnings for certain tax effects resulting from the Tax Cuts and Jobs Act that would otherwise be stranded in accumulated other comprehensive income. Entergy’s policy for releasing income tax effects from accumulated other comprehensive income for available-for-sale securities is to use the portfolio approach. Entergy elected to reclassify the $15.5 million of stranded tax effects in accumulated other comprehensive income resulting from the Tax Cuts and Jobs Act to retained earnings ($32 million decrease) or the regulatory liability for income taxes ($16.5 million increase). Entergy’s reclassification only includes the effect of the change in the federal corporate income tax rate on accumulated other comprehensive income.
Entergy implemented ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities” effective January 1, 2019. The ASU makes a number of amendments to hedge accounting, most significantly changing the recognition and presentation of highly effective hedges. Entergy implemented this standard using a modified retrospective method, and recorded an adjustment increasing retained earnings and increasing accumulated other comprehensive loss by approximately $8 million as of January 1, 2019 for the cumulative effect of the ineffectiveness portion of designated hedges on nuclear power sales.
Entergy implemented ASU 2017-08 “Receivables (Topic 310): Nonrefundable Fees and Other Costs” effective January 1, 2019. The ASU amends the amortization period for certain purchased callable debt securities held at a premium to the earliest call date. Entergy implemented this standard using the modified retrospective approach, and recorded an adjustment decreasing retained earnings and decreasing accumulated other
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comprehensive loss by approximately $1 million as of January 1, 2019 for the cumulative effect of the amended amortization period.
Entergy Corporation received dividend payments and distributions from subsidiaries totaling $113 million in 2020, $124 million in 2019, and $27 million in 2018.
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, 2020 by component:
| Cash flow hedges net unrealized gain (loss) | Pension and other postretirement liabilities | Net unrealized investment gain (loss) | Total Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||
| Beginning balance, January 1, 2020 | $84,206 | ($557,072) | $25,946 | ($446,920) | |||||||||||||||||||
| Other comprehensive income (loss) before reclassifications | 60,928 | (49,113) | 41,354 | 53,169 | |||||||||||||||||||
| Amounts reclassified from accumulated other comprehensive income (loss) | (116,415) | 71,609 | (10,650) | (55,456) | |||||||||||||||||||
| Net other comprehensive income (loss) for the period | (55,487) | 22,496 | 30,704 | (2,287) | |||||||||||||||||||
| Ending balance, December 31, 2020 | $28,719 | ($534,576) | $56,650 | ($449,207) | |||||||||||||||||||
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The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 2019 by component:
| Cash flow hedges net unrealized gain (loss) | Pension and other postretirement liabilities | Net unrealized investment gain (loss) | Total Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||
| Ending balance, December 31, 2018 | ($23,135) | ($531,922) | ($2,116) | ($557,173) | |||||||||||||||||||
Implementation of accounting standards | (7,685) | — | 879 | (6,806) | |||||||||||||||||||
| Beginning balance, January 1, 2019 | ($30,820) | ($531,922) | ($1,237) | ($563,979) | |||||||||||||||||||
Other comprehensive income (loss) before reclassifications | 191,147 | (93,696) | 32,914 | 130,365 | |||||||||||||||||||
Amounts reclassified from accumulated other comprehensive income (loss) | (76,121) | 68,546 | (5,731) | (13,306) | |||||||||||||||||||
Net other comprehensive income (loss) for the period | 115,026 | (25,150) | 27,183 | 117,059 | |||||||||||||||||||
| Ending balance, December 31, 2019 | $84,206 | ($557,072) | $25,946 | ($446,920) | |||||||||||||||||||
The following table presents changes in accumulated other comprehensive income (loss) for Entergy Louisiana for the year ended December 31, 2020:
| Pension and Other Postretirement Liabilities | ||||||||
| (In Thousands) | ||||||||
| Beginning balance, January 1, 2020 | $4,562 | |||||||
| Other comprehensive income (loss) before reclassifications | 3,002 | |||||||
| Amounts reclassified from accumulated other comprehensive income (loss) | (3,237) | |||||||
| Net other comprehensive income (loss) for the period | (235) | |||||||
| Ending balance, December 31, 2020 | $4,327 | |||||||
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The following table presents changes in accumulated other comprehensive income (loss) for Entergy Louisiana for the year ended December 31, 2019:
| Pension and Other Postretirement Liabilities | ||||||||
| (In Thousands) | ||||||||
| Beginning balance, January 1, 2019 | ($6,153) | |||||||
Other comprehensive income (loss) before reclassifications | 14,591 | |||||||
Amounts reclassified from accumulated other comprehensive income (loss) | (3,876) | |||||||
Net other comprehensive income (loss) for the period | 10,715 | |||||||
| Ending balance, December 31, 2019 | $4,562 | |||||||
Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy for the years ended December 31, 2020 and 2019 are as follows:
| Amounts reclassified from AOCI | Income Statement Location | |||||||||||||||||||
| 2020 | 2019 | |||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| Cash flow hedges net unrealized gain (loss) | ||||||||||||||||||||
| Power contracts | $147,554 | $96,549 | Competitive business operating revenues | |||||||||||||||||
| Interest rate swaps | (194) | (194) | Miscellaneous - net | |||||||||||||||||
| Total realized gain (loss) on cash flow hedges | 147,360 | 96,355 | ||||||||||||||||||
| Income taxes | (30,945) | (20,234) | Income taxes | |||||||||||||||||
| Total realized gain (loss) on cash flow hedges (net of tax) | $116,415 | $76,121 | ||||||||||||||||||
| Pension and other postretirement liabilities | ||||||||||||||||||||
| Amortization of prior-service costs | $20,769 | $21,300 | (a) | |||||||||||||||||
| Amortization of loss | (110,185) | (83,246) | (a) | |||||||||||||||||
| Settlement loss | (243) | (25,155) | (a) | |||||||||||||||||
| Total amortization and settlement loss | (89,659) | (87,101) | ||||||||||||||||||
| Income taxes | 18,050 | 18,555 | Income taxes | |||||||||||||||||
| Total amortization and settlement loss (net of tax) | ($71,609) | ($68,546) | ||||||||||||||||||
| Net unrealized investment gain (loss) | ||||||||||||||||||||
| Realized gain (loss) | $16,851 | $9,069 | Interest and investment income | |||||||||||||||||
| Income taxes | (6,201) | (3,338) | Income taxes | |||||||||||||||||
| Total realized investment gain (loss) (net of tax) | $10,650 | $5,731 | ||||||||||||||||||
| Total reclassifications for the period (net of tax) | $55,456 | $13,306 | ||||||||||||||||||
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| (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, 2020 and 2019 are as follows:
| Amounts reclassified from AOCI | Income Statement Location | |||||||||||||||||||
| 2020 | 2019 | |||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| Pension and other postretirement liabilities | ||||||||||||||||||||
| Amortization of prior-service costs | $6,179 | $7,349 | (a) | |||||||||||||||||
| Amortization of loss | (1,557) | (2,106) | (a) | |||||||||||||||||
| Settlement loss | (243) | — | (a) | |||||||||||||||||
| Total amortization | 4,379 | 5,243 | ||||||||||||||||||
| Income taxes | (1,142) | (1,367) | Income taxes | |||||||||||||||||
| Total amortization (net of tax) | 3,237 | 3,876 | ||||||||||||||||||
| Total reclassifications for the period (net of tax) | $3,237 | $3,876 | ||||||||||||||||||
| (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 commissions, 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 $132.7 million in 2020, $135.5 million in 2019, and $137.6 million in 2018. If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $141 million in 2021, and a total of $1.41 billion for the years 2022 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
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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. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.
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 has 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 is 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 ANO 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.
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
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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 has breached 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 2018, 2019, and 2020 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE.
In September 2018 the DOE submitted an offer of judgment to resolve claims in the second round Entergy Nuclear Generation Company case involving Pilgrim. The $62 million offer was accepted by Entergy Nuclear Generation Company, and the U.S. Court of Federal Claims issued a judgment in that amount in favor of Entergy Nuclear Generation Company. Entergy received payment from the U.S. Treasury in October 2018. The effect in 2018 of recording the judgment was a reduction to plant and other operation and maintenance expenses. The Pilgrim damages awarded included $60 million related to costs previously capitalized and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $60 million, Entergy recorded $4 million as a reduction to previously-recorded depreciation expense, a $10 million reduction to bring its remaining Pilgrim plant asset balance to zero, and the excess $46 million as a reduction to other operation and maintenance expense because Pilgrim’s plant asset balance is fully impaired.
In August 2019 the U.S. Court of Federal Claims issued a final judgment in the amount of $19 million in favor of Entergy Louisiana against the DOE in the second round River Bend damages case. Entergy Louisiana received payment from the U.S. Treasury in September 2019. The effects in 2019 of recording the judgment were reductions to plant, nuclear fuel expense, and other operation and maintenance expense. The River Bend damages awarded included $12 million related to costs previously recorded as nuclear fuel expense, $5 million related to costs previously recorded as other operation and maintenance expense, and $2 million in costs previously capitalized.
In December 2019 the DOE submitted an offer of judgment to resolve claims in the third round ANO damages case. The $80 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 January 2020. The effects in 2019 of recording the judgment were reductions to plant, nuclear fuel expense, other operation and maintenance expense, depreciation expense, and taxes other than income taxes. The ANO damages awarded included $55 million in costs previously capitalized, $12 million related to costs previously recorded as nuclear fuel expense, $12 million related to costs previously recorded as other operation and maintenance expense, and $1 million related to costs previously recorded as taxes other than income taxes. Of the $55 million, Entergy Arkansas, recorded $5 million as a reduction to previously-recorded depreciation expense.
In December 2019 the Entergy FitzPatrick Properties (formerly Entergy Nuclear FitzPatrick) and the DOE entered into a settlement agreement and the U.S. Court of Federal Claims issued a judgment in the amount of $7
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million in favor of Entergy FitzPatrick Properties against the DOE in the second round FitzPatrick damages case. Entergy received payment from the U.S. Treasury in January 2020. Substantially all of the FitzPatrick damages awarded relate to costs previously expensed as asset write-offs, impairments, and related charges, and in December 2019 Entergy recorded $7 million as a reduction to asset write-offs, impairments, and related charges.
In April 2020 the U.S. Court of Federal Claims issued a final judgment in the amount of $33 million in favor of Entergy Louisiana against the DOE in the second round Waterford 3 damages case. Entergy Louisiana received payment from the U.S. Treasury in June 2020. The effects of recording the judgment were reductions to plant, nuclear fuel expense, and other operation and maintenance expense. The Waterford 3 damages awarded included $20 million related to costs previously recorded as nuclear fuel expense, $8 million related to costs previously recorded as other operation and maintenance expenses, and $5 million in costs previously capitalized.
In October 2020 the U.S. Court of Federal Claims issued a final judgment in the amount of $40.5 million in favor of System Energy and against the DOE in the third round Grand Gulf damages case. System Energy received payment from the U.S. Treasury in December 2020. The effects of recording the judgment were reductions to plant, nuclear fuel expense, and other operation and maintenance expense. The amounts of Grand Gulf damages awarded related to System Energy’s 90% ownership of Grand Gulf included $5 million related to costs previously capitalized, $21 million related to costs previously recorded as nuclear fuel expense, and $10 million related to costs previously recorded as other operation and maintenance expense.
In January 2021 the U.S. Court of Federal Clams issued a final judgment in the amount of $23.1 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 expense, and taxes other than income taxes. The Palisades damages awarded included $15.7 million related to costs previously capitalized, $7.1 million related to costs previously recorded as other operation and maintenance expenses, and $0.3 million related to costs previously recorded as taxes other than income taxes. Of the $15.7 million previously capitalized, Entergy recorded $9.1 million as a reduction to previously-recorded depreciation expense.
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 $450 million 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.Within the Secondary Financial Protection level, 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 $137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.101 billion). This retrospective
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premium is payable at a rate currently set at approximately $21 million per year per incident per nuclear power reactor.
3.In the event that one or more acts of terrorism cause a nuclear power plant accident, which results in third-party damages – off-site property and environmental damage, off-site bodily injury, and on-site third-party bodily injury (i.e. contractors), the primary level provided by ANI combined with the Secondary Financial Protection would provide approximately $14 billion in coverage. The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to $100 billion in coverage in excess of existing coverage for a terrorist event. Under current law, the Terrorism Risk Insurance Act extends through 2027.
The shutdown Big Rock Point facility maintains its NRC site specific statutory nuclear liability insurance requirement limit of $44.4 million.
Currently, 97 nuclear reactors are participating in the Secondary Financial Protection program that provides approximately $13 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.
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). The Entergy Wholesale Commodities segment includes the ownership, operation, and decommissioning of three nuclear power reactors and the ownership of the shutdown Indian Point 1 reactor and Big Rock Point facility. Indian Point 2 was shutdown in April 2020 and has been defueled successfully as of May 2020. Indian Point 3 and Palisades are scheduled for shutdown in April 2021 and May 2022, respectively. The Entergy Wholesale Commodities segment previously included two nuclear power reactors that were sold in 2019. Vermont Yankee was sold in January 2019 and Pilgrim was sold in August 2019.
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 and Entergy Wholesale Commodity plants are in compliance with the financial protection requirements of the NRC.
The Utility plants’ (ANO 1 and 2, Grand Gulf, River Bend, and Waterford 3) property damage insurance limits are $1.5 billion per occurrence at each plant with an additional $100 million per nuclear property occurrence that is shared among the plants. 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 wind 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.
The Entergy Wholesale Commodities’ plants (Palisades, Indian Point 2, Indian Point 3, and Big Rock Point) have property damage insurance limits as follows: Big Rock Point - $50 million per occurrence; Palisades - $1.115 billion per occurrence; and Indian Point - $1.06 billion per occurrence. For losses that are considered non-nuclear in nature, the property damage insurance limit at Palisades and Indian Point is $500 million. Property damage from wind and flood at Indian Point 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, and property damage from earth movement at Indian Point is excluded. Property damage from wind, flood, and earth movement at Palisades includes a deductible
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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 wind, flood, and earth movement at Big Rock Point 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 $14 million.
The valuation basis of the insured property at Palisades and Indian Point have been changed from replacement cost to actual cash value, given the sites’ ages, anticipated ownership horizon and/or shutdown status.
In addition, Waterford 3 and Grand Gulf are also covered under NEIL’s Accidental Outage Coverage program. Due to Entergy’s gradual exit from the merchant/wholesale power business, Entergy no longer purchases Accidental Outage Coverage for its non-regulated, non-generation assets. 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 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; then
•80% of the weekly indemnity for each week for the second payment period of 52 weeks; and thereafter
•80% of the weekly indemnity for an additional 58 weeks for the third and final payment period.
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, 2020, the maximum amounts of such possible assessments per occurrence were as follows:
| Assessments | |||||
| (In Millions) | |||||
| Utility: | |||||
| Entergy Arkansas | $29.6 | ||||
| Entergy Louisiana | $51.8 | ||||
| Entergy Mississippi | $0.11 | ||||
| Entergy New Orleans | $0.11 | ||||
| Entergy Texas | N/A | ||||
| System Energy | $22.4 | ||||
| Entergy Wholesale Commodities | $— | ||||
Potential assessments for the Entergy Wholesale Commodities plants are covered by insurance obtained through NEIL’s reinsurers.
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 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.
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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 $300 million in terrorism insurance coverage for its conventional property. The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to $100 billion in coverage in excess of existing coverage for a terrorist event. Under current law, the Terrorism Risk Insurance Act extends through 2027.
Employment and Labor-related Proceedings
The Registrant Subsidiaries and other Entergy subsidiaries 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 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 plans. Entergy and the Registrant Subsidiaries 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 Utility operating companies.
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 200 lawsuits involving approximately 350 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.
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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. The agreement will remain in effect until terminated by the parties and the termination is approved by the FERC, most likely upon Grand Gulf’s retirement from service. 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 2020 under the agreement were approximately $15.7 million for Entergy Arkansas, $6.3 million for Entergy Louisiana, $13.8 million for Entergy Mississippi, and $7.6 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.
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 an amount sufficient to amortize the cost of Grand Gulf 2 over 27 years (See Reallocation Agreement terms below) and 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 obligations. Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Accordingly, no payments under the Availability Agreement have ever been required. 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 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.
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. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (Entergy Louisiana-26.23%, Entergy Mississippi-43.97%, and Entergy New Orleans-29.80%) under the terms of the Reallocation Agreement. 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
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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.
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:
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
| Entergy Arkansas | $212.6 | $168.9 | |||||||||
| Entergy Louisiana | $302.5 | ($2.4) | |||||||||
| Entergy Mississippi | $107.3 | $80.8 | |||||||||
| Entergy New Orleans | $63.2 | $52.9 | |||||||||
| Entergy Texas | $115.3 | $42.5 | |||||||||
| System Energy | $92.9 | $75.9 | |||||||||
As of December 31, 2020 the regulatory asset for removal costs for the Utility operating companies includes amounts related to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration costs.
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The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2020 and 2019 by Entergy were as follows:
| Liabilities as of December 31, 2019 | Accretion | Spending | Liabilities as of December 31, 2020 | ||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||
| Entergy | $6,159.2 | $394.6 | ($84.3) | $6,469.5 | |||||||||||||||||||
| Utility | |||||||||||||||||||||||
| Entergy Arkansas | 1,242.6 | 73.3 | (1.7) | 1,314.2 | |||||||||||||||||||
| Entergy Louisiana | 1,497.3 | 76.0 | — | 1,573.3 | |||||||||||||||||||
| Entergy Mississippi | 9.7 | 0.6 | (0.5) | 9.8 | |||||||||||||||||||
| Entergy New Orleans | 3.5 | 0.3 | — | 3.8 | |||||||||||||||||||
| Entergy Texas | 7.6 | 0.5 | — | 8.1 | |||||||||||||||||||
| System Energy | 931.7 | 37.2 | — | 968.9 | |||||||||||||||||||
| Entergy Wholesale Commodities | |||||||||||||||||||||||
| Big Rock Point | 40.3 | 3.3 | (2.5) | 41.1 | |||||||||||||||||||
| Indian Point 1 | 238.6 | 20.4 | (12.4) | 246.6 | |||||||||||||||||||
| Indian Point 2 | 829.0 | 69.4 | (58.6) | 839.8 | |||||||||||||||||||
| Indian Point 3 | 808.4 | 67.4 | (6.4) | 869.4 | |||||||||||||||||||
| Palisades | 549.8 | 46.4 | (2.1) | 594.1 | |||||||||||||||||||
| Other (a) | 0.5 | — | — | 0.5 | |||||||||||||||||||
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| Liabilities as of December 31, 2018 | Accretion | Change in Cash Flow Estimate | Spending | Dispositions | Liabilities as of December 31, 2019 | ||||||||||||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||||||||||||||
| Entergy | $6,923.4 | $414.0 | $273.7 | ($45.6) | ($1,406.3) | $6,159.2 | |||||||||||||||||||||||||||||
| Utility | |||||||||||||||||||||||||||||||||||
| Entergy Arkansas | 1,048.4 | 68.0 | 126.2 | — | — | 1,242.6 | |||||||||||||||||||||||||||||
| Entergy Louisiana | 1,280.3 | 69.5 | 147.5 | — | — | 1,497.3 | |||||||||||||||||||||||||||||
| Entergy Mississippi | 9.2 | 0.5 | — | — | — | 9.7 | |||||||||||||||||||||||||||||
| Entergy New Orleans | 3.3 | 0.2 | — | — | — | 3.5 | |||||||||||||||||||||||||||||
| Entergy Texas | 7.2 | 0.4 | — | — | — | 7.6 | |||||||||||||||||||||||||||||
| System Energy | 896.0 | 35.7 | — | — | — | 931.7 | |||||||||||||||||||||||||||||
| Entergy Wholesale Commodities | |||||||||||||||||||||||||||||||||||
| Big Rock Point | 39.7 | 3.2 | — | (2.6) | — | 40.3 | |||||||||||||||||||||||||||||
| Indian Point 1 | 227.9 | 19.5 | — | (8.8) | — | 238.6 | |||||||||||||||||||||||||||||
| Indian Point 2 | 768.0 | 65.5 | — | (4.5) | — | 829.0 | |||||||||||||||||||||||||||||
| Indian Point 3 | 750.6 | 62.5 | — | (4.7) | — | 808.4 | |||||||||||||||||||||||||||||
| Palisades | 508.0 | 42.9 | — | (1.1) | — | 549.8 | |||||||||||||||||||||||||||||
| Pilgrim | 816.5 | 44.1 | — | (23.9) | (836.7) | (b) | — | ||||||||||||||||||||||||||||
| Vermont Yankee | 567.9 | 1.7 | — | — | (569.6) | (b) | — | ||||||||||||||||||||||||||||
| Other (a) | 0.4 | 0.1 | — | — | — | 0.5 | |||||||||||||||||||||||||||||
(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 Pilgrim plant to Holtec International in August 2019 and the sale of the Vermont Yankee plant to NorthStar in January 2019.
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. As described below, during 2019 and 2018, Entergy updated decommissioning cost estimates for certain nuclear power plants. Entergy did not update decommissioning cost estimates in 2020.
Utility
In the first quarter 2019, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and ANO 2 as a result of a revised decommissioning cost study. The revised estimates resulted in a $126.2 million increase in its decommissioning cost liabilities, along with corresponding increases in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.
In the second quarter 2019, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $147.5 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.
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Entergy Wholesale Commodities
Pilgrim
Entergy Nuclear Generation Company filed its Post-Shutdown Decommissioning Activities report (PSDAR) with the NRC in the fourth quarter 2018 for the Pilgrim plant in anticipation of its May 2019 shutdown. As part of the development of the PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2018. The revised estimate resulted in a $117.5 million increase in the decommissioning cost liability and a corresponding impairment charge.
Vermont Yankee
In the fourth quarter 2018, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Vermont Yankee. The revised estimate resulted in a $293 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The revision was prompted by the progress of the Vermont Yankee sales transaction, which is described in Note 14 to the financial statements. Entergy accordingly evaluated the Vermont Yankee asset retirement obligation in light of the terms of the sale transaction, upon determining that Vermont Yankee was in held for sale status. Based on the terms of the sales agreement, which include Entergy receiving a note receivable from the purchaser, Entergy determined that $165 million of the asset retirement cost was impaired, and it was accordingly written down in the fourth quarter 2018. The Vermont Yankee plant was sold to NorthStar in January 2019.
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 June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contained two primary regulatory options: (1) regulating CCRs destined for disposal in landfills or received (including stored) in surface impoundments as so-called “special wastes” under the hazardous waste program of Resource Conservation and Recovery Act (RCRA) Subtitle C; or (2) regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes under Subtitle D of RCRA. Under both options, CCRs that are beneficially reused in certain processes would remain excluded from hazardous waste regulation. In April 2015 the EPA published the final CCR rule with the material being regulated under the second scenario presented above - as non-hazardous wastes regulated under RCRA 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. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed for CCR that cannot be transferred for beneficial reuse. In December 2016 the Water Infrastructure Improvements for the Nation Act (WIIN Act) was signed into law, which authorizes states to regulate coal ash rather than leaving primary enforcement to citizen suit actions. States may submit to the EPA proposals for permit programs.
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NOTE 10. LEASES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Entergy implemented ASU 2016-02, “Leases (Topic 842),” effective January 1, 2019. The ASU’s core principle is that “a lessee should recognize the assets and liabilities that arise from leases.” The ASU considers that “all leases create an asset and a liability,” and accordingly requires recording the assets and liabilities related to all leases with a term greater than 12 months. Concurrent with the implementation of ASU 2016-02, Entergy implemented ASU 2018-01, “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842,” which provided Entergy the option to elect not to evaluate existing land easements that are not currently accounted for as leases under the previous lease standard, and ASU 2018-11, “Leases (Topic 842): Targeted Improvements,” which intended to simplify the transition requirement giving Entergy the option to apply the transition provisions of the new standard at the date of adoption instead of at the earliest comparative period. In implementing these ASUs, Entergy elected the options provided in both ASU 2018-01 and ASU 2018-11. This accounting was applied to all lease agreements using the modified retrospective method, which required an adjustment to retained earnings for the cumulative effect of adopting the standard as of the effective date, and when implemented with ASU 2018-11, allowed Entergy to recognize the leased assets and liabilities on its balance sheet beginning on January 1, 2019 without restating prior periods. In adopting the standard in January 2019, Entergy recognized right-of-use assets and corresponding lease liabilities totaling approximately $263 million, including $59 million for Entergy Arkansas, $51 million for Entergy Louisiana, $26 million for Entergy Mississippi, $7 million for Entergy New Orleans, and $16 million for Entergy Texas. Implementation of the standards had no material effect on consolidated net income; therefore, no adjustment to retained earnings was recorded. The adoption of the standards had no effect on cash flows.
General
As of December 31, 2020 and 2019, 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 60 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, 2020 and 2019:
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| Operating lease cost | $67,471 | $63,566 | ||||||||||||
| Finance lease cost: | ||||||||||||||
| Amortization of right-of-use assets | $12,180 | $16,048 | ||||||||||||
| Interest on lease liabilities | $2,884 | $3,667 | ||||||||||||
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Of the lease costs disclosed above, Entergy had $759 thousand and $43 thousand in short-term leases costs for the years ended December 31, 2020 and 2019, respectively.
The lease costs disclosed above materially approximate the cash flows used by Entergy for leases with all costs included within operating activities on the Consolidated Statements of Cash Flows, except for the finance lease costs which are included in financing activities.
The Registrant Subsidiaries incurred the following lease costs for the year ended December 31, 2020:
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||
| Operating lease cost | $14,344 | $13,944 | $6,584 | $1,443 | $4,870 | ||||||||||||||||||||||||
| Finance lease cost: | |||||||||||||||||||||||||||||
| Amortization of right-of-use assets | $2,693 | $4,097 | $1,627 | $712 | $1,340 | ||||||||||||||||||||||||
| Interest on lease liabilities | $408 | $597 | $254 | $120 | $196 | ||||||||||||||||||||||||
Of the lease costs disclosed above, Entergy Arkansas had $43 thousand and Entergy Louisiana had $719 thousand in short-term lease costs for the year ended December 31, 2020.
The lease costs 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.
The Registrant Subsidiaries incurred the following lease costs for the year ended December 31, 2019:
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||
| Operating lease cost | $13,213 | $11,975 | $6,927 | $1,406 | $4,259 | ||||||||||||||||||||||||
| Finance lease cost: | |||||||||||||||||||||||||||||
| Amortization of right-of-use assets | $3,643 | $5,940 | $2,097 | $1,042 | $1,568 | ||||||||||||||||||||||||
| Interest on lease liabilities | $594 | $895 | $353 | $168 | $241 | ||||||||||||||||||||||||
Of the lease costs disclosed above, Entergy Louisiana had $43 thousand in short-term lease costs for the year ended December 31, 2019.
The lease costs 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 sheet at December 31, 2020 and 2019 are $230 million and $234 million related to operating leases, respectively, and $60 million and $61 million related to finance leases, respectively.
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Included within Utility Plant on the Registrant Subsidiaries’ respective balance sheets at December 31, 2020 and 2019 are the following amounts:
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||
| 2020 | |||||||||||||||||||||||||||||
| Operating leases | $55,840 | $43,189 | $16,538 | $5,222 | $14,738 | ||||||||||||||||||||||||
| Finance leases | $12,447 | $16,425 | $7,452 | $3,428 | $5,719 | ||||||||||||||||||||||||
| 2019 | |||||||||||||||||||||||||||||
| Operating leases | $52,317 | $36,034 | $16,900 | $3,878 | $14,020 | ||||||||||||||||||||||||
| Finance leases | $11,216 | $17,209 | $6,869 | $3,291 | $5,273 | ||||||||||||||||||||||||
The following lease-related liabilities are recorded within the respective Other lines on Entergy’s consolidated balance sheet as of December 31, 2020 and 2019:
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| Current liabilities: | ||||||||||||||
| Operating leases | $59,004 | $52,678 | ||||||||||||
| Finance leases | $11,921 | $11,413 | ||||||||||||
| Non-current liabilities: | ||||||||||||||
| Operating leases | $170,980 | $181,339 | ||||||||||||
| Finance leases | $52,803 | $53,396 | ||||||||||||
The following lease-related liabilities are recorded within the respective Other lines on the Registrant Subsidiaries’ respective balance sheets at December 31, 2020:
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||
| Current liabilities: | |||||||||||||||||||||||||||||
| Operating leases | $11,942 | $11,934 | $5,738 | $1,406 | $4,277 | ||||||||||||||||||||||||
| Finance leases | $2,660 | $3,821 | $1,644 | $686 | $1,327 | ||||||||||||||||||||||||
| Non-current liabilities: | |||||||||||||||||||||||||||||
| Operating leases | $43,914 | $31,260 | $10,867 | $3,819 | $10,469 | ||||||||||||||||||||||||
| Finance leases | $9,788 | $12,603 | $5,808 | $2,741 | $4,392 | ||||||||||||||||||||||||
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The following lease-related liabilities are recorded within the respective Other lines on the Registrant Subsidiaries’ respective balance sheets at December 31, 2019:
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||
| Current liabilities: | |||||||||||||||||||||||||||||
| Operating leases | $11,443 | $10,331 | $5,633 | $1,134 | $3,698 | ||||||||||||||||||||||||
| Finance leases | $2,442 | $3,919 | $1,487 | $647 | $1,222 | ||||||||||||||||||||||||
| Non-current liabilities: | |||||||||||||||||||||||||||||
| Operating leases | $40,880 | $25,743 | $11,232 | $2,746 | $10,364 | ||||||||||||||||||||||||
| Finance leases | $8,768 | $13,376 | $5,382 | $2,644 | $4,009 | ||||||||||||||||||||||||
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, 2020 and 2019:
| 2020 | 2019 | |||||||||||||
| Weighted average remaining lease terms: | ||||||||||||||
| Operating leases | 4.82 | 5.14 | ||||||||||||
| Finance leases | 6.34 | 6.69 | ||||||||||||
| Weighted average discount rate: | ||||||||||||||
| Operating leases | 3.58 | % | 3.86 | % | ||||||||||
| Finance leases | 4.42 | % | 4.60 | % | ||||||||||
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, 2020:
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||
| Weighted average remaining lease terms: | |||||||||||||||||||||||||||||
| Operating leases | 5.74 | 4.72 | 5.30 | 5.78 | 4.30 | ||||||||||||||||||||||||
| Finance leases | 5.60 | 5.20 | 5.44 | 5.69 | 5.39 | ||||||||||||||||||||||||
| Weighted average discount rate: | |||||||||||||||||||||||||||||
| Operating leases | 3.34 | % | 3.11 | % | 3.43 | % | 3.09 | % | 3.07 | % | |||||||||||||||||||
| Finance leases | 3.18 | % | 3.33 | % | 3.22 | % | 3.35 | % | 3.22 | % | |||||||||||||||||||
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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, 2019:
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||
| Weighted average remaining lease terms: | |||||||||||||||||||||||||||||
| Operating leases | 5.84 | 4.33 | 5.04 | 5.62 | 4.54 | ||||||||||||||||||||||||
| Finance leases | 5.43 | 5.24 | 5.32 | 5.93 | 5.12 | ||||||||||||||||||||||||
| Weighted average discount rate: | |||||||||||||||||||||||||||||
| Operating leases | 3.67 | % | 3.65 | % | 3.75 | % | 3.88 | % | 3.73 | % | |||||||||||||||||||
| Finance leases | 3.68 | % | 3.65 | % | 3.67 | % | 3.74 | % | 3.82 | % | |||||||||||||||||||
Maturity of the lease liabilities for Entergy as of December 31, 2020 are as follows:
| Year | Operating Leases | Finance Leases | ||||||||||||
| (In Thousands) | ||||||||||||||
| 2021 | $65,693 | $14,436 | ||||||||||||
| 2022 | 57,497 | 13,175 | ||||||||||||
| 2023 | 46,540 | 12,114 | ||||||||||||
| 2024 | 38,525 | 10,013 | ||||||||||||
| 2025 | 20,269 | 8,225 | ||||||||||||
| Years thereafter | 20,999 | 16,436 | ||||||||||||
| Minimum lease payments | 249,523 | 74,399 | ||||||||||||
| Less: amount representing interest | 19,539 | 9,675 | ||||||||||||
| Present value of net minimum lease payments | $229,984 | $64,724 | ||||||||||||
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Maturity of the lease liabilities for the Registrant Subsidiaries as of December 31, 2020 are as follows:
Operating Leases
| Year | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||
| 2021 | $13,527 | $13,076 | $6,183 | $1,533 | $4,650 | |||||||||||||||||||||||||||
| 2022 | 11,547 | 10,581 | 4,890 | 1,256 | 3,705 | |||||||||||||||||||||||||||
| 2023 | 9,868 | 8,624 | 2,788 | 1,028 | 3,299 | |||||||||||||||||||||||||||
| 2024 | 8,524 | 6,466 | 1,749 | 773 | 2,313 | |||||||||||||||||||||||||||
| 2025 | 6,993 | 3,693 | 872 | 406 | 1,037 | |||||||||||||||||||||||||||
| Years thereafter | 10,737 | 3,717 | 1,927 | 694 | 657 | |||||||||||||||||||||||||||
| Minimum lease payments | 61,196 | 46,157 | 18,409 | 5,690 | 15,661 | |||||||||||||||||||||||||||
| Less: amount representing interest | 5,340 | 2,963 | 1,804 | 465 | 915 | |||||||||||||||||||||||||||
| Present value of net minimum lease payments | $55,856 | $43,194 | $16,605 | $5,225 | $14,746 | |||||||||||||||||||||||||||
Finance Leases
| Year | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||
| 2021 | $3,013 | $4,305 | $1,857 | $790 | $1,490 | |||||||||||||||||||||||||||
| 2022 | 2,712 | 3,856 | 1,665 | 729 | 1,258 | |||||||||||||||||||||||||||
| 2023 | 2,441 | 3,437 | 1,483 | 684 | 1,119 | |||||||||||||||||||||||||||
| 2024 | 1,978 | 2,493 | 1,156 | 561 | 882 | |||||||||||||||||||||||||||
| 2025 | 1,498 | 1,783 | 885 | 456 | 677 | |||||||||||||||||||||||||||
| Years thereafter | 1,843 | 1,893 | 1,027 | 523 | 759 | |||||||||||||||||||||||||||
| Minimum lease payments | 13,485 | 17,767 | 8,073 | 3,743 | 6,185 | |||||||||||||||||||||||||||
| Less: amount representing interest | 1,037 | 1,343 | 621 | 316 | 467 | |||||||||||||||||||||||||||
| Present value of net minimum lease payments | $12,448 | $16,424 | $7,452 | $3,427 | $5,718 | |||||||||||||||||||||||||||
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, fuel storage agreements, and purchased power agreements and to allocate the contract consideration to both lease and non-lease components for real estate leases.
Following are the relevant lease disclosures from Note 10 to the financial statements in the Form 10-K for the year ended December 31, 2018.
Total 2018 rental expenses for all leases (excluding power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf sale and leaseback transaction) amounted to $47.8 million for Entergy.
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Total 2018 rental expenses for leases (excluding power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf sale and leaseback transaction) amounted to $6.2 million for Entergy Arkansas, $20.2 million for Entergy Louisiana, $4.6 million for Entergy Mississippi, $2.5 million for Entergy New Orleans, $3.1 million for Entergy Texas, and $1.9 million for System Energy.
In addition to rental expense, railcar operating lease payments and oil tank facilities lease payments are recorded in fuel expense in accordance with regulatory treatment. Railcar operating lease payments were $2.8 million in 2018 for Entergy Arkansas and $0.4 million in 2018 for Entergy Louisiana. Oil tank facilities lease payments for Entergy Mississippi were $0.1 million in 2018.
Total capacity expense under the power purchase agreement accounted for as an operating lease at Entergy Texas was $30.5 million in 2018.
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 eight defined benefit qualified pension plans covering substantially all employees. 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, the Entergy Corporation Retirement Plan III, and the Entergy Corporation Retirement Plan IV for Bargaining Employees are non-contributory final average pay plans and provide pension benefits that are based on employees’ credited service and compensation during employment. Non-bargaining employees whose most recent date of hire is after June 30, 2014 but before January 1, 2021 participate in the Entergy Corporation Cash Balance Plan for Non-Bargaining Employees (Non-Bargaining Cash Balance Plan). Certain bargaining employees hired or rehired after June 30, 2014, or such later date provided for in their applicable collective bargaining agreements, participate in the Entergy Corporation Cash Balance Plan for Bargaining Employees (Bargaining Cash Balance Plan). The Registrant Subsidiaries participate in these four plans: Non-Bargaining Plan I, Bargaining Plan I, Non-Bargaining Cash Balance Plan, and Bargaining Cash Balance Plan.
The assets of the six final average pay defined benefit qualified pension plans are held in a master trust established by Entergy, and the assets of the two cash balance pension plans are held in a second master trust established by Entergy. Each pension plan has an undivided beneficial interest in each of the investment accounts in its respective master trust that is maintained by a trustee. Use of the master trusts 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 trusts 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 each trust to the various participating pension plans in that particular trust. The fair value of the trusts’ assets is determined by the trustee and certain investment managers. For each trust, 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 trusts 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.
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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 2020, 2019, and 2018 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Thousands) | |||||||||||||||||
Net periodic pension cost: | |||||||||||||||||
Service cost - benefits earned during the period | $161,487 | $134,193 | $155,010 | ||||||||||||||
Interest cost on projected benefit obligation | 239,614 | 293,114 | 267,415 | ||||||||||||||
Expected return on assets | (414,273) | (414,947) | (442,142) | ||||||||||||||
Amortization of prior service cost | — | — | 398 | ||||||||||||||
Recognized net loss | 350,010 | 241,117 | 274,104 | ||||||||||||||
Settlement charges | 36,946 | 23,492 | 828 | ||||||||||||||
Net periodic pension costs | $373,784 | $276,969 | $255,613 | ||||||||||||||
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | |||||||||||||||||
Arising this period: | |||||||||||||||||
Net loss | $483,653 | $614,600 | $394,951 | ||||||||||||||
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | |||||||||||||||||
Amortization of prior service cost | — | — | (398) | ||||||||||||||
Amortization of net loss | (358,473) | (241,117) | (274,104) | ||||||||||||||
Settlement charge | (36,946) | (23,492) | (828) | ||||||||||||||
Total | $88,234 | $349,991 | $119,621 | ||||||||||||||
Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax) | $462,018 | $626,960 | $375,234 | ||||||||||||||
164
The Registrant Subsidiaries’ total 2020, 2019, and 2018 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, for their employees included the following components:
| 2020 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Net periodic pension cost: | ||||||||||||||||||||||||||||||||||||||
| Service cost - benefits earned during the period | $26,329 | $35,158 | $8,060 | $2,654 | $6,116 | $7,883 | ||||||||||||||||||||||||||||||||
| Interest cost on projected benefit obligation | 44,165 | 50,432 | 12,922 | 5,825 | 10,731 | 11,006 | ||||||||||||||||||||||||||||||||
| Expected return on assets | (78,187) | (89,691) | (23,147) | (10,509) | (21,951) | (18,757) | ||||||||||||||||||||||||||||||||
| Recognized net loss | 68,338 | 66,640 | 18,983 | 8,018 | 13,173 | 17,104 | ||||||||||||||||||||||||||||||||
| Settlement charges | 21,078 | 8,109 | 3,366 | — | 4,289 | 105 | ||||||||||||||||||||||||||||||||
| Net pension cost | $81,723 | $70,648 | $20,184 | $5,988 | $12,358 | $17,341 | ||||||||||||||||||||||||||||||||
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | ||||||||||||||||||||||||||||||||||||||
| Arising this period: | ||||||||||||||||||||||||||||||||||||||
| Net loss | $106,178 | $90,064 | $36,899 | $8,148 | $13,379 | $35,403 | ||||||||||||||||||||||||||||||||
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | ||||||||||||||||||||||||||||||||||||||
| Amortization of net loss | (69,713) | (68,248) | (19,393) | (8,213) | (13,564) | (17,434) | ||||||||||||||||||||||||||||||||
| Settlement charge | (21,078) | (8,109) | (3,366) | — | (4,289) | (105) | ||||||||||||||||||||||||||||||||
| Total | $15,387 | $13,707 | $14,140 | ($65) | ($4,474) | $17,864 | ||||||||||||||||||||||||||||||||
| Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax) | $97,110 | $84,355 | $34,324 | $5,923 | $7,884 | $35,205 | ||||||||||||||||||||||||||||||||
165
| 2019 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
Net periodic pension cost: | ||||||||||||||||||||||||||||||||||||||
Service cost - benefits earned during the period | $21,043 | $29,137 | $6,516 | $2,274 | $5,401 | $6,199 | ||||||||||||||||||||||||||||||||
Interest cost on projected benefit obligation | 56,701 | 63,529 | 16,272 | 7,495 | 14,451 | 13,456 | ||||||||||||||||||||||||||||||||
Expected return on assets | (80,705) | (90,607) | (23,873) | (10,785) | (23,447) | (18,710) | ||||||||||||||||||||||||||||||||
Recognized net loss | 47,361 | 46,571 | 12,416 | 6,117 | 9,335 | 11,400 | ||||||||||||||||||||||||||||||||
Net pension cost | $44,400 | $48,630 | $11,331 | $5,101 | $5,740 | $12,345 | ||||||||||||||||||||||||||||||||
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | ||||||||||||||||||||||||||||||||||||||
Arising this period: | ||||||||||||||||||||||||||||||||||||||
| Net loss | $118,898 | $99,346 | $41,088 | $6,531 | $10,869 | $36,711 | ||||||||||||||||||||||||||||||||
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | ||||||||||||||||||||||||||||||||||||||
Amortization of net loss | (47,361) | (46,571) | (12,416) | (6,117) | (9,335) | (11,400) | ||||||||||||||||||||||||||||||||
Total | $71,537 | $52,775 | $28,672 | $414 | $1,534 | $25,311 | ||||||||||||||||||||||||||||||||
Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax) | $115,937 | $101,405 | $40,003 | $5,515 | $7,274 | $37,656 | ||||||||||||||||||||||||||||||||
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| 2018 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
Net periodic pension cost: | ||||||||||||||||||||||||||||||||||||||
Service cost - benefits earned during the period | $24,757 | $33,783 | $7,286 | $2,693 | $6,356 | $7,102 | ||||||||||||||||||||||||||||||||
Interest cost on projected benefit obligation | 52,017 | 59,761 | 15,075 | 7,253 | 13,390 | 12,907 | ||||||||||||||||||||||||||||||||
Expected return on assets | (87,404) | (99,236) | (26,007) | (11,973) | (26,091) | (19,963) | ||||||||||||||||||||||||||||||||
Recognized net loss | 53,650 | 57,800 | 14,438 | 7,816 | 10,503 | 14,859 | ||||||||||||||||||||||||||||||||
Net pension cost | $43,020 | $52,108 | $10,792 | $5,789 | $4,158 | $14,905 | ||||||||||||||||||||||||||||||||
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | ||||||||||||||||||||||||||||||||||||||
Arising this period: | ||||||||||||||||||||||||||||||||||||||
| Net (gain)/loss | $74,570 | $41,642 | $19,244 | $2,351 | $24,121 | ($2,359) | ||||||||||||||||||||||||||||||||
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | ||||||||||||||||||||||||||||||||||||||
Amortization of net loss | (53,650) | (57,800) | (14,438) | (7,816) | (10,503) | (14,859) | ||||||||||||||||||||||||||||||||
Total | $20,920 | ($16,158) | $4,806 | ($5,465) | $13,618 | ($17,218) | ||||||||||||||||||||||||||||||||
Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax) | $63,940 | $35,950 | $15,598 | $324 | $17,776 | ($2,313) | ||||||||||||||||||||||||||||||||
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Qualified Pension Obligations, Plan Assets, Funded Status, Amounts Recognized in the Balance Sheet
Qualified pension obligations, plan assets, funded status, amounts recognized in the Consolidated Balance Sheets for Entergy Corporation and its Subsidiaries as of December 31, 2020 and 2019 are as follows:
| 2020 | 2019 | ||||||||||
| (In Thousands) | |||||||||||
Change in Projected Benefit Obligation (PBO) | |||||||||||
Balance at January 1 | $8,406,203 | $7,404,917 | |||||||||
Service cost | 161,487 | 134,193 | |||||||||
Interest cost | 239,614 | 293,114 | |||||||||
| Actuarial loss | 969,609 | 1,292,767 | |||||||||
Benefits paid (including settlement lump sum benefit payments of ($84,754) in 2020 and ($68,203) in 2019) | (633,261) | (718,788) | |||||||||
Balance at December 31 | $9,143,652 | $8,406,203 | |||||||||
Change in Plan Assets | |||||||||||
Fair value of assets at January 1 | $6,271,160 | $5,497,415 | |||||||||
Actual return on plan assets | 900,229 | 1,093,114 | |||||||||
Employer contributions | 316,298 | 399,419 | |||||||||
| Benefits paid (including settlement lump sum benefit payments of ($84,754) in 2020 and ($68,203) in 2019) | (633,261) | (718,788) | |||||||||
Fair value of assets at December 31 | $6,854,426 | $6,271,160 | |||||||||
Funded status | ($2,289,226) | ($2,135,043) | |||||||||
Amount recognized in the balance sheet | |||||||||||
Non-current liabilities | ($2,289,226) | ($2,135,043) | |||||||||
Amount recognized as a regulatory asset | |||||||||||
Net loss | $2,926,670 | $2,831,408 | |||||||||
Amount recognized as AOCI (before tax) | |||||||||||
Net loss | $726,010 | $724,575 | |||||||||
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Qualified pension obligations, plan assets, funded status, amounts recognized in the Balance Sheets for the Registrant Subsidiaries as of December 31, 2020 and 2019 are as follows:
| 2020 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Change in Projected Benefit Obligation (PBO) | ||||||||||||||||||||||||||||||||||||||
| Balance at January 1 | $1,615,084 | $1,784,474 | $471,510 | $206,962 | $396,764 | $393,607 | ||||||||||||||||||||||||||||||||
| Service cost | 26,329 | 35,158 | 8,060 | 2,654 | 6,116 | 7,883 | ||||||||||||||||||||||||||||||||
| Interest cost | 44,165 | 50,432 | 12,922 | 5,825 | 10,731 | 11,006 | ||||||||||||||||||||||||||||||||
| Actuarial loss | 196,755 | 196,032 | 62,564 | 20,535 | 37,579 | 57,574 | ||||||||||||||||||||||||||||||||
| Benefits paid (a) | (142,951) | (138,825) | (44,947) | (15,689) | (40,526) | (28,922) | ||||||||||||||||||||||||||||||||
| Balance at December 31 | $1,739,382 | $1,927,271 | $510,109 | $220,287 | $410,664 | $441,148 | ||||||||||||||||||||||||||||||||
| Change in Plan Assets | ||||||||||||||||||||||||||||||||||||||
| Fair value of assets at January 1 | $1,200,035 | $1,364,030 | $354,928 | $160,777 | $339,126 | $282,668 | ||||||||||||||||||||||||||||||||
| Actual return on plan assets | 168,764 | 195,658 | 48,812 | 22,896 | 46,151 | 40,927 | ||||||||||||||||||||||||||||||||
| Employer contributions | 60,008 | 55,443 | 12,601 | 4,567 | 4,997 | 16,145 | ||||||||||||||||||||||||||||||||
| Benefits paid (a) | (142,951) | (138,825) | (44,947) | (15,689) | (40,526) | (28,922) | ||||||||||||||||||||||||||||||||
| Fair value of assets at December 31 | $1,285,856 | $1,476,306 | $371,394 | $172,551 | $349,748 | $310,818 | ||||||||||||||||||||||||||||||||
| Funded status | ($453,526) | ($450,965) | ($138,715) | ($47,736) | ($60,916) | ($130,330) | ||||||||||||||||||||||||||||||||
| Amounts recognized in the balance sheet (funded status) | ||||||||||||||||||||||||||||||||||||||
| Non-current liabilities | ($453,526) | ($450,965) | ($138,715) | ($47,736) | ($60,916) | ($130,330) | ||||||||||||||||||||||||||||||||
| Amounts recognized as regulatory asset | ||||||||||||||||||||||||||||||||||||||
| Net loss | $816,002 | $766,099 | $239,904 | $91,991 | $156,480 | $212,062 | ||||||||||||||||||||||||||||||||
| Amounts recognized as AOCI (before tax) | ||||||||||||||||||||||||||||||||||||||
| Net loss | $— | $31,921 | $— | $— | $— | $— | ||||||||||||||||||||||||||||||||
(a) Including settlement lump sum benefit payments of ($48.4) million at Entergy Arkansas, ($18.6) million at Entergy Louisiana, ($7.7) million at Entergy Mississippi, ($9.8) million at Entergy Texas, and ($236) thousand at System Energy.
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| 2019 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
Change in Projected Benefit Obligation (PBO) | ||||||||||||||||||||||||||||||||||||||
Balance at January 1 | $1,443,808 | $1,599,916 | $414,089 | $191,190 | $369,604 | $339,034 | ||||||||||||||||||||||||||||||||
Service cost | 21,043 | 29,137 | 6,516 | 2,274 | 5,401 | 6,199 | ||||||||||||||||||||||||||||||||
Interest cost | 56,701 | 63,529 | 16,272 | 7,495 | 14,451 | 13,456 | ||||||||||||||||||||||||||||||||
| Actuarial loss | 248,213 | 248,509 | 79,453 | 24,299 | 49,235 | 66,460 | ||||||||||||||||||||||||||||||||
Benefits paid | (154,681) | (156,617) | (44,820) | (18,296) | (41,927) | (31,542) | ||||||||||||||||||||||||||||||||
Balance at December 31 | $1,615,084 | $1,784,474 | $471,510 | $206,962 | $396,764 | $393,607 | ||||||||||||||||||||||||||||||||
Change in Plan Assets | ||||||||||||||||||||||||||||||||||||||
Fair value of assets at January 1 | $1,068,842 | $1,215,926 | $316,716 | $145,968 | $315,514 | $245,516 | ||||||||||||||||||||||||||||||||
Actual return on plan assets | 210,020 | 239,770 | 62,238 | 28,552 | 61,814 | 48,460 | ||||||||||||||||||||||||||||||||
Employer contributions | 75,854 | 64,951 | 20,794 | 4,553 | 3,725 | 20,234 | ||||||||||||||||||||||||||||||||
Benefits paid | (154,681) | (156,617) | (44,820) | (18,296) | (41,927) | (31,542) | ||||||||||||||||||||||||||||||||
Fair value of assets at December 31 | $1,200,035 | $1,364,030 | $354,928 | $160,777 | $339,126 | $282,668 | ||||||||||||||||||||||||||||||||
Funded status | ($415,049) | ($420,444) | ($116,582) | ($46,185) | ($57,638) | ($110,939) | ||||||||||||||||||||||||||||||||
Amounts recognized in the balance sheet (funded status) | ||||||||||||||||||||||||||||||||||||||
Non-current liabilities | ($415,049) | ($420,444) | ($116,582) | ($46,185) | ($57,638) | ($110,939) | ||||||||||||||||||||||||||||||||
Amounts recognized as regulatory asset | ||||||||||||||||||||||||||||||||||||||
Net loss | $799,235 | $759,228 | $225,354 | $91,862 | $160,564 | $193,870 | ||||||||||||||||||||||||||||||||
Amounts recognized as AOCI (before tax) | ||||||||||||||||||||||||||||||||||||||
Net loss | $— | $23,481 | $— | $— | $— | $— | ||||||||||||||||||||||||||||||||
The qualified pension plans incurred actuarial losses during 2020 and 2019 primarily due to a fall in bond yields that resulted in decreases to the discount rates used to develop the benefit obligations. These losses were partially offset by gains resulting from the actual return on assets exceeding the expected return on assets for both 2020 and 2019.
Accumulated Pension Benefit Obligation
The accumulated benefit obligation for Entergy’s qualified pension plans was $8.4 billion and $7.8 billion at December 31, 2020 and 2019, respectively.
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The qualified pension accumulated benefit obligation for each of the Registrant Subsidiaries for their employees as of December 31, 2020 and 2019 was as follows:
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (In Thousands) | |||||||||||
| Entergy Arkansas | $1,617,858 | $1,519,998 | |||||||||
| Entergy Louisiana | $1,753,980 | $1,643,759 | |||||||||
| Entergy Mississippi | $466,497 | $438,817 | |||||||||
| Entergy New Orleans | $201,159 | $192,561 | |||||||||
| Entergy Texas | $379,050 | $371,589 | |||||||||
| System Energy | $410,296 | $368,771 | |||||||||
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), will be eligible to participate in a new Entergy-sponsored retiree health plan, and will no longer be eligible for retiree coverage under the Entergy Corporation Companies’ Benefits Plus Medical, Dental and Vision Plans. Under the new Entergy retiree health plan, Medicare-eligible participants will be 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. In accordance with accounting standards, the effects of this change are reflected in the December 31, 2020 other postretirement obligation. The changes affecting active bargaining unit employees will be 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 benefit 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 benefit costs collected in rates into external trusts. System Energy is funding, on behalf of Entergy Operations, other postretirement benefits associated with 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
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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 Benefit Cost and Other Amounts Recognized as a Regulatory Asset and/or AOCI
Entergy Corporation’s and its subsidiaries’ total 2020, 2019, and 2018 other postretirement benefit costs, including amounts capitalized and amounts recognized as a regulatory asset and/or other comprehensive income, included the following components:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Thousands) | |||||||||||||||||
Other postretirement costs: | |||||||||||||||||
Service cost - benefits earned during the period | $24,500 | $18,699 | $27,129 | ||||||||||||||
Interest cost on accumulated postretirement benefit obligation (APBO) | 28,597 | 47,901 | 50,725 | ||||||||||||||
Expected return on assets | (40,880) | (38,246) | (41,493) | ||||||||||||||
Amortization of prior service credit | (32,882) | (35,377) | (37,002) | ||||||||||||||
Recognized net loss | 3,481 | 1,430 | 13,729 | ||||||||||||||
Net other postretirement benefit (income)/cost | ($17,184) | ($5,593) | $13,088 | ||||||||||||||
Other changes in plan assets and benefit obligations recognized as a regulatory asset and /or AOCI (before tax) | |||||||||||||||||
Arising this period: | |||||||||||||||||
Prior service credit for period | ($128,837) | $— | $— | ||||||||||||||
| Net (gain)/loss | 41,031 | (38,526) | (274,354) | ||||||||||||||
Amounts reclassified from regulatory asset and /or AOCI to net periodic benefit cost in the current year: | |||||||||||||||||
Amortization of prior service credit | 32,882 | 35,377 | 37,002 | ||||||||||||||
Amortization of net loss | (3,481) | (1,430) | (13,729) | ||||||||||||||
Total | ($58,405) | ($4,579) | ($251,081) | ||||||||||||||
Total recognized as net periodic benefit (income)/cost, regulatory asset, and/or AOCI (before tax) | ($75,589) | ($10,172) | ($237,993) | ||||||||||||||
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Total 2020, 2019, and 2018 other postretirement benefit costs of the Registrant Subsidiaries, including amounts capitalized and deferred, for their employees included the following components:
| 2020 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| Other postretirement costs: | ||||||||||||||||||||||||||||||||||||||
| Service cost - benefits earned during the period | $3,626 | $5,993 | $1,468 | $445 | $1,219 | $1,254 | ||||||||||||||||||||||||||||||||
| Interest cost on APBO | 4,712 | 6,216 | 1,536 | 784 | 2,008 | 1,130 | ||||||||||||||||||||||||||||||||
| Expected return on assets | (17,104) | — | (5,167) | (5,382) | (9,643) | (2,958) | ||||||||||||||||||||||||||||||||
| Amortization of prior service credit | (1,849) | (6,179) | (1,652) | (763) | (3,364) | (1,065) | ||||||||||||||||||||||||||||||||
| Recognized net (gain)/ loss | 540 | (447) | 171 | (13) | 907 | 121 | ||||||||||||||||||||||||||||||||
| Net other postretirement benefit (income)/cost | ($10,075) | $5,583 | ($3,644) | ($4,929) | ($8,873) | ($1,518) | ||||||||||||||||||||||||||||||||
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | ||||||||||||||||||||||||||||||||||||||
| Arising this period: | ||||||||||||||||||||||||||||||||||||||
| Prior service cost/(credit) for the period | $12,320 | ($23,508) | ($4,428) | ($5,493) | ($22,441) | ($1,963) | ||||||||||||||||||||||||||||||||
| Net (gain)/loss | $2,245 | $8,744 | ($4,456) | ($5,351) | ($3,266) | $58 | ||||||||||||||||||||||||||||||||
| Amounts reclassified from regulatory asset and/or AOCI to net periodic benefit cost in the current year: | ||||||||||||||||||||||||||||||||||||||
| Amortization of prior service credit | 1,849 | 6,179 | 1,652 | 763 | 3,364 | 1,065 | ||||||||||||||||||||||||||||||||
| Amortization of net (gain)/loss | (540) | 447 | (171) | 13 | (907) | (121) | ||||||||||||||||||||||||||||||||
| Total | $15,874 | ($8,138) | ($7,403) | ($10,068) | ($23,250) | ($961) | ||||||||||||||||||||||||||||||||
| Total recognized as net periodic other postretirement (income)/cost, regulatory asset, and/or AOCI (before tax) | $5,799 | ($2,555) | ($11,047) | ($14,997) | ($32,123) | ($2,479) | ||||||||||||||||||||||||||||||||
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| 2019 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
Other postretirement costs: | ||||||||||||||||||||||||||||||||||||||
Service cost - benefits earned during the period | $2,363 | $4,639 | $1,046 | $367 | $943 | $973 | ||||||||||||||||||||||||||||||||
Interest cost on APBO | 7,226 | 10,664 | 2,681 | 1,581 | 3,415 | 1,902 | ||||||||||||||||||||||||||||||||
Expected return on assets | (15,962) | — | (4,794) | (4,947) | (9,103) | (2,788) | ||||||||||||||||||||||||||||||||
Amortization of prior service credit | (4,950) | (7,349) | (1,756) | (682) | (2,243) | (1,450) | ||||||||||||||||||||||||||||||||
| Recognized net (gain)/loss | 576 | (695) | 723 | 231 | 485 | 354 | ||||||||||||||||||||||||||||||||
Net other postretirement benefit (income)/cost | ($10,747) | $7,259 | ($2,100) | ($3,450) | ($6,503) | ($1,009) | ||||||||||||||||||||||||||||||||
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | ||||||||||||||||||||||||||||||||||||||
Arising this period: | ||||||||||||||||||||||||||||||||||||||
Net gain | ($26,707) | ($2,220) | ($11,950) | ($10,967) | ($6,406) | ($5,539) | ||||||||||||||||||||||||||||||||
Amounts reclassified from regulatory asset and/or AOCI to net periodic benefit cost in the current year: | ||||||||||||||||||||||||||||||||||||||
Amortization of prior service credit | 4,950 | 7,349 | 1,756 | 682 | 2,243 | 1,450 | ||||||||||||||||||||||||||||||||
| Amortization of net (gain)/ loss | (576) | 695 | (723) | (231) | (485) | (354) | ||||||||||||||||||||||||||||||||
Total | ($22,333) | $5,824 | ($10,917) | ($10,516) | ($4,648) | ($4,443) | ||||||||||||||||||||||||||||||||
Total recognized as net periodic other postretirement (income)/cost, regulatory asset, and/or AOCI (before tax) | ($33,080) | $13,083 | ($13,017) | ($13,966) | ($11,151) | ($5,452) | ||||||||||||||||||||||||||||||||
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| 2018 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
Other postretirement costs: | ||||||||||||||||||||||||||||||||||||||
Service cost - benefits earned during the period | $3,170 | $6,225 | $1,284 | $516 | $1,319 | $1,223 | ||||||||||||||||||||||||||||||||
Interest cost on APBO | 7,986 | 11,154 | 2,731 | 1,669 | 3,754 | 1,998 | ||||||||||||||||||||||||||||||||
Expected return on assets | (17,368) | — | (5,213) | (5,250) | (9,784) | (3,130) | ||||||||||||||||||||||||||||||||
Amortization of prior service credit | (5,110) | (7,735) | (1,823) | (745) | (2,316) | (1,513) | ||||||||||||||||||||||||||||||||
Recognized net loss | 1,154 | 1,550 | 1,508 | 137 | 823 | 932 | ||||||||||||||||||||||||||||||||
Net other postretirement benefit (income)/cost | ($10,168) | $11,194 | ($1,513) | ($3,673) | ($6,204) | ($490) | ||||||||||||||||||||||||||||||||
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | ||||||||||||||||||||||||||||||||||||||
Arising this period: | ||||||||||||||||||||||||||||||||||||||
| Net gain | (32,219) | (73,249) | (7,794) | (981) | (10,561) | (6,680) | ||||||||||||||||||||||||||||||||
Amounts reclassified from regulatory asset and/or AOCI to net periodic benefit cost in the current year: | ||||||||||||||||||||||||||||||||||||||
Amortization of prior service credit | 5,110 | 7,735 | 1,823 | 745 | 2,316 | 1,513 | ||||||||||||||||||||||||||||||||
Amortization of net loss | (1,154) | (1,550) | (1,508) | (137) | (823) | (932) | ||||||||||||||||||||||||||||||||
Total | ($28,263) | ($67,064) | ($7,479) | ($373) | ($9,068) | ($6,099) | ||||||||||||||||||||||||||||||||
Total recognized as net periodic other postretirement (income)/cost, regulatory asset, and/or AOCI (before tax) | ($38,431) | ($55,870) | ($8,992) | ($4,046) | ($15,272) | ($6,589) | ||||||||||||||||||||||||||||||||
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Other Postretirement Benefit Obligations, Plan Assets, Funded Status, and Amounts Not Yet Recognized and Recognized in the Balance Sheet
Other postretirement benefit 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, 2020 and 2019 are as follows:
| 2020 | 2019 | ||||||||||
| (In Thousands) | |||||||||||
| Change in APBO | |||||||||||
| Balance at January 1 | $1,252,903 | $1,232,619 | |||||||||
| Service cost | 24,500 | 18,699 | |||||||||
| Interest cost | 28,597 | 47,901 | |||||||||
| Plan amendments | (128,837) | — | |||||||||
| Plan participant contributions | 37,176 | 38,640 | |||||||||
| Actuarial loss | 80,162 | 23,673 | |||||||||
| Benefits paid | (113,786) | (109,223) | |||||||||
| Medicare Part D subsidy received | 360 | 594 | |||||||||
| Balance at December 31 | $1,181,075 | $1,252,903 | |||||||||
| Change in Plan Assets | |||||||||||
| Fair value of assets at January 1 | $686,262 | $609,782 | |||||||||
| Actual return on plan assets | 80,011 | 100,445 | |||||||||
| Employer contributions | 48,203 | 46,618 | |||||||||
| Plan participant contributions | 37,176 | 38,640 | |||||||||
| Benefits paid | (113,786) | (109,223) | |||||||||
| Fair value of assets at December 31 | $737,866 | $686,262 | |||||||||
| Funded status | ($443,209) | ($566,641) | |||||||||
| Amounts recognized in the balance sheet | |||||||||||
| Current liabilities | ($38,963) | ($48,040) | |||||||||
| Non-current liabilities | (404,246) | (518,601) | |||||||||
| Total funded status | ($443,209) | ($566,641) | |||||||||
| Amounts recognized as a regulatory asset | |||||||||||
| Prior service credit | ($45,501) | ($11,899) | |||||||||
| Net gain | (8,565) | (5,081) | |||||||||
| ($54,066) | ($16,980) | ||||||||||
| Amounts recognized as AOCI (before tax) | |||||||||||
| Prior service credit | ($83,581) | ($21,231) | |||||||||
| Net (gain)/loss | 24,365 | (16,670) | |||||||||
| ($59,216) | ($37,901) | ||||||||||
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Other postretirement benefit obligations, plan assets, funded status, and amounts not yet recognized and recognized in the Balance Sheets of the Registrant Subsidiaries as of December 31, 2020 and 2019 are as follows:
| 2020 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Change in APBO | ||||||||||||||||||||||||||||||||||||||
| Balance at January 1 | $185,744 | $274,175 | $65,979 | $38,460 | $94,742 | $47,348 | ||||||||||||||||||||||||||||||||
| Service cost | 3,626 | 5,993 | 1,468 | 445 | 1,219 | 1,254 | ||||||||||||||||||||||||||||||||
| Interest cost | 4,712 | 6,216 | 1,536 | 784 | 2,008 | 1,130 | ||||||||||||||||||||||||||||||||
| Plan amendments | 12,320 | (23,508) | (4,428) | (5,493) | (22,441) | (1,963) | ||||||||||||||||||||||||||||||||
| Plan participant contributions | 7,792 | 8,269 | 2,122 | 1,123 | 2,456 | 1,732 | ||||||||||||||||||||||||||||||||
| Actuarial (gain)/loss | 18,257 | 8,744 | 684 | (91) | 5,952 | 3,025 | ||||||||||||||||||||||||||||||||
| Benefits paid | (23,141) | (24,395) | (5,382) | (3,530) | (9,721) | (4,851) | ||||||||||||||||||||||||||||||||
| Medicare Part D subsidy received | 59 | 77 | 11 | 9 | 18 | 26 | ||||||||||||||||||||||||||||||||
| Balance at December 31 | $209,369 | $255,571 | $61,990 | $31,707 | $74,233 | $47,701 | ||||||||||||||||||||||||||||||||
| Change in Plan Assets | ||||||||||||||||||||||||||||||||||||||
| Fair value of assets at January 1 | $284,224 | $— | $86,085 | $93,858 | $161,810 | $48,471 | ||||||||||||||||||||||||||||||||
| Actual return on plan assets | 33,116 | — | 10,307 | 10,642 | 18,861 | 5,925 | ||||||||||||||||||||||||||||||||
| Employer contributions | 2,201 | 16,126 | 343 | 641 | 690 | 1,342 | ||||||||||||||||||||||||||||||||
| Plan participant contributions | 7,792 | 8,269 | 2,122 | 1,123 | 2,456 | 1,732 | ||||||||||||||||||||||||||||||||
| Benefits paid | (23,141) | (24,395) | (5,382) | (3,530) | (9,721) | (4,851) | ||||||||||||||||||||||||||||||||
| Fair value of assets at December 31 | $304,192 | $— | $93,475 | $102,734 | $174,096 | $52,619 | ||||||||||||||||||||||||||||||||
| Funded status | $94,823 | ($255,571) | $31,485 | $71,027 | $99,863 | $4,918 | ||||||||||||||||||||||||||||||||
| Amounts recognized in the balance sheet | ||||||||||||||||||||||||||||||||||||||
| Current liabilities | $— | ($15,580) | $— | $— | $— | $— | ||||||||||||||||||||||||||||||||
| Non-current liabilities | 94,823 | (239,991) | 31,485 | 71,027 | 99,863 | 4,918 | ||||||||||||||||||||||||||||||||
| Total funded status | $94,823 | ($255,571) | $31,485 | $71,027 | $99,863 | $4,918 | ||||||||||||||||||||||||||||||||
| Amounts recognized in regulatory asset | ||||||||||||||||||||||||||||||||||||||
| Prior service cost/(credit) | $7,655 | $— | ($5,884) | ($4,730) | ($20,498) | ($1,754) | ||||||||||||||||||||||||||||||||
| Net (gain)/loss | (16,557) | — | (1,355) | (13,385) | 2,030 | 2,818 | ||||||||||||||||||||||||||||||||
| ($8,902) | $— | ($7,239) | ($18,115) | ($18,468) | $1,064 | |||||||||||||||||||||||||||||||||
| Amounts recognized in AOCI (before tax) | ||||||||||||||||||||||||||||||||||||||
| Prior service credit | $— | ($22,244) | $— | $— | $— | $— | ||||||||||||||||||||||||||||||||
| Net gain | — | (15,548) | — | — | — | — | ||||||||||||||||||||||||||||||||
| $— | ($37,792) | $— | $— | $— | $— | |||||||||||||||||||||||||||||||||
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| 2019 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
Change in APBO | ||||||||||||||||||||||||||||||||||||||
Balance at January 1 | $187,830 | $275,269 | $68,976 | $41,987 | $88,310 | $48,791 | ||||||||||||||||||||||||||||||||
Service cost | 2,363 | 4,639 | 1,046 | 367 | 943 | 973 | ||||||||||||||||||||||||||||||||
Interest cost | 7,226 | 10,664 | 2,681 | 1,581 | 3,415 | 1,902 | ||||||||||||||||||||||||||||||||
Plan participant contributions | 8,125 | 8,876 | 2,197 | 1,343 | 2,602 | 1,765 | ||||||||||||||||||||||||||||||||
| Actuarial (gain)/loss | 166 | (2,220) | (3,778) | (4,234) | 8,279 | (891) | ||||||||||||||||||||||||||||||||
Benefits paid | (20,048) | (23,160) | (5,159) | (2,598) | (8,830) | (5,229) | ||||||||||||||||||||||||||||||||
Medicare Part D subsidy received | 82 | 107 | 16 | 14 | 23 | 37 | ||||||||||||||||||||||||||||||||
Balance at December 31 | $185,744 | $274,175 | $65,979 | $38,460 | $94,742 | $47,348 | ||||||||||||||||||||||||||||||||
Change in Plan Assets | ||||||||||||||||||||||||||||||||||||||
Fair value of assets at January 1 | $252,055 | $— | $75,853 | $81,774 | $144,846 | $43,670 | ||||||||||||||||||||||||||||||||
Actual return on plan assets | 42,835 | — | 12,966 | 11,680 | 23,788 | 7,436 | ||||||||||||||||||||||||||||||||
Employer contributions | 1,257 | 14,284 | 228 | 1,659 | (596) | 829 | ||||||||||||||||||||||||||||||||
Plan participant contributions | 8,125 | 8,876 | 2,197 | 1,343 | 2,602 | 1,765 | ||||||||||||||||||||||||||||||||
Benefits paid | (20,048) | (23,160) | (5,159) | (2,598) | (8,830) | (5,229) | ||||||||||||||||||||||||||||||||
Fair value of assets at December 31 | $284,224 | $— | $86,085 | $93,858 | $161,810 | $48,471 | ||||||||||||||||||||||||||||||||
Funded status | $98,480 | ($274,175) | $20,106 | $55,398 | $67,068 | $1,123 | ||||||||||||||||||||||||||||||||
Amounts recognized in the balance sheet | ||||||||||||||||||||||||||||||||||||||
Current liabilities | $— | ($18,467) | $— | $— | $— | $— | ||||||||||||||||||||||||||||||||
Non-current liabilities | 98,480 | (255,708) | 20,106 | 55,398 | 67,068 | 1,123 | ||||||||||||||||||||||||||||||||
Total funded status | $98,480 | ($274,175) | $20,106 | $55,398 | $67,068 | $1,123 | ||||||||||||||||||||||||||||||||
Amounts recognized in regulatory asset | ||||||||||||||||||||||||||||||||||||||
Prior service credit | ($6,515) | $— | ($3,108) | $— | ($1,422) | ($854) | ||||||||||||||||||||||||||||||||
| Net (gain)/loss | (18,262) | — | 3,272 | (8,046) | 6,203 | 2,881 | ||||||||||||||||||||||||||||||||
| ($24,777) | $— | $164 | ($8,046) | $4,781 | $2,027 | |||||||||||||||||||||||||||||||||
Amounts recognized in AOCI (before tax) | ||||||||||||||||||||||||||||||||||||||
Prior service credit | $— | ($4,915) | $— | $— | $— | $— | ||||||||||||||||||||||||||||||||
Net gain | — | (24,739) | — | — | — | — | ||||||||||||||||||||||||||||||||
| $— | ($29,654) | $— | $— | $— | $— | |||||||||||||||||||||||||||||||||
The other postretirement plans incurred actuarial losses during 2020 primarily due to a reduction in the projected Employer Group Waiver Plan (EGWP) revenue and a fall in bond yields that resulted in decreases to the discount rates used to develop the benefit obligations. These losses were partially offset by gains resulting from the actual return on assets exceeding the expected return on assets for 2020, an update to the latest mortality projection scale MP-2020, and favorable claims experience. The other postretirement plans experienced actuarial gains during 2019 primarily due to the actual return on assets exceeding the expected return on assets for 2019, favorable claims
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experience, an increase in projected EGWP revenue, and the adoption of the Pri.H-2012 mortality table with improvement scale MP-2019. These gains were partially offset by losses resulting from a fall in bond yields that resulted in decreases to the discount rates used to develop the benefit obligations.
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 $18.1 million in 2020, $22.6 million in 2019, and $24.4 million in 2018. In 2019, and 2018 Entergy recognized $7.4 million and $7.7 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 $182.4 million as of December 31, 2020 of which $22.9 million was a current liability and $159.5 million was a non-current liability. The projected benefit obligation was $162.8 million as of December 31, 2019 of which $18.1 million was a current liability and $144.6 million was a non-current liability. The accumulated benefit obligation was $161.3 million and $143.4 million as of December 31, 2020 and 2019, respectively. The unamortized prior service cost and net loss are recognized in regulatory assets ($77.3 million at December 31, 2020 and $58.8 million at December 31, 2019) and accumulated other comprehensive income before taxes ($16.7 million at December 31, 2020 and $24.9 million at December 31, 2019).
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 employees for the non-qualified plans for 2020, 2019, and 2018, was as follows:
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||
| 2020 | $333 | $148 | $359 | $31 | $469 | ||||||||||||||||||||||||
| 2019 | $275 | $159 | $326 | $20 | $481 | ||||||||||||||||||||||||
| 2018 | $474 | $180 | $300 | $81 | $650 | ||||||||||||||||||||||||
Included in the 2019 net periodic pension cost above are settlement charges of $40 thousand for Entergy Mississippi related to the lump sum benefits paid out of the plan. Included in the 2018 net periodic pension cost above are settlement charges of $30 thousand and $139 thousand for Entergy Arkansas and Entergy Texas, respectively, related to the lump sum benefits paid out of the plan.
The projected benefit obligation for their employees for the non-qualified plans as of December 31, 2020 and 2019 was as follows:
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||
| 2020 | $3,197 | $1,965 | $3,852 | $247 | $8,475 | ||||||||||||||||||||||||
| 2019 | $2,755 | $1,682 | $3,286 | $231 | $7,783 | ||||||||||||||||||||||||
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The accumulated benefit obligation for their employees for the non-qualified plans as of December 31, 2020 and 2019 was as follows:
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||
| 2020 | $2,626 | $1,802 | $3,345 | $240 | $7,949 | ||||||||||||||||||||||||
| 2019 | $2,248 | $1,682 | $2,938 | $230 | $7,391 | ||||||||||||||||||||||||
The following amounts were recorded on the balance sheet as of December 31, 2020 and 2019:
| 2020 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||
| Current liabilities | ($218) | ($193) | ($181) | ($17) | ($633) | |||||||||||||||||||||||||||
| Non-current liabilities | (2,979) | (1,772) | (3,671) | (230) | (7,842) | |||||||||||||||||||||||||||
| Total funded status | ($3,197) | ($1,965) | ($3,852) | ($247) | ($8,475) | |||||||||||||||||||||||||||
| Regulatory asset/(liability) | $1,535 | $424 | $1,757 | ($558) | $147 | |||||||||||||||||||||||||||
| Accumulated other comprehensive income (before taxes) | $— | $18 | $— | $— | $— | |||||||||||||||||||||||||||
| 2019 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||
Current liabilities | ($249) | ($216) | ($357) | ($17) | ($723) | |||||||||||||||||||||||||||
Non-current liabilities | (2,506) | (1,467) | (2,930) | (215) | (7,060) | |||||||||||||||||||||||||||
Total funded status | ($2,755) | ($1,683) | ($3,287) | ($232) | ($7,783) | |||||||||||||||||||||||||||
Regulatory asset/(liability) | $1,232 | $3 | $1,432 | ($559) | ($603) | |||||||||||||||||||||||||||
The non-qualified pension plans incurred actuarial losses during 2020 and 2019 primarily due to a fall in bond yields that resulted in decreases to the discount rates used to develop the benefit obligations.
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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, 2020:
| Qualified Pension Costs | Other Postretirement Costs | Non-Qualified Pension Costs | Total | ||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||
| Entergy | |||||||||||||||||||||||
| Amortization of prior service cost | $— | $21,000 | ($231) | $20,769 | |||||||||||||||||||
| Amortization of loss | (105,853) | (1,006) | (3,326) | (110,185) | |||||||||||||||||||
| Settlement loss | (243) | — | — | (243) | |||||||||||||||||||
| ($106,096) | $19,994 | ($3,557) | ($89,659) | ||||||||||||||||||||
| Entergy Louisiana | |||||||||||||||||||||||
| Amortization of prior service cost | $— | $6,179 | $— | $6,179 | |||||||||||||||||||
| Amortization of loss | (2,001) | 447 | (3) | (1,557) | |||||||||||||||||||
| Settlement loss | (243) | — | — | (243) | |||||||||||||||||||
| ($2,244) | $6,626 | ($3) | $4,379 | ||||||||||||||||||||
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, 2019:
| Qualified Pension Costs | Other Postretirement Costs | Non-Qualified Pension Costs | Total | ||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||
Entergy | |||||||||||||||||||||||
Amortization of prior service cost | $— | $21,498 | ($198) | $21,300 | |||||||||||||||||||
Amortization of loss | (82,284) | 1,230 | (2,192) | (83,246) | |||||||||||||||||||
Settlement loss | (23,458) | — | (1,697) | (25,155) | |||||||||||||||||||
| ($105,742) | $22,728 | ($4,087) | ($87,101) | ||||||||||||||||||||
Entergy Louisiana | |||||||||||||||||||||||
Amortization of prior service cost | $— | $7,349 | $— | $7,349 | |||||||||||||||||||
Amortization of loss | (2,795) | 695 | (6) | (2,106) | |||||||||||||||||||
| ($2,795) | $8,044 | ($6) | $5,243 | ||||||||||||||||||||
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 benefit 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 benefit obligations are recorded as other comprehensive income. Entergy Louisiana recovers other postretirement benefit costs on a pay-as-you-go basis and records the unrecognized prior
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service cost, gains and losses, and transition obligation for its other postretirement benefit 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 benefit plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets. In general, Entergy determines the MRV of its pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns and for its other postretirement benefit plan assets Entergy generally uses fair value.
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
In 2020, year-to-date lump sum benefit payments from the Entergy Corporation Retirement Plan for Bargaining Employees exceeded the sum of the Plan’s 2020 service and interest cost, resulting in a settlement cost of $36.9 million. In accordance with accounting standards, settlement accounting requires immediate recognition of the portion of previously unrecognized losses associated with the settled portion of the plan’s pension liability. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas participate in the Entergy Corporation Retirement Plan for Bargaining Employees and incurred settlement costs of $21.1 million, $8.1 million, $3.4 million, and $4.3 million, respectively. 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, and Entergy Mississippi received regulatory approval to defer the expense portion of the 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 2020, Entergy Texas elected to establish a reserve, in accordance with PUCT regulations, for the difference between the amount recorded for pension and other postretirement benefits expense under generally accepted accounting principles during the first year that rates from Entergy Texas’s last general rate proceeding were in effect, and the annual amount of actuarially determined pension and other postretirement benefits chargeable to Entergy Texas’s expense in 2020. The reserve amount will be evaluated in Entergy Texas’s next base rate case proceeding and a reasonable amortization period will be determined by the PUCT at that time. At December 31, 2020, the balance in this reserve was approximately $3.8 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.
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The target asset allocation for pension adjusts dynamically based on the pension plans’ funded status. 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, 2020 and 2019 and the target asset allocation and ranges for 2020 are as follows:
| Pension Asset Allocation | Target | Range | Actual 2020 | Actual 2019 | ||||||||||||||||||||||||||||
| Domestic Equity Securities | 39% | 32% | to | 46% | 38% | 39% | ||||||||||||||||||||||||||
| International Equity Securities | 19% | 15% | to | 23% | 19% | 19% | ||||||||||||||||||||||||||
| Fixed Income Securities | 42% | 39% | to | 45% | 42% | 41% | ||||||||||||||||||||||||||
| Other | 0% | 0% | to | 10% | 1% | 1% | ||||||||||||||||||||||||||
| Postretirement Asset Allocation | Non-Taxable and Taxable | |||||||||||||||||||||||||||||||
| Target | Range | Actual 2020 | Actual 2019 | |||||||||||||||||||||||||||||
| Domestic Equity Securities | 26% | 21% | to | 31% | 29% | 29% | ||||||||||||||||||||||||||
| International Equity Securities | 18% | 13% | to | 23% | 18% | 18% | ||||||||||||||||||||||||||
| Fixed Income Securities | 56% | 51% | to | 61% | 53% | 53% | ||||||||||||||||||||||||||
| Other | 0% | 0% | to | 5% | 0% | 0% | ||||||||||||||||||||||||||
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,
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foreign country, geographic area and individual security issuance. As of December 31, 2020, 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 benefit 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, 2020, and December 31, 2019, 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.
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Qualified Defined Benefit Pension Plan Trusts
| 2020 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||
Corporate stocks: | ||||||||||||||||||||||||||
Preferred | $15,756 | (b) | $— | $— | $15,756 | |||||||||||||||||||||
Common | 1,031,213 | (b) | — | (b) | — | 1,031,213 | ||||||||||||||||||||
Common collective trusts (c) | 2,958,767 | |||||||||||||||||||||||||
Registered investment companies | — | (d) | — | — | — | |||||||||||||||||||||
Fixed income securities: | ||||||||||||||||||||||||||
U.S. Government securities | — | 731,319 | (a) | — | 731,319 | |||||||||||||||||||||
Corporate debt instruments | — | 1,029,370 | (a) | — | 1,029,370 | |||||||||||||||||||||
Registered investment companies (e) | 81,800 | (d) | 3,076 | (d) | — | 1,128,107 | ||||||||||||||||||||
Other | 156 | (f) | 56,323 | (f) | — | 56,479 | ||||||||||||||||||||
Other: | ||||||||||||||||||||||||||
Insurance company general account (unallocated contracts) | — | 6,253 | (g) | — | 6,253 | |||||||||||||||||||||
Total investments | $1,128,925 | $1,826,341 | $— | $6,957,264 | ||||||||||||||||||||||
Cash | 2,316 | |||||||||||||||||||||||||
Other pending transactions | (29,121) | |||||||||||||||||||||||||
Less: Other postretirement assets included in total investments | (76,033) | |||||||||||||||||||||||||
Total fair value of qualified pension assets | $6,854,426 | |||||||||||||||||||||||||
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| 2019 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||
Corporate stocks: | ||||||||||||||||||||||||||
Preferred | $10,379 | (b) | $— | $— | $10,379 | |||||||||||||||||||||
Common | 857,159 | (b) | — | (b) | — | 857,159 | ||||||||||||||||||||
Common collective trusts (c) | 2,698,697 | |||||||||||||||||||||||||
Registered investment companies | 132,389 | (d) | — | — | 132,389 | |||||||||||||||||||||
Fixed income securities: | ||||||||||||||||||||||||||
U.S. Government securities | — | (b) | 805,671 | (a) | — | 805,671 | ||||||||||||||||||||
Corporate debt instruments | — | 762,577 | (a) | — | 762,577 | |||||||||||||||||||||
Registered investment companies (e) | 53,842 | (d) | 2,903 | (d) | — | 1,008,371 | ||||||||||||||||||||
Other | 73 | (f) | 43,106 | (f) | — | 43,179 | ||||||||||||||||||||
Other: | ||||||||||||||||||||||||||
Insurance company general account (unallocated contracts) | — | 40,452 | (g) | — | 40,452 | |||||||||||||||||||||
Total investments | $1,053,842 | $1,654,709 | $— | $6,358,874 | ||||||||||||||||||||||
Cash | 1,407 | |||||||||||||||||||||||||
Other pending transactions | (22,549) | |||||||||||||||||||||||||
Less: Other postretirement assets included in total investments | (66,572) | |||||||||||||||||||||||||
Total fair value of qualified pension assets | $6,271,160 | |||||||||||||||||||||||||
Other Postretirement Trusts
| 2020 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||
Common collective trust (c) | $315,191 | |||||||||||||||||||||||||
Fixed income securities: | ||||||||||||||||||||||||||
U.S. Government securities | 46,498 | (b) | 97,604 | (a) | — | 144,102 | ||||||||||||||||||||
Corporate debt instruments | — | 147,287 | (a) | — | 147,287 | |||||||||||||||||||||
Registered investment companies | 16,965 | (d) | — | — | 16,965 | |||||||||||||||||||||
Other | — | 60,219 | (f) | — | 60,219 | |||||||||||||||||||||
Total investments | $63,463 | $305,110 | $— | $683,764 | ||||||||||||||||||||||
Other pending transactions | (21,931) | |||||||||||||||||||||||||
Plus: Other postretirement assets included in the investments of the qualified pension trust | 76,033 | |||||||||||||||||||||||||
Total fair value of other postretirement assets | $737,866 | |||||||||||||||||||||||||
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| 2019 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||
Common collective trust (c) | $289,398 | |||||||||||||||||||||||||
Fixed income securities: | ||||||||||||||||||||||||||
U.S. Government securities | 49,930 | (b) | 89,297 | (a) | — | 139,227 | ||||||||||||||||||||
Corporate debt instruments | — | 130,333 | (a) | — | 130,333 | |||||||||||||||||||||
Registered investment companies | 1,877 | (d) | — | — | 1,877 | |||||||||||||||||||||
Other | — | 57,210 | (f) | — | 57,210 | |||||||||||||||||||||
Total investments | $51,807 | $276,840 | $— | $618,045 | ||||||||||||||||||||||
Other pending transactions | 1,645 | |||||||||||||||||||||||||
Plus: Other postretirement assets included in the investments of the qualified pension trust | 66,572 | |||||||||||||||||||||||||
Total fair value of other postretirement assets | $686,262 | |||||||||||||||||||||||||
(a)Certain preferred stocks and certain fixed income debt securities (corporate, government, and securitized) are stated at fair value as determined by broker quotes.
(b)Common stocks, certain 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. Net asset value per share of common collective trusts estimate fair value. Certain of these 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 and estimate fair value using net asset value per share.
(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. 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.
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Estimated Future Benefit Payments
Based upon the assumptions used to measure Entergy’s qualified pension and other postretirement benefit obligations at December 31, 2020, and including pension and other postretirement benefits attributable to estimated future employee service, Entergy expects that benefits to be paid and the Medicare Part D subsidies to be received 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 (before Medicare Subsidy) | Estimated Future Medicare D Subsidy Receipts | ||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||
| Year(s) | |||||||||||||||||||||||
| 2021 | $566,242 | $22,851 | $68,109 | $123 | |||||||||||||||||||
| 2022 | $568,058 | $24,193 | $67,904 | $82 | |||||||||||||||||||
| 2023 | $569,348 | $23,906 | $68,149 | $93 | |||||||||||||||||||
| 2024 | $576,365 | $17,183 | $67,569 | $101 | |||||||||||||||||||
| 2025 | $552,303 | $25,477 | $66,414 | $112 | |||||||||||||||||||
| 2026 - 2030 | $2,641,864 | $56,584 | $314,972 | $703 | |||||||||||||||||||
Based upon the same assumptions, Entergy expects that benefits to be paid and the Medicare Part D subsidies to be received over the next ten years for the Registrant Subsidiaries for their employees will be as follows:
| Estimated Future Qualified Pension Benefits Payments | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Year(s) | ||||||||||||||||||||||||||||||||||||||
| 2021 | $115,340 | $130,058 | $38,131 | $15,011 | $32,935 | $29,202 | ||||||||||||||||||||||||||||||||
| 2022 | $114,260 | $130,019 | $38,104 | $15,202 | $32,859 | $28,854 | ||||||||||||||||||||||||||||||||
| 2023 | $111,759 | $128,199 | $37,159 | $15,030 | $31,439 | $28,833 | ||||||||||||||||||||||||||||||||
| 2024 | $110,128 | $126,927 | $35,571 | $14,437 | $29,541 | $28,641 | ||||||||||||||||||||||||||||||||
| 2025 | $108,314 | $124,911 | $34,377 | $14,052 | $27,781 | $27,378 | ||||||||||||||||||||||||||||||||
| 2026 - 2030 | $513,207 | $575,141 | $155,722 | $63,426 | $123,688 | $132,163 | ||||||||||||||||||||||||||||||||
| Estimated Future Non-Qualified Pension Benefits Payments | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||
| Year(s) | ||||||||||||||||||||||||||||||||
| 2021 | $218 | $193 | $181 | $17 | $633 | |||||||||||||||||||||||||||
| 2022 | $424 | $211 | $411 | $17 | $871 | |||||||||||||||||||||||||||
| 2023 | $328 | $217 | $377 | $21 | $1,004 | |||||||||||||||||||||||||||
| 2024 | $285 | $196 | $454 | $19 | $851 | |||||||||||||||||||||||||||
| 2025 | $580 | $209 | $439 | $19 | $762 | |||||||||||||||||||||||||||
| 2026 - 2030 | $976 | $718 | $2,146 | $111 | $3,250 | |||||||||||||||||||||||||||
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| Estimated Future Other Postretirement Benefits Payments (before Medicare Part D Subsidy) | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Year(s) | ||||||||||||||||||||||||||||||||||||||
| 2021 | $12,693 | $15,600 | $3,386 | $2,412 | $5,322 | $2,739 | ||||||||||||||||||||||||||||||||
| 2022 | $12,542 | $15,502 | $3,498 | $2,322 | $4,840 | $2,734 | ||||||||||||||||||||||||||||||||
| 2023 | $12,329 | $15,397 | $3,541 | $2,238 | $4,770 | $2,676 | ||||||||||||||||||||||||||||||||
| 2024 | $12,156 | $15,034 | $3,574 | $2,151 | $4,597 | $2,579 | ||||||||||||||||||||||||||||||||
| 2025 | $11,869 | $14,825 | $3,614 | $2,070 | $4,486 | $2,518 | ||||||||||||||||||||||||||||||||
| 2026 - 2030 | $56,603 | $69,424 | $17,668 | $8,853 | $20,622 | $11,749 | ||||||||||||||||||||||||||||||||
| Estimated Future Medicare Part D Subsidy | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||||||||
| Year(s) | ||||||||||||||||||||||||||||||||||||||
| 2021 | $40 | $20 | $15 | $— | $13 | $5 | ||||||||||||||||||||||||||||||||
| 2022 | $39 | $6 | $15 | $— | $4 | $1 | ||||||||||||||||||||||||||||||||
| 2023 | $42 | $6 | $17 | $— | $5 | $2 | ||||||||||||||||||||||||||||||||
| 2024 | $45 | $8 | $17 | $— | $5 | $2 | ||||||||||||||||||||||||||||||||
| 2025 | $49 | $8 | $19 | $— | $6 | $1 | ||||||||||||||||||||||||||||||||
| 2026 - 2030 | $289 | $58 | $112 | $— | $43 | $12 | ||||||||||||||||||||||||||||||||
Contributions
Entergy currently expects to contribute approximately $356 million to its qualified pension plans and approximately $39.9 million to other postretirement plans in 2021. The expected 2021 pension and other postretirement plan contributions of the Registrant Subsidiaries for their employees are shown below. The 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021.
The Registrant Subsidiaries expect to contribute approximately the following to the qualified pension and other postretirement plans for their employees in 2021:
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||||||||
| Pension Contributions | $66,649 | $59,882 | $13,715 | $5,395 | $6,955 | $18,663 | |||||||||||||||||||||||||||||
| Other Postretirement Contributions | $517 | $15,600 | $130 | $175 | $66 | $22 | |||||||||||||||||||||||||||||
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Actuarial Assumptions
The significant actuarial assumptions used in determining the pension PBO and the other postretirement benefit APBO as of December 31, 2020 and 2019 were as follows:
| 2020 | 2019 | ||||||||||
Weighted-average discount rate: | |||||||||||
Qualified pension | 2.60% - 2.83% Blended 2.77% | 3.26% - 3.43% Blended 3.39% | |||||||||
Other postretirement | 2.62% | 3.26% | |||||||||
Non-qualified pension | 1.61% | 2.72% | |||||||||
Weighted-average rate of increase in future compensation levels | 3.98% - 4.40% | 3.98% - 4.40% | |||||||||
| Interest crediting rate | 2.60% | 2.60% | |||||||||
| Assumed health care trend rate: | |||||||||||
| Pre-65 | 5.87% | 6.13% | |||||||||
| Post-65 | 6.31% | 6.25% | |||||||||
| Ultimate rate | 4.75% | 4.75% | |||||||||
| Year ultimate rate is reached and beyond: | |||||||||||
| Pre-65 | 2030 | 2027 | |||||||||
| Post-65 | 2028 | 2027 | |||||||||
The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2020, 2019, and 2018 were as follows:
| 2020 | 2019 | 2018 | |||||||||||||||
| Weighted-average discount rate: | |||||||||||||||||
| Qualified pension: | |||||||||||||||||
| Service cost | 3.42% | 4.57% | 3.89% | ||||||||||||||
| Interest cost | 2.99% | 4.15% | 3.44% | ||||||||||||||
| Other postretirement: | |||||||||||||||||
| Service cost | 3.27% | 4.62% | 3.88% | ||||||||||||||
| Interest cost | 2.41% | 4.01% | 3.33% | ||||||||||||||
| Non-qualified pension: | |||||||||||||||||
| Service cost | 2.71% | 3.94% | 3.35% | ||||||||||||||
| Interest cost | 2.25% | 3.46% | 2.76% | ||||||||||||||
| Weighted-average rate of increase in future compensation levels | 3.98% - 4.40% | 3.98% | 3.98% | ||||||||||||||
| Expected long-term rate of return on plan assets: | |||||||||||||||||
| Pension assets | 7.00% | 7.25% | 7.50% | ||||||||||||||
| Other postretirement non-taxable assets | 6.25% - 7.00% | 6.5%-7.25% | 6.50% - 7.50% | ||||||||||||||
| Other postretirement taxable assets | 5.25% | 5.50% | 5.50% | ||||||||||||||
| Assumed health care trend rate: | |||||||||||||||||
| Pre-65 | 6.13% | 6.59% | 6.95% | ||||||||||||||
| Post-65 | 6.25% | 7.15% | 7.25% | ||||||||||||||
| Ultimate rate | 4.75% | 4.75% | 4.75% | ||||||||||||||
| Year ultimate rate is reached and beyond: | |||||||||||||||||
| Pre-65 | 2027 | 2027 | 2027 | ||||||||||||||
| Post-65 | 2027 | 2026 | 2027 | ||||||||||||||
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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, 2020 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, 2020 other postretirement benefit APBO. Entergy used the Pri-2012 Employee and Healthy Annuitant Tables with a fully generational MP-2019 projection scale, in determining its December 31, 2019 pension plans’ PBOs and the Pri.H 2012 (headcount weighted) Employee and Healthy Annuitant Tables with a fully generational MP-2019 projection scale, in determining its December 31, 2019 other postretirement benefit 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 (established in April 2007) and the Savings Plan of Entergy Corporation and Subsidiaries 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.
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 $63.1 million in 2020, $57.6 million in 2019, and $54.3 million in 2018. The majority of the contributions were to the System Savings Plan.
The Registrant Subsidiaries’ 2020, 2019, and 2018 contributions to defined contribution plans for their employees were as follows:
Year | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||
| 2020 | $4,515 | $6,518 | $2,863 | $1,115 | $2,596 | |||||||||||||||||||||||||||
| 2019 | $4,111 | $5,641 | $2,424 | $882 | $2,136 | |||||||||||||||||||||||||||
| 2018 | $3,985 | $5,450 | $2,307 | $795 | $1,992 | |||||||||||||||||||||||||||
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
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(2019 Plan). The maximum number of common shares that can be issued from the 2019 Plan for stock-based awards is 7,300,000 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, 2020, there were 6,108,451 authorized shares remaining for stock-based awards.
Stock Options
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:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Millions) | |||||||||||||||||
| Compensation expense included in Entergy’s consolidated net income | $3.9 | $3.8 | $4.3 | ||||||||||||||
| Tax benefit recognized in Entergy’s consolidated net income | $1.0 | $1.0 | $1.1 | ||||||||||||||
| Compensation cost capitalized as part of fixed assets and inventory | $1.5 | $1.4 | $0.7 | ||||||||||||||
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:
| 2020 | 2019 | 2018 | |||||||||||||||
| Stock price volatility | 17.16% | 17.23% | 17.44% | ||||||||||||||
| Expected term in years | 7.04 | 7.32 | 7.33 | ||||||||||||||
| Risk-free interest rate | 1.49% | 2.50% | 2.54% | ||||||||||||||
| Dividend yield | 4.00% | 4.50% | 4.75% | ||||||||||||||
| Dividend payment per share | $3.74 | $3.66 | $3.58 | ||||||||||||||
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.
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A summary of stock option activity for the year ended December 31, 2020 and changes during the year are presented below:
Number of Options | Weighted- Average Exercise Price | Aggregate Intrinsic Value | Weighted- Average Contractual Life | ||||||||||||||||||||
| Options outstanding as of January 1, 2020 | 2,448,913 | $78.48 | |||||||||||||||||||||
| Options granted | 530,716 | $131.72 | |||||||||||||||||||||
| Options exercised | (544,082) | $79.27 | |||||||||||||||||||||
| Options forfeited/expired | (36,168) | $108.69 | |||||||||||||||||||||
| Options outstanding as of December 31, 2020 | 2,399,379 | $89.63 | $40,842,152 | 6.72 years | |||||||||||||||||||
| Options exercisable as of December 31, 2020 | 1,264,641 | $74.55 | $31,979,370 | 5.26 years | |||||||||||||||||||
| Weighted-average grant-date fair value of options granted during 2020 | $11.45 | ||||||||||||||||||||||
The weighted-average grant-date fair value of options granted during the year was $8.32 for 2019 and $6.99 for 2018. The total intrinsic value of stock options exercised was $26 million during 2020, $29 million during 2019, and $19 million during 2018. 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, 2020. The aggregate intrinsic value of the stock options outstanding as of December 31, 2020 was $40.8 million. Stock options outstanding as of December 31, 2020 includes 512,316 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 $5 million during 2020, $5 million during 2019, and $4 million during 2018. Cash received from option exercises was $43 million for the year ended December 31, 2020. The tax benefits realized from options exercised was $7 million for the year ended December 31, 2020.
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The following table summarizes information about stock options outstanding as of December 31, 2020:
| Options Outstanding | Options Exercisable | ||||||||||||||||||||||||||||||||||
| Range of Exercise Price | As of December 31, 2020 | Weighted-Average Remaining Contractual Life-Yrs. | Weighted Average Exercise Price | Number Exercisable as of December 31, 2020 | Weighted Average Exercise Price | ||||||||||||||||||||||||||||||
| $51 | - | $64.99 | 240,200 | 2.72 | $63.69 | 240,200 | $63.69 | ||||||||||||||||||||||||||||
| $65 | - | $78.99 | 960,110 | 6.09 | $73.86 | 759,031 | $72.74 | ||||||||||||||||||||||||||||
| $79 | - | $91.99 | 686,753 | 7.24 | $89.34 | 265,410 | $89.57 | ||||||||||||||||||||||||||||
| $92 | - | $131.72 | 512,316 | 9.08 | $131.72 | — | $0.00 | ||||||||||||||||||||||||||||
| $51 | - | $131.72 | 2,399,379 | 6.72 | $89.63 | 1,264,641 | $74.55 | ||||||||||||||||||||||||||||
Stock-based compensation cost related to non-vested stock options outstanding as of December 31, 2020 not yet recognized is approximately $6 million and is expected to be recognized over a weighted-average period of 1.72 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 2020 the Board approved and Entergy granted 313,805 restricted stock awards under the 2019 Plan. The restricted stock awards were made effective on January 30, 2020 and were valued at $131.72 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, 2020:
| Shares | Weighted-Average Grant Date Fair Value Per Share | ||||||||||
| Outstanding shares at January 1, 2020 | 692,134 | $82.56 | |||||||||
| Granted | 336,363 | $130.11 | |||||||||
| Vested | (345,271) | $79.41 | |||||||||
| Forfeited | (34,728) | $101.32 | |||||||||
| Outstanding shares at December 31, 2020 | 648,498 | $107.89 | |||||||||
The following table includes financial information for restricted stock for each of the years presented:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Millions) | |||||||||||||||||
| Compensation expense included in Entergy’s consolidated net income | $23.1 | $20.2 | $19.8 | ||||||||||||||
| Tax benefit recognized in Entergy’s consolidated net income | $5.9 | $5.1 | $5.1 | ||||||||||||||
| Compensation cost capitalized as part of fixed assets and inventory | $8.5 | $7.1 | $5.7 | ||||||||||||||
The total fair value of the restricted stock awards granted was $44 million, $34 million, and $28 million for the years ended December 31, 2020, 2019, and 2018, respectively.
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The total fair value of the restricted stock awards vested was $27 million, $25 million, and $25 million for the years ended December 31, 2020, 2019, and 2018, 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. For the 2020-2021 performance period, performance will be measured based eighty percent on relative total shareholder return and twenty percent on a cumulative adjusted earnings per share metric.
In January 2020 the Board approved and Entergy granted 134,853 performance units under the 2019 Plan. The performance units were granted on January 30, 2020, and eighty percent were valued at $169.74 per share based on various factors, primarily market conditions; and twenty percent were valued at $131.72 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 cumulative adjusted earnings per share 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, 2020:
| Shares | Weighted-Average Grant Date Fair Value Per Share | ||||||||||
| Outstanding shares at January 1, 2020 | 551,933 | $84.01 | |||||||||
| Granted | 376,557 | $105.90 | |||||||||
| Vested | (423,225) | $71.40 | |||||||||
| Forfeited | (29,500) | $111.86 | |||||||||
| Outstanding shares at December 31, 2020 | 475,765 | $110.82 | |||||||||
The following table includes financial information for the long-term performance units for each of the years presented:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Millions) | |||||||||||||||||
| Compensation expense included in Entergy’s consolidated net income | $12.6 | $11.1 | $11.5 | ||||||||||||||
| Tax benefit recognized in Entergy’s consolidated net income | $3.2 | $2.8 | $2.9 | ||||||||||||||
| Compensation cost capitalized as part of fixed assets and inventory | $4.9 | $4.0 | $3.3 | ||||||||||||||
The total fair value of the long-term performance units granted was $40 million, $23 million, and $16 million for the years ended December 31, 2020, 2019, and 2018, respectively.
In January 2020, Entergy issued 423,184 shares of Entergy Corporation common stock at a share price of $126.31 for awards earned and dividends accrued under the 2017-2019 Long-Term Performance Unit Program. In January 2019, Entergy issued 226,208 shares of Entergy Corporation common stock at a share price of $86.03 for awards earned and dividends accrued under the 2016-2018 Long-Term Performance Unit Program. In January
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2018, Entergy issued 50,812 shares of Entergy Corporation common stock at a share price of $78.51 for awards earned and dividends accrued under the 2015-2017 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 33 months. As of December 31, 2020, there were 86,175 unvested restricted stock units that are expected to vest over an average period of 16 months.
The following table includes information about the restricted stock unit awards outstanding as of December 31, 2020:
| Shares | Weighted-Average Grant Date Fair Value Per Share | ||||||||||
| Outstanding shares at January 1, 2020 | 130,463 | $82.72 | |||||||||
| Granted | 18,100 | $114.30 | |||||||||
| Vested | (55,888) | $77.04 | |||||||||
| Forfeited | (6,500) | $84.32 | |||||||||
| Outstanding shares at December 31, 2020 | 86,175 | $92.92 | |||||||||
The following table includes financial information for restricted stock unit awards for each of the years presented:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Millions) | |||||||||||||||||
| Compensation expense included in Entergy’s consolidated net income | $2.0 | $2.2 | $2.9 | ||||||||||||||
| Tax benefit recognized in Entergy’s consolidated net income | $0.5 | $0.6 | $0.7 | ||||||||||||||
| Compensation cost capitalized as part of fixed assets and inventory | $0.9 | $0.9 | $0.7 | ||||||||||||||
The total fair value of the restricted stock unit awards granted was $2 million, $3 million, and $2 million for the years ended December 31, 2020, 2019, and 2018, respectively.
The total fair value of the restricted stock unit awards vested was $4 million, $6 million, and $3.1 million for the years ended December 31, 2020, 2019, and 2018, respectively.
NOTE 13. BUSINESS SEGMENT INFORMATION (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Entergy’s reportable segments as of December 31, 2020 are Utility and Entergy Wholesale Commodities. Utility includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Louisiana, Mississippi, and Texas, and natural gas utility service in portions of Louisiana. Entergy Wholesale Commodities includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities also includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. “All Other” includes the parent company, Entergy Corporation, and other business activity.
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Entergy’s segment financial information was as follows:
| 2020 | Utility | Entergy Wholesale Commodities | All Other | Eliminations | Consolidated | |||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||
| Operating revenues | $9,170,714 | $942,869 | $78 | ($25) | $10,113,636 | |||||||||||||||||||||||||||
| Asset write-offs, impairments, and related charges | $— | $26,623 | $— | $— | $26,623 | |||||||||||||||||||||||||||
| Depreciation, amortization, & decommissioning | $1,685,138 | $306,974 | $2,835 | $— | $1,994,947 | |||||||||||||||||||||||||||
| Interest and investment income | $299,004 | $234,194 | $19,563 | ($159,943) | $392,818 | |||||||||||||||||||||||||||
| Interest expense | $648,851 | $22,432 | $146,730 | ($32,350) | $785,663 | |||||||||||||||||||||||||||
| Income taxes | ($282,311) | $104,937 | $55,868 | $— | ($121,506) | |||||||||||||||||||||||||||
| Consolidated net income (loss) | $1,816,354 | ($62,763) | ($219,344) | ($127,594) | $1,406,653 | |||||||||||||||||||||||||||
| Total assets | $55,940,153 | $3,800,378 | $552,632 | ($2,053,951) | $58,239,212 | |||||||||||||||||||||||||||
| Cash paid for long-lived asset additions | $5,102,322 | $54,455 | $84 | $— | $5,156,861 | |||||||||||||||||||||||||||
| 2019 | Utility | Entergy Wholesale Commodities | All Other | Eliminations | Consolidated | |||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||
Operating revenues | $9,583,985 | $1,294,719 | $21 | ($52) | $10,878,673 | |||||||||||||||||||||||||||
Asset write-offs, impairments, and related charges | $— | $290,027 | $— | $— | $290,027 | |||||||||||||||||||||||||||
Depreciation, amortization, & decommissioning | $1,493,167 | $384,707 | $2,944 | $— | $1,880,818 | |||||||||||||||||||||||||||
Interest and investment income | $289,570 | $414,636 | $26,295 | ($182,589) | $547,912 | |||||||||||||||||||||||||||
Interest expense | $589,395 | $29,450 | $178,575 | ($54,995) | $742,425 | |||||||||||||||||||||||||||
Income taxes | $19,634 | ($161,295) | ($28,164) | $— | ($169,825) | |||||||||||||||||||||||||||
Consolidated net income (loss) | $1,425,643 | $148,870 | ($188,675) | ($127,594) | $1,258,244 | |||||||||||||||||||||||||||
Total assets | $49,557,664 | $4,154,961 | $514,020 | ($2,502,733) | $51,723,912 | |||||||||||||||||||||||||||
Cash paid for long-lived asset additions | $4,527,045 | $104,300 | $160 | $— | $4,631,505 | |||||||||||||||||||||||||||
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| 2018 | Utility | Entergy Wholesale Commodities | All Other | Eliminations | Consolidated | |||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||
Operating revenues | $9,540,670 | $1,468,905 | $— | ($123) | $11,009,452 | |||||||||||||||||||||||||||
Asset write-offs, impairments, and related charges | $— | $532,321 | $— | $— | $532,321 | |||||||||||||||||||||||||||
Depreciation, amortization, & decommissioning | $1,367,944 | $388,732 | $1,274 | $— | $1,757,950 | |||||||||||||||||||||||||||
Interest and investment income | $203,936 | $14,543 | $31,602 | ($186,217) | $63,864 | |||||||||||||||||||||||||||
Interest expense | $552,919 | $33,694 | $179,358 | ($58,623) | $707,348 | |||||||||||||||||||||||||||
Income taxes | ($732,548) | ($269,025) | ($35,253) | $— | ($1,036,826) | |||||||||||||||||||||||||||
Consolidated net income (loss) | $1,495,061 | ($340,641) | ($164,271) | ($127,594) | $862,555 | |||||||||||||||||||||||||||
Total assets | $44,777,167 | $5,459,275 | $733,366 | ($2,694,742) | $48,275,066 | |||||||||||||||||||||||||||
Investment in affiliates - at equity | $— | $— | $— | $— | $— | |||||||||||||||||||||||||||
Cash paid for long-lived asset additions | $3,987,424 | $283,707 | $86 | $— | $4,271,217 | |||||||||||||||||||||||||||
The Entergy Wholesale Commodities business is sometimes referred to as the “competitive businesses.” Eliminations are primarily intersegment activity. Almost all of Entergy’s goodwill is related to the Utility segment.
In January 2019, Entergy sold the Vermont Yankee plant, which it had previously shut down, to NorthStar. In August 2019, Entergy sold the Pilgrim plant, which it had previously shut down, to Holtec. Indian Point 2 was shut down in April 2020, and Entergy has also announced plans to shut down Indian Point 3 in April 2021 and Palisades in May 2022, and has purchase and sale agreements with Holtec for each of them expected to close after they are shut down. Management expects these transactions to result in the cessation of merchant power generation at all Entergy Wholesale Commodities nuclear power plants owned and operated by Entergy by 2022. Entergy will continue to have the obligation to decommission the nuclear plants pending their sales to third parties.
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 the consolidated income statements.
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Total restructuring charges in 2020, 2019, and 2018 were comprised of the following:
| Employee retention and severance expenses and other benefits-related costs | Contracted economic development costs | Total | ||||||||||||||||||
| (In Millions) | ||||||||||||||||||||
| Balance as of December 31, 2017 | $83 | $14 | $97 | |||||||||||||||||
| Restructuring costs accrued | 139 | — | 139 | |||||||||||||||||
| Cash paid out | 43 | — | 43 | |||||||||||||||||
| Balance as of December 31, 2018 | $179 | $14 | $193 | |||||||||||||||||
| Restructuring costs accrued | 91 | — | 91 | |||||||||||||||||
| Cash paid out | 141 | — | 141 | |||||||||||||||||
| Balance as of December 31, 2019 | $129 | $14 | $143 | |||||||||||||||||
| Restructuring costs accrued | 71 | — | 71 | |||||||||||||||||
| Cash paid out | 55 | — | 55 | |||||||||||||||||
| Balance as of December 31, 2020 | $145 | $14 | $159 | |||||||||||||||||
In addition, Entergy Wholesale Commodities incurred $19 million in 2020, $290 million in 2019, and $532 million in 2018 of impairment, loss on sales, and other related charges associated with these strategic decisions and transactions. See Note 14 to the financial statements for further discussion of these impairment charges.
Going forward, Entergy Wholesale Commodities expects to incur employee retention and severance expenses of approximately $40 million in 2021 and approximately $15 million in 2022 associated with these strategic transactions.
Geographic Areas
For the years ended December 31, 2020, 2019, and 2018, the amount of revenue Entergy derived from outside of the United States was insignificant. As of December 31, 2020 and 2019, 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 is 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.
NOTE 14. ACQUISITIONS, DISPOSITIONS, AND IMPAIRMENT OF LONG-LIVED ASSETS (Entergy Corporation, Entergy Louisiana, and Entergy Mississippi)
Acquisitions
Choctaw Generating Station
In October 2019, Entergy Mississippi purchased the Choctaw Generating Station, an 810 MW natural gas fired combined-cycle turbine plant located near French Camp, Mississippi, from a subsidiary of GenOn Energy Inc. The purchase price for the Choctaw Generating Station was approximately $305 million.
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Washington Parish Energy Center
In April 2017, Entergy Louisiana entered into an agreement with a subsidiary of Calpine Corporation for the construction and purchase of Washington Parish Energy Center, which consists of two natural gas-fired combustion turbine units with a total nominal capacity of approximately 361 MW. In November 2020, Entergy Louisiana completed the purchase, as approved by the LPSC, of the Washington Parish Energy Center. The total investment including transmission and other related costs, is approximately $261 million, including a payment of $222 million to purchase the plant.
Dispositions
Pilgrim
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 Entergy Nuclear Generation Company, the owner of the Pilgrim plant. In August 2019 the NRC approved the sale of the plant to Holtec. The transaction closed in August 2019 for a purchase price of $1,000 (subject to adjustments for net liabilities and other amounts). The sale included the transfer of the Pilgrim nuclear decommissioning trust and the asset retirement obligation for spent fuel management and plant decommissioning. The transaction resulted in a loss of $190 million ($156 million net-of-tax) in the third quarter 2019. The disposition-date fair value of the nuclear decommissioning trust fund was approximately $1,030 million and the disposition-date fair value of the asset retirement obligation was $837 million. The transaction also included property, plant, and equipment with a net book value of zero, materials and supplies, and prepaid assets.
Willow Glen
In December 2018, Entergy Louisiana sold the Willow Glen Power Station, a non-operating gas plant. Entergy Louisiana sold Willow Glen for approximately $12 million in cash and the transfer of the obligation to decommission the plant. Entergy Louisiana recognized a regulatory liability of $5.7 million for return of removal costs previously collected in rates. Entergy Louisiana realized a pre-tax gain of $14.8 million on the sale. Entergy Louisiana recorded a $31.9 million regulatory liability to recognize the obligation to refund excess customer collections for decommissioning Willow Glen.
Vermont Yankee
In November 2016, Entergy entered into an agreement to sell 100% of the membership interests in Entergy Nuclear Vermont Yankee, LLC to a subsidiary of NorthStar. Entergy Nuclear Vermont Yankee was the owner of the Vermont Yankee plant. The sale of Entergy Nuclear Vermont Yankee to NorthStar included the transfer of the nuclear decommissioning trust fund and the asset retirement obligation for the spent fuel management and decommissioning of the plant.
In March 2018, Entergy and NorthStar entered into a settlement agreement and a Memorandum of Understanding with State of Vermont agencies and other interested parties that set forth the terms on which the agencies and parties support the Vermont Public Utility Commission’s approval of the transaction. The agreements provide additional financial assurance for decommissioning, spent fuel management and site restoration, and detail the site restoration standards. In October 2018 the NRC issued an order approving the application to transfer Vermont Yankee’s license to NorthStar for decommissioning. In December 2018, the Vermont Public Utility Commission issued an order approving the transaction consistent with the Memorandum of Understanding’s terms. On January 11, 2019, Entergy and NorthStar closed the transaction.
Entergy Nuclear Vermont Yankee had an outstanding credit facility that was used to pay for dry fuel storage costs. This credit facility was guaranteed by Entergy Corporation. A subsidiary of Entergy assumed the
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obligations under the credit facility, which remains outstanding. At the closing of the sale transaction, NorthStar caused Entergy Nuclear Vermont Yankee, renamed NorthStar Vermont Yankee, to issue a $139 million promissory note to the Entergy subsidiary that assumed the credit facility obligations. The amount of the note included the balance outstanding on the credit facility, as well as borrowing fees and costs incurred by Entergy in connection with the credit facility.
With the receipt of the NRC and Vermont Public Utility Commission approvals and the resolution among the parties of the significant conditions of the sale, Entergy concluded that as of December 31, 2018 Vermont Yankee was in held for sale status. Entergy accordingly evaluated the Vermont Yankee asset retirement obligation in light of the terms of the sale transaction and evaluated the remaining values of the Vermont Yankee assets. These evaluations resulted in an increase in the asset retirement obligation and $173 million of asset impairment and related other charges in the fourth quarter 2018. See Note 9 to the financial statements for additional discussion of the asset retirement obligation. Upon closing of the transaction in January 2019, the Vermont Yankee decommissioning trust, along with the decommissioning obligation for the plant, was transferred to NorthStar. The assets and liabilities associated with the sale of Vermont Yankee were classified as held for sale on the Entergy Corporation and Subsidiaries Consolidated Balance Sheet as of December 31, 2018. As of December 31, 2018, the value of the decommissioning trust was $532 million. As of December 31, 2018, the asset retirement cost asset was $127 million, classified within other deferred debits, and the asset retirement cost obligation was $568 million, classified within other non-current liabilities.
The Vermont Yankee spent fuel disposal contract was assigned to NorthStar as part of the transaction. The Vermont Yankee transaction resulted in Entergy generating a net deferred tax asset in January 2019. The deferred tax asset could not be fully realized by Entergy in the first quarter of 2019; accordingly, Entergy accrued a net tax expense of $29 million on the disposition of Vermont Yankee. The transaction also resulted in other charges of $5.4 million ($4.2 million net-of-tax) in the first quarter 2019.
Impairment of Long-lived Assets
2018, 2019, and 2020 Impairments
Entergy continues to execute its strategy to shut down and sell all of the remaining plants in Entergy Wholesale Commodities’ merchant nuclear fleet, with planned shutdowns of Indian Point 3 by April 30, 2021 and Palisades by May 31, 2022. The Indian Point 2 plant permanently ceased operations on April 30, 2020. The other three Entergy Wholesale Commodities’ nuclear plants, FitzPatrick, Vermont Yankee, and Pilgrim, have been sold. The FitzPatrick plant was classified as held-for-sale at December 31, 2016, and subsequently sold to Exelon in March 2017. The Vermont Yankee plant was classified as held-for-sale at December 31, 2018, and subsequently sold to NorthStar on January 11, 2019. The Pilgrim plant was sold to Holtec International on August 26, 2019.
Entergy Wholesale Commodities incurred $19 million in 2020, $100 million in 2019, and $532 million in 2018 of impairment charges related to nuclear fuel spending, nuclear refueling outage spending, expenditures for capital assets, and asset retirement obligation revisions. These costs were charged to expense as incurred as a result of the impaired fair value of the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining estimated operating lives associated with management’s strategy to exit the Entergy Wholesale Commodities merchant power business.
With respect to Palisades, Entergy and Consumers Energy had agreed to amend the existing PPA so that it would terminate early, on May 31, 2018. In September 2017, however, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy continues to operate Palisades under the current PPA with Consumers Energy, instead of shutting down in the fall of 2018 as previously planned. Entergy intends to shut down the Palisades plant permanently no later than May 31, 2022. As a result of the change in expected operating life of the Palisades plant, the expected probability-weighted undiscounted net cash flows as of September 30, 2017 exceeded the carrying value of the plant and related assets. Accordingly, nuclear fuel spending, nuclear refueling
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outage spending, and expenditures for capital assets incurred at Palisades after September 30, 2017 are no longer charged to expense as incurred, but recorded as assets and depreciated or amortized, subject to the typical periodic impairment reviews prescribed in the accounting rules.
The impairments and other related charges are recorded as a separate line item in Entergy’s consolidated statements of operations and are included within the results of the Entergy Wholesale Commodities segment. In addition to the impairments and other related charges, Entergy expects to incur additional charges through mid-2022 associated with these strategic transactions. See Note 13 to the financial statements for further discussion of these additional charges.
2018 Pilgrim Impairment
The Pilgrim plant ceased operations on May 31, 2019, at the end of its current fuel cycle. Entergy Nuclear Generation Company filed its Post-Shutdown Decommissioning Activities Report (PSDAR) with the NRC in the fourth quarter 2018 for the Pilgrim plant. As part of the development of the PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2018. The revised estimate resulted in a $117.5 million increase in the decommissioning cost liability and a corresponding impairment charge in the third quarter 2018. As discussed above in Dispositions, on August 26, 2019, Entergy sold the Pilgrim plant to a Holtec International subsidiary.
2018 Vermont Yankee Impairment
As discussed above in Dispositions, on January 11, 2019, Entergy sold the Vermont Yankee plant to NorthStar. With the receipt of the NRC and Vermont Public Utility Commission approvals and the resolution among the parties of the significant conditions of the sale, Entergy concluded that as of December 31, 2018 Vermont Yankee was in held-for- sale status. Entergy accordingly evaluated the Vermont Yankee asset retirement obligation in light of the terms of the sale transaction, and evaluated the remaining values of the Vermont Yankee assets. These evaluations resulted in $173 million of asset impairment and related charges in the fourth quarter 2018. See Note 9 to the financial statements for additional discussion of the revision of the asset retirement obligation.
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.
As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy and capacity in the day ahead or spot markets. In addition to its forward physical power and gas contracts, Entergy Wholesale Commodities may also use a combination of financial contracts, including swaps, collars, and options, to mitigate commodity price risk. When the market price falls, the combination of instruments
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is expected to settle in gains that offset lower revenue from generation, which results in a more predictable cash flow.
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 and interest rate swaps. 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 enters 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 settle against day-ahead power pool prices are used to manage price exposure for Entergy Wholesale Commodities generation. The maximum length of time over which Entergy Wholesale Commodities is currently hedging the variability in future cash flows with derivatives for forecasted power transactions at December 31, 2020 is approximately 3 months. Planned generation currently under contract from Entergy Wholesale Commodities nuclear power plants is 98% for 2021, of which approximately 29% is sold under financial derivatives and the remainder under normal purchase/normal sale contracts. Total planned generation for 2021 is 9.6 TWh.
Entergy may use standardized master netting agreements to help mitigate the credit risk of derivative instruments. These master agreements facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Cash, letters of credit, and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds an established threshold. The threshold represents an unsecured credit limit, which may be supported by a parental/affiliate guarantee, as determined in accordance with Entergy’s credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
Certain of the agreements to sell the power produced by Entergy Wholesale Commodities power plants contain provisions that require an Entergy subsidiary to provide credit support to secure its obligations depending on the mark-to-market values of the contracts. The primary form of credit support to satisfy these requirements is an Entergy Corporation guarantee. As of December 31, 2020, there were no derivative contracts with counterparties in a liability position. In addition to the corporate guarantee, $5 million in cash collateral was required to be posted by the Entergy subsidiary to its counterparties and $39 million in letters of credit were required to be posted by its counterparties to the Entergy subsidiary. As of December 31, 2019, there were no derivative contracts with counterparties in a liability position. In addition to the corporate guarantee, $11 million in cash collateral was
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required to be posted by the Entergy subsidiary to its counterparties and $1 million in cash collateral and $98 million in letters of credit were required to be posted by its counterparties to the Entergy subsidiary. If the Entergy Corporation credit rating falls below investment grade, Entergy would have to post collateral equal to the estimated outstanding liability under the contract at the applicable date.
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 had executed natural gas swaps and options as of December 31, 2020 is 3.25 years for Entergy Louisiana and the maximum length of time over which Entergy has executed natural gas swaps as of December 31, 2020 is 10 months for Entergy Mississippi and 3 months Entergy New Orleans. The total volume of natural gas swaps and options outstanding as of December 31, 2020 is 38,799,000 MMBtu for Entergy, including 23,720,000 MMBtu for Entergy Louisiana, 14,573,000 MMBtu for Entergy Mississippi, and 506,000 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 2020, Entergy participated in the annual financial transmission rights auction process for the MISO planning year of June 1, 2020 through May 31, 2021. 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 Entergy Wholesale Commodities 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, 2020 is 57,196 GWh for Entergy, including 14,138 GWh for Entergy Arkansas, 26,679 GWh for Entergy Louisiana, 6,362 GWh for Entergy Mississippi, 2,618 GWh for Entergy New Orleans, and 7,205 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 Entergy Wholesale Commodities is covered by cash. No cash or letters of credit were required to be posted for financial transmission rights exposure for Entergy Wholesale Commodities as of December 31, 2020 and December 31, 2019. Letters of credit posted with MISO covered the financial transmission rights exposure for Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas as of December 31, 2020 and for Entergy Mississippi as of December 31, 2019.
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The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 2020 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.
| Instrument | Balance Sheet Location | Gross Fair Value (a) | Offsetting Position (b) | Net Fair Value (c) (d) | Business | |||||||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||||||||
| Derivatives designated as hedging instruments | ||||||||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||||||||
| Electricity swaps and options | Prepayments and other (current portion) | $39 | ($1) | $38 | Entergy Wholesale Commodities | |||||||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||||||||
| Electricity swaps and options | Other current liabilities (current portion) | $1 | ($1) | $— | Entergy Wholesale Commodities | |||||||||||||||||||||||||||
| Derivatives not designated as hedging instruments | ||||||||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||||||||
| Natural gas swaps and options | Prepayments and other (current portion) | $1 | $— | $1 | Utility | |||||||||||||||||||||||||||
| Natural gas swaps and options | Other deferred debits and other assets (non-current portion) | $1 | $— | $1 | Utility | |||||||||||||||||||||||||||
| Financial transmission rights | Prepayments and other | $9 | $— | $9 | Utility and Entergy Wholesale Commodities | |||||||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||||||||
| Natural gas swaps and options | Other current liabilities (current portion) | $6 | $— | $6 | Utility | |||||||||||||||||||||||||||
| Natural gas swaps and options | Other non-current liabilities (non-current portion) | $1 | $— | $1 | Utility | |||||||||||||||||||||||||||
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The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 2019 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.
| Instrument | Balance Sheet Location | Gross Fair Value (a) | Offsetting Position (b) | Net Fair Value (c) (d) | Business | |||||||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||||||||
| Derivatives designated as hedging instruments | ||||||||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||||||||
| Electricity swaps and options | Prepayments and other (current portion) | $92 | ($1) | $91 | Entergy Wholesale Commodities | |||||||||||||||||||||||||||
| Electricity swaps and options | Other deferred debits and other assets (non-current portion) | $17 | $— | $17 | Entergy Wholesale Commodities | |||||||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||||||||
| Electricity swaps and options | Other current liabilities (current portion) | $1 | ($1) | $— | Entergy Wholesale Commodities | |||||||||||||||||||||||||||
| Derivatives not designated as hedging instruments | ||||||||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||||||||
| Electricity swaps and options | Prepayments and other (current portion) | $11 | ($1) | $10 | Entergy Wholesale Commodities | |||||||||||||||||||||||||||
| Natural gas swaps and options | Other deferred debits and other assets (non-current portion) | $1 | $— | $1 | Utility | |||||||||||||||||||||||||||
| Financial transmission rights | Prepayments and other | $10 | $— | $10 | Utility and Entergy Wholesale Commodities | |||||||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||||||||
| Electricity swaps and options | Other current liabilities (current portion) | $2 | ($2) | $— | Entergy Wholesale Commodities | |||||||||||||||||||||||||||
| Natural gas swaps and options | Other current liabilities (current portion) | $5 | $— | $5 | Utility | |||||||||||||||||||||||||||
| Natural gas swaps and options | Other non-current liabilities (non-current portion) | $2 | $— | $2 | Utility | |||||||||||||||||||||||||||
(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 Sheet
(d)Excludes cash collateral in the amount of $5 million posted as of December 31, 2020 and $11 million posted and $1 million held as of December 31, 2019. Also excludes letters of credit in the amount of $1 million posted and $39 million held as of December 31, 2020 and $98 million held as of December 31, 2019.
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The effects of Entergy’s derivative instruments designated as cash flow hedges on the consolidated income statements for the years ended December 31, 2020, 2019, and 2018 are as follows:
| Instrument | Amount of gain (loss) recognized in other comprehensive income | Income Statement location | Amount of gain (loss) reclassified from accumulated other comprehensive income into income (a) | |||||||||||||||||
| (In Millions) | (In Millions) | |||||||||||||||||||
| 2020 | ||||||||||||||||||||
| Electricity swaps and options | $77 | Competitive business operating revenues | $148 | |||||||||||||||||
| 2019 | ||||||||||||||||||||
| Electricity swaps and options | $232 | Competitive business operating revenues | $97 | |||||||||||||||||
| 2018 | ||||||||||||||||||||
| Electricity swaps and options | ($40) | Competitive business operating revenues | ($68) | |||||||||||||||||
(a)Before taxes of $31 million, $20 million, and ($14) million, for the years ended December 31, 2020, 2019, and 2018, respectively
Prior to the adoption of ASU 2017-12, Entergy measured its hedges for ineffectiveness. Any ineffectiveness was recognized in earnings during the period. The ineffective portion of cash flow hedges was recorded in competitive businesses operating revenues. The change in fair value of Entergy’s cash flow hedges due to ineffectiveness was ($5.9) million for the year ended December 31, 2018.
Based on market prices as of December 31, 2020, unrealized gains recorded in accumulated other comprehensive income on cash flow hedges relating to power sales totaled $38 million of net unrealized losses. Approximately $38 million is expected to be reclassified from accumulated other comprehensive income to operating revenues in the next twelve months. The actual amount reclassified from accumulated other comprehensive income, however, could vary due to future changes in market prices.
Entergy may effectively liquidate 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 continue to be deferred in other comprehensive income until they are included in income as the original hedged transaction occurs. From the point of de-designation, the gains or losses on the original hedge and the offsetting contract are recorded as assets or liabilities on the balance sheet and offset as they flow through to earnings.
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The effects of Entergy’s derivative instruments not designated as hedging instruments on the consolidated income statements for the years ended December 31, 2020, 2019, and 2018 are as follows:
| Instrument | Income Statement location | Amount of gain (loss) recorded in the income statement | ||||||||||||
| (In Millions) | ||||||||||||||
| 2020 | ||||||||||||||
| Natural gas swaps and options | Fuel, fuel-related expenses, and gas purchased for resale | (a) | ($12) | |||||||||||
| Financial transmission rights | Purchased power expense | (b) | $92 | |||||||||||
| Electricity swaps and options (c) | Competitive business operating revenues | $1 | ||||||||||||
| 2019 | ||||||||||||||
| Natural gas swaps and option | Fuel, fuel-related expenses, and gas purchased for resale | (a) | ($13) | |||||||||||
| Financial transmission rights | Purchased power expense | (b) | $94 | |||||||||||
| Electricity swaps and options (c) | Competitive business operating revenues | $12 | ||||||||||||
| 2018 | ||||||||||||||
| Natural gas swaps | Fuel, fuel-related expenses, and gas purchased for resale | (a) | $8 | |||||||||||
| Financial transmission rights | Purchased power expense | (b) | $131 | |||||||||||
| Electricity swaps and options (c) | Competitive business operating revenues | $8 | ||||||||||||
(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.
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The fair values of the Registrant Subsidiaries’ derivative instruments not designated as hedging instruments on their balance sheets as of December 31, 2020 and 2019 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.
| Instrument | Balance Sheet Location | Gross Fair Value (a) | Offsetting Position (b) | Net Fair Value (c) (d) | Registrant | |||||||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||||||||
| 2020 | ||||||||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||||||||
| Natural gas swaps and options | Prepayments and other | $0.8 | $— | $0.8 | Entergy Louisiana | |||||||||||||||||||||||||||
| Natural gas swaps and options | Other deferred debits and other assets | $0.5 | $— | $0.5 | Entergy Louisiana | |||||||||||||||||||||||||||
| Financial transmission rights | Prepayments and other | $2.9 | ($0.2) | $2.7 | Entergy Arkansas | |||||||||||||||||||||||||||
| Financial transmission rights | Prepayments and other | $4.3 | ($0.1) | $4.2 | Entergy Louisiana | |||||||||||||||||||||||||||
| Financial transmission rights | Prepayments and other | $0.6 | $— | $0.6 | Entergy Mississippi | |||||||||||||||||||||||||||
| Financial transmission rights | Prepayments and other | $0.2 | ($0.1) | $0.1 | Entergy New Orleans | |||||||||||||||||||||||||||
| Financial transmission rights | Prepayments and other | $1.6 | $— | $1.6 | Entergy Texas | |||||||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||||||||
| Natural gas swaps and options | Other current liabilities | $0.3 | $— | $0.3 | Entergy Louisiana | |||||||||||||||||||||||||||
| Natural gas swaps and options | Other non-current liabilities | $1.3 | $— | $1.3 | Entergy Louisiana | |||||||||||||||||||||||||||
| Natural gas swaps | Other current liabilities | $5.0 | $— | $5.0 | Entergy Mississippi | |||||||||||||||||||||||||||
| Natural gas swaps | Other current liabilities | $0.3 | $— | $0.3 | Entergy New Orleans | |||||||||||||||||||||||||||
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| Instrument | Balance Sheet Location | Gross Fair Value (a) | Offsetting Position (b) | Net Fair Value (c) (d) | Registrant | |||||||||||||||||||||||||||
| 2019 | ||||||||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||||||||
| Natural gas swaps and options | Other deferred debits and other assets | $0.8 | $— | $0.8 | Entergy Louisiana | |||||||||||||||||||||||||||
| Financial transmission rights | Prepayments and other | $3.4 | ($0.1) | $3.3 | Entergy Arkansas | |||||||||||||||||||||||||||
| Financial transmission rights | Prepayments and other | $4.5 | $— | $4.5 | Entergy Louisiana | |||||||||||||||||||||||||||
| Financial transmission rights | Prepayments and other | $0.8 | $— | $0.8 | Entergy Mississippi | |||||||||||||||||||||||||||
| Financial transmission rights | Prepayments and other | $0.3 | $— | $0.3 | Entergy New Orleans | |||||||||||||||||||||||||||
| Financial transmission rights | Prepayments and other | $1.0 | ($0.1) | $0.9 | Entergy Texas | |||||||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||||||||
| Natural gas swaps and options | Other current liabilities | $2.4 | $— | $2.4 | Entergy Louisiana | |||||||||||||||||||||||||||
| Natural gas swaps and options | Other non-current liabilities | $2.2 | $— | $2.2 | Entergy Louisiana | |||||||||||||||||||||||||||
| Natural gas swaps | Other current liabilities | $2.3 | $— | $2.3 | Entergy Mississippi | |||||||||||||||||||||||||||
| Natural gas swaps | Other current liabilities | $0.2 | $— | $0.2 | Entergy New Orleans | |||||||||||||||||||||||||||
(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, 2020, letters of credit posted with MISO covered financial transmission rights exposure of $0.3 million for Entergy Louisiana, $0.2 million for Entergy Mississippi, $0.2 million for Entergy New Orleans, and $0.5 million for Entergy Texas. As of December 31, 2019, letters of credit posted with MISO covered financial transmission rights exposure of $0.2 million for Entergy Mississippi.
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The effects of the Registrant Subsidiaries’ derivative instruments not designated as hedging instruments on their income statements for the years ended December 31, 2020, 2019, and 2018 are as follows:
| Instrument | Income Statement Location | Amount of gain (loss) recorded in the income statement | Registrant | |||||||||||||||||
| (In Millions) | ||||||||||||||||||||
| 2020 | ||||||||||||||||||||
| Natural gas swaps | Fuel, fuel-related expenses, and gas purchased for resale | ($11.1) | (a) | Entergy Mississippi | ||||||||||||||||
| Natural gas swaps | Fuel, fuel-related expenses, and gas purchased for resale | ($0.8) | (a) | Entergy New Orleans | ||||||||||||||||
| Financial transmission rights | Purchased power | $26.7 | (b) | Entergy Arkansas | ||||||||||||||||
| Financial transmission rights | Purchased power | $19.6 | (b) | Entergy Louisiana | ||||||||||||||||
| Financial transmission rights | Purchased power | $3.0 | (b) | Entergy Mississippi | ||||||||||||||||
| Financial transmission rights | Purchased power | $1.4 | (b) | Entergy New Orleans | ||||||||||||||||
| Financial transmission rights | Purchased power | $40.4 | (b) | Entergy Texas | ||||||||||||||||
| 2019 | ||||||||||||||||||||
| Natural gas swaps and options | Fuel, fuel-related expenses, and gas purchased for resale | ($5.3) | (a) | Entergy Louisiana | ||||||||||||||||
| Natural gas swaps | Fuel, fuel-related expenses, and gas purchased for resale | ($7.7) | (a) | Entergy Mississippi | ||||||||||||||||
| Financial transmission rights | Purchased power | $22.3 | (b) | Entergy Arkansas | ||||||||||||||||
| Financial transmission rights | Purchased power | $46.7 | (b) | Entergy Louisiana | ||||||||||||||||
| Financial transmission rights | Purchased power | $6.8 | (b) | Entergy Mississippi | ||||||||||||||||
| Financial transmission rights | Purchased power | $2.7 | (b) | Entergy New Orleans | ||||||||||||||||
| Financial transmission rights | Purchased power | $15.7 | (b) | Entergy Texas | ||||||||||||||||
| 2018 | ||||||||||||||||||||
| Natural gas swaps | Fuel, fuel-related expenses, and gas purchased for resale | $4.4 | (a) | Entergy Louisiana | ||||||||||||||||
| Natural gas swaps | Fuel, fuel-related expenses, and gas purchased for resale | $3.2 | (a) | Entergy Mississippi | ||||||||||||||||
| Natural gas swaps | Fuel, fuel-related expenses, and gas purchased for resale | $0.2 | (a) | Entergy New Orleans | ||||||||||||||||
| Financial transmission rights | Purchased power | $25.3 | (b) | Entergy Arkansas | ||||||||||||||||
| Financial transmission rights | Purchased power | $72.7 | (b) | Entergy Louisiana | ||||||||||||||||
| Financial transmission rights | Purchased power | $26.3 | (b) | Entergy Mississippi | ||||||||||||||||
| Financial transmission rights | Purchased power | $13.8 | (b) | Entergy New Orleans | ||||||||||||||||
| Financial transmission rights | Purchased power | ($6.0) | (b) | Entergy Texas | ||||||||||||||||
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(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 other than those instruments held by the Entergy Wholesale Commodities business 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;
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–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 and derivative power contracts used as cash flow hedges of power sales at merchant power plants.
The values for power contract assets or liabilities are 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 are classified as Level 3 assets and liabilities. The valuations of these assets and liabilities are performed by the Office of Corporate Risk Oversight and the Entergy Wholesale Commodities Accounting group. The primary related functions of the Office of Corporate Risk Oversight include: gathering, validating and reporting market data, providing market risk analyses and valuations in support of Entergy Wholesale Commodities’ 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 is also responsible for managing the energy trading and risk management system, forecasting revenues, forward positions and analysis. The Entergy Wholesale Commodities Accounting group performs 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 Entergy Wholesale Commodities Accounting group reports to the Chief Accounting Officer.
The amounts reflected as the fair value of electricity swaps are based on the estimated amount that the contracts are 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 would equal the estimated amount receivable to or payable by Entergy if the contracts were settled at that date. These derivative contracts include cash flow hedges that swap fixed for floating cash flows for sales of the output from the Entergy Wholesale Commodities business. The fair values are 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 are recorded as derivative contract assets or liabilities. For contracts that have unit contingent terms, a further discount is 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 are valued based on a Black Scholes model, and are calculated at the end of each month for accounting purposes. Inputs to the valuation include end of day forward market prices for the period when the transactions will settle, 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 are reviewed and can be adjusted if it is determined that there is a better representation of fair value.
On a daily basis, the Office of Corporate Risk Oversight calculates the mark-to-market for electricity swaps and options. The Office of Corporate Risk Oversight also validates forward market prices by comparing them to other sources of forward market prices or to settlement prices of actual market transactions. Significant differences are 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 are also validated using actual counterparty quotes for Entergy Wholesale Commodities transactions when available and compared with other sources of market
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implied volatilities. Moreover, on a quarterly basis, the Office of Corporate Risk Oversight confirms the mark-to-market calculations and prepares price scenarios and credit downgrade scenario analysis. The scenario analysis is communicated to senior management within Entergy and within Entergy Wholesale Commodities. Finally, for all proposed derivative transactions, an analysis is completed to assess the risk of adding the proposed derivative to Entergy Wholesale Commodities’ portfolio. In particular, the credit and liquidity effects are calculated for this analysis. This analysis is communicated to senior management within Entergy and Entergy Wholesale Commodities.
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 Entergy Wholesale Commodities Accounting group review 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 Entergy Wholesale Commodities 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, 2020 and December 31, 2019. The assessment of the significance of a particular input to a fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels.
| 2020 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
| Temporary cash investments | $1,630 | $— | $— | $1,630 | ||||||||||||||||||||||
| Decommissioning trust funds (a): | ||||||||||||||||||||||||||
| Equity securities | 1,533 | — | — | 1,533 | ||||||||||||||||||||||
| Debt securities (b) | 919 | 1,698 | — | 2,617 | ||||||||||||||||||||||
| Common trusts (c) | 3,103 | |||||||||||||||||||||||||
| Power contracts | — | — | 38 | 38 | ||||||||||||||||||||||
| Securitization recovery trust account | 42 | — | — | 42 | ||||||||||||||||||||||
| Escrow accounts | 148 | — | — | 148 | ||||||||||||||||||||||
| Gas hedge contracts | 1 | 1 | — | 2 | ||||||||||||||||||||||
| Financial transmission rights | — | — | 9 | 9 | ||||||||||||||||||||||
| $4,273 | $1,699 | $47 | $9,122 | |||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
| Gas hedge contracts | $6 | $1 | $— | $7 | ||||||||||||||||||||||
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| 2019 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
| Temporary cash investments | $391 | $— | $— | $391 | ||||||||||||||||||||||
| Decommissioning trust funds (a): | ||||||||||||||||||||||||||
| Equity securities | 905 | — | — | 905 | ||||||||||||||||||||||
| Debt securities | 1,139 | 1,824 | — | 2,963 | ||||||||||||||||||||||
| Common trusts (c) | 2,536 | |||||||||||||||||||||||||
| Power contracts | — | — | 118 | 118 | ||||||||||||||||||||||
| Securitization recovery trust account | 47 | — | — | 47 | ||||||||||||||||||||||
| Escrow accounts | 459 | — | — | 459 | ||||||||||||||||||||||
| Gas hedge contracts | — | 1 | — | 1 | ||||||||||||||||||||||
| Financial transmission rights | — | — | 10 | 10 | ||||||||||||||||||||||
| $2,941 | $1,825 | $128 | $7,430 | |||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
| Gas hedge contracts | $5 | $2 | $— | $7 | ||||||||||||||||||||||
(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 herein for additional information on the investment portfolios.
(b)The decommissioning trust funds fair value presented herein does not include the recognition of a credit loss valuation allowance of $0.1 million on debt securities due to the adoption of ASU 2016-13. See Note 16 to the financial statements herein for additional information on the allowance for expected credit losses.
(c)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 (liabilities) for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the years ended December 31, 2020, 2019, and 2018:
| 2020 | 2019 | 2018 | ||||||||||||||||||||||||
| Power Contracts | Financial transmission rights | Power Contracts | Financial transmission rights | Power Contracts | Financial transmission rights | |||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
| Balance as of January 1, | $118 | $10 | ($31) | $15 | ($65) | $21 | ||||||||||||||||||||
| Total gains (losses) for the period (a) | ||||||||||||||||||||||||||
| Included in earnings | 1 | 1 | 12 | — | 2 | (1) | ||||||||||||||||||||
| Included in other comprehensive income | 77 | — | 232 | — | (40) | — | ||||||||||||||||||||
| Included as a regulatory liability/asset | — | 67 | — | 54 | — | 80 | ||||||||||||||||||||
| Issuances of financial transmission rights | — | 23 | — | 35 | — | 46 | ||||||||||||||||||||
| Settlements | (158) | (92) | (95) | (94) | 72 | (131) | ||||||||||||||||||||
| Balance as of December 31, | $38 | $9 | $118 | $10 | ($31) | $15 | ||||||||||||||||||||
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(a) Change in unrealized gains or losses for the period included in earnings for derivatives held at the end of the reporting period is ($0.3) million, ($9.2) million, and ($3.5) million for the years ended December 31, 2020, 2019, and 2018, respectively.
The following table sets forth a description of the types of transactions classified as Level 3 in the fair value hierarchy and significant unobservable inputs to each which cause that classification, as of December 31, 2020:
| Transaction Type | Fair Value as of December 31, 2020 | Significant Unobservable Inputs | Range from Average % | Effect on Fair Value | ||||||||||||||||||||||
| (In Millions) | (In Millions) | |||||||||||||||||||||||||
| Power contracts - electricity swaps | $38 | Unit contingent discount | 4.75% | $4 | ||||||||||||||||||||||
The values of 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 | Position | 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, 2020 and December 31, 2019. The assessment of the significance of a particular input to a fair value measurement requires judgment and may affect its placement within the fair value hierarchy levels.
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Entergy Arkansas
| 2020 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
| Temporary cash investments | $168.0 | $— | $— | $168.0 | ||||||||||||||||||||||
| Decommissioning trust funds (a): | ||||||||||||||||||||||||||
| Equity securities | 1.3 | — | — | 1.3 | ||||||||||||||||||||||
| Debt securities | 98.2 | 349.7 | — | 447.9 | ||||||||||||||||||||||
| Common trusts (b) | 824.7 | |||||||||||||||||||||||||
| Financial transmission rights | — | — | 2.7 | 2.7 | ||||||||||||||||||||||
| $267.5 | $349.7 | $2.7 | $1,444.6 | |||||||||||||||||||||||
| 2019 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
| Decommissioning trust funds (a): | ||||||||||||||||||||||||||
| Equity securities | $0.6 | $— | $— | $0.6 | ||||||||||||||||||||||
| Debt securities | 108.7 | 304.1 | — | 412.8 | ||||||||||||||||||||||
| Common trusts (b) | 687.9 | |||||||||||||||||||||||||
| Securitization recovery trust account | 4.0 | — | — | 4.0 | ||||||||||||||||||||||
| Financial transmission rights | — | — | 3.3 | 3.3 | ||||||||||||||||||||||
| $113.3 | $304.1 | $3.3 | $1,108.6 | |||||||||||||||||||||||
Entergy Louisiana
| 2020 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
| Temporary cash investments | $726.7 | $— | $— | $726.7 | ||||||||||||||||||||||
| Decommissioning trust funds (a): | ||||||||||||||||||||||||||
| Equity securities | 8.7 | — | — | 8.7 | ||||||||||||||||||||||
| Debt securities | 172.4 | 459.8 | — | 632.2 | ||||||||||||||||||||||
| Common trusts (b) | 1,153.1 | |||||||||||||||||||||||||
| Securitization recovery trust account | 2.7 | — | — | 2.7 | ||||||||||||||||||||||
| Gas hedge contracts | 0.8 | 0.5 | — | 1.3 | ||||||||||||||||||||||
| Financial transmission rights | — | — | 4.2 | 4.2 | ||||||||||||||||||||||
| $911.3 | $460.3 | $4.2 | $2,528.9 | |||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
| Gas hedge contracts | $0.3 | $1.3 | $— | $1.6 | ||||||||||||||||||||||
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| 2019 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
| Temporary cash investments | $1.5 | $— | $— | $1.5 | ||||||||||||||||||||||
| Decommissioning trust funds (a): | ||||||||||||||||||||||||||
| Equity securities | 4.3 | — | — | 4.3 | ||||||||||||||||||||||
| Debt securities | 180.8 | 420.7 | — | 601.5 | ||||||||||||||||||||||
| Common trusts (b) | 958.0 | |||||||||||||||||||||||||
| Escrow accounts | 295.9 | — | — | 295.9 | ||||||||||||||||||||||
| Securitization recovery trust account | 3.7 | — | — | 3.7 | ||||||||||||||||||||||
| Gas hedge contracts | — | 0.8 | — | 0.8 | ||||||||||||||||||||||
| Financial transmission rights | — | — | 4.5 | 4.5 | ||||||||||||||||||||||
| $486.2 | $421.5 | $4.5 | $1,870.2 | |||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
| Gas hedge contracts | $2.4 | $2.2 | $— | $4.6 | ||||||||||||||||||||||
Entergy Mississippi
| 2020 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
| Escrow accounts | $64.6 | $— | $— | $64.6 | ||||||||||||||||||||||
| Financial transmission rights | — | — | 0.6 | 0.6 | ||||||||||||||||||||||
| $64.6 | $— | $0.6 | $65.2 | |||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
| Gas hedge contracts | $5.0 | $— | $— | $5.0 | ||||||||||||||||||||||
| 2019 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
| Temporary cash investments | $51.6 | $— | $— | $51.6 | ||||||||||||||||||||||
| Escrow accounts | 80.2 | — | — | 80.2 | ||||||||||||||||||||||
| Financial transmission rights | — | — | 0.8 | 0.8 | ||||||||||||||||||||||
| $131.8 | $— | $0.8 | $132.6 | |||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
| Gas hedge contracts | $2.3 | $— | $— | $2.3 | ||||||||||||||||||||||
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Entergy New Orleans
| 2020 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
| Securitization recovery trust account | $3.4 | $— | $— | $3.4 | ||||||||||||||||||||||
| Escrow accounts | 83.0 | — | — | 83.0 | ||||||||||||||||||||||
| Financial transmission rights | — | — | 0.1 | 0.1 | ||||||||||||||||||||||
| $86.4 | $— | $0.1 | $86.5 | |||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
| Gas hedge contracts | $0.3 | $— | $— | $0.3 | ||||||||||||||||||||||
| 2019 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
| Temporary cash investments | $6.0 | $— | $— | $6.0 | ||||||||||||||||||||||
| Securitization recovery trust account | 2.0 | — | — | 2.0 | ||||||||||||||||||||||
| Escrow accounts | 82.6 | — | — | 82.6 | ||||||||||||||||||||||
| Financial transmission rights | — | — | 0.3 | 0.3 | ||||||||||||||||||||||
| $90.6 | $— | $0.3 | $90.9 | |||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
| Gas hedge contracts | $0.2 | $— | $— | $0.2 | ||||||||||||||||||||||
Entergy Texas
| 2020 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||
| Temporary cash investments | $248.6 | $— | $— | $248.6 | ||||||||||||||||||||||
| Securitization recovery trust account | 36.2 | — | — | 36.2 | ||||||||||||||||||||||
| Financial transmission rights | — | — | 1.6 | 1.6 | ||||||||||||||||||||||
| $284.8 | $— | $1.6 | $286.4 | |||||||||||||||||||||||
| 2019 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||
| Temporary cash investments | $12.9 | $— | $— | $12.9 | ||||||||||||||||||||||
| Securitization recovery trust account | 37.7 | — | — | 37.7 | ||||||||||||||||||||||
| Financial transmission rights | — | — | 0.9 | 0.9 | ||||||||||||||||||||||
| $50.6 | $— | $0.9 | $51.5 | |||||||||||||||||||||||
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System Energy
| 2020 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
| Temporary cash investments | $216.4 | $— | $— | $216.4 | ||||||||||||||||||||||
| Decommissioning trust funds (a): | ||||||||||||||||||||||||||
| Equity securities | 3.8 | — | — | 3.8 | ||||||||||||||||||||||
| Debt securities | 177.3 | 250.4 | — | 427.7 | ||||||||||||||||||||||
| Common trusts (b) | 784.4 | |||||||||||||||||||||||||
| $397.5 | $250.4 | $— | $1,432.3 | |||||||||||||||||||||||
| 2019 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
| Temporary cash investments | $68.4 | $— | $— | $68.4 | ||||||||||||||||||||||
| Decommissioning trust funds (a): | ||||||||||||||||||||||||||
| Equity securities | 13.3 | — | — | 13.3 | ||||||||||||||||||||||
| Debt securities | 176.3 | 209.9 | — | 386.2 | ||||||||||||||||||||||
| Common trusts (b) | 654.6 | |||||||||||||||||||||||||
| $258.0 | $209.9 | $— | $1,122.5 | |||||||||||||||||||||||
(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 herein 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, 2020.
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||||||||
| Balance as of January 1, 2020 | $3.3 | $4.5 | $0.8 | $0.3 | $0.9 | ||||||||||||||||||||||||
| Issuances of financial transmission rights | 6.5 | 13.2 | 1.4 | (0.1) | 2.4 | ||||||||||||||||||||||||
| Gains (losses) included as a regulatory liability/asset | 19.6 | 6.1 | 1.4 | 1.3 | 38.7 | ||||||||||||||||||||||||
| Settlements | (26.7) | (19.6) | (3.0) | (1.4) | (40.4) | ||||||||||||||||||||||||
| Balance as of December 31, 2020 | $2.7 | $4.2 | $0.6 | $0.1 | $1.6 | ||||||||||||||||||||||||
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The following table sets forth a reconciliation of changes in the net assets (liabilities) for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the year ended December 31, 2019.
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||||||||
| Balance as of January 1, 2019 | $3.4 | $8.3 | $2.2 | $1.3 | ($0.5) | ||||||||||||||||||||||||
| Issuances of financial transmission rights | 9.6 | 18.7 | 3.9 | 2.7 | 0.1 | ||||||||||||||||||||||||
| Gains (losses) included as a regulatory liability/asset | 12.6 | 24.2 | 1.5 | (1.0) | 17.0 | ||||||||||||||||||||||||
| Settlements | (22.3) | (46.7) | (6.8) | (2.7) | (15.7) | ||||||||||||||||||||||||
| Balance as of December 31, 2019 | $3.3 | $4.5 | $0.8 | $0.3 | $0.9 | ||||||||||||||||||||||||
NOTE 16. DECOMMISSIONING TRUST FUNDS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
The NRC requires Entergy subsidiaries to maintain nuclear decommissioning trusts to fund the costs of decommissioning ANO 1, ANO 2, River Bend, Waterford 3, Grand Gulf, Indian Point 1, Indian Point 2, Indian Point 3, and Palisades. 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, the Registrant Subsidiaries have recorded an offsetting amount of unrealized gains/(losses) on investment securities 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 Entergy Wholesale Commodities nuclear plants do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains/(losses) recorded on the equity securities in the trust funds are recognized in earnings. Unrealized gains recorded on the available-for-sale debt securities in the trust funds are recognized in the accumulated other comprehensive income component of shareholders’ equity. Unrealized losses (where cost exceeds fair market value) on the available-for-sale debt securities in the trust funds are also recorded in the accumulated other comprehensive income component of shareholders’ equity unless the unrealized loss is other than temporary and therefore recorded in earnings. A portion of Entergy’s decommissioning trust funds were held in a wholly-owned registered investment company, and unrealized gains and losses on both the equity and debt securities held in the registered investment company were recognized in earnings. In December 2020, Entergy liquidated its interest in the registered investment company. 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.
The unrealized gains/(losses) recognized during the year ended December 31, 2020 on equity securities still held as of December 31, 2020 were $531 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.
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The available-for-sale securities held as of December 31, 2020 and 2019 are summarized as follows:
| Fair Value | Total Unrealized Gains | Total Unrealized Losses | ||||||||||||||||||
| (In Millions) | ||||||||||||||||||||
| 2020 | ||||||||||||||||||||
| Debt Securities (a) | $2,617 | $197 | $3 | |||||||||||||||||
| 2019 | ||||||||||||||||||||
| Debt Securities (a) | $2,456 | $96 | $6 | |||||||||||||||||
(a) Debt securities presented herein do not include the $507 million of debt securities held in the wholly-owned registered investment company as of December 31, 2019, which are not accounted for as available-for-sale.
The unrealized gains/(losses) above are reported before deferred taxes of $31 million as of December 31, 2020 and $13 million as of December 31, 2019 for debt securities. The amortized cost of available-for-sale debt securities was $2,423 million as of December 31, 2020 and $2,366 million as of December 31, 2019. As of December 31, 2020, available-for-sale debt securities have an average coupon rate of approximately 3.01%, an average duration of approximately 7.36 years, and an average maturity of approximately 10.72 years.
The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2020:
| Fair Value | Gross Unrealized Losses | ||||||||||
| (In Millions) | |||||||||||
| Less than 12 months | $187 | $3 | |||||||||
| More than 12 months | 2 | — | |||||||||
| Total | $189 | $3 | |||||||||
The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2019:
| Fair Value | Gross Unrealized Losses | ||||||||||
| (In Millions) | |||||||||||
| Less than 12 months | $404 | $5 | |||||||||
| More than 12 months | 38 | 1 | |||||||||
| Total | $442 | $6 | |||||||||
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The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2020 and 2019 are as follows:
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
| Less than 1 year | ($4) | $128 | |||||||||
| 1 year - 5 years | 672 | 807 | |||||||||
| 5 years - 10 years | 852 | 666 | |||||||||
| 10 years - 15 years | 377 | 125 | |||||||||
| 15 years - 20 years | 144 | 126 | |||||||||
| 20 years+ | 576 | 604 | |||||||||
| Total | $2,617 | $2,456 | |||||||||
During the years ended December 31, 2020, 2019, and 2018, proceeds from the dispositions of available-for-sale securities amounted to $1,024 million, $1,427 million, and $2,406 million, respectively. During the years ended December 31, 2020, 2019, and 2018, gross gains of $47 million, $25 million, and $7 million, respectively, and gross losses of $4 million, $4 million, and $47 million, respectively, related to available-for-sale securities were reclassified out of other comprehensive income or other regulatory liabilities/assets into earnings.
The fair values of the decommissioning trust funds related to the Entergy Wholesale Commodities nuclear plants as of December 31, 2020 are $631 million for Indian Point 1, $794 million for Indian Point 2, $991 million for Indian Point 3, and $554 million for Palisades. The fair values of the decommissioning trust funds related to the Entergy Wholesale Commodities nuclear plants as of December 31, 2019 are $556 million for Indian Point 1, $701 million for Indian Point 2, $930 million for Indian Point 3, and $498 million for Palisades. The fair values of the decommissioning trust funds for the Registrant Subsidiaries’ nuclear plants are detailed below.
Entergy Arkansas
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, 2020 and 2019 are summarized as follows:
| Fair Value | Total Unrealized Gains | Total Unrealized Losses | ||||||||||||||||||
| (In Millions) | ||||||||||||||||||||
| 2020 | ||||||||||||||||||||
| Debt Securities | $447.9 | $27.7 | $0.3 | |||||||||||||||||
| 2019 | ||||||||||||||||||||
| Debt Securities | $412.8 | $9.9 | $2.6 | |||||||||||||||||
The amortized cost of available-for-sale debt securities was $420.4 million as of December 31, 2020 and $405.4 million as of December 31, 2019. As of December 31, 2020, the available-for-sale debt securities have an average coupon rate of approximately 2.57%, an average duration of approximately 6.97 years, and an average maturity of approximately 8.24 years.
The unrealized gains/(losses) recognized during the year ended December 31, 2020 on equity securities still held as of December 31, 2020 were $116.8 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.
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The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2020:
| Fair Value | Gross Unrealized Losses | ||||||||||
| (In Millions) | |||||||||||
| Less than 12 months | $29.9 | $0.3 | |||||||||
| More than 12 months | — | — | |||||||||
| Total | $29.9 | $0.3 | |||||||||
The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2019:
| Fair Value | Gross Unrealized Losses | ||||||||||
| (In Millions) | |||||||||||
| Less than 12 months | $104.8 | $2.5 | |||||||||
| More than 12 months | 7.7 | 0.1 | |||||||||
| Total | $112.5 | $2.6 | |||||||||
The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2020 and 2019 are as follows:
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
| Less than 1 year | $— | $44.1 | |||||||||
| 1 year - 5 years | 113.1 | 109.1 | |||||||||
| 5 years - 10 years | 189.8 | 156.0 | |||||||||
| 10 years - 15 years | 81.4 | 31.3 | |||||||||
| 15 years - 20 years | 28.5 | 23.8 | |||||||||
| 20 years+ | 35.1 | 48.5 | |||||||||
| Total | $447.9 | $412.8 | |||||||||
During the years ended December 31, 2020, 2019, and 2018, proceeds from the dispositions of available-for-sale securities amounted to $94.5 million, $110.6 million, and $82.1 million, respectively. During the years ended December 31, 2020, 2019, and 2018, gross gains of $8.8 million, $2.9 million, and $0.1 million, respectively, and gross losses of $0.2 million, $0.1 million, and $2.9 million, respectively, related to available-for-sale securities were reclassified out of other regulatory liabilities/assets into earnings.
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Entergy Louisiana
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, 2020 and 2019 are summarized as follows:
| Fair Value | Total Unrealized Gains | Total Unrealized Losses | ||||||||||||||||||
| (In Millions) | ||||||||||||||||||||
| 2020 | ||||||||||||||||||||
| Debt Securities | $632.2 | $51.3 | $0.5 | |||||||||||||||||
| 2019 | ||||||||||||||||||||
| Debt Securities | $601.5 | $29.3 | $0.8 | |||||||||||||||||
The amortized cost of available-for-sale debt securities was $581.4 million as of December 31, 2020 and $573 million as of December 31, 2019. As of December 31, 2020, the available-for-sale debt securities have an average coupon rate of approximately 3.64%, an average duration of approximately 7.25 years, and an average maturity of approximately 12.73 years.
The unrealized gains/(losses) recognized during the year ended December 31, 2020 on equity securities still held as of December 31, 2020 were $163.6 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 have been in a continuous loss position, are as follows as of December 31, 2020:
| Fair Value | Gross Unrealized Losses | ||||||||||
| (In Millions) | |||||||||||
| Less than 12 months | $36.4 | $0.5 | |||||||||
| More than 12 months | 0.8 | — | |||||||||
| Total | $37.2 | $0.5 | |||||||||
The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2019:
| Fair Value | Gross Unrealized Losses | ||||||||||
| (In Millions) | |||||||||||
| Less than 12 months | $71.2 | $0.8 | |||||||||
| More than 12 months | 7.9 | — | |||||||||
| Total | $79.1 | $0.8 | |||||||||
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The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2020 and 2019 are as follows:
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
| Less than 1 year | $— | $40.7 | |||||||||
| 1 year - 5 years | 117.0 | 142.0 | |||||||||
| 5 years - 10 years | 159.4 | 132.4 | |||||||||
| 10 years - 15 years | 101.2 | 39.8 | |||||||||
| 15 years - 20 years | 66.9 | 49.2 | |||||||||
| 20 years+ | 187.7 | 197.4 | |||||||||
| Total | $632.2 | $601.5 | |||||||||
During the years ended December 31, 2020, 2019, and 2018, proceeds from the dispositions of available-for-sale securities amounted to $159.7 million, $186 million, and $401.7 million, respectively. During the years ended December 31, 2020, 2019, and 2018, gross gains of $8.1 million, $4.8 million, and $2.1 million, respectively, and gross losses of $0.7 million, $0.3 million, and $7.5 million, respectively, related to available-for-sale securities were reclassified out of other regulatory liabilities/assets into earnings.
System Energy
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, 2020 and 2019 are summarized as follows:
| Fair Value | Total Unrealized Gains | Total Unrealized Losses | ||||||||||||||||||
| (In Millions) | ||||||||||||||||||||
| 2020 | ||||||||||||||||||||
| Debt Securities | $427.7 | $30.0 | $0.8 | |||||||||||||||||
| 2019 | ||||||||||||||||||||
| Debt Securities | $386.2 | $15.1 | $0.3 | |||||||||||||||||
The amortized cost of available-for-sale debt securities was $398.4 million as of December 31, 2020 and $371.4 million as of December 31, 2019. As of December 31, 2020, the available-for-sale debt securities have an average coupon rate of approximately 2.74%, an average duration of approximately 7.54 years, and an average maturity of approximately 11.09 years.
The unrealized gains/(losses) recognized during the year ended December 31, 2020 on equity securities still held as of December 31, 2020 were $111.1 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.
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The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2020:
| Fair Value | Gross Unrealized Losses | ||||||||||
| (In Millions) | |||||||||||
| Less than 12 months | $28.9 | $0.8 | |||||||||
| More than 12 months | — | — | |||||||||
| Total | $28.9 | $0.8 | |||||||||
The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2019:
| Fair Value | Gross Unrealized Losses | ||||||||||
| (In Millions) | |||||||||||
| Less than 12 months | $56.9 | $0.3 | |||||||||
| More than 12 months | 0.3 | — | |||||||||
| Total | $57.2 | $0.3 | |||||||||
The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2020 and 2019 are as follows:
| 2020 | 2019 | ||||||||||
| (In Millions) | |||||||||||
| Less than 1 year | ($1.1) | $8.5 | |||||||||
| 1 year - 5 years | 134.7 | 154.6 | |||||||||
| 5 years - 10 years | 141.5 | 92.3 | |||||||||
| 10 years - 15 years | 31.5 | 13.4 | |||||||||
| 15 years - 20 years | 5.3 | 14.4 | |||||||||
| 20 years+ | 115.8 | 103.0 | |||||||||
| Total | $427.7 | $386.2 | |||||||||
During the years ended December 31, 2020, 2019, and 2018, proceeds from the dispositions of available-for-sale securities amounted to $252.2 million, $338.1 million, and $361.9 million, respectively. During the years ended December 31, 2020, 2019, and 2018, gross gains of $11.5 million, $5.4 million, and $0.5 million, respectively, and gross losses of $0.6 million, $0.7 million, and $6.1 million, respectively, related to available-for-sale securities were reclassified out of other regulatory liabilities/assets into earnings.
Allowance for expected credit losses
Entergy implemented ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, effective January 1, 2020. In accordance with the new standard, Entergy estimates the expected credit losses for its available for sale securities based on the current credit rating and remaining life of the securities. To the extent an individual security is determined to be uncollectible it is written off against this allowance. Entergy’s available-for-sale securities are held in trusts managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. Specifically, available-for-sale securities are subject to credit worthiness restrictions, with requirements for both the average credit rating of the portfolio and minimum credit ratings for individual debt
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securities. As of December 31, 2020, Entergy’s allowance for expected credit losses related to available-for-sale securities was $0.1 million. Entergy did not record any impairments of available-for-sale debt securities for the year ended December 31, 2020.
Other-than-temporary impairments and unrealized gains and losses
Prior to the implementation of ASU 2016-13 on January 1, 2020, Entergy evaluated the available-for-sale debt securities in the Entergy Wholesale Commodities nuclear decommissioning trust funds with unrealized losses at the end of each period to determine whether an other-than-temporary impairment had occurred. The assessment of whether an investment in a debt security suffered an other-than-temporary impairment was based on whether Entergy had the intent to sell or more likely than not would have been required to sell the debt security before recovery of its amortized costs. Further, if Entergy did not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment was considered to have occurred and it was measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). Entergy did not have any material other-than-temporary impairments relating to credit losses on debt securities for the years ended December 31, 2019 and 2018.
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 responsible to repurchase nuclear fuel 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 Gulf States Reconstruction Funding I, LLC, and Entergy Texas Restoration Funding, LLC, companies wholly-owned and consolidated by Entergy Texas, are variable interest entities and Entergy Texas is the primary beneficiary. In June 2007, Entergy Gulf States Reconstruction Funding issued senior secured transition bonds (securitization bonds) to finance Entergy Texas’s Hurricane Rita reconstruction costs. 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. With the proceeds, the variable interest entities purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition 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 variable interest entities, including the transition property, and the creditors
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of the variable interest entities do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to the variable interest entities except to remit transition charge collections. See Note 5 to the financial statements for additional details regarding the securitization bonds.
Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, is a variable interest entity and Entergy Arkansas is the primary beneficiary. In August 2010, Entergy Arkansas Restoration Funding issued storm cost recovery bonds to finance Entergy Arkansas’s January 2009 ice storm damage restoration costs. With the proceeds, Entergy Arkansas Restoration Funding purchased from Entergy Arkansas 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 Arkansas balance sheet as of December 31, 2019. Although the principal amount was not due until August 2021, Entergy Arkansas Restoration Funding made principal payments on the bonds in 2020, after which the bonds were fully repaid. See Note 5 to the financial statements for additional details regarding the storm cost recovery bonds.
Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, is a variable interest entity 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. The investment recovery property is reflected as a regulatory asset on the consolidated Entergy Louisiana balance sheet. The creditors of Entergy Louisiana do not have recourse to the assets or revenues of Entergy Louisiana Investment Recovery Funding, including the investment recovery property, and the creditors of Entergy Louisiana Investment Recovery Funding do not have recourse to the assets or revenues of Entergy Louisiana. Entergy Louisiana has no payment obligations to Entergy Louisiana Investment Recovery Funding except to remit investment recovery charge collections. 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 variable interest entity, 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.
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 on its lease, including interest, of $17.2 million in 2020, $17.2 million in 2019, and $17.2 million in 2018. 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
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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 unlikely 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.
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 variable interest entities. 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 Entergy’s money pool and earn interest income from the money pool. As described in Note 2 to the financial statements, Entergy Louisiana receives preferred membership interest distributions from Entergy Holdings Company.
The tables below contain the various affiliate transactions of the Utility operating companies, System Energy, and other Entergy affiliates.
Intercompany Revenues
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||||||||||||||
| 2020 | $105.2 | $280.5 | $1.2 | $— | $40.4 | $520.7 | |||||||||||||||||||||||||||||
| 2019 | $117.5 | $277.8 | $1.4 | $— | $51.6 | $584.1 | |||||||||||||||||||||||||||||
| 2018 | $104.3 | $299.0 | $2.5 | $— | $58.8 | $456.7 | |||||||||||||||||||||||||||||
Intercompany Operating Expenses
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||||||||||||||
| 2020 | $515.5 | $661.5 | $283.3 | $266.0 | $260.3 | $177.4 | |||||||||||||||||||||||||||||
| 2019 | $534.0 | $665.4 | $306.7 | $292.1 | $255.0 | $156.2 | |||||||||||||||||||||||||||||
| 2018 | $471.9 | $627.8 | $266.8 | $256.4 | $240.2 | $176.5 | |||||||||||||||||||||||||||||
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Intercompany Interest and Investment Income
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||||||||||||||
| 2020 | $— | $127.7 | $0.1 | $— | $— | $0.2 | |||||||||||||||||||||||||||||
| 2019 | $0.4 | $128.5 | $0.4 | $— | $0.4 | $1.0 | |||||||||||||||||||||||||||||
| 2018 | $0.4 | $128.2 | $— | $— | $0.2 | $1.2 | |||||||||||||||||||||||||||||
Transactions with Equity Method Investees
EWO Marketing, LLC, an indirect wholly-owned subsidiary of Entergy, paid capacity charges and gas transportation to RS Cogen in the amounts of $26 million in 2020, $24.5 million in 2019, and $24 million in 2018.
Entergy’s operating transactions with its other equity method investees were not significant in 2020, 2019, or 2018.
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, 2020 and 2019 are as follows:
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| Utility: | ||||||||||||||
| Residential | $3,550,317 | $3,531,500 | ||||||||||||
| Commercial | 2,292,740 | 2,475,586 | ||||||||||||
| Industrial | 2,331,170 | 2,541,287 | ||||||||||||
| Governmental | 212,131 | 228,470 | ||||||||||||
| Total billed retail | 8,386,358 | 8,776,843 | ||||||||||||
| Sales for resale (a) | 295,810 | 285,722 | ||||||||||||
| Other electric revenues (b) | 348,102 | 343,143 | ||||||||||||
| Revenues from contracts with customers | 9,030,270 | 9,405,708 | ||||||||||||
| Other revenues (c) | 16,373 | 24,270 | ||||||||||||
| Total electric revenues | 9,046,643 | 9,429,978 | ||||||||||||
| Natural gas | 124,008 | 153,954 | ||||||||||||
| Entergy Wholesale Commodities: | ||||||||||||||
| Competitive businesses sales from contracts with customers (a) | 771,360 | 1,164,552 | ||||||||||||
| Other revenues (c) | 171,625 | 130,189 | ||||||||||||
| Total competitive businesses revenues | 942,985 | 1,294,741 | ||||||||||||
| Total operating revenues | $10,113,636 | $10,878,673 | ||||||||||||
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The Registrant Subsidiaries’ total revenues for the year ended December 31, 2020 were as follows:
| 2020 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||
| Residential | $841,162 | $1,270,187 | $523,379 | $243,502 | $672,087 | |||||||||||||||||||||||||||
| Commercial | 466,273 | 886,548 | 395,875 | 179,406 | 364,638 | |||||||||||||||||||||||||||
| Industrial | 461,907 | 1,314,234 | 145,100 | 24,248 | 385,681 | |||||||||||||||||||||||||||
| Governmental | 18,011 | 68,901 | 41,955 | 59,819 | 23,445 | |||||||||||||||||||||||||||
| Total billed retail | 1,787,353 | 3,539,870 | 1,106,309 | 506,975 | 1,445,851 | |||||||||||||||||||||||||||
| Sales for resale (a) | 173,115 | 333,594 | 77,530 | 33,213 | 100,273 | |||||||||||||||||||||||||||
| Other electric revenues (b) | 109,642 | 141,004 | 54,590 | 8,294 | 39,981 | |||||||||||||||||||||||||||
| Revenues from contracts with customers | 2,070,110 | 4,014,468 | 1,238,429 | 548,482 | 1,586,105 | |||||||||||||||||||||||||||
| Other revenues (c) | 14,384 | 4,595 | 9,425 | 12,150 | 1,020 | |||||||||||||||||||||||||||
| Total electric revenues | 2,084,494 | 4,019,063 | 1,247,854 | 560,632 | 1,587,125 | |||||||||||||||||||||||||||
| Natural gas | — | 50,799 | — | 73,209 | — | |||||||||||||||||||||||||||
| Total operating revenues | $2,084,494 | $4,069,862 | $1,247,854 | $633,841 | $1,587,125 | |||||||||||||||||||||||||||
The Registrant Subsidiaries’ total revenues for the year ended December 31, 2019 were as follows:
| 2019 | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | |||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||
| Residential | $795,269 | $1,270,478 | $562,219 | $245,081 | $658,453 | |||||||||||||||||||||||||||
| Commercial | 538,850 | 947,412 | 444,173 | 202,138 | 343,013 | |||||||||||||||||||||||||||
| Industrial | 520,958 | 1,450,966 | 164,491 | 31,824 | 373,048 | |||||||||||||||||||||||||||
| Governmental | 20,795 | 71,046 | 44,300 | 70,865 | 21,464 | |||||||||||||||||||||||||||
| Total billed retail | 1,875,872 | 3,739,902 | 1,215,183 | 549,908 | 1,395,978 | |||||||||||||||||||||||||||
| Sales for resale (a) | 257,864 | 333,395 | 39,295 | 38,626 | 59,074 | |||||||||||||||||||||||||||
| Other electric revenues (b) | 112,618 | 135,783 | 58,269 | 9,842 | 32,424 | |||||||||||||||||||||||||||
| Revenues from contracts with customers | 2,246,354 | 4,209,080 | 1,312,747 | 598,376 | 1,487,476 | |||||||||||||||||||||||||||
| Other revenues (c) | 13,240 | 13,947 | 10,296 | (3,959) | 1,479 | |||||||||||||||||||||||||||
| Total electric revenues | 2,259,594 | 4,223,027 | 1,323,043 | 594,417 | 1,488,955 | |||||||||||||||||||||||||||
| Natural gas | — | 62,148 | — | 91,806 | — | |||||||||||||||||||||||||||
| Total operating revenues | $2,259,594 | $4,285,175 | $1,323,043 | $686,223 | $1,488,955 | |||||||||||||||||||||||||||
(a)Sales for resale and competitive businesses sales include 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 and unbilled revenue.
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(c)Other revenues include the settlement of financial hedges, occasional sales of inventory, alternative revenue programs, provisions for revenue subject to refund, and late fees.
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 its 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.
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Competitive Businesses Revenues
The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power and capacity produced by its operating plants to wholesale customers. The majority of Entergy Wholesale Commodities’ revenues are from Entergy’s nuclear power plants located in the northern United States. Entergy issues monthly invoices to the counterparties for these electric sales at the respective contracted or ISO market rate of electricity and related services provided during the previous month.
Almost all of the Palisades nuclear plant output is sold under a 15-year PPA with Consumers Energy, executed as part of the acquisition of the plant in 2007 and expiring in April 2022. Prices under the original PPA range from $43.50/MWh in 2007 to $61.50/MWh in 2022, and the average price under the PPA is $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 issues 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 amortizes a liability to revenue over the life of the agreement. The amount amortized each period is 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 $11 million in 2020, $10 million in 2019, and $6 million in 2018. Amounts to be amortized to revenue through the remaining life of the agreement will be approximately $12 million in 2021 and $5 million in 2022.
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 of the subsidiaries within the Entergy Wholesale Commodities segment have operations and maintenance 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
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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. Due to the effect of the COVID-19 pandemic on customer receivables, however, Entergy recorded an increase in its allowance for doubtful accounts, as shown below:
| Entergy | Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | ||||||||||||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2019 | $7.4 | $1.2 | $1.9 | $0.6 | $3.2 | $0.5 | |||||||||||||||||||||||||||||
| Provisions (a) | 109.0 | 16.2 | 43.7 | 18.8 | 14.1 | 16.2 | |||||||||||||||||||||||||||||
| Write-offs | (8.6) | (1.8) | (3.5) | (1.2) | (1.0) | (1.1) | |||||||||||||||||||||||||||||
| Recoveries | 9.9 | 2.7 | 3.6 | 1.3 | 1.1 | 1.2 | |||||||||||||||||||||||||||||
| Balance as of December 31, 2020 | $117.7 | $18.3 | $45.7 | $19.5 | $17.4 | $16.8 | |||||||||||||||||||||||||||||
(a)Provisions include estimated incremental bad debt expenses resulting from the COVID-19 pandemic of $87.1 million for Entergy, $10.5 million for Entergy Arkansas, $36 million for Entergy Louisiana, $15.5 million for Entergy Mississippi, $12.2 million for Entergy New Orleans, and $12.9 million for Entergy Texas that have been deferred as regulatory assets. See Note 2 to the financial statements for discussion of the COVID-19 orders issued by retail regulators.
The allowance for currently expected credit losses 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.
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NOTE 20. QUARTERLY FINANCIAL DATA (UNAUDITED) (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Operating results for the four quarters of 2020 and 2019 for Entergy Corporation and subsidiaries were:
| Operating Revenues | Operating Income | Consolidated Net Income | Net Income Attributable to Entergy Corporation | ||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||
| 2020: | |||||||||||||||||||||||
| First Quarter | $2,427,179 | $399,756 | $123,294 | $118,714 | |||||||||||||||||||
| Second Quarter | $2,412,788 | $439,311 | $365,113 | $360,533 | |||||||||||||||||||
| Third Quarter | $2,903,568 | $778,016 | $525,699 | $521,119 | |||||||||||||||||||
| Fourth Quarter | $2,370,101 | $152,112 | $392,547 | $387,968 | |||||||||||||||||||
| 2019: | |||||||||||||||||||||||
| First Quarter | $2,609,584 | $283,254 | $258,646 | $254,537 | |||||||||||||||||||
| Second Quarter | $2,666,209 | $338,775 | $240,533 | $236,424 | |||||||||||||||||||
| Third Quarter | $3,140,575 | $519,929 | $369,459 | $365,240 | |||||||||||||||||||
| Fourth Quarter | $2,462,305 | $248,539 | $389,606 | $385,025 | |||||||||||||||||||
Earnings per average common share
| 2020 | 2019 | ||||||||||||||||||||||
| Basic | Diluted | Basic | Diluted | ||||||||||||||||||||
| First Quarter | $0.59 | $0.59 | $1.34 | $1.32 | |||||||||||||||||||
| Second Quarter | $1.80 | $1.79 | $1.22 | $1.22 | |||||||||||||||||||
| Third Quarter | $2.60 | $2.59 | $1.84 | $1.82 | |||||||||||||||||||
| Fourth Quarter | $1.95 | $1.93 | $1.96 | $1.94 | |||||||||||||||||||
Results of operations for 2020 include resolution of the 2014-2015 IRS audit, which resulted in a reduction in deferred income tax expense of $230 million that includes a $396 million reduction in deferred income tax expense at Utility related to the basis of assets contributed in the 2015 Entergy Louisiana and Entergy Gulf States Louisiana business combination, including the recognition of previously uncertain tax positions, and deferred income tax expense of $105 million at Entergy Wholesale Commodities and $61 million at Parent and Other resulting from the revaluation of net operating losses as a result of the release of the reserves. See Note 3 to the financial statements for further discussion of the IRS audit resolution.
Results of operations for 2019 include: 1) a loss of $190 million ($156 million net-of-tax) as a result of the sale of the Pilgrim plant in August 2019; 2) a $156 million reduction in income tax expense recognized by Entergy Wholesale Commodities as a result of an internal restructuring; and 3) impairment charges of $100 million ($79 million net-of-tax) due to costs being charged directly to expense as incurred as a result of the impaired value of the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining estimated operating lives associated with management’s strategy to exit the Entergy Wholesale Commodities’ merchant power business. See Note 3 to the financial statements for further discussion of the internal restructuring. See Note 14 to the financial statements for further discussion of the sale of the Pilgrim plant.
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The business of the Utility operating companies is subject to seasonal fluctuations with the peak periods occurring during the third quarter. Operating results for the Registrant Subsidiaries for the four quarters of 2020 and 2019 were:
Operating Revenues
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||||||||
| 2020: | |||||||||||||||||||||||||||||||||||
| First Quarter | $481,912 | $930,647 | $293,922 | $149,302 | $339,336 | $130,664 | |||||||||||||||||||||||||||||
| Second Quarter | $491,767 | $1,011,652 | $297,954 | $147,343 | $372,194 | $126,049 | |||||||||||||||||||||||||||||
| Third Quarter | $644,389 | $1,120,022 | $356,496 | $182,064 | $494,922 | $148,517 | |||||||||||||||||||||||||||||
| Fourth Quarter | $466,426 | $1,007,541 | $299,482 | $155,132 | $380,673 | $90,228 | |||||||||||||||||||||||||||||
| 2019: | |||||||||||||||||||||||||||||||||||
| First Quarter | $545,812 | $959,330 | $282,244 | $163,194 | $340,474 | $140,104 | |||||||||||||||||||||||||||||
| Second Quarter | $542,929 | $1,106,317 | $302,737 | $175,793 | $363,580 | $139,009 | |||||||||||||||||||||||||||||
| Third Quarter | $687,526 | $1,231,677 | $398,732 | $194,204 | $442,877 | $145,472 | |||||||||||||||||||||||||||||
| Fourth Quarter | $483,327 | $987,851 | $339,330 | $153,032 | $342,024 | $148,825 | |||||||||||||||||||||||||||||
Operating Income
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||||||||
| 2020: | |||||||||||||||||||||||||||||||||||
| First Quarter | $67,835 | $166,779 | $41,181 | $12,091 | $36,060 | $35,309 | |||||||||||||||||||||||||||||
| Second Quarter | $107,949 | $256,412 | $67,705 | $7,602 | $56,443 | $31,236 | |||||||||||||||||||||||||||||
| Third Quarter | $217,648 | $324,496 | $93,843 | $32,322 | $108,306 | $48,896 | |||||||||||||||||||||||||||||
| Fourth Quarter | $9,126 | $117,134 | $33,466 | $12,397 | $46,040 | $1,303 | |||||||||||||||||||||||||||||
| 2019: | |||||||||||||||||||||||||||||||||||
| First Quarter | $42,471 | $153,944 | $30,792 | $16,136 | $16,741 | $31,368 | |||||||||||||||||||||||||||||
| Second Quarter | $69,774 | $241,520 | $45,607 | $17,509 | $36,022 | $24,300 | |||||||||||||||||||||||||||||
| Third Quarter | $182,176 | $336,754 | $87,024 | $28,876 | $69,510 | $29,086 | |||||||||||||||||||||||||||||
| Fourth Quarter | $32,576 | $164,424 | $40,331 | $6,164 | $24,229 | $30,231 | |||||||||||||||||||||||||||||
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Net Income
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | ||||||||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||||||||
| 2020: | |||||||||||||||||||||||||||||||||||
| First Quarter | $44,595 | $189,396 | $22,526 | $11,186 | $32,707 | $28,513 | |||||||||||||||||||||||||||||
| Second Quarter | $60,170 | $170,459 | $38,893 | $4,929 | $46,868 | $28,991 | |||||||||||||||||||||||||||||
| Third Quarter | $135,843 | $223,466 | $58,589 | $19,450 | $92,164 | $31,064 | |||||||||||||||||||||||||||||
| Fourth Quarter | $4,624 | $499,031 | $20,575 | $13,773 | $43,334 | $10,563 | |||||||||||||||||||||||||||||
| 2019: | |||||||||||||||||||||||||||||||||||
| First Quarter | $39,121 | $127,633 | $15,398 | $9,023 | $21,342 | $23,578 | |||||||||||||||||||||||||||||
| Second Quarter | $50,299 | $183,084 | $26,667 | $13,003 | $38,936 | $24,472 | |||||||||||||||||||||||||||||
| Third Quarter | $149,716 | $255,260 | $56,237 | $24,908 | $73,224 | $25,031 | |||||||||||||||||||||||||||||
| Fourth Quarter | $23,828 | $125,560 | $21,623 | $5,695 | $25,895 | $26,039 | |||||||||||||||||||||||||||||
Earnings Applicable to Common Equity/Stock
| Entergy Texas | ||||||||
| (In Thousands) | ||||||||
| 2020: | ||||||||
| First Quarter | $32,237 | |||||||
| Second Quarter | $46,397 | |||||||
| Third Quarter | $91,694 | |||||||
| Fourth Quarter | $42,863 | |||||||
| 2019: | ||||||||
| First Quarter | $21,342 | |||||||
| Second Quarter | $38,936 | |||||||
| Third Quarter | $73,114 | |||||||
| Fourth Quarter | $25,425 | |||||||
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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 Item 1A. of this report, “Risk Factors,” before deciding whether to invest in Entergy or the Registrant Subsidiaries.
Utility Regulatory Risks
•The impacts of the COVID-19 pandemic and responsive measures taken are highly uncertain and cannot be predicted.
•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 lengthy litigation and uncertainty as to ultimate results.
•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.
•Entergy’s business could experience adverse effects related to changes to state or federal legislation or regulation.
•There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
•The Utility operating companies are subject to risks associated with participation in the MISO markets and the allocation of transmission upgrade costs.
•A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta) could have material effects on Entergy and those Utility operating companies affected by severe weather.
Nuclear Operating, Shutdown, and Regulatory Risks
•The results of operations, financial condition, and liquidity of Entergy Arkansas, Entergy Louisiana, System Energy, and Entergy Wholesale Commodities could be materially affected by the following:
◦failure to consistently operate their nuclear power plants at high capacity factors;
◦refueling outages that last 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 imposed under the Price-Anderson Act in the event of a nuclear incident, and losses not covered by insurance;
◦the risk that the decommissioning trust fund assets for the nuclear power plants 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.
•Entergy Wholesale Commodities’ power plants are subject to impairment charges in certain circumstances and its nuclear power plants are exposed to price risk.
•The Entergy Wholesale Commodities business is 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.
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General Business Risks
•Entergy and the Utility operating companies 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. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, access capital and operate and grow their businesses, and the cost of capital.
•A downgrade in Entergy Corporation’s or its subsidiaries’ credit ratings could, among other things, negatively affect Entergy Corporation’s and its subsidiaries’ ability to access capital.
•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, the Utility operating companies’, and System Energy’s 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.
•The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs (i) to fulfill their obligations related to environmental and other matters or (ii) related to reliability standards.
•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.
•Entergy could be negatively affected by the effects of climate change and environmental and regulatory obligations intended to compel greenhouse gas emission reductions or increase clean or renewable energy requirements or to place a price on greenhouse gas emissions.
•Entergy is dependent on the continued and future availability and quality of water for cooling, process, and sanitary uses.
•Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices.
•The Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations.
•Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
•The litigation environment in the states in which certain Entergy subsidiaries operate poses a significant risk to those businesses.
•Terrorist attacks, cyber attacks, system failures, or data breaches of Entergy’s and its subsidiaries’ or its suppliers’ technology systems may adversely affect Entergy’s results of operations.
•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.
•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.
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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 30,000 MW of electric generating capacity, including approximately 8,000 MW of nuclear power. Entergy delivers electricity to 3.0 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $10.1 billion in 2020 and had more than 13,000 employees as of December 31, 2020.
Entergy operates primarily through two business segments: Utility and Entergy Wholesale Commodities.
•The Utility business 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.
•The Entergy Wholesale Commodities business segment includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” for discussion of the operation and planned shutdown and sale of each of the Entergy Wholesale Commodities nuclear power plants.
See Note 13 to the financial statements for financial information regarding Entergy’s business segments.
Strategy
Entergy’s strategy is to operate and grow the premier utility business that creates sustainable value for its customers, employees, communities, and owners. Entergy’s strategy to achieve its stakeholder objectives has two key aspects. First, Entergy invests in the Utility for the benefit of its customers, which supports steady, predictable growth in earnings and dividends. Second, Entergy manages risks by ensuring its Utility investments are customer-centric, supported by progressive regulatory constructs, and executed with disciplined project management. Entergy’s strategy for the Entergy Wholesale Commodities business segment is to continue to manage the risk of its operating portfolio as Entergy completes its exit from the merchant power business.
Utility
The Utility business 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. 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 overall generation portfolio of the Utility, which relies heavily on natural gas and nuclear generation, is consistent with Entergy’s strong support for the environment.
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Customers
As of December 31, 2020, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:
| Electric Customers | Gas Customers | ||||||||||||||||||||||||||||
| Area Served | (In Thousands) | (%) | (In Thousands) | (%) | |||||||||||||||||||||||||
| Entergy Arkansas | Portions of Arkansas | 722 | 25 | % | |||||||||||||||||||||||||
| Entergy Louisiana | Portions of Louisiana | 1,096 | 37 | % | 94 | 47 | % | ||||||||||||||||||||||
| Entergy Mississippi | Portions of Mississippi | 456 | 15 | % | |||||||||||||||||||||||||
| Entergy New Orleans | City of New Orleans | 207 | 7 | % | 108 | 53 | % | ||||||||||||||||||||||
| Entergy Texas | Portions of Texas | 473 | 16 | % | |||||||||||||||||||||||||
| Total customers | 2,954 | 100 | % | 202 | 100 | % | |||||||||||||||||||||||
Electric Energy Sales
The 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 10, 2020, Entergy reached a 2020 peak demand of 21,340 MWh, compared to the 2019 peak of 21,598 MWh recorded on August 12, 2019. Selected electric energy sales data is shown in the table below:
Selected 2020 Electric Energy Sales Data
| Entergy Arkansas | Entergy Louisiana | Entergy Mississippi | Entergy New Orleans | Entergy Texas | System Energy | Entergy (a) | |||||||||||||||||||||||||||||||||||
| (In GWh) | |||||||||||||||||||||||||||||||||||||||||
| Sales to retail customers | 20,749 | 53,896 | 12,402 | 5,447 | 18,677 | — | 111,170 | ||||||||||||||||||||||||||||||||||
| Sales for resale: | |||||||||||||||||||||||||||||||||||||||||
| Affiliates | 1,659 | 5,585 | — | — | 1,203 | 5,849 | — | ||||||||||||||||||||||||||||||||||
| Others | 4,198 | 2,365 | 4,316 | 1,969 | 810 | — | 13,658 | ||||||||||||||||||||||||||||||||||
| Total | 26,606 | 61,846 | 16,718 | 7,416 | 20,690 | 5,849 | 124,828 | ||||||||||||||||||||||||||||||||||
| Average use per residential customer (kWh) | 12,633 | 14,576 | 14,093 | 12,315 | 14,829 | — | 13,917 | ||||||||||||||||||||||||||||||||||
(a)Includes the effect of intercompany eliminations.
The following table illustrates the Utility operating companies’ 2020 combined electric sales volume as a percentage of total electric sales volume, and 2020 combined electric revenues as a percentage of total 2020 electric revenue, each by customer class.
| Customer Class | % of Sales Volume | % of Revenue | ||||||||||||
| Residential | 28.2 | 39.2 | ||||||||||||
| Commercial | 21.2 | 25.4 | ||||||||||||
| Industrial (a) | 37.7 | 25.8 | ||||||||||||
| Governmental | 2.0 | 2.3 | ||||||||||||
| Wholesale/Other | 10.9 | 7.3 | ||||||||||||
(a)Major industrial customers are primarily in the petroleum refining and chemical industries.
See “Selected Financial Data” for each of the Utility operating companies for the detail of their sales by customer class for 2016-2020.
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Selected 2020 Natural Gas Sales Data
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 9,467,899 and 6,268,003 Mcf, respectively, of natural gas to retail customers in 2020. In 2020, 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, 88% of operating revenue was derived from the electric utility business and 12% from the natural gas distribution business in 2020.
Following is data concerning Entergy New Orleans’s 2020 retail operating revenue sources.
| Customer Class | Electric Operating Revenue | Natural Gas Operating Revenue | ||||||||||||
| Residential | 48% | 51% | ||||||||||||
| Commercial | 35% | 25% | ||||||||||||
| Industrial | 5% | 18% | ||||||||||||
| Governmental/Municipal | 12% | 6% | ||||||||||||
Retail Rate Regulation
General (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas)
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’ retail rate mechanisms are discussed below.
| Rate base (in billions) | Current authorized return on common equity | Weighted average cost of capital (after-tax) | Equity ratio | Regulatory construct | |||||||||||||||||||||||||||||||
| Entergy Arkansas | $8.4 (a) | 9.25% - 10.25% | 5.04% | 36.6% | - forward test year formula rate plan through 2021 test year (i) - riders: MISO, capacity, Grand Gulf, tax adjustment, energy efficiency, fuel and purchased power | ||||||||||||||||||||||||||||||
| Entergy Louisiana (electric) | $11.9 (b) | 9.2% - 10.4% | 6.97% | 48.63% | - formula rate plan through 2019 test year (j) - riders/specific recovery: MISO, capacity, transmission, fuel | ||||||||||||||||||||||||||||||
| Entergy Louisiana (gas) | $0.08 (c) | 9.3% - 10.3% | 6.96% | 48.37% | - gas rate stabilization plan - rider: gas infrastructure | ||||||||||||||||||||||||||||||
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| Entergy Mississippi | $3.0 (d) | 8.89% - 10.93% | 6.82% | 49.09% | - formula rate plan with forward-looking features - riders: power management, Grand Gulf, fuel, MISO, unit power cost, storm damage, energy efficiency, ad valorem tax adjustment, vegetation, grid modernization, restructuring credit | ||||||||||||||||||||||||||||||
| Entergy New Orleans (electric) | $0.8 (e) | 9.35% | 7.09% | 50% | - formula rate plan with forward-looking features - riders/specific recovery: fuel and purchased power, MISO, energy efficiency, environmental | ||||||||||||||||||||||||||||||
| Entergy New Orleans (gas) | $0.1 (e) | 9.35% | 7.09% | 50% | - formula rate plan with forward-looking features - rider: purchased gas | ||||||||||||||||||||||||||||||
| Entergy Texas | $2.4 (f) | 9.65% | 7.73% | 50.9% | - rate case - riders: fuel, distribution and transmission, generation, rate case expenses, AMI surcharge, tax reform, among others | ||||||||||||||||||||||||||||||
| System Energy | $1.6 (g) | 10.94% (h) | 8.57 % | 65% (h) | - monthly cost of service | ||||||||||||||||||||||||||||||
(a)Based on 2021 test year.
(b)Based on December 31, 2019 test year and excludes approximately $800 million for the Lake Charles Power Station and $300 million for the Washington Parish Energy Center, each included in the capacity rider, and $400 million of transmission plant, included in the transmission rider.
(c)Based on September 30, 2019 test year.
(d)Based on 2020 forward test year and excludes approximately $300 million for the Choctaw Generating Station, included in interim capacity mechanism.
(e)Based on December 31, 2018 test year and known and measurables through December 31, 2019. Electric rate base excludes approximately $190 million for New Orleans Power Station and $40 million for New Orleans Solar Station.
(f)Based on December 31, 2017 test year and excludes $1.0 billion in cost recovery riders.
(g)Based on calculation as of December 31, 2020.
(h)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.
(i)See Note 2 to the financial statements for discussion of Entergy Arkansas’s pending formula rate plan extension request.
(j)See Note 2 to the financial statements for discussion of Entergy Louisiana’s pending formula rate plan extension request.
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Entergy Arkansas
Fuel and Purchased Power Cost Recovery
Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased power costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs. In December 2007 the APSC issued an order stating that Entergy Arkansas’s energy cost recovery rider will remain in effect, and any future termination of the rider would be subject to eighteen months advance notice by the APSC, which would occur following notice and hearing.
Production Cost Allocation Rider
Entergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of System Agreement proceedings.
Entergy Louisiana
Fuel Recovery
Entergy Louisiana’s rate schedules include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Louisiana’s fuel adjustment clause filings.
To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Louisiana historically hedged approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity was reviewed on an annual basis. In 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
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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.
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.
Entergy Mississippi
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
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.
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Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
Formula Rate Plan
In August 2012 the MPSC opened inquiries to review whether the 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.
Entergy New Orleans
Fuel Recovery
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.
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Energy Efficiency Programs
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect. In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. See Note 2 to the financial statements for discussion of Entergy New Orleans’s application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022.
Entergy Texas
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included in base rates. Semi-annual revisions of the fixed fuel factor are 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. The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.
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. Entergy Texas has not exercised the option to recover its capacity costs under the new rider mechanism, but will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.
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
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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 Entergy Texas’s power region.
The law also contains 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.
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.
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 permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect depreciation expense, federal income tax and other taxes, and return on investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery factor 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.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas franchises are considered to be contracts and, therefore, are terminable 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.
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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 68 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2020-2058.
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, 2020, is indicated below:
| Owned and Leased Capability MW(a) | ||||||||||||||||||||||||||||||||||||||
| Company | Total | Gas/Oil | Nuclear | Coal | Hydro | Solar | ||||||||||||||||||||||||||||||||
| Entergy Arkansas | 5,175 | 2,091 | 1,817 | 1,194 | 73 | — | ||||||||||||||||||||||||||||||||
| Entergy Louisiana | 11,317 | 8,827 | 2,144 | 346 | — | — | ||||||||||||||||||||||||||||||||
| Entergy Mississippi | 3,347 | 2,929 | — | 416 | — | 2 | ||||||||||||||||||||||||||||||||
| Entergy New Orleans | 665 | 638 | — | — | — | 27 | ||||||||||||||||||||||||||||||||
| Entergy Texas | 2,260 | 2,005 | — | 255 | — | — | ||||||||||||||||||||||||||||||||
| System Energy | 1,256 | — | 1,256 | — | — | — | ||||||||||||||||||||||||||||||||
| Total | 24,020 | 16,490 | 5,217 | 2,211 | 73 | 29 | ||||||||||||||||||||||||||||||||
(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.
Summer peak load for the Utility has averaged 21,591 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 8,801 MW of new long-term resources and the deactivation of about 4,664 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.
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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 limited-term (1 to 3 years) and long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•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;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•In October 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the facility is scheduled to be in service by early 2022;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020 and the facility is scheduled to be in service by the end of 2021;
•Entergy New Orleans received regulatory approval in August 2019 to construct the New Orleans Solar Station (a 20 MW self-build solar project) located at the NASA Michoud Facility. The facility was placed in service in December 2020;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Lee County, Arkansas. In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2022;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2023; and
•In June 2020, Entergy Texas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 1,200 acres in Liberty County near Dayton, Texas. In September 2020, Entergy Texas filed a petition with the PUCT seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2023.
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The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
•In May 2011, Entergy Texas and Calpine Energy Services, L.P. executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. Entergy Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
•In September 2012, Entergy Gulf States Louisiana executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from Rain CII Carbon LLC’s 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 executed a 20-year agreement for 8.5 MW from Agrilectric Power Partners, LP’s 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 executed a 10-year agreement with TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, 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. The transaction received regulatory approval and will begin in June 2022;
•In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a 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 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 solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a five-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;
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•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021; and
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in Polk County, Texas. The PPA is expected to start when the facility reaches commercial operation in 2023.
In April 2020, Entergy Services, on behalf of Entergy Texas, issued an RFP for combined-cycle gas turbine capacity and energy resources. The RFP was seeking up to 1,000 MW - 1,200 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes, if any, from a single generation resource located in the “Eastern Region” of Entergy Texas’s service area. In December 2020, Entergy Texas posted notice that it has elected to proceed with the self-build alternative, Orange County Power Station. The self-build alternative will be conditioned on receipt of required internal and regulatory approvals.
In June 2020, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. The RFP was seeking 300 MW of energy, capacity, capacity-related benefits, other electric products, and environmental attributes from eligible new-build solar photovoltaic generation resources. In December 2020, Entergy Louisiana concluded evaluations of the RFP. Three proposals have been placed on the primary selection list and two proposals have been placed on the secondary selection list. Negotiations are currently in progress.
In January 2021, Entergy Texas provided notice that it intends to issue an RFP for solar generation resources. The RFP is seeking a minimum of 200 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process, including Entergy Mississippi’s January 2006 acquisition of the 480 MW, combined-cycle, gas-fired Attala power plant; Entergy Gulf States Louisiana’s March 2008 acquisition of the 322 MW, simple-cycle, gas-fired Calcasieu Generating Facility; Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2; Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) March 2016 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); and Entergy Mississippi’s October 2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
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. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility is an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, owned by East Texas Electric Cooperative. Entergy Texas is currently seeking regulatory certification to move forward with the purchase of the facility. The facility has been in operation since January 2010.
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Power Through Program
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 that is to be installed at commercial and industrial customer premises. If approved, 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.”
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-electric production facilities, combustion-turbine generators, pressurized and boiling water nuclear reactors, and inverter-based technologies operating in the MISO energy and ancillary services market. Entergy’s Utility operating companies are MISO market participants and are interconnected with 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. As a Regional Transmission Organization, MISO assures consumers of unbiased regional grid management and open access to the transmission facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC). SERC is a nonprofit corporation responsible for promoting and improving the reliability, adequacy, and critical infrastructure of the bulk power supply systems in all or portions of 16 central and southeastern states. SERC serves as a 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 the SERC Region.
Gas Property
As of December 31, 2020, 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, 2020, 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.
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Fuel Supply
The sources of generation and average fuel cost per kWh for the Utility operating companies and System Energy for the years 2018-2020 were:
| Natural Gas | Nuclear | Coal | Purchased Power | MISO Purchases | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Year | % of Gen | Cents Per kWh | % of Gen | Cents Per kWh | % of Gen | Cents Per kWh | % of Gen | Cents Per kWh | % of Gen | Cents Per kWh | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2020 | 47 | 1.92 | 29 | 0.57 | 3 | 2.54 | 8 | 4.36 | 13 | 2.48 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2019 | 40 | 2.33 | 28 | 0.73 | 6 | 2.31 | 8 | 4.86 | 18 | 2.71 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2018 | 39 | 2.84 | 27 | 0.84 | 9 | 2.24 | 8 | 5.23 | 17 | 3.71 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Actual 2020 and projected 2021 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:
| Natural Gas | Nuclear | Coal | Purchased Power (d) | MISO Purchases (e) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2020 | 2021 | 2020 | 2021 | 2020 | 2021 | 2020 | 2021 | 2020 | 2021 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Entergy Arkansas (a) | 24 | % | 35 | % | 60 | % | 51 | % | 10 | % | 13 | % | 1 | % | 1 | % | 5 | % | — | ||||||||||||||||||||||||||||||||||||||||
| Entergy Louisiana | 51 | % | 59 | % | 26 | % | 27 | % | 1 | % | 2 | % | 9 | % | 12 | % | 13 | % | — | ||||||||||||||||||||||||||||||||||||||||
| Entergy Mississippi (b) | 73 | % | 69 | % | 14 | % | 22 | % | 4 | % | 9 | % | — | — | 9 | % | — | ||||||||||||||||||||||||||||||||||||||||||
| Entergy New Orleans (b) | 55 | % | 56 | % | 33 | % | 40 | % | 1 | % | 2 | % | 2 | % | 2 | % | 9 | % | — | ||||||||||||||||||||||||||||||||||||||||
| Entergy Texas | 39 | % | 60 | % | 11 | % | 13 | % | 2 | % | 6 | % | 23 | % | 21 | % | 25 | % | — | ||||||||||||||||||||||||||||||||||||||||
| System Energy (c) | — | — | 100 | % | 100 | % | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||
| Utility (a) (b) | 47 | % | 55 | % | 29 | % | 31 | % | 3 | % | 6 | % | 8 | % | 8 | % | 13 | % | — | ||||||||||||||||||||||||||||||||||||||||
(a)Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2020 and is expected to provide less than 1% of its generation in 2021.
(b)Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2020 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2021.
(c)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.
(d)Excludes MISO purchases.
(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 2020 is not projected for 2021.
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 2021, 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 50% of the Utility operating companies’ power plants maintain some level of long-
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term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements. Entergy Texas owns a gas storage facility that provides reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to seven one- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2021. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 15% of total coal requirements will be satisfied by contracts with a term of less than one year. Based on continued improved Powder River Basin (PRB) coal deliveries by rail and the high cost of alternate sources and modes of transportation, no alternative coal consumption is expected at Entergy Arkansas during 2021. Coal will be transported to Arkansas via an existing transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2021.
Entergy Louisiana has committed to five one- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2021. 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 for Entergy Arkansas’s plants, no alternative coal consumption is expected at Nelson Unit 6 during 2021. Coal will be transported to Nelson primarily via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2021.
For the year 2020, coal transportation delivery rates to Entergy Arkansas-and Entergy Louisiana-operated coal-fired units were adequate to meet supply needs and obligations, and it is expected that delivery times in 2021 will continue to be consistent. Both Entergy Arkansas and Entergy Louisiana control a sufficient number of railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2021. 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
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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 most of 2023. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. 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 CenterPoint Energy Services which guarantees 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 CenterPoint Energy Service 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 2020 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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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.
System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Prior to each operating company’s 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. Under the terms of the System Agreement, generating capacity and other power resources were jointly operated by the Utility operating companies that were participating in the System Agreement. The System Agreement provided, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) would receive payments from those parties having generating reserves that were less than their allocated share of reserves (short companies). Such payments were at amounts sufficient to cover certain of the long companies’ costs for intermediate and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred equity, and a fair rate of return on common equity investment. Under the System Agreement, the rates used to compensate long companies were based on costs associated with the long companies’ steam electric generating units fueled by oil or gas and having an annual average heat rate above 10,000 Btu/kWh. In addition, for all energy exchanged among the Utility operating companies under the System Agreement, the companies purchasing exchange energy were required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.
Although the System Agreement has terminated, certain of the Utility operating companies’ and their retail regulators are pursuing litigation involving the System Agreement at the FERC and in federal courts. The proceedings include challenges to the allocation of costs as defined by the System Agreement and other matters. See Note 2 to the financial statements for discussion of legal proceedings at the FERC and in federal courts involving the System Agreement.
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 generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. 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
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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.
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 July 2001 a rate proceeding commenced by System Energy at the FERC in 1995 became final, with the FERC approving a prospective 10.94% return on equity. 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 complaints filed with the FERC regarding System Energy’s return on equity.
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 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, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted rate relief 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. 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 rate relief 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 financing by System Energy
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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 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 its two outstanding series of first mortgage bonds. 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 have ever been required. 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 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 Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.
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.
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Service Companies
Entergy Services, a limited liability company wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, but also provides services to Entergy Wholesale Commodities. 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.
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Entergy New Orleans Internal Restructuring
In November 2017, pursuant to the agreement in principle, Entergy New Orleans, Inc. undertook a multi-step restructuring, including the following:
•Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
•Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.
•Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans 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 New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.
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.
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•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.
Entergy Wholesale Commodities
Entergy Wholesale Commodities includes the ownership, operation, and decommissioning of nuclear power plants, located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities revenues are primarily derived from sales of energy and generation capacity from these plants. Entergy Wholesale Commodities also provides operations and management services, including decommissioning-related services, to nuclear power plants owned by non-affiliated entities in the United States. Entergy Wholesale Commodities also includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
Property
Nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership of the following nuclear power plants:
| Power Plant | Market | In Service Year | Acquired | Location | Capacity - Reactor Type | License Expiration Date | ||||||||||||||||||||||||||||||||
| Indian Point 3 (a) | NYISO | 1976 | Nov. 2000 | Buchanan, NY | 1,041 MW - Pressurized Water | 2025 (a) | ||||||||||||||||||||||||||||||||
| Indian Point 2 (a) | NYISO | 1974 | Sept. 2001 | Buchanan, NY | 1,028 MW - Pressurized Water | 2024 (a) | ||||||||||||||||||||||||||||||||
| Palisades (b) | MISO | 1971 | Apr. 2007 | Covert, MI | 811 MW - Pressurized Water | 2031 (b) | ||||||||||||||||||||||||||||||||
(a)Power operations ceased at the Indian Point 2 plant in April 2020. The fuel was permanently removed from the reactor vessel and placed in the spent fuel pool in May 2020. The Indian Point 3 plant is expected to cease operations on April 30, 2021. Entergy and Holtec jointly filed a license transfer application with the NRC in November 2019, requesting approval for the transfer of the Indian Point plants, along with their nuclear decommissioning trusts and decommissioning liabilities, from Entergy to Holtec. The NRC approved the license transfer application on November 23, 2020.
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(b)The Palisades plant is expected to cease operations on May 31, 2022. There is a contract to sell the plant to Holtec subject to NRC and other regulatory approvals.
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
Entergy Wholesale Commodities also includes the ownership of two non-operating nuclear facilities, Big Rock Point in Michigan and Indian Point 1 in New York that were acquired when Entergy purchased the Palisades and Indian Point 2 nuclear plants, respectively. These facilities are in various stages of the decommissioning process. Both Big Rock Point and Indian Point 1 are under contract to be sold with their respective plants.
Non-nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership, or interests in joint ventures that own, 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 | ||||||||||||||||||||||
| RS Cogen; 425 MW (c) | Lake Charles, LA | 50% | 213 MW | Gas/Steam | ||||||||||||||||||||||
| 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 Wholesale Commodities. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.
(c)Indirectly owned through an interest in an unconsolidated joint venture. In December 2020, Entergy’s wholly-owned subsidiary with a direct interest in RS Cogen, LLC entered into a membership interest purchase agreement with a subsidiary of the other 50% equity partner to sell its 50% membership interest in the joint venture to the equity partner. The targeted closing date for the transaction is October 2022.
Independent System Operators
The Indian Point plants fall under the authority of the New York Independent System Operator (NYISO). The Palisades plant falls under the authority of the MISO. The primary purpose of NYISO and MISO is to direct the operations of the major generation and transmission facilities in their respective regions; ensure grid reliability; administer and monitor wholesale electricity markets; and plan for their respective region’s energy needs.
Energy and Capacity Sales
As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy in the day ahead or spot markets. Entergy Wholesale Commodities also sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both. See “Market and Credit Risk Sensitive Instruments” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional information regarding these contracts.
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As part of the purchase of the Palisades plant in 2007, Entergy executed a 15-year PPA with the seller, Consumers Energy, for 100% of the plant’s output, excluding any future uprates. Under the purchased power agreement, Consumers Energy receives the value of any new environmental credits for the first ten years of the agreement. Palisades and Consumers Energy will share on a 50/50 basis the value of any new environmental credits for years 11 through 15 of the agreement. The environmental credits are defined as benefits from a change in law that causes capability of the plant as of the purchase date to become a tradable attribute (e.g., emission credit, renewable energy credit, environmental credit, “green” credit, etc.) or otherwise to have a market value. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022 and transfer to Holtec thereafter.
Customers
Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its nuclear plants include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. These customers include Consumers Energy, the company from which Entergy purchased the Palisades plant, and NYISO and MISO. Substantially all the credit exposure associated with the planned energy output under contract for Entergy Wholesale Commodities nuclear plants is with counterparties or their guarantors that have public investment grade credit ratings.
Competition
The NYISO market is highly competitive. Entergy Wholesale Commodities has numerous competitors in New York including generation companies affiliated with regulated utilities, other independent power producers, municipal and co-operative generators, owners of co-generation plants and wholesale power marketers. Entergy Wholesale Commodities is an independent power producer, which means it generates power for sale to third parties at day ahead or spot market prices to the extent that the power is not sold under a fixed price contract. Municipal and co-operative generators also generate power but use most of it to deliver power to their municipal or co-operative power customers. Owners of co-generation plants produce power primarily for their own consumption. Wholesale power marketers do not own generation; rather they buy power from generators or other market participants and resell it to retail providers or other market participants. Competition in the New York power market is affected by, among other factors, the amount of generation and transmission capacity in these markets. MISO does not have a centralized clearing capacity market, but load serving entities do meet most of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. Almost all of Palisades’ current output is contracted to Consumers Energy through May 2022. Entergy Wholesale Commodities does not expect to be materially affected by competition in the MISO market in the near term.
Seasonality
Entergy Wholesale Commodities’ revenues and operating income are subject to fluctuations during the year due to seasonal factors, weather conditions, and contract pricing. When outdoor and cooling water temperatures are low, generally during colder months, Entergy Wholesale Commodities nuclear power plants operate more efficiently, and consequently, generate more electricity. Many of Entergy Wholesale Commodities’ contracts provide for shaped pricing over the course of the year. As a result of these factors, Entergy Wholesale Commodities’ revenues are typically higher in the first and third quarters than in the second and fourth quarters.
Fuel Supply
Nuclear Fuel
See “Fuel Supply - Nuclear Fuel” in the Utility portion of Part I, Item 1 for a discussion of the nuclear fuel cycle and markets. Entergy Nuclear Fuels Company, a wholly-owned subsidiary, is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for Entergy Wholesale Commodities nuclear power plants,
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while Entergy Nuclear Operations, Inc. acts as the agent for the purchase of nuclear fuel assembly fabrication services. All contracts for the disposal of spent nuclear fuel are between the DOE and each of the nuclear power plant owners. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment has been adjusted to reflect reduced overall requirements related to the planned permanent shutdowns of the Indian Point 3 and Palisades plants. Fuel procurement for the Entergy Wholesale Commodities segment was primarily limited to the requirements of the Palisades plant’s final refueling in 2020.
Other Business Activities
Entergy Nuclear Power Marketing, LLC (ENPM) was formed in 2005 to centralize the power marketing function for Entergy Wholesale Commodities nuclear plants. Upon its formation, ENPM entered into long-term power purchase agreements with the Entergy Wholesale Commodities subsidiaries that own nuclear power plants (generating subsidiaries). As part of a series of agreements, ENPM agreed to assume and/or otherwise service the existing power purchase agreements that were in effect between the generating subsidiaries and their customers. ENPM’s functions include origination of new energy and capacity transactions and generation scheduling.
Services provided by either Entergy Nuclear, Inc. or other Entergy Wholesale Commodities subsidiaries include engineering, operations and maintenance, fuel procurement, management and supervision, technical support and training, administrative support, and other managerial or technical services required to operate, maintain, and decommission nuclear electric power facilities.
TLG Services, a subsidiary in the Entergy Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Entergy provides plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029.
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.
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Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 70 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery rider;
•terms and conditions of service;
•service standards;
•the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;
•certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;
•avoided cost payments to 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 or other regulatory 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 and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•certification of certain transmission projects;
•certification of capacity acquisitions, both for owned capacity and purchase power contracts;
•procurement process to acquire over 50 MW;
•audits of the environmental adjustment charge, avoided cost payment to Qualifying Facilities, and energy efficiency rider;
•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;
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•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery mechanism;
•terms and conditions of service;
•service standards;
•certification of generating facilities and certain transmission projects;
•avoided cost payments to Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•audit of the environmental adjustment charge;
•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
•integrated resource planning;
•net energy metering;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:
•retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
•fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
•service standards;
•certification of certain transmission and generation projects;
•utility service areas, including extensions into new areas;
•avoided cost payments to Qualifying Facilities;
•net energy metering; and
•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.
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Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC. Entergy subsidiaries in the Entergy Wholesale Commodities segment are subject to the NRC’s jurisdiction as the owners and operators of Indian Point Energy Center, Palisades, and Big Rock Point.
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, 2020 of $192.0 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick, Indian Point 3, Indian Point 1 and Indian Point 2, Vermont Yankee, Palisades, and Big Rock Point spent fuel disposal contracts with the DOE held by their previous owners. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the sale of the plant, completed in March 2017. The Vermont Yankee spent fuel disposal contract was assigned to NorthStar as part of the sale of the plant in January 2019. The Pilgrim spent fuel disposal contract was transferred to Holtec as part of the sale of Entergy Nuclear Generation Company in August 2019. The owners of these plants previous to Entergy have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. 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 $1.6 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 (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 has breached 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
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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 2018, 2019, and 2020 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2020, Entergy’s subsidiaries won and collected on judgments against the government totaling approximately $800 million.
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 Palisades in 1993, at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, at Indian Point in 2008, 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 October 2020, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and ANO 2 decommissioning trusts were adequately funded without further collections, and in December 2020, the APSC ordered zero collections for ANO 1 and ANO 2 decommissioning.
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.
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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 September 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.
In January 2019, Entergy sold 100% of the membership interest in Entergy Nuclear Vermont Yankee to a subsidiary of NorthStar. As a result of the sale, NorthStar assumed ownership of Vermont Yankee and its decommissioning and site restoration trusts, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 9 to the financial statements for further discussion of Vermont Yankee decommissioning costs and see “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the NorthStar transaction.
In August 2019, Entergy sold 100% of the equity interests in Entergy Nuclear Generation Company, LLC to a subsidiary of Holtec International. As a result of the sale, Holtec assumed ownership of Pilgrim and its decommissioning trust, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 14 to the financial statements for further discussion of the sale.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities with the right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assigns the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy, which was completed in January 2017. In March 2017, Entergy sold the FitzPatrick plant to Exelon, and as part of the transaction, the FitzPatrick decommissioning trust fund, along with the decommissioning obligation for that plant, was transferred to Exelon. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the transaction. See Note 14 to the financial statements for discussion of the FitzPatrick sale.
In March 2020 filings with the NRC were made reporting on decommissioning funding for all of Entergy 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
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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 $137.6 million per reactor (with 97 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, System Energy, or an Entergy Wholesale Commodities company 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, and “multiple/repetitive degraded cornerstone column,” or Column 4. 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. The nuclear generating plants owned and operated by Entergy’s Utility and Entergy Wholesale Commodities businesses are currently in Column 1, except for Grand Gulf, which is currently in Column 2.
In November 2020 the NRC placed Grand Gulf in Column 2 based on the incidence of three unplanned plant scrams during the second and third quarters of 2020. Two of the scram events related to new turbine control system components that failed, and a third related to a feedwater valve positioner that failed, all of which had been replaced in a refueling outage that ended in May 2020. The NRC plans to conduct a supplemental inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 2. As a consequence of two additional Grand Gulf scrams during the fourth quarter 2020, System Energy expects Grand Gulf to be placed into NRC Column 3 based on plant performance indicators for the four quarters ended December 31, 2020. This will involve an additional supplemental NRC inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 3.
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.
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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.
New Source Review (NSR)
Preconstruction permits are required for new facilities and for existing facilities that undergo a modification that results in a significant net emissions increase and is not classified as routine repair, maintenance, or replacement. Units that undergo certain non-routine modifications must obtain a permit modification and may be required to install additional air pollution control technologies. In December 2020 the EPA amended the NSR regulations to clarify when a physical change or change in the method of operation will constitute such a modification. Entergy has an established process for identifying modifications requiring additional permitting approval and is monitoring the regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. Several years ago, however, the EPA implemented an enforcement initiative, aimed primarily at coal plants, to identify modifications that it does not consider routine for which the unit did not obtain a modified permit. Various courts and the EPA have been inconsistent in their judgments regarding modifications that are considered routine and on other legal issues that affect this program.
In February 2011, Entergy received a request from the EPA for several categories of information concerning capital and maintenance projects at the White Bluff and Independence facilities, both located in Arkansas, in order to determine compliance with the Clean Air Act, including NSR requirements and air permits issued by the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ). In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA. In September 2015 an additional request for similar information was received for the White Bluff facility. Entergy responded to all requests. None of these EPA requests for information alleged that the facilities were in violation of law.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims as well as other issues facing Entergy Arkansas’s fossil generation plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. In October 2019 the District Court requested supplemental briefing on several issues to be resolved prior to addressing the motion to approve the
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settlement; that briefing was completed in May 2020. For further information about the settlement, see “Regional Haze” discussed below.
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 construction and 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 December 2020 the EPA designated 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. Challenges to these final designations must be filed within 60 days of publication in the Federal Register. 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. Entergy will continue to monitor this situation.
Cross-State Air Pollution
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.
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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 September 2016 the EPA finalized the CSAPR Update Rule to address interstate transport for the 2008 ozone NAAQS. Starting in 2017 the final rule requires reductions in summer nitrogen oxides (NOx) emissions. Several states, including Arkansas and Texas, filed a challenge to the Update Rule. In September 2019 the D.C. Circuit upheld the EPA’s underlying approach to the Update Rule, but determined that it was inconsistent with the Clean Air Act because it failed to include deadlines consistent with downwind states’ deadlines for attainment. The court remanded the rule to the EPA for further consideration, but did not vacate so the rule remains in effect pending the EPA’s further review. In October 2020 the EPA issued its proposal intended to address the D.C. Circuit’s remand. The draft rule proposes to finalize interstate transport obligations for 21 states. For nine states, including Arkansas, Mississippi, and Texas, the EPA proposes that additional emission reductions are not necessary. For 12 states, however, including Louisiana, the EPA proposes additional emission reductions through proposed reductions in the number of NOx emission allowances allocated to each state. Entergy, through its various trade associations, filed comments on the proposal and will continue to monitor the rulemaking and its potential impact on its facilities in Louisiana. If the October 2020 proposal is finalized, ozone season NOx emissions may become more expensive in Louisiana.
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 (BART) to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states.
In Arkansas, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) prepared a state implementation plan (SIP) for Arkansas facilities to implement its obligations under the CAVR. In April 2012 the EPA finalized a decision addressing the Arkansas Regional Haze SIP, in which it disapproved a large portion of the Arkansas plan, including the emission limits for NOx and SO2 at White Bluff. In April 2015 the EPA published a proposed federal implementation plan (FIP) for Arkansas, taking comment on requiring installation of scrubbers and low NOx burners to continue operating both units at the White Bluff plant and both units at the Independence plant and NOx controls to continue operating the Lake Catherine plant. Entergy filed comments by the deadline in August 2015. Among other comments, including opposition to the EPA’s proposed controls on the Independence units, Entergy proposed to meet more stringent SO2 and NOx limits at both White Bluff and Independence within three years of the effective date of the final FIP and to cease the use of coal at the White Bluff units at a later date.
In September 2016 the EPA published the final Arkansas Regional Haze FIP. In most respects, the EPA finalized its original proposal but shortened the time for compliance for installation of the NOx controls. The FIP required an emission limitation consistent with SO2 scrubbers at both White Bluff and Independence by October 2021 and NOx controls by April 2018. The EPA declined to adopt Entergy’s proposals related to ceasing coal use as an alternative to SO2 scrubbers for White Bluff SO2 BART. In November 2016, Entergy and other interested parties, including the State of Arkansas, filed petitions for administrative reconsideration and stay at the EPA as well as petitions for judicial review in the U.S. Court of Appeals for the Eighth Circuit. The Eighth Circuit granted the stay pending settlement discussions and pending the State’s development of a SIP that, if approved by the EPA, would replace the FIP. The state had proposed its replacement SIP in two parts: Part I considers NOx requirements, and Part II considers SO2 requirements. The EPA approved the Part I NOx SIP in January 2018. The Part I SIP requires that Entergy address NOx impacts on visibility via compliance with the Cross-State Air Pollution Rule ozone-season emission trading program. Arkansas has finalized a Part II SIP which has been approved by the EPA but is currently pending a state court appeal. That appeal has been stayed pending the outcome of a federal court case, which may resolve many of the issues on appeal. The final Part II SIP requires that Entergy achieve SO2 emission reductions via the use of low-sulfur coal at both White Bluff and Independence within three years. The
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Part II SIP also requires that Entergy cease to use coal at White Bluff by December 31, 2028 and notes the current planning assumption that Entergy’s Independence units will cease to use coal by December 31, 2030.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement and in many cases also the Part II SIP, Entergy Arkansas, along with co-owners, will begin using only low-sulfur coal at Independence and White Bluff by mid-2021; cease to use coal at White Bluff and Independence by the end of 2028 and 2030, respectively; cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserve the option to develop new generating sources at each plant site; and commit to install or propose to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waive certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. The EPA, which is allowed to comment on such a settlement agreement, has stated that it has no objections to the settlement. In November 2020 the court denied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. Still pending before the court is a motion by the plaintiffs to approve the settlement, in support of which Entergy made a filing. The Arkansas Attorney General also filed an application before the APSC in December 2018 seeking an investigation into the effects of the settlement. The Arkansas Affordable Energy Coalition filed to support the Arkansas Attorney General’s application, and Entergy Arkansas filed a motion to dismiss it. The application remains pending before the APSC. In October 2019 the District Court requested supplemental briefing on several issues prior to addressing the motion to approve the settlement; that briefing concluded in May 2020.
In Louisiana, Entergy has worked with the Louisiana Department of Environmental Quality (LDEQ) and the EPA to revise the Louisiana SIP for regional haze, which had been disapproved in part in 2012. The LDEQ submitted a revised SIP in February 2017. In May 2017 the EPA proposed to approve a majority of the revisions. In September 2017 the EPA issued a proposed SIP approval for the Nelson plant, requiring an emission limitation consistent with the use of low-sulfur coal, with a compliance date of January 22, 2021. The EPA issued final approval in December 2017. The EPA approval was appealed to the U.S. Court of Appeals for the Fifth Circuit. In October 2019 the Fifth Circuit affirmed the EPA’s SIP approval. A petition for rehearing filed by plaintiffs was denied by the Fifth Circuit. Plaintiffs did not petition for further review by the Supreme Court.
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 2021. Entergy received information collection requests from Arkansas and Louisiana requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, and Ninemile. Responses to the information requests have been submitted to the respective state agencies.
New and Existing Source Performance Standards for Greenhouse Gas Emissions
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, which established
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national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy facilities to help the states collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests and will continue to monitor litigation challenging the rule. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also vacated the repeal of the Clean Power Plan. The vacatur will not be effective until the court issues its mandate which is being held until after disposition of any petitions for rehearing. Entergy is currently reviewing the court’s opinion.
In 2018 the EPA proposed a revision to the new source performance standard on greenhouse gas emissions that primarily impacts new coal units and, therefore, should not impact Entergy. In January 2021 the EPA finalized a pollutant-specific contribution finding for greenhouse gas emissions from new, modified, and reconstructed electric generating units. The rule establishes a three percent threshold for determining when a pollutant significantly contributes to air pollution and reaffirms the EPA’s position that the Clean Air Act Section 111(b) requires the EPA to make pollutant-specific significant contribution findings before promulgation of a new source performance standard. The EPA did not, however, finalize the new source performance standard on greenhouse gas emissions and intends to address the 2018 proposal in a future action.
Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives concerning air emissions, as well as other media, 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:
•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 NOx, SO2, mercury, and 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 Greenhouse Gas Initiative by several states in the northeastern United States and similar actions in other regions of the United States;
•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);
•efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance risk;
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•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.
Entergy continues to support national legislation that would increase planning certainty for electric utilities while addressing carbon dioxide emissions in an economy-wide, responsible, and flexible manner. 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. In 2020, Entergy succeeded in achieving its initial climate commitment to reduce carbon dioxide cumulative emissions by 20% from 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the United States were approximately 39.1 million tons in 2020 and 40.7 million tons in 2019. Since its original commitment in 2001, Entergy’s cumulative emissions are approximately 7.6% below its 2020 goal.
Entergy voluntarily conducted a climate scenario analysis and published a comprehensive report in March 2019. The report follows the framework and recommendations of the Task Force on Climate-related Disclosures, describing climate-related governance, strategy, risk management, and metrics and targets. Scenario analyses resulted in Entergy developing and publishing a new goal of reducing the Utility’s emission rate by 50 percent from 2000 levels by 2030. In September 2020, Entergy committed to achieving net-zero carbon emissions by 2050, while continuing its commitment to grid reliability and affordability for customers. In December 2020, Entergy published a report regarding this long-term commitment that describes its approach and technology point-of-view. Technology research and development, innovation, and advancement are critical to Entergy’s ability to meet this climate commitment.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy’s annual greenhouse gas emissions inventory is also third-party verified, and that certification is made available on the American Carbon Registry website. Entergy participates annually in the Dow Jones Sustainability Index and in 2020 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for nineteen consecutive years. Entergy also participated in the 2020 CDP and CDP Water evaluations, receiving a ‘B’ for both responses.
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 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
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Steam Electric Effluent Guidelines
The 2015 Steam Electric Effluent Limitations Guidelines (ELG) rule required, among other things, that there be no discharge of bottom ash transport water. In October 2020 the EPA issued its final rule revision on bottom ash transport water allowing the discharge of up to 10% system volume for certain purge waters, including storm events and non-routine operations. The final rule requires compliance as soon as possible beginning October 31, 2021, but no later than December 31, 2025. Several challenges to the final rule have been filed. Additionally, the Fifth Circuit Court of Appeals previously vacated and remanded the provisions of the rule related to legacy wastewater and leachate, which the EPA plans to address in a separate rulemaking. Despite the final rule and pending challenges, Entergy is implementing projects at its White Bluff and Independence plants to convert to zero-discharge systems to comply with the ELG rule and the coal combustion residuals restrictions on impoundments. Additionally, the Nelson Unit 6 facility is implementing operational and maintenance measures to minimize the potential for discharge of bottom ash transport water from the existing bottom ash handling system at the site, and is reviewing the effectiveness of these changes for compliance with the requirements of the October 2020 final rule.
Federal Jurisdiction of Waters of the United States
In February 2019 the EPA published its proposed revised definition of Waters of the United States, which proposes to narrow the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. The final rule was released in January 2020 and effective in June 2020. In October 2019 the EPA repealed the 2015 rule and re-codified the pre-existing regulations. That rule was effective late December 2019. Numerous challenges have been filed against both rules.
Groundwater at Certain Nuclear Sites
The NRC requires nuclear power plants to monitor and report regularly the presence of radioactive material in the environment. Entergy joined other nuclear utilities and the Nuclear Energy Institute in 2006 to develop a voluntary groundwater monitoring and protection program. This initiative began after detection of very low levels of radioactive material, primarily tritium, in groundwater at several plants in the United States. Tritium is a radioactive form of hydrogen that occurs naturally and is also a byproduct of nuclear plant operations. In addition to tritium, other radionuclides have been found in site groundwater at nuclear plants.
As part of the groundwater monitoring and protection program, Entergy has: (1) performed reviews of plant groundwater characteristics (hydrology) and historical records of past events on site that may have potentially impacted groundwater; (2) implemented fleet procedures on how to handle events that could impact groundwater; and (3) installed groundwater monitoring wells and began periodic sampling. The program also includes protocols for notifying local officials if contamination is found. To date, radionuclides such as tritium have been detected at Arkansas Nuclear One, Indian Point, Palisades, Grand Gulf, and River Bend. Each of these sites has installed groundwater monitoring wells and implemented a program for testing groundwater at the sites for the presence of tritium and other radionuclides. Based on current information, the concentrations and locations of radionuclides detected at these plants pose no threat to public health or safety, but each site continues to evaluate the results from its groundwater monitoring program.
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 in the Utility and Entergy Wholesale Commodities businesses have sent waste materials to various
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disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been or will be 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 June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contained two primary regulatory options: (1) regulating CCRs destined for disposal in landfills or received (including stored) in surface impoundments as so-called “special wastes” under the hazardous waste program of Resource Conservation and Recovery Act (RCRA) Subtitle C; or (2) regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes under Subtitle D of RCRA. Under both options, CCRs that are beneficially reused in certain processes would remain excluded from hazardous waste regulation. In April 2015 the EPA published the final CCR rule with the material being regulated under the second scenario presented above - as non-hazardous wastes regulated under RCRA 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. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed for CCR that cannot be transferred for beneficial reuse. As of December 31, 2020, Entergy has recorded asset retirement obligations related to CCR management of $20.1 million.
In December 2016 the Water Infrastructure Improvements for the Nation Act (WIIN Act) was signed into law, which authorizes states to regulate coal ash rather than leaving primary enforcement to citizen suit actions. States may submit to the EPA proposals for a permit program.
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 have 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 has commenced closure of one of its two recycle ponds, with the remaining pond being held in reserve during initial operation of the new bottom ash handling system. Closure of the remaining recycle pond at each site will commence as soon as possible, but no later than April 11, 2021, which is the deadline under the finalized CCR rule to commence closure of any 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.
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Other Environmental Matters
Entergy Louisiana and Entergy Texas
Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, currently is involved in the second phase of the remedial investigation of the Lake Charles Service Center site, located in Lake Charles, Louisiana. A manufactured gas plant (MGP) is believed to have operated at this site from approximately 1916 to 1931. Coal tar, a by-product of the distillation process employed at MGPs, apparently was routed to a portion of the property for disposal. The same area also has been used as a landfill. In 1999, Entergy Gulf States, Inc. signed a second administrative consent order with the EPA to perform a removal action at the site. Removal actions addressed contaminated source material, soil, and sediment and included capping certain soil on and off-site. In 2002 approximately 7,400 tons of contaminated soil and debris were excavated and disposed of from an area within the service center. In 2003 a cap was constructed over the remedial area to prevent the migration of contamination to the surface. In August 2005 an administrative order was issued by the EPA requiring that a 10-year groundwater study be conducted at this site. The groundwater monitoring study commenced in January 2006. The EPA released the second Five Year Review in 2015. In that review, the EPA indicated that the remediation technique was insufficient and that Entergy would need to utilize other remediation technologies on the site. In July 2015, Entergy submitted a Focused Feasibility Study to the EPA outlining the potential remedies and suggesting installation of the new remedial method, a waterloo barrier. The estimated cost for this remedy is approximately $2 million, to be allocated between Entergy Louisiana and Entergy Texas. In early 2017 the EPA indicated that the waterloo barrier may not be necessary and requested revisions to the Focused Feasibility Study. The EPA released the third Five Year Review in late-2019 confirming that a new remedial method is not necessary but requiring continuation of the current groundwater monitoring. The site’s remedy includes monitored natural attenuation of groundwater, and institutional controls to restrict groundwater and land use. The EPA has determined that no additional actions are needed for the remedy to be protective over the long-term, and the remedy is protective of human health and the environment.
Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
The Texas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas that the TCEQ believes those entities are potentially responsible parties (PRPs) concerning contamination existing at the San Angelo Electric Service Company (SESCO) facility in San Angelo, Texas. The facility operated as a transformer repair and scrapping facility from the 1930s until 2003. Both soil and groundwater contamination existed at the site. Entergy subsidiaries sent transformers to this facility. Entergy Arkansas, Entergy Louisiana, and Entergy Texas responded to an information request from the TCEQ. Entergy Louisiana and Entergy Texas joined a group of PRPs responding to site conditions in cooperation with the State of Texas, creating cost allocation models based on review of SESCO documents and employee interviews, and investigating contribution actions against other PRPs. Entergy Louisiana and Entergy Texas have agreed to contribute to the remediation of contaminated soil and groundwater at the site in a measure proportionate to those companies’ involvement at the site. Current estimates, although variable depending on ultimate remediation design and performance, indicate that Entergy’s total share of remediation costs likely will be approximately $1.5 million to $2 million. Groundwater monitoring wells at the site were plugged and abandoned in December 2019 following receipt of a certificate of completion issued by the TCEQ. Site decommissioning activities are complete and final disposition of the property will be determined at a later time.
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
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letter seeking reimbursement for response costs totaling $4 million expended at the site. The demand letter is being evaluated and liability and PRP allocation of response costs are yet to be determined.
Entergy Texas
In December 2016 a transformer inside the Hartburg, Texas Substation had an internal fault resulting in a release of approximately 15,000 gallons of non-PCB mineral oil. Cleanup ensued immediately; however, rain caused much of the oil to spread across the substation yard and into a nearby wetland. The TCEQ and the National Response Center were immediately notified, and the TCEQ responded to the site approximately two hours after the cleanup was initiated. The remediation liability is estimated at $2.2 million; however, this number could fluctuate depending on the remediation extent and wetland mitigation requirements. In July 2017, Entergy entered into the Voluntary Cleanup Program with the TCEQ. In November 2017, additional soil sampling was completed in the wetland area and, in February 2018, a site summary report of findings was submitted to the TCEQ. The TCEQ responded in June 2018 and requested an ecological exclusion criteria checklist/Tier II screening-level ecological risk assessment, and additional site assessment, additional soil samples, groundwater samples, and some additional diagrams and maps. In October 2018, Entergy submitted the requested information to the TCEQ. In January 2019 the TCEQ responded with another request for information. In March 2019, Entergy submitted the requested information to the TCEQ. In August 2019 the TCEQ responded with a request for additional information including an Affected Property Assessment Report (APAR) and water well survey. The TCEQ has agreed that the necessity of the water well survey is dependent on the results of the groundwater resampling that will occur. Groundwater sampling was completed in December 2019 and results were submitted to the TCEQ for review. Based on the groundwater sampling results, the TCEQ confirmed in February 2020 that a water well survey is not necessary and requested the APAR and an Ecological Risk Assessment by August 2020. Due to COVID-19 delays, the TCEQ extended the APAR and Ecological Risk Assessment submittal dates to December 2020, which Entergy timely met.
Litigation
Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but certain states in which Entergy operates have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas 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.
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Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2020, Entergy subsidiaries employed 13,400 people.
| Utility: | |||||
| Entergy Arkansas | 1,244 | ||||
| Entergy Louisiana | 1,654 | ||||
| Entergy Mississippi | 750 | ||||
| Entergy New Orleans | 303 | ||||
| Entergy Texas | 658 | ||||
| System Energy | — | ||||
| Entergy Operations | 3,529 | ||||
| Entergy Services | 3,859 | ||||
| Entergy Nuclear Operations | 1,356 | ||||
| Other subsidiaries | 47 | ||||
| Total Entergy | 13,400 | ||||
Approximately 3,900 employees are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Teamsters, 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 (%) | 2020 | 2019 | |||||||||
| Female | 21 | 20 | |||||||||
| Male | 79 | 80 | |||||||||
| 100 | 100 | ||||||||||
| Race/Ethnicity (%) | 2020 | 2019 | |||||||||
| White | 78 | 79 | |||||||||
| Black/African American | 15 | 15 | |||||||||
| Hispanic/Latino | 3 | 2 | |||||||||
| Asian | 2 | 2 | |||||||||
| Other | 2 | 2 | |||||||||
| 100 | 100 | ||||||||||
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.
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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 Personnel Committee establishes priorities and reviews performance on a range of topics. 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 and succession plans to align a high performing executive team with Entergy’s priorities. The Personnel 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.
Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on 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. While the COVID-19 pandemic and historical hurricane season presented significant challenges, Entergy’s safety strategy and commitment to excellence showed results in 2020. Entergy employees achieved a total recordable incident rate of 0.40 in 2020 compared to 0.56 in 2019 and 0.48 in 2018. 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 and is not inclusive of potential work-related COVID-19 cases. This marked improvement in total recordable incident rate placed Entergy in top-decile in safety performance when benchmarked amongst peers within the Edison Electric Institute.
Organizational Health, including Diversity, Inclusion and Belonging
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 2020 of 72 (near top quartile). In addition to significantly improved scores, initial employee participation of 66 percent in 2014 rose to and remains at 90 percent in 2018-2020.
Entergy believes that a culture focused on diversity, inclusion, and belonging drives foundational engagement. Entergy is committed to developing and retaining a workforce that reflects the rich diversity of the communities it serves. In 2019, Entergy embarked on a three-year phased approach to enhance inclusion for individuals and teams. Among other actions, the primary focus of its 2020 actions was taking a stand against social injustice, reinforcing expectations, training and leading by example, starting at the top of the organization and cascading through management ranks.
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Talent Management
Entergy’s focus on talent management is organized in three areas: developing and attracting a 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, proxies, and amendments to such reports. 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 http://www.sec.gov. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
Entergy uses its website, http://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q (including related filings in Inline XBRL format) and current reports on Form 8-K; proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy’s Investor Relations website free of charge. 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. The contents of the website are not incorporated into this report.
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RISK FACTORS
See “RISK FACTOR 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 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 impacts of the COVID-19 pandemic and responsive measures taken on Entergy’s and its Utility operating companies’ business, results of operations, and financial condition are highly uncertain and cannot be predicted.
In December 2019 a novel strain of coronavirus was reported to have surfaced in Wuhan, China. Since then, COVID-19 has spread throughout most countries in the world, including the United States. Public health officials in the United States have both recommended and mandated wearing of masks, precautions to mitigate the spread of COVID-19, including prohibitions on congregating in heavily-populated areas, mandated closure or limitations on the functions of non-essential business, and shelter-in-place orders or similar measures, including throughout Entergy’s service areas. While some of these mitigation measures have been lifted, it is unclear how long certain forms of mitigation measures will remain in place, whether they will be reinstated in the future, and how they will ultimately impact the general economy, Entergy’s customers, and its operations.
Entergy and its Utility operating companies have experienced a decline in commercial and industrial sales and an increase in arrearages and bad debt expense due to non-payment by customers, and expect such reduced levels of sales and increased arrearages and bad debt expense to continue, the extent and duration of which management cannot predict. The Utility operating companies temporarily suspended disconnecting customers for non-payment of bills, and the suspension remains in place at Entergy Arkansas, has been re-instituted at Entergy New Orleans, and could be re-instituted at the other Utility operating companies should their regulators mandate. While they are working with regulators to ensure ultimate recovery for those and other COVID-19 related costs, the amount, method, and timing of such recovery is unknown. Entergy and its Registrant Subsidiaries also could experience, and in some cases have experienced, among other challenges, supply chain, vendor, and contractor disruptions; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed outages; delays in regulatory proceedings; workforce availability, health or safety issues; increased storm recovery costs; increased cybersecurity risks as a result of many employees telecommuting; increased late or uncollectible customer payments; 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); or other adverse impacts on their ability to execute on business strategies and initiatives.
A sustained or further economic decline could adversely impact Entergy’s and the Utility operating companies’ liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense. The Utility operating companies also may experience regulatory outcomes that require them to postpone planned investment and otherwise reduce costs due to the impact of the COVID-19 pandemic on their customers. In addition, if the COVID-19 pandemic continues to create disruptions or turmoil in the credit or financial markets, or adversely impacts Entergy’s credit metrics or ratings, such developments could adversely affect its ability to access capital on favorable terms and continue to meet its
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liquidity needs, or cause a decrease in the value of its defined benefit pension trust funds, as well as its nuclear decommissioning trust funds, all of which are highly uncertain and cannot be predicted.
Entergy cannot predict the extent or duration of the outbreak, the impact of new variants of COVID-19, the timing, availability, distribution or effectiveness of a vaccine, anti-viral or other treatments for COVID-19, governmental responsive measures, or the extent of the effects or ultimate impacts on the global, national or local economy, the capital markets, or its customers, suppliers, operations, financial condition, results of operations, or cash flows.
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 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 affected stakeholders.
In addition, regulators may initiate 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 the Utility operating companies may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings.
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 the operation of their assets and infrastructure or the quality 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.
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. These riders include a distribution cost recovery factor rider mechanism for the recovery of distribution-related capital investment and certain non-fuel MISO charges, a transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a generation cost recovery rider mechanism for the recovery of generation-related capital investments, and a fixed fuel factor mechanism for the recovery of MISO fuel and energy-related costs. Entergy Texas also is required to make a filing every three years,
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at a minimum, reconciling its fuel and purchased power costs and fuel factor revenues. 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 for the reconciliation period. Entergy Texas also 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.
Between base rate cases, Entergy Arkansas and Entergy Mississippi are able to adjust base rates annually through formula rate plans that utilize a forward test year (Entergy Arkansas) or forward-looking features (Entergy Mississippi). 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 expires in 2021. Entergy Arkansas has requested APSC approval of the extension of the formula rate plan tariff for an additional five years through 2026. If Entergy Arkansas’s formula rate plan were terminated or not extended beyond the initial term, 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. If Entergy Mississippi’s formula rate plan is terminated, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan. Entergy Arkansas and Entergy Mississippi recover fuel and purchased energy and certain non-fuel costs through other APSC-approved and MPSC-approved tariffs, respectively.
Entergy Louisiana historically sets electric base rates annually through a formula rate plan using an 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. The formula rate plan was most recently extended through the test year 2019; certain modifications were made in that extension, including a decrease to the allowed return on equity and the addition of a transmission 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 and as noted, for certain transmission investment, among other items. MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause. Entergy Louisiana has a pending request to extend its formula rate plan with certain modifications, including implementation of a distribution investment recovery mechanism and use of end of period rate base. In the event that the electric formula rate plan is not renewed or extended, Entergy Louisiana would revert to the more traditional rate case environment.
Entergy New Orleans previously operated under a formula rate plan that ended with the 2011 test year. Based on a settlement agreement approved by the City Council, with limited exceptions, the base rates of Entergy New Orleans were frozen until rates were implemented in connection with 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. In November 2020 the City Council issued a resolution approving a settlement of the 2018 rate case. As part of this settlement, Entergy New Orleans agreed to postpone the filing of its first test year formula rate plan to 2021 and, in return, to be provided an additional test year for the three-year cycle. See Note 2 to the financial statements for further discussion.
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
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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, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a separate request for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material 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. System Energy has received FERC acceptance for billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
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. 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, 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 could put upward pressure on rates, resulting in adverse regulatory actions to mitigate such effects on rates. 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.
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, 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 very 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. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power costs recovery, see Note 2 to the financial statements.
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There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
The Utility operating companies historically engaged in the coordinated planning, construction, and operation of generating resources and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that had been approved by the FERC. The System Agreement terminated in its entirety on August 31, 2016.
There remains uncertainty regarding the long-term effect of the termination of the System Agreement on the Utility operating companies because of the significant effect of the agreement on the generation and transmission functions of the Utility operating companies and the significant period of time (over 30 years) that it had been in existence. In the absence of the System Agreement, there remains uncertainty around the effectiveness of governance processes and the potential absence of federal authority to resolve certain issues among the Utility operating companies and their retail regulators.
In addition, although the System Agreement terminated in its entirety in August 2016, there are a few outstanding System Agreement proceedings at the FERC and at the D.C. Circuit that may require future adjustments, including challenges to the level and timing of payments made by Entergy Arkansas under the System Agreement. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.
For further information regarding the regulatory proceedings relating to the System Agreement, 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.
On December 19, 2013, the Utility operating companies integrated into the MISO RTO. 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. 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 generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The Utility operating companies are subject to economic risks associated with participation in the MISO markets. 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 the cost of serving the Utility operating companies’ respective loads, and MISO market rules may change in ways that cause additional risk.
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. 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, 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
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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 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. 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. These filings have been submitted periodically by each of the Utility operating companies as required by their respective retail regulators, and the outcome of the resulting proceedings may affect the Utility operating companies’ continued membership in MISO.
(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 (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta), or the impact on customer bills of permitted storm cost recovery, 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 or revenues lost as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather. 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.
In August and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Utility’s service territories in Louisiana, including New Orleans, Texas, and to a lesser extent, in Arkansas and Mississippi. The storms resulted in widespread power 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. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.4 billion. Because Entergy has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities must 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, System Energy, and Entergy Wholesale Commodities. Nuclear plant operations involve substantial fixed operating
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costs. Consequently, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity factors, consistent with safety requirements. For the Utility operating companies that own nuclear plants, lower 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. For the Entergy Wholesale Commodities nuclear plants, lower capacity factors directly affect revenues and cash flow from operations. Entergy Wholesale Commodities’ forward sales are comprised of various hedge products, many of which have some degree of operational-contingent price risk. Certain unit-contingent contracts guarantee specified minimum capacity factors. In the event plants with these contracts were operating below the guaranteed capacity factors, Entergy would be subject to price risk for the undelivered power. Further, Entergy Wholesale Commodities’ nuclear forward sales contracts can also be on a firm LD basis, which subjects Entergy to increasing price risk as capacity factors decrease. Many of these firm hedge products have damages risk.
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 typically extends the planned outage duration. 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 2020 and beyond. 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 or limitations on importation of uranium or uranium products from foreign countries, or shifting trade arrangements 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 normal inherent market uncertainties, 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 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 countries, such as Russia, in which international sanctions or tariffs could further restrict the ability of such
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suppliers to continue to supply fuel or provide such services at acceptable prices or at all. The inability of such suppliers or service providers 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.
Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business 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 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 (through Entergy Wholesale Commodities), its 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, System Energy, and the Entergy Wholesale Commodities business, 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, System Energy, or Entergy Wholesale Commodities.
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities 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, System Energy, and the Entergy Wholesale Commodities business 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 the 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 the Utility operating companies and System Energy, this could result in certain costs being stranded and potentially not fully recoverable in regulatory proceedings. For Entergy Wholesale Commodities, this could result in lost revenue and increased fuel and purchased power expense to meet
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supply commitments and penalties for failure to perform under their contracts with customers. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
The nuclear industry continues to address susceptibility to the effects of stress corrosion cracking and other corrosion mechanisms on certain materials within plant systems. The issue is applicable at all nuclear units to varying degrees and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.
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 Entergy.
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities nuclear power plants, 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, System Energy, and the owners of the Entergy Wholesale Commodities nuclear plants 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 Yucca Mountain 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 has breached 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, System Energy, and the Entergy Wholesale Commodities nuclear plant owners may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act 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. 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 $137.6 million per reactor. With 97 reactors currently
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participating, this translates to a total public liability cap of approximately $14 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 required by the Price-Anderson Act, the Utility operating companies, System Energy, and Entergy Wholesale Commodities carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which is $450 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. 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, System Energy, and the Entergy Wholesale Commodities plant owners, 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 $137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.101 billion). The retrospective premium payment is currently limited to approximately $21 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $137.6 million cap.
NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities plants. 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 December 31, 2020, the maximum annual assessment amounts total $104 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments and the Entergy Wholesale Commodities plants currently maintain the retrospective premium insurance to cover those potential assessments.
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, System Energy, or the Entergy Wholesale Commodities subsidiaries.
The decommissioning trust fund assets for the nuclear power plants owned by the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners 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, System Energy, and owners of the Entergy Wholesale Commodities nuclear power plants maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies 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
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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 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. In addition to NRC requirements, there are other decommissioning-related obligations for certain of the Entergy Wholesale Commodities nuclear power plants, which management believes it will be able to satisfy.
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 Utility operating companies, System Energy, or Entergy Wholesale Commodities nuclear power plants 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, Entergy’s results of operations, liquidity, and financial condition 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 the Utility operating companies, System Energy, or the Entergy Wholesale Commodities nuclear plant owners may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to the Utility operating companies, may not be recoverable from customers in a timely fashion or at all.
For further information regarding nuclear decommissioning costs, management’s decision to exit the merchant power business, the impairment charges that resulted from such decision, and the planned sales of Palisades and Indian Point Energy Center (which, in each case, will include the transfer of the associated decommissioning trusts), 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, the “Entergy Wholesale Commodities Exit from the Merchant Power Business” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries, and Notes 9 and 14 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.
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(Entergy Corporation)
Entergy Wholesale Commodities nuclear power plants are exposed to price risk.
Entergy and its subsidiaries do not have a regulator-authorized rate of return on their capital investments in non-utility businesses. As a result, the sale of capacity and energy from the Entergy Wholesale Commodities nuclear power plants, unless otherwise contracted, is subject to the fluctuation of market power prices. In order to reduce future price risk to desired levels, Entergy Wholesale Commodities utilizes contracts that are unit-contingent and Firm LD and various products such as forward sales, options, and collars. As of December 31, 2020, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 98% in 2021 and 99% in 2022 of its generation portfolio’s planned energy output, reflecting the planned shutdown and sale of the remaining Entergy Wholesale Commodities nuclear power plants by mid-2022.
Market conditions such as product cost, market liquidity, and other portfolio considerations influence the product and contractual mix. The obligations under unit-contingent agreements depend on a generating asset that is operating; if the generation asset is not operating, the seller generally is not liable for damages. For some unit-contingent obligations, however, there is also a guarantee of availability that provides for the payment to the power purchaser of contract damages, if incurred, in the event the unit owner fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. Firm LD sales transactions may be exposed to substantial operational price risk, a portion of which may be capped through the use of risk management products, to the extent that the plants do not run as expected and market prices exceed contract prices.
Market prices may fluctuate substantially, sometimes over relatively short periods of time, and at other times experience sustained increases or decreases. Demand for electricity and its fuel stock can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, from time to time there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, credit requirements, bidding rules, and other mechanisms to address volatility and other issues in these markets.
The effects of sustained low natural gas prices and power market structure challenges have resulted in lower market prices for electricity in the power regions where the Entergy Wholesale Commodities nuclear power plants are located. In addition, currently the market design under which the plants operate does not adequately compensate merchant nuclear plants for their environmental and fuel diversity benefits in the region. These conditions were primary factors leading to Entergy’s decision to shut down (or sell) Entergy Wholesale Commodities’ nuclear power plants before the end of their operating licenses.
The price that different counterparties offer for various products including forward sales is influenced both by market conditions as well as the contract terms such as damage provisions, credit support requirements, and the number of available counterparties interested in contracting for the desired forward period. Depending on differences between market factors at the time of contracting versus current conditions, Entergy Wholesale Commodities’ contract portfolio may have average contract prices above or below current market prices, including at the expiration of the contracts, which may significantly affect Entergy Wholesale Commodities’ results of operations, financial condition, or liquidity. New hedges are generally layered into on a rolling forward basis, which tends to drive hedge over-performance to market in a falling price environment, and hedge underperformance to market in a rising price environment; however, hedge timing, product choice, and hedging costs will also affect these results. See the “Market and Credit Risk Sensitive Instruments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. Since Entergy Wholesale Commodities has announced the closure (or sale) of its nuclear plants, Entergy Wholesale Commodities may enter into fewer forward sales contracts for output from such plants.
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The Entergy Wholesale Commodities business is 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.
The Entergy Wholesale Commodities business is subject to extensive regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause the Entergy Wholesale Commodities business 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. Each of the owners of the Entergy Wholesale Commodities nuclear power plants that generates electricity, as well as Entergy Nuclear Power Marketing, LLC, is 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 these generating and power marketing companies the authority to sell electricity at market-based rates. The FERC’s orders that grant the Entergy Wholesale Commodities’ generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that the Entergy Wholesale Commodities business can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, the Entergy Wholesale Commodities’ market-based sales are subject to certain market behavior rules, and if any of its generating and power marketing companies 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 $1.29 million per day per violation. If the Entergy Wholesale Commodities’ generating or power marketing companies were to lose their market-based rate authority, such companies 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 the Entergy Wholesale Commodities business charges for power from its facilities.
The Entergy Wholesale Commodities business is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operators. The Independent System Operators that oversee most of the wholesale power markets may impose, 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 these markets. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of the Entergy Wholesale Commodities business’ generation facilities that sell energy and capacity into the wholesale power markets. For further information regarding federal, state, and local laws and regulation applicable to the Entergy Wholesale Commodities business, see the “Regulation of Entergy’s Business” section in Part I, Item 1.
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 the Entergy Wholesale Commodities business. 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 because energy prices in wholesale markets exceed the marginal cost of operating nuclear power plants, 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, the Entergy Wholesale Commodities business’ results of operations, financial condition, and liquidity could be materially affected.
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The power plants owned by the Entergy Wholesale Commodities business are subject to impairment charges in certain circumstances, which could have a material effect on Entergy’s results of operations, financial condition, or liquidity.
Entergy reviews long-lived assets held in all of its business segments 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 the operations of such 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. In particular, the remaining assets of the Entergy Wholesale Commodities business are subject to further impairment in connection with the closure and sale of its nuclear power plants. Moreover, prior to the closure and sale of these plants, the failure of the Entergy Wholesale Commodities business to achieve forecasted operating results and cash flows, an unfavorable change in forecasted operating results or cash flows, a reduction in the expected remaining useful life of a unit, or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.
If Entergy concludes that any of its nuclear power plants is unlikely to operate through its planned shutdown date, which conclusion would be based on a variety of factors, such a conclusion could result in a further impairment of part or all of the carrying value of the plant. Any impairment charge taken by Entergy with respect to its long-lived assets, including the remaining power plants owned by the Entergy Wholesale Commodities business, would likely be material in the quarter that the charge is taken and could otherwise have a material effect on Entergy’s results of operations, financial condition, or liquidity. For further information regarding evaluating long-lived assets for impairment, see the “Critical Accounting Estimates - Impairment of Long-lived Assets” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and for further discussion of the impairment charges, see Note 14 to the financial statements.
General Business
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Entergy and the Utility operating companies 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, access capital and 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 and Entergy Wholesale Commodities. In addition, Entergy’s and the Utility operating companies’ 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 territory with Hurricane Katrina and Hurricane Rita in 2005, Hurricane Gustav and Hurricane Ike in 2008, Hurricane Isaac in 2012, and Hurricane Laura, Hurricane Delta, and Hurricane Zeta in 2020. The occurrence of one or more contingencies, including 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 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 and the Utility operating companies, which in turn could negatively affect access to the capital markets.
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The inability to raise capital on favorable terms, particularly during times of high interest rates, 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 companies that experience extreme weather events, that rely on fossil fuels or offerings to fund fossil fuel projects, or due to risks related to climate change. Events 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. 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.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
A downgrade in Entergy Corporation’s or its subsidiaries’ credit ratings could negatively affect Entergy Corporation’s and its subsidiaries’ ability to access capital and/or could require Entergy Corporation 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 Corporation and the Registrant Subsidiaries, including each Registrant’s regulatory framework, ability to recover costs and earn returns, diversification and financial strength and liquidity. If one or more rating agencies downgrade Entergy Corporation’s, any of the Utility operating companies’, or System Energy’s 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 Corporation’s and its subsidiaries’ suppliers and counterparties require sufficient creditworthiness to enter into transactions. If Entergy Corporation’s or its subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy Corporation 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 Corporation or its subsidiaries. At December 31, 2020 based on power prices at that time, Entergy had liquidity exposure of $62 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $6 million of posted cash collateral. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2020, Entergy would have been required to provide approximately $30 million of additional cash or letters of credit under some of the agreements. As of December 31, 2020, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $22 million for a $1 per MMBtu increase in gas prices in both the short- and long-term markets.
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 and CARES Act of 2020 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 interpretive
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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.
As further described in Note 3 to the financial statements, as a result of amortization of accumulated deferred income taxes and payment of such amounts to customers in 2019, Entergy’s net regulatory liability for income taxes balance is $1.6 billion as of December 31, 2020. 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. Further, there may be other material effects resulting from the legislation that have not been identified.
See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act on 2018, 2019 and 2020 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.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s, the Utility operating companies’, and System Energy’s 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. 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, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition, and liquidity. For further information regarding Entergy’s income taxes, see 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 benefits that they anticipate from such transactions.
Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, which are subject to business, regulatory, economic, 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, Entergy has entered into an agreement to sell its equity interests in the subsidiary that owns the Palisades Nuclear Plant and the decommissioned Big Rock Point Nuclear Power Plant and an agreement to sell the equity interests of Indian Point 1, Indian Point 2, and Indian Point 3, in each case after each of the plants has been shut down and defueled. Also, a significant portion of Entergy’s utility business over the next several years includes the construction and/or purchase of a variety of generating units. These transactions and plans are or may become subject to regulatory approval and other material conditions or contingencies. 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:
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•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 disposition of a business, including Entergy’s planned exit from the merchant power 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, in a timely 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, and reliance on suppliers for timely and satisfactory performance. Delays in obtaining permits, 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, and other events beyond the control of the Utility operating companies or the Entergy Wholesale Commodities business 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 territory, and as to the Entergy Wholesale Commodities business, 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.
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Failure to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
We rely on a large and changing workforce of team members, including employees, contractors and temporary staffing. Certain events, such as an aging workforce, mismatching of skill sets, failing to appropriately anticipate future workforce needs, or the unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base, and the time required for skill development. In this case, 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 workforce needs associated with nuclear generation facilities and new skills required to operate a modernized, technology-enabled 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.
The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs to fulfill their obligations related to environmental and other matters.
The businesses in which the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business 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, System Energy, and the Entergy Wholesale Commodities business conduct their operations and make capital expenditures. These laws and regulations also affect how the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business 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, System Energy, and the Entergy Wholesale Commodities business 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, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business potentially are subject to 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, System Energy, and Entergy Wholesale Commodities and of property 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. The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business 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 air emissions from generating plants potentially are subject to increased regulation, controls, and mitigation expenses. In addition, existing air 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 compel greenhouse gas emission reductions, 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
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stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, see the “Regulation of Entergy’s Business – Environmental Regulation” section of Part I, Item 1.
The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business 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 Wholesale Commodities businesses.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
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 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. Extreme weather conditions including hurricanes or tropical storms, flooding events, or ice storms 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, 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. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and their replacement with more efficient ones, 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 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
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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 effects of climate change, environmental and regulatory obligations intended to compel greenhouse gas emission reductions or increase clean or renewable energy requirements or to place a price on greenhouse gas emissions, or achieving voluntary climate commitments could materially affect the financial condition, results of operations, and liquidity of Entergy, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.
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, in response to the United States Supreme Court’s 2007 decision holding that the EPA has authority to regulate emissions of CO2 and other “greenhouse gases” under the Clean Air Act, the EPA, various environmental interest groups, and other organizations focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. Since that ruling, the EPA has promulgated regulations controlling greenhouse gas emissions from certain vehicles, and from new, existing, and significantly modified stationary sources of emissions, including electric generating units. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been developed in California. In Louisiana, the Office of the Governor announced the creation of a Climate Initiatives Task Force and issued an executive order that established a path to net-zero emissions by 2050 while 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 will have on existing and pending environmental laws and regulations related to greenhouse gas emissions is currently unclear.
Developing and implementing plans for compliance with greenhouse gas emissions reduction, 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) at lower than expected capacity factors could require increased generation from higher emitting units, thus increasing the company’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 the Utility operating companies, System Energy, or Entergy Wholesale Commodities do business. Violations of such requirements may subject Entergy Wholesale Commodities and 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. 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 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) could 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
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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 addition to the regulatory and financial risks associated with climate change discussed above, potential physical risks from climate change include an increase in sea level, wind and storm surge damages, wildfires, wetland and barrier island erosion, risks of 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 subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms, 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 supply necessary for operations.
These and other physical changes could result in 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, 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, Entergy Wholesale Commodities’, System Energy’s, and the Utility operating companies’ financial condition, results of operations, and liquidity.
In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. Technology research and development, innovation, and advancement are critical to Entergy’s ability to achieve this commitment. Moreover, Entergy cannot predict the ultimate impact of achieving this objective, or the various implementation aspects, on its system reliability, or its results of operations, financial condition or liquidity.
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 the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.
Water is a vital natural resource that is also critical to the Utility operating companies’, System Energy’s, and Entergy Wholesale Commodities’ business operations. Entergy’s 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 business operations. Impacts to water availability or quality could negatively impact both operations and revenues.
Entergy secures water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operates under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy also obtains and operates 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, and the potential impacts of climate change on water resources may cause water use restrictions that affect Entergy and its subsidiaries.
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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 financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies and the Entergy Wholesale Commodities business, 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 the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy Wholesale Commodities.
The hedging and risk management practices of the Utility operating companies and the Entergy Wholesale Commodities 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.
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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 benefit 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 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 benefit 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 benefit 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 certain Entergy subsidiaries operate poses a significant risk to those businesses.
Entergy and its subsidiaries are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and ratepayer matters, and injuries and damages issues, among other matters. The states in which the Utility operating companies 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, cyber attacks, system failures or data breaches of Entergy’s and its subsidiaries’ or our suppliers’ technology systems may adversely affect Entergy’s results of 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 and employees, 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 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. As an operator of critical infrastructure, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism, cyber 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. An actual act could affect Entergy’s 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, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security
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and controls. If Entergy’s or its subsidiaries’ technology systems 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 its confidential, sensitive, and proprietary information, including personal information of its customers, employees, suppliers, and others in Entergy’s care.
Any such attacks, failures or data breaches could have a material effect on Entergy’s and the Utility operating companies’ business, financial condition, results of operations or reputation. Although we purchase insurance coverage for cyber-attacks or data breaches, such insurance may not be adequate to cover all losses that might arise in connection with these events. Such events may also expose Entergy to an increased risk of litigation (and associated damages and fines).
(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 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 period when gas is purchased and the time when ultimate recovery from customers occurs.
(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.
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 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 expires in November 2044. System Energy’s financial condition depends both on the receipt of payments from the Utility operating companies 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, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a request in a separate proceeding for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. The LPSC has also authorized the filing of a prudence complaint at the FERC relating to Grand Gulf operations. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material 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 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 the Entergy System companies’ support of System Energy, see Notes 5 and 8 to the
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Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.
(Entergy Corporation)
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.
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’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 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 and are therefore subject to prior payment of distributions on its preferred securities.
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ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy Arkansas’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $10 million. Natural gas purchases for Entergy Arkansas for February 1st through 25th, 2021 are approximately $105 million compared to natural gas purchases for February 2020 of $10 million.
Results of Operations
2020 Compared to 2019
Net Income
Net income decreased $17.7 million primarily due to lower volume/weather, a formula rate plan provision recorded in 2020 to reflect the 2019 historical year netting adjustment, and higher depreciation and amortization expenses, partially offset by higher retail electric price and lower other operation and maintenance expenses. See Note 2 to the financial statements for discussion of the 2019 historical year netting adjustment.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2020 to 2019:
| Amount | |||||
| (In Millions) | |||||
| 2019 operating revenues | $2,259.6 | ||||
| Fuel, rider, and other revenues that do not significantly affect net income | (278.5) | ||||
| Volume/weather | (72.2) | ||||
| Retail electric price | 57.4 | ||||
| Return of unprotected excess accumulated deferred income taxes to customers | 118.2 | ||||
| 2020 operating revenues | $2,084.5 | ||||
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 a decrease of 1,069 GWh, or 5%, in billed electricity usage, including decreased commercial and industrial usage as a result of the COVID-19 pandemic, and the effect of less favorable weather on residential and commercial sales, partially offset by an increase in residential usage as a
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result of the COVID-19 pandemic. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the COVID-19 pandemic.
The retail electric price variance is primarily due to the $56.5 million annual formula rate plan increase related to the 2020 projected test year included in the 2019 formula rate plan filing effective with the first billing cycle of January 2020. See Note 2 to the financial statements for further discussion of the formula rate plan filing.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through a tax adjustment rider beginning in April 2018. In 2020, $8.1 million was returned to customers as compared to $126.3 million in 2019. There is no effect on net income as the reduction in operating revenues in each period was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
Other Income Statement Variances
Nuclear refueling outage expenses decreased primarily due to the amortization of lower costs associated with the most recent outages as compared to previous outages.
Other operation and maintenance expenses decreased primarily due to:
•a decrease of $18.3 million in nuclear generation expenses primarily due to lower nuclear labor costs, including contract labor, in part as a result of the COVID-19 pandemic;
•a decrease of $13.2 million in non-nuclear generation expenses primarily due to lower long-term service agreement expenses;
•an $11.2 million write-off in 2019 of specific costs related to the potential construction of scrubbers at the White Bluff plant. See Note 2 to the financial statements for discussion of the write-off;
•higher nuclear insurance refunds of $7.8 million;
•a decrease of $5.9 million primarily due to contract costs in 2019 related to initiatives to explore new customer products and services; and
•a decrease of $5.8 million in energy efficiency costs.
The decrease was partially offset by the effects of recording in 2019 a final judgment 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 $11.9 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other income increased primarily due to changes in decommissioning trust fund investment activity.
Other regulatory credits - net for 2020 includes a provision of $43.5 million to reflect the 2019 historical year netting adjustment included in the APSC’s December 2020 order in the 2020 formula rate plan proceeding. See Note 2 to the financial statements for discussion of the 2020 formula rate plan proceeding.
The effective income tax rates were 16.3% for 2020 and (21.6%) for 2019. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2019 was primarily due to the amortization of excess accumulated deferred income taxes. See Notes 2 and 3 to the financial statements for a discussion of the effects and regulatory activity regarding the Tax Cuts and Jobs Act. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.
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Management’s Financial Discussion and Analysis
2019 Compared to 2018
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, 2019, filed with the SEC on February 21, 2020, for discussion of results of operations for 2019 compared to 2018.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, and 2018 were as follows:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Thousands) | |||||||||||||||||
| Cash and cash equivalents at beginning of period | $3,519 | $119 | $6,216 | ||||||||||||||
| Net cash provided by (used in): | |||||||||||||||||
| Operating activities | 659,818 | 677,766 | 211,825 | ||||||||||||||
| Investing activities | (795,709) | (676,293) | (688,727) | ||||||||||||||
| Financing activities | 324,500 | 1,927 | 470,805 | ||||||||||||||
| Net increase (decrease) in cash and cash equivalents | 188,609 | 3,400 | (6,097) | ||||||||||||||
| Cash and cash equivalents at end of period | $192,128 | $3,519 | $119 | ||||||||||||||
2020 Compared to 2019
Operating Activities
Net cash flow provided by operating activities decreased $17.9 million in 2020 primarily due to:
•the timing of recovery of fuel and purchased power costs;
•lower collections of receivables from customers, in part due to the COVID-19 pandemic; and
•the timing of payments to vendors.
The decrease was partially offset by:
•a decrease in the return of unprotected excess accumulated deferred income taxes to customers in 2020 as compared to 2019. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act;
•$25 million in proceeds received from the DOE in 2020 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; and
•a decrease of $15.8 million in pension contributions in 2020. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
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Investing Activities
Net cash flow used in investing activities increased $119.4 million in 2020 primarily due to:
•an increase of $79.5 million in storm spending;
•an increase of $47.3 million in non-nuclear generation construction expenditures primarily due to increased spending on various projects in 2020;
•an increase of $39.4 million in nuclear construction expenditures primarily as a result of work performed in 2020 on various ANO 2 outage projects;
•an increase of $38.5 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 in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle; and
•an increase of $30.3 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Arkansas’s distribution system, including increased spending on advanced metering infrastructure.
The increase was partially offset by:
•a decrease of $56 million in transmission construction expenditures primarily due to a lower scope of work performed in 2020 as compared to 2019; and
•$55 million in proceeds received from the DOE in 2020 resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Financing Activities
Net cash flow provided by financing activities increased $322.6 million in 2020 primarily due to:
•issuances of $100 million of 4.0% Series mortgage bonds in March 2020 and $675 million of 2.65% Series mortgage bonds in September 2020;
•money pool activity;
•a decrease of $41.6 million in net long-term repayments in 2020 on the Entergy Arkansas nuclear fuel company variable interest entity credit facility; and
•a decrease of $20 million in common equity distributions in 2020 in order to maintain Entergy Arkansas’s capital structure.
The increase was partially offset by:
•the issuance of $350 million of 4.20% Series mortgage bonds in March 2019;
•the repayment in October 2020 of $200 million of 4.90% Series mortgage bonds due December 2052; and
•the repayment in October 2020 of $125 million of 4.75% Series mortgage bonds due June 2063.
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 by $21.6 million in 2020 compared to decreasing by $161.1 million in 2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
See Note 5 to the financial statements for further details of long-term debt.
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2019 Compared to 2018
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, 2019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
Capital Structure
Entergy Arkansas’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio is primarily due to the net issuances of long-term debt in 2020.
| December 31, 2020 | December 31, 2019 | ||||||||||
| Debt to capital | 54.8 | % | 53.0 | % | |||||||
| Effect of excluding the securitization bonds | — | % | — | % | |||||||
| Debt to capital, excluding securitization bonds (a) | 54.8 | % | 53.0 | % | |||||||
| Effect of subtracting cash | (1.2 | %) | — | % | |||||||
| Net debt to net capital, excluding securitization bonds (a) | 53.6 | % | 53.0 | % | |||||||
(a)Calculation excludes the securitization bonds, which are non-recourse to Entergy Arkansas.
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 ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because the securitization bonds, which have been repaid as of December 31, 2020, were non-recourse to Entergy Arkansas, as more fully described in Note 5 to the financial statements. Entergy Arkansas 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 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, 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 reducing distributions, Entergy Arkansas may receive equity contributions to maintain its capital structure.
Uses of Capital
Entergy Arkansas requires capital resources for:
•construction and other capital investments;
•debt maturities or retirements;
•working capital purposes, including the financing of fuel and purchased power costs; and
•distribution and interest payments.
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Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
| 2021 | 2022 | 2023 | |||||||||||||||
| (In Millions) | |||||||||||||||||
| Planned construction and capital investment: | |||||||||||||||||
| Generation | $340 | $355 | $430 | ||||||||||||||
| Transmission | 40 | 45 | 190 | ||||||||||||||
| Distribution | 95 | 255 | 420 | ||||||||||||||
| Utility Support | 105 | 80 | 75 | ||||||||||||||
| Total | $580 | $735 | $1,115 | ||||||||||||||
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| 2021 | 2022-2023 | 2024-2025 | After 2025 | Total | |||||||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||||||||
| Long-term debt (a) | $611 | $543 | $581 | $4,713 | $6,448 | ||||||||||||||||||||||||
| Operating leases (b) | $14 | $21 | $15 | $11 | $61 | ||||||||||||||||||||||||
| Finance leases (b) | $3 | $5 | $3 | $2 | $13 | ||||||||||||||||||||||||
| Purchase obligations (c) | $452 | $618 | $509 | $3,882 | $5,461 | ||||||||||||||||||||||||
(a)Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.
(b)Lease obligations are discussed in Note 10 to the financial statements.
(c)Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Arkansas, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which are discussed in Note 8 to the financial statements.
In addition to the contractual obligations given above, Entergy Arkansas currently expects to contribute approximately $66.6 million to its qualified pension plans and approximately $517 thousand to its other postretirement health care and life insurance plans in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy Arkansas has $252 million of unrecognized tax benefits and interest net of unused tax attributes 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 to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes specific investments in renewables such as the Searcy Solar Facility, Walnut Bend Solar Facility, and West Memphis Solar Facility; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; investments in ANO 1 and 2; software and security; 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, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt maturities in Note 5 to the financial statements.
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As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.
Renewables
Searcy Solar Facility
In March 2019, Entergy Arkansas announced that it signed an agreement for the purchase of an approximately 100 MW solar energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. The purchase is contingent upon, among other things, obtaining necessary approvals from applicable federal and state regulatory and permitting agencies. The project is being constructed by a subsidiary of NextEra Energy Resources. Entergy Arkansas will purchase the facility upon mechanical completion and after the other purchase contingencies have been met. Closing is expected to occur by the end of 2021. In May 2019, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. In September 2019 other parties filed testimony largely supporting the resource acquisition but disputing Entergy Arkansas’s proposed method of cost recovery. Entergy Arkansas filed its rebuttal testimony in October 2019. In February 2020, Entergy Arkansas, the Attorney General, and the APSC general staff filed a partial settlement agreement asking the APSC to approve, based on the record in the proceeding, all issues except certain issues that are submitted to the APSC for determination. In April 2020 the APSC issued an order approving Entergy Arkansas’s acquisition of the Searcy Solar facility as being in the public interest, but declined to approve Entergy Arkansas’s preferred cost recovery rider mechanism, finding instead, based on the particular facts and circumstances presented, that the formula rate plan rider was a sufficient recovery mechanism for this resource.
Walnut Bend Solar Facility
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 requested a decision by the APSC by June 15, 2021 and primarily requests cost recovery through the formula rate plan rider. A procedural schedule was established with a hearing scheduled in April 2021. Closing is expected to occur in 2022.
West Memphis Solar Facility
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. Entergy Arkansas requested a decision by the APSC by September 7, 2021 and primarily requests cost recovery through the formula rate plan rider. Closing is expected to occur in 2023.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy Arkansas may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
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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 indentures and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| 2020 | 2019 | 2018 | 2017 | |||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| $3,110 | ($21,634) | ($182,738) | ($166,137) | |||||||||||||||||
See Note 4 to the financial statements for a description of the money pool.
Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in September 2024. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2021. 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, 2020, 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, 2020, a $1 million letter of credit was 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 September 2022. As of December 31, 2020, $12.2 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 July 2022 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 July 2022. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2022.
State and Local Rate Regulation and Fuel-Cost Recovery
Retail Rates
2018 Formula Rate Plan Filing
In July 2018, Entergy Arkansas filed with the APSC its 2018 formula rate plan filing to set its formula rate for the 2019 calendar year. The filing showed Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2019 test period to be below the formula rate plan bandwidth. Additionally, the filing included the first netting adjustment under the current formula rate plan for the historical test year 2017, reflecting the change in formula rate plan revenues associated with actual 2017 results when compared to the allowed rate of return on equity. The filing included a projected $73.4 million revenue deficiency for 2019 and a $95.6 million revenue deficiency for the 2017 historical test year, for a total revenue requirement of $169 million for this filing. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is
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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 four percent of total revenue, which originally was $65.4 million but was increased to $66.7 million based upon the APSC staff’s updated calculation of 2018 revenue. In October 2018, Entergy Arkansas and the parties to the proceeding filed joint motions to approve a partial settlement agreement as to certain factual issues and agreed to brief contested legal issues. In November 2018 the APSC held a hearing and was briefed on a contested legal issue. In December 2018 the APSC issued a decision related to the initial legal brief, approved the partial settlement agreement and $66.7 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan, with updated rates going into effect for the first billing cycle of January 2019.
2019 Formula Rate Plan Filing
In July 2019, Entergy Arkansas filed with the APSC its 2019 formula rate plan filing to set its formula rate for the 2020 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2020 and a netting adjustment for the historical year 2018. The total proposed formula rate plan rider revenue change designed to produce a target rate of return on common equity of 9.75% is $15.3 million, which is based upon a deficiency of approximately $61.9 million for the 2020 projected year, netted with a credit of approximately $46.6 million in the 2018 historical year netting adjustment. During 2018 Entergy Arkansas experienced higher-than expected sales volume, and actual costs were lower than forecasted. These changes, coupled with a reduced income tax rate resulting from the Tax Cuts and Jobs Act, resulted in the credit for the historical year netting adjustment. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflected the estimate of the historical year netting adjustment that was expected to be included in the 2019 filing. In 2019, Entergy Arkansas recorded additional provisions totaling $11.5 million to reflect the updated estimate of the historical year netting adjustment included in the 2019 filing. In October 2019 other parties in the proceeding filed their errors and objections requesting certain adjustments to Entergy Arkansas’s filing that would reduce or eliminate Entergy Arkansas’s proposed revenue change. Entergy Arkansas filed its response addressing the requested adjustments in October 2019. In its response, Entergy Arkansas accepted certain of the adjustments recommended by the General Staff of the APSC that would reduce the proposed formula rate plan rider revenue change to $14 million. Entergy Arkansas disputed the remaining adjustments proposed by the parties. In October 2019, Entergy Arkansas filed a unanimous settlement agreement with the other parties in the proceeding seeking APSC approval of a revised total formula rate plan rider revenue change of $10.1 million. In its July 2019 formula rate plan filing, Entergy Arkansas proposed to recover an $11.2 million regulatory asset, amortized over five years, associated with specific costs related to the potential construction of scrubbers at the White Bluff plant. Although Entergy Arkansas does not concede that the regulatory asset lacks merit, for purposes of reaching a settlement on the total formula rate plan rider amount, Entergy Arkansas agreed not to include the White Bluff scrubber regulatory asset cost in the 2019 formula rate plan filing or future filings. Entergy Arkansas recorded a write-off in 2019 of the $11.2 million White Bluff scrubber regulatory asset. In December 2019 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 2020.
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 is 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. In October 2020 other parties in the proceeding filed their errors
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and objections recommending certain adjustments, and Entergy Arkansas filed responsive testimony disputing these adjustments. 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, and in January 2021 the APSC granted further consideration of Entergy Arkansas’s petition. Based on the progress of the proceeding to date, 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. Also with the formula rate plan filing, Entergy Arkansas is requesting an extension of the formula rate plan rider for a second five-year term. Decisions by the APSC on the netting adjustment rehearing and the extension are expected in March 2021.
Internal Restructuring
In November 2017, Entergy Arkansas filed an application with the APSC seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy Arkansas to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. In July 2018, Entergy Arkansas filed a settlement, reached by all parties in the APSC proceeding, resolving all issues. The APSC approved the settlement agreement and restructuring in August 2018. Pursuant to the settlement agreement, Entergy Arkansas will credit retail customers $39.6 million over six years, beginning in 2019. Entergy Arkansas also received the required FERC and NRC approvals.
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.
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Production Cost Allocation Rider
The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section in Note 2 to the financial statements.
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 previously noted, subject to certain timelines and conditions set forth in the settlement agreement. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.
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 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 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
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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 2019, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01882 per kWh to $0.01462 per kWh and became effective with the first billing cycle in April 2019. In March 2019 the Arkansas Attorney General filed a response to Entergy Arkansas’s annual adjustment and included with its filing a motion for investigation of alleged overcharges to customers in connection with the FERC’s October 2018 order in the opportunity sales proceeding. Entergy Arkansas filed its response to the Attorney General’s motion in April 2019 in which Entergy Arkansas stated its intent to initiate a proceeding to address recovery issues related to the October 2018 FERC order. In May 2019, Entergy Arkansas initiated the opportunity sales recovery proceeding, discussed below, and requested that the APSC establish that proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC October 2018 order and related FERC orders in the opportunity sales proceeding. In June 2019 the APSC granted Entergy Arkansas’s request and also denied the Attorney General’s motion in the energy cost recovery proceeding seeking an investigation into Entergy Arkansas’s annual energy cost recovery rider adjustment and referred the evaluation of such matters to the opportunity sales recovery proceeding.
In March 2020, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01462 per kWh to $0.01052 per kWh. The redetermined rate became effective with the first billing cycle in April 2020 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
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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
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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. The December 2018 compliance filing is pending FERC action. 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) | |||||||||||
| (In Millions) | |||||||||||
| Principal | Interest | Total | |||||||||
| Entergy Arkansas | $68 | $67 | $135 | ||||||||
| Entergy Louisiana | ($30) | ($29) | ($59) | ||||||||
| Entergy Mississippi | ($18) | ($18) | ($36) | ||||||||
| Entergy New Orleans | ($3) | ($4) | ($7) | ||||||||
| Entergy Texas | ($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 have been 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 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.
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
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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 scheduled a hearing for February 26, 2021 regarding issues addressed in the pre-trial conference report.
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 would allow 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 has 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, cooperatives, the Arkansas Attorney General, industrial customers, and Entergy Arkansas 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
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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.
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.
COVID-19 Orders
In April 2020, in light of the COVID-19 pandemic, the APSC issued an order requiring utilities, to the extent they had not already done so, to suspend service disconnections during the remaining pendency of the Arkansas Governor’s emergency declaration or until the APSC rescinds the directive. The order also authorizes utilities to establish a regulatory asset to record costs resulting from the suspension of service disconnections, directs that in future proceedings the APSC will consider whether the request for recovery of these regulatory assets is reasonable and necessary, and requires utilities to track and report the costs and any savings directly attributable to suspension of disconnects. In May 2020 the APSC approved Entergy Arkansas expanding deferred payment agreements to assist customers during the COVID-19 pandemic. Quarterly reporting began in August 2020 and the APSC ordered additional reporting in October 2020 regarding utilities’ transitional plans for ending the moratorium on service disconnects. In February 2021 the APSC issued an order finding that it is not in the public interest to immediately lift the moratorium on service disconnects, but to announce a target date of May 3, 2021. In March 2021 the APSC will issue an order either confirming the lifting of the moratorium on service disconnects or extending the moratorium. As of December 31, 2020, Entergy Arkansas recorded a regulatory asset of $10.5 million for costs associated with the COVID-19 pandemic.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Nuclear Matters
Entergy Arkansas owns and, through an affiliate, operates the ANO 1 and ANO 2 nuclear power plants. Entergy Arkansas is, therefore, subject to the risks related to owning and operating nuclear plants. 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, to position Entergy’s nuclear fleet to meet its operational goals; the performance and capacity factors of these nuclear plants including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems; 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 and types of insurance commercially available 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 ANO 2, Entergy Arkansas may be required to
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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.
Environmental Risks
Entergy Arkansas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Arkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Arkansas’s financial statements in conformity with generally accepted accounting principles 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 policies and 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 the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Arkansas’s financial position or results of operations.
In the first quarter 2019, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and ANO 2 as a result of a revised decommissioning cost study. The revised estimates resulted in a $126.2 million increase in its decommissioning cost liabilities, along with corresponding increases in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Impairment of Long-lived Assets
See “Impairment of Long-lived Assets” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
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Qualified Pension and Other Postretirement Benefits
Entergy Arkansas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “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 and Sensitivities
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| Actuarial Assumption | Change in Assumption | Impact on 2021 Qualified Pension Cost | Impact on 2020 Qualified Projected Benefit Obligation | |||||||||||||||||
| Increase/(Decrease) | ||||||||||||||||||||
| Discount rate | (0.25%) | $2,406 | $46,791 | |||||||||||||||||
| Rate of return on plan assets | (0.25%) | $2,914 | $— | |||||||||||||||||
| Rate of increase in compensation | 0.25% | $1,838 | $8,922 | |||||||||||||||||
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| Actuarial Assumption | Change in Assumption | Impact on 2021 Postretirement Benefit Cost | Impact on 2020 Accumulated Postretirement Benefit Obligation | |||||||||||||||||
| Increase/(Decrease) | ||||||||||||||||||||
| Discount rate | (0.25%) | $174 | $6,576 | |||||||||||||||||
| Health care cost trend | 0.25% | $225 | $4,516 | |||||||||||||||||
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy Arkansas in 2020 was $81.7 million, including $21.1 million in settlement costs. Entergy Arkansas anticipates 2021 qualified pension cost to be $61.6 million. Entergy Arkansas contributed $60 million to its qualified pension plans in 2020 and estimates pension contributions will be approximately $66.6 million in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021.
Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 2020 was $10.1 million. Entergy Arkansas expects 2021 postretirement health care and life insurance benefit income of approximately $11.1 million. Entergy Arkansas contributed $2.2 million to its other postretirement plans in 2020 and estimates 2021 contributions will be approximately $517 thousand.
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Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
329
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the member and Board of Directors of
Entergy Arkansas, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Arkansas, LLC and Subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of income, cash flows and changes in member’s equity (pages 332 through 336 and applicable items in pages 51 through 238), for each of the three years in the period ended December 31, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters —Entergy Arkansas, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
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, such as property, plant, and equipment;
330
regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
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 significant 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, including costs related to the Opportunity Sales Proceeding and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the APSC and the FERC, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the APSC and the FERC 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 costs incurred as property, plant, and equipment and deferred as 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 property, plant, and equipment; 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 and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information 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 the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, including the Opportunity Sales Proceeding, we inspected the Company’s filings with the APSC and the FERC, including the annual formula rate plan filing, 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, including the Opportunity Sales Proceeding, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2021
We have served as the Company’s auditor since 2001.
331
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES | ||||||||||||||||||||
| CONSOLIDATED INCOME STATEMENTS | ||||||||||||||||||||
| For the Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| OPERATING REVENUES | ||||||||||||||||||||
| Electric | $2,084,494 | $2,259,594 | $2,060,643 | |||||||||||||||||
| OPERATING EXPENSES | ||||||||||||||||||||
| Operation and Maintenance: | ||||||||||||||||||||
| Fuel, fuel-related expenses, and gas purchased for resale | 271,896 | 458,907 | 517,245 | |||||||||||||||||
| Purchased power | 187,690 | 204,640 | 252,390 | |||||||||||||||||
| Nuclear refueling outage expenses | 55,737 | 68,769 | 77,915 | |||||||||||||||||
| Other operation and maintenance | 669,518 | 720,217 | 724,831 | |||||||||||||||||
| Decommissioning | 73,319 | 68,030 | 60,420 | |||||||||||||||||
| Taxes other than income taxes | 121,057 | 115,869 | 104,771 | |||||||||||||||||
| Depreciation and amortization | 338,029 | 307,351 | 292,649 | |||||||||||||||||
| Other regulatory credits - net | (35,310) | (11,186) | (14,807) | |||||||||||||||||
| TOTAL | 1,681,936 | 1,932,597 | 2,015,414 | |||||||||||||||||
| OPERATING INCOME | 402,558 | 326,997 | 45,229 | |||||||||||||||||
| OTHER INCOME | ||||||||||||||||||||
| Allowance for equity funds used during construction | 15,019 | 15,499 | 16,557 | |||||||||||||||||
| Interest and investment income | 35,579 | 26,020 | 25,406 | |||||||||||||||||
| Miscellaneous - net | (21,908) | (18,566) | (14,874) | |||||||||||||||||
| TOTAL | 28,690 | 22,953 | 27,089 | |||||||||||||||||
| INTEREST EXPENSE | ||||||||||||||||||||
| Interest expense | 144,834 | 140,087 | 124,459 | |||||||||||||||||
| Allowance for borrowed funds used during construction | (6,595) | (6,332) | (7,781) | |||||||||||||||||
| TOTAL | 138,239 | 133,755 | 116,678 | |||||||||||||||||
| INCOME (LOSS) BEFORE INCOME TAXES | 293,009 | 216,195 | (44,360) | |||||||||||||||||
| Income taxes | 47,777 | (46,769) | (297,067) | |||||||||||||||||
| NET INCOME | 245,232 | 262,964 | 252,707 | |||||||||||||||||
| Preferred dividend requirements | — | — | 1,249 | |||||||||||||||||
| EARNINGS APPLICABLE TO COMMON EQUITY | $245,232 | $262,964 | $251,458 | |||||||||||||||||
| See Notes to Financial Statements. | ||||||||||||||||||||
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| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES | ||||||||||||||||||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||||||||||||||||
| For the Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| OPERATING ACTIVITIES | ||||||||||||||||||||
| Net income | $245,232 | $262,964 | $252,707 | |||||||||||||||||
| Adjustments to reconcile net income to net cash flow provided by operating activities: | ||||||||||||||||||||
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | 490,457 | 465,299 | 443,698 | |||||||||||||||||
| Deferred income taxes, investment tax credits, and non-current taxes accrued | 87,019 | 94,368 | 129,524 | |||||||||||||||||
| Changes in assets and liabilities: | ||||||||||||||||||||
| Receivables | (24,507) | (58,077) | 4,294 | |||||||||||||||||
| Fuel inventory | (10,066) | (10,597) | 6,210 | |||||||||||||||||
| Accounts payable | (22,773) | 3,059 | (126,405) | |||||||||||||||||
| Prepaid taxes and taxes accrued | 6 | 24,942 | 9,568 | |||||||||||||||||
| Interest accrued | (43) | 3,895 | 678 | |||||||||||||||||
| Deferred fuel costs | (1,186) | 72,560 | 43,869 | |||||||||||||||||
| Other working capital accounts | (11,061) | 18,783 | (30,118) | |||||||||||||||||
| Provisions for estimated losses | 6,289 | 14,901 | 14,250 | |||||||||||||||||
| Other regulatory assets | (165,534) | (131,873) | 32,460 | |||||||||||||||||
| Other regulatory liabilities | 106,878 | 39,293 | (341,682) | |||||||||||||||||
| Pension and other postretirement liabilities | 42,576 | 5,831 | (40,157) | |||||||||||||||||
| Other assets and liabilities | (83,469) | (127,582) | (187,071) | |||||||||||||||||
| Net cash flow provided by operating activities | 659,818 | 677,766 | 211,825 | |||||||||||||||||
| INVESTING ACTIVITIES | ||||||||||||||||||||
| Construction expenditures | (775,595) | (641,525) | (660,044) | |||||||||||||||||
| Allowance for equity funds used during construction | 15,019 | 15,306 | 17,013 | |||||||||||||||||
| Nuclear fuel purchases | (100,678) | (54,344) | (99,417) | |||||||||||||||||
| Proceeds from sale of nuclear fuel | 30,638 | 22,782 | 54,810 | |||||||||||||||||
| Proceeds from nuclear decommissioning trust fund sales | 321,360 | 317,377 | 300,801 | |||||||||||||||||
| Investment in nuclear decommissioning trust funds | (336,392) | (336,519) | (315,163) | |||||||||||||||||
| Payment for purchase of assets | (5,988) | — | — | |||||||||||||||||
| Changes in money pool receivable - net | (3,110) | — | — | |||||||||||||||||
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | 55,001 | — | — | |||||||||||||||||
| Insurance proceeds | — | — | 14,790 | |||||||||||||||||
| Other | 4,036 | 630 | (1,517) | |||||||||||||||||
| Net cash flow used in investing activities | (795,709) | (676,293) | (688,727) | |||||||||||||||||
| FINANCING ACTIVITIES | ||||||||||||||||||||
| Proceeds from the issuance of long-term debt | 1,071,121 | 834,038 | 958,434 | |||||||||||||||||
| Retirement of long-term debt | (632,175) | (548,952) | (690,488) | |||||||||||||||||
| Capital contribution from parent | — | — | 350,000 | |||||||||||||||||
| Redemption of preferred stock | — | — | (32,660) | |||||||||||||||||
| Change in money pool payable - net | (21,634) | (161,104) | 16,601 | |||||||||||||||||
| Changes in short-term borrowings - net | — | — | (49,974) | |||||||||||||||||
| Distributions/dividends paid: | ||||||||||||||||||||
| Common equity | (95,000) | (115,000) | (91,751) | |||||||||||||||||
| Preferred stock | — | — | (1,606) | |||||||||||||||||
| Other | 2,188 | (7,055) | 12,249 | |||||||||||||||||
| Net cash flow provided by financing activities | 324,500 | 1,927 | 470,805 | |||||||||||||||||
| Net increase (decrease) in cash and cash equivalents | 188,609 | 3,400 | (6,097) | |||||||||||||||||
| Cash and cash equivalents at beginning of period | 3,519 | 119 | 6,216 | |||||||||||||||||
| Cash and cash equivalents at end of period | $192,128 | $3,519 | $119 | |||||||||||||||||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||||||||||||||||
| Cash paid (received) during the period for: | ||||||||||||||||||||
| Interest - net of amount capitalized | $140,735 | $131,134 | $118,731 | |||||||||||||||||
| Income taxes | ($21,971) | ($33,989) | $44,393 | |||||||||||||||||
| See Notes to Financial Statements. | ||||||||||||||||||||
333
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES | ||||||||||||||
| CONSOLIDATED BALANCE SHEETS | ||||||||||||||
| ASSETS | ||||||||||||||
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| CURRENT ASSETS | ||||||||||||||
| Cash and cash equivalents: | ||||||||||||||
| Cash | $24,108 | $3,519 | ||||||||||||
| Temporary cash investments | 168,020 | — | ||||||||||||
| Total cash and cash equivalents | 192,128 | 3,519 | ||||||||||||
| Securitization recovery trust account | — | 4,036 | ||||||||||||
| Accounts receivable: | ||||||||||||||
| Customer | 183,719 | 117,679 | ||||||||||||
| Allowance for doubtful accounts | (18,334) | (1,169) | ||||||||||||
| Associated companies | 34,216 | 29,178 | ||||||||||||
| Other | 35,845 | 117,653 | ||||||||||||
| Accrued unbilled revenues | 109,000 | 108,489 | ||||||||||||
| Total accounts receivable | 344,446 | 371,830 | ||||||||||||
| Fuel inventory - at average cost | 43,811 | 33,745 | ||||||||||||
| Materials and supplies - at average cost | 237,640 | 211,320 | ||||||||||||
| Deferred nuclear refueling outage costs | 32,692 | 48,875 | ||||||||||||
| Prepayments and other | 13,296 | 14,096 | ||||||||||||
| TOTAL | 864,013 | 687,421 | ||||||||||||
| OTHER PROPERTY AND INVESTMENTS | ||||||||||||||
| Decommissioning trust funds | 1,273,921 | 1,101,283 | ||||||||||||
| Other | 341 | 345 | ||||||||||||
| TOTAL | 1,274,262 | 1,101,628 | ||||||||||||
| UTILITY PLANT | ||||||||||||||
| Electric | 12,905,322 | 12,293,483 | ||||||||||||
| Construction work in progress | 234,213 | 197,775 | ||||||||||||
| Nuclear fuel | 163,044 | 195,547 | ||||||||||||
| TOTAL UTILITY PLANT | 13,302,579 | 12,686,805 | ||||||||||||
| Less - accumulated depreciation and amortization | 5,255,355 | 5,019,826 | ||||||||||||
| UTILITY PLANT - NET | 8,047,224 | 7,666,979 | ||||||||||||
| DEFERRED DEBITS AND OTHER ASSETS | ||||||||||||||
| Regulatory assets: | ||||||||||||||
Other regulatory assets (includes securitization property of $— as of December 31, 2020 and $1,706 as of December 31, 2019) | 1,832,384 | 1,666,850 | ||||||||||||
| Deferred fuel costs | 68,220 | 67,690 | ||||||||||||
| Other | 14,028 | 15,065 | ||||||||||||
| TOTAL | 1,914,632 | 1,749,605 | ||||||||||||
| TOTAL ASSETS | $12,100,131 | $11,205,633 | ||||||||||||
See Notes to Financial Statements. | ||||||||||||||
334
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES | ||||||||||||||
| CONSOLIDATED BALANCE SHEETS | ||||||||||||||
| LIABILITIES AND EQUITY | ||||||||||||||
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| CURRENT LIABILITIES | ||||||||||||||
| Currently maturing long-term debt | $485,000 | $— | ||||||||||||
| Accounts payable: | ||||||||||||||
| Associated companies | 59,448 | 111,785 | ||||||||||||
| Other | 208,591 | 202,201 | ||||||||||||
| Customer deposits | 98,506 | 101,411 | ||||||||||||
| Taxes accrued | 81,837 | 81,831 | ||||||||||||
| Interest accrued | 22,745 | 22,788 | ||||||||||||
| Deferred fuel costs | 53,065 | 53,721 | ||||||||||||
| Current portion of unprotected excess accumulated deferred income taxes | — | 9,296 | ||||||||||||
| Other | 40,628 | 38,760 | ||||||||||||
| TOTAL | 1,049,820 | 621,793 | ||||||||||||
| NON-CURRENT LIABILITIES | ||||||||||||||
| Accumulated deferred income taxes and taxes accrued | 1,286,123 | 1,183,126 | ||||||||||||
| Accumulated deferred investment tax credits | 30,500 | 31,701 | ||||||||||||
| Regulatory liability for income taxes - net | 467,031 | 478,174 | ||||||||||||
| Other regulatory liabilities | 686,872 | 559,555 | ||||||||||||
| Decommissioning | 1,314,160 | 1,242,616 | ||||||||||||
| Accumulated provisions | 70,169 | 63,880 | ||||||||||||
| Pension and other postretirement liabilities | 361,682 | 319,075 | ||||||||||||
Long-term debt (includes securitization bonds of $— as of December 31, 2020 and $6,772 as of December 31, 2019) | 3,482,507 | 3,517,208 | ||||||||||||
| Other | 75,098 | 62,568 | ||||||||||||
| TOTAL | 7,774,142 | 7,457,903 | ||||||||||||
| Commitments and Contingencies | ||||||||||||||
| EQUITY | ||||||||||||||
| Member's equity | 3,276,169 | 3,125,937 | ||||||||||||
| TOTAL | 3,276,169 | 3,125,937 | ||||||||||||
| TOTAL LIABILITIES AND EQUITY | $12,100,131 | $11,205,633 | ||||||||||||
See Notes to Financial Statements. | ||||||||||||||
335
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES | |||||
| CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY | |||||
| For the Years Ended December 31, 2020, 2019, and 2018 | |||||
| Member's Equity | |||||
| (In Thousands) | |||||
| Balance at December 31, 2017 | $2,376,754 | ||||
| Net income | 252,707 | ||||
| Capital contributions from parent | 350,000 | ||||
| Common equity distributions | (91,751) | ||||
| Non-cash contribution from parent | 94,335 | ||||
| Preferred stock dividends | (1,249) | ||||
| Other | 2,307 | ||||
| Balance at December 31, 2018 | $2,983,103 | ||||
| Net income | 262,964 | ||||
| Common equity distributions | (115,000) | ||||
| Other | (5,130) | ||||
| Balance at December 31, 2019 | $3,125,937 | ||||
| Net income | 245,232 | ||||
| Common equity distributions | (95,000) | ||||
| Balance at December 31, 2020 | $3,276,169 | ||||
| See Notes to Financial Statements. | |||||
336
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES | ||||||||||||||||||||||||||||||||
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | ||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2017 | 2016 | ||||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||||||||
| Operating revenues | $2,084,494 | $2,259,594 | $2,060,643 | $2,139,919 | $2,086,608 | |||||||||||||||||||||||||||
| Net income | $245,232 | $262,964 | $252,707 | $139,844 | $167,212 | |||||||||||||||||||||||||||
| Total assets | $12,100,131 | $11,205,633 | $10,401,596 | $10,134,029 | $9,606,117 | |||||||||||||||||||||||||||
| Long-term obligations (a) | $3,482,507 | $3,517,208 | $3,225,759 | $2,983,749 | $2,746,435 | |||||||||||||||||||||||||||
| (a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund. | ||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2017 | 2016 | ||||||||||||||||||||||||||||
| (Dollars In Millions) | ||||||||||||||||||||||||||||||||
| Electric Operating Revenues: | ||||||||||||||||||||||||||||||||
| Residential | $841 | $795 | $807 | $768 | $789 | |||||||||||||||||||||||||||
| Commercial | 466 | 539 | 426 | 495 | 495 | |||||||||||||||||||||||||||
| Industrial | 462 | 521 | 434 | 472 | 446 | |||||||||||||||||||||||||||
| Governmental | 18 | 21 | 17 | 19 | 18 | |||||||||||||||||||||||||||
| Total billed retail | 1,787 | 1,876 | 1,684 | 1,754 | 1,748 | |||||||||||||||||||||||||||
| Sales for resale: | ||||||||||||||||||||||||||||||||
| Associated companies | 105 | 118 | 104 | 128 | 49 | |||||||||||||||||||||||||||
| Non-associated companies | 68 | 140 | 145 | 121 | 118 | |||||||||||||||||||||||||||
| Other | 124 | 126 | 128 | 137 | 172 | |||||||||||||||||||||||||||
| Total | $2,084 | $2,260 | $2,061 | $2,140 | $2,087 | |||||||||||||||||||||||||||
| Billed Electric Energy Sales (GWh): | ||||||||||||||||||||||||||||||||
| Residential | 7,584 | 7,996 | 8,248 | 7,298 | 7,618 | |||||||||||||||||||||||||||
| Commercial | 5,356 | 5,822 | 5,967 | 5,825 | 5,988 | |||||||||||||||||||||||||||
| Industrial | 7,586 | 7,759 | 8,071 | 7,528 | 6,795 | |||||||||||||||||||||||||||
| Governmental | 223 | 241 | 239 | 237 | 237 | |||||||||||||||||||||||||||
| Total retail | 20,749 | 21,818 | 22,525 | 20,888 | 20,638 | |||||||||||||||||||||||||||
| Sales for resale: | ||||||||||||||||||||||||||||||||
| Associated companies | 1,659 | 2,180 | 1,773 | 1,782 | 1,609 | |||||||||||||||||||||||||||
| Non-associated companies | 4,198 | 7,206 | 6,447 | 6,549 | 7,115 | |||||||||||||||||||||||||||
| Total | 26,606 | 31,204 | 30,745 | 29,219 | 29,362 | |||||||||||||||||||||||||||
337
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
Hurricane Laura, Hurricane Delta, and Hurricane Zeta
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. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.0 billion, including approximately $1.67 billion in capital costs and approximately $330 million in non-capital costs. This estimate includes all costs to restore power and repair or replace the damages from the hurricanes, except for the cost to repair or replace damage incurred to an Entergy Louisiana transmission line in southeast Louisiana, and the amount of that cost could be significant. The restoration plan for this transmission line and the related cost estimate is still being evaluated. Also, Entergy Louisiana’s revenues were adversely affected in 2020, primarily due to power outages resulting from the hurricanes. Entergy Louisiana is considering all reasonable avenues to recover storm-related costs from Hurricane Laura, Hurricane Delta, and Hurricane Zeta, including securitization. Storm cost recovery or financing will be subject to review by applicable regulatory authorities.
Entergy Louisiana recorded accounts payable and corresponding construction work in progress and regulatory assets for the estimated costs incurred that were necessary to return customers to service. Entergy Louisiana recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. There are well established mechanisms and precedent for addressing these catastrophic events and providing for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles. Because Entergy Louisiana has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments to facilitate issuance of shorter-term 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 drew $257 million from its funded storm reserves.
In December 2020, Entergy Louisiana provided the LPSC with notification that it intends to initiate a storm cost recovery proceeding in the near future, which will permit the LPSC to retain any outside consultants and counsel needed to review the storm cost recovery application. In February 2021 the LPSC voted to retain outside counsel and consultants to assist in the review of Entergy Louisiana’s upcoming storm cost recovery application, which is expected to be filed in March 2021.
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February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy Louisiana’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $50 million to $60 million. Natural gas purchases for Entergy Louisiana for February 1st through 25th, 2021 are approximately $190 million compared to natural gas purchases for February 2020 of $39 million.
Results of Operations
2020 Compared to 2019
Net Income
Net income increased $390.8 million primarily due to the $382.8 million reduction in deferred income tax expense related to the basis of assets contributed in the 2015 Entergy Louisiana and Entergy Gulf States Louisiana business combination as a result of the resolution of the 2014-2015 IRS audit in the fourth quarter 2020 and the $58 million reduction in income tax expense resulting from an IRS settlement in the first quarter 2020 related to the uncertain tax position regarding the Hurricane Isaac Louisiana Act 55 financing, which also resulted in a $29 million ($21 million net-of-tax) regulatory charge to reflect Entergy Louisiana’s agreement to share the savings with customers. Also contributing to the increase were higher retail electric price, lower other operation and maintenance expenses, and a lower effective income tax rate. The increase was partially offset by higher depreciation and amortization expenses, lower volume/weather, lower other income, higher interest expense, and higher taxes other than income taxes. See Note 3 to the financial statements for further discussion of the tax audit resolution and the tax settlement.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2020 to 2019:
| Amount | |||||
| (In Millions) | |||||
| 2019 operating revenues | $4,285.2 | ||||
| Fuel, rider, and other revenues that do not significantly affect net income | (330.3) | ||||
| Volume/weather | (68.8) | ||||
| Return of unprotected excess accumulated deferred income taxes to customers | 7.5 | ||||
| Retail electric price | 176.3 | ||||
| 2020 operating revenues | $4,069.9 | ||||
Entergy Louisiana’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The volume/weather variance is primarily due to decreased commercial and industrial usage as a result of the COVID-19 pandemic, the effects of Hurricane Laura, Hurricane Delta, and Hurricane Zeta on sales, and the effect of less favorable weather on residential sales, partially offset by increased residential usage as a result of the COVID-19 pandemic. The decrease in industrial usage is partially offset by an increase in demand from expansion projects, primarily in the transportation and chemicals industries. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the
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COVID-19 pandemic. See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of the storms.
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 2020, $31.1 million was returned to customers as compared to $38.6 million in 2019. There was no effect on net income as the reduction in operating revenues was offset by a reduction 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 formula rate plan revenues effective June 2019 due to the inclusion of the first-year revenue requirement for the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and effective April 2020 due to the inclusion of the first-year revenue requirement for the Lake Charles Power Station and increases in formula rate plan revenues effective September 2019 and September 2020. See Note 2 to the financial statements for further discussion of the formula rate plan proceedings.
Other Income Statement Variances
Other operation and maintenance expenses decreased primarily due to:
•a decrease of $10.2 million in nuclear generation expenses primarily due to a lower scope of work performed in 2020 as compared to 2019, in part as a result of the COVID-19 pandemic;
•a decrease of $9.5 million primarily due to contract costs in 2019 related to initiatives to explore new customer products and services;
•a decrease of $6.8 million in loss provisions;
•higher nuclear insurance refunds of $5.9 million;
•a decrease of $5.8 million in energy efficiency costs due to the timing of recovery from customers; and
•a decrease of $4.3 million in non-nuclear generation expenses primarily due to a lower scope of work performed during plant outages in 2020 as compared to the same period in 2019, partially offset by increases resulting from the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and the Lake Charles Power Station being placed in service.
The decrease was partially offset by:
•an increase of $4.1 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefits costs as a result of a decrease in the discount rate used to value the benefit liabilities. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs; and
•several individually insignificant items.
Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher property assessments.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station), which was placed into service in May 2019 and the Lake Charles Power Station, which was placed in service in March 2020.
Other regulatory charges (credits) include regulatory charges of $32.6 million recorded in the fourth quarter 2020 due to a settlement with the IRS related to the uncertain tax position regarding Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing because the savings will be shared with customers and $29 million recorded in the first quarter 2020 due to a settlement with the IRS related to the uncertain tax position regarding Hurricane Isaac Louisiana Act 55 financing because the savings will be shared with customers. See Note 3 to the financial statements for further discussion of the settlements and savings obligations.
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Other income decreased primarily due to:
•a decrease in the allowance for equity funds used during construction due to higher construction work in progress in 2019, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and the Lake Charles Power Station projects; and
•changes in decommissioning trust fund activity.
Interest expense increased primarily due to:
•the issuances of $300 million of 4.20% Series mortgage bonds and $350 million of 2.90% Series mortgage bonds, each in March 2020;
•the issuance of $525 million of 4.20% Series mortgage bonds in March 2019; and
•a decrease in the allowance for borrowed funds used during construction due to higher construction work in progress in 2019, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and Lake Charles Power Station projects.
The effective income tax rates were (54.6%) for 2020 and 15% for 2019. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2020 was primarily due to completion of the 2014-2015 IRS audit effectively settling the tax positions for those years. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2019 was primarily due to the amortization of excess accumulated deferred income taxes. See Notes 2 and 3 to the financial statements for a discussion of the effects and regulatory activity regarding the Tax Cuts and Jobs Act. See Note 3 to the financial statements for a reconciliation of the federal statutory rates of 21% to the effective income tax rates.
2019 Compared to 2018
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, 2019, filed with the SEC on February 21, 2020, for discussion of results of operations for 2019 compared to 2018.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, and 2018 were as follows:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Thousands) | |||||||||||||||||
| Cash and cash equivalents at beginning of period | $2,006 | $43,364 | $35,907 | ||||||||||||||
| Net cash provided by (used in): | |||||||||||||||||
| Operating activities | 1,072,986 | 1,236,002 | 1,395,204 | ||||||||||||||
| Investing activities | (1,944,671) | (1,653,634) | (1,878,208) | ||||||||||||||
| Financing activities | 1,597,699 | 376,274 | 490,461 | ||||||||||||||
| Net increase (decrease) in cash and cash equivalents | 726,014 | (41,358) | 7,457 | ||||||||||||||
| Cash and cash equivalents at end of period | $728,020 | $2,006 | $43,364 | ||||||||||||||
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2020 Compared to 2019
Operating Activities
Net cash flow provided by operating activities decreased $163 million in 2020 primarily due to:
•an increase of $186.1 million in storm spending in 2020, primarily due to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration efforts. See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of storm restoration efforts;
•lower collections of receivables from customers, in part due to the COVID-19 pandemic;
•the timing of recovery of fuel and purchased power costs; and
•an increase of $21.5 million in interest paid.
The decrease was partially offset by:
•a decrease in $43.7 million in spending on nuclear refueling outages;
•the timing of payments to vendors; and
•income tax refunds of $14.7 million in 2020 compared to $15.3 million in income tax payments in 2019. Entergy Louisiana had income tax refunds in 2020 and income tax payments in 2019 in accordance with an intercompany tax allocation agreement. Entergy Louisiana had income tax refunds in 2020 as a result of a refund of an overpayment on a prior year state income tax return.
Investing Activities
Net cash flow used in investing activities increased $291 million in 2020 primarily due to:
•an increase of $709.7 million in storm spending 2020, primarily due to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration efforts, See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of storm restoration efforts;
•the purchase of Washington Parish Energy Center in November 2020 for approximately $222 million. See Note 14 to the financial statements for further discussion of the Washington Parish Energy Center purchase;
•an increase of $16.7 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Louisiana’s distribution system, including increased spending on advanced metering infrastructure; and
•money pool activity.
The increase was partially offset by:
•an increase of $302.2 million in net receipts from storm reserve escrow accounts;
•a decrease of $207.8 million in non-nuclear generation construction expenditures due to higher spending in 2019 on the Lake Charles Power Station and J. Wayne Leonard Power Station (formerly St. Charles Power Station) projects;
•a decrease of $133.1 million in transmission construction expenditures primarily due to a lower scope of work performed on various projects in 2020 as compared to 2019;
•a decrease of $89.5 million in nuclear construction expenditures primarily due to a lower scope of work performed on various nuclear projects in 2020 as compared to 2019; and
•a decrease of $26.1 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 in the Utility business, material, and service deliveries, and the timing of cash payments during the nuclear fuel cycle.
Increases in Entergy Louisiana’s receivable from the money pool are a use of cash flow, and Entergy Louisiana’s receivable from the money pool increased by $13.4 million in 2020 compared to decreasing by $46.8
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million in 2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Financing Activities
Net cash flow provided by financing activities increased $1,221.4 million in 2020 primarily due to:
•the issuance of $1.1 billion of 0.62% Series mortgage bonds in November 2020;
•the issuance of $350 million of 2.90% Series mortgage bonds and $300 million of 4.20% Series mortgage bonds, each in March 2020;
•the issuance of $300 million of 2.90% Series mortgage bonds and $300 million of 1.60% Series mortgage bonds, each in November 2020; and
•a decrease of $186.5 million in common equity distributions in 2020 primarily due to upcoming capital expenditures.
The increase was partially offset by:
•the issuance of $525 million of 4.20% Series mortgage bonds in March 2019;
•the repayment in August 2020 of $250 million of 3.95% Series mortgage bonds due October 2020;
•the repayment in December 2020 of $200 million of 5.25% Series mortgage bonds due July 2052;
•money pool activity;
•the repayment in December 2020 of $100 million of 4.70% Series mortgage bonds due June 2063; and
•net repayments of long-term borrowings of $62 million in 2020 on the nuclear fuel company variable interest entities’ credit facilities.
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 by $82.8 million in 2020 compared to increasing by $82.8 million in 2019.
See Note 5 to the financial statements for details of long-term debt.
2019 Compared to 2018
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, 2019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
Capital Structure
Entergy Louisiana’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio for Entergy Louisiana is primarily due to the net issuances of long-term debt in 2020.
| December 31, 2020 | December 31, 2019 | ||||||||||
| Debt to capital | 54.8 | % | 53.4 | % | |||||||
| Effect of excluding securitization bonds | 0.0 | % | (0.1 | %) | |||||||
| Debt to capital, excluding securitization bonds (a) | 54.8 | % | 53.3 | % | |||||||
| Effect of subtracting cash | (2.1 | %) | (0.1 | %) | |||||||
| Net debt to net capital, excluding securitization bonds (a) | 52.7 | % | 53.2 | % | |||||||
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(a)Calculation excludes the securitization bonds, which are non-recourse to Entergy Louisiana.
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 ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because the securitization bonds are non-recourse to Entergy Louisiana, as more fully described in Note 5 to the financial statements. Entergy Louisiana 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 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, 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 reducing distributions, Entergy Louisiana may receive equity contributions to maintain its capital structure.
Uses of Capital
Entergy Louisiana requires capital resources for:
•construction and other capital investments;
•debt maturities or retirements;
•working capital purposes, including the financing of fuel and purchased power costs; and
•distribution and interest payments.
Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.
| 2021 | 2022 | 2023 | |||||||||||||||
| (In Millions) | |||||||||||||||||
| Planned construction and capital investment: | |||||||||||||||||
| Generation | $365 | $460 | $785 | ||||||||||||||
| Transmission | 425 | 340 | 230 | ||||||||||||||
| Distribution | 540 | 485 | 500 | ||||||||||||||
| Utility Support | 160 | 130 | 115 | ||||||||||||||
| Total | $1,490 | $1,415 | $1,630 | ||||||||||||||
In addition to the planned spending in the table above, Entergy Louisiana also expects to pay for $845 million of capital investments in 2021 related to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration work that have been accrued as of December 31, 2020.
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Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| 2021 | 2022-2023 | 2024-2025 | After 2025 | Total | |||||||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||||||||
| Long-term debt (a) | $557 | $2,294 | $1,495 | $9,506 | $13,852 | ||||||||||||||||||||||||
| Operating leases (b) | $13 | $19 | $10 | $4 | $46 | ||||||||||||||||||||||||
| Finance leases (b) | $4 | $7 | $4 | $2 | $17 | ||||||||||||||||||||||||
| Purchase obligations (c) | $687 | $1,463 | $1,472 | $4,838 | $8,460 | ||||||||||||||||||||||||
(a)Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.
(b)Lease obligations are discussed in Note 10 to the financial statements.
(c)Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Louisiana, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Vidalia purchased power agreement and the Unit Power Sales Agreement, both of which are discussed in Note 8 to the financial statements.
In addition to the contractual obligations given above, Entergy Louisiana currently expects to contribute approximately $59.9 million to its qualified pension plans and approximately $15.6 million to its other postretirement health care and life insurance plans in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana includes specific investments such as transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to maintain reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; investments in River Bend and Waterford 3; software and security; 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, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly.
Sources of Capital
Entergy Louisiana’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•storm reserve escrow accounts;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy Louisiana may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
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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.
Entergy Louisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| 2020 | 2019 | 2018 | 2017 | |||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| $13,426 | ($82,826) | $46,843 | $11,173 | |||||||||||||||||
See Note 4 to the financial statements for a description of the money pool.
Entergy Louisiana has a credit facility in the amount of $350 million scheduled to expire in September 2024. 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, 2020, 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, 2020, $2.2 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 September 2022. As of December 31, 2020, $18.9 million of loans were outstanding under the credit facility for the Entergy Louisiana River Bend nuclear fuel company variable interest entity. As of December 31, 2020, $39.3 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 July 2022 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 Isaac
In June 2014 the LPSC voted to approve a series of orders which (i) quantified $290.8 million of Hurricane Isaac system restoration costs as prudently incurred; (ii) determined $290 million as the level of storm reserves to be re-established; (iii) authorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) granted other requested relief associated with storm reserves and Act 55 financing of 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 Louisiana Utilities Restoration Corporation and the Louisiana State Bond Commission. See Note 2 to the financial statements for a discussion of the August 2014 issuance of bonds under Act 55 of the Louisiana Legislature.
Little Gypsy Repowering Project
In April 2007, Entergy Louisiana announced that it intended to pursue the solid fuel repowering of a 538 MW unit at its Little Gypsy plant. In March 2009 the LPSC voted in favor of a motion directing Entergy Louisiana
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to temporarily suspend the repowering project and, based upon an analysis of the project’s economic viability, to make a recommendation regarding whether to proceed with the project. This action was based upon a number of factors including the recent decline in natural gas prices, as well as environmental concerns, the unknown costs of carbon legislation and changes in the capital/financial markets. In April 2009, Entergy Louisiana complied with the LPSC’s directive and recommended that the project be suspended for an extended period of time of three years or more. In May 2009 the LPSC issued an order declaring that Entergy Louisiana’s decision to place the Little Gypsy project into a longer-term suspension of three years or more is in the public interest and prudent.
In October 2009, Entergy Louisiana made a filing with the LPSC seeking permission to cancel the Little Gypsy repowering project and seeking project cost recovery over a five-year period. In June 2010 and August 2010, the LPSC staff and intervenors filed testimony. The LPSC staff (1) agreed that it was prudent to move the project from long-term suspension to cancellation and that the timing of the decision to suspend on a longer-term basis was not imprudent; (2) indicated that, except for $0.8 million in compensation-related costs, the costs incurred should be deemed prudent; (3) recommended recovery from customers over ten years but stated that the LPSC may want to consider 15 years; (4) allowed for recovery of carrying costs and earning a return on project costs, but at a reduced rate approximating the cost of debt, while also acknowledging that the LPSC may consider ordering no return; and (5) indicated that Entergy Louisiana should be directed to securitize project costs, if legally feasible and in the public interest. In the third quarter 2010, in accordance with accounting standards, Entergy Louisiana determined that it was probable that the Little Gypsy repowering project would be abandoned and accordingly reclassified $199.8 million of project costs from construction work in progress to a regulatory asset. A hearing on the issues, except for cost allocation among customer classes, was held before the ALJ in November 2010. In January 2011 all parties participated in a mediation on the disputed issues, resulting in a settlement of all disputed issues, including cost recovery and cost allocation. The settlement provides for Entergy Louisiana to recover $200 million as of March 31, 2011, and carrying costs on that amount on specified terms thereafter. The settlement also provides for Entergy Louisiana to recover the approved project costs by securitization. In April 2011, Entergy Louisiana filed an application with the LPSC to authorize the securitization of the investment recovery costs associated with the project and to issue a financing order by which Entergy Louisiana could accomplish such securitization. In August 2011 the LPSC issued an order approving the settlement and also issued a financing order for the securitization. See Note 5 to the financial statements for a discussion of the September 2011 issuance of the securitization bonds.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Louisiana is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approval of the rates charged to customers.
Retail Rates - Electric
Filings with the LPSC
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 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
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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 and intervenors submitted their responses to Entergy Louisiana’s original formula rate plan evaluation report and supplemental compliance updates. The LPSC staff asserted objections/reservations regarding 1) Entergy Louisiana’s proposed rate adjustments associated with the return of excess accumulated deferred income taxes pursuant to the Tax Act and the treatment of accumulated deferred income taxes related to reductions of rate base; 2) Entergy Louisiana’s reservation regarding treatment of a regulatory asset related to certain special orders by the LPSC; and 3) test year expenses billed from Entergy Services to Entergy Louisiana. Intervenors also objected to Entergy Louisiana’s treatment of the regulatory asset related to certain special orders by the LPSC. A procedural schedule has not yet been established to resolve these issues.
Entergy Louisiana also included in its filing a presentation of an initial proposal to combine the legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana residential rates, which combination, if approved, would be accomplished on a revenue-neutral basis intended not to affect the rates of other customer classes.
Commercial operation at J. Wayne Leonard Power Station (formerly St. Charles Power Station) commenced in May 2019. In May 2019, Entergy Louisiana filed an update to its 2017 formula rate plan evaluation report to include the estimated first-year revenue requirement of $109.5 million associated with the J. Wayne Leonard Power Station. The resulting interim adjustment to rates became effective with the first billing cycle of June 2019. In June 2020, Entergy Louisiana submitted information to the LPSC to review the prudence of Entergy Louisiana’s management of the project. In August 2020 discovery commenced and a procedural schedule was established with a hearing in July 2021.
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 will decrease as a result of this filing, overall formula rate plan revenues will increase by approximately $118.7 million. This outcome is 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 is subject to review by the LPSC. Resulting rates were implemented in September 2019, subject to refund.
Entergy Louisiana also included in its filing a presentation of an initial proposal to combine the legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana residential rates, which combination, if approved, would be accomplished on a revenue-neutral basis intended not to affect the rates of other customer classes. Entergy Louisiana contemplates that any combination of residential rates resulting from this request would be implemented with the results of the 2019 test year formula rate plan filing.
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 its report the LPSC staff re-urged reservations with respect to the outstanding issues from the 2017 test year formula rate plan filing and disputed the inclusion of certain affiliate costs for test years 2017 and 2018. The LPSC staff objected to Entergy Louisiana’s proposal to combine residential rates but proposed the setting of a status conference to establish a procedural schedule to more fully address the issue. The LPSC staff also reserved its right to object to the treatment of the sale of Willow Glen reflected in the evaluation report and to the August 2019 compliance update, which was made primarily to update the capital additions reflected in the formula rate plan’s transmission recovery mechanism,
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based on limited time to review it. Additionally, since the completion of certain transmission projects, the LPSC staff issued supplemental data requests addressing the prudence of Entergy Louisiana’s expenditures in connection with those projects. Entergy Louisiana has responded to all such requests.
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 an effort to narrow the remaining issues in formula rate plan test years 2017 and 2018, Entergy Louisiana provided notice to the parties in October 2020 that it was withdrawing its request to combine residential rates. Entergy Louisiana noted that the withdrawal is without prejudice to Entergy Louisiana’s right to seek to combine residential rates in a future proceeding.
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 will not change as a result of this filing, overall formula rate plan revenues will increase 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 is 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 the revenue neutral rider adjustment, and as updated in an August 2020 filing, were implemented in September 2020, subject to refund. Entergy Louisiana is in the process of providing additional information and details on the May 2020 filing as requested by the LPSC staff.
In November 2020, Entergy Louisiana accepted ownership of the Washington Parish Energy Center and filed an update to its 2019 formula rate plan evaluation report to include the estimated first-year revenue requirement of $35 million associated with the Washington Parish Energy Center. The resulting interim adjustment to rates became effective with the first billing cycle of December 2020. In January 2021, Entergy Louisiana filed an update to its 2019 formula rate plan evaluation report to include the implementation of a scheduled step-up in its nuclear decommissioning revenue requirement and a true-up for under-collections of nuclear decommissioning expenses. The total rate adjustment would increase formula rate plan revenues by approximately $1.2 million. The resulting interim adjustment to rates became effective with the first billing cycle of February 2021.
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 seeks 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. Entergy Louisiana also seeks to maintain its existing additional capacity mechanism, tax reform adjustment mechanism, transmission recovery mechanism, and the MISO cost recovery mechanism. Entergy Louisiana also seeks to add a distribution cost recovery mechanism which operates in substantially the same manner as the transmission recovery mechanism, seeks to utilize end of period rate base to calculate cost of service, and requests a deferral of certain expenses incurred for outside of right-of-way vegetation programs. Settlement discussions are ongoing.
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Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
Fuel and purchased power recovery
Entergy Louisiana recovers electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Louisiana’s purchased gas adjustments 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 July 2014 the LPSC authorized its staff to initiate an audit of the fuel adjustment clause filings by Entergy Gulf States Louisiana, whose business was combined with Entergy Louisiana in 2015. The audit includes a review of the reasonableness of charges flowed through Entergy Gulf States Louisiana’s fuel adjustment clause for the period from 2010 through 2013. In January 2019, the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $900,000, plus interest, to customers based upon the imputation of a claim of vendor fault in servicing its nuclear plant. Entergy Louisiana recorded a provision in first quarter 2019 for the potential outcome of the audit. In August 2019, Entergy Louisiana filed direct testimony challenging the basis for the LPSC staff’s recommended disallowance and providing an alternative calculation of replacement power costs should it be determined that a disallowance is appropriate. Entergy Louisiana’s calculation would require no refund to customers.
In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Louisiana through its fuel adjustment clause for the period from 2010 through 2013. In January 2019 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $7.3 million, plus interest, to customers based upon the imputation of a claim of vendor fault in servicing its nuclear plant. Entergy Louisiana recorded a provision in the first quarter 2019 for the potential outcome of the audit. In August 2019, Entergy Louisiana filed direct testimony challenging the basis for the LPSC staff’s recommended disallowance and providing an alternative calculation of replacement power costs should it be determined that a disallowance is appropriate. Entergy Louisiana’s calculation would require a refund to customers of approximately $4.3 million, plus interest, as compared to the LPSC staff’s recommendation of $7.3 million, plus interest. Responsive testimony was filed by the LPSC staff and intervenors in September 2019; all parties either agreed with or did not oppose Entergy Louisiana’s alternative calculation of replacement power costs.
In November 2019 the pending LPSC proceedings for the 2010-2013 Entergy Louisiana and Entergy Gulf States Louisiana audits were consolidated to facilitate a settlement of both fuel audits. In December 2019 an unopposed settlement was reached that requires a refund to legacy Entergy Louisiana customers of approximately $2.3 million, including interest, and no refund to legacy Entergy Gulf States Louisiana customers. The LPSC approved the settlement in January 2020. A one-time refund was made in February 2020.
In June 2016 the LPSC issued notice of audits of Entergy Louisiana’s fuel adjustment clause filings for the period 2014 through 2015 and purchased gas adjustment clause filings for the period 2012 through 2015. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and also includes a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audits include a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2014 through 2015 and charges flowed through Entergy Louisiana’s
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Management’s Financial Discussion and Analysis
purchased gas adjustment clause for the period from 2012 through 2015. Regarding the fuel adjustment clause filing, the LPSC staff issued a report in January 2021 that did not recommend a disallowance for the period 2014 through 2015 recoveries, but did propose various reporting requirements. Entergy Louisiana is currently reviewing the LPSC staff recommendations regarding reporting requirements. Regarding the purchased gas adjustment clause filings, the LPSC staff issued a report in February 2020 that did not recommend a disallowance for the period 2012 through 2015 recoveries. The LPSC issued an order in September 2020 accepting the LPSC staff’s report.
In May 2018 the LPSC staff provided notice of audits 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 2016 through 2017. In February 2020 the LPSC staff issued an audit report recommending a disallowance of approximately $29 thousand Entergy Louisiana submitted a letter disputing the basis of the proposed disallowance but indicated that due to the amount at issue it would not oppose the recommended refund. The LPSC staff and Entergy Louisiana submitted a joint report noting each party’s position on the substantive issues in the matter and recommending resolution of the matters. The LPSC issued an order in September 2020 resolving the matter and ordering a refund of approximately $29 thousand. In January 2021 the LPSC issued a notice closing the matter.
In March 2020 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2016 through 2019. Discovery commenced in September 2020 and is ongoing.
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 have 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. As of December 31, 2020, Entergy Louisiana recorded a regulatory asset of $48.8 million for costs associated with the COVID-19 pandemic.
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.
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Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Nuclear Matters
Entergy Louisiana owns and, through an affiliate, operates the River Bend and Waterford 3 nuclear power plants. Entergy Louisiana is, therefore, subject to the risks related to owning and operating nuclear plants. 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, to position Entergy’s nuclear fleet to meet its operational goals; the performance and capacity factors of these nuclear plants; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts and types of insurance commercially available for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of River Bend or Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Waterford 3’s operating license expires in 2044 and River Bend’s operating license expires in 2045.
Environmental Risks
Entergy Louisiana’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Louisiana is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Louisiana’s financial statements in conformity with generally accepted accounting principles 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 policies and 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 the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Louisiana’s financial position or results of operations.
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Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
In the second quarter 2019, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $147.5 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.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Impairment of Long-lived Assets
See “Impairment of Long-lived Assets” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Louisiana’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| Actuarial Assumption | Change in Assumption | Impact on 2021 Qualified Pension Cost | Impact on 2020 Projected Qualified Benefit Obligation | |||||||||||||||||
| Increase/(Decrease) | ||||||||||||||||||||
| Discount rate | (0.25%) | $3,053 | $52,030 | |||||||||||||||||
| Rate of return on plan assets | (0.25%) | $3,338 | $— | |||||||||||||||||
| Rate of increase in compensation | 0.25% | $2,313 | $11,706 | |||||||||||||||||
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Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| Actuarial Assumption | Change in Assumption | Impact on 2021 Postretirement Benefit Cost | Impact on 2020 Accumulated postretirement Benefit Obligation | |||||||||||||||||
| Increase/(Decrease) | ||||||||||||||||||||
| Discount rate | (0.25%) | $872 | $8,226 | |||||||||||||||||
| Health care cost trend | 0.25% | $964 | $5,853 | |||||||||||||||||
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy Louisiana in 2020 was $70.6 million, including $8.1 million in settlement costs. Entergy Louisiana anticipates 2021 qualified pension cost to be $65.1 million. Entergy Louisiana contributed $55.4 million to its qualified pension plans in 2020 and estimates pension contributions will be approximately $59.9 million in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021.
Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 2020 were $5.6 million. Entergy Louisiana expects 2021 postretirement health care and life insurance benefit costs of approximately $5.4 million. Entergy Louisiana contributed $16.1 million to its other postretirement plans in 2020 and estimates that 2021 contributions will be approximately $15.6 million.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the member and Board of Directors of
Entergy Louisiana, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Louisiana, LLC and Subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, cash flows, and changes in equity (pages 357 through 362 and applicable items in pages 51 through 238), for each of the three years in the period ended December 31, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which they relate.
Rate and Regulatory Matters —Entergy Louisiana, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
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
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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, such as property, plant, and equipment; regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
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 significant 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, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the LPSC and the FERC 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 costs incurred as property, plant, and equipment and deferred as 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 property, plant, and equipment; 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 and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information 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 the 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, including the annual formula rate plan filing, 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.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2021
We have served as the Company’s auditor since 2001.
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| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | ||||||||||||||||||||
| CONSOLIDATED INCOME STATEMENTS | ||||||||||||||||||||
| For the Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| OPERATING REVENUES | ||||||||||||||||||||
| Electric | $4,019,063 | $4,223,027 | $4,232,541 | |||||||||||||||||
| Natural gas | 50,799 | 62,148 | 63,779 | |||||||||||||||||
| TOTAL | 4,069,862 | 4,285,175 | 4,296,320 | |||||||||||||||||
| OPERATING EXPENSES | ||||||||||||||||||||
| Operation and Maintenance: | ||||||||||||||||||||
| Fuel, fuel-related expenses, and gas purchased for resale | 700,152 | 845,108 | 915,410 | |||||||||||||||||
| Purchased power | 596,480 | 810,462 | 960,272 | |||||||||||||||||
| Nuclear refueling outage expenses | 55,305 | 54,170 | 51,626 | |||||||||||||||||
| Other operation and maintenance | 969,630 | 994,637 | 959,185 | |||||||||||||||||
| Decommissioning | 65,225 | 59,346 | 53,736 | |||||||||||||||||
| Taxes other than income taxes | 208,902 | 194,222 | 183,745 | |||||||||||||||||
| Depreciation and amortization | 609,931 | 535,791 | 492,179 | |||||||||||||||||
| Other regulatory charges (credits) - net | (584) | (105,203) | 4,396 | |||||||||||||||||
| TOTAL | 3,205,041 | 3,388,533 | 3,620,549 | |||||||||||||||||
| OPERATING INCOME | 864,821 | 896,642 | 675,771 | |||||||||||||||||
| OTHER INCOME | ||||||||||||||||||||
| Allowance for equity funds used during construction | 38,151 | 74,023 | 79,922 | |||||||||||||||||
| Interest and investment income | 225,627 | 231,985 | 141,882 | |||||||||||||||||
| Miscellaneous - net | (116,366) | (115,427) | (27,530) | |||||||||||||||||
| TOTAL | 147,412 | 190,581 | 194,274 | |||||||||||||||||
| INTEREST EXPENSE | ||||||||||||||||||||
| Interest expense | 331,352 | 309,493 | 288,658 | |||||||||||||||||
| Allowance for borrowed funds used during construction | (19,147) | (35,430) | (39,616) | |||||||||||||||||
| TOTAL | 312,205 | 274,063 | 249,042 | |||||||||||||||||
| INCOME BEFORE INCOME TAXES | 700,028 | 813,160 | 621,003 | |||||||||||||||||
| Income taxes | (382,324) | 121,623 | (54,611) | |||||||||||||||||
| NET INCOME | $1,082,352 | $691,537 | $675,614 | |||||||||||||||||
| See Notes to Financial Statements. | ||||||||||||||||||||
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| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | ||||||||||||||||||||
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | ||||||||||||||||||||
| For the Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| Net Income | $1,082,352 | $691,537 | $675,614 | |||||||||||||||||
| Other comprehensive income (loss) | ||||||||||||||||||||
| Pension and other postretirement liabilities | ||||||||||||||||||||
(net of tax expense (benefit) of ($83), $3,781, and $17,743) | (235) | 10,715 | 50,296 | |||||||||||||||||
| Other comprehensive income (loss) | (235) | 10,715 | 50,296 | |||||||||||||||||
| Comprehensive Income | $1,082,117 | $702,252 | $725,910 | |||||||||||||||||
| See Notes to Financial Statements. | ||||||||||||||||||||
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| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | ||||||||||||||||||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||||||||||||||||
| For the Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| OPERATING ACTIVITIES | ||||||||||||||||||||
| Net income | $1,082,352 | $691,537 | $675,614 | |||||||||||||||||
| Adjustments to reconcile net income to net cash flow provided by operating activities: | ||||||||||||||||||||
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | 783,616 | 685,062 | 662,390 | |||||||||||||||||
| Deferred income taxes, investment tax credits, and non-current taxes accrued | (356,256) | 196,533 | 174,063 | |||||||||||||||||
| Changes in working capital: | ||||||||||||||||||||
| Receivables | (79,451) | 13,942 | 89,701 | |||||||||||||||||
| Fuel inventory | (9,067) | (7,195) | 5,310 | |||||||||||||||||
| Accounts payable | 160,659 | (33,375) | 11,372 | |||||||||||||||||
| Prepaid taxes and taxes accrued | 50,576 | (38,827) | 12,711 | |||||||||||||||||
| Interest accrued | 4,505 | 4,294 | 7,922 | |||||||||||||||||
| Deferred fuel costs | (57,895) | 24,234 | (40,036) | |||||||||||||||||
| Other working capital accounts | (76,284) | (62,536) | (5,809) | |||||||||||||||||
| Changes in provisions for estimated losses | (295,480) | 9,664 | 8,307 | |||||||||||||||||
| Changes in other regulatory assets | (410,855) | (210,134) | 40,765 | |||||||||||||||||
| Changes in other regulatory liabilities | 71,698 | (35,881) | (125,185) | |||||||||||||||||
| Changes in pension and other postretirement liabilities | 12,199 | 35,162 | (106,269) | |||||||||||||||||
| Other | 192,669 | (36,478) | (15,652) | |||||||||||||||||
| Net cash flow provided by operating activities | 1,072,986 | 1,236,002 | 1,395,204 | |||||||||||||||||
| INVESTING ACTIVITIES | ||||||||||||||||||||
| Construction expenditures | (1,960,787) | (1,673,194) | (1,805,641) | |||||||||||||||||
| Allowance for equity funds used during construction | 38,151 | 74,023 | 79,922 | |||||||||||||||||
| Nuclear fuel purchases | (92,831) | (85,984) | (111,329) | |||||||||||||||||
| Proceeds from the sale of nuclear fuel | 44,511 | 11,596 | 53,603 | |||||||||||||||||
| Payments to storm reserve escrow account | (1,488) | (6,353) | (4,770) | |||||||||||||||||
| Receipts from storm reserve escrow account | 297,363 | — | 4 | |||||||||||||||||
| Changes in securitization account | 951 | (32) | (1,655) | |||||||||||||||||
| Proceeds from nuclear decommissioning trust fund sales | 347,021 | 412,559 | 1,055,690 | |||||||||||||||||
| Investment in nuclear decommissioning trust funds | (372,227) | (442,501) | (1,097,204) | |||||||||||||||||
| Changes in money pool receivable - net | (13,426) | 46,843 | (35,672) | |||||||||||||||||
| Proceeds from sale of assets | — | — | 11,987 | |||||||||||||||||
| Payment for purchase of assets | (236,999) | — | (26,623) | |||||||||||||||||
| Insurance proceeds | — | 7,040 | 3,480 | |||||||||||||||||
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | 5,090 | 2,369 | — | |||||||||||||||||
| Net cash flow used in investing activities | (1,944,671) | (1,653,634) | (1,878,208) | |||||||||||||||||
| FINANCING ACTIVITIES | ||||||||||||||||||||
| Proceeds from the issuance of long-term debt | 3,675,083 | 2,691,133 | 2,319,799 | |||||||||||||||||
| Retirement of long-term debt | (1,962,635) | (2,199,053) | (1,664,354) | |||||||||||||||||
| Change in money pool payable - net | (82,826) | 82,826 | — | |||||||||||||||||
| Changes in short-term borrowings - net | — | — | (43,540) | |||||||||||||||||
| Distributions paid: | ||||||||||||||||||||
| Common equity | (21,500) | (208,000) | (128,000) | |||||||||||||||||
| Other | (10,423) | 9,368 | 6,556 | |||||||||||||||||
| Net cash flow provided by financing activities | 1,597,699 | 376,274 | 490,461 | |||||||||||||||||
| Net increase (decrease) in cash and cash equivalents | 726,014 | (41,358) | 7,457 | |||||||||||||||||
| Cash and cash equivalents at beginning of period | 2,006 | 43,364 | 35,907 | |||||||||||||||||
| Cash and cash equivalents at end of period | $728,020 | $2,006 | $43,364 | |||||||||||||||||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||||||||||||||||
| Cash paid (received) during the period for: | ||||||||||||||||||||
| Interest - net of amount capitalized | $318,352 | $296,842 | $272,335 | |||||||||||||||||
| Income taxes | ($14,714) | $15,272 | ($105,157) | |||||||||||||||||
| See Notes to Financial Statements. | ||||||||||||||||||||
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| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | ||||||||||||||
| CONSOLIDATED BALANCE SHEETS | ||||||||||||||
| ASSETS | ||||||||||||||
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| CURRENT ASSETS | ||||||||||||||
| Cash and cash equivalents: | ||||||||||||||
| Cash | $1,303 | $488 | ||||||||||||
| Temporary cash investments | 726,717 | 1,518 | ||||||||||||
| Total cash and cash equivalents | 728,020 | 2,006 | ||||||||||||
| Accounts receivable: | ||||||||||||||
| Customer | 317,905 | 194,869 | ||||||||||||
| Allowance for doubtful accounts | (45,693) | (1,902) | ||||||||||||
| Associated companies | 81,624 | 77,212 | ||||||||||||
| Other | 41,760 | 42,179 | ||||||||||||
| Accrued unbilled revenues | 178,840 | 169,201 | ||||||||||||
| Total accounts receivable | 574,436 | 481,559 | ||||||||||||
| Deferred fuel costs | 2,250 | — | ||||||||||||
| Fuel inventory | 50,680 | 41,613 | ||||||||||||
| Materials and supplies - at average cost | 437,933 | 354,020 | ||||||||||||
| Deferred nuclear refueling outage costs | 48,407 | 56,743 | ||||||||||||
| Prepaid taxes | — | 7,959 | ||||||||||||
| Prepayments and other | 36,813 | 37,837 | ||||||||||||
| TOTAL | 1,878,539 | 981,737 | ||||||||||||
| OTHER PROPERTY AND INVESTMENTS | ||||||||||||||
| Investment in affiliate preferred membership interests | 1,390,587 | 1,390,587 | ||||||||||||
| Decommissioning trust funds | 1,794,042 | 1,563,812 | ||||||||||||
| Storm reserve escrow account | — | 295,875 | ||||||||||||
| Non-utility property - at cost (less accumulated depreciation) | 323,110 | 312,896 | ||||||||||||
| Other | 13,399 | 13,476 | ||||||||||||
| TOTAL | 3,521,138 | 3,576,646 | ||||||||||||
| UTILITY PLANT | ||||||||||||||
| Electric | 25,619,789 | 22,620,365 | ||||||||||||
| Natural gas | 262,744 | 235,678 | ||||||||||||
| Construction work in progress | 667,281 | 1,383,603 | ||||||||||||
| Nuclear fuel | 210,128 | 267,779 | ||||||||||||
| TOTAL UTILITY PLANT | 26,759,942 | 24,507,425 | ||||||||||||
| Less - accumulated depreciation and amortization | 9,372,224 | 9,118,524 | ||||||||||||
| UTILITY PLANT - NET | 17,387,718 | 15,388,901 | ||||||||||||
| DEFERRED DEBITS AND OTHER ASSETS | ||||||||||||||
| Regulatory assets: | ||||||||||||||
Other regulatory assets (includes securitization property of $5,088 as of December 31, 2020 and $27,596 as of December 31, 2019) | 1,726,066 | 1,315,211 | ||||||||||||
| Deferred fuel costs | 168,122 | 168,122 | ||||||||||||
| Other | 23,924 | 33,491 | ||||||||||||
| TOTAL | 1,918,112 | 1,516,824 | ||||||||||||
| TOTAL ASSETS | $24,705,507 | $21,464,108 | ||||||||||||
| See Notes to Financial Statements. | ||||||||||||||
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| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | ||||||||||||||
| CONSOLIDATED BALANCE SHEETS | ||||||||||||||
| LIABILITIES AND EQUITY | ||||||||||||||
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| CURRENT LIABILITIES | ||||||||||||||
| Currently maturing long-term debt | $240,000 | $320,002 | ||||||||||||
| Accounts payable: | ||||||||||||||
| Associated companies | 103,148 | 187,615 | ||||||||||||
| Other | 1,450,008 | 357,206 | ||||||||||||
| Customer deposits | 152,612 | 153,097 | ||||||||||||
| Taxes accrued | 42,617 | — | ||||||||||||
| Interest accrued | 92,249 | 87,744 | ||||||||||||
| Deferred fuel costs | — | 55,645 | ||||||||||||
| Current portion of unprotected excess accumulated deferred income taxes | 31,138 | 31,138 | ||||||||||||
| Other | 62,968 | 64,668 | ||||||||||||
| TOTAL | 2,174,740 | 1,257,115 | ||||||||||||
| NON-CURRENT LIABILITIES | ||||||||||||||
| Accumulated deferred income taxes and taxes accrued | 2,138,522 | 2,464,513 | ||||||||||||
| Accumulated deferred investment tax credits | 107,317 | 112,128 | ||||||||||||
| Regulatory liability for income taxes - net | 447,628 | 500,083 | ||||||||||||
| Other regulatory liabilities | 918,293 | 794,140 | ||||||||||||
| Decommissioning | 1,573,307 | 1,497,349 | ||||||||||||
| Accumulated provisions | 24,939 | 320,419 | ||||||||||||
| Pension and other postretirement liabilities | 692,728 | 677,619 | ||||||||||||
Long-term debt (includes securitization bonds of $10,278 as of December 31, 2020 and $33,220 as of December 31, 2019) | 8,787,451 | 6,983,667 | ||||||||||||
| Other | 382,894 | 459,957 | ||||||||||||
| TOTAL | 15,073,079 | 13,809,875 | ||||||||||||
| Commitments and Contingencies | ||||||||||||||
| EQUITY | ||||||||||||||
Member’s equity | 7,453,361 | 6,392,556 | ||||||||||||
| Accumulated other comprehensive income | 4,327 | 4,562 | ||||||||||||
| TOTAL | 7,457,688 | 6,397,118 | ||||||||||||
| TOTAL LIABILITIES AND EQUITY | $24,705,507 | $21,464,108 | ||||||||||||
| See Notes to Financial Statements. | ||||||||||||||
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| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | ||||||||||||||||||||
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY | ||||||||||||||||||||
| For the Years Ended December 31, 2020, 2019, and 2018 | ||||||||||||||||||||
| Common Equity | ||||||||||||||||||||
Member’s Equity | Accumulated Other Comprehensive Income (Loss) | Total | ||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| Balance at December 31, 2017 | $5,355,204 | ($46,400) | $5,308,804 | |||||||||||||||||
| Net income | 675,614 | — | 675,614 | |||||||||||||||||
| Other comprehensive income | — | 50,296 | 50,296 | |||||||||||||||||
| Distributions declared on common equity | (128,000) | — | (128,000) | |||||||||||||||||
| Reclassification pursuant to ASU 2018-02 | 6,262 | (10,049) | (3,787) | |||||||||||||||||
| Other | (9) | — | (9) | |||||||||||||||||
| Balance at December 31, 2018 | $5,909,071 | ($6,153) | $5,902,918 | |||||||||||||||||
| Net income | 691,537 | — | 691,537 | |||||||||||||||||
| Other comprehensive income | — | 10,715 | 10,715 | |||||||||||||||||
| Distributions declared on common equity | (208,000) | — | (208,000) | |||||||||||||||||
| Other | (52) | — | (52) | |||||||||||||||||
| Balance at December 31, 2019 | $6,392,556 | $4,562 | $6,397,118 | |||||||||||||||||
| Net income | 1,082,352 | — | 1,082,352 | |||||||||||||||||
| Other comprehensive loss | — | (235) | (235) | |||||||||||||||||
| Distributions declared on common equity | (21,500) | — | (21,500) | |||||||||||||||||
| Other | (47) | — | (47) | |||||||||||||||||
| Balance at December 31, 2020 | $7,453,361 | $4,327 | $7,457,688 | |||||||||||||||||
See Notes to Financial Statements. | ||||||||||||||||||||
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| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | |||||||||||||||||||||||||||||
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2017 | 2016 | |||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||
| Operating revenues | $4,069,862 | $4,285,175 | $4,296,320 | $4,300,550 | $4,177,048 | ||||||||||||||||||||||||
| Net income | $1,082,352 | $691,537 | $675,614 | $316,347 | $622,047 | ||||||||||||||||||||||||
| Total assets | $24,705,507 | $21,464,108 | $19,651,815 | $18,448,864 | $17,701,271 | ||||||||||||||||||||||||
| Long-term obligations (a) | $8,787,451 | $6,983,667 | $6,805,766 | $5,469,069 | $5,612,593 | ||||||||||||||||||||||||
| (a) Includes long-term debt (excluding currently maturing debt). | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2017 | 2016 | |||||||||||||||||||||||||
| (Dollars In Millions) | |||||||||||||||||||||||||||||
| Electric Operating Revenues: | |||||||||||||||||||||||||||||
| Residential | $1,270 | $1,271 | $1,244 | $1,198 | $1,196 | ||||||||||||||||||||||||
| Commercial | 887 | 947 | 941 | 956 | 930 | ||||||||||||||||||||||||
| Industrial | 1,314 | 1,451 | 1,462 | 1,534 | 1,350 | ||||||||||||||||||||||||
| Governmental | 69 | 71 | 69 | 69 | 67 | ||||||||||||||||||||||||
| Total billed retail | 3,540 | 3,740 | 3,716 | 3,757 | 3,543 | ||||||||||||||||||||||||
| Sales for resale: | |||||||||||||||||||||||||||||
| Associated companies | 276 | 273 | 295 | 278 | 368 | ||||||||||||||||||||||||
| Non-associated companies | 58 | 60 | 62 | 64 | 50 | ||||||||||||||||||||||||
| Other | 145 | 150 | 160 | 147 | 165 | ||||||||||||||||||||||||
| Total | $4,019 | $4,223 | $4,233 | $4,246 | $4,126 | ||||||||||||||||||||||||
| Billed Electric Energy Sales (GWh): | |||||||||||||||||||||||||||||
| Residential | 13,771 | 14,046 | 14,494 | 13,357 | 13,810 | ||||||||||||||||||||||||
| Commercial | 10,465 | 11,353 | 11,578 | 11,342 | 11,478 | ||||||||||||||||||||||||
| Industrial | 28,881 | 29,801 | 29,255 | 29,754 | 28,517 | ||||||||||||||||||||||||
| Governmental | 779 | 827 | 823 | 790 | 794 | ||||||||||||||||||||||||
| Total retail | 53,896 | 56,027 | 56,150 | 55,243 | 54,599 | ||||||||||||||||||||||||
| Sales for resale: | |||||||||||||||||||||||||||||
| Associated companies | 5,585 | 4,813 | 5,498 | 4,793 | 7,345 | ||||||||||||||||||||||||
| Non-associated companies | 2,365 | 1,924 | 1,762 | 1,711 | 1,690 | ||||||||||||||||||||||||
| Total | 61,846 | 62,764 | 63,410 | 61,747 | 63,634 | ||||||||||||||||||||||||
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ENTERGY MISSISSIPPI, LLC
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19” Pandemic section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy Mississippi’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $50 million to $60 million. Natural gas purchases for Entergy Mississippi for February 1st through 25th, 2021 are approximately $45 million compared to natural gas purchases for February 2020 of $14 million.
Results of Operations
2020 Compared to 2019
Net Income
Net income increased $20.7 million primarily due to higher retail electric price, partially offset by higher depreciation and amortization expenses, higher other operation and maintenance expenses, and lower volume/weather.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2020 to 2019.
| Amount | |||||
| (In Millions) | |||||
| 2019 operating revenues | $1,323.0 | ||||
| Fuel, rider, and other revenues that do not significantly affect net income | (153.2) | ||||
| Volume/weather | (17.6) | ||||
| Retail electric price | 95.7 | ||||
| 2020 operating revenues | 1,247.9 | ||||
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 volume/weather variance is primarily due to decreased commercial and industrial usage as a result of the COVID-19 pandemic and the effect of less favorable weather on residential sales, partially offset by increased residential usage as a result of the COVID-19 pandemic. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the COVID-19 pandemic.
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The retail electric price variance is primarily due to:
•increases in the formula rate plan rates effective with the first billing cycles of July 2019 and April 2020 and an interim capacity rate adjustment to the formula rate plan effective January 2020 to recover non-fuel related costs of acquiring and operating the Choctaw Generating Station; and
•the implementation of a vegetation management rider effective with the April 2020 billing cycle.
See Note 2 to the financial statements for further discussion of the formula rate plan filings and the vegetation management rider.
Other Income Statement Variances
Other operation and maintenance expenses increased primarily due to:
•an increase of $13.5 million in non-nuclear generation expenses primarily due to an increase in costs after the purchase of the Choctaw Generating Station in October 2019, partially offset by a decrease of $11.1 million primarily due to a lower scope of work performed during plant outages in 2020 as compared to the same period in 2019, including a delay in plant outages as a result of the COVID-19 pandemic;
•an increase of $8.1 million in storm damage provisions. See Note 2 to the financial statements for a discussion of storm cost recovery;
•an increase of $4.7 million in distribution operations costs due to a higher scope of work, including contract costs in 2020 as compared to the same period in 2019;
•an increase of $2.5 million in energy efficiency costs due to the timing of recovery from customers; and
•several individually insignificant items.
The increase was partially offset by a decrease of $3.7 million primarily due to contract costs in 2019 related to initiatives to explore new customer products and services.
Depreciation and amortization expenses increased primarily as a result of higher depreciation rates effective July 2019, as approved by the MPSC, and additions to plant in service, including the Choctaw Generating Station, which was purchased in October 2019.
The effective income tax rates were 16.2% for 2020 and 20.5% for 2019. See Note 3 to the financial statements for a reconciliation of the federal statutory rates of 21% to the effective income tax rates.
2019 Compared to 2018
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, 2019, filed with the SEC on February 21, 2020, for discussion of results of operations for 2019 compared to 2018.
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Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, and 2018 were as follows:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Thousands) | |||||||||||||||||
| Cash and cash equivalents at beginning of period | $51,601 | $36,954 | $6,096 | ||||||||||||||
| Net cash provided by (used in): | |||||||||||||||||
| Operating activities | 300,314 | 339,952 | 418,382 | ||||||||||||||
| Investing activities | (530,762) | (733,684) | (419,453) | ||||||||||||||
| Financing activities | 178,865 | 408,379 | 31,929 | ||||||||||||||
| Net increase (decrease) in cash and cash equivalents | (51,583) | 14,647 | 30,858 | ||||||||||||||
| Cash and cash equivalents at end of period | $18 | $51,601 | $36,954 | ||||||||||||||
2020 Compared to 2019
Operating Activities
Net cash flow provided by operating activities decreased $39.6 million in 2020 primarily due to:
•the timing of recovery of fuel and purchased power;
•lower collections of receivables from customers, in part due to the COVID-19 pandemic; and
•an increase of $10.3 million in storm spending in 2020.
The decrease was partially offset by the timing of payments to vendors and a decrease of $8.2 million in pension contributions in 2020. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Investing Activities
Net cash flow used in investing activities decreased $202.9 million in 2020 primarily due to:
•the purchase of the Choctaw Generating Station in October 2019 for approximately $305 million. See Note 14 to the financial statements for further discussion of the Choctaw Generating Station purchase; and
•money pool activity.
The decrease was partially offset by:
•an increase of $47.3 million in storm spending in 2020;
•an increase of $40.9 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Mississippi’s distribution system, including increased spending on advanced metering infrastructure;
•an increase of $25.8 million in non-nuclear construction expenditures primarily due to increased expenditures after the purchase of the Choctaw Generating Station in October 2019 and higher long-term service agreement expenses;
•$24.6 million in plant upgrades for Choctaw Generating Station in March 2020; and
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•an increase of $22.4 million in transmission construction expenditures primarily due to a higher scope of work performed in 2020 as compared to 2019.
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 by $44.7 million in 2020 compared to increasing by $3.3 million in 2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Financing Activities
Net cash flow provided by financing activities decreased $229.5 million in 2020 primarily due to:
•the issuance of $170 million of 3.5% Series mortgage bonds in 2020 compared to the issuance of $435 million of 3.85% Series mortgage bonds in 2019; and
•a capital contribution of $130 million in October 2019 in anticipation of the purchase of the Choctaw Generating Station.
The decrease was partially offset by the repayment, at maturity, of $150 million of 6.64% Series mortgage bonds in July 2019 and money pool activity.
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 $16.5 million in 2020.
See Note 5 to the financial statements for details on long-term debt.
2019 Compared to 2018
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, 2019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
Capital Structure
Entergy Mississippi’s debt to capital ratio is shown in the following table.
| December 31, 2020 | December 31, 2019 | ||||||||||
| Debt to capital | 51.7 | % | 51.2 | % | |||||||
| Effect of subtracting cash | — | % | (0.8 | %) | |||||||
| Net debt to net capital | 51.7 | % | 50.4 | % | |||||||
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. 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.
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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, 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 reducing distributions, Entergy Mississippi may receive equity contributions to maintain its capital structure.
Uses of Capital
Entergy Mississippi requires capital resources for:
•construction and other capital investments;
•debt maturities or retirements;
•working capital purposes, including the financing of fuel and purchased power costs; and
•distributions and interest payments.
Following are the amounts of Entergy Mississippi’s planned construction and other capital investments.
| 2021 | 2022 | 2023 | |||||||||||||||
| (In Millions) | |||||||||||||||||
| Planned construction and capital investment: | |||||||||||||||||
| Generation | $180 | $140 | $180 | ||||||||||||||
| Transmission | 120 | 75 | 55 | ||||||||||||||
| Distribution | 210 | 200 | 225 | ||||||||||||||
| Utility Support | 80 | 85 | 30 | ||||||||||||||
| Total | $590 | $500 | $490 | ||||||||||||||
Following are the amounts of Entergy Mississippi’s existing debt obligations and lease obligations (includes estimated interest payments) and other purchase obligations.
| 2021 | 2022-2023 | 2024-2025 | After 2025 | Total | |||||||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||||||||
| Long-term debt (a) | $65 | $376 | $209 | $2,575 | $3,225 | ||||||||||||||||||||||||
| Operating leases (b) | $6 | $8 | $2 | $2 | $18 | ||||||||||||||||||||||||
| Finance leases (b) | $2 | $3 | $2 | $1 | $8 | ||||||||||||||||||||||||
| Purchase obligations (c) | $223 | $434 | $412 | $3,779 | $4,848 | ||||||||||||||||||||||||
(a)Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.
(b)Lease obligations are discussed in Note 10 to the financial statements.
(c)Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Mississippi, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements.
In addition to the contractual obligations given above, Entergy Mississippi currently expects to contribute approximately $13.7 million to its qualified pension plans and approximately $130 thousand to other postretirement health care and life insurance plans in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021. See
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“Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also, in addition to the contractual obligations, Entergy Mississippi has $84 million of unrecognized tax benefits and interest net of unused tax attributes 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 to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Mississippi includes amounts associated with specific investments such as the Sunflower Solar Facility; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; software and security; 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, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Mississippi pays distributions from its earnings at a percentage determined monthly.
Sunflower Solar Facility
In November 2018, Entergy Mississippi announced that it signed an agreement for the purchase of an approximately 100 MW solar photovoltaic facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. The estimated base purchase price is approximately $138.4 million. The estimated total investment, including the base purchase price and other related costs, for Entergy Mississippi to acquire the Sunflower Solar Facility is approximately $153.2 million. The purchase is contingent upon, among other things, obtaining necessary approvals, including full cost recovery, from applicable federal and state regulatory and permitting agencies. The project is being built by Sunflower County Solar Project, LLC, an indirect subsidiary of Recurrent Energy, LLC. Entergy Mississippi will purchase the facility upon mechanical completion and after the other purchase contingencies have been met. In December 2018, Entergy Mississippi filed a joint petition with Sunflower Solar Project with the MPSC for Sunflower Solar Project to construct and for Entergy Mississippi to acquire and thereafter own, operate, improve, and maintain the solar facility. Entergy Mississippi proposed revisions to its formula rate plan that would provide for a mechanism, the interim capacity rate adjustment mechanism, in the formula rate plan to recover the non-fuel related costs of additional owned capacity acquired by Entergy Mississippi, including the annual ownership costs of the Sunflower Solar Facility. In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to provide for an interim capacity rate adjustment mechanism. Recovery through the interim capacity rate adjustment requires MPSC approval for each new resource. In August 2019 consultants retained by the Mississippi Public Utilities Staff filed a report expressing concerns regarding the project economics. In March 2020, Entergy Mississippi filed supplemental testimony addressing questions and observations raised by the consultants retained by the Mississippi Public Utilities Staff and proposing an alternative structure for the transaction that would reduce its cost. A hearing before the MPSC was held in March 2020. In April 2020 the MPSC issued an order approving certification of the Sunflower Solar Facility and its recovery through the interim capacity rate adjustment mechanism, subject to certain conditions including: (i) that Entergy Mississippi pursue a 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. Closing is targeted to occur by the end of 2021.
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Sources of Capital
Entergy Mississippi’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•storm reserve escrow accounts;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy Mississippi may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
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.
Entergy Mississippi’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| 2020 | 2019 | 2018 | 2017 | |||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| ($16,516) | $44,693 | $41,380 | $1,633 | |||||||||||||||||
See Note 4 to the financial statements for a description of the money pool.
Entergy Mississippi has three separate credit facilities in the aggregate amount of $82.5 million scheduled to expire in April 2021. No borrowings were outstanding under the credit facilities as of December 31, 2020. In addition, Entergy Mississippi is a party to an uncommitted letter of credit facility primarily as a means to post collateral to support its obligations to MISO. As of December 31, 2020, $1 million of MISO letters of credit and $1 million of non-MISO letters 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 July 2022 for short-term borrowings not to exceed an aggregate amount of $175 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.
Entergy Mississippi has $33 million in its storm reserve escrow account at December 31, 2020.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Mississippi charges for electricity 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.
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Formula Rate Plan Filings
In October 2018, Entergy Mississippi proposed revisions to its formula rate plan that would 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, including the non-fuel annual ownership costs of the Choctaw Generating Station, as well as to allow similar cost recovery treatment for other future capacity acquisitions, such as the Sunflower Solar Facility, that are approved by the MPSC. In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to provide for an interim capacity rate adjustment mechanism to recover the $59 million first-year annual revenue requirement associated with the non-fuel ownership costs of the Choctaw Generating Station, which Entergy Mississippi began billing in January 2020. 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. Effective with the April 2020 billing cycle, Entergy Mississippi implemented a rider to recover $22 million in vegetation management costs.
In March 2019, Entergy Mississippi submitted its formula rate plan 2019 test year filing and 2018 look-back filing showing Entergy Mississippi’s earned return for the historical 2018 calendar year to be above the formula rate plan bandwidth and projected earned return for the 2019 calendar year to be below the formula rate plan bandwidth. The 2019 test year filing shows a $36.8 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.94% return on rate base, within the formula rate plan bandwidth. The 2018 look-back filing compares actual 2018 results to the approved benchmark return on rate base and shows a $10.1 million interim decrease in formula rate plan revenues is necessary. In the fourth quarter 2018, Entergy Mississippi recorded a provision of $9.3 million that reflected the estimate of the difference between the 2018 expected earned rate of return on rate base and an established performance-adjusted benchmark rate of return under the formula rate plan performance-adjusted bandwidth mechanism. In the first quarter 2019, Entergy Mississippi recorded a $0.8 million increase in the provision to reflect the amount shown in the look-back filing. In June 2019, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed that the 2019 test year filing showed that a $32.8 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.93% return on rate base, within the formula rate plan bandwidth. Additionally, pursuant to the joint stipulation, Entergy Mississippi’s 2018 look-back filing reflected an earned return on rate base of 7.81% in calendar year 2018 which is above the look-back benchmark return on rate base of 7.13%, resulting in an $11 million decrease in formula rate plan revenues on an interim basis through May 2020. In the second quarter 2019, Entergy Mississippi recorded an additional $0.9 million increase in the provision to reflect the $11 million shown in the look-back filing. In June 2019 the MPSC approved the joint stipulation with rates effective for the first billing cycle of July 2019.
In March 2020, Entergy Mississippi submitted its formula rate plan 2020 test year filing and 2019 look-back filing showing Entergy Mississippi’s earned return for the historical 2019 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2020 calendar year to be below the formula rate plan bandwidth. The 2020 test year filing shows a $24.6 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.51% return on rate base, within the formula rate plan bandwidth. The 2019 look-back filing compares actual 2019 results to the approved benchmark return on rate base and reflects the need for a $7.3 million interim increase in formula rate plan revenues. In accordance with the MPSC-approved revisions to the formula rate plan, Entergy Mississippi implemented a $24.3 million interim rate increase, reflecting a cap equal to 2% of 2019 retail revenues, effective with the April 2020 billing cycle, subject to refund. In June 2020, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed that the 2020 test year filing showed that a $23.8 million rate increase is necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of
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adjustment of 6.51% return on rate base, within the formula rate plan bandwidth. Pursuant to the joint stipulation, Entergy Mississippi’s 2019 look-back filing reflected an earned return on rate base of 6.75% in calendar year 2019, which is within the look-back bandwidth. As a result, there is no change in formula rate plan revenues in the 2019 look-back filing. In June 2020 the MPSC approved the joint stipulation with rates effective for the first billing cycle of July 2020. In the June 2020 order the MPSC directed Entergy Mississippi to submit revisions to its formula rate plan to realign recovery of costs from its energy efficiency cost recovery rider to its formula rate plan. 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.
COVID-19 Order
In March 2020 the MPSC issued an order suspending disconnections for a period of sixty days. The MPSC extended the order on disconnections through May 26, 2020. In April 2020 the MPSC issued an order authorizing utilities to defer incremental costs and expenses associated with COVID-19 compliance and to seek future recovery through rates of the prudently incurred incremental costs and expenses. In December 2020, Entergy Mississippi resumed disconnections for commercial, industrial, and governmental customers with past-due balances that have not made payment arrangements. In January 2021, Entergy Mississippi resumed disconnecting service for residential customers with past-due balances that have not made arrangements. As of December 31, 2020, Entergy Mississippi recorded a regulatory asset of $19.2 million for costs associated with the COVID-19 pandemic.
Internal Restructuring
In March 2018, Entergy Mississippi filed an application with the MPSC seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy Mississippi to a new entity, which would ultimately be held by an existing Entergy subsidiary holding company. In September 2018, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed a joint stipulation regarding the restructuring filing. In September 2018 the MPSC issued an order accepting the stipulation in its entirety and approving the restructuring and credits of $27 million to retail customers over six years, consisting of annual payments of $4.5 million for the years 2019-2024. Entergy Mississippi also received the required FERC approval.
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.
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In December 2018, Entergy Mississippi filed its notice of intent to implement the restructuring credit rider to allow Entergy Mississippi to return credits of $27 million to retail customers over six years. In January 2019 the MPSC approved the proposed restructuring credit adjustment factor, which is effective for bills rendered beginning February 2019.
Fuel and Purchased Power Cost Recovery
Entergy Mississippi’s rate schedules include an energy cost recovery rider that is adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
In January 2017 the MPSC certified to the Mississippi Legislature the audit reports of its independent auditors for the fuel year ending September 30, 2016. In November 2017 the Mississippi Public Utilities Staff separately engaged a consultant to review the September 2016 outage at the Grand Gulf Nuclear Station and to review ongoing operations at Grand Gulf. This engagement continues, and subsequently, was expanded to include all outages at Grand Gulf that occurred through 2019.
In November 2017, 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 $61.5 million as of September 30, 2017. In January 2018 the MPSC approved the proposed energy cost factors effective for February 2018 bills.
In November 2018, 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 $57 million as of September 30, 2018. In January 2019 the MPSC approved the proposed energy cost factor effective for February 2019 bills.
In November 2019, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation included $39.6 million of prior over-recovery flowing back to customers beginning September 2020. Entergy Mississippi’s balance in its deferred fuel account did not decrease as expected after implementation of the new factor. In an effort to assist customers during the COVID-19 pandemic, in May 2020, Entergy Mississippi requested an interim adjustment to the energy cost recovery rider to credit approximately $50 million from the over-recovered balance in the deferred fuel account to customers over four consecutive billing months. The MPSC approved this interim adjustment in May 2020 effective for June through September 2020 bills.
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.
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.
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Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Nuclear Matters
See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.
Environmental Risks
Entergy Mississippi’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Mississippi is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Mississippi’s financial statements in conformity with generally accepted accounting principles 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 policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of Entergy Mississippi’s financial position or results of operations.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Impairment of Long-lived Assets
See “Impairment of Long-lived Assets” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Mississippi’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified
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Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| Actuarial Assumption | Change in Assumption | Impact on 2021 Qualified Pension Cost | Impact on 2020 Projected Qualified Benefit Obligation | |||||||||||||||||
| Increase/(Decrease) | ||||||||||||||||||||
| Discount rate | (0.25%) | $654 | $12,777 | |||||||||||||||||
| Rate of return on plan assets | (0.25%) | $828 | $— | |||||||||||||||||
| Rate of increase in compensation | 0.25% | $533 | $2,720 | |||||||||||||||||
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| Actuarial Assumption | Change in Assumption | Impact on 2021 Postretirement Benefit Cost | Impact on 2020 Accumulated Postretirement Benefit Obligation | |||||||||||||||||
| Increase/(Decrease) | ||||||||||||||||||||
| Discount rate | (0.25%) | $59 | $1,970 | |||||||||||||||||
| Health care cost trend | 0.25% | $73 | $1,402 | |||||||||||||||||
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy Mississippi in 2020 was $20.2 million, including $3.4 million in settlement costs. Entergy Mississippi anticipates 2021 qualified pension cost to be $19.6 million. Entergy Mississippi contributed $12.6 million to its qualified pension plans in 2020 and estimates 2021 pension contributions will be approximately $13.7 million, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021.
Total postretirement health care and life insurance benefit income for Entergy Mississippi in 2020 was $3.6 million. Entergy Mississippi expects 2021 postretirement health care and life insurance benefit income of approximately $4.7 million. Entergy Mississippi contributed $343 thousand to its other postretirement plans in 2020 and estimates that 2021 contributions will be approximately $130 thousand.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
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New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the member and Board of Directors of
Entergy Mississippi, LLC
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Entergy Mississippi, LLC (the “Company”) as of December 31, 2020 and 2019, the related statements of income, cash flows and changes in member’s equity (pages 379 through 384 and applicable items in pages 51 through 238), for each of the three years in the period ended December 31, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters —Entergy Mississippi, LLC — Refer to Note 2 to the financial statements
Critical Audit Matter Description
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, such as property, plant, and equipment;
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regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
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 significant 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, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the MPSC and the FERC 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 costs incurred as property, plant, and equipment and deferred as 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 property, plant, and equipment; 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 and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information 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 the 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, including the annual formula rate plan filing, 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.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2021
We have served as the Company’s auditor since 2001.
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| ENTERGY MISSISSIPPI, LLC | ||||||||||||||||||||
| INCOME STATEMENTS | ||||||||||||||||||||
| For the Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| OPERATING REVENUES | ||||||||||||||||||||
| Electric | $1,247,854 | $1,323,043 | $1,335,112 | |||||||||||||||||
| OPERATING EXPENSES | ||||||||||||||||||||
| Operation and Maintenance: | ||||||||||||||||||||
| Fuel, fuel-related expenses, and gas purchased for resale | 187,087 | 277,425 | 260,198 | |||||||||||||||||
| Purchased power | 240,471 | 284,492 | 364,575 | |||||||||||||||||
| Other operation and maintenance | 288,543 | 266,175 | 261,613 | |||||||||||||||||
| Taxes other than income taxes | 101,525 | 105,318 | 101,999 | |||||||||||||||||
| Depreciation and amortization | 209,252 | 170,886 | 152,577 | |||||||||||||||||
| Other regulatory charges (credits) - net | (15,219) | 14,993 | 147,704 | |||||||||||||||||
| TOTAL | 1,011,659 | 1,119,289 | 1,288,666 | |||||||||||||||||
| OPERATING INCOME | 236,195 | 203,754 | 46,446 | |||||||||||||||||
| OTHER INCOME (DEDUCTIONS) | ||||||||||||||||||||
| Allowance for equity funds used during construction | 6,726 | 8,356 | 8,710 | |||||||||||||||||
| Interest and investment income | 272 | 1,412 | 135 | |||||||||||||||||
| Miscellaneous - net | (9,253) | (4,478) | (2,732) | |||||||||||||||||
| TOTAL | (2,255) | 5,290 | 6,113 | |||||||||||||||||
| INTEREST EXPENSE | ||||||||||||||||||||
| Interest expense | 68,945 | 61,785 | 55,905 | |||||||||||||||||
| Allowance for borrowed funds used during construction | (2,778) | (3,532) | (3,651) | |||||||||||||||||
| TOTAL | 66,167 | 58,253 | 52,254 | |||||||||||||||||
| INCOME BEFORE INCOME TAXES | 167,773 | 150,791 | 305 | |||||||||||||||||
| Income taxes | 27,190 | 30,866 | (125,773) | |||||||||||||||||
| NET INCOME | 140,583 | 119,925 | 126,078 | |||||||||||||||||
| Preferred dividend requirements and other | — | — | 834 | |||||||||||||||||
| EARNINGS APPLICABLE TO COMMON EQUITY | $140,583 | $119,925 | $125,244 | |||||||||||||||||
| See Notes to Financial Statements. | ||||||||||||||||||||
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380
| ENTERGY MISSISSIPPI, LLC | ||||||||||||||||||||
| STATEMENTS OF CASH FLOWS | ||||||||||||||||||||
| For the Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| OPERATING ACTIVITIES | ||||||||||||||||||||
| Net income | $140,583 | $119,925 | $126,078 | |||||||||||||||||
| Adjustments to reconcile net income to net cash flow provided by operating activities: | ||||||||||||||||||||
| Depreciation and amortization | 209,252 | 170,886 | 152,577 | |||||||||||||||||
| Deferred income taxes, investment tax credits, and non-current taxes accrued | 36,827 | 32,547 | 56,502 | |||||||||||||||||
| Changes in assets and liabilities: | ||||||||||||||||||||
| Receivables | (1,889) | (17,245) | 37,762 | |||||||||||||||||
| Fuel inventory | (1,978) | (3,208) | 33,675 | |||||||||||||||||
| Accounts payable | 22,794 | (226) | (7,472) | |||||||||||||||||
| Taxes accrued | 17,423 | 13,109 | (5,291) | |||||||||||||||||
| Interest accrued | 1,989 | (1,331) | (2,670) | |||||||||||||||||
| Deferred fuel costs | (55,711) | 78,418 | 24,428 | |||||||||||||||||
| Other working capital accounts | 630 | (5,557) | (9,902) | |||||||||||||||||
| Provisions for estimated losses | (3,517) | (1,121) | 6,378 | |||||||||||||||||
| Other regulatory assets | (89,369) | (34,923) | 54,860 | |||||||||||||||||
| Other regulatory liabilities | (18,672) | (21,524) | (131,856) | |||||||||||||||||
| Pension and other postretirement liabilities | 11,319 | 6,534 | (8,405) | |||||||||||||||||
| Other assets and liabilities | 30,633 | 3,668 | 91,718 | |||||||||||||||||
| Net cash flow provided by operating activities | 300,314 | 339,952 | 418,382 | |||||||||||||||||
| INVESTING ACTIVITIES | ||||||||||||||||||||
| Construction expenditures | (555,287) | (432,600) | (387,293) | |||||||||||||||||
| Allowance for equity funds used during construction | 6,726 | 8,356 | 8,710 | |||||||||||||||||
| Changes in money pool receivable - net | 44,692 | (3,313) | (39,747) | |||||||||||||||||
| Payment for purchase of plant or assets | (28,612) | (305,472) | — | |||||||||||||||||
| Other | 1,719 | (655) | (1,123) | |||||||||||||||||
| Net cash flow used in investing activities | (530,762) | (733,684) | (419,453) | |||||||||||||||||
| FINANCING ACTIVITIES | ||||||||||||||||||||
| Proceeds from the issuance of long-term debt | 165,385 | 437,153 | 54,449 | |||||||||||||||||
| Retirement of long-term debt | — | (150,000) | — | |||||||||||||||||
| Changes in money pool payable - net | 16,516 | — | — | |||||||||||||||||
| Redemption of preferred stock | — | — | (21,208) | |||||||||||||||||
| Capital contributions from parent | — | 130,000 | — | |||||||||||||||||
| Distributions/dividends paid: | ||||||||||||||||||||
| Common equity | (10,000) | — | (10,000) | |||||||||||||||||
| Preferred stock | — | — | (993) | |||||||||||||||||
| Other | 6,964 | (8,774) | 9,681 | |||||||||||||||||
| Net cash flow provided by financing activities | 178,865 | 408,379 | 31,929 | |||||||||||||||||
| Net increase (decrease) in cash and cash equivalents | (51,583) | 14,647 | 30,858 | |||||||||||||||||
| Cash and cash equivalents at beginning of period | 51,601 | 36,954 | 6,096 | |||||||||||||||||
| Cash and cash equivalents at end of period | $18 | $51,601 | $36,954 | |||||||||||||||||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||||||||||||||||
| Cash paid (received) during the period for: | ||||||||||||||||||||
| Interest - net of amount capitalized | $64,536 | $60,533 | $56,037 | |||||||||||||||||
| Income taxes | ($8,084) | ($12,204) | ($19,118) | |||||||||||||||||
| See Notes to Financial Statements. | ||||||||||||||||||||
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| ENTERGY MISSISSIPPI, LLC | ||||||||||||||
| BALANCE SHEETS | ||||||||||||||
| ASSETS | ||||||||||||||
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| CURRENT ASSETS | ||||||||||||||
| Cash and cash equivalents: | ||||||||||||||
| Cash | $11 | $11 | ||||||||||||
| Temporary cash investments | 7 | 51,590 | ||||||||||||
| Total cash and cash equivalents | 18 | 51,601 | ||||||||||||
| Accounts receivable: | ||||||||||||||
| Customer | 105,732 | 92,050 | ||||||||||||
| Allowance for doubtful accounts | (19,527) | (636) | ||||||||||||
| Associated companies | 2,740 | 49,257 | ||||||||||||
| Other | 11,821 | 14,986 | ||||||||||||
| Accrued unbilled revenues | 59,514 | 47,426 | ||||||||||||
| Total accounts receivable | 160,280 | 203,083 | ||||||||||||
| Fuel inventory - at average cost | 17,117 | 15,139 | ||||||||||||
| Materials and supplies - at average cost | 59,542 | 57,972 | ||||||||||||
| Prepayments and other | 4,876 | 7,149 | ||||||||||||
| TOTAL | 241,833 | 334,944 | ||||||||||||
| OTHER PROPERTY AND INVESTMENTS | ||||||||||||||
| Non-utility property - at cost (less accumulated depreciation) | 4,543 | 4,560 | ||||||||||||
| Escrow accounts | 64,635 | 80,201 | ||||||||||||
| TOTAL | 69,178 | 84,761 | ||||||||||||
| UTILITY PLANT | ||||||||||||||
| Electric | 6,084,730 | 5,672,589 | ||||||||||||
| Construction work in progress | 134,854 | 88,373 | ||||||||||||
| TOTAL UTILITY PLANT | 6,219,584 | 5,760,962 | ||||||||||||
| Less - accumulated depreciation and amortization | 2,005,087 | 1,894,000 | ||||||||||||
| UTILITY PLANT - NET | 4,214,497 | 3,866,962 | ||||||||||||
| DEFERRED DEBITS AND OTHER ASSETS | ||||||||||||||
| Regulatory assets: | ||||||||||||||
| Other regulatory assets | 467,341 | 377,972 | ||||||||||||
| Other | 14,413 | 10,105 | ||||||||||||
| TOTAL | 481,754 | 388,077 | ||||||||||||
| TOTAL ASSETS | $5,007,262 | $4,674,744 | ||||||||||||
| See Notes to Financial Statements. | ||||||||||||||
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| ENTERGY MISSISSIPPI, LLC | ||||||||||||||
| BALANCE SHEETS | ||||||||||||||
| LIABILITIES AND EQUITY | ||||||||||||||
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| CURRENT LIABILITIES | ||||||||||||||
| Accounts payable: | ||||||||||||||
| Associated companies | $61,727 | $48,090 | ||||||||||||
| Other | 117,629 | 94,729 | ||||||||||||
| Customer deposits | 86,200 | 85,938 | ||||||||||||
| Taxes accrued | 108,084 | 90,661 | ||||||||||||
| Interest accrued | 20,889 | 18,900 | ||||||||||||
| Deferred fuel costs | 14,691 | 70,402 | ||||||||||||
| Other | 34,270 | 32,667 | ||||||||||||
| TOTAL | 443,490 | 441,387 | ||||||||||||
| NON-CURRENT LIABILITIES | ||||||||||||||
| Accumulated deferred income taxes and taxes accrued | 646,674 | 594,832 | ||||||||||||
| Accumulated deferred investment tax credits | 9,062 | 9,602 | ||||||||||||
| Regulatory liability for income taxes - net | 224,000 | 236,988 | ||||||||||||
| Other regulatory liabilities | 15,828 | 21,512 | ||||||||||||
| Asset retirement cost liabilities | 9,762 | 9,727 | ||||||||||||
| Accumulated provisions | 46,504 | 50,021 | ||||||||||||
| Pension and other postretirement liabilities | 110,901 | 99,406 | ||||||||||||
| Long-term debt | 1,780,577 | 1,614,129 | ||||||||||||
| Other | 47,730 | 54,989 | ||||||||||||
| TOTAL | 2,891,038 | 2,691,206 | ||||||||||||
| Commitments and Contingencies | ||||||||||||||
| EQUITY | ||||||||||||||
| Member's equity | 1,672,734 | 1,542,151 | ||||||||||||
| TOTAL | 1,672,734 | 1,542,151 | ||||||||||||
| TOTAL LIABILITIES AND EQUITY | $5,007,262 | $4,674,744 | ||||||||||||
| See Notes to Financial Statements. | ||||||||||||||
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| ENTERGY MISSISSIPPI, LLC | |||||
| STATEMENTS OF CHANGES IN MEMBER'S EQUITY | |||||
| For the Years Ended December 31, 2020, 2019, and 2018 | |||||
| Member's Equity | |||||
| (In Thousands) | |||||
| Balance at December 31, 2017 | $1,177,870 | ||||
| Net income | 126,078 | ||||
| Common equity distributions | (10,000) | ||||
| Preferred stock dividends | (834) | ||||
| Other | (888) | ||||
| Balance at December 31, 2018 | $1,292,226 | ||||
| Net income | 119,925 | ||||
| Capital contribution from parent | 130,000 | ||||
| Balance at December 31, 2019 | $1,542,151 | ||||
| Net income | 140,583 | ||||
| Common equity distributions | (10,000) | ||||
| Balance at December 31, 2020 | $1,672,734 | ||||
| See Notes to Financial Statements. | |||||
384
| ENTERGY MISSISSIPPI, LLC | |||||||||||||||||||||||||||||
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2017 | 2016 | |||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||
| Operating revenues | $1,247,854 | $1,323,043 | $1,335,112 | $1,198,229 | $1,094,649 | ||||||||||||||||||||||||
| Net income | $140,583 | $119,925 | $126,078 | $110,032 | $109,184 | ||||||||||||||||||||||||
| Total assets | $5,007,262 | $4,674,744 | $3,946,804 | $3,879,375 | $3,602,140 | ||||||||||||||||||||||||
| Long-term obligations (a) | $1,780,577 | $1,614,129 | $1,175,750 | $1,290,503 | $1,141,924 | ||||||||||||||||||||||||
| (a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and preferred stock without sinking fund. | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2017 | 2016 | |||||||||||||||||||||||||
| (Dollars In Millions) | |||||||||||||||||||||||||||||
| Electric Operating Revenues: | |||||||||||||||||||||||||||||
| Residential | $523 | $562 | $579 | $502 | $459 | ||||||||||||||||||||||||
| Commercial | 396 | 444 | 462 | 423 | 374 | ||||||||||||||||||||||||
| Industrial | 145 | 165 | 175 | 159 | 134 | ||||||||||||||||||||||||
| Governmental | 42 | 44 | 44 | 41 | 38 | ||||||||||||||||||||||||
| Total billed retail | 1,106 | 1,215 | 1,260 | 1,125 | 1,005 | ||||||||||||||||||||||||
| Sales for resale: | |||||||||||||||||||||||||||||
| Associated companies | — | — | 1 | — | 1 | ||||||||||||||||||||||||
| Non-associated companies | 78 | 39 | 25 | 18 | 30 | ||||||||||||||||||||||||
| Other | 64 | 69 | 49 | 55 | 59 | ||||||||||||||||||||||||
| Total | $1,248 | $1,323 | $1,335 | $1,198 | $1,095 | ||||||||||||||||||||||||
| Billed Electric Energy Sales (GWh): | |||||||||||||||||||||||||||||
| Residential | 5,378 | 5,659 | 5,829 | 5,308 | 5,617 | ||||||||||||||||||||||||
| Commercial | 4,283 | 4,698 | 4,865 | 4,783 | 4,894 | ||||||||||||||||||||||||
| Industrial | 2,343 | 2,443 | 2,559 | 2,536 | 2,493 | ||||||||||||||||||||||||
| Governmental | 398 | 436 | 438 | 421 | 439 | ||||||||||||||||||||||||
| Total retail | 12,402 | 13,236 | 13,691 | 13,048 | 13,443 | ||||||||||||||||||||||||
| Sales for resale: | |||||||||||||||||||||||||||||
| Non-associated companies | 4,316 | 1,776 | 1,060 | 857 | 1,021 | ||||||||||||||||||||||||
| Total | 16,718 | 15,012 | 14,751 | 13,905 | 14,464 | ||||||||||||||||||||||||
385
ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
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. Total restoration costs for the repair and/or replacement of Entergy New Orleans’s electric facilities damaged by Hurricane Zeta are currently estimated to be approximately $40 million, including approximately $30 million in capital costs and approximately $10 million in non-capital costs. Entergy New Orleans is considering all available avenues to recover storm-related costs from Hurricane Zeta, including accessing funded storm reserve escrows and securitization. Storm cost recovery or financing will be subject to review by applicable regulatory authorities.
Entergy New Orleans recorded accounts payable and corresponding construction work in progress and regulatory assets for the estimated costs incurred that were necessary to return customers to service. Entergy New Orleans recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. There are well established mechanisms and precedent for addressing these catastrophic events and providing for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles. Because Entergy New Orleans has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy New Orleans is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy New Orleans’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $1 million. Natural gas purchases for Entergy New Orleans for February 1st through 25th, 2021 are approximately $15 million compared to natural gas purchases for February 2020 of $7 million.
Results of Operations
2020 Compared to 2019
Net Income
Net income decreased $3.3 million primarily due to lower volume/weather, lower retail electric price, and higher interest expense, partially offset by a lower effective income tax rate.
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Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2020 to 2019.
| Amount | |||||
| (In Millions) | |||||
| 2019 operating revenues | $686.2 | ||||
| Fuel, rider, and other revenues that do not significantly affect net income | (32.5) | ||||
| Volume/weather | (12.5) | ||||
| Retail electric price | (7.4) | ||||
| 2020 operating revenues | $633.8 | ||||
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 primarily due to a decrease of 374 GWh, or 6.4%, in billed electricity usage, including the effect of decreased commercial and governmental usage as a result of the COVID-19 pandemic and the effect of less favorable weather on residential and commercial sales, partially offset by an increase in residential usage as a result of the COVID-19 pandemic. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the COVID-19 pandemic.
The retail electric price variance is primarily due to the effects of a rate reduction implemented with April 2020 bills that was effective August 2019 in accordance with the City Council resolution and related agreement in principle reached in the 2018 base rate case. See Note 2 to the financial statements for further discussion of the rate case.
Other Income Statement Variances
Other operation and maintenance expenses increased primarily due to:
•an increase of $4.9 million primarily due to the 2019 deferral of costs related to the 2018 rate case and a system conversion for Algiers customers as a result of the 2018 combined rate case resolution approved by the City Council. See Note 2 to the financial statements for further discussion of the rate case resolution; and
•an increase of $3.8 million in energy efficiency costs.
The increase was partially offset by:
•a decrease of $2.4 million in gas operations costs primarily due to the deferral in 2020 of certain gas infrastructure replacement program costs as a result of the 2018 combined rate case resolution. See Note 2 to the financial statements for further discussion of the rate case resolution; and
•a decrease of $2.2 million primarily due to contract costs in 2019 related to initiatives to explore new customer products and services.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
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Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other regulatory charges - net include regulatory credits recorded in the first quarter 2020 to reflect compliance with terms of the 2018 combined rate case resolution approved by the City Council in February 2020. See Note 2 to the financial statements for further discussion of the rate case resolution.
Interest expense increased primarily due to the issuance of:
•a $70 million term loan at 3.0% in December 2019;
•$78 million of 3.00% Series mortgage bonds in March 2020; and
•$62 million of 3.75% Series mortgage bonds in March 2020.
The effective income tax rates were (9.3%) for 2020 and 0.4% for 2019. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2020 was primarily due to the amortization of excess accumulated deferred income taxes and the completion of the 2014-2015 IRS audit effectively settling the tax positions for those years. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2019 was primarily due to the amortization of excess accumulated deferred income taxes. See Notes 2 and 3 to the financial statements for a discussion of the effects and regulatory activity regarding the Tax Cuts and Jobs Act. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.
2019 Compared to 2018
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, 2019, filed with the SEC on February 21, 2020, for discussion of results of operations for 2019 compared to 2018.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, and 2018 were as follows:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Thousands) | |||||||||||||||||
| Cash and cash equivalents at beginning of period | $6,017 | $19,677 | $32,741 | ||||||||||||||
| Net cash provided by (used in): | |||||||||||||||||
| Operating activities | 64,024 | 115,604 | 171,778 | ||||||||||||||
| Investing activities | (220,845) | (204,310) | (207,616) | ||||||||||||||
| Financing activities | 150,830 | 75,046 | 22,774 | ||||||||||||||
| Net decrease in cash and cash equivalents | (5,991) | (13,660) | (13,064) | ||||||||||||||
| Cash and cash equivalents at end of period | $26 | $6,017 | $19,677 | ||||||||||||||
2020 Compared to 2019
Operating Activities
Net cash flow provided by operating activities decreased $51.6 million in 2020 primarily due to:
•lower collections of receivables from customers, in part due to the COVID-19 pandemic;
•the timing of recovery of fuel and purchased power costs; and
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Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•income tax payments of $3.4 million made in 2020 compared to income tax refunds of $5.3 million received in 2019, each in accordance with an intercompany income tax allocation agreement. The income tax refunds resulted from the utilization of Entergy New Orleans’s net operating loss.
The decrease was partially offset by the timing of payments to vendors.
Investing Activities
Net cash flow used in investing activities increased $16.5 million in 2020 primarily due to:
•an increase of $12.4 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy New Orleans’s distribution system, including increased spending on advanced metering infrastructure;
•money pool activity;
•an increase of $10.8 million in storm spending in 2020, primarily due to Hurricane Zeta restoration efforts. See “Hurricane Zeta” above for discussion of hurricane restoration efforts; and
•an increase of $5.1 million in facilities construction expenditures primarily due to a higher scope of work performed in 2020.
The increase was partially offset by:
•a decrease of $16.2 million in non-nuclear generation construction expenditures primarily due to lower spending in 2020 on the New Orleans Power Station project, partially offset by higher spending in 2020 on the New Orleans Solar Station project; and
•a decrease of $7.5 million in transmission construction expenditures primarily due to lower spending in 2020 on the New Orleans Power Station project.
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 $5.2 million in 2020 compared to decreasing $16.8 million in 2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Financing Activities
Net cash flow provided by financing activities increased $75.8 million primarily due to a capital contribution received from Entergy Corporation of $60 million in November 2020 in order to maintain Entergy New Orleans’s capital structure and money pool activity.
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 $10.2 million in 2020.
2019 Compared to 2018
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, 2019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
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Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Capital Structure
Entergy New Orleans’s debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio is primarily due to an increase in equity resulting from a $60 million capital contribution received from Entergy Corporation in 2020 and net income, partially offset by the net issuance of long-term debt in 2020.
| December 31, 2020 | December 31, 2019 | ||||||||||
| Debt to capital | 51.5 | % | 53.1 | % | |||||||
| Effect of excluding securitization bonds | (1.6 | %) | (2.4 | %) | |||||||
| Debt to capital, excluding securitization bonds (a) | 49.9 | % | 50.7 | % | |||||||
| Effect of subtracting cash | — | % | (0.3 | %) | |||||||
| Net debt to net capital, excluding securitization bonds (a) | 49.9 | % | 50.4 | % | |||||||
(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. 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, 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 reducing distributions, Entergy New Orleans may receive equity contributions to maintain its capital structure.
Uses of Capital
Entergy New Orleans requires capital resources for:
•construction and other capital investments;
•working capital purposes, including the financing of fuel and purchased power costs;
•debt maturities or retirements; and
•distribution and interest payments.
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Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy New Orleans’s planned construction and other capital investments.
| 2021 | 2022 | 2023 | |||||||||||||||
| (In Millions) | |||||||||||||||||
| Planned construction and capital investment: | |||||||||||||||||
| Generation | $10 | $15 | $5 | ||||||||||||||
| Transmission | 20 | 25 | 20 | ||||||||||||||
| Distribution | 90 | 125 | 120 | ||||||||||||||
| Utility Support | 20 | 15 | 10 | ||||||||||||||
| Total | $140 | $180 | $155 | ||||||||||||||
In addition to the planned spending in the table above, Entergy New Orleans also expects to pay for $25 million of capital investments in 2021 related to Hurricane Zeta restoration work that have been accrued as of December 31, 2020.
Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| 2021 | 2022-2023 | 2024-2025 | After 2025 | Total | |||||||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||||||||
| Long-term debt (a) | $37 | $240 | $119 | $686 | $1,082 | ||||||||||||||||||||||||
| Operating leases (b) | $2 | $2 | $1 | $1 | $6 | ||||||||||||||||||||||||
| Finance leases (b) | $1 | $1 | $1 | $1 | $4 | ||||||||||||||||||||||||
| Purchase obligations (c) | $217 | $438 | $419 | $3,287 | $4,361 | ||||||||||||||||||||||||
(a)Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.
(b)Lease obligations are discussed in Note 10 to the financial statements.
(c)Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy New Orleans, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements.
In addition to the contractual obligations given above, Entergy New Orleans currently expects to contribute approximately $5.4 million to its qualified pension plan and approximately $175 thousand to other postretirement health care and life insurance plans in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy New Orleans has $187.6 million of unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy New Orleans includes transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; software and security; 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, environmental compliance, business opportunities, market volatility, economic trends, business restructuring,
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changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the financial statements.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy New Orleans pays distributions from its earnings at a percentage determined monthly.
Gas Infrastructure Rebuild Plan
In September 2016, Entergy New Orleans submitted to the City Council a request for authorization for Entergy New Orleans to proceed with annual incremental capital funding of $12.5 million for its gas infrastructure rebuild plan, which would replace all of Entergy New Orleans’s low pressure cast iron, steel, and vintage plastic pipe over a ten-year period commencing in 2017. Entergy New Orleans also proposed that recovery of the investment to fund its gas infrastructure replacement plan be determined in connection with its next base rate case. The City Council authorized Entergy New Orleans to proceed with its replacement plans and established a schedule for proceedings in advance of the rate case intended to provide an opportunity for evaluation of the gas infrastructure plan that would best serve the public interest and the effect on customers of the approval of any such plan. In the course of that proceeding, the City Council’s advisors submitted pre-filed testimony recommending that Entergy New Orleans be allowed to continue with its condition-based approach to gas pipeline replacement to replace approximately 238 miles of low pressure pipe at a rate of approximately 25 miles per year. The City Council’s advisors also recommended that Entergy New Orleans be required to adhere to certain reporting requirements and recognized the need to address the sustained level of investment in gas infrastructure on customer bills. In September 2017, Entergy New Orleans filed rebuttal testimony suggesting that its recovery of future investment and customer effects would be addressed in the rate case that Entergy New Orleans was required to file in July 2018. The procedural schedule was suspended in order to allow for resolution in the rate case proceeding. As a result of the rate case, the City Council approved the planned gas rebuild expenditures through 2019, but rejected Entergy New Orleans’s proposed gas infrastructure rider. In April 2020, Entergy New Orleans submitted its gas infrastructure rebuild plan to the City Council, which maintained the previously proposed timeline and cost estimates, but included measures to spread out the cost impact to customers of the program.
Renewables
In July 2018, Entergy New Orleans filed an application with the City Council requesting approval of three utility-scale solar projects totaling 90 MW. If approved, the resource additions will allow Entergy New Orleans to make significant progress towards meeting its voluntary commitment to the City Council to add up to 100 MW of renewable energy resources. The three projects include constructing a self-build solar plant in Orleans Parish with an output of 20 MW, acquiring a 50 MW solar facility in Washington Parish through a build-own-transfer acquisition, and procuring 20 MW of solar power from a project to be built in St. James Parish through a power purchase agreement. In December 2018 the City Council advisors requested that Entergy New Orleans pursue alternative deal structures for the Washington Parish project and attempt to reduce costs for the 20 MW New Orleans Solar Station. As a result of settlement discussions, in March 2019, Entergy New Orleans revised its application to convert the build-own transfer acquisition of the 50 MW facility in Washington Parish to a power purchase agreement. In June 2019 the parties to the proceeding executed a stipulated settlement term sheet, which recommends that the City Council approve Entergy New Orleans’s revised application as to all three projects. In July 2019 the City Council approved the stipulated settlement. Commercial operation of the 20 MW New Orleans Solar Station commenced in December 2020. Entergy New Orleans expects to begin receiving power under the 50 MW Iris Solar and the 20 MW St. James Solar power purchase agreements by third quarter 2021.
Sources of Capital
Entergy New Orleans’s sources to meet its capital requirements include:
•internally generated funds;
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•cash on hand;
•storm reserve escrow accounts;
•debt and preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy New Orleans may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
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 indentures and other agreements. Entergy New Orleans has sufficient capacity under these tests to meet its foreseeable capital needs.
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.
| 2020 | 2019 | 2018 | 2017 | |||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| ($10,190) | $5,191 | $22,016 | $12,723 | |||||||||||||||||
See Note 4 to the financial statements for a description of the money pool.
Entergy New Orleans has a credit facility in the amount of $25 million scheduled to expire in November 2021. 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, 2020, there were no cash borrowings and an $0.8 million letter of credit outstanding under the 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, 2020, a $1 million letter of credit was outstanding under Entergy New Orleans’s 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 July 2022 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 July 2022.
State and Local Rate Regulation
The rates that Entergy New Orleans charges for electricity and natural gas significantly influence its financial position, results of operations, and liquidity. Entergy New Orleans is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the City Council, is primarily responsible for approval of the rates charged to customers.
Retail Rates
Energy Efficiency
In December 2019, Entergy New Orleans filed an application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022. Entergy New Orleans proposed to recover the costs of the program through mechanisms previously approved by the City Council
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or through the energy efficiency cost recovery rider, which was approved in the 2018 combined rate case resolution. In January 2020 the City Council’s advisors recommended that, beginning with Program Year 10, the City Council allow Entergy New Orleans to earn a utility performance incentive of 7% of Energy Smart costs for each year in which Entergy New Orleans achieves 100% of the City Council’s savings targets for Energy Smart. In February 2020 the City Council approved Entergy New Orleans’s application.
2018 Base Rate Case
In September 2018, Entergy New Orleans filed an electric and gas base rate case with the City Council. The filing requested a 10.5% return on equity for electric operations with opportunity to earn a 10.75% return on equity through a performance adder provision of the electric formula rate plan in subsequent years under a formula rate plan and requested a 10.75% return on equity for gas operations. The proposed electric rates in the revised filing reflect a net reduction of $20.3 million. The reduction in electric rates includes a base rate increase of $135.2 million, of which $131.5 million is associated with moving costs currently collected through fuel and other riders into base rates, plus a request for an advanced metering surcharge to recover $7.1 million associated with advanced metering infrastructure, offset by a net decrease of $31.1 million related to fuel and other riders. The filing also included a proposed gas rate decrease of $142 thousand. Entergy New Orleans’s rates reflected the inclusion of federal income tax reductions due to the Tax Act and the provisions of a previously-approved agreement in principle determining how the benefits of the Tax Act would flow. Entergy New Orleans included cost of service studies for electric and gas operations for the twelve months ended December 31, 2017 and the projected twelve months ending December 31, 2018. In addition, Entergy New Orleans included capital additions expected to be placed into service for the period through December 31, 2019. Entergy New Orleans based its request for a change in rates on the projected twelve months ending December 31, 2018.
The filing’s major provisions included: (1) a new electric rate structure, which realigns the revenue requirement associated with capacity and long-term service agreement expense from certain existing riders to base revenue, provides for the recovery of the cost of advanced metering infrastructure, and partially blends rates for Entergy New Orleans’s customers residing in Algiers with customers residing in the remainder of Orleans Parish through a three-year phase-in; (2) contemporaneous cost recovery riders for investments in energy efficiency/demand response, incremental changes in capacity/long-term service agreement costs, grid modernization investment, and gas infrastructure replacement investment; and (3) formula rate plans for both electric and gas operations. In February 2019 the City Council’s advisors and several intervenors filed testimony in response to Entergy New Orleans’s application. The City Council’s advisors recommended, among other things, overall rate reductions of approximately $33 million in electric rates and $3.8 million in gas rates. Certain intervenors recommended overall rate reductions of up to approximately $49 million in electric rates and $5 million in gas rates. An evidentiary hearing was held in June 2019, and the record and post-hearing briefs were submitted in July 2019.
In October 2019 the City Council’s Utility Committee approved a resolution for a change in electric and gas rates for consideration by the full City Council that included a 9.35% return on common equity, an equity ratio of the lesser of 50% or Entergy New Orleans’s actual equity ratio, and a total reduction in revenues that Entergy New Orleans initially estimated to be approximately $39 million ($36 million electric; $3 million gas). At its November 7, 2019 meeting, the full City Council approved the resolution that had previously been approved by the City Council’s Utility Committee. Based on the approved resolution, in the fourth quarter 2019 Entergy New Orleans recorded an accrual of $10 million that reflects the estimate of the revenue billed in 2019 to be refunded to customers in 2020 based on an August 2019 effective date for the rate decrease. Entergy New Orleans also recorded a total of $12 million in regulatory assets for rate case costs and information technology costs associated with integrating Algiers customers with Entergy New Orleans’s legacy system and records. Entergy New Orleans will also be allowed to recover $10 million of retired general plant costs over a 20-year period.
The resolution directed Entergy New Orleans to submit a compliance filing within 30 days of the date of the resolution to facilitate the eventual implementation of rates, including all necessary calculations and conforming rate schedules and riders. The electric formula rate plan rider includes, among other things, 1) a provision for
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forward-looking adjustments to include known and measurable changes realized up to 12 months after the evaluation period; 2) a decoupling mechanism; and 3) recognition that Entergy New Orleans is authorized to make an in-service adjustment to the formula rate plan to include the non-fuel cost of the New Orleans Power Station in rates, unless the two pending appeals in the New Orleans Power Station proceeding have not concluded. Under this circumstance, Entergy New Orleans shall be permitted to defer the New Orleans Power Station non-fuel costs, including the cost of capital, until Entergy New Orleans commences non-fuel cost recovery. After taking into account the requirements for submission of the compliance filing, the total annual revenue requirement reduction required by the resolution was refined to approximately $45 million ($42 million electric, including $29 million in rider reductions; $3 million gas). In January 2020 the City Council’s advisors found that the rates calculated by Entergy New Orleans and reflected in the December 2019 compliance filing should be implemented, except with respect to the City Council-approved energy efficiency cost recovery rider, which rider calculation should take into account events to be determined by the City Council in the future. Also in response to the resolution, Entergy New Orleans filed timely a petition for appeal and judicial review and for stay of or injunctive relief alleging that the resolution is unlawful in failing to produce just and reasonable rates. A hearing on the requested injunction was scheduled in Civil District Court for February 2020, but by joint motion of the City Council and Entergy New Orleans, the Civil District Court issued an order for a limited remand to the City Council to consider a potential agreement in principle/stipulation at its February 20, 2020 meeting. On February 17, 2020, Entergy New Orleans filed with the City Council an agreement in principle between Entergy New Orleans and the City Council’s advisors. On February 20, 2020, the City Council voted to approve the proposed agreement in principle and issued a resolution modifying the required treatment of certain accumulated deferred income taxes. As a result of the agreement in principle, the total annual revenue requirement reduction will be approximately $45 million ($42 million electric, including $29 million in rider reductions; and $3 million gas). Entergy New Orleans fully implemented the new rates in April 2020. In January 2021, pursuant to the agreement in principle approved by the City Council in October 2020, Entergy New Orleans filed with Civil District Court a motion seeking to dismiss its petition for judicial review of the City Council’s resolution in the 2018 combined rate case.
Commercial operation of the New Orleans Power Station commenced in May 2020. In accordance with the City Council resolution issued in the 2018 base rate case proceeding, Entergy New Orleans had been deferring the New Orleans Power Station non-fuel costs pending the conclusion of the appellate proceedings. In October 2020 the Louisiana Supreme Court denied all writ applications relating to the New Orleans Power Station. With those denials, Entergy New Orleans began recovering New Orleans Power Station costs in rates in November 2020. As of December 31, 2020 the regulatory asset for the deferral of New Orleans Power Station non-fuel costs was $5 million. Entergy New Orleans is recovering the costs over a five-year period that began in November 2020. In December 2020 the Alliance for Affordable Energy and Sierra Club filed a joint motion with the City Council to institute a prudence review to investigate the costs of the New Orleans Power Station. On January 28, 2021, the City Council passed a resolution giving parties 30 days to respond to the motion. Entergy New Orleans plans to respond to the motion.
2020 Formula Rate Plan Filing
Entergy New Orleans’s first annual filing under the three-year formula rate plan approved by the City Council in November 2019 was originally due to be filed in April 2020. The authorized return on equity under the approved three-year formula rate plan is 9.35% for both electric and gas operations. The City Council approved several extensions of the deadline to allow additional time to assess the effects of the COVID-19 pandemic on the New Orleans community, Entergy New Orleans customers, and Entergy New Orleans itself. In October 2020 the City Council approved an agreement in principle filed by Entergy New Orleans that results in Entergy New Orleans foregoing its 2020 formula rate plan filing and shifting the three-year formula rate plan to filings in 2021, 2022, and 2023. Key provisions of the agreement in principle include: changing the lower of actual equity ratio or 50% equity ratio approved in the rate case to a hypothetical capital structure of 51% equity and 49% debt for the duration of the three-year formula rate plan; changing the 2% depreciation rate for the New Orleans Power Station approved in the rate case to 3%; retention of over-recovery of $2.2 million in rider revenues; recovery of $1.4 million of certain rate
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case expenses outside of the earnings band; recovery of the New Orleans Solar Station costs upon commercial operation; and Entergy New Orleans’s dismissal of its 2018 rate case appeal.
COVID-19 Orders
In March 2020, Entergy New Orleans voluntarily suspended customer disconnections for non-payment of utility bills through May 2020. Subsequently, the City Council ordered that the moratorium be extended to August 1, 2020. In May 2020 the City Council issued an accounting order authorizing Entergy New Orleans to establish a regulatory asset for incremental COVID-19-related expenses. In January 2021, Entergy New Orleans resumed disconnecting service to commercial and small business customers with past-due balances that have not made payment arrangements. In February 2021 the City Council adopted a resolution suspending residential customer disconnections for non-payment of utility bills and suspending the assessment and accumulation of late fees on residential customers with past-due balances through May 15, 2021. As of December 31, 2020, Entergy New Orleans recorded a regulatory asset of $14.3 million for costs associated with the COVID-19 pandemic.
In June 2020 the City Council established the City Council Cares Program and directed Entergy New Orleans to use the approximately $7 million refund received from the Entergy Arkansas opportunity sales FERC proceeding, currently being held in escrow, and approximately $15 million of non-securitized storm reserves to fund this program, which is intended to provide temporary bill relief to customers who become unemployed during the COVID-19 pandemic. The program became effective July 1, 2020, and offers qualifying residential customers bill credits of $100 per month for up to four months, for a maximum of $400 in residential customer bill credits. As of December 31, 2020, credits of $3.4 million have been applied to customer bills under the City Council Cares Program.
Fuel and Purchased Power Cost Recovery
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
Show Cause Order
In July 2016 the City Council approved the issuance of a show cause order, which directed Entergy New Orleans to make a filing on or before September 29, 2016 to demonstrate the reasonableness of its actions or positions with regard to certain issues in four existing dockets that relate to Entergy New Orleans’s: (i) storm hardening proposal; (ii) 2015 integrated resource plan; (iii) gas infrastructure rebuild proposal; and (iv) proposed sizing of the New Orleans Power Station and its community outreach prior to the filing. In September 2016, Entergy New Orleans filed its response to the City Council’s show cause order. The City Council has not established any further procedural schedule with regard to this proceeding.
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
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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 has 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 opens 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 and 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 disagrees 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. Although the City Council evidentiary record has been lodged with the Civil District count, the court has not yet established a briefing schedule.
Renewable Portfolio Standard Rulemaking
In March 2019 the City Council initiated a rulemaking proceeding to consider whether to establish a renewable portfolio standard. The rulemaking will consider, among other issues, whether to adopt a renewable portfolio standard, whether such standard should be voluntary or mandatory, what kinds of technologies should qualify for inclusion in the rules, what level, if any, of renewable generation should be required, and whether penalties are an appropriate component of the proposed rules. Parties to the proceeding submitted initial comments in June 2019 and reply comments in July 2019. Entergy New Orleans recommends that the City Council adopt a voluntary clean energy standard of 70% of generation being clean energy by 2030, as so defined, which, in addition to renewable generation, would include nuclear, beneficial electrification, and demand-side management as compliant technologies. Several other industry leaders, academic researchers, and environmental advocates filed comments also supporting a clean energy standard. Other parties, including many representatives of the solar and wind industry, are recommending mandatory, renewables-only requirements of up to 100% renewable resources by 2040. In September 2019 the City Council advisors issued a report and recommendations, which also put forth three alternative rules for comment from the parties. Comments were submitted in October 2019 and replies were filed in November 2019. In March 2020 the City Council’s Utility Committee recommended a resolution for approval by the City Council that directed the City Council advisors to work toward development of a rule for enacting a Renewable and Clean Portfolio Standard. The four components of the Renewable and Clean Portfolio Standard that the City Council expressed a desire to implement are: (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 first technical meeting of the parties occurred in June 2020; a second technical meeting occurred in July 2020. In August 2020 the City Council advisors issued a final draft of the rules for review and comment from the parties before final rules are proposed for consideration by the City Council. Entergy New Orleans filed comments in September and October 2020. A City Council decision is expected in the first quarter 2021.
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Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Nuclear Matters
See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.
Environmental Risks
Entergy New Orleans’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous solid wastes, and other environmental matters. Management believes that Entergy New Orleans is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy New Orleans’s financial statements in conformity with generally accepted accounting principles 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 policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of Entergy New Orleans’s financial position or results of operations.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Impairment of Long-lived Assets
See “Impairment of Long-lived Assets” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy New Orleans’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy
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Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| Actuarial Assumption | Change in Assumption | Impact on 2021 Qualified Pension Cost | Impact on 2020 Projected Qualified Benefit Obligation | |||||||||||||||||
| Increase/(Decrease) | ||||||||||||||||||||
| Discount rate | (0.25%) | $303 | $5,858 | |||||||||||||||||
| Rate of return on plan assets | (0.25%) | $388 | $— | |||||||||||||||||
| Rate of increase in compensation | 0.25% | $225 | $1,060 | |||||||||||||||||
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| Actuarial Assumption | Change in Assumption | Impact on 2021 Postretirement Benefit Cost | Impact on 2020 Accumulated Postretirement Benefit Obligation | |||||||||||||||||
| Increase/(Decrease) | ||||||||||||||||||||
| Discount rate | (0.25%) | $76 | $893 | |||||||||||||||||
| Health care cost trend | 0.25% | $82 | $571 | |||||||||||||||||
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy New Orleans in 2020 was $6 million. Entergy New Orleans anticipates 2021 qualified pension cost to be $5.9 million. Entergy New Orleans contributed $4.6 million to its qualified pension plans in 2020 and estimates 2021 pension contributions will be approximately $5.4 million, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021.
Total postretirement health care and life insurance benefit income for Entergy New Orleans in 2020 was $4.9 million. Entergy New Orleans expects 2021 postretirement health care and life insurance benefit income of approximately $6.4 million. Entergy New Orleans contributed $641 thousand to its other postretirement plans in 2020 and estimates 2021 contributions will be approximately $175 thousand.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the member and Board of Directors of
Entergy New Orleans, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy New Orleans, LLC and Subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of income, cash flows, and changes in member’s equity (pages 402 through 406 and applicable items in pages 51 through 238), for each of the three years in the period ended December 31, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters— Entergy New Orleans, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
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
400
rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
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 significant 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, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the City Council and the FERC 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 costs incurred as property, plant, and equipment and deferred as 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 property, plant, and equipment; 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 and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information 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 the 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, including the base rate case filing, 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.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2021
We have served as the Company’s auditor since 2001.
401
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES | ||||||||||||||||||||
| CONSOLIDATED INCOME STATEMENTS | ||||||||||||||||||||
| For the Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| OPERATING REVENUES | ||||||||||||||||||||
| Electric | $560,632 | $594,417 | $624,733 | |||||||||||||||||
| Natural gas | 73,209 | 91,806 | 92,657 | |||||||||||||||||
| TOTAL | 633,841 | 686,223 | 717,390 | |||||||||||||||||
| OPERATING EXPENSES | ||||||||||||||||||||
| Operation and Maintenance: | ||||||||||||||||||||
| Fuel, fuel-related expenses, and gas purchased for resale | 76,781 | 105,217 | 114,787 | |||||||||||||||||
| Purchased power | 243,572 | 258,306 | 270,634 | |||||||||||||||||
| Other operation and maintenance | 125,756 | 121,057 | 124,293 | |||||||||||||||||
| Taxes other than income taxes | 57,454 | 55,270 | 56,141 | |||||||||||||||||
| Depreciation and amortization | 64,012 | 56,072 | 55,930 | |||||||||||||||||
| Other regulatory charges - net | 1,854 | 21,616 | 21,413 | |||||||||||||||||
| TOTAL | 569,429 | 617,538 | 643,198 | |||||||||||||||||
| OPERATING INCOME | 64,412 | 68,685 | 74,192 | |||||||||||||||||
| OTHER INCOME (DEDUCTIONS) | ||||||||||||||||||||
| Allowance for equity funds used during construction | 6,339 | 9,941 | 5,941 | |||||||||||||||||
| Interest and investment income | 120 | 428 | 604 | |||||||||||||||||
| Miscellaneous - net | 316 | (6,038) | (10,444) | |||||||||||||||||
| TOTAL | 6,775 | 4,331 | (3,899) | |||||||||||||||||
| INTEREST EXPENSE | ||||||||||||||||||||
| Interest expense | 29,105 | 24,463 | 21,772 | |||||||||||||||||
| Allowance for borrowed funds used during construction | (3,049) | (4,262) | (2,195) | |||||||||||||||||
| TOTAL | 26,056 | 20,201 | 19,577 | |||||||||||||||||
| INCOME BEFORE INCOME TAXES | 45,131 | 52,815 | 50,716 | |||||||||||||||||
| Income taxes | (4,207) | 186 | (2,436) | |||||||||||||||||
| NET INCOME | $49,338 | $52,629 | $53,152 | |||||||||||||||||
| See Notes to Financial Statements. | ||||||||||||||||||||
402
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES | ||||||||||||||||||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||||||||||||||||
| For the Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| OPERATING ACTIVITIES | ||||||||||||||||||||
| Net income | $49,338 | $52,629 | $53,152 | |||||||||||||||||
| Adjustments to reconcile net income to net cash flow provided by operating activities: | ||||||||||||||||||||
| Depreciation and amortization | 64,012 | 56,072 | 55,930 | |||||||||||||||||
| Deferred income taxes, investment tax credits, and non-current taxes accrued | 3,938 | 21,350 | 24,548 | |||||||||||||||||
| Changes in assets and liabilities: | ||||||||||||||||||||
| Receivables | (12,003) | (9,372) | 15,724 | |||||||||||||||||
| Fuel inventory | (58) | (387) | 357 | |||||||||||||||||
| Accounts payable | 5,582 | (5,571) | (385) | |||||||||||||||||
| Taxes accrued | 398 | 234 | 30,547 | |||||||||||||||||
| Interest accrued | 1,179 | 550 | 879 | |||||||||||||||||
| Deferred fuel costs | (7,048) | 3,630 | (6,486) | |||||||||||||||||
| Other working capital accounts | (13,156) | 5,021 | 4,146 | |||||||||||||||||
| Provisions for estimated losses | 1,356 | 1,948 | 1,511 | |||||||||||||||||
| Other regulatory assets | (7,427) | (29,567) | 21,637 | |||||||||||||||||
| Other regulatory liabilities | (4,728) | (22,105) | (28,459) | |||||||||||||||||
| Pension and other postretirement liabilities | (14,063) | (14,624) | (15,134) | |||||||||||||||||
| Other assets and liabilities | (3,296) | 55,796 | 13,811 | |||||||||||||||||
| Net cash flow provided by operating activities | 64,024 | 115,604 | 171,778 | |||||||||||||||||
| INVESTING ACTIVITIES | ||||||||||||||||||||
| Construction expenditures | (228,983) | (229,560) | (202,186) | |||||||||||||||||
| Allowance for equity funds used during construction | 6,339 | 9,941 | 5,941 | |||||||||||||||||
| Payment for purchase of assets | (1,584) | — | — | |||||||||||||||||
| Changes in money pool receivable - net | 5,191 | 16,825 | (9,293) | |||||||||||||||||
| Payments to storm reserve escrow account | (433) | (1,752) | (1,311) | |||||||||||||||||
| Receipts from storm reserve escrow account | — | — | 3 | |||||||||||||||||
| Changes in securitization account | (1,375) | 236 | (770) | |||||||||||||||||
| Net cash flow used in investing activities | (220,845) | (204,310) | (207,616) | |||||||||||||||||
| FINANCING ACTIVITIES | ||||||||||||||||||||
| Proceeds from the issuance of long-term debt | 138,925 | 113,876 | 59,234 | |||||||||||||||||
| Retirement of long-term debt | (56,593) | (35,376) | (11,042) | |||||||||||||||||
| Repayment of long-term payable due to associated company | (1,838) | (1,979) | (2,077) | |||||||||||||||||
| Capital contributions from parent | 60,000 | — | — | |||||||||||||||||
| Changes in money pool payable - net | 10,190 | — | — | |||||||||||||||||
| Common equity distributions paid | — | — | (23,750) | |||||||||||||||||
| Other | 146 | (1,475) | 409 | |||||||||||||||||
| Net cash flow provided by financing activities | 150,830 | 75,046 | 22,774 | |||||||||||||||||
| Net decrease in cash and cash equivalents | (5,991) | (13,660) | (13,064) | |||||||||||||||||
| Cash and cash equivalents at beginning of period | 6,017 | 19,677 | 32,741 | |||||||||||||||||
| Cash and cash equivalents at end of period | $26 | $6,017 | $19,677 | |||||||||||||||||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||||||||||||||||
| Cash paid (received) during the period for: | ||||||||||||||||||||
| Interest - net of amount capitalized | $26,673 | $22,873 | $19,840 | |||||||||||||||||
| Income taxes | $3,392 | ($5,310) | ($39,781) | |||||||||||||||||
| See Notes to Financial Statements. | ||||||||||||||||||||
403
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES | ||||||||||||||
| CONSOLIDATED BALANCE SHEETS | ||||||||||||||
| ASSETS | ||||||||||||||
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| CURRENT ASSETS | ||||||||||||||
| Cash and cash equivalents | ||||||||||||||
| Cash | $26 | $26 | ||||||||||||
| Temporary cash investments | — | 5,991 | ||||||||||||
| Total cash and cash equivalents | 26 | 6,017 | ||||||||||||
| Securitization recovery trust account | 3,364 | 1,989 | ||||||||||||
| Accounts receivable: | ||||||||||||||
| Customer | 70,694 | 48,265 | ||||||||||||
| Allowance for doubtful accounts | (17,430) | (3,226) | ||||||||||||
| Associated companies | 2,381 | 6,280 | ||||||||||||
| Other | 4,248 | 7,378 | ||||||||||||
| Accrued unbilled revenues | 31,069 | 25,453 | ||||||||||||
| Total accounts receivable | 90,962 | 84,150 | ||||||||||||
| Deferred fuel costs | 2,130 | — | ||||||||||||
| Fuel inventory - at average cost | 1,978 | 1,920 | ||||||||||||
| Materials and supplies - at average cost | 16,550 | 13,522 | ||||||||||||
| Prepayments and other | 3,715 | 4,846 | ||||||||||||
| TOTAL | 118,725 | 112,444 | ||||||||||||
| OTHER PROPERTY AND INVESTMENTS | ||||||||||||||
| Non-utility property at cost (less accumulated depreciation) | 1,016 | 1,016 | ||||||||||||
| Storm reserve escrow account | 83,038 | 82,605 | ||||||||||||
| TOTAL | 84,054 | 83,621 | ||||||||||||
| UTILITY PLANT | ||||||||||||||
| Electric | 1,821,638 | 1,467,215 | ||||||||||||
| Natural gas | 348,024 | 311,432 | ||||||||||||
| Construction work in progress | 12,460 | 201,829 | ||||||||||||
| TOTAL UTILITY PLANT | 2,182,122 | 1,980,476 | ||||||||||||
| Less - accumulated depreciation and amortization | 740,796 | 715,406 | ||||||||||||
| UTILITY PLANT - NET | 1,441,326 | 1,265,070 | ||||||||||||
| DEFERRED DEBITS AND OTHER ASSETS | ||||||||||||||
| Regulatory assets: | ||||||||||||||
| Deferred fuel costs | 4,080 | 4,080 | ||||||||||||
Other regulatory assets (includes securitization property of $35,559 as of December 31, 2020 and $49,542 as of December 31, 2019) | 266,790 | 259,363 | ||||||||||||
| Other | 23,931 | 10,720 | ||||||||||||
| TOTAL | 294,801 | 274,163 | ||||||||||||
| TOTAL ASSETS | $1,938,906 | $1,735,298 | ||||||||||||
| See Notes to Financial Statements. | ||||||||||||||
404
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES | ||||||||||||||
| CONSOLIDATED BALANCE SHEETS | ||||||||||||||
| LIABILITIES AND EQUITY | ||||||||||||||
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| CURRENT LIABILITIES | ||||||||||||||
| Currently maturing long-term debt | $— | $25,000 | ||||||||||||
| Payable due to associated company | 1,618 | 1,838 | ||||||||||||
| Accounts payable: | ||||||||||||||
| Associated companies | 54,234 | 43,222 | ||||||||||||
| Other | 60,766 | 43,963 | ||||||||||||
| Customer deposits | 27,912 | 28,493 | ||||||||||||
| Taxes accrued | 4,700 | 4,302 | ||||||||||||
| Interest accrued | 8,095 | 6,916 | ||||||||||||
| Deferred fuel costs | — | 4,918 | ||||||||||||
| Current portion of unprotected excess accumulated deferred income taxes | 3,296 | 9,470 | ||||||||||||
| Other | 5,462 | 15,827 | ||||||||||||
| TOTAL CURRENT LIABILITIES | 166,083 | 183,949 | ||||||||||||
| NON-CURRENT LIABILITIES | ||||||||||||||
| Accumulated deferred income taxes and taxes accrued | 338,714 | 354,536 | ||||||||||||
| Accumulated deferred investment tax credits | 16,095 | 2,131 | ||||||||||||
| Regulatory liability for income taxes - net | 55,675 | 49,090 | ||||||||||||
| Asset retirement cost liabilities | 3,768 | 3,522 | ||||||||||||
| Accumulated provisions | 89,898 | 88,542 | ||||||||||||
Long-term debt (includes securitization bonds of $41,291 as of December 31, 2020 and $52,641 as of December 31, 2019) | 629,704 | 521,539 | ||||||||||||
| Long-term payable due to associated company | 10,911 | 12,529 | ||||||||||||
| Other | 21,141 | 21,881 | ||||||||||||
| TOTAL NON-CURRENT LIABILITIES | 1,165,906 | 1,053,770 | ||||||||||||
| Commitments and Contingencies | ||||||||||||||
| EQUITY | ||||||||||||||
| Member's equity | 606,917 | 497,579 | ||||||||||||
| TOTAL | 606,917 | 497,579 | ||||||||||||
| TOTAL LIABILITIES AND EQUITY | $1,938,906 | $1,735,298 | ||||||||||||
| See Notes to Financial Statements. | ||||||||||||||
405
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES | ||||||||
| CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY | ||||||||
| For the Years Ended December 31, 2020, 2019, and 2018 | ||||||||
Member’s Equity | ||||||||
| (In Thousands) | ||||||||
| Balance at December 31, 2017 | $415,548 | |||||||
| Net income | 53,152 | |||||||
| Common equity distributions | (23,750) | |||||||
| Balance at December 31, 2018 | $444,950 | |||||||
| Net income | 52,629 | |||||||
| Balance at December 31, 2019 | $497,579 | |||||||
| Net income | 49,338 | |||||||
| Capital contributions from parent | 60,000 | |||||||
| Balance at December 31, 2020 | $606,917 | |||||||
| See Notes to Financial Statements. | ||||||||
406
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES | |||||||||||||||||||||||||||||
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2017 | 2016 | |||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||
| Operating revenues | $633,841 | $686,223 | $717,390 | $716,070 | $665,463 | ||||||||||||||||||||||||
| Net income | $49,338 | $52,629 | $53,152 | $44,553 | $48,849 | ||||||||||||||||||||||||
| Total assets | $1,938,906 | $1,735,298 | $1,576,588 | $1,497,836 | $1,494,569 | ||||||||||||||||||||||||
| Long-term obligations (a) | $640,615 | $534,068 | $481,725 | $434,793 | $466,670 | ||||||||||||||||||||||||
| (a) Includes long-term debt (including the long-term payable to associated company and excluding currently maturing debt) and preferred stock without sinking fund. | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2017 | 2016 | |||||||||||||||||||||||||
| (Dollars In Millions) | |||||||||||||||||||||||||||||
| Electric Operating Revenues: | |||||||||||||||||||||||||||||
| Residential | $244 | $245 | $262 | $250 | $231 | ||||||||||||||||||||||||
| Commercial | 179 | 202 | 217 | 228 | 206 | ||||||||||||||||||||||||
| Industrial | 24 | 32 | 33 | 36 | 33 | ||||||||||||||||||||||||
| Governmental | 60 | 71 | 72 | 77 | 69 | ||||||||||||||||||||||||
| Total billed retail | 507 | 550 | 584 | 591 | 539 | ||||||||||||||||||||||||
| Sales for resale: | |||||||||||||||||||||||||||||
| Associated companies | — | — | — | — | 30 | ||||||||||||||||||||||||
| Non-associated companies | 33 | 38 | 30 | 29 | 3 | ||||||||||||||||||||||||
| Other | 21 | 6 | 11 | 12 | 15 | ||||||||||||||||||||||||
| Total | $561 | $594 | $625 | $632 | $587 | ||||||||||||||||||||||||
| Billed Electric Energy Sales (GWh): | |||||||||||||||||||||||||||||
| Residential | 2,294 | 2,353 | 2,401 | 2,155 | 2,231 | ||||||||||||||||||||||||
| Commercial | 1,975 | 2,215 | 2,270 | 2,248 | 2,268 | ||||||||||||||||||||||||
| Industrial | 423 | 438 | 448 | 429 | 441 | ||||||||||||||||||||||||
| Governmental | 755 | 815 | 795 | 790 | 794 | ||||||||||||||||||||||||
| Total retail | 5,447 | 5,821 | 5,914 | 5,622 | 5,734 | ||||||||||||||||||||||||
| Sales for resale: | |||||||||||||||||||||||||||||
| Associated companies | — | — | — | — | 1,071 | ||||||||||||||||||||||||
| Non-associated companies | 1,969 | 1,961 | 1,484 | 1,703 | 141 | ||||||||||||||||||||||||
| Total | 7,416 | 7,782 | 7,398 | 7,325 | 6,946 | ||||||||||||||||||||||||
407
ENTERGY TEXAS, INC. AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
Hurricane Laura and Hurricane Delta
In August 2020 and October 2020, Hurricane Laura and Hurricane Delta caused extensive damage to Entergy Texas’s service area. The storm resulted in widespread power outages, significant damage primarily to distribution and transmission infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair and/or replacement of Entergy Texas’s electric facilities damaged by Hurricane Laura and Hurricane Delta are currently estimated to be approximately $300 million, including $245 million in capital costs and approximately $55 million in non-capital costs. Entergy Texas is considering all available avenues to recover storm-related costs from Hurricanes Laura and Hurricane Delta, including securitization. Storm cost recovery or financing will be subject to review by applicable regulatory authorities.
Entergy Texas recorded accounts payable and corresponding construction work in progress and regulatory assets for the estimated costs incurred that were necessary to return customers to service. Entergy Texas recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. There are well established mechanisms and precedent for addressing these catastrophic events and providing for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles. Because Entergy Texas has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy Texas is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy Texas’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $12 million. Natural gas purchases for Entergy Texas for February 1st through 25th, 2021 are approximately $155 million compared to natural gas purchases for February 2020 of $10 million.
Results of Operations
2020 Compared to 2019
Net Income
Net income increased $55.7 million primarily due to higher retail electric price, higher other income, lower other operation and maintenance expenses, a lower effective income tax rate, after excluding the effect of the return of unprotected excess accumulated deferred income taxes to customers which is offset in income taxes, and higher volume/weather. The increase was partially offset by higher depreciation and amortization expenses.
408
Operating Revenues
Following is an analysis of the change in operating revenue comparing 2020 to 2019.
| Amount | |||||
| (In Millions) | |||||
| 2019 operating revenues | $1,489.0 | ||||
| Fuel, rider, and other revenues that do not significantly affect net income | 4.4 | ||||
| Return of unprotected excess accumulated deferred income taxes to customers | 58.6 | ||||
| Retail electric price | 28.1 | ||||
| Volume/weather | 7.0 | ||||
| 2020 operating revenues | $1,587.1 | ||||
Entergy Texas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The 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 2020, $28.8 million was returned to customers as compared to $87.4 million in 2019. There is no effect on net income as the reduction in operating revenues is offset by a reduction 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 the transmission cost recovery factor rider effective January 2020 and an increase in the distribution cost recovery factor rider effective October 2020. See Note 2 to the financial statements for further discussion of the transmission and distribution cost recovery factor rider filings.
The volume/weather variance is primarily due to an increase in usage during the unbilled sales period and an increase in billed residential usage as a result of the COVID-19 pandemic, partially offset by the effect of less favorable weather on residential sales and decreased commercial and industrial usage as a result of the COVID-19 pandemic. The decrease in industrial usage is partially offset by an increase in demand from expansion projects, primarily in the chemicals and transportation industries. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the COVID-19 pandemic.
Other Income Statement Variances
Other operation and maintenance expenses decreased primarily due to:
•a decrease of $7.7 million in non-nuclear generation expenses primarily due to a lower scope of work performed during plant outages in 2020 as compared to the same period in 2019, including a delay in plant outages as a result of the COVID-19 pandemic; and
•a decrease of $3.7 million primarily due to contract costs in 2019 related to initiatives to explore new customer products and services.
The decrease was partially offset by $2.3 million of transaction costs incurred in connection with the purchase of the Hardin County Peaking Facility and the partial sale of Montgomery County Power Station.
409
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other income increased primarily due to an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2020, including the Montgomery County Power Station project.
The effective income tax rates were 1.4% for 2020 and (51.1%) for 2019. The difference in the effective income tax rates versus the federal statutory rate of 21% for 2020 and 2019 was primarily due to the amortization of excess accumulated deferred income taxes. See Notes 2 and 3 to the financial statements for a discussion of the effects and regulatory activity regarding the Tax Cuts and Jobs Act. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.
2019 Compared to 2018
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, 2019, filed with the SEC on February 21, 2020, for discussion of results of operations for 2019 compared to 2018.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, and 2018 were as follows:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Thousands) | |||||||||||||||||
| Cash and cash equivalents at beginning of period | $12,929 | $56 | $115,513 | ||||||||||||||
| Net cash provided by (used in): | |||||||||||||||||
| Operating activities | 375,325 | 286,739 | 331,753 | ||||||||||||||
| Investing activities | (848,648) | (878,280) | (395,973) | ||||||||||||||
| Financing activities | 708,990 | 604,414 | (51,237) | ||||||||||||||
| Net increase (decrease) in cash and cash equivalents | 235,667 | 12,873 | (115,457) | ||||||||||||||
| Cash and cash equivalents at end of period | $248,596 | $12,929 | $56 | ||||||||||||||
2020 Compared to 2019
Operating Activities
Net cash flow provided by operating activities increased $88.6 million in 2020 compared to 2019 primarily due to the timing of recovery of fuel and purchased power costs and a decrease in the return of unprotected excess accumulated deferred income taxes to customers. The increase was partially offset by lower collections of receivables from customers, in part due to the COVID-19 pandemic, and increased storm spending. See Note 2 to the financial statements for further discussion of the regulatory activity regarding the Tax Cuts and Jobs Act. See “Hurricane Laura and Hurricane Delta” above for discussion of hurricane restoration efforts.
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Investing Activities
Net cash flow used in investing activities decreased $29.6 million in 2020 primarily due to:
•a decrease of $158.8 million in non-nuclear generation construction expenditures primarily due to the Montgomery County Power Station in 2020 as compared to 2019;
•a decrease of $9.9 million in information technology capital expenditures primarily due to decreased spending on various technology projects; and
•money pool activity.
The decrease was partially offset by:
•an increase of $93.8 million in storm spending in 2020, primarily due to Hurricane Laura and Hurricane Delta restoration efforts. See “Hurricane Laura and Hurricane Delta” above for discussion of hurricane restoration efforts;
•an increase of $43.9 million in distribution construction expenditures, primarily due to investment in the reliability and infrastructure of Entergy Texas’s distribution system, including increased spending on advanced metering infrastructure; and
•an increase of $29.8 million in transmission construction expenditures primarily due to a higher scope of work performed in 2020 as compared to 2019.
Decreases in Entergy Texas’s receivable from the money pool are a source of cash flow, and Entergy Texas’s receivable from the money pool decreased by $6.6 million in 2020 compared to increasing $11.2 million in 2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Financing Activities
Net cash flow provided by financing activities increased $104.6 million from 2020 compared to 2019 primarily due to:
•the issuance of $600 million of 1.75% Series mortgage bonds in October 2020;
•the repayment, at maturity, of $500 million of 7.125% Series mortgage bonds in February 2019;
•the issuance of $175 million of 3.55% Series mortgage bonds in March 2020; and
•money pool activity.
The increase was partially offset by:
•the issuances of $300 million of 4.0% Series mortgage bonds and $400 million of 4.5% Series mortgage bonds, each in January 2019;
•the issuance of $300 million of 3.55% Series mortgage bonds in September 2019;
•the repayment of $135 million of 5.625% Series mortgage bonds in November 2020;
•the issuance of $35 million aggregate liquidation value 5.375% Series A preferred stock in September 2019; and
•the payment of $30 million of common stock dividends in 2020. No common stock dividends were paid in 2019 as a result of upcoming capital expenditures, including Montgomery County Power Station.
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 $22.4 million in 2019.
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2019 Compared to 2018
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, 2019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
Capital Structure
Entergy Texas’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio for Entergy Texas is primarily due to the net issuance of $640 million of mortgage bonds in 2020, partially offset by the $175 million capital contribution received from Entergy Corporation in 2020 and net income in 2020.
| December 31, 2020 | December 31, 2019 | ||||||||||
| Debt to capital | 53.7 | % | 51.7 | % | |||||||
| Effect of excluding the securitization bonds | (1.3 | %) | (2.8 | %) | |||||||
| Debt to capital, excluding securitization bonds (a) | 52.4 | % | 48.9 | % | |||||||
| Effect of subtracting cash | (2.7 | %) | (0.2 | %) | |||||||
| Net debt to net capital, excluding securitization bonds (a) | 49.7 | % | 48.7 | % | |||||||
| (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. 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, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Texas may issue incremental debt or reduce dividends, or both, to maintain its capital structure. In addition, Entergy Texas may receive equity contributions to maintain its capital structure for certain circumstances such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced dividends.
Uses of Capital
Entergy Texas requires capital resources for:
•construction and other capital investments;
•debt maturities or retirements;
•working capital purposes, including the financing of fuel and purchased power costs; and
•dividend and interest payments.
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Following are the amounts of Entergy Texas’s planned construction and other capital investments.
| 2021 | 2022 | 2023 | |||||||||||||||
| (In Millions) | |||||||||||||||||
| Planned construction and capital investment: | |||||||||||||||||
| Generation | $95 | $40 | $490 | ||||||||||||||
| Transmission | 115 | 125 | 180 | ||||||||||||||
| Distribution | 245 | 285 | 295 | ||||||||||||||
| Utility Support | 55 | 75 | 50 | ||||||||||||||
| Total | $510 | $525 | $1,015 | ||||||||||||||
In addition to the planned spending in the table above, Entergy Texas also expects to pay for $180 million of capital investments in 2021 related to Hurricane Laura and Hurricane Delta restoration work that have been accrued as of December 31, 2020.
Following are the amounts of Entergy Texas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| 2021 | 2022-2023 | 2024-2025 | After 2025 | Total | |||||||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||||||||
| Long-term debt (a) | $353 | $207 | $151 | $2,163 | $2,874 | ||||||||||||||||||||||||
| Operating leases (b) | $5 | $7 | $3 | $1 | $16 | ||||||||||||||||||||||||
| Finance leases (b) | $1 | $2 | $2 | $1 | $6 | ||||||||||||||||||||||||
| Purchase obligations (c) | $255 | $384 | $361 | $294 | $1,294 | ||||||||||||||||||||||||
(a)Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.
(b)Lease obligations are discussed in Note 10 to the financial statements.
(c)Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Texas, it primarily includes unconditional fuel and purchased power obligations.
In addition to the contractual obligations given above, Entergy Texas expects to contribute approximately $7 million to its qualified pension plans and approximately $66 thousand to other postretirement health care and life insurance plans in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy Texas has $14.2 million of unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Texas includes specific investments such as the Liberty County Power Station and the Hardin County Peaking Facility; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; software and security; 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,
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environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt in Note 5 to the financial statements.
As a subsidiary, Entergy Texas dividends its earnings to Entergy Corporation at a percentage determined monthly.
Liberty County Solar Facility
In September 2020, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to acquire the 100 MW Liberty County Solar Facility and a determination that Entergy Texas’s acquisition of the facility through a tax equity partnership is in the public interest. In its preliminary order, the PUCT determined that, in considering Entergy Texas’s application, it would not specifically address whether Entergy Texas’s use of a tax equity partnership is in the public interest. A procedural schedule was established with a hearing on the merits scheduled in April 2021. Closing is expected to occur in 2023.
Hardin County Peaking Facility
In April 2020, Entergy Texas and East Texas Electric Cooperative, Inc. filed a joint report and application seeking PUCT approvals related to two transactions: (1) Entergy Texas’s acquisition of the Hardin County Peaking Facility from East Texas Electric Cooperative, Inc.; and (2) Entergy Texas’s sale of a 7.55% partial interest in the Montgomery County Power Station to East Texas Electric Cooperative, Inc. The two transactions, currently scheduled to close in April 2021 (pending PUCT approval), are interdependent. In October 2020, Entergy Texas filed an unopposed settlement agreement supporting approval of the transactions. Key provisions of the settlement include: Entergy Texas will propose to depreciate its investment in Hardin County Peaking Facility through the end of 2041; Entergy Texas’s recovery of its investment in Hardin County Peaking Facility will be capped at approximately $36 million; and Entergy Texas will not seek recovery of an acquisition adjustment, if any, or transaction costs for either transaction. The settlement is currently pending before the PUCT.
Sources of Capital
Entergy Texas’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•debt or preferred stock issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy Texas may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
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.
Entergy Texas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| 2020 | 2019 | 2018 | 2017 | |||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| $4,601 | $11,181 | ($22,389) | $44,903 | |||||||||||||||||
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See Note 4 to the financial statements for a description of the money pool.
Entergy Texas has a credit facility in the amount of $150 million scheduled to expire in September 2024. 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, 2020, there were no cash borrowings and $1.3 million of 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, 2020, $6.2 million in letters of credit were outstanding under Entergy Texas’s 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 July 2022 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.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Texas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Texas is regulated and the rates charged to its customers are determined in regulatory proceedings. The PUCT, a governmental agency, is primarily responsible for approval of the rates charged to customers.
Filings with the PUCT
2018 Rate Case
In May 2018, Entergy Texas filed a base rate case with the PUCT seeking an increase in base rates and rider rates of approximately $166 million, of which $48 million is associated with moving costs currently being collected through riders into base rates such that the total incremental revenue requirement increase is approximately $118 million. The base rate case was based on a 12-month test year ending December 31, 2017. In addition, Entergy Texas included capital additions placed into service for the period of April 1, 2013 through December 31, 2017, as well as a post-test year adjustment to include capital additions placed in service by June 30, 2018.
In October 2018 the parties filed an unopposed settlement resolving all issues in the proceeding and a motion for interim rates effective for usage on and after October 17, 2018. The unopposed settlement reflects the following terms: a base rate increase of $53.2 million (net of costs realigned from riders and including updated depreciation rates), a $25 million refund to reflect the lower federal income tax rate applicable to Entergy Texas from January 25, 2018 through the date new rates are implemented, $6 million of capitalized skylining tree hazard costs will not be recovered from customers, $242.5 million of protected excess accumulated deferred income taxes, which includes a tax gross-up, will be returned to customers through base rates under the average rate assumption method over the lives of the associated assets, and $185.2 million of unprotected excess accumulated deferred income taxes, which includes a tax gross-up, will be returned to customers through a rider. The unprotected excess accumulated deferred income taxes rider will include carrying charges and will be in effect over a period of 12 months for large customers and over a period of four years for other customers. The settlement also provides for the deferral of $24.5 million of costs associated with the remaining book value of the Neches and Sabine 2 plants, previously taken out of service, to be recovered over a ten-year period and the deferral of $20.5 million of costs associated with Hurricane Harvey to be recovered over a 12-year period, each beginning in October 2018. The settlement provides final resolution of all issues in the matter, including those related to the Tax Act. In October 2018 the ALJ granted the unopposed motion for interim rates to be effective for service rendered on or after October 17, 2018. In December 2018 the PUCT issued an order approving the unopposed settlement.
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Distribution Cost Recovery Factor (DCRF) Rider
In March 2019, Entergy Texas filed with the PUCT a request to set a new DCRF rider. The proposed new DCRF rider is designed to collect approximately $3.2 million annually from Entergy Texas’s retail customers based on its capital invested in distribution between January 1, 2018 and December 31, 2018. In September 2019 the PUCT issued an order approving rates, which had been effective on an interim basis since June 2019, at the level proposed in Entergy Texas’s application.
In March 2020, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $23.6 million annually, or $20.4 million in incremental annual DCRF revenue beyond Entergy Texas’s then-effective DCRF rider, based on its capital invested in distribution between January 1, 2019 and December 31, 2019. In May and June 2020 intervenors filed testimony recommending reductions in Entergy Texas’s annual revenue requirement of approximately $0.3 million and $4.1 million. The parties briefed the contested issues in this matter and a proposal for decision was issued in September 2020 recommending a $4.1 million revenue reduction related to non-Advanced Metering System meters included in the DCRF calculation. The parties filed exceptions to the proposal for decision and replies to those exceptions in September 2020. In October 2020 the PUCT issued a final order approving a $16.3 million incremental annual DCRF revenue increase.
In October 2020, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The proposed rider is 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 currently effective DCRF rider based on its capital invested in distribution between January 1, 2020 and August 31, 2020. In February 2021 the administrative law judge with the State Office of Administrative Hearings approved Entergy Texas's agreed motion for interim rates, which will go into effect in March 2021. The administrative law judge also adopted a procedural schedule setting a hearing on the merits, if necessary, in April 2021.
Transmission Cost Recovery Factor (TCRF) Rider
In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The proposed new TCRF rider is 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 August 2019, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended TCRF rider is designed to collect approximately $19.4 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and June 30, 2019, which is $16.7 million in incremental annual revenue above the $2.7 million approved in the prior pending TCRF proceeding. In January 2020 the PUCT issued an order approving an unopposed settlement providing for recovery of the requested revenue requirement. Entergy Texas implemented the amended rider beginning with bills covering usage on and after January 23, 2020.
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In October 2020, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $51 million annually, or $31.6 million in incremental annual revenues beyond Entergy Texas’s currently effective TCRF rider based on its capital invested in transmission between July 1, 2019 and August 31, 2020. A procedural schedule was established with a hearing scheduled in March 2021. In February 2021, Entergy Texas filed an agreed motion to abate the procedural schedule, noting that the parties had reached a settlement in principle, and the administrative law judge granted the motion to abate.
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 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 is 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 retains 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. On January 14, 2021, the PUCT approved the generation cost recovery rider settlement rates on an interim basis and abated the proceeding. Within 60 days of Montgomery County Power Station being placed in service on January 1, 2021, Entergy Texas will file to update its generation cost recovery rider to include investment in Montgomery County Power Station after August 31, 2020. The current estimated cost of Montgomery County Power Station, including transmission interconnection and network upgrades, is approximately $921 million. Of this investment, approximately $756 million is eligible to begin being recovered through the generation cost recovery rider. Entergy Texas will address recovery of the remainder of its Montgomery County Power Station investment through other rate mechanisms.
In December 2020, Entergy Texas filed an application to amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which is expected to close in April 2021. The initial generation cost recovery rider rates proposed in the application represent no change from the generation cost recovery rider rates to be established in Entergy Texas’s previous generation cost recovery rider proceeding. Once Entergy Texas has acquired the Hardin County Peaking Facility, its investment in the facility will be reflected in the updated filing to Entergy Texas’s application, which will be made within 60 days of the acquisition’s closing.
COVID-19 Orders
In March 2020 the PUCT authorized electric utilities to record as a regulatory asset expenses resulting from the effects of COVID-19. In future proceedings the PUCT will consider whether each utility's request for recovery of these regulatory assets is reasonable and necessary, the appropriate period of recovery, and any amount of carrying costs thereon. In March 2020 the PUCT ordered a moratorium on disconnections for nonpayment for all customer classes, but, in April 2020, revised the disconnect moratorium to apply only to residential customers. The PUCT allowed the moratorium to expire on June 13, 2020, but on July 17, 2020, the PUCT re-established the disconnect moratorium for residential customers until August 31, 2020. In January 2021, Entergy Texas resumed disconnections for customers with past-due balances that have not made payment arrangements. As of December 31, 2020, Entergy Texas recorded a regulatory asset of $12.9 million for costs associated with the COVID-19 pandemic.
Fuel and Purchased Power Cost Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates. Semi-annual revisions of the fixed fuel factor are made in March
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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. A fuel reconciliation is required to be filed at least once every three years and outside of a base rate case filing.
In December 2017, Entergy Texas filed an application for a fuel refund of approximately $30.5 million for the months of May 2017 through October 2017. Also in December 2017, the PUCT’s ALJ approved the refund on an interim basis. For most customers, the refunds flowed through bills January 2018 through March 2018. The fuel refund was approved by the PUCT in March 2018.
In September 2019, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period from April 2016 through March 2019. During the reconciliation period, Entergy Texas incurred approximately $1.6 billion in Texas jurisdictional eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. Entergy Texas estimated an under-recovery balance of approximately $25.8 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2019. In March 2020 an intervenor filed testimony proposing that the PUCT disallow: (1) $2 million in replacement power costs associated with generation outages during the reconciliation period; and (2) $24.4 million associated with the operation of the Spindletop natural gas storage facility during the reconciliation period. In April 2020, Entergy Texas filed rebuttal testimony refuting all points raised by the intervenor. In June 2020 the parties filed a stipulation and settlement agreement, which included a $1.2 million disallowance not associated with any particular issue raised by any party. The PUCT approved the settlement in August 2020.
In July 2020, Entergy Texas filed an application with the PUCT to implement an interim fuel refund of $25.5 million, including interest. Entergy Texas proposed that the interim fuel refund be implemented beginning with the first August 2020 billing cycle over a three-month period for smaller customers and in a lump sum amount in the billing month of August 2020 for transmission-level customers. The interim fuel refund was approved in July 2020, and Entergy Texas began refunds in August 2020.
In February 2021, Entergy Texas filed an application to implement a fuel refund for a cumulative over-recovery of approximately $75 million that is primarily attributable to settlements received by Entergy Texas from MISO related to Hurricane Laura. Entergy Texas planned to issue the refund over the period of March through August 2021. On February 22, 2021, Entergy Texas filed a motion to abate its fuel refund proceeding to assess how the February 2021 winter storm impacted Entergy Texas’s fuel over-recovery position.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Nuclear Matters
See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.
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
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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.
Environmental Risks
Entergy Texas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Texas is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Texas’s financial statements in conformity with generally accepted accounting principles 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 policies and 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 the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Texas’s financial position or results of operations.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Impairment of Long-lived Assets
See “Impairment of Long-lived Assets” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Texas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries’ Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension and qualified projected benefit obligation cost to changes in certain actuarial assumptions (dollars in thousands).
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| Actuarial Assumption | Change in Assumption | Impact on 2021 Qualified Pension Cost | Impact on 2020 Qualified Projected Benefit Obligation | |||||||||||||||||
| Increase/(Decrease) | ||||||||||||||||||||
| Discount rate | (0.25%) | $472 | $9,960 | |||||||||||||||||
| Rate of return on plan assets | (0.25%) | $772 | $— | |||||||||||||||||
| Rate of increase in compensation | 0.25% | $388 | $1,916 | |||||||||||||||||
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation changes in certain actuarial assumptions (dollars in thousands).
| Actuarial Assumption | Change in Assumption | Impact on 2021 Postretirement Benefit Cost | Impact on 2020 Accumulated Postretirement Benefit Obligation | |||||||||||||||||
| Increase/(Decrease) | ||||||||||||||||||||
| Discount rate | (0.25%) | $49 | $2,206 | |||||||||||||||||
| Health care cost trend | 0.25% | $76 | $1,593 | |||||||||||||||||
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy Texas in 2020 was $12.4 million, including $4.3 million in settlement costs. Entergy Texas anticipates 2021 qualified pension cost to be $8.9 million. Entergy Texas contributed $5 million to its qualified pension plans in 2020 and estimates 2021 pension contributions will be approximately $7 million, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021.
Total postretirement health care and life insurance benefit income for Entergy Texas in 2020 was $8.9 million. Entergy Texas expects 2020 postretirement health care and life insurance benefit income to approximate $10.9 million. In 2020, Entergy Texas’ postretirement contributions (that is, contributions to the external trusts plus claims payments) were $690 thousand. Entergy Texas estimates 2021 contributions will be approximately $66 thousand.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors of
Entergy Texas, Inc. and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Texas, Inc. and Subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of income, cash flows, and changes in common equity (pages 423 through 428 and applicable items in pages 51 through 238), for each of the three years in the period ended December 31, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters —Entergy Texas, Inc. and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
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
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regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
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 significant 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, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the PUCT and the FERC 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 costs incurred as property, plant, and equipment and deferred as 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 property, plant, and equipment; 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 and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information 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 the 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, including the base rate case filing, 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.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2021
We have served as the Company’s auditor since 2001.
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| ENTERGY TEXAS, INC. AND SUBSIDIARIES | ||||||||||||||||||||
| CONSOLIDATED INCOME STATEMENTS | ||||||||||||||||||||
| For the Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| OPERATING REVENUES | ||||||||||||||||||||
| Electric | $1,587,125 | $1,488,955 | $1,605,902 | |||||||||||||||||
| OPERATING EXPENSES | ||||||||||||||||||||
| Operation and Maintenance: | ||||||||||||||||||||
| Fuel, fuel-related expenses, and gas purchased for resale | 238,428 | 162,544 | 204,830 | |||||||||||||||||
| Purchased power | 510,633 | 602,563 | 614,012 | |||||||||||||||||
| Other operation and maintenance | 250,170 | 258,924 | 238,400 | |||||||||||||||||
| Taxes other than income taxes | 72,909 | 76,366 | 82,033 | |||||||||||||||||
| Depreciation and amortization | 177,738 | 153,286 | 128,534 | |||||||||||||||||
| Other regulatory charges - net | 90,398 | 88,770 | 131,667 | |||||||||||||||||
| TOTAL | 1,340,276 | 1,342,453 | 1,399,476 | |||||||||||||||||
| OPERATING INCOME | 246,849 | 146,502 | 206,426 | |||||||||||||||||
| OTHER INCOME | ||||||||||||||||||||
| Allowance for equity funds used during construction | 44,073 | 28,445 | 9,723 | |||||||||||||||||
| Interest and investment income | 1,201 | 3,072 | 2,188 | |||||||||||||||||
| Miscellaneous - net | (28) | 546 | (655) | |||||||||||||||||
| TOTAL | 45,246 | 32,063 | 11,256 | |||||||||||||||||
| INTEREST EXPENSE | ||||||||||||||||||||
| Interest expense | 92,920 | 86,333 | 87,203 | |||||||||||||||||
| Allowance for borrowed funds used during construction | (18,940) | (13,269) | (5,513) | |||||||||||||||||
| TOTAL | 73,980 | 73,064 | 81,690 | |||||||||||||||||
| INCOME BEFORE INCOME TAXES | 218,115 | 105,501 | 135,992 | |||||||||||||||||
| Income taxes | 3,042 | (53,896) | (26,243) | |||||||||||||||||
| NET INCOME | 215,073 | 159,397 | 162,235 | |||||||||||||||||
| Preferred dividend requirements | 1,882 | 580 | — | |||||||||||||||||
| EARNINGS APPLICABLE TO COMMON STOCK | $213,191 | $158,817 | $162,235 | |||||||||||||||||
| See Notes to Financial Statements. | ||||||||||||||||||||
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| ENTERGY TEXAS, INC. AND SUBSIDIARIES | ||||||||||||||||||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||||||||||||||||
| For the Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| OPERATING ACTIVITIES | ||||||||||||||||||||
| Net income | $215,073 | $159,397 | $162,235 | |||||||||||||||||
| Adjustments to reconcile net income to net cash flow provided by operating activities: | ||||||||||||||||||||
| Depreciation and amortization | 177,738 | 153,286 | 128,534 | |||||||||||||||||
| Deferred income taxes, investment tax credits, and non-current taxes accrued | 36,033 | 20,143 | (39,545) | |||||||||||||||||
| Changes in assets and liabilities: | ||||||||||||||||||||
| Receivables | (30,082) | 58,445 | (17,099) | |||||||||||||||||
| Fuel inventory | (5,938) | (4,926) | 64 | |||||||||||||||||
| Accounts payable | (23,692) | (33,646) | 43,319 | |||||||||||||||||
| Prepaid taxes and taxes accrued | 2,730 | (3,805) | 7,854 | |||||||||||||||||
| Interest accrued | 1,864 | (5,363) | (1,201) | |||||||||||||||||
| Deferred fuel costs | 72,355 | (6,696) | (47,604) | |||||||||||||||||
| Other working capital accounts | (11,837) | (13,822) | 1,328 | |||||||||||||||||
| Provisions for estimated losses | 274 | (5,748) | 3,741 | |||||||||||||||||
| Other regulatory assets | (12,065) | 85,400 | 63,350 | |||||||||||||||||
| Other regulatory liabilities | (57,477) | (105,517) | (19,336) | |||||||||||||||||
| Pension and other postretirement liabilities | (28,825) | (7,152) | (13,135) | |||||||||||||||||
| Other assets and liabilities | 39,174 | (3,257) | 59,248 | |||||||||||||||||
| Net cash flow provided by operating activities | 375,325 | 286,739 | 331,753 | |||||||||||||||||
| INVESTING ACTIVITIES | ||||||||||||||||||||
| Construction expenditures | (895,857) | (898,090) | (451,988) | |||||||||||||||||
| Allowance for equity funds used during construction | 44,073 | 28,526 | 9,861 | |||||||||||||||||
| Proceeds from sale of assets | — | — | 3,753 | |||||||||||||||||
| Payment for purchase of assets | (4,931) | — | — | |||||||||||||||||
| Changes in money pool receivable - net | 6,580 | (11,181) | 44,903 | |||||||||||||||||
| Changes in securitization account | 1,487 | 2,465 | (2,502) | |||||||||||||||||
| Net cash flow used in investing activities | (848,648) | (878,280) | (395,973) | |||||||||||||||||
| FINANCING ACTIVITIES | ||||||||||||||||||||
| Proceeds from the issuance of long-term debt | 937,725 | 986,019 | — | |||||||||||||||||
| Retirement of long-term debt | (367,565) | (578,593) | (74,950) | |||||||||||||||||
| Capital contributions from parent | 175,000 | 185,000 | — | |||||||||||||||||
| Proceeds from the issuance of preferred stock | — | 33,188 | — | |||||||||||||||||
| Change in money pool payable - net | — | (22,389) | 22,389 | |||||||||||||||||
| Dividends paid: | ||||||||||||||||||||
| Common stock | (30,000) | — | — | |||||||||||||||||
| Preferred stock | (2,064) | — | — | |||||||||||||||||
| Other | (4,106) | 1,189 | 1,324 | |||||||||||||||||
| Net cash flow provided by (used in) financing activities | 708,990 | 604,414 | (51,237) | |||||||||||||||||
| Net increase (decrease) in cash and cash equivalents | 235,667 | 12,873 | (115,457) | |||||||||||||||||
| Cash and cash equivalents at beginning of period | 12,929 | 56 | 115,513 | |||||||||||||||||
| Cash and cash equivalents at end of period | $248,596 | $12,929 | $56 | |||||||||||||||||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||||||||||||||||
| Cash paid during the period for: | ||||||||||||||||||||
| Interest - net of amount capitalized | $89,077 | $89,402 | $85,719 | |||||||||||||||||
| Income taxes | $2,792 | $17,010 | $20,787 | |||||||||||||||||
| See Notes to Financial Statements. | ||||||||||||||||||||
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| ENTERGY TEXAS, INC. AND SUBSIDIARIES | ||||||||||||||
| CONSOLIDATED BALANCE SHEETS | ||||||||||||||
| ASSETS | ||||||||||||||
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| CURRENT ASSETS | ||||||||||||||
| Cash and cash equivalents: | ||||||||||||||
| Cash | $26 | $25 | ||||||||||||
| Temporary cash investments | 248,570 | 12,904 | ||||||||||||
| Total cash and cash equivalents | 248,596 | 12,929 | ||||||||||||
| Securitization recovery trust account | 36,233 | 37,720 | ||||||||||||
| Accounts receivable: | ||||||||||||||
| Customer | 103,221 | 59,365 | ||||||||||||
| Allowance for doubtful accounts | (16,810) | (471) | ||||||||||||
| Associated companies | 18,892 | 24,001 | ||||||||||||
| Other | 11,780 | 17,050 | ||||||||||||
| Accrued unbilled revenues | 56,411 | 50,048 | ||||||||||||
| Total accounts receivable | 173,494 | 149,993 | ||||||||||||
| Fuel inventory - at average cost | 53,531 | 47,593 | ||||||||||||
| Materials and supplies - at average cost | 56,227 | 46,056 | ||||||||||||
| Prepayments and other | 20,165 | 21,012 | ||||||||||||
| TOTAL | 588,246 | 315,303 | ||||||||||||
| OTHER PROPERTY AND INVESTMENTS | ||||||||||||||
| Investments in affiliates - at equity | 349 | 396 | ||||||||||||
| Non-utility property - at cost (less accumulated depreciation) | 376 | 376 | ||||||||||||
| Other | 19,889 | 20,077 | ||||||||||||
| TOTAL | 20,614 | 20,849 | ||||||||||||
| UTILITY PLANT | ||||||||||||||
| Electric | 6,007,687 | 5,199,027 | ||||||||||||
| Construction work in progress | 879,908 | 760,354 | ||||||||||||
| TOTAL UTILITY PLANT | 6,887,595 | 5,959,381 | ||||||||||||
| Less - accumulated depreciation and amortization | 1,864,494 | 1,770,852 | ||||||||||||
| UTILITY PLANT - NET | 5,023,101 | 4,188,529 | ||||||||||||
| DEFERRED DEBITS AND OTHER ASSETS | ||||||||||||||
| Regulatory assets: | ||||||||||||||
Other regulatory assets (includes securitization property of $78,590 as of December 31, 2020 and $160,375 as of December 31, 2019) | 524,713 | 512,648 | ||||||||||||
| Other | 70,397 | 33,393 | ||||||||||||
| TOTAL | 595,110 | 546,041 | ||||||||||||
| TOTAL ASSETS | $6,227,071 | $5,070,722 | ||||||||||||
| See Notes to Financial Statements. | ||||||||||||||
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| ENTERGY TEXAS, INC. AND SUBSIDIARIES | ||||||||||||||
| CONSOLIDATED BALANCE SHEETS | ||||||||||||||
| LIABILITIES AND EQUITY | ||||||||||||||
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| CURRENT LIABILITIES | ||||||||||||||
| Currently maturing long-term debt | $200,000 | $— | ||||||||||||
| Accounts payable: | ||||||||||||||
| Associated companies | 55,944 | 58,055 | ||||||||||||
| Other | 350,947 | 188,460 | ||||||||||||
| Customer deposits | 36,282 | 40,232 | ||||||||||||
| Taxes accrued | 52,438 | 49,708 | ||||||||||||
| Interest accrued | 20,856 | 18,992 | ||||||||||||
| Current portion of unprotected excess accumulated deferred income taxes | 29,249 | 26,552 | ||||||||||||
| Deferred fuel costs | 85,356 | 13,001 | ||||||||||||
| Other | 12,370 | 10,521 | ||||||||||||
| TOTAL | 843,442 | 405,521 | ||||||||||||
| NON-CURRENT LIABILITIES | ||||||||||||||
| Accumulated deferred income taxes and taxes accrued | 639,422 | 585,413 | ||||||||||||
| Accumulated deferred investment tax credits | 9,942 | 10,559 | ||||||||||||
| Regulatory liability for income taxes - net | 175,594 | 225,980 | ||||||||||||
| Other regulatory liabilities | 32,297 | 42,085 | ||||||||||||
| Asset retirement cost liabilities | 8,063 | 7,631 | ||||||||||||
| Accumulated provisions | 8,382 | 8,108 | ||||||||||||
Long-term debt (includes securitization bonds of $123,066 as of December 31, 2020 and $205,349 as of December 31, 2019) | 2,293,708 | 1,922,956 | ||||||||||||
| Other | 58,643 | 63,062 | ||||||||||||
| TOTAL | 3,226,051 | 2,865,794 | ||||||||||||
| Commitments and Contingencies | ||||||||||||||
| EQUITY | ||||||||||||||
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2020 and 2019 | 49,452 | 49,452 | ||||||||||||
| Paid-in capital | 955,162 | 780,182 | ||||||||||||
| Retained earnings | 1,117,964 | 934,773 | ||||||||||||
| Total common shareholder's equity | 2,122,578 | 1,764,407 | ||||||||||||
| Preferred stock without sinking fund | 35,000 | 35,000 | ||||||||||||
| TOTAL | 2,157,578 | 1,799,407 | ||||||||||||
| TOTAL LIABILITIES AND EQUITY | $6,227,071 | $5,070,722 | ||||||||||||
| See Notes to Financial Statements. | ||||||||||||||
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| ENTERGY TEXAS, INC. AND SUBSIDIARIES | |||||||||||||||||||||||||||||
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY | |||||||||||||||||||||||||||||
| For the Years Ended December 31, 2020, 2019, and 2018 | |||||||||||||||||||||||||||||
| Common Equity | |||||||||||||||||||||||||||||
| Preferred Stock | Common Stock | Paid-in Capital | Retained Earnings | Total | |||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||
| Balance at December 31, 2017 | $— | $49,452 | $596,994 | $613,721 | $1,260,167 | ||||||||||||||||||||||||
| Net income | — | — | — | 162,235 | 162,235 | ||||||||||||||||||||||||
| Balance at December 31, 2018 | $— | $49,452 | $596,994 | $775,956 | $1,422,402 | ||||||||||||||||||||||||
| Net income | — | — | — | 159,397 | 159,397 | ||||||||||||||||||||||||
| Capital contributions from parent | — | 185,000 | — | 185,000 | |||||||||||||||||||||||||
| Preferred stock issuance | 35,000 | — | (1,812) | — | 33,188 | ||||||||||||||||||||||||
| Preferred stock dividends | — | — | — | (580) | (580) | ||||||||||||||||||||||||
| Balance at December 31, 2019 | $35,000 | $49,452 | $780,182 | $934,773 | $1,799,407 | ||||||||||||||||||||||||
| Net income | — | — | — | 215,073 | 215,073 | ||||||||||||||||||||||||
| Capital contributions from parent | — | — | 175,000 | — | 175,000 | ||||||||||||||||||||||||
| Common stock dividends | — | — | — | (30,000) | (30,000) | ||||||||||||||||||||||||
| Preferred stock dividends | — | — | — | (1,882) | (1,882) | ||||||||||||||||||||||||
| Other | — | — | (20) | — | (20) | ||||||||||||||||||||||||
| Balance at December 31, 2020 | $35,000 | $49,452 | $955,162 | $1,117,964 | $2,157,578 | ||||||||||||||||||||||||
| See Notes to Financial Statements. | |||||||||||||||||||||||||||||
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| ENTERGY TEXAS, INC. AND SUBSIDIARIES | |||||||||||||||||||||||||||||
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2017 | 2016 | |||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||||||
| Operating revenues | $1,587,125 | $1,488,955 | $1,605,902 | $1,544,893 | $1,615,619 | ||||||||||||||||||||||||
| Net income | $215,073 | $159,397 | $162,235 | $76,173 | $107,538 | ||||||||||||||||||||||||
| Total assets | $6,227,071 | $5,070,722 | $4,400,020 | $4,279,738 | $4,033,081 | ||||||||||||||||||||||||
| Long-term obligations (a) | $2,293,708 | $1,922,956 | $1,013,735 | $1,587,150 | $1,508,407 | ||||||||||||||||||||||||
| (a) Includes long-term debt (excluding currently maturing debt). | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2017 | 2016 | |||||||||||||||||||||||||
| (Dollars In Millions) | |||||||||||||||||||||||||||||
| Electric Operating Revenues: | |||||||||||||||||||||||||||||
| Residential | $672 | $658 | $674 | $636 | $613 | ||||||||||||||||||||||||
| Commercial | 365 | 343 | 381 | 378 | 356 | ||||||||||||||||||||||||
| Industrial | 386 | 373 | 394 | 384 | 365 | ||||||||||||||||||||||||
| Governmental | 23 | 22 | 25 | 25 | 24 | ||||||||||||||||||||||||
| Total billed retail | 1,446 | 1,396 | 1,474 | 1,423 | 1,358 | ||||||||||||||||||||||||
| Sales for resale: | |||||||||||||||||||||||||||||
| Associated companies | 40 | 52 | 59 | 58 | 178 | ||||||||||||||||||||||||
| Non-associated companies | 60 | 7 | 39 | 22 | 40 | ||||||||||||||||||||||||
| Other | 41 | 34 | 34 | 42 | 40 | ||||||||||||||||||||||||
| Total | $1,587 | $1,489 | $1,606 | $1,545 | $1,616 | ||||||||||||||||||||||||
| Billed Electric Energy Sales (GWh): | |||||||||||||||||||||||||||||
| Residential | 6,146 | 6,039 | 6,135 | 5,716 | 5,836 | ||||||||||||||||||||||||
| Commercial | 4,386 | 4,667 | 4,747 | 4,548 | 4,570 | ||||||||||||||||||||||||
| Industrial | 7,885 | 8,043 | 8,052 | 7,521 | 7,493 | ||||||||||||||||||||||||
| Governmental | 260 | 259 | 286 | 273 | 283 | ||||||||||||||||||||||||
| Total retail | 18,677 | 19,008 | 19,220 | 18,058 | 18,182 | ||||||||||||||||||||||||
| Sales for resale: | |||||||||||||||||||||||||||||
| Associated companies | 1,203 | 1,472 | 1,516 | 1,534 | 4,625 | ||||||||||||||||||||||||
| Non-associated companies | 810 | 343 | 962 | 729 | 1,086 | ||||||||||||||||||||||||
| Total | 20,690 | 20,823 | 21,698 | 20,321 | 23,893 | ||||||||||||||||||||||||
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SYSTEM ENERGY RESOURCES, INC.
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
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 is currently involved in proceedings at the FERC commenced by the retail regulators of its customers regarding its return on equity, its capital structure, its renewal of the sale-leaseback of 11.5% of Grand Gulf, the treatment of uncertain tax positions in rate base, and the rates it charges under the Unit Power Sales Agreement.
Results of Operations
2020 Compared to 2019
Net Income
Net income remained relatively unchanged. An increase in operating revenues resulting from changes in rate base was substantially offset by higher provisions against revenue, as compared to prior year. A provision for rate refund was recorded in 2020 to reflect a one-time credit of $25.2 million provided for in the Federal Power Act section 205 filing made by System Energy in December 2020. Provisions against revenue were recorded in 2019 in connection with the return on equity complaint against System Energy. See “Complaints Against System Energy” below for further discussion of these items and other proceedings involving System Energy at the FERC. The one-time credit is discussed in the Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue part of that section. The return on equity complaint is discussed in the Return on Equity and Capital Structure Complaints part of that section.
Income Taxes
The effective income tax rates were 17.2% for 2020 and 13.4% for 2019. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.
2019 Compared to 2018
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, 2019, filed with the SEC on February 21, 2020, for discussion of results of operations for 2019 compared to 2018.
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Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, and 2018 were as follows:
| 2020 | 2019 | 2018 | |||||||||||||||
| (In Thousands) | |||||||||||||||||
| Cash and cash equivalents at beginning of period | $68,534 | $95,685 | $287,187 | ||||||||||||||
| Net cash provided by (used in): | |||||||||||||||||
| Operating activities | (145,462) | 300,141 | 101,328 | ||||||||||||||
| Investing activities | (206,443) | (119,553) | (286,161) | ||||||||||||||
| Financing activities | 525,840 | (207,739) | (6,669) | ||||||||||||||
| Net increase (decrease) in cash and cash equivalents | 173,935 | (27,151) | (191,502) | ||||||||||||||
| Cash and cash equivalents at end of period | $242,469 | $68,534 | $95,685 | ||||||||||||||
2020 Compared to 2019
Operating Activities
System Energy’s operating activities used $145.5 million of cash in 2020 compared to providing $300.1 million of cash in 2019 primarily due to:
•an increase of $382 million in income taxes paid in 2020. System Energy made income tax payments of $384.3 million in 2020 in accordance with an intercompany income tax allocation agreement. The 2020 income tax payments are primarily related to the resolution of the 2014-2015 IRS audit regarding the treatment of nuclear decommissioning costs included in cost of goods sold, which is discussed in Note 3 to the financial statements in Tax Accounting Methods;
•an increase in spending of $34.9 million on nuclear refueling outages in 2020 as compared to prior year; and
•timing of payments to vendors.
The increase in cash used was offset by proceeds of $35 million received in December 2020 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for a discussion of the spent nuclear fuel litigation.
Investing Activities
Net cash flow used in investing activities increased by $86.9 million in 2020 primarily due to:
•an increase of $77.2 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
•an increase of $28 million in nuclear construction expenditures as a result of spending in 2020 on Grand Gulf outage projects.
The increase was partially offset by money pool activity and proceeds of $5.5 million received in December 2020 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
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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 by $55.3 million in 2020 compared to decreasing by $47.8 million in 2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Financing Activities
System Energy’s financing activities provided $525.8 million of cash in 2020 compared to using $207.7 million of cash in 2019 primarily due to the following activity:
•a $350 million capital contribution from Entergy Corporation in order to maintain System Energy’s capital structure in conjunction with the tax payments discussed in “Operating Activities”
•the issuance in December 2020 of $200 million of 2.14% Series mortgage bonds;
•the issuance in October 2020 of $90 million of 2.05% Series K notes by the System Energy nuclear fuel company variable interest entity;
•a decrease in net repayments of $50.7 million of long-term borrowings in 2020 on the nuclear fuel company variable interest entity’s credit facility; and
•a decrease of $43.6 million in common stock dividends and distributions in 2020 in order to maintain System Energy’s capital structure.
See Note 5 to the financial statements for additional details of long-term debt.
2019 Compared to 2018
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, 2019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
Capital Structure
System Energy’s debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio is primarily due to the capital contribution from Entergy Corporation, partially offset by the issuance of long-term debt in 2020.
| December 31, 2020 | December 31, 2019 | ||||||||||
| Debt to capital | 42.7 | % | 43.5 | % | |||||||
| Effect of subtracting cash | (8.5 | %) | (3.3 | %) | |||||||
| Net debt to net capital | 34.2 | % | 40.2 | % | |||||||
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. 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.
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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, 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, System Energy may issue incremental debt or reduce dividends, or both, to maintain its capital structure. In addition, System Energy may receive equity contributions to maintain its capital structure for certain circumstances that would materially alter the capital structure if financed entirely with debt and reduced dividends.
Uses of Capital
System Energy requires capital resources for:
•construction and other capital investments;
•debt maturities or retirements;
•working capital purposes, including the financing of fuel costs and tax payments; and
•dividend, distribution, and interest payments.
Following are the amounts of System Energy’s planned construction and other capital investments.
| 2021 | 2022 | 2023 | |||||||||||||||
| (In Millions) | |||||||||||||||||
| Planned construction and capital investment: | |||||||||||||||||
| Generation | $90 | $145 | $140 | ||||||||||||||
| Utility Support | 15 | 10 | 15 | ||||||||||||||
| Total | $105 | $155 | $155 | ||||||||||||||
Following are the amounts of System Energy’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| 2021 | 2022-2023 | 2024-2025 | After 2025 | Total | |||||||||||||||||||||||||
| (In Millions) | |||||||||||||||||||||||||||||
| Long-term debt (a) | $138 | $444 | $246 | $299 | $1,127 | ||||||||||||||||||||||||
| Purchase obligations (b) | $6 | $53 | $47 | $40 | $146 | ||||||||||||||||||||||||
(a)Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.
(b)Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For System Energy, it includes nuclear fuel purchase obligations.
In addition to the contractual obligations given above, System Energy expects to contribute approximately $18.7 million to its qualified pension plans and approximately $22 thousand to other postretirement health care and life insurance plans in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, System Energy has $14.2 million of unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
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In addition to routine spending to maintain operations, the planned capital investment estimate includes specific Grand Gulf investments and initiatives.
As a wholly-owned subsidiary, System Energy dividends its earnings to Entergy Corporation at a percentage determined monthly.
Sources of Capital
System Energy’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•debt issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•equity contributions; and
•bank financing under new or existing facilities.
System Energy may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
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.
System Energy’s receivables from the money pool were as follows as of December 31 for each of the following years.
| 2020 | 2019 | 2018 | 2017 | |||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| $4,004 | $59,298 | $107,122 | $111,667 | |||||||||||||||||
See Note 4 to the financial statements for a description of the money pool.
The System Energy nuclear fuel company variable interest entity has a credit facility in the amount of $120 million scheduled to expire in September 2022. As of December 31, 2020, no 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 July 14, 2022 for the following:
•short-term borrowings not to exceed an aggregate amount of $200 million at any time outstanding;
•long-term borrowings and security issuances; and
•borrowings by its nuclear fuel company variable interest entity.
See Note 4 to the financial statements for further discussion of System Energy’s short-term borrowing limits.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
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Complaints Against System Energy
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.
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 have been 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 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 and the APSC and 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 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
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prospective basis, the LPSC argues for an authorized return on equity for System Energy of 7.97% and the APSC and 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 Entergy 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 and the APSC and 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 MPSC recommend that 35.98% be set as the common equity ratio for System Energy. As an alternative, the APSC and 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
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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
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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, and the initial decision is due in March 2021. System Energy recorded a provision against revenue for the potential outcome of this proceeding.
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, MPSC, and 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, MPSC, APSC and 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.
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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 $191 million through December 31, 2020. 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 an 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 System Energy’s rate base should have been reduced for those liabilities. If the ALJ’s initial decision is upheld, the estimated refund for this issue through December 31, 2020, is approximately $422 million, plus interest, which is approximately $110 million through December 31, 2020. 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. If the initial decision is affirmed on this issue, System Energy estimates refunds of approximately $19 million, which includes interest through December 31, 2020.
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. The ALJ in the initial decision acknowledges that these are issues of first impression before the FERC. 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
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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, MPSC, APSC, City Council, and the FERC trial staff opposed the exceptions filed by System Energy. Also in October 2020 the MPSC, APSC, and the City Council filed briefs adopting the exceptions of the LPSC and the FERC trial staff. The case is pending before the FERC, which will review the case and issue an order on the proceeding, and the FERC may accept, reject, or modify the ALJ’s initial decision in whole or in part. Refunds, if any, that might be required will only become due after the FERC issues its order reviewing the initial decision.
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, APSC, MPSC, and 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, APSC, MPSC, and 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, APSC, and 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.
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LPSC Authorization of 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 notes 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 authorizes 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.”
The first of the additional complaints was filed at the FERC by the LPSC, the APSC, the MPSC, and the City Council in September 2020. The new 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 lease refinancing costs in rate base as prepayments; improperly included nuclear decommissioning outage costs in rate base; failed to include categories of accumulated deferred income taxes as a reduction 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: incentive and executive compensation, lack of an equity re-opener, lobbying, and private airplane travel. The new 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 new 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 2020, System Energy filed a response to the complainant’s response.
The operational prudence-related complaint has not been filed as of this date, and the LPSC directive did not set a date for the filing.
Unit Power Sales Agreement
In August 2017, System Energy submitted to the FERC proposed amendments to the Unit Power Sales
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Agreement pursuant to which System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The filing proposes limited amendments to the Unit Power Sales Agreement to adopt (1) updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses and (2) updated nuclear decommissioning cost annual revenue requirements, both of which are recovered through the Unit Power Sales Agreement rate formula. The amendments result in lower charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. The changes were based on updated depreciation and nuclear decommissioning studies that take into account the renewal of Grand Gulf’s operating license for a term through November 1, 2044.
In September 2017 the FERC accepted System Energy’s proposed Unit Power Sales Agreement amendments, subject to further proceedings to consider the justness and reasonableness of the amendments. Because the amendments propose a rate decrease, the FERC also initiated an investigation under section 206 of the Federal Power Act to determine if the rate decrease should be lower than proposed. The FERC accepted the proposed amendments effective October 1, 2017, subject to refund pending the outcome of the further settlement and/or hearing proceedings, and established a refund effective date of October 11, 2017 with respect to the rate decrease. In June 2018, System Energy filed with the FERC an uncontested settlement relating to the updated depreciation rates and nuclear decommissioning cost annual revenue requirements. In August 2018 the FERC issued an order accepting the settlement. In the third quarter 2018, System Energy recorded a reduction in depreciation expense of approximately $26 million, representing the cumulative difference in depreciation expense resulting from the depreciation rates used from October 11, 2017 through September 30, 2018 and the depreciation rates included in the settlement filing accepted by the FERC.
Nuclear Matters
System Energy owns and, through an affiliate, operates Grand Gulf. System Energy is, therefore, subject to the risks related to owning and operating a nuclear plant. 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, to position Grand Gulf to meet its operational goals; the performance and capacity factors of Grand Gulf, including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license renewal and 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 and types of insurance commercially available 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.
In November 2020 the NRC placed Grand Gulf in the “regulatory response column”, or Column 2, of the NRC’s Reactor Oversight Process Action Matrix based on the incidence of three unplanned plant scrams during the second and third quarters of 2020. Two of the scram events related to new turbine control system components that failed, and a third related to a feedwater valve positioner that failed, all of which had been replaced in a refueling outage that ended in May 2020. The NRC plans to conduct a supplemental inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 2. As a consequence of two additional Grand Gulf scrams during the fourth quarter 2020, System Energy expects Grand Gulf to be placed into the “degraded cornerstone column”, or Column 3, of the NRC’s Reactor Oversight Process Action Matrix based on plant performance indicators for the four quarters ended December 31, 2020. This will involve an additional supplemental NRC inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 3.
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Environmental Risks
System Energy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that System Energy is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of System Energy’s financial statements in conformity with generally accepted accounting principles 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 policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of System Energy’s financial position or results of operations.
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Impairment of Long-lived Assets
See “Impairment of Long-lived Assets” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
System Energy’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “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.
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Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| Actuarial Assumption | Change in Assumption | Impact on 2021 Qualified Pension Cost | Impact on 2020 Projected Qualified Benefit Obligation | |||||||||||||||||
| Increase/(Decrease) | ||||||||||||||||||||
| Discount rate | (0.25%) | $727 | $12,152 | |||||||||||||||||
| Rate of return on plan assets | (0.25%) | $709 | $— | |||||||||||||||||
| Rate of increase in compensation | 0.25% | $464 | $2,133 | |||||||||||||||||
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| Actuarial Assumption | Change in Assumption | Impact on 2021 Postretirement Benefit Cost | Impact on 2020 Accumulated Postretirement Benefit Obligation | |||||||||||||||||
| Increase/(Decrease) | ||||||||||||||||||||
| Discount rate | (0.25%) | $58 | $1,635 | |||||||||||||||||
| Health care cost trend | 0.25% | $69 | $1,202 | |||||||||||||||||
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for System Energy in 2020 was $17.3 million, including $105 thousand in settlement costs. System Energy anticipates 2021 qualified pension cost to be $20 million. System Energy contributed $16.1 million to its qualified pension plans in 2020 and estimates 2021 pension contributions will approximate $18.7 million, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021.
Total postretirement health care and life insurance benefit income for System Energy in 2020 was $1.5 million. System Energy expects 2021 postretirement health care and life insurance benefit income to approximate $1.3 million. System Energy contributed $1.3 million to its other postretirement plans in 2020 and expects 2021 contributions to approximate $22 thousand.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholder and Board of Directors of
System Energy Resources, Inc.
Opinion on the Financial Statements
We have audited the accompanying balance sheets of System Energy Resources, Inc. (the “Company”) as of December 31, 2020 and 2019, the related statements of income, cash flows, and changes in common equity (pages 447 through 452 and applicable items in pages 51 through 238), for each of the three years in the period ended December 31, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that is material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing 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 Notes 2 to the financial statements
Critical Audit Matter Description
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, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; income taxes; and depreciation and amortization expense.
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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 significant 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, (2) likelihood of refunds to customers, and (3) ongoing complaints filed with the FERC against the Company. Auditing management’s judgments regarding the outcome of future decisions by the FERC, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the FERC 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 costs incurred as property, plant, and equipment and deferred as 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 property, plant, and equipment; 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 and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information 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 the 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 and ongoing complaints filed with the FERC, including the Return on Equity, Capital Structure, and Grand Gulf Sale-Leaseback Renewal complaints, and considered the filings with 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, including the complaints filed with the FERC against the Company, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2021
We have served as the Company’s auditor since 2001.
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| SYSTEM ENERGY RESOURCES, INC. | ||||||||||||||||||||
| INCOME STATEMENTS | ||||||||||||||||||||
| For the Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| OPERATING REVENUES | ||||||||||||||||||||
| Electric | $495,458 | $573,410 | $456,707 | |||||||||||||||||
| OPERATING EXPENSES | ||||||||||||||||||||
| Operation and Maintenance: | ||||||||||||||||||||
| Fuel, fuel-related expenses, and gas purchased for resale | 23,026 | 82,438 | 64,778 | |||||||||||||||||
| Nuclear refueling outage expenses | 27,737 | 33,376 | 20,715 | |||||||||||||||||
| Other operation and maintenance | 178,249 | 206,444 | 196,505 | |||||||||||||||||
| Decommissioning | 37,181 | 35,729 | 34,336 | |||||||||||||||||
| Taxes other than income taxes | 28,657 | 29,018 | 28,090 | |||||||||||||||||
| Depreciation and amortization | 110,395 | 106,630 | 97,527 | |||||||||||||||||
| Other regulatory credits - net | (26,531) | (35,210) | (28,924) | |||||||||||||||||
| TOTAL | 378,714 | 458,425 | 413,027 | |||||||||||||||||
| OPERATING INCOME | 116,744 | 114,985 | 43,680 | |||||||||||||||||
| OTHER INCOME | ||||||||||||||||||||
| Allowance for equity funds used during construction | 9,122 | 8,709 | 8,750 | |||||||||||||||||
| Interest and investment income | 36,478 | 29,488 | 35,985 | |||||||||||||||||
| Miscellaneous - net | (10,012) | (5,516) | (5,775) | |||||||||||||||||
| TOTAL | 35,588 | 32,681 | 38,960 | |||||||||||||||||
| INTEREST EXPENSE | ||||||||||||||||||||
| Interest expense | 34,467 | 35,328 | 38,424 | |||||||||||||||||
| Allowance for borrowed funds used during construction | (1,809) | (2,131) | (2,218) | |||||||||||||||||
| TOTAL | 32,658 | 33,197 | 36,206 | |||||||||||||||||
| INCOME BEFORE INCOME TAXES | 119,674 | 114,469 | 46,434 | |||||||||||||||||
| Income taxes | 20,543 | 15,349 | (47,675) | |||||||||||||||||
| NET INCOME | $99,131 | $99,120 | $94,109 | |||||||||||||||||
| See Notes to Financial Statements. | ||||||||||||||||||||
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| SYSTEM ENERGY RESOURCES, INC. | ||||||||||||||||||||
| STATEMENTS OF CASH FLOWS | ||||||||||||||||||||
| For the Years Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||
| OPERATING ACTIVITIES | ||||||||||||||||||||
| Net income | $99,131 | $99,120 | $94,109 | |||||||||||||||||
| Adjustments to reconcile net income to net cash flow provided by (used in) operating activities: | ||||||||||||||||||||
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | 184,429 | 212,170 | 186,719 | |||||||||||||||||
| Deferred income taxes, investment tax credits, and non-current taxes accrued | (455,732) | 95 | 24,040 | |||||||||||||||||
| Changes in assets and liabilities: | ||||||||||||||||||||
| Receivables | 13,932 | (23,382) | 18,169 | |||||||||||||||||
| Accounts payable | (11,587) | 18,204 | (7,067) | |||||||||||||||||
| Prepaid taxes and taxes accrued | 69,145 | 19,247 | (51,999) | |||||||||||||||||
| Interest accrued | 729 | (1,302) | (94) | |||||||||||||||||
| Other working capital accounts | (34,158) | 15,879 | (45,415) | |||||||||||||||||
| Other regulatory assets | (48,880) | (43,712) | (2,044) | |||||||||||||||||
| Other regulatory liabilities | 140,965 | 130,949 | (156,802) | |||||||||||||||||
| Pension and other postretirement liabilities | 15,596 | 11,177 | (23,235) | |||||||||||||||||
| Other assets and liabilities | (119,032) | (138,304) | 64,947 | |||||||||||||||||
| Net cash flow provided by (used in) operating activities | (145,462) | 300,141 | 101,328 | |||||||||||||||||
| INVESTING ACTIVITIES | ||||||||||||||||||||
| Construction expenditures | (193,857) | (166,695) | (194,696) | |||||||||||||||||
| Allowance for equity funds used during construction | 9,122 | 8,709 | 8,750 | |||||||||||||||||
| Nuclear fuel purchases | (94,991) | (18,170) | (125,272) | |||||||||||||||||
| Proceeds from the sale of nuclear fuel | 25,836 | 26,223 | 30,634 | |||||||||||||||||
| Proceeds from nuclear decommissioning trust fund sales | 418,943 | 500,384 | 573,561 | |||||||||||||||||
| Investment in nuclear decommissioning trust funds | (432,249) | (517,828) | (583,683) | |||||||||||||||||
| Changes in money pool receivable - net | 55,294 | 47,824 | 4,545 | |||||||||||||||||
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | 5,459 | — | — | |||||||||||||||||
| Net cash flow used in investing activities | (206,443) | (119,553) | (286,161) | |||||||||||||||||
| FINANCING ACTIVITIES | ||||||||||||||||||||
| Proceeds from the issuance of long-term debt | 1,147,903 | 1,103,917 | 741,785 | |||||||||||||||||
| Retirement of long-term debt | (891,410) | (1,187,406) | (662,904) | |||||||||||||||||
| Capital contribution from parent | 350,000 | — | — | |||||||||||||||||
| Changes in short-term credit borrowings - net | — | — | (17,830) | |||||||||||||||||
| Common stock dividends and distributions | (80,653) | (124,250) | (67,720) | |||||||||||||||||
| Net cash flow provided by (used in) financing activities | 525,840 | (207,739) | (6,669) | |||||||||||||||||
| Net increase (decrease) in cash and cash equivalents | 173,935 | (27,151) | (191,502) | |||||||||||||||||
| Cash and cash equivalents at beginning of period | 68,534 | 95,685 | 287,187 | |||||||||||||||||
| Cash and cash equivalents at end of period | $242,469 | $68,534 | $95,685 | |||||||||||||||||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||||||||||||||||||
| Cash paid during the period for: | ||||||||||||||||||||
| Interest - net of amount capitalized | $35,061 | $21,052 | $17,183 | |||||||||||||||||
| Income taxes | $384,329 | $2,284 | $53,956 | |||||||||||||||||
| See Notes to Financial Statements. | ||||||||||||||||||||
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| SYSTEM ENERGY RESOURCES, INC. | ||||||||||||||
| BALANCE SHEETS | ||||||||||||||
| ASSETS | ||||||||||||||
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| CURRENT ASSETS | ||||||||||||||
| Cash and cash equivalents: | ||||||||||||||
| Cash | $26,086 | $93 | ||||||||||||
| Temporary cash investments | 216,383 | 68,441 | ||||||||||||
| Total cash and cash equivalents | 242,469 | 68,534 | ||||||||||||
| Accounts receivable: | ||||||||||||||
| Associated companies | 57,743 | 121,972 | ||||||||||||
| Other | 2,550 | 7,547 | ||||||||||||
| Total accounts receivable | 60,293 | 129,519 | ||||||||||||
| Materials and supplies - at average cost | 123,006 | 108,766 | ||||||||||||
| Deferred nuclear refueling outage costs | 34,459 | 14,493 | ||||||||||||
| Prepayments and other | 6,864 | 6,045 | ||||||||||||
| TOTAL | 467,091 | 327,357 | ||||||||||||
| OTHER PROPERTY AND INVESTMENTS | ||||||||||||||
| Decommissioning trust funds | 1,215,868 | 1,054,098 | ||||||||||||
| TOTAL | 1,215,868 | 1,054,098 | ||||||||||||
| UTILITY PLANT | ||||||||||||||
| Electric | 5,309,458 | 5,070,859 | ||||||||||||
| Construction work in progress | 59,831 | 164,996 | ||||||||||||
| Nuclear fuel | 175,005 | 149,574 | ||||||||||||
| TOTAL UTILITY PLANT | 5,544,294 | 5,385,429 | ||||||||||||
| Less - accumulated depreciation and amortization | 3,355,367 | 3,285,487 | ||||||||||||
| UTILITY PLANT - NET | 2,188,927 | 2,099,942 | ||||||||||||
| DEFERRED DEBITS AND OTHER ASSETS | ||||||||||||||
| Regulatory assets: | ||||||||||||||
| Other regulatory assets | 538,963 | 490,083 | ||||||||||||
| Accumulated deferred income tax | — | 8,023 | ||||||||||||
| Other | 3,119 | 3,192 | ||||||||||||
| TOTAL | 542,082 | 501,298 | ||||||||||||
| TOTAL ASSETS | $4,413,968 | $3,982,695 | ||||||||||||
| See Notes to Financial Statements. | ||||||||||||||
450
| SYSTEM ENERGY RESOURCES, INC. | ||||||||||||||
| BALANCE SHEETS | ||||||||||||||
| LIABILITIES AND EQUITY | ||||||||||||||
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| (In Thousands) | ||||||||||||||
| CURRENT LIABILITIES | ||||||||||||||
| Currently maturing long-term debt | $100,015 | $10 | ||||||||||||
| Accounts payable: | ||||||||||||||
| Associated companies | 15,309 | 14,619 | ||||||||||||
| Other | 41,313 | 64,144 | ||||||||||||
| Taxes accrued | 82,977 | 13,832 | ||||||||||||
| Interest accrued | 12,722 | 11,993 | ||||||||||||
| Other | 4,248 | 3,381 | ||||||||||||
| TOTAL | 256,584 | 107,979 | ||||||||||||
| NON-CURRENT LIABILITIES | ||||||||||||||
| Accumulated deferred income taxes and taxes accrued | 359,835 | 821,963 | ||||||||||||
| Accumulated deferred investment tax credits | 38,902 | 40,181 | ||||||||||||
| Regulatory liability for income taxes - net | 151,829 | 142,845 | ||||||||||||
| Other regulatory liabilities | 665,396 | 533,415 | ||||||||||||
| Decommissioning | 968,910 | 931,729 | ||||||||||||
| Pension and other postretirement liabilities | 125,412 | 109,816 | ||||||||||||
| Long-term debt | 705,259 | 548,097 | ||||||||||||
| Other | 61,295 | 34,602 | ||||||||||||
| TOTAL | 3,076,838 | 3,162,648 | ||||||||||||
| Commitments and Contingencies | ||||||||||||||
| COMMON EQUITY | ||||||||||||||
Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2020 and 2019 | 951,850 | 601,850 | ||||||||||||
| Retained earnings | 128,696 | 110,218 | ||||||||||||
| TOTAL | 1,080,546 | 712,068 | ||||||||||||
| TOTAL LIABILITIES AND EQUITY | $4,413,968 | $3,982,695 | ||||||||||||
| See Notes to Financial Statements. | ||||||||||||||
451
| SYSTEM ENERGY RESOURCES, INC. | |||||||||||||||||
| STATEMENTS OF CHANGES IN COMMON EQUITY | |||||||||||||||||
| For the Years Ended December 31, 2020, 2019, and 2018 | |||||||||||||||||
| Common Equity | |||||||||||||||||
| Common Stock | Retained Earnings | Total | |||||||||||||||
| (In Thousands) | |||||||||||||||||
| Balance at December 31, 2017 | $658,350 | $52,459 | $710,809 | ||||||||||||||
| Net income | — | 94,109 | 94,109 | ||||||||||||||
| Common stock dividends and distributions | (56,500) | (11,220) | (67,720) | ||||||||||||||
| Balance at December 31, 2018 | $601,850 | $135,348 | $737,198 | ||||||||||||||
| Net income | — | 99,120 | 99,120 | ||||||||||||||
| Common stock dividends and distributions | — | (124,250) | (124,250) | ||||||||||||||
| Balance at December 31, 2019 | $601,850 | $110,218 | $712,068 | ||||||||||||||
| Net income | — | 99,131 | 99,131 | ||||||||||||||
| Capital contribution from parent | 350,000 | — | 350,000 | ||||||||||||||
| Common stock dividends and distributions | — | (80,653) | (80,653) | ||||||||||||||
| Balance at December 31, 2020 | $951,850 | $128,696 | $1,080,546 | ||||||||||||||
| See Notes to Financial Statements. | |||||||||||||||||
452
| SYSTEM ENERGY RESOURCES, INC. | |||||||||||||||||||||||||||||
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2017 | 2016 | |||||||||||||||||||||||||
| (Dollars In Thousands) | |||||||||||||||||||||||||||||
| Operating revenues | $495,458 | $573,410 | $456,707 | $633,458 | $548,291 | ||||||||||||||||||||||||
| Net income | $99,131 | $99,120 | $94,109 | $78,596 | $96,744 | ||||||||||||||||||||||||
| Total assets | $4,413,968 | $3,982,695 | $3,848,814 | $3,938,887 | $3,927,712 | ||||||||||||||||||||||||
| Long-term obligations (a) | $705,259 | $548,097 | $630,744 | $466,484 | $501,129 | ||||||||||||||||||||||||
| Electric energy sales (GWh) | 5,849 | 9,940 | 6,264 | 6,675 | 5,384 | ||||||||||||||||||||||||
| (a) Includes long-term debt (excluding currently maturing debt). | |||||||||||||||||||||||||||||
453
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 “Entergy Wholesale Commodities - 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 2020 are discussed in Part I. Item 1. - Entergy’s Business under the sections titled “Retail Rate Regulation,” “Environmental Regulation,” and “Litigation” and “Impairment of Long-lived Assets” in Note 14 to the financial statements.
Item 4. Mine Safety Disclosures
Not applicable.
INFORMATION ABOUT EXECUTIVE OFFICERS OF ENTERGY CORPORATION
Executive Officers
| Name | Age | Position | Period | |||||||||||||||||
Leo P. Denault (a) | 61 | Chairman of the Board and Chief Executive Officer of Entergy Corporation | 2013-Present | |||||||||||||||||
A. Christopher Bakken, III (a) | 59 | Executive Vice President and Chief Nuclear Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy | 2016-Present | |||||||||||||||||
Project Director, Hinkley Point C of EDF Energy | 2009-2016 | |||||||||||||||||||
Marcus V. Brown (a) | 59 | 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 | |||||||||||||||||
Andrew S. Marsh (a) | 49 | Executive Vice President and Chief Financial Officer of Entergy Corporation | 2013-Present | |||||||||||||||||
Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | 2013-Present | |||||||||||||||||||
Chief Financial Officer of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | 2014-Present | |||||||||||||||||||
454
| Name | Age | Position | Period | |||||||||||||||||
Roderick K. West (a) | 52 | 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 | |||||||||||||||||||
President and Chief Executive Officer of Entergy New Orleans | 2018 | |||||||||||||||||||
Executive Vice President of Entergy Corporation | 2010-2017 | |||||||||||||||||||
Chief Administrative Officer of Entergy Corporation | 2010-2016 | |||||||||||||||||||
Paul D. Hinnenkamp (a) | 59 | Executive Vice President and Chief Operating Officer of Entergy Corporation | 2017-Present | |||||||||||||||||
Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas | 2015-Present | |||||||||||||||||||
Senior Vice President and Chief Operating Officer of Entergy Corporation | 2015-2017 | |||||||||||||||||||
Senior Vice President, Capital Project Management and Technology of Entergy Services, Inc. | 2015 | |||||||||||||||||||
| Kathryn A. Collins | 57 | Senior Vice President and Chief Human Resources Officer, Entergy Corporation | 2020-Present | |||||||||||||||||
| Chief Human Resources Officer, Arcosa, Inc. | 2018-2020 | |||||||||||||||||||
| Vice President, Human Resources, Trinity, Inc. | 2014-2018 | |||||||||||||||||||
Julie E. Harbert (a) | 47 | Senior Vice President, Corporate Business Services of Entergy Corporation | 2019-Present | |||||||||||||||||
Vice President, Shared Services of Entergy Services, Inc. | 2017-2019 | |||||||||||||||||||
Senior Vice President, Global Business Services of Philips Health Tech | 2015-2017 | |||||||||||||||||||
Kimberly A. Fontan (a) | 47 | 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-Present | |||||||||||||||||
Vice President, System Planning of Entergy Services, Inc. | 2017-2019 | |||||||||||||||||||
Vice President, Regulatory Services of Entergy Services, Inc. | 2015-2017 | |||||||||||||||||||
Peter S. Norgeot, Jr. (a) | 55 | Senior Vice President, Transformation of Entergy Corporation | 2018-Present | |||||||||||||||||
Senior Vice President, Power Generation of Entergy Services | 2017-2018 | |||||||||||||||||||
Vice President, Fossil Generation of Entergy Services | 2015-2017 | |||||||||||||||||||
(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, 2020.
455
PART II
Item 5. Market for Registrants’ Common Equity and Related Stockholder Matters
Entergy Corporation
The shares of Entergy Corporation’s common stock are listed on the New York Stock and Chicago Stock Exchanges under the ticker symbol ETR. As of January 31, 2021, there were 22,817 stockholders of record of Entergy Corporation.
Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities (1)
| Period | Total Number of Shares Purchased | Average Price Paid per Share | Total Number of Shares Purchased as Part of a Publicly Announced Plan | Maximum $ Amount of Shares that May Yet be Purchased Under a Plan (2) | |||||||||||||||||||||||||
| 10/01/2020 - 10/31/2020 | — | $— | — | $350,052,918 | |||||||||||||||||||||||||
| 11/01/2020 - 11/30/2020 | — | $— | — | $350,052,918 | |||||||||||||||||||||||||
| 12/01/2020 - 12/31/2020 | — | $— | — | $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 2020, Entergy withheld 151,159 shares of its common stock at $126.31 per share, 79,153 shares of its common stock at $129.55 per share, 41,167 shares of its common stock at $131.52 per share, 2,269 shares of its common stock at $124.28 per share, 1,331 shares of its common stock at $123.74 per share, 1,088 shares of its common stock at $102.93 per share, 441 shares of its common stock at $132.19 per share, 71 shares of its common stock at $86.51 per share, 31 shares of its common stock at $115.90 per share, and 19 shares of its common stock at $86.74 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 plan 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. Information with respect to restrictions that limit the ability of the Registrant Subsidiaries to pay dividends or distributions is presented in Note 7 to the financial statements.
456
Item 6. Selected Financial Data
Refer to “SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, LLC AND SUBSIDIARIES, ENTERGY LOUISIANA, LLC AND SUBSIDIARIES, ENTERGY MISSISSIPPI, LLC, ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES, ENTERGY TEXAS, INC. AND SUBSIDIARIES, and SYSTEM ENERGY RESOURCES, INC.” which follow each company’s financial statements in this report, for information with respect to selected financial data and certain operating statistics.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Refer to “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, LLC AND SUBSIDIARIES, ENTERGY LOUISIANA, LLC AND SUBSIDIARIES, ENTERGY MISSISSIPPI, LLC, 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, 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, 2020, 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 (individually “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.
457
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 (individually “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, 2020. 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, 2020.
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 Controls 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, 2020 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
458
Attestation Report of Registered Public Accounting Firm
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors of
Entergy Corporation and Subsidiaries
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2020, 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, 2020, 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, 2020 of the Corporation and our report dated February 26, 2021 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Item 9A, Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2021
459
PART III
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 7, 2021, and is incorporated herein by reference.
All officers and directors listed below held the specified positions with their respective companies as of the date of filing this report, unless otherwise noted.
| Name | Age | Position | Period | |||||||||||||||||
| Entergy Arkansas, LLC | ||||||||||||||||||||
| Directors | ||||||||||||||||||||
Laura R. Landreaux | 47 | President and Chief Executive Officer of Entergy Arkansas | 2018-Present | |||||||||||||||||
Director of Entergy Arkansas | 2018-Present | |||||||||||||||||||
Operational Finance Director of Entergy Arkansas | 2017-2018 | |||||||||||||||||||
Vice President, Regulatory Affairs of Entergy Arkansas | 2014-2017 | |||||||||||||||||||
Paul D. Hinnenkamp | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Andrew S. Marsh | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Roderick K. West | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
| Officers | ||||||||||||||||||||
A. Christopher Bakken, III | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Marcus V. Brown | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Leo P. Denault | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Paul D. Hinnenkamp | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Laura R. Landreaux | See information under the Entergy Arkansas Directors Section above. | |||||||||||||||||||
Andrew S. Marsh | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Kimberly A. Fontan | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Roderick K. West | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
460
| ENTERGY LOUISIANA, LLC | ||||||||||||||||||||
| Directors | ||||||||||||||||||||
Phillip R. May, Jr. | 58 | President and Chief Executive Officer of Entergy Louisiana | 2013-Present | |||||||||||||||||
Director of Entergy Louisiana | 2013-Present | |||||||||||||||||||
Paul D. Hinnenkamp | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Andrew S. Marsh | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Roderick K. West | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
| Officers | ||||||||||||||||||||
A. Christopher Bakken, III | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Marcus V. Brown | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Leo P. Denault | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Paul D. Hinnenkamp | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Andrew S. Marsh | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Phillip R. May, Jr. | See information under the Entergy Louisiana Directors Section above. | |||||||||||||||||||
Kimberly A. Fontan | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Roderick K. West | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
| ENTERGY MISSISSIPPI, LLC | ||||||||||||||||||||
| Directors | ||||||||||||||||||||
Haley R. Fisackerly | 55 | President and Chief Executive Officer of Entergy Mississippi | 2008-Present | |||||||||||||||||
Director of Entergy Mississippi | 2008-Present | |||||||||||||||||||
Paul D. Hinnenkamp | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Andrew S. Marsh | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Roderick K. West | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
461
| Officers | ||||||||||||||||||||
Marcus V. Brown | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Leo P. Denault | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Haley R. Fisackerly | See information under the Entergy Mississippi Directors Section above. | |||||||||||||||||||
Paul D. Hinnenkamp | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Andrew S. Marsh | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Kimberly A. Fontan | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Roderick K. West | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
| ENTERGY NEW ORLEANS, LLC | ||||||||||||||||||||
| Directors | ||||||||||||||||||||
David D. Ellis | 52 | President and Chief Executive Officer of Entergy New Orleans | 2018-Present | |||||||||||||||||
Director of Entergy New Orleans | 2018-Present | |||||||||||||||||||
President and Chief Executive Officer, Global Power Technologies | 2018 | |||||||||||||||||||
Managing Director and Chairman of Comverge International, Inc. | 2010-2017 | |||||||||||||||||||
Paul D. Hinnenkamp | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Andrew S. Marsh | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Roderick K. West | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
| Officers | ||||||||||||||||||||
Marcus V. Brown | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Leo P. Denault | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
David D. Ellis | See information under the Entergy New Orleans Directors Section above. | |||||||||||||||||||
Paul D. Hinnenkamp | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Andrew S. Marsh | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Kimberly A. Fontan | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Roderick K. West | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
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| ENTERGY TEXAS, INC. | ||||||||||||||||||||
| Directors | ||||||||||||||||||||
Sallie T. Rainer | 58 | President and Chief Executive Officer of Entergy Texas | 2012-Present | |||||||||||||||||
Director of Entergy Texas | 2012-Present | |||||||||||||||||||
Paul D. Hinnenkamp | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Andrew S. Marsh | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Roderick K. West | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
| Officers | ||||||||||||||||||||
Marcus V. Brown | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Leo P. Denault | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Paul D. Hinnenkamp | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Andrew S. Marsh | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Kimberly A. Fontan | See information under the Information about Executive Officers of Entergy Corporation in Part I. | |||||||||||||||||||
Sallie T. Rainer | See information under the Entergy Texas Directors Section above. | |||||||||||||||||||
Roderick K. West | 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, LLC, Entergy Louisiana, LLC, Entergy Mississippi, LLC and Entergy New Orleans, LLC 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 at the annual organizational meeting of the 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, 2020.
Corporate Governance Guidelines and Committee Charters
Each of the Audit, Corporate Governance, and Personnel Committees of Entergy Corporation’s Board of Directors operates under a written charter. In addition, the Board has adopted Corporate Governance Guidelines. Each charter and the guidelines are available through Entergy’s website (www.entergy.com) or upon written request.
Audit Committee of the Entergy Corporation Board
The following directors are members of the Audit Committee of Entergy Corporation’s Board of Directors:
Patrick J. Condon (Chairman)
Philip L. Frederickson
M. Elise Hyland
Karen A. Puckett
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All Audit Committee members are independent. In addition to the general independence requirements of the NYSE, all Audit Committee members must meet the heightened independence standards imposed by the SEC and NYSE. All Audit Committee members possess the level of financial literacy required by the NYSE rules and the Board has determined that Messrs. Condon and Frederickson satisfy the financial expertise requirements of the NYSE and have the requisite experience to be designated an audit committee financial expert as that term is defined by the rules of the SEC.
Code of Ethics
Effective October 2018, the Entergy Corporation Board of Directors adopted a Code of Business Conduct and Ethics that applies to members of the Entergy Corporation Board of Directors and all Entergy officers and employees. The Code of Business Conduct and Ethics includes Special Provisions Relating to Principal Executive Officer and Senior Financial Officers. It is to be read in conjunction with Entergy’s omnibus code of integrity under which Entergy operates, called the Code of Entegrity, as well as system policies. All employees are expected to abide by the Codes. Non-bargaining employees are required to acknowledge annually that they understand and abide by the Code of Entegrity. The Code of Business Conduct and Ethics, including any amendments or any waivers thereto, and the Code of Entegrity are available through Entergy’s website (www.entergy.com) or upon written request.
Nominations to the Entergy Corporation Board of Directors; Nominating Procedure
Shareholders wishing to recommend a candidate to the Corporate Governance Committee should do so by submitting the recommendation in writing to Entergy Corporation’s Secretary at 639 Loyola Avenue, P.O. Box 61000, New Orleans, LA 70161, and it will be forwarded to the Corporate Governance Committee members for their consideration. Any recommendation should include:
•the number of shares of Entergy Corporation stock held by the shareholder;
•the name and address of the candidate;
•a brief biographical description of the candidate, including his or her occupation for at least the last five years, and a statement of the qualifications of the candidate, taking into account the qualification requirements discussed in the Proxy Statement under “Board of Directors - Identifying Director Candidates” and
•the candidate’s signed consent to be named in the Proxy Statement and a representation of such candidates’ intent to serve as a director for the entire term if elected.
Once the Corporate Governance Committee receives the recommendation, it may request additional information from the candidate about the candidate’s independence, qualifications, and other information that would assist the Corporate Governance Committee in evaluating the candidate, as well as certain information that must be disclosed about the candidate in the Proxy Statement, if nominated. The Corporate Governance Committee will apply the same standards in considering director candidates recommended by shareholders as it applies to other candidates.
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Item 11. Executive Compensation
ENTERGY CORPORATION
Information concerning compensation earned by the directors and officers of Entergy Corporation is set forth in its Proxy Statement, to be filed in connection with the Annual Meeting of Shareholders to be held May 7, 2021, under the headings “Compensation Discussion and Analysis,” “Annual Compensation Programs Risk Assessment,” “Executive Compensation Tables,” “Pay Ratio Disclosure,” “Our 2021 Director Nominees,” and “2020 Non-Employee Director Compensation,” all of which information is incorporated herein by reference. References in this section to the “Company” refer to Entergy Corporation.
ENTERGY ARKANSAS, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND ENTERGY TEXAS
COMPENSATION DISCUSSION AND ANALYSIS
This Compensation Discussion and Analysis describes Entergy Corporation’s executive compensation policies, programs, philosophy and decisions regarding the Named Executive Officers (“NEOs”) for 2020. It also explains how and why the Personnel Committee of Entergy Corporation’s Board of Directors arrived at the specific compensation decisions involving the NEOs in 2020 who were:
Name(1) | Title | ||||
A. Christopher Bakken, III | Executive Vice President, Nuclear Operations/Chief Nuclear Officer | ||||
| Marcus V. Brown | Executive Vice President and General Counsel | ||||
Leo P. Denault | Chairman of the Board and Chief Executive Officer | ||||
David D. Ellis | President and Chief Executive Officer, Entergy New Orleans | ||||
Haley R. Fisackerly | President and Chief Executive Officer, Entergy Mississippi | ||||
Laura R. Landreaux | President and Chief Executive Officer, Entergy Arkansas | ||||
Andrew S. Marsh | Executive Vice President and Chief Financial Officer, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas | ||||
Phillip R. May, Jr. | President and Chief Executive Officer, Entergy Louisiana | ||||
Sallie T. Rainer | President and Chief Executive Officer, Entergy Texas | ||||
Roderick K. West | Group President, Utility Operations | ||||
(1)Messrs. Bakken, Brown, Denault, Marsh, and West 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 2020 to any of these officers for their service as NEOs of the Utility operating companies.
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Entergy Corporation’s Compensation Principles and Philosophy
Entergy Corporation’s executive compensation programs are based on a philosophy of pay for performance that supports its strategy and business objectives. It believes the executive pay programs:
•Motivate its management team to drive strong financial and operational results by linking pay to performance.
•Attract and retain a highly experienced, diverse and successful management team.
•Incentivize and reward the achievement of results that are deemed by the Personnel Committee to be consistent with the overall goals and strategic direction that the Entergy Corporation Board has approved.
•Create sustainable value for the benefit of all of Entergy Corporation’s stakeholders, including its customers, employees, communities and owners.
•Align the interests of the executives and Entergy Corporation’s investors in its long-term business strategy by directly tying the value of equity-based awards to Entergy Corporation’s stock price performance and relative total shareholder return.
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Executive Compensation Best Practices:
Entergy Corporation regularly reviews its executive compensation programs to align them with commonly viewed best practices in the market and to reflect feedback from discussions with Entergy Corporation’s investors on executive compensation.
| What Entergy Corporation Does | |||||
✓ | Executive compensation programs are highly correlated to performance and focused on long-term value creation | ||||
✓ | Double trigger for cash severance payments and equity acceleration in the event of a change in control | ||||
✓ | Clawback policy | ||||
✓ | Maximum payout capped at 200% of target for annual incentive awards and Long-Term Performance Unit Program for members of the OCE | ||||
✓ | Rigorous goal setting aligned with externally disclosed annual and multi-year financial targets | ||||
✓ | Minimum vesting periods for equity-based awards | ||||
✓ | Long-term compensation mix weighted more toward performance units than service-based equity awards | ||||
✓ | All long-term incentive compensation is settled in Entergy Corporation common stock | ||||
✓ | Rigorous stock ownership and share retention requirements | ||||
✓ | Annual Say on Pay vote | ||||
✓ | Annual Compensation Risk Assessment | ||||
| What Entergy Corporation Doesn’t Do | |||||
× | No 280G tax “gross up” payments in the event of a change in control | ||||
× | No tax “gross up” payments on any executive perquisites for members of the OCE, other than relocation benefits | ||||
× | No option repricing or cash buy-outs for underwater options without shareholder approval | ||||
× | No agreements providing for severance payments to executive officers that exceed 2.99 times annual base salary and annual incentive awards without shareholder approval | ||||
× | No unusual or excessive perquisites | ||||
× | No hedging or pledging of Entergy Corporation common stock | ||||
× | No fixed term employment agreements | ||||
× | No new officer participation in the System Executive Retirement Plan | ||||
× | No grants of supplemental service credit to newly-hired officers under any of Entergy Corporation’s non-qualified retirement plans | ||||
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How Entergy Corporation Makes Compensation Decisions
The Personnel Committee oversees the executive compensation programs and policies with the advice of its independent compensation consultant and support from Entergy Corporation’s management team.
| Personnel Committee | • | The Personnel Committee is responsible for the review and approval of all aspects of the executive compensation programs and policies. | |||||||||
• | Among its duties, the Personnel Committee is responsible for approving the compensation for all members of the OCE, including: | ||||||||||
• | Annual review of the compensation elements and mix of elements for the following year; | ||||||||||
• | Annual review and approval of incentive program design, goals and objectives for alignment with Entergy Corporation’s compensation and business strategies; | ||||||||||
• | Evaluation of Company and individual performance results in light of these goals and objectives; | ||||||||||
• | Evaluation of the competitiveness of each executive officer’s total compensation package; | ||||||||||
• | Approval of any changes to its executive officers’ compensation, including but not limited to, base salary, annual and long-term incentive award opportunities and retention programs; | ||||||||||
• | Evaluation of the performance of Entergy Corporation’s Chairman and Chief Executive Officer; and | ||||||||||
• | Reporting, at least annually, to the Entergy Corporation Board of Directors on succession planning. | ||||||||||
• | The Personnel Committee also receives reports and engages on other significant matters affecting the general employee population, including workforce diversity, inclusion and belonging, organizational health and safety. | ||||||||||
• | The Personnel Committee has the sole authority to hire its compensation consultant, approve its compensation, determine the nature and scope of its services, evaluate its performance and terminate its engagement. | ||||||||||
| Management | • | Entergy Corporation’s Chief Executive Officer and Chief Human Resources Officer (CHRO) work closely with the Personnel Committee in managing the executive compensation programs and attend meetings of the Personnel Committee. Mr. Denault and the CHRO, Kathryn Collins since she joined Entergy Corporation, attended all of the Personnel Committee meetings held in 2020. | |||||||||
• | The Chief Executive Officer reviews with the committee the performance of the members of the OCE other than himself and makes recommendations to the committee regarding compensation for these executive officers. | ||||||||||
| Independent Compensation Consultant | • | During 2020, Pay Governance, LLC (“Pay Governance”) assisted the Personnel Committee with its responsibilities related to Entergy Corporation’s executive compensation programs. | |||||||||
• | Pay Governance: | ||||||||||
• | Regularly attended meetings of the committee; | ||||||||||
• | Conducted studies of competitive compensation practices; | ||||||||||
• | Identified Entergy Corporation’s market surveys and proxy peer group; | ||||||||||
• | Provided updates on executive compensation trends and regulatory developments; | ||||||||||
• | Reviewed base salary, annual incentives and long-term incentive compensation opportunities relative to competitive practices; and | ||||||||||
• | Developed conclusions and recommendations related to the executive compensation programs for consideration by the committee. | ||||||||||
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2021 Executive Compensation Program Enhancements
Annual Incentive Awards. Feedback from Entergy Corporation’s investors has indicated that environmental, social and governance (or ESG) issues are being viewed as increasingly vital to long-term performance. In addition, investors are expecting more transparency regarding corporate ESG commitments. This echoes Entergy Corporation’s own commitment to ESG and all of its critical stakeholders. Thus, Entergy Corporation conducted a comprehensive review of its incentive program in 2020 to identify and prioritize the optimal incentive metrics – including ESG goals – to use in the 2021 program. Historically, Entergy Corporation has used two financial measures to determine the Entergy Achievement Multiplier (“EAM”), which is the performance metric used to determine the maximum funding available for annual incentive awards. ESG and other performance metrics were considered in determining the allocation of incentive funds to certain workgroups and individual recipients. However, to demonstrate Entergy Corporation’s strong commitment to its ESG goals, and to more explicitly link compensation to the interests of its stakeholders, the EAM will be determined based on financial and non-financial measures beginning in 2021. Specifically, a financial measure will be weighted 60%, while quantitative and qualitative non-financial measures, including ESG metrics, will account for the remaining 40%.
Financial Measure: Keeping with the committee’s goal of aligning performance measures with financial results that link to externally communicated investor guidance, ETR Tax Adjusted earnings per share or ETR Tax Adjusted EPS will continue to be used as the financial measure to determine 60% of the EAM. ETR Tax Adjusted EPS is based on Entergy’s Adjusted Earnings Per Share (“ETR Adjusted EPS”), which is the earnings measure that is used for external guidance. ETR Adjusted EPS adjusts Entergy Corporation’s as reported (GAAP) earnings per share results to eliminate the impact of its Entergy Wholesale Commodities business, significant tax items and other non-routine items. To arrive at ETR Tax Adjusted EPS, ETR Adjusted EPS is adjusted to add back the effect of significant tax items, and to eliminate the effect of: (i) major storms, including the impact on total debt of pending securitizations, (ii) the resolution of certain unresolved regulatory litigation matters, (iii) unrealized gains or losses on equity securities, (iv) potential effects of federal income tax law changes, and (v) elective contributions to pension plans or trusts related to non-qualified postretirement benefits that deviate from original plan assumptions.
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Non-Financial Measures: The following non-financial metrics will be used to determine 40% of the EAM for 2021:
| Measure | Description | Rationale | ||||||
| Safety | Quantitative measure of serious injury and fatalities per 100 employees or contractors as defined by EEI. | •Ensures a safe and incident-free workplace is maintained for all of Entergy Corporation’s employees and contractors. | ||||||
| Diversity, Inclusion & Belonging (DIB) | Overall qualitative assessment of DIB key performance indicators assessed in the workforce, workplace and marketplace, informed by quantitative measures; progress on DIB initiatives; and responsiveness to emergent issues. | •Reinforces the commitment to be a fair and equitable work environment that is welcoming to all and allows Entergy Corporation to attract and retain superb talent, allowing it to execute its strategy to be the Premier Utility. | ||||||
•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 key initiatives and Utility CO2 emission rate outcomes. | •Reinforces Entergy Corporation’s commitment to long-term sustainability and a reduced impact on the environment. Ensures accountability for achieving its significant external commitments to reduce carbon emissions. | ||||||
| Customer Net Promoter Score | Utilize quantitative Residential Net Promoter Score benchmark survey process. | •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 Entergy Corporation’s customer relationship. | ||||||||
Targets for each of the non-financial measures will be clearly defined and will be designed to drive employee behaviors that support all four of Entergy Corporation’s stakeholders – customers, employees, communities and our owners.
Long-Term Performance Incentive Program (“LTIP”). In recent performance periods, Entergy Corporation has used two financial measures to determine awards under the LTIP – a cumulative earnings per share (EPS) measure (most recently cumulative ETR Adjusted EPS) and relative total shareholder return (“TSR”). To emphasize the importance of strong cash generation for the long-term health of its business, Entergy Corporation is replacing the EPS measure with a credit measure – adjusted FFO/Debt ratio for the 2021 – 2023 performance period. The adjusted FFO/Debt ratio is the ratio of: (i) adjusted funds from operations calculated as operating cash flow adjusted for allowance for funds used during construction, working capital and the effects of securitization revenue, and the pre-defined exclusions discussed above for the annual incentives; to (ii) total debt, excluding outstanding or pending securitization debt. The Personnel Committee decided to use this ratio 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 communities, provides low-cost access to capital markets and promotes employee confidence. Relative TSR will continue to be used as the other performance measure for the 2021 – 2023 LTIP performance period, with relative TSR weighted 80% and the credit measure weighted 20%. Relative TSR measures Entergy Corporation’s total TSR relative to the TSR of the companies in the Philadelphia Utility Index as of December 31, 2020. Targets for the LTIP performance measures will include the same exclusions that will be used to determine the annual incentive financial measure targets.
2020 Incentive Payouts
Performance measures and targets for the 2020 annual incentive awards were determined by the Personnel Committee in January 2020 and the targets and measures for the 2018 – 2020 LTIP performance cycle were
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established in January 2018. In January 2021, the Personnel Committee certified the results for the EAM for the 2020 annual incentive awards and the 2018 – 2020 LTIP performance cycle. The Personnel Committee did not make any adjustments to the targets for either program for the impact of COVID-19 on Entergy Corporation and its subsidiaries.
Entergy Corporation believes the 2020 incentive pay outcomes for the NEOs demonstrate the application of its pay for performance philosophy.
Annual Incentive Awards
The Personnel Committee determined that the 2020 EAM would be based on two equally weighted performance metrics:
•ETR Tax Adjusted Earnings Per Share (“ETR Tax Adjusted EPS”): Entergy Corporation uses a single non-GAAP earnings measure for guidance and investor reporting purposes that reflects its ongoing business. This measure, Entergy Adjusted Earnings Per Share (“ETR Adjusted EPS”) adjusts Entergy Corporation’s as reported (GAAP) earnings per share results to eliminate the impact of its Entergy Wholesale Commodities business, significant tax items and other non-routine items. ETR Tax Adjusted EPS is based on the externally reported ETR Adjusted EPS, which is then adjusted to add back the effect of significant tax items, and to eliminate the effect of major storms, the resolution of certain unresolved regulatory litigation matters, changes in federal income tax law and unrealized gains or losses on equity securities (the “Pre-Determined Exclusions”), as well as other items the Personnel Committee may consider appropriate adjustments based on management accountability and business rationale.
•Entergy Adjusted Operating Cash Flow (“ETR Adjusted OCF”): ETR Adjusted OCF is calculated based on Entergy Corporation’s as-reported (GAAP) operating cash flow, adjusted to eliminate the effect of any Pre-Determined Exclusions.
The 2020 annual incentive award targets and results determined by the Personnel Committee were:
| Annual Incentive Program Performance Goals | 2020 Targets | 2020 Results | ||||||
| ETR Tax Adjusted EPS | $5.60 | $6.90 | ||||||
| ETR Adjusted OCF ($ billions) | $3.450 | $3.127 | ||||||
| EAM as a percentage of target | 100% | 120% | ||||||
| Average NEO Payout (as a percentage of target) | 124% | |||||||
In January 2021, the Personnel Committee determined that ETR Adjusted EPS exceeded the maximum by $1.30, but fell short of achieving its ETR Adjusted OCF target of $3.45 billion by approximately $323 million, leading to a preliminary EAM of 118%. In recognition of management’s success in achieving positive outcomes in 2020 on certain strategic efforts deemed critical to Entergy Corporation’s long-term success, the committee exercised its discretion to increase the EAM by 2% to 120%. Based on each NEO’s individual accountabilities and accomplishments, the committee then determined individual annual incentive awards of 115% to 150% of the target opportunity for each of the NEOs.
Long-Term Performance Unit Program
In January 2018, the Personnel Committee chose relative TSR and Cumulative Adjusted Utility, Plant & Other Earnings Per Share (“Cumulative Adjusted UP&O EPS”), each weighted equally, as the performance measures for the 2018 – 2020 LTIP performance period. Cumulative Adjusted UP&O EPS adjusts Entergy Corporation’s cumulative operational Utility, Parent & Other results to eliminate the impact of tax items and weather. Similar to the way targets are established for the annual incentive awards, the relative TSR and Cumulative Adjusted UP&O EPS performance measures were established by the Personnel Committee after the Board’s review of Entergy Corporation’s strategic plan.
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The targets and results for the 2018 – 2020 LTIP performance period as determined by the Personnel Committee were:
| LTIP Results | 2018 - 2020 LTIP Target | 2018 - 2020 LTIP Result | ||||||
| Relative TSR | Median | 2nd Quartile | ||||||
| Cumulative Adjusted UP&O EPS | $15.20 | $15.25 | ||||||
| Payout (as a percentage of target) | 100% | 126% | ||||||
What Entergy Corporation Pays and Why
Principal Executive Compensation Elements
The principal components of Entergy Corporation’s 2020 executive compensation programs and the purpose of each component were:
| Compensation Element | Form | Performance Metrics | Primary Purpose | Vesting Period | Subject to Clawback | ||||||||||||
| Base Salary | Cash | N/A | Provides a base level of competitive cash compensation for executive talent. | N/A | N/A | ||||||||||||
| Annual Incentive | Cash | ETR Tax Adjusted EPS (50%) | Motivates and rewards executives for performance on key financial measures during the year. | 1 year | ü | ||||||||||||
| ETR Adjusted OCF (50%) | |||||||||||||||||
| Long-Term Performance Units | Equity | Relative TSR (80%) | Focuses the executive officers on building long-term shareholder value, growing earnings and increases executives’ ownership of Entergy Corporation common stock. | 3 years | ü | ||||||||||||
| Cumulative ETR Adjusted EPS (20%) | |||||||||||||||||
| Stock Options | Equity | N/A | Align interests of executives with long-term shareholder value, provide competitive compensation, and increase executives’ ownership in Entergy Corporation common stock. | 3 years | ü | ||||||||||||
| Restricted Stock | Equity | N/A | Aligns interests of executives with long-term shareholder value, provides competitive compensation, retains executive talent and increases the executives’ ownership in Entergy Corporation common stock. | 3 years | ü | ||||||||||||
Competitive Positioning
Market Data for Compensation Comparison
Annually, the Personnel Committee reviews:
•Published and private compensation survey data compiled by Pay Governance, the Personnel Committee’s independent compensation consultant;
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•Both utility and general industry data to determine total cash compensation (base salary and annual incentive) for non-industry specific roles;
•Data from utility companies to determine total cash compensation for management roles that are utility-specific, such as Group President, Utility Operations; and
•Utility market data to determine long-term incentives for all positions.
How the Personnel Committee Uses the Market Data
The Personnel Committee uses this survey data to develop compensation opportunities that are designed to deliver total direct compensation (“TDC”) within a targeted range of approximately the 50th percentile of the surveyed companies in the aggregate. In most cases, the committee considers its objectives to have been met if Entergy Corporation’s Chief Executive Officer and the eight other executive officers (including the applicable NEOs) who constitute the OCE each has a target compensation opportunity that falls within a targeted range of 85% - 115% of the 50th percentile of the survey data. In general, compensation levels for an executive officer who is new to a position tend to be at the lower end of the competitive range, while seasoned executive officers whose experience and skill set are viewed as critical to retain would be positioned at the higher end of the competitive range. Generally, differences in the levels of TDC among the NEOs are primarily driven by the scope of their responsibilities, differences in the competitive market pay range for similar positions, performance and considerations of internal pay equity.
Proxy Peer Group
Although the survey data described above are the primary data used in benchmarking compensation, the committee uses compensation information from the companies included in the Philadelphia Utility Index to evaluate the overall reasonableness of Entergy Corporation’s compensation programs and to determine relative TSR for the 2020 - 2022 LTIP performance period. The companies included in the Philadelphia Utility Index at the time the Personnel Committee approved the 2020 compensation model and framework were:
AES Corporation | El Paso Electric Co.* | ||||||||||
Ameren Corporation | Eversource Energy | ||||||||||
American Electric Power Co. Inc. | Exelon Corporation | ||||||||||
| American Water Works Company, Inc. | FirstEnergy Corporation | ||||||||||
CenterPoint Energy Inc. | NextEra Energy, Inc. | ||||||||||
Consolidated Edison Inc. | Pinnacle West Capital Corporation | ||||||||||
Dominion Energy | Public Service Enterprise Group, Inc. | ||||||||||
DTE Energy Company | Southern Company | ||||||||||
Duke Energy Corporation | Xcel Energy, Inc. | ||||||||||
Edison International | |||||||||||
*El Paso Electric Co. is no longer included in the Philadelphia Utility Index.
2020 Compensation Decisions
Base Salary
When setting the base salaries of the NEOs who are members of the OCE, the Personnel Committee generally targets the range of compensation paid to similarly situated executive officers of the companies included in the market data previously discussed in this Compensation Discussion and Analysis under “Competitive Positioning.” For the other NEOs, their salaries are established by their immediate supervisors using the same criteria. The base salaries of the NEOs are considered annually as part of the performance review process, and upon a NEO’s promotion or other change in job responsibilities. Based on this review in 2020 and after reviewing the market data above, all of the NEOs, other than Mr. Denault, received increases in their base salaries ranging from approximately 2.5% to 6.15%. In 2020, Mr. Denault did not receive an increase in his base salary. Instead, the
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Personnel Committee increased Mr. Denault’s TDC by increasing his long-term incentive target opportunities; thereby, increasing the portion of his compensation that is “at risk” and further aligning his interests with those of Entergy Corporation’s shareholders.
The following table sets forth the 2019 and 2020 base salaries for the Named Executive Officers. Changes in base salaries for 2020 were effective in April.
| Named Executive Officer | 2019 Base Salary | 2020 Base Salary | ||||||||||||
| A. Christopher Bakken, III | $654,078 | $673,700 | ||||||||||||
| Marcus V. Brown | $666,250 | $690,000 | ||||||||||||
| Leo P. Denault | $1,260,000 | $1,260,000 | ||||||||||||
| David D. Ellis | $313,388 | $321,849 | ||||||||||||
| Haley R. Fisackerly | $376,023 | $388,244 | ||||||||||||
| Laura R. Landreaux | $316,470 | $326,755 | ||||||||||||
| Andrew S. Marsh | $650,000 | $690,000 | ||||||||||||
| Phillip R. May, Jr. | $392,043 | $404,784 | ||||||||||||
| Sallie T. Rainer | $347,422 | $358,713 | ||||||||||||
| Roderick K. West | $714,013 | $731,863 | ||||||||||||
Annual Incentive Compensation
In 2020, annual incentive awards were tied to Entergy Corporation’s financial and operational performance through the EAM. Entergy Corporation uses the following process to determine annual incentive awards:
•Establish Performance Measures to Determine EAM Pool. Annually, the Personnel Committee engages in a rigorous process to determine the performance measures used to determine the EAM. The Personnel Committee’s goal is to establish measures that are consistent with Entergy Corporation’s strategy and business objectives for the upcoming year, as reflected in its strategic plan, and are designed to drive results that represent a high level of achievement. These measures are approved based on a comprehensive review of Entergy Corporation’s strategic plan by its full Board of Directors conducted in December of the preceding year and updated in January to reflect key drivers of anticipated changes in performance from the preceding year.
•Establish Target Achievement Levels. In January, after Entergy Corporation’s strategic plan is updated to reflect any changes from that reviewed in December, the Personnel Committee establishes the specific targets that must be achieved for each performance measure. The Personnel Committee also seeks to assure that the targets:
◦Take into account changes in the business environment and specific challenges facing Entergy Corporation;
◦Reflect an appropriate balancing of the various risks and opportunities recognized at the time the targets are set; and
◦Are aligned with external expectations communicated to Entergy Corporation’s shareholders.
•Establish NEO Target Opportunities. In January of each year, the Personnel Committee establishes the target opportunities for the members of the OCE based on its review of the competitive analysis of job-specific market data prepared by Pay Governance as well as the officer’s role, individual performance and internal equity considerations. For the NEOs who are members of the OCE (Messrs. Bakken, Brown, Denault, Marsh and West), target award opportunities are established based on these factors. For the other NEOs, target award opportunities are determined based on their management level within the Entergy organization. Executive management levels at Entergy Corporation range from ML level 1 through ML level 4 (the “ML 1-4 Officers”). At December 31, 2020, Mr. May held a Level 3 position, and Mr. Ellis,
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Mr. Fisackerly, Ms. Landreaux and Ms. Rainer held Level 4 positions. Accordingly, their respective incentive award opportunities differ from one another based on either their management level or the external market data developed by the Committee’s independent compensation consultant. The 2020 target opportunities were increased for Mr. Bakken, Mr. Brown, Mr. Marsh and Mr. West to align more closely with market data and internal pay equity. Mr. Denault’s 2020 target opportunity was unchanged from the level set in 2019 due to the Personnel Committee’s decision to increase his TDC by increasing his long-term incentive target opportunities. The target levels for the other NEOs are comparable to the levels set for 2019.
•Determine the EAM. In January, after the end of the fiscal year, the Finance and Personnel Committees jointly review Entergy Corporation’s financial results and the Personnel Committee determines the EAM, which represents the level of success in achieving the performance objectives established by the committee and determines the maximum funding level of the annual incentive plan, as a percentage of the total target opportunity.
•Determine Annual Incentive Awards. To determine individual executive officer awards under the annual incentive plan, the Personnel Committee considers not only each executive’s role in executing on Entergy Corporation’s strategies and delivering the financial performance achieved, but also the individual’s accountability for any challenges Entergy Corporation experienced during the year.
Establishing 2020 Financial Measures and Targets
Using the process described above, in December 2019, the Personnel Committee decided to use ETR Tax Adjusted EPS and ETR Adjusted OCF, with each measure weighted equally, as the performance measures for determining the 2020 EAM pool. ETR Tax Adjusted EPS is based on ETR Adjusted EPS, which is the primary earnings measure used by Entergy Corporation externally and the measure on which it provides annual earnings guidance. To arrive at ETR Tax Adjusted EPS, ETR Adjusted EPS is adjusted to add back the effect of any significant tax items that were excluded to arrive at ETR Adjusted EPS and to eliminate the effects, if any, of the Pre-Determined Exclusions. ETR Adjusted OCF is calculated based on Entergy Corporation’s as-reported (GAAP) operating cash flow, adjusted to eliminate the effect of any significant non-routine items not representative of the ongoing business, such as items associated with the decisions to sell or close the Entergy Wholesale Commodities nuclear plants, and any Pre-Determined Exclusions. The Personnel Committee determined that ETR Tax Adjusted EPS and ETR Adjusted OCF were the appropriate metrics to use for annual incentives in 2020 because:
•They are based on objective financial measures that Entergy Corporation and its investors consider to be important in evaluating its financial performance;
•They are based on the same metrics we use for internal and external financial reporting; and
•They provide both discipline and transparency.
The Personnel Committee considered it appropriate to use ETR Tax Adjusted EPS, which adds back the effect of significant tax items that may have been excluded from ETR Adjusted EPS, as the earnings measure because of the significant financial benefits to Entergy Corporation resulting from such tax items and the management effort required to achieve them. The Personnel Committee also considered the appropriateness of excluding the effect of each of the specific Pre-Determined Exclusions it had identified from each of the financial measures. It viewed the exclusion of major storms as appropriate because although Entergy Corporation includes estimates for storm costs in its financial plan, it does not include estimates for a major storm event, such as a hurricane. The Personnel Committee considered the exclusion of any unanticipated effects of the tax reform legislation adopted at the end of 2017 to be appropriate because of the lingering uncertainty around those effects and the inability of management to impact those results. The Personnel Committee approved the other exclusions from reported results - for the impact of certain legacy unresolved regulatory litigation and unanticipated unrealized gains and losses on securities held by Entergy Corporation’s nuclear decommissioning trusts - primarily because of management’s inability to influence either of the related outcomes. The Personnel Committee further provided that in determining the 2020 EAM, the 2020 results would be subject to adjustment for other items the committee may consider appropriate in its review of 2020 performance, considering management accountability and business
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rationale, and the EAM as so calculated would be subject to further adjustment at the committee’s discretion based on business considerations.
In determining the targets to set for 2020, the Personnel Committee reviewed anticipated drivers and risks to Entergy Corporation’s expectations for its adjusted earnings and operating cash flow for 2020 as set forth in its financial plan, as well as factors driving the strong financial performance achieved in 2019. The Personnel Committee confirmed that the proposed plan targets for ETR Tax Adjusted EPS and ETR Adjusted OCF reflected significant growth in the core earnings and consolidated operating cash flow measures underlying the annual incentive plan targets. The Personnel Committee also noted that while the 2020 ETR Tax Adjusted EPS target was less than the 2019 results, the 2020 target represented significant growth in the underlying ETR Adjusted EPS both from 2019 results and from the 2019 target, with the primary driver of the higher results in 2019 being certain one-time tax benefits that would not be recurring in 2020. The Personnel Committee also considered the potential impact of a wide range of identified risks and opportunities and confirmed that the related annual incentive plan targets reflected a reasonable balancing of such risks and opportunities and an appropriate degree of challenge.
2020 Performance Assessment
The following table shows the 2020 annual incentive plan performance metrics and targets established by the Personnel Committee to determine the 2020 EAM and 2020 results:
Annual Incentive Plan Targets and Results
Performance Goals(1) | |||||||||||||||||
| Weight | Minimum | Target | Maximum | 2020 Results | |||||||||||||
| ETR Tax Adjusted EPS ($) | 50% | 5.04 | 5.60 | 6.16 | 6.90 | ||||||||||||
ETR Adjusted OCF ($ billions) | 50% | 3.070 | 3.450 | 3.830 | 3.127 | ||||||||||||
| EAM as % of Target | 25% | 100% | 200% | 120% | |||||||||||||
(1)Payouts for performance between achievement levels are calculated using straight-line interpolation, with no payout for performance below the minimum achievement level for both performance measures.
In January 2021, the Finance and Personnel Committees jointly reviewed Entergy Corporation’s financial results against the performance objectives reflected in the table above. Management discussed with the committees Entergy Corporation’s ETR Tax Adjusted EPS and the ETR Adjusted OCF results for 2020, including primary factors explaining how those results compared to the 2020 business plan and annual incentive plan targets set in January 2020. ETR Tax Adjusted EPS exceeded the ETR Tax Adjusted EPS target of $5.60 per share by $1.30, but management fell short of achieving its ETR Adjusted OCF target of $3.45 billion by approximately $323 million, leading to a preliminary EAM of 118%. These results reflected a positive adjustment of $0.10 to ETR Tax Adjusted EPS and a positive adjustment of $274 million to ETR Adjusted OCF for the effects on earnings and operational cash flow of major storms impacting Entergy Corporation’s service area during 2020, consistent with the Pre-Determined Exclusions approved when the targets were set at the beginning of the year. The results also reflected a positive adjustment of $100 million to ETR Adjusted OCF for the effect on operational cash flow of additional voluntary contributions made to Entergy Corporation’s pension plan in 2020 over and above the required level of contributions, which adjustment was made because the committee did not consider it appropriate for management to be penalized in the incentive compensation process for choosing to make such elective contributions, consistent with the Pre-Determined Exclusion for items the committee determined should be excluded based on management accountability and business rationale.
The Personnel Committee considered whether 2020 ETR Tax Adjusted EPS or ETR Adjusted OCF should be adjusted for any other factors that had impacted 2020 results. The committee noted that 2020 revenues and cash flow had been adversely impacted by reduced sales resulting from unfavorable weather, the COVID-19 pandemic and, to a lesser extent, major storms, which collectively reduced ETR Adjusted EPS by approximately $0.71 per share, and ETR Adjusted OCF by approximately $663 million as compared to plan. In addition, the Personnel Committee noted that ETR Adjusted OCF had been further reduced by approximately $178 million due to increased customer arrearages as a result of regulatory moratoria on customer disconnects following the onset of the pandemic. As noted, both ETR Tax Adjusted EPS and ETR Adjusted OCF were adjusted to reflect the impact of
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major storms as a Pre-Determined Exclusion. However, the committee decided not to adjust the results to reflect the impact of the COVID-19 pandemic, the disconnect moratoria or the unfavorable weather experienced in 2020.
In addition to the foregoing financial results, the Personnel Committee considered management’s degree of success in achieving various operational and regulatory goals set out at the beginning of the year and in overcoming certain challenges that arose in the business during the course of the year. The committee took note of not only the many ways management had created value for all Entergy Corporation’s key stakeholders during 2020, but also the major challenges that were overcome in the process, including the COVID-19 pandemic and the challenges of responding to three hurricanes in a record-breaking storm season for the Gulf Coast. The committee also noted that despite these challenges, management had remained focused on achieving strong financial results for the benefit of all of its stakeholders while at the same time driving positive outcomes in certain areas that would contribute to Entergy Corporation’s long term sustainability, including particularly the achievement of its 2020 CO2 emissions goal, development and announcement of its goal to achieve net zero carbon emissions by 2050, and significant enhancements to its sustainability disclosure and reporting, and substantial progress in other important ESG and sustainability efforts. In recognition of these accomplishments, which the committee considers to be critical to Entergy Corporation’s long-term success, the committee exercised its discretion to increase the EAM by 2% to 120%.
To determine individual NEO annual incentive awards for the NEOs who are member of the OCE, the Personnel Committee considered individual performance in executing on Entergy Corporation’s strategies and delivering the strong financial performance achieved in 2020. In addition, the Personnel Committee considered the individual’s key accountabilities and accomplishments in relation to certain operational and regulatory challenges Entergy Corporation experienced during the year. With these considerations in mind, the Personnel Committee approved payouts ranging from 115% to 120% of target for each of the NEOs who are members of the OCE.
After the EAM was established to determine overall funding for the annual incentive awards, Entergy Corporation’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 117% of target to 150% of target for the NEOs who are not members of the OCE.
Based on the foregoing evaluation of management performance, the Named Executive Officers received the following annual incentive payouts for 2020:
| Named Executive Officer | Base Salary | Target as Percentage of Base Salary | Payout as Percentage of Target | 2020 Annual Incentive Award | ||||||||||
| A. Christopher Bakken, III | $673,700 | 75% | 115% | $581,066 | ||||||||||
| Marcus V. Brown | $690,000 | 80% | 120% | $662,400 | ||||||||||
| Leo P. Denault | $1,260,000 | 140% | 120% | $2,116,800 | ||||||||||
| David D. Ellis | $321,849 | 40% | 128% | $164,955 | ||||||||||
| Haley R. Fisackerly | $388,244 | 40% | 150% | $232,737 | ||||||||||
| Laura R. Landreaux | $326,755 | 40% | 128% | $167,153 | ||||||||||
| Andrew S. Marsh | $690,000 | 85% | 120% | $703,800 | ||||||||||
| Phillip R. May, Jr. | $404,784 | 60% | 117% | $284,881 | ||||||||||
| Sallie T. Rainer | $358,713 | 40% | 122% | $175,713 | ||||||||||
| Roderick K. West | $731,863 | 80% | 115% | $673,314 | ||||||||||
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Long-Term Incentive Compensation
Overview
Long-term incentive compensation, consisting solely of equity awards in 2020, represents the largest portion of executive officer compensation, and as noted earlier, the increase in Mr. Denault’s TDC opportunity was delivered in the form of long-term incentive compensation. Entergy Corporation believes the combination of long-term incentives it employs provides a compelling performance-based compensation opportunity, acts in retaining the senior management team, and aligns the interests of Entergy Corporation’s executive officers with the interests of its shareholders and customers by enhancing executives focus on Entergy Corporation’s long-term goals. In general, Entergy Corporation seeks to allocate the total value of long-term incentive compensation 60% to performance units and 40% to a combination of stock options and restricted stock, equally divided in value, based on the value the compensation model seeks to deliver.
For each NEO who is a member of the OCE, a dollar value is established to determine that NEO’s long-term incentive awards target. The targeted 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 January 2020, the Personnel Committee approved the 2020 long-term incentive award target amounts for each NEO with each NEO’s target amount increasing in recognition of the contributions made to Entergy Corporation in 2019. This target amount was then converted into the number of performance units, stock options and shares of restricted stock granted to each NEO based on the allocation described above.
In consultation with Entergy Corporation’s Chief Executive Officer, the Personnel Committee reviews each of the other NEO’s performance, role and responsibilities, strengths, developmental opportunities and internal equity and allocates awards of restricted stock and stock options to each of these officers based on these factors. Grants of long-term performance units for these NEOs were determined based on the average of the market data for the officers within a specific management level, without regard to the officer’s specific job function, and allocated as described above.
2020 Long-Term Incentive Award Mix
Long-Term Performance Unit Program
The NEOs are issued performance unit awards under the LTIP.
•Each performance unit represents one share of Entergy Corporation’s common stock at the end of the three-year performance period, plus dividends accrued during the performance period.
•The performance units and accrued dividends on any shares earned during the performance period are settled in shares of Entergy Corporation common stock.
•The Personnel Committee sets payout opportunities for the program at the outset of each performance period.
•No payout under this program will be made if relative TSR for the performance period falls within the lowest quartile of the peer companies in the Philadelphia Utility Index and Cumulative ETR Adjusted EPS is below the minimum performance goal.
•All shares paid out under the LTIP are required to be retained by Entergy Corporation’s officers until applicable executive stock ownership requirements are met.
The LTIP specifies a minimum, target and maximum achievement level, the achievement of which will determine the number of performance units that may be earned by each participant. For the 2020 – 2022 LTIP performance period, the Personnel Committee chose the performance measures and targets set forth below.
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2020-2022 LTIP Unit Program Period: Measures and Goals(1)
Performance Measures(1) | LTIP Measure Weight | Payout | ||||||
| Relative TSR | 80% | Minimum (25%) - Bottom of 3rd Quartile Target (100%) - Median Percentile Maximum (200%) - Top Quartile | ||||||
| Cumulative ETR Adjusted EPS | 20% | Minimum (25%) - $16.07 Target (100%) - $17.85 Maximum (200%) - $19.63 | ||||||
(1)Payouts for performance between achievement levels are calculated using straight-line interpolation, with no payouts for performance below the minimum achievement level for both performance measures.
Performance Measures
Relative TSR
•The Personnel Committee chose relative TSR as a performance measure because it reflects Entergy Corporation’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 Corporation’s TSR in relation to the TSR of the companies in the Philadelphia Utility Index. The Personnel 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 deemed to be comparable to Entergy Corporation in terms of business and scale.
Cumulative ETR Adjusted EPS
•Cumulative ETR Adjusted EPS, which adjusts Entergy Corporation’s as reported (GAAP) results to eliminate the impact of earnings or loss from Entergy Wholesale Commodities and other non-routine items, was selected in 2020 as a performance measure because the Personnel Committee wished to incentivize management to achieve steady, predictable earnings growth for Entergy Corporation over the 3 year performance period, and because it aligns with the earnings measure used to communicate Entergy Corporation’s earnings expectations externally to investors.
•In a manner similar to the way targets are established for the annual incentives, targets for the Cumulative ETR Adjusted EPS performance measure were established by the Personnel Committee after the Entergy Corporation Board’s review of Entergy’s strategic plan for the three-year period beginning in 2020 and are consistent with the earnings expectations for Entergy Corporation that are communicated to investors. These targets also incorporate the Pre-Determined Exclusions discussed previously with respect to the annual incentive measures.
Stock Options and Restricted Stock
Entergy Corporation grants stock options and shares of restricted stock because they align the interests of the executive officers with long-term shareholder value, provide competitive compensation, and increase the executives’ ownership in Entergy Corporation common stock. Generally, stock options are granted with a maximum term of ten years, and vest one-third on each of the first three anniversaries of the date of grant. The exercise price for each option granted in 2020 was $131.72, which was the closing price of Entergy Corporation’s common stock on the date of grant. Shares of restricted stock vest one-third on each of the first three anniversaries
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of the date of grant, are paid dividends which are reinvested in shares of Entergy Corporation common stock and have full voting rights. The dividend reinvestment shares are subject to forfeiture similar to the terms of the original grant.
2020 Long-Term Incentive Awards
In January 2020, the Personnel Committee granted the following long-term performance units, stock options and shares of restricted stock to each NEO. The number of long-term performance units, stock options and shares of restricted stock were determined as discussed above under “Long-Term Incentive Compensation - Overview.”
Named Executive Officer | 2020-2022 Target LTIP Units | Stock Options | Shares of Restricted Stock | ||||||||
| A. Christopher Bakken, III | 7,758 | 29,279 | 3,104 | ||||||||
| Marcus V. Brown | 7,571 | 28,574 | 3,029 | ||||||||
| Leo P. Denault | 31,263 | 117,990 | 12,505 | ||||||||
| David D. Ellis | 950 | 3,200 | 500 | ||||||||
| Haley R. Fisackerly | 950 | 4,300 | 750 | ||||||||
| Laura R. Landreaux | 950 | 4,300 | 750 | ||||||||
| Andrew S. Marsh | 9,560 | 36,079 | 3,824 | ||||||||
Phillip R. May, Jr. | 1,400 | 7,300 | 1,100 | ||||||||
| Sallie T. Rainer | 950 | 4,300 | 750 | ||||||||
| Roderick K. West | 8,401 | 31,705 | 3,361 | ||||||||
All of the performance units, shares of restricted stock and stock options granted to the NEOs in 2020 were granted pursuant to the 2019 Omnibus Incentive Plan or 2019 OIP. The 2019 OIP requires both a change in control and an involuntary job loss without cause or a resignation by the NEO for good reason within 24 months following a change in control (a “double trigger”) for the acceleration of these awards upon a change in control.
2020 LTIP Payouts
Payout for the 2018 – 2020 LTIP Performance Period. In January 2018, the Personnel Committee chose relative TSR and Cumulative Adjusted UP&O EPS as the performance measures, each weighted equally, for the 2018 – 2020 LTIP performance period. Cumulative Adjusted UP&O EPS, which adjusted Entergy Corporation’s operational Utility, Parent & Other results to eliminate the impact of tax items and weather (the “UP&O Adjustments”), was added as a performance measure because it aligned with Entergy Corporation’s externally communicated earnings measure on its core utility business and was the primary measure on which Entergy Corporation communicated its long term earnings outlooks in 2018. Similar to the way targets are established for the annual incentive program, targets for the Cumulative Adjusted UP&O EPS performance measure were established by the Personnel Committee after the Entergy Corporation Board’s review of Entergy Corporation’s strategic plan. These targets also exclude the Pre-Determined Exclusions discussed previously with respect to the annual incentive measures, as well as the UP&O Adjustments. 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:
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2018-2020 LTIP Performance Period Measures and Goals
Performance Measure(1) | LTIP Measure Weight | Payout | ||||||
| Relative TSR | 50% | Minimum (25%) - Bottom of 3rd Quartile Target (100%) - Median Percentile Maximum (200%) - Top Quartile | ||||||
| Cumulative Adjusted UP&O EPS ($) | 50% | Minimum (25%) - $13.68 Target (100%) - $15.20 Maximum (200%) - $16.72 | ||||||
(1)Payouts for performance between achievement levels are calculated using straight-line interpolation, with no payouts for performance below the minimum achievement level.
In January 2021, the Personnel Committee reviewed Entergy Corporation’s TSR and the Cumulative Adjusted UP&O EPS for the 2018 – 2020 LTIP performance period in order to determine the payout to participants based upon the performance measures and range of potential payouts for the 2018 – 2020 LTIP performance period as provided above. The committee compared Entergy Corporation’s TSR against the TSR of the companies that were included in the Philadelphia Utility Index throughout the three year performance period, which were:
| AES Corporation | Edison International | ||||||||||
| Ameren Corporation | Eversource Energy | ||||||||||
| American Electric Power Co. Inc. | Exelon Corporation | ||||||||||
| American Water Works Company, Inc. | FirstEnergy Corporation | ||||||||||
| CenterPoint Energy Inc. | NextEra Energy, Inc. | ||||||||||
| Consolidated Edison Inc. | PG&E Corporation | ||||||||||
| Dominion Energy | Public Service Enterprise Group, Inc. | ||||||||||
| DTE Energy Company | Southern Company | ||||||||||
| Duke Energy Corporation | Xcel Energy, Inc. | ||||||||||
As recommended by the Finance Committee, the Personnel Committee concluded that Entergy Corporation’s relative TSR for the 2018 – 2020 performance period was in the second quartile, and that Cumulative Adjusted UP&O EPS was $15.25, yielding a payout of 126% of target for the NEOs.
Named Executive Officer | 2018-2020 Target | Number of Shares Issued(1) | Value of Shares Actually Issued(2) | Grant Date Fair Value(3) | ||||||||||
| A. Christopher Bakken, III | 7,900 | 11,048 | $1,050,886 | $651,079 | ||||||||||
| Marcus V. Brown | 7,900 | 11,048 | $1,050,886 | $651,079 | ||||||||||
| Leo P. Denault | 42,700 | 59,718 | $5,680,376 | $3,519,121 | ||||||||||
David D. Ellis(4) | 1,100 | 1,488 | $141,539 | $90,657 | ||||||||||
| Haley R. Fisackerly | 1,650 | 2,307 | $219,442 | $135,985 | ||||||||||
Laura R. Landreaux(5) | 1,375 | 1,892 | $179,967 | $113,321 | ||||||||||
| Andrew S. Marsh | 7,900 | 11,048 | $1,050,886 | $651,079 | ||||||||||
Phillip R. May, Jr. | 2,550 | 3,566 | $339,198 | $210,158 | ||||||||||
| Sallie T. Rainer | 1,650 | 2,307 | $219,442 | $135,985 | ||||||||||
| Roderick K. West | 7,900 | 11,048 | $1,050,886 | $651,079 | ||||||||||
(1)Includes accrued dividends.
(2)Value determined based on the closing price of Entergy Corporation common stock on January 19, 2021 ($95.12), the date the Personnel Committee certified the 2018-2020 performance period results.
(3)Represents the aggregate grant date fair value calculated in accordance with applicable accounting rules as reflected in the 2018 Summary Compensation Table.
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(4)As a new hire in 2018, Mr. Ellis received a pro-rata target award opportunity for the 2018 - 2020 performance period.
(5)As a new officer in 2018, Ms. Landreaux received a pro-rata target award opportunity for the 2018 - 2020 performance period.
Benefits and Perquisites
Entergy Corporation’s NEOs are eligible to participate in or receive the following benefits:
| Plan Type | Description | ||||
| Retirement Plans | Entergy Corporation-sponsored: Entergy Retirement Plan - a tax-qualified final average pay defined benefit pension plan that covers a broad group of employees hired before July 1, 2014. 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. Pension Equalization Plan - a non-qualified pension restoration plan for a select group of management or highly compensated employees who participate in the Entergy Retirement Plan. Cash Balance Equalization Plan - a non-qualified restoration plan for a select group of management or highly compensated employees who participate in the Cash Balance Plan. System Executive Retirement Plan - a non-qualified supplemental retirement plan for individuals who became executive officers before July 1, 2014. | ||||
| Savings Plan | Entergy Corporation-sponsored 401(k) Savings Plan that covers a broad group of employees. | ||||
| 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 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. | ||||
| 2020 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 assistance. In 2020, the NEOs who are not members of the OCE also were provided in 2020 with club dues and tax gross up payments on this perquisite. For additional information regarding perquisites, see the “All Other Compensation” column in the 2020 Summary Compensation Table. | ||||
| Deferred Compensation | The NEOs are eligible to defer up to 100% of their base salary and annual incentive awards into the Entergy Corporation sponsored Executive Deferred Compensation Plan. | ||||
| Executive Disability Plan | Eligible individuals who become disabled under the terms of the plan are eligible for 65% of the difference between their annual base salary and $276,923 (i.e. the annual base salary that produces the maximum $15,000 monthly disability payment under the general long-term disability plan). | ||||
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.
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Severance and Retention Arrangements
The Personnel 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 Personnel 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 under which ML 1-4 Officers are 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 Entergy Corporation and its subsidiaries. Entergy Corporation strives to ensure that the benefits and payment levels under the System Executive Continuity Plan are consistent with market practices. Entergy Corporation’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 the System Executive Continuity Plan, see “2020 Potential Payments Upon Termination or Change in Control.”
Nuclear Retention Plan
Mr. Bakken participates in the Nuclear Retention Plan, a retention plan for officers and other leaders with expertise in the nuclear industry. The Personnel Committee authorized this plan to attract and retain key management and employee talent in the nuclear power field, a field that requires unique technical and other expertise that is in great demand in the utility industry. The plan provides for bonuses to be paid annually over a three-year service period with the bonus opportunity dependent on the participant’s management level and continued employment. Each annual payment is equal to an amount ranging from 15% to 30% of the employee’s base salary as of their date of enrollment in the plan.
In recognition of the value Entergy Corporation places on Mr. Bakken as a member of its senior management team and his extensive experience in the nuclear industry, and to keep his pay competitive, in May 2019, Mr. Bakken’s participation in the plan was renewed for another three-year period beginning on May 1, 2019. In accordance with the terms and conditions of the Nuclear Retention Plan, in May 2020 Mr. Bakken received, and in May 2021 and 2022, Mr. Bakken will receive a cash bonus equal to 30% of $654,078, his base salary as of May 1, 2019. The three-year period covered and percentage of base salary paid to Mr. Bakken under the plan are consistent with the terms of participation of other senior executive officers who participate in this plan.
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:
Clawback Provisions
Entergy Corporation has adopted a clawback policy that covers all individuals subject to Section 16 of the Exchange Act, including all of the NEOs. Under the policy, which goes beyond the requirements of Sarbanes-Oxley Act of 2002 (Sarbanes-Oxley), incentives paid to covered executive officers are required to be reimbursed where:
•(i) the payment was predicated upon the achievement of certain financial results with respect to the applicable performance period that were subsequently determined to be the subject of a material restatement other than a restatement due to changes in accounting policy; or (ii) a material miscalculation of a performance award occurs, whether or not the financial statements were restated and, in either such case, a lower payment would have been made to the executive officer based upon the restated financial results or correct calculation; or
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•in the Board of Directors’ view, the executive officer engaged in fraud that caused or partially caused the need for a restatement or caused a material miscalculation of a performance award, in each case, whether or not the financial statements were restated.
The amount required to be reimbursed is equal to the excess of the gross incentive payment made over the gross payment that would have been made if the original payment had been determined based on the restated financial results or correct calculation. In addition, Entergy Corporation will seek to recover any compensation received by its Chief Executive Officer and Chief Financial Officer that is required to be reimbursed under Sarbanes-Oxley following a material restatement of Entergy Corporation’s financial statements.
Stock Ownership Guidelines and Share Retention Requirements
For many years, Entergy Corporation has had stock ownership guidelines for executives, including the NEOs. These guidelines are designed to align the executives’ long-term financial interests with the interests of Entergy Corporation’s shareholders. Annually, the Personnel Committee monitors the executive officers’ compliance with these guidelines with all of the NEOs satisfying the applicable ownership guidelines at that time. The ownership guidelines are as follows:
The ownership guidelines are as follows:
| Role | Value of Common Stock to be Owned | ||||
| Chief Executive Officer (ML-1) | 6 x base salary | ||||
| Executive Vice Presidents (ML-2) | 3 x base salary | ||||
| Senior Vice Presidents (ML-3) | 2 x base salary | ||||
| Vice Presidents (ML-4) | 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 LTIP;
•all net after-tax shares of the restricted stock and restricted stock units received upon vesting; 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 Entergy Corporation’s General Counsel or his designee prior to entering into any transaction involving Entergy Corporation securities, including gifts, other than the exercise of employee stock options. 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 may be entered into only during an open trading window and must be approved by Entergy Corporation. A NEO bears full responsibility if he or she violates Entergy Corporation’s policy by buying or selling shares of Entergy Corporation stock without pre-approval or when trading is restricted.
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.
Entergy Corporation also has adopted an anti-hedging policy that prohibits officers, directors, and employees from entering into hedging or monetization transactions involving Entergy Corporation’s common stock. Prohibited transactions include, without limitation, zero-cost collars, forward sale contracts, purchase or sale of options, puts, calls, straddles or equity swaps or other derivatives that are directly linked to Entergy Corporation’s stock or transactions involving “short-sales” of its common stock.
484
Compensation Consultant Independence
Annually, the Personnel Committee reviews the relationship with its compensation consultant to determine whether any conflicts of interest exist that would prevent Pay Governance from independently advising the Personnel Committee. Factors considered by the committee when assessing the independence of its compensation consultant included, 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 Personnel 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 Personnel 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 2020, Pay Governance did not provide any services to Entergy Corporation other than the services it performed on behalf of the Personnel and Corporate Governance Committees, and it worked with Entergy Corporation’s management only as directed by the committees.
PERSONNEL COMMITTEE REPORT
The Personnel Committee Report included in the Entergy Corporation 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.
485
EXECUTIVE COMPENSATION TABLES
2020 Summary Compensation Tables
The following table summarizes the total compensation paid or earned by each of the NEOs for the fiscal year ended December 31, 2020, and to the extent required by SEC executive compensation disclosure rules, the fiscal years ended December 31, 2019 and 2018. 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 tables, 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) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | (k) | ||||||||||||||||||||||
Name and Principal Position (1) | Year | Salary (2) | Bonus (3) | Stock Awards (4) | Option Awards (5) | Non-Equity Incentive Plan Compen-sation (6) | Change in Pension Value and Non-qualified Deferred Compen-sation Earnings (7) | All Other Compen-sation (8) | Total | Total Without Change in Pension Value (9) | ||||||||||||||||||||||
| A. Christopher Bakken, III | 2020 | $693,819 | $196,223 | $1,666,710 | $335,245 | $581,066 | $115,100 | $85,846 | $3,674,009 | $3,558,909 | ||||||||||||||||||||||
| Executive Vice President and | 2019 | $649,507 | $181,500 | $1,273,399 | $303,023 | $618,104 | $98,500 | $62,407 | $3,186,440 | $3,087,940 | ||||||||||||||||||||||
| Chief Nuclear Officer of Entergy Corp. | 2018 | $632,967 | $181,500 | $1,041,479 | $283,095 | $544,959 | $108,700 | $452,012 | $3,244,712 | $3,136,012 | ||||||||||||||||||||||
| Marcus V. Brown | 2020 | $709,688 | $— | $1,626,512 | $327,172 | $662,400 | $1,746,000 | $78,631 | $5,150,403 | $3,404,403 | ||||||||||||||||||||||
| Executive Vice President and | 2019 | $661,563 | $— | $1,248,839 | $297,182 | $684,573 | $1,455,300 | $69,955 | $4,417,412 | $2,962,112 | ||||||||||||||||||||||
| General Counsel of Entergy Corp. | 2018 | $644,231 | $— | $1,041,479 | $283,095 | $546,000 | $371,800 | $61,885 | $2,948,490 | $2,576,690 | ||||||||||||||||||||||
| Leo P. Denault | 2020 | $1,308,462 | $— | $6,716,017 | $1,350,986 | $2,116,800 | $4,416,700 | $289,632 | $16,198,597 | $11,781,897 | ||||||||||||||||||||||
| Chairman of the | 2019 | $1,260,000 | $— | $5,391,253 | $1,282,994 | $2,416,680 | $3,704,500 | $208,822 | $14,264,249 | $10,559,749 | ||||||||||||||||||||||
| Board and CEO - | 2018 | $1,251,346 | $— | $4,744,977 | $1,168,029 | $2,041,200 | $982,800 | $138,104 | $10,326,456 | $9,343,656 | ||||||||||||||||||||||
| Entergy Corp. | ||||||||||||||||||||||||||||||||
| David D. Ellis | 2020 | $331,803 | $— | $219,889 | $36,640 | $164,955 | $32,200 | $19,323 | $804,810 | $772,610 | ||||||||||||||||||||||
| CEO - Entergy | 2019 | $311,004 | $— | $188,861 | $39,104 | $159,804 | $18,000 | $15,267 | $732,040 | $714,040 | ||||||||||||||||||||||
| New Orleans | 2018 | $7,258 | $200,000 | $— | $— | $— | $600 | $35,308 | $243,166 | $242,566 | ||||||||||||||||||||||
| Haley R. Fisackerly | 2020 | $384,848 | $— | $252,819 | $49,235 | $232,737 | $836,200 | $48,101 | $1,803,940 | $967,740 | ||||||||||||||||||||||
| CEO - Entergy | 2019 | $373,313 | $— | $197,780 | $51,584 | $274,570 | $644,700 | $37,897 | $1,579,844 | $935,144 | ||||||||||||||||||||||
| Mississippi | 2018 | $363,089 | $— | $198,449 | $46,134 | $172,000 | $— | $35,982 | $815,654 | $815,654 | ||||||||||||||||||||||
| Laura R. Landreaux | 2020 | $323,907 | $— | $252,819 | $49,235 | $167,153 | $330,700 | $26,698 | $1,150,512 | $819,812 | ||||||||||||||||||||||
| CEO - Entergy | 2019 | $314,407 | $— | $188,861 | $42,432 | $263,523 | $228,700 | $26,536 | $1,064,459 | $835,759 | ||||||||||||||||||||||
| Arkansas | 2018 | $246,136 | $— | $273,062 | $— | $124,000 | $21,500 | $10,741 | $675,439 | $653,939 | ||||||||||||||||||||||
486
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | (k) | ||||||||||||||||||||||
Name and Principal Position (1) | Year | Salary (2) | Bonus (3) | Stock Awards (4) | Option Awards (5) | Non-Equity Incentive Plan Compen-sation (6) | Change in Pension Value and Non-qualified Deferred Compen-sation Earnings (7) | All Other Compen-sation (8) | Total | Total Without Change in Pension Value (9) | ||||||||||||||||||||||
| Andrew S. Marsh | 2020 | $704,692 | $— | $2,053,717 | $413,105 | $703,800 | $2,054,000 | $77,741 | $6,007,055 | $3,953,055 | ||||||||||||||||||||||
| Executive Vice | 2019 | $641,923 | $— | $1,579,663 | $375,914 | $712,400 | $1,554,300 | $69,863 | $4,934,063 | $3,379,763 | ||||||||||||||||||||||
| President and CFO - | 2018 | $615,654 | $— | $1,057,095 | $342,510 | $531,188 | $— | $57,638 | $2,604,085 | $2,604,085 | ||||||||||||||||||||||
| Entergy Corp., | ||||||||||||||||||||||||||||||||
| Entergy Arkansas, | ||||||||||||||||||||||||||||||||
| Entergy Louisiana, | ||||||||||||||||||||||||||||||||
| Entergy Mississippi, | ||||||||||||||||||||||||||||||||
| Entergy New | ||||||||||||||||||||||||||||||||
| Orleans, | ||||||||||||||||||||||||||||||||
| Entergy Texas | ||||||||||||||||||||||||||||||||
| Phillip R. May, Jr. | 2020 | $416,677 | $— | $371,882 | $83,585 | $284,881 | $1,072,100 | $28,836 | $2,257,961 | $1,185,861 | ||||||||||||||||||||||
| CEO - Entergy | 2019 | $389,016 | $— | $294,183 | $77,376 | $407,922 | $877,100 | $28,297 | $2,073,894 | $1,196,794 | ||||||||||||||||||||||
| Louisiana | 2018 | $377,108 | $— | $288,238 | $69,201 | $270,000 | $— | $26,874 | $1,031,421 | $1,031,421 | ||||||||||||||||||||||
| Sallie T. Rainer | 2020 | $369,133 | $— | $252,819 | $49,235 | $175,713 | $663,100 | $33,383 | $1,543,383 | $880,283 | ||||||||||||||||||||||
| CEO - Entergy | 2019 | $344,722 | $— | $197,780 | $51,584 | $219,069 | $617,200 | $37,361 | $1,467,716 | $850,516 | ||||||||||||||||||||||
| Texas | 2018 | $335,263 | $— | $198,449 | $46,134 | $159,000 | $— | $35,379 | $774,225 | $774,225 | ||||||||||||||||||||||
| Roderick K. West | 2020 | $754,742 | $— | $1,804,816 | $363,022 | $673,314 | $1,976,400 | $59,730 | $5,632,024 | $3,655,624 | ||||||||||||||||||||||
| Group President | 2019 | $709,023 | $— | $1,340,679 | $319,039 | $674,742 | $1,604,100 | $67,191 | $4,714,774 | $3,110,674 | ||||||||||||||||||||||
| Utility Operations of | 2018 | $690,581 | $— | $1,057,095 | $297,075 | $560,762 | $— | $67,234 | $2,672,747 | $2,672,747 | ||||||||||||||||||||||
| Entergy Corp. | ||||||||||||||||||||||||||||||||
(1)Mr. Ellis was named Chief Executive Officer, Entergy New Orleans in December 2018, and Ms. Landreaux was named Chief Executive Officer, Entergy Arkansas in July 2018.
(2)The amounts in column (c) represent the actual base salary paid to the NEOs in the applicable year. The 2020 base salary amounts include an amount attributable to an extra pay period that occurred in 2020 as the NEOs are paid on a bi-weekly basis. The 2020 changes in base salaries noted in the Compensation Discussion and Analysis were effective in April 2020.
(3)The amount in column (d) in 2020, 2019, and 2018 for Mr. Bakken represents the cash bonus paid to him pursuant to the Nuclear Retention Plan. See “Nuclear Retention Plan” in Compensation Discussion and Analysis. The amount in column (d) in 2018 for Mr. Ellis represents a cash sign-on bonus paid in connection with his commencement of employment with Entergy New Orleans.
(4)The amounts in column (e) represent the aggregate grant date fair value of restricted stock and performance units granted under the 2015 Equity Ownership Plan of Entergy Corporation and Subsidiaries (the “2015 EOP”) and the 2019 OIP (together with the 2015 EOP, the “Equity Plans”), each calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures. The grant date fair value of the restricted stock 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 with vesting based on the total shareholder return 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 total shareholder return and Cumulative ETR Adjusted EPS, for performance units granted in 2020 are as follows: Mr. Bakken,
487
$2,043,768; Mr. Brown, $1,994,504; Mr. Denault, $8,235,925; Mr. Ellis, $250,268; Mr. Fisackerly, $250,268; Ms. Landreaux $250,268; Mr. Marsh, $2,518,486; Mr. May, $368,816; Ms. Rainer, $250,268; and Mr. West, $2,213,159.
(5)The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the Equity Plans 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.
(6)The amounts in column (g) represent annual incentive award cash payments made under the 2019 OIP.
(7)For all NEOs, the amounts in column (h) include the annual actuarial increase 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 (see “2020 Pension Benefits”). The increase in pension benefits for all of the NEOs in 2020 was driven by a decline in the discount rate that was a result of the decrease in prevailing interest rates. None of the increases for any of the NEOs is attributable to above-market or preferential earnings on non-qualified deferred compensation. For 2018, the aggregate change in the actuarial present value was a decrease of pension benefits of $52,000 for Mr. Fisackerly, $163,000 for Mr. Marsh, $700 for Mr. May, $110,700 for Ms. Rainer, and $149,300 for Mr. West.
(8)The amounts in column (i) for 2020 include (a) matching contributions by Entergy Corporation under the Savings Plan to each of the NEOs; (b) dividends paid on restricted stock when vested; (c) life insurance premiums; (d) tax gross up payments on club dues; and (e) perquisites and other compensation as described further below. The amounts are listed in the following table:
| Named Executive Officer | Company Contribution – Savings Plan | Dividends Paid on Restricted Stock | Life Insurance Premium | Tax Gross Up Payments | Perquisites and Other Compensation | Total | ||||||||||||||
| A. Christopher Bakken, III | $17,100 | $52,032 | $12,415 | $— | $4,299 | $85,846 | ||||||||||||||
| Marcus V. Brown | $11,970 | $56,953 | $7,482 | $— | $2,226 | $78,631 | ||||||||||||||
| Leo P. Denault | $11,970 | $173,952 | $11,484 | $— | $92,226 | $289,632 | ||||||||||||||
| David D. Ellis | $17,100 | $658 | $745 | $— | $820 | $19,323 | ||||||||||||||
| Haley R. Fisackerly | $11,970 | $8,305 | $5,705 | $7,939 | $14,182 | $48,101 | ||||||||||||||
| Laura R. Landreaux | $— | $13,094 | $493 | $4,281 | $8,829 | $26,697 | ||||||||||||||
| Andrew S. Marsh | $11,970 | $59,177 | $6,594 | $— | $— | $77,741 | ||||||||||||||
| Phillip R. May, Jr. | $11,970 | $10,902 | $5,964 | $— | $— | $28,836 | ||||||||||||||
| Sallie T. Rainer | $11,970 | $8,564 | $1,580 | $2,836 | $8,433 | $33,383 | ||||||||||||||
| Roderick K. West | $11,970 | $41,931 | $4,002 | $— | $1,827 | $59,730 | ||||||||||||||
(9)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 Personnel Committee.
488
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 2020.
| Named Executive Officer | Personal Use of Corporate Aircraft | Club Dues | Executive Physical Exams | ||||||||
| A. Christopher Bakken, III | X | ||||||||||
| Marcus V. Brown | X | X | |||||||||
| Leo P. Denault | X | X | |||||||||
| David D. Ellis | X | ||||||||||
| Haley R. Fisackerly | X | X | |||||||||
| Laura R. Landreaux | X | ||||||||||
| Andrew S. Marsh | X | ||||||||||
| Phillip R. May, Jr. | |||||||||||
| Sallie T. Rainer | X | ||||||||||
| Roderick K. West | X | ||||||||||
For security and business reasons, Entergy Corporation’s Chief Executive Officer is permitted to use its corporate aircraft for personal use at the expense of Entergy Corporation. The other NEOs may use the corporate aircraft for personal travel subject to the approval of Entergy Corporation’s Chief Executive Officer. The Personnel Committee reviews the level of usage throughout the year. Entergy Corporation believes that its officers’ ability to use its plane for limited personal use saves time and provides additional security for them, thereby benefiting Entergy Corporation. 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. Denault’s personal use of the corporate aircraft was $86,618 for fiscal year 2020. In addition, Entergy Corporation offers its executives comprehensive annual physical exams at Entergy Corporation’s expense. None of the other perquisites referenced above exceeded $25,000 for any of the other NEOs.
489
2020 Grants of Plan-Based Awards
The following table summarizes award grants during 2020 to the NEOs.
Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1) | Estimated Future Payouts under Equity Incentive Plan Awards (2) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | (k) | (l) | |||||||||||||||||||||||||||||||||||||||||||||
| Name | Grant Date | Thresh-old | Target | Maximum | Thresh-old | Target | Maximum | All Other Stock Awards: Number of Shares of Stock or Units | All Other Option Awards: Number of Securities Under-lying Options | Exercise or Base Price of Option Awards | Grant Date Fair Value of Stock and Option Awards | |||||||||||||||||||||||||||||||||||||||||||||
| ($) | ($) | ($) | (#) | (#) | (#) | (#) (3) | (#) (4) | ($/Sh) | ($) (5) | |||||||||||||||||||||||||||||||||||||||||||||||
| A. Christopher | 1/30/20 | $- | $505,275 | $1,010,550 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Bakken, III | 1/30/20 | 1,940 | 7,758 | 15,516 | $1,257,851 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 3,104 | $408,859 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 29,279 | $131.72 | $335,245 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Marcus V. | 1/30/20 | $- | $552,000 | $1,104,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Brown | 1/30/20 | 1,893 | 7,571 | 15,142 | $1,227,532 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 3,029 | $398,980 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 28,574 | $131.72 | $327,172 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Leo P. | 1/30/20 | $- | $1,764,000 | $3,528,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Denault | 1/30/20 | 7,816 | 31,263 | 62,526 | $5,068,858 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 12,505 | $1,647,159 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 117,990 | $131.72 | $1,350,986 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| David D. | 1/30/20 | $- | $128,740 | $257,480 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Ellis | 1/30/20 | 238 | 950 | 1,900 | $154,029 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| 500 | $65,860 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 3,200 | $131.72 | $36,640 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Haley R. | 1/30/20 | $- | $155,297 | $310,594 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Fisackerly | 1/30/20 | 238 | 950 | 1,900 | $154,029 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 750 | $98,790 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 4,300 | $131.72 | $49,235 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Laura R. | 1/30/20 | $- | $130,702 | $261,404 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Landreaux | 1/30/20 | 238 | 950 | 1,900 | $154,029 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 750 | $98,790 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 4,300 | $131.72 | $49,235 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Andrew S. | 1/30/20 | $- | $586,500 | $1,173,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Marsh | 1/30/20 | 2,390 | 9,560 | 19,120 | $1,550,020 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 3,824 | $503,697 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 36,079 | $131.72 | $413,105 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
490
Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1) | Estimated Future Payouts under Equity Incentive Plan Awards (2) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | (k) | (l) | |||||||||||||||||||||||||||||||||||||||||||||
| Name | Grant Date | Thresh-old | Target | Maximum | Thresh-old | Target | Maximum | All Other Stock Awards: Number of Shares of Stock or Units | All Other Option Awards: Number of Securities Under-lying Options | Exercise or Base Price of Option Awards | Grant Date Fair Value of Stock and Option Awards | |||||||||||||||||||||||||||||||||||||||||||||
| ($) | ($) | ($) | (#) | (#) | (#) | (#) (3) | (#) (4) | ($/Sh) | ($) (5) | |||||||||||||||||||||||||||||||||||||||||||||||
| Phillip R. | 1/30/20 | $- | $242,870 | $485,740 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| May, Jr. | 1/30/20 | 350 | 1,400 | 2,800 | $226,990 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 1,100 | $144,892 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 7,300 | $131.72 | $85,585 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Sallie T. | 1/30/20 | $- | $143,485 | $286,970 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Rainer | 1/30/20 | 238 | 950 | 1,900 | $154,029 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 750 | $98,790 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 4,300 | $131.72 | $49,235 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Roderick K. | 1/30/20 | $- | $585,490 | $1,170,980 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| West | 1/30/20 | 2,100 | 8,401 | 16,802 | $1,362,105 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 3,361 | $442,711 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 1/30/20 | 31,705 | $131.72 | $363,022 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
(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 Summary Compensation Table.
(2)The amounts in columns (f), (g), and (h) represent the minimum, target, and maximum payment levels under the LTIP. Performance under the program is measured by Entergy Corporation’s total shareholder return relative to the total shareholder returns of the companies included in the Philadelphia Utility Index and Cumulative Entergy Adjusted EPS with total shareholder return weighted eighty percent and Cumulative Entergy Adjusted EPS weighted twenty percent. There is no payout under the program if Entergy Corporation’s total shareholder return falls within the lowest quartile of the peer companies in the Philadelphia Utility Index and Cumulative Entergy Adjusted EPS 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 (December 31, 2022). 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. 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. The options were granted under the 2019 OIP.
(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 Notes 4 and 5 to the 2020 Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value.
491
2020 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, 2020.
| Option Awards | Stock Awards | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | |||||||||||||||||||||||||||||||||||||||||||||||
| Name | Number of Securities Underlying Unexercised Options Exercisable | Number of Securities Underlying Unexercised Options Unexercisable | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | Option Exercise Price | Option Expiration Date | Number of Shares or Units of Stock That Have Not Vested | Market Value of Shares or Units of Stock That Have Not Vested | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested | |||||||||||||||||||||||||||||||||||||||||||||||
| (#) | (#) | (#) | ($) | (#) | ($) | (#) | ($) | |||||||||||||||||||||||||||||||||||||||||||||||||
| A. Christopher Bakken, III | — | 29,279(1) | $131.72 | 1/30/2030 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| — | 24,281(2) | $89.19 | 1/31/2029 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| — | 13,500(3) | $78.08 | 1/25/2028 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
1,940(4) | $193,640 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
19,136(5) | $1,910,538 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
3,104(6) | $309,903 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2,403(7) | $239,916 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
1,667(8) | $166,433 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
20,000(9) | $1,996,800 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Marcus V. Brown | — | 28,574(1) | $131.72 | 1/30/2030 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| — | 23,813(2) | $89.19 | 1/31/2029 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| — | 13,500(3) | $78.08 | 1/25/2028 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
1,893(4) | $188,972 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
18,766(5) | $1,873,597 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
3,029(6) | $302,415 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2,357(7) | $235,323 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
1,667(8) | $166,433 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
492
| Option Awards | Stock Awards | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | |||||||||||||||||||||||||||||||||||||||||||||||
| Name | Number of Securities Underlying Unexercised Options Exercisable | Number of Securities Underlying Unexercised Options Unexercisable | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | Option Exercise Price | Option Expiration Date | Number of Shares or Units of Stock That Have Not Vested | Market Value of Shares or Units of Stock That Have Not Vested | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested | |||||||||||||||||||||||||||||||||||||||||||||||
| (#) | (#) | (#) | ($) | (#) | ($) | (#) | ($) | |||||||||||||||||||||||||||||||||||||||||||||||||
| Leo P. Denault | — | 117,990(1) | $131.72 | 1/30/2030 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| 51,402 | 102,804(2) | $89.19 | 1/31/2029 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 111,400 | 55,700(3) | $78.08 | 1/25/2028 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 179,400 | — | $70.53 | 1/26/2027 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 167,000 | — | $70.56 | 1/28/2026 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 88,000 | — | $89.90 | 1/29/2025 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 106,000 | — | $63.17 | 1/30/2024 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 50,000 | — | $64.60 | 1/31/2023 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
7,816(4) | $780,324 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
81,016(5) | $8,088,637 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
12,505(6) | $1,248,499 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
10,173(7) | $1,015,672 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
5,234(8) | $522,563 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| David D. Ellis | — | 3,200(1) | $131.72 | 1/30/2030 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| 1,566 | 3,134(2) | $89.19 | 1/31/2029 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
238(4) | $23,712 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2,900(5) | $289,536 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
500(6) | $49,920 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
334(7) | $33,347 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Haley R. Fisackerly | — | 4,300(1) | $131.72 | 1/30/2030 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| — | 4,134(2) | $89.19 | 1/31/2029 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| — | 2,200(3) | $78.08 | 1/25/2028 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
238(4) | $23,712 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2,900(5) | $289,536 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
750(6) | $74,880 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
400(7) | $39,936 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
267(8) | $26,657 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
493
| Option Awards | Stock Awards | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | |||||||||||||||||||||||||||||||||||||||||||||||
| Name | Number of Securities Underlying Unexercised Options Exercisable | Number of Securities Underlying Unexercised Options Unexercisable | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | Option Exercise Price | Option Expiration Date | Number of Shares or Units of Stock That Have Not Vested | Market Value of Shares or Units of Stock That Have Not Vested | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested | |||||||||||||||||||||||||||||||||||||||||||||||
| (#) | (#) | (#) | ($) | (#) | ($) | (#) | ($) | |||||||||||||||||||||||||||||||||||||||||||||||||
| Laura R. Landreaux | — | 4,300(1) | $131.72 | 1/30/2030 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| 1,700 | 3,400(2) | $89.19 | 1/31/2029 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
238(4) | $23,712 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2,900(5) | $289,536 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
750(6) | $74,880 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
334(7) | $33,347 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
400(8) | $39,936 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Andrew S. Marsh | — | 36,079(1) | $131.72 | 1/30/2030 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| 15,060 | 30,122(2) | $89.19 | 1/31/2029 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 32,666 | 16,334(3) | $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 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 35,000 | — | $63.17 | 1/30/2024 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 32,000 | — | $64.60 | 1/31/2023 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 10,000 | — | $71.30 | 1/26/2022 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 4,000 | — | $72.79 | 1/27/2021 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
2,390(4) | $238,618 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
23,738(5) | $2,370,002 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
3,824(6) | $381,788 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2,981(7) | $297,623 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
1,734(8) | $173,123 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Phillip R. May, Jr. | — | 7,300(1) | $131.72 | 1/30/2030 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| — | 6,200(2) | $89.19 | 1/31/2029 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| — | 3,300(3) | $78.08 | 1/25/2028 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
350(4) | $34,944 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
4,300(5) | $429,312 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
1,100(6) | $109,824 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
600(7) | $59,904 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
343(8) | $33,347 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
494
| Option Awards | Stock Awards | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | |||||||||||||||||||||||||||||||||||||||||||||||
| Name | Number of Securities Underlying Unexercised Options Exercisable | Number of Securities Underlying Unexercised Options Unexercisable | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | Option Exercise Price | Option Expiration Date | Number of Shares or Units of Stock That Have Not Vested | Market Value of Shares or Units of Stock That Have Not Vested | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested | |||||||||||||||||||||||||||||||||||||||||||||||
| (#) | (#) | (#) | ($) | (#) | ($) | (#) | ($) | |||||||||||||||||||||||||||||||||||||||||||||||||
| Sallie T. Rainer | — | 4,300(1) | $131.72 | 1/30/2030 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2,066 | 4,134(2) | $89.19 | 1/31/2029 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2,200 | 2,200(3) | $78.08 | 1/25/2028 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2,600 | — | $70.53 | 1/26/2027 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
238(4) | $23,712 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2,900(5) | $289,536 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
750(6) | $74,880 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
400(7) | $39,936 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
267(8) | $26,657 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Roderick K. West | — | 31,705(1) | $131.72 | 1/30/2030 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| — | 25,564(2) | $89.19 | 1/31/2029 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| — | 14,167(3) | $78.08 | 1/25/2028 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
2,100(4) | $209,689 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
20,146(5) | $2,011,377 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
3,361(6) | $335,562 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2,530(7) | $252,595 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
1,734(8) | $173,123 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
(1)Consists of options granted under the 2019 OIP; 1/3 of the options vested on January 30, 2021 and 1/3 of the remaining options will vest on each of January 30, 2022 and January 30, 2023.
(2)Consists of options granted under the 2015 EOP; 1/2 of the options vested on January 31, 2021 and the remaining options will vest on January 30, 2022.
(3)Consists of options granted under the 2015 EOP that vested on January 25, 2021.
(4)Consists of performance units granted under the 2019 OIP that will vest on December 31, 2022 based on two performance measures: 1) Entergy Corporation’s total shareholder return performance over the 2020-2022 performance period and 2) Cumulative Entergy Adjusted EPS with total shareholder return weighted eighty percent and Cumulative Entergy Adjusted EPS weighted twenty percent, as described under “What Entergy Corporation Pays and Why - Long-Term Incentive Compensation - 2020 Long-Term Incentive Award Mix - Long-Term Performance Unit Program” in the Compensation Discussion and Analysis.
(5)Consists of performance units granted under the 2015 EOP that will vest on December 31, 2021 based on two performance measures: 1) Entergy Corporation’s total shareholder return performance over the 2019-2021 performance period and 2) Cumulative Entergy Adjusted EPS with total shareholder return weighted eighty percent and Cumulative Entergy Adjusted EPS 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 30, 2021 and 1/3 of the remaining shares will vest on each of January 30, 2022 and January 30, 2023.
495
(7)Consists of shares of restricted stock granted under the 2015 EOP; 1/2 of the shares of restricted stock vested on January 31, 2021 and the remaining shares of restricted stock will vest on January 31, 2022.
(8)Consists of shares of restricted stock granted under the 2015 EOP that vested on January 25, 2021.
(9)Consists of restricted stock units granted under the 2015 EOP which will vest 1/2 on each of April 6, 2022 and April 6, 2025.
2020 Option Exercises and Stock Vested
The following table provides information concerning each exercise of stock options and each vesting of stock during 2020 for the NEOs.
| Options Awards | Stock Awards | |||||||||||||||||||||||||
| (a) | (b) | (c) | (d) | (e) | ||||||||||||||||||||||
| Name | Number of Shares Acquired on Exercise | Value Realized on Exercise | Number of Shares Acquired on Vesting | Value Realized on Vesting (1) | ||||||||||||||||||||||
| (#) | ($) | (#) | ($) | |||||||||||||||||||||||
| A. Christopher Bakken, III | 38,174 | $1,954,334 | 16,051 | $1,701,473 | ||||||||||||||||||||||
| Marcus V. Brown | 40,075 | $2,081,630 | 16,366 | $1,742,234 | ||||||||||||||||||||||
| Leo P. Denault | — | $— | 77,044 | $7,935,333 | ||||||||||||||||||||||
| David D. Ellis | — | $— | 1,659 | $164,028 | ||||||||||||||||||||||
| Haley R. Fisackerly | 6,800 | $351,077 | 3,122 | $325,433 | ||||||||||||||||||||||
| Laura R. Landreaux | — | $— | 3,059 | $331,489 | ||||||||||||||||||||||
| Andrew S. Marsh | — | $— | 37,861 | $3,959,325 | ||||||||||||||||||||||
| Phillip R. May, Jr. | 13,900 | $774,394 | 4,650 | $480,241 | ||||||||||||||||||||||
| Sallie T. Rainer | — | $— | 3,140 | $327,765 | ||||||||||||||||||||||
| Roderick K. West | 97,249 | $4,940,267 | 15,436 | $1,621,930 | ||||||||||||||||||||||
(1)Represents the value of performance units for the 2018 - 2020 performance period (payable solely in shares based on the closing stock price of Entergy Corporation on the date of vesting) under the LTIP and the vesting of shares of restricted stock in 2020.
496
2020 Pension Benefits
The following table shows the present value as of December 31, 2020, 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 2020 | ||||||||||||||||||||||
| A. Christopher Bakken, III | Cash Balance Equalization Plan | 4.74 | $287,400 | $— | ||||||||||||||||||||||
| Cash Balance Plan | 4.74 | $95,800 | $— | |||||||||||||||||||||||
Marcus V. Brown(1) | System Executive Retirement Plan | 25.74 | $7,889,100 | $— | ||||||||||||||||||||||
| Entergy Retirement Plan | 25.74 | $1,385,300 | $— | |||||||||||||||||||||||
Leo P. Denault (1)(2) | System Executive Retirement Plan | 30.00 | $30,747,600 | $— | ||||||||||||||||||||||
| Entergy Retirement Plan | 21.83 | $1,230,700 | $— | |||||||||||||||||||||||
| David D. Ellis | Cash Balance Equalization Plan | 2.06 | $15,200 | $— | ||||||||||||||||||||||
| Cash Balance Plan | 2.06 | $35,600 | $— | |||||||||||||||||||||||
Haley R. Fisackerly(1) | System Executive Retirement Plan | 25.08 | $2,338,800 | $— | ||||||||||||||||||||||
| Entergy Retirement Plan | 25.08 | $1,249,300 | $— | |||||||||||||||||||||||
| Laura R. Landreaux | Pension Equalization Plan | 13.48 | $258,600 | $— | ||||||||||||||||||||||
| Entergy Retirement Plan | 13.48 | $577,100 | $— | |||||||||||||||||||||||
| Andrew S. Marsh | System Executive Retirement Plan | 22.37 | $6,543,400 | $— | ||||||||||||||||||||||
| Entergy Retirement Plan | 22.37 | $944,000 | $— | |||||||||||||||||||||||
Phillip R. May, Jr. (1)(3) | System Executive Retirement Plan | 30.00 | $3,747,400 | $— | ||||||||||||||||||||||
| Entergy Retirement Plan | 34.56 | $1,827,300 | $— | |||||||||||||||||||||||
Sallie T. Rainer (1)(3) | System Executive Retirement Plan | 30.00 | $1,850,000 | $— | ||||||||||||||||||||||
| Entergy Retirement Plan | 36.00 | $2,090,800 | $— | |||||||||||||||||||||||
| Roderick K. West | System Executive Retirement Plan | 21.75 | $7,667,200 | $— | ||||||||||||||||||||||
| Entergy Retirement Plan | 21.75 | $994,300 | $— | |||||||||||||||||||||||
(1)As of December 31, 2020, Mr. Brown, Mr. Denault, Mr. Fisackerly, Mr. May, and Ms. Rainer were retirement eligible.
(2)In 2006, Mr. Denault entered into a retention agreement granting him additional years of service and permission to retire under the non-qualified System Executive Retirement Plan (“SERP”) in the event his employment is terminated by his Entergy employer other than for cause (as defined in the retention agreement), by Mr. Denault for good reason (as defined in the retention agreement), or on account of his death or disability. His retention agreement also provides that if he terminates employment for any other reason, he shall be entitled to up to an additional 15 years of service under the SERP only if his Entergy employer grants him permission to retire subject to the overall 30 year cap on service credit under the SERP. The amount reflected in the table for the SERP is calculated based on 30 years of service. The additional years of service credited to Mr. Denault under his retention agreement increased the present value of Mr. Denault’s benefit by $4,020,200.
(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 and Ms. Rainer are calculated based on 30 years of service pursuant to the terms of the SERP.
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Retirement Benefits
The tables below contain summaries of the pension benefit plans sponsored by Entergy Corporation that the NEOs participated in during 2020. Benefits for the NEOs who participate in these plans are determined using the same formulas as for other eligible employees.
Qualified Retirement Benefits
| Entergy Retirement Plan | Cash Balance Plan | ||||||||||
| Eligible Named Executive Officers | Marcus V. Brown Haley R. Fisackerly Leo P. Denault Andrew S. Marsh Laura R. Landreaux | Phillip R. May, Jr. Sallie T. Rainer Roderick K. West | A. Christopher Bakken, III David D. Ellis | ||||||||
| 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. | |||||||||
| 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 Internal Revenue Code limitations, 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. | 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 Internal Revenue Code limitations and exclude all other bonuses. Executive annual incentive 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%. | |||||||||
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| Benefit Timing | 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 can 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. | |||||||||
Non-qualified Retirement Benefits
The NEOs are eligible to participate in certain non-qualified retirement benefit plans that provide retirement income, including the Pension Equalization Plan (“PEP”), the Cash Balance Equalization Plan, and the SERP. Each of these plans is an unfunded non-qualified defined benefit pension plan that provides benefits to key management employees. In these plans, as described below, an executive may participate in one or more non-qualified plans, but is only paid the amount due under the plan that provides the highest benefit. In general, upon disability, participants in the PEP and the SERP remain eligible for continued service credits until the earlier 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.
| Pension Equalization Plan | Cash Balance Equalization Plan | System Executive Retirement Plan | |||||||||||||||
| Eligible Named Executive Officers | Marcus V. Brown Haley R. Fisackerly Leo P. Denault Laura R. Landreaux Andrew S. Marsh | Phillip R. May, Jr. Sallie T. Rainer Roderick K. West | A. Christopher Bakken, III David D. Ellis | Marcus V. Brown Haley R. Fisackerly Leo P. Denault Andrew S. Marsh | Phillip R. May, Jr. Sallie T. Rainer Roderick K. West | ||||||||||||
| Eligibility | 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 | ||||||||||||||
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| 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 awards as eligible earnings and without applying limitations of the Internal Revenue Code of 1986, as amended (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 3 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 | 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. Benefits payable upon separation from service subject to the 6 month delay required under the Code Section 409A. | Payable upon separation from service subject to 6 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. Benefits payable upon separation from service subject to the 6 month delay required under Internal Revenue Code Section 409A. | ||||||||||||||
Additional Information
(1)Effective July 1, 2014, (a) no new grants of supplemental service may be provided to participants in the Pension Equalization Plan; (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 Pension Equalization Plan and instead may be eligible to participate in the Cash Balance Equalization Plan.
(2)Benefits accrued under the SERP, PEP, and Cash Balance Equalization Plan, 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 6 months under Internal Revenue Code Section 409A.
(3)The SERP was closed to new executive officers effective July 1, 2014.
500
2020 Non-qualified Deferred Compensation
As of December 31, 2020, 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 the participant 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 2020 | Registrant Contributions in 2020 | Aggregate Earnings in 2020(1) | Aggregate Withdrawals/Distributions | Aggregate Balance at December 31, 2020 | |||||||||||||||||||||||||||
| (a) | (b) | (c) | (d) | (e) | (f) | |||||||||||||||||||||||||||
| Phillip R. May, Jr. | $— | $— | $80 | $— | $3,067 | |||||||||||||||||||||||||||
(1)Amounts in this column are not included in the Summary Compensation Table.
2020 Potential Payments Upon Termination or Change in Control
Entergy Corporation 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 Corporation or its subsidiaries.
Change in Control
Under Entergy Corporation’s System Executive Continuity Plan (the “Continuity Plan”), ML 1-4 Officers are eligible to receive the severance benefits described below if their employment is terminated by their Entergy System employer other than for cause 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 Corporation 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 his or her non-compete provision (which generally runs for two years but extends to three years if permissible under applicable law). Entergy Corporation does not have any plans or agreements that provide for payments or benefits to any of the NEOs solely upon a change in control.
In the event of a Qualifying Termination, executive officers, including the NEOs, generally will receive the benefits set forth below:
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| Compensation Element | Payment | ||||
| 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 of control period or, if higher, immediately prior to a circumstance constituting good reason, plus (b) the participant’s annual incentive, 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 | Under the 2015 EOP and the performance unit agreements in respect of the 2019 - 2021 performance period, participants would forfeit outstanding performance units, and in lieu of any payment for any outstanding performance period, would receive a single-lump sum payment calculated by multiplying the target performance units for the most recent performance period preceding (but not including) the calendar year in which termination occurs by the closing price of Entergy’s common stock as of the later of the date of such termination or the date of the Change in Control. Under the 2019 OIP and the performance unit agreements in respect of the 2020 - 2022 performance unit period, 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 the performance of Entergy Corporation 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, shares of restricted stock and restricted stock units will vest immediately upon a “double trigger” Qualifying Termination pursuant to the terms of the 2015 EOP and 2019 OIP. | ||||
| Retirement Benefits | Benefits already accrued under the SERP, PEP and Cash Balance Equalization Plan, 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 plus (b) the higher of his or her actual annual incentive payment under the annual incentive program or his or her annual incentive, 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. 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, non-solicitation, confidentiality and non-denigration provisions. If an executive discloses non-public data or information concerning Entergy Corporation or any of its subsidiaries or violates his or her non-compete provision, he or she will be required to repay any benefits previously received under the Continuity Plan.
For purposes of the Continuity Plan the following events are generally defined as:
•Change in Control: (a) the purchase of 30% or more of either Entergy Corporation’s common stock or the combined voting power of Entergy Corporation’s voting securities; (b) the merger or consolidation of Entergy Corporation (unless its Board members constitute at least a majority of the board members of the surviving entity); (c) the liquidation, dissolution or sale of all or substantially all of Entergy Corporation’s assets; or (d) a change in the composition of Entergy Corporation’s Board such that, during any two-year period, the individuals serving at the beginning of the period no longer constitute a majority of Entergy Corporation’s Board at the end of the period.
•Potential Change in Control: (a) Entergy Corporation or an affiliate enters into an agreement the consummation of which would constitute a Change in Control; (b) the Entergy Corporation Board adopts resolutions determining that, for purposes of the Continuity Plan, a potential Change in Control has occurred; (c) a System Company or other person or entity publicly announces an intention to take actions that would constitute a Change in Control; or (d) any person or entity becomes the beneficial owner (directly or indirectly)
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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 either his or her 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 | Stock Options | Restricted Stock | Performance Units | |||||||||||||
| Voluntary Resignation | None | Forfeited* | Unvested options are forfeited. Vested options expire on the earlier of (i) 90 days from the last day of active employment and (ii) the option’s normal expiration date. | Forfeited | Forfeited** | ||||||||||||
| Termination for Cause | None | Forfeited | Forfeited | Forfeited | Forfeited | ||||||||||||
| Retirement | None | Pro-rated based on number of days employed during the performance period | Unvested stock options granted prior to 2020 vest on the retirement date and expire on the earlier of (i) five years from the retirement date and (ii) the option’s normal expiration date. Unvested stock options granted in 2020 continue to vest following retirement, in accordance with the original vesting schedule and expire the earlier of (i) five years from the retirement date and (ii) the option’s normal expiration date. | Forfeited | Officers with a minimum of 12 months of participation are eligible for a pro-rated award based on actual performance and full months of service during the performance period | ||||||||||||
| Death/Disability | None | Pro-rated based on number of days employed during the performance period | Unvested stock options vest on the termination date and expire on the earlier of (i) five years from the termination date and (ii) the option’s normal expiration date | Fully Vest | Officers are eligible for pro-rated award based on actual performance and full months of service during the performance period | ||||||||||||
503
* If an officer resigns after the completion of an annual incentive plan, he or she may receive, at Entergy Corporation’s discretion, an annual incentive payment.
** If an officer resigns after the completion of a LTIP performance period, he or she may receive a payout under the LTIP based on the outcome of the performance period.
Mr. Denault’s 2006 Retention Agreement
In 2006, Entergy Corporation entered into a retention agreement with Mr. Denault that provides benefits to him in addition to, or in lieu of, the benefits described above. Specifically, in the event of a Termination Event (as defined in his agreement): 1) Mr. Denault is entitled to a Target LTIP Award calculated by using the average annual number of performance units with respect to the two most recent performance periods preceding the calendar year in which his employment termination occurs, assuming all performance goals were achieved at target; and 2) all of Mr. Denault’s unvested stock options and shares of restricted stock will immediately vest.
In the event of death or disability, Mr. Denault would receive the greater of the Target LTIP Award calculated as described above or the pro-rated number of performance units for all open performance periods, based on the number of months of his participation in each open performance period.
Under the terms of his 2006 retention agreement, Mr. Denault’s employment may be terminated for cause upon Mr. Denault’s: (a) continuing failure to substantially perform his duties (other than because of physical or mental illness or after he has given notice of termination for good reason) that remains uncured for 30 days after receiving a written notice from the Personnel Committee; (b) willfully engaging in conduct that is demonstrably and materially injurious to Entergy; (c) conviction of or entrance of a plea of guilty or nolo contendere to a felony or other crime that has or may have a material adverse effect on his ability to carry out his duties or upon Entergy’s reputation; (d) material violation of any agreement that he has entered into with Entergy; or (e) unauthorized disclosure of Entergy’s confidential information.
Mr. Denault may terminate his employment for good reason upon: (a) the substantial reduction in the nature or status of his duties or responsibilities from those in effect immediately prior to the date of the retention agreement, other than de minimis acts that are remedied after notice from Mr. Denault; (b) a reduction of 5% or more in his base salary as in effect on the date of the retention agreement; (c) the relocation of his principal place of employment to a location other than the corporate headquarters; (d) the failure to continue to allow him to participate in programs or plans providing opportunities for equity awards, incentive compensation and other plans on a basis not materially less favorable than enjoyed at the time of the retention agreement (other than changes similarly affecting all senior executives); (e) the failure to continue to allow him to participate in programs or plans with opportunities for benefits not materially less favorable than those enjoyed by him under any of the pension, savings, life insurance, medical, health and accident, disability or vacation plans or policies at the time of the retention agreement (other than changes similarly affecting all senior executives); or (f) any purported termination of his employment not taken in accordance with his retention agreement.
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, 2020 under the various scenarios described above. For purposes of these tables, a stock price of $99.84 was used, which was the closing market price of Entergy Corporation stock on December 31, 2020, the last trading day of the year.
504
| Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement | Disability | Death | Termination Related to a Change in Control | ||||||||||||||||
A. Christopher Bakken, III(1) | |||||||||||||||||||||||
Severance Payment | — | — | — | — | — | — | $3,435,870 | ||||||||||||||||
Performance Units(3) | — | — | — | — | $895,065 | $895,065 | $1,086,858 | ||||||||||||||||
Stock Options | — | — | — | — | $552,353 | $552,353 | $552,353 | ||||||||||||||||
Restricted Stock | — | — | — | — | $764,339 | $764,339 | $764,339 | ||||||||||||||||
Welfare Benefits(5) | — | — | — | — | — | — | $22,248 | ||||||||||||||||
Unvested Restricted Stock Units(7) | — | — | — | — | — | — | $1,996,800 | ||||||||||||||||
Marcus V. Brown(2) | |||||||||||||||||||||||
Severance Payment | — | — | — | — | — | — | $3,570,750 | ||||||||||||||||
Performance Units(3) | — | — | — | $876,595 | $876,595 | $876,595 | $1,080,668 | ||||||||||||||||
Stock Options | — | — | — | $547,368 | $547,368 | $547,368 | $547,368 | ||||||||||||||||
Restricted Stock | — | — | — | — | $751,664 | $751,664 | $751,664 | ||||||||||||||||
Welfare Benefits(6) | — | — | — | — | — | — | — | ||||||||||||||||
Leo P. Denault(2) | |||||||||||||||||||||||
Severance Payment | — | — | — | — | — | — | $10,993,273 | ||||||||||||||||
Performance Units(3)(4) | — | — | $4,512,768 | $3,736,712 | $4,512,768 | $4,512,768 | $5,902,641 | ||||||||||||||||
Stock Options | — | — | $2,306,895 | $2,306,895 | $2,306,895 | $2,306,895 | $2,306,895 | ||||||||||||||||
Restricted Stock | — | — | $2,966,300 | — | $2,966,300 | $2,966,300 | $2,966,300 | ||||||||||||||||
Welfare Benefits(6) | — | — | — | — | — | — | — | ||||||||||||||||
David D. Ellis(1) | |||||||||||||||||||||||
Severance Payment | — | — | — | — | — | — | $386,219 | ||||||||||||||||
Performance Units(3) | — | — | — | — | $128,194 | $128,194 | $216,353 | ||||||||||||||||
Stock Options | — | — | — | — | $33,377 | $33,377 | $33,377 | ||||||||||||||||
Restricted Stock | — | — | — | — | $87,425 | $87,425 | $87,425 | ||||||||||||||||
Welfare Benefits(5) | — | — | — | — | — | — | $19,908 | ||||||||||||||||
Haley R. Fisackerly(2) | |||||||||||||||||||||||
Severance Payment | — | — | — | — | — | — | $543,541 | ||||||||||||||||
Performance Units(3) | — | — | — | 128,194 | $128,194 | $128,194 | $216,353 | ||||||||||||||||
Stock Options | — | — | — | 91,899 | $91,899 | $91,899 | $91,899 | ||||||||||||||||
Restricted Stock | — | — | — | 150,174 | $150,174 | $150,174 | $150,174 | ||||||||||||||||
Welfare Benefits(6) | — | — | — | — | — | — | — | ||||||||||||||||
Laura R. Landreaux(1) | |||||||||||||||||||||||
Severance Payment | — | — | — | — | — | — | $457,457 | ||||||||||||||||
Performance Units(3) | — | — | — | — | $128,194 | $128,194 | $216,353 | ||||||||||||||||
Stock Options | — | — | — | — | $36,210 | $36,210 | $36,210 | ||||||||||||||||
Restricted Stock | — | — | — | — | $157,978 | $157,978 | $157,978 | ||||||||||||||||
Welfare Benefits(5) | — | — | — | — | — | — | $19,908 | ||||||||||||||||
505
| Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement | Disability | Death | Termination Related to a Change in Control | ||||||||||||||||
Andrew S. Marsh(1) | |||||||||||||||||||||||
Severance Payment | — | — | — | — | — | — | $3,622,500 | ||||||||||||||||
Performance Units(3) | — | — | — | — | $1,108,224 | $1,108,224 | $1,146,862 | ||||||||||||||||
Stock Options | — | — | — | — | $676,227 | $676,227 | $676,227 | ||||||||||||||||
Restricted Stock | — | — | — | — | $908,105 | $908,105 | $908,105 | ||||||||||||||||
Welfare Benefits(5) | — | — | — | — | — | — | $29,862 | ||||||||||||||||
Phillip R. May, Jr.(2) | |||||||||||||||||||||||
Severance Payment | — | — | — | — | — | — | $1,295,309 | ||||||||||||||||
Performance Units(3) | — | — | — | $189,796 | $189,796 | $189,796 | $361,121 | ||||||||||||||||
Stock Options | — | — | — | $137,838 | $137,838 | $137,838 | $137,838 | ||||||||||||||||
Restricted Stock | — | — | — | — | $215,243 | $215,243 | $215,243 | ||||||||||||||||
Welfare Benefits(6) | — | — | — | — | — | — | — | ||||||||||||||||
Sallie T. Rainer(2) | |||||||||||||||||||||||
Severance Payment | — | — | — | — | — | — | $502,198 | ||||||||||||||||
Performance Units(3) | — | — | — | $128,194 | $128,194 | $128,194 | $216,353 | ||||||||||||||||
Stock Options | — | — | — | $91,899 | $91,899 | $91,899 | $91,899 | ||||||||||||||||
Restricted Stock | — | — | — | — | $150,174 | $150,174 | $150,174 | ||||||||||||||||
Welfare Benefits(6) | — | — | — | — | — | — | — | ||||||||||||||||
Roderick K. West(1) | |||||||||||||||||||||||
Severance Payment | — | — | — | — | — | — | $3,732,501 | ||||||||||||||||
Performance Units(3) | — | — | — | — | $950,177 | $950,177 | $1,108,324 | ||||||||||||||||
Stock Options | — | — | — | — | $580,531 | $580,531 | $580,531 | ||||||||||||||||
Restricted Stock | — | — | — | — | $811,984 | $811,984 | $811,984 | ||||||||||||||||
Welfare Benefits(5) | — | — | — | — | — | — | $29,862 | ||||||||||||||||
1)See “2020 Pension Benefits” for a description of the pension benefits Mr. Bakken, Mr. Ellis, Ms. Landreaux, Mr. Marsh, and Mr. West may receive upon the occurrence of certain termination events.
2)As of December 31, 2020, Mr. Brown, Mr. Denault, Mr. Fisackerly, Mr. May, and Ms. Rainer are retirement eligible and would retire rather than voluntarily resign, and in addition to the payments and benefits in the table, Mr. Brown, Mr. Denault, Mr. Fisackerly, Mr. May, and Ms. Rainer also would be entitled to receive their vested pension benefits under the Entergy Retirement Plan. For a description of these benefits, see “2020 Pension Benefits.”
3)For purposes of the table, in the event of a qualifying termination related to a change in control, each NEO would receive a payment in respect of his performance units for the 2019 – 2021 performance period and a number of performance units for the 2020 – 2022 performance period, calculated as follows.
For the 2019 – 2021 performance period, each NEO would be entitled to receive a single-lump sum payment calculated using the target number of performance units that the officer would have been entitled to receive under the 2015 EOP with respect to the most recent performance period that precedes and does not include the officer’s date of termination. The value of Mr. Denault’s payments was calculated by multiplying the target performance units for the 2017 – 2019 LTIP performance period (48,700) by the closing price of Entergy Corporation stock on December 31, 2020 ($99.84), which would equal a payment of $4,862,208 for the forfeited performance units for the 2019 – 2021 performance period. The value of Mr. Bakken’s, Mr. Brown’s,
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Mr. Marsh’s, and Mr. West’s was calculated by multiplying the target performance units for the 2017 – 2019 LTIP performance period (8,300) by the closing price of Entergy Corporation stock on December 31, 2020 ($99.84), which would equal a payment of $828,672 for the forfeited performance units for the 2019 – 2021 performance period. The value of Mr. May’s payment was calculated by multiplying the target performance units for the 2017 – 2019 LTIP performance period (3,150) by the closing price of Entergy Corporation stock on December 31, 2020 ($99.84), which would equal a payment of $314,496 for the forfeited performance units for the 2019 – 2021 performance period. The value of the payments for the other NEOs was calculated by multiplying the target performance units for the 2017 – 2019 LTIP performance period (1,850) by the closing price of Entergy Corporation stock on December 31, 2020 ($99.84), which would equal a payment of $184,704 for the forfeited performance units for the 2019 – 2021 performance period.
For the 2020 – 2022 performance period, in the event of a qualifying termination related to a change in control, each NEO would be entitled to receive a number of shares of Entergy Corporation stock equal to the greater of (1) the target number of performance units subject to the 2020 – 2022 performance unit agreement or (2) the number of performance units that would vest under the 2020 – 2022 performance unit agreement calculated based on Entergy Corporation’s actual performance through the NEO’s termination date, in either case pro-rated based on the portion of the performance period that occurs through the termination date. For purposes of the table, the values of the performance unit awards for the 2020 – 2022 performance period for each NEO were calculated as follows, based on the assumption that the target number of performance units was the greater number:
Mr. Bakken: 2,586 (12/36*7,758) performance units at target, assuming a stock price of $99.84 = $258,186
Mr. Brown: 2,524 (12/36*7,571) performance units at target, assuming a stock price of $99.84 = $251,996
Mr. Denault: 10,421 (12/36*31,263) performance units at target, assuming a stock price of $99.84 = $1,040,433
Mr. Ellis: 317 (12/36*950) performance units at target, assuming a stock price of $99.84 = $31,649
Mr. Fisackerly: 317 (12/36*950) performance units at target, assuming a stock price of $99.84 = $31,649
Ms. Landreaux: 317 (12/36*950) performance units at target, assuming a stock price of $99.84 = $31,649
Mr. May: 467 (12/36*1,400) performance units at target, assuming a stock price of $99.84 = $46,625
Mr. Marsh: 3,187 (12/36*9,560) performance units at target, assuming a stock price of $99.84 = $318,190
Ms. Rainer: 317 (12/36*950) performance units at target, assuming a stock price of $99.84 = $31,649
Mr. West: 2,801 (12/36*8,401) performance units at target, assuming a stock price of $99.84 = $279,652
The total values of the single sum payment for the 2019 – 2021 performance period and the performance units award for the 2020 – 2022 performance period upon a change in control for each NEO is as follows:
Mr. Bakken: $828,672 + $258,186 = $1,086,858
Mr. Brown: $828,672 + $251,996 = $1,080,668
Mr. Denault: $4,862,208 + $1,040,433 = $5,902,641
Mr. Ellis: $184,704 + $31,649 = $216,353
Mr. Fisackerly: $184,704 + $31,649 = $216,353
Ms. Landreaux: $184,704 + $31,649 = $216,353
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Mr. May: $314,496 + $46,625 = $361,121
Mr. Marsh: $828,672 + $318,190 = $1,146,862
Ms. Rainer: $184,704 + $31,649 = $216,353
Mr. West: $828,672 + $279,652 = $1,108,324
For purposes of the table, the values of the awards payable in the event of retirement in the case of Mr. Denault, Mr. Brown, Mr. Fisackerly, Mr. May, or Ms. Rainer or upon death or disability, other than Mr. Denault, for each NEO were calculated as follows:
Mr. Bakken’s:
2019 – 2021 LTIP Performance Period: 6,379 (24/36*9,568) performance units at target, assuming a stock price of $99.84 = $636,879
2020 – 2022 LTIP Performance Period: 2,586 (12/36*7,758) performance units at target, assuming a stock price of $99.84 = $258,186
Total: $895,065
Mr. Brown’s:
2019 – 2021 LTIP Performance Period: 6,256 (24/36*9,383) performance units at target, assuming a stock price of $99.84 = $$624,599
2020 – 2022 LTIP Performance Period: 2,524 (12/36*7,571) performance units at target, assuming a stock price of $99.84 = $251,996
Total: $876,595
Mr. Denault’s:
2019 – 2021 LTIP Performance Period: 27,006 (24/36*40,508) performance units at target, assuming a stock price of $99.84 = $2,696,279
2020 – 2022 LTIP Performance Period: 10,421 (12/36*31,263) performance units at target, assuming a stock price of $99.84 = $1,040,433
Total: $3,736,712
Mr. Marsh’s:
2019 – 2021 LTIP Performance Period: 7,913 (24/36*11,869) performance units at target, assuming a stock price of $99.84 = $790,034
2020 – 2022 LTIP Performance Period: 3,187 (12/36*9,560) performance units at target, assuming a stock price of $99.84 = $318,190
Total: $1,108,224
Mr. May’s:
2019 – 2021 LTIP Performance Period: 1,434 (24/36*2,150) performance units at target, assuming a stock price of $99.84 = $143,171
2020 – 2022 LTIP Performance Period: 467 (12/36*1,400) performance units at target, assuming a stock price of $99.84 = $46,625
Total: $189,796
Mr. Ellis’s, Mr. Fisackerly’s, Ms. Landreaux’s and Ms. Rainer’s:
2019 – 2021 LTIP Performance Period: 967 (24/36*1,450) performance units at target, assuming a stock price of $99.84 = $96,545
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2020 – 2022 LTIP Performance Period: 317 (12/36*950) performance units at target, assuming a stock price of $99.84 = $31,649
Total: $128,194
Mr. West’s:
2019 – 2021 LTIP Performance Period: 6,716 (24/36*10,073) performance units at target, assuming a stock price of $99.84 = $670,525
2020 – 2022 LTIP Performance Period: 2,801 (12/36*8,401) performance units at target, assuming a stock price of $99.84 = $279,652
Total: $950,177
4)For purposes of the table, the value of Mr. Denault’s retention payment was calculated by taking an average of the target performance units from the 2016 - 2018 LTIP (41,700) and from the 2017 - 2019 LTIP (48,700). This average number of units (45,200) multiplied by the closing price of Entergy stock on December 31, 2020 ($99.84) would equal a payment of $4,512,768.
5)Pursuant to the SERP, in the event of a termination related to a change in control, Mr. Bakken, Mr. Marsh, and Mr. West would be eligible to receive Entergy-subsidized COBRA benefits for 18 months and Mr. Ellis and Ms. Landreaux would be eligible to receive Entergy-subsidized COBRA benefits for 12 months.
6)Upon retirement, Mr. Brown, Mr. Denault, Mr. Fisackerly, Mr. May, and Ms. Rainer would be eligible for retiree medical and dental benefits, the same as all other retirees.
7)Mr. Bakken’s 20,000 restricted stock units vest in two equal installments on April 6, 2022 and April 6, 2025. In the event of a change in control, the unvested restricted stock units will fully vest upon Mr. Bakken’s Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. Bakken is subject to certain restrictions on his ability to compete with Entergy and its affiliates or solicit its employees or customers during and for 12 months after his employment with his Entergy employer. In addition, the restricted stock unit agreement limits Mr. Bakken’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. Bakken will forfeit any restricted stock units that are not yet vested and paid, and 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 2, 2020 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.
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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 2020 Summary Compensation Table with respect to each of the NEOs.
Entergy Arkansas Ratio
For 2020,
•The median of the annual total compensation of all of Entergy Arkansas’s employees, other than Ms. Landreaux, was $135,370.
•Ms. Landreaux’s annual total compensation, as reported in the Total column of the 2020 Summary Compensation Table was $1,150,511.
•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 8:1.
Entergy Louisiana Ratio
For 2020,
•The median of the annual total compensation of all of Entergy Louisiana’s employees, other than Mr. May, was $131,155.
•Mr. May’s annual total compensation, as reported in the Total column of the 2020 Summary Compensation Table, was $2,257,961.
•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 17:1.
Entergy Mississippi Ratio
For 2020,
•The median of the annual total compensation of all of Entergy Mississippi’s employees, other than Mr. Fisackerly, was $111,238.
•Mr. Fisackerly’s annual total compensation, as reported in the Total column of the 2020 Summary Compensation Table, was $1,803,939.
•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 16:1.
Entergy New Orleans Ratio
For 2020,
•The median of the annual total compensation of all of Entergy New Orleans’s employees, other than Mr. Ellis, was $150,102.
•Mr. Ellis’s annual total compensation, as reported in the Total column of the 2020 Summary Compensation Table was $804,810.
•Based on this information, the ratio of the annual total compensation of Mr. Ellis to the median of the annual total compensation of all employees is estimated to be 5:1.
Entergy Texas Ratio
For 2020,
•The median of the annual total compensation of all of Entergy Texas’s employees, other than Ms. Rainer, was $160,680.
•Ms. Rainer’s annual total compensation, as reported in the Total column of the 2020 Summary Compensation Table, was $1,543,383.
•Based on this information, the ratio of the annual total compensation of Ms. Rainer to the median of the annual total compensation of all employees is estimated to be 10:1.
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Item 12. Security Ownership of Certain Beneficial Owners and Management
Entergy Corporation owns 100% of the outstanding common stock of registrant Entergy Texas and indirectly 100% of the outstanding common membership interests of registrants Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The information with respect to 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 Entergy Corporation 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, 2021 for all directors and NEOs. 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.
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| Name | Shares (1)(2) | Options Exercisable Within 60 Days | Stock Units (3) | |||||||||||||||||
| Entergy Corporation | ||||||||||||||||||||
| A. Christopher Bakken, III** | 18,115 | 35,399 | — | |||||||||||||||||
| Marcus V. Brown** | 38,813 | 34,930 | — | |||||||||||||||||
| John R. Burbank* | 3,353 | — | 563 | |||||||||||||||||
| Patrick J. Condon* | 9,333 | — | — | |||||||||||||||||
| Leo P. Denault*** | 324,528 | 899,634 | — | |||||||||||||||||
| Kirkland H. Donald* | 8,590 | — | 3,668 | |||||||||||||||||
| Brian W. Ellis* | 64 | |||||||||||||||||||
| Philip L. Frederickson* | 7,889 | — | 805 | |||||||||||||||||
| Alexis M. Herman* | 14,780 | — | — | |||||||||||||||||
| M. Elise Hyland* | 1,663 | 563 | ||||||||||||||||||
| Stuart L. Levenick* | 22,920 | — | — | |||||||||||||||||
| Blanche L. Lincoln* | 16,654 | — | — | |||||||||||||||||
| Andrew S. Marsh** | 90,482 | 281,147 | — | |||||||||||||||||
| Karen A. Puckett* | 9,333 | — | — | |||||||||||||||||
| Roderick K. West** | 33,757 | 37,517 | — | |||||||||||||||||
| All directors and executive officers as a group (20 persons) | 680,178 | 1,429,697 | 5,599 | |||||||||||||||||
| Entergy Arkansas | ||||||||||||||||||||
| A. Christopher Bakken, III** | 18,115 | 35,399 | — | |||||||||||||||||
| Marcus V. Brown** | 38,813 | 34,930 | — | |||||||||||||||||
| Leo P. Denault** | 324,528 | 899,634 | — | |||||||||||||||||
| Andrew S. Marsh*** | 90,482 | 281,147 | — | |||||||||||||||||
| Laura R. Landreaux*** | 5,678 | 4,833 | — | |||||||||||||||||
| Roderick K. West*** | 33,757 | 37,517 | — | |||||||||||||||||
| All directors and executive officers as a group (8 persons) | 556,160 | 1,390,535 | — | |||||||||||||||||
| Entergy Louisiana | ||||||||||||||||||||
| A. Christopher Bakken, III** | 18,115 | 35,399 | — | |||||||||||||||||
| Marcus V. Brown** | 38,813 | 34,930 | — | |||||||||||||||||
| Leo P. Denault** | 324,528 | 899,634 | — | |||||||||||||||||
| Andrew S. Marsh*** | 90,482 | 281,147 | — | |||||||||||||||||
| Phillip R. May, Jr.*** | 23,383 | 8,833 | 13 | |||||||||||||||||
| Roderick K. West*** | 33,757 | 37,517 | — | |||||||||||||||||
| All directors and executive officers as a group (8 persons) | 573,865 | 1,394,535 | 13 | |||||||||||||||||
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| Name | Shares (1)(2) | Options Exercisable Within 60 Days | Stock Units (3) | |||||||||||||||||
| Entergy Mississippi | ||||||||||||||||||||
| Marcus V. Brown** | 38,813 | 34,930 | — | |||||||||||||||||
| Leo P. Denault** | 324,528 | 899,634 | — | |||||||||||||||||
| Haley R. Fisackerly*** | 7,760 | 5,700 | — | |||||||||||||||||
| Andrew S. Marsh*** | 90,482 | 281,147 | — | |||||||||||||||||
| Roderick K. West*** | 33,757 | 37,517 | — | |||||||||||||||||
| All directors and executive officers as a group (7 persons) | 540,127 | 1,356,003 | — | |||||||||||||||||
| Entergy New Orleans | ||||||||||||||||||||
| Marcus V. Brown** | 38,813 | 34,930 | — | |||||||||||||||||
| Leo P. Denault** | 324,528 | 899,634 | — | |||||||||||||||||
| David D. Ellis*** | 3,332 | 4,199 | — | |||||||||||||||||
| Andrew S. Marsh*** | 90,482 | 281,147 | — | |||||||||||||||||
| Roderick K. West*** | 33,757 | 37,517 | — | |||||||||||||||||
| All directors and executive officers as a group (7 persons) | 535,699 | 1,354,502 | — | |||||||||||||||||
| Entergy Texas | ||||||||||||||||||||
| Marcus V. Brown** | 38,813 | 34,930 | — | |||||||||||||||||
| Leo P. Denault** | 324,528 | 899,634 | — | |||||||||||||||||
| Andrew S. Marsh*** | 90,482 | 281,147 | — | |||||||||||||||||
| Sallie T. Rainer*** | 13,437 | 12,566 | — | |||||||||||||||||
| Roderick K. West*** | 33,757 | 37,517 | — | |||||||||||||||||
| All directors and executive officers as a group (7 persons) | 545,804 | 1,362,869 | — | |||||||||||||||||
| * | 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.
(2)For the non-employee directors, the balances include phantom units that are issued under the Service Recognition Program. All non-employee directors are credited with phantom units for each year of service on the Entergy Corporation Board. These phantom units do not have voting rights or accrue dividends, and will be settled in shares of Entergy Corporation common stock following the non-employee director’s separation from the Board.
(3)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. Messrs. Donald and Frederickson have deferred receipt of some of their quarterly stock grants. The deferred shares will be settled in cash in an amount equal to the market value of Entergy Corporation common stock at the end of the deferral period.
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Equity Compensation Plan Information
The following table summarizes the equity compensation plan information as of December 31, 2020. 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 | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a) | Weighted Average Exercise Price (b)(2) | Number of Securities Remaining Available for Future Issuance (excluding securities reflected in column (a))(c) | |||||||||||||||||
Equity compensation plans approved by security holders (1) | 2,399,379 | $89.63 | 6,108,451 | |||||||||||||||||
Equity compensation plans not approved by security holders | — | — | — | |||||||||||||||||
| Total | 2,399,379 | $89.63 | 6,108,451 | |||||||||||||||||
(1)Includes the 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, the 2015 Equity Plan, and the 2019 Omnibus Incentive Plan. The 2007 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 12, 2006, and only applied to awards granted between January 1, 2007 and May 5, 2011. The 2011 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 6, 2011, and only applied to awards granted between May 6, 2011 and May 7, 2015. The 2015 Equity Plan was approved by Entergy Corporation shareholders on May 8, 2015, and only applied to awards granted between May 8, 2015 and May 3, 2019. The 2019 Omnibus Incentive Plan was approved by the Entergy Corporation shareholders on May 3, 2019, and 7,300,000 shares of Entergy Corporation common stock can be issued from the 2019 Omnibus Incentive Plan, with all shares available for equity-based incentive awards. The 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, the 2015 Equity Plan, and the 2019 Omnibus Incentive Plan (collectively, the “Plans”) are administered by the Personnel Committee of the Board of Directors (other than with respect to awards granted to non-employee directors, which awards are administered by the entire Board of Directors). Eligibility under the Plans is limited to the non-employee directors and to the officers and employees of an Entergy employer or an affiliate of Entergy Corporation. The Plans provide for the issuance of stock options, restricted stock, equity awards (units whose value is related to the value of shares of the common stock but do not represent actual shares of common stock), performance awards (performance shares or units valued by reference to shares of common stock or performance units valued by reference to financial measures or property other than common stock), restricted stock unit awards, and other stock-based awards.
(2)The weighted average exercise price reported in this column does not include outstanding performance awards.
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Item 13. Certain Relationships and Related Party Transactions and Director Independence
For information regarding certain relationship, related transactions and director independence of Entergy Corporation, see the Entergy Corporation Proxy Statement under the headings “Corporate Governance - Director Independence” and “Corporate Governance - Corporate Governance Policies - Review and Approval of Related Party Transactions.”
Entergy Corporation’s Board of Directors has adopted a written Related Party Transaction Approval Policy that applies to any transaction or series of transactions in which Entergy Corporation or a subsidiary is a participant:
•When the amount involved exceeds $120,000; and
•When a Related Party (an Entergy Corporation director or executive officer, any nominee for director, any shareholder owning an excess of 5% of the total equity of Entergy Corporation and any immediate family member of any such person) has a direct or indirect material interest in such transaction(s) (other than solely as a result of being a director or a less than 10% beneficial owner of another entity).
The policy is administered by Entergy Corporation’s Corporate Governance Committee. The committee will consider relevant facts and circumstance in determining whether or not to approve or ratify such a transaction, and will approve or ratify only those transactions that are, in the Corporate Governance Committee’s judgment, appropriate or desirable under the circumstances. The Corporate Governance Committee has determined that certain types of transactions do not create or involve a direct or indirect material interest, including (i) compensation and related party transactions involving a director or an executive officer solely resulting from service as a director or employment with Entergy Corporation so long as the compensation is approved by the Entergy Corporation Board of Directors (or an appropriate committee); (ii) transactions involving public utility services at rates or charges fixed in conformity with law or governmental authority; or (iii) all business relationships between Entergy Corporation and a Related Party made in the ordinary course of business on terms and conditions generally available in the marketplace an in accordance with applicable law. To Entergy Corporation’s knowledge, since January 1, 2020, neither Entergy Corporation nor any of its affiliates has participated in any Related Party transaction.
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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, 2020 and 2019 by Deloitte & Touche LLP were as follows:
| 2020 | 2019 | ||||||||||
| Entergy Corporation (consolidated) | |||||||||||
| Audit Fees | $9,323,550 | $8,710,000 | |||||||||
| Audit-Related Fees (a) | 786,000 | 775,000 | |||||||||
| Total audit and audit-related fees | 10,109,550 | 9,485,000 | |||||||||
| Tax Fees | — | — | |||||||||
| All Other Fees (b) | 183,060 | 31,835 | |||||||||
| Total Fees (c) | $10,292,610 | $9,516,835 | |||||||||
| Entergy Arkansas | |||||||||||
| Audit Fees | $1,137,507 | $1,015,125 | |||||||||
| Audit-Related Fees (a) | — | — | |||||||||
| Total audit and audit-related fees | 1,137,507 | 1,015,125 | |||||||||
| Tax Fees | — | — | |||||||||
| All Other Fees | — | — | |||||||||
| Total Fees (c) | $1,137,507 | $1,015,125 | |||||||||
| Entergy Louisiana | |||||||||||
| Audit Fees | $2,302,851 | $1,871,918 | |||||||||
| Audit-Related Fees (a) | 360,000 | 360,000 | |||||||||
| Total audit and audit-related fees | 2,662,851 | 2,231,918 | |||||||||
| Tax Fees | — | — | |||||||||
| All Other Fees | — | — | |||||||||
| Total Fees (c) | $2,662,851 | $2,231,918 | |||||||||
| Entergy Mississippi | |||||||||||
| Audit Fees | $982,507 | $1,005,125 | |||||||||
| Audit-Related Fees (a) | — | — | |||||||||
| Total audit and audit-related fees | 982,507 | 1,005,125 | |||||||||
| Tax Fees | — | — | |||||||||
| All Other Fees | — | — | |||||||||
| Total Fees (c) | $982,507 | $1,005,125 | |||||||||
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| 2020 | 2019 | ||||||||||
| Entergy New Orleans | |||||||||||
| Audit Fees | $1,027,507 | $950,125 | |||||||||
| Audit-Related Fees (a) | — | — | |||||||||
| Total audit and audit-related fees | 1,027,507 | 950,125 | |||||||||
| Tax Fees | — | — | |||||||||
| All Other Fees | — | — | |||||||||
| Total Fees (c) | $1,027,507 | $950,125 | |||||||||
| Entergy Texas | |||||||||||
| Audit Fees | $1,258,220 | $1,165,125 | |||||||||
| Audit-Related Fees (a) | — | — | |||||||||
| Total audit and audit-related fees | 1,258,220 | 1,165,125 | |||||||||
| Tax Fees | — | — | |||||||||
| All Other Fees | — | — | |||||||||
| Total Fees (c) | $1,258,220 | $1,165,125 | |||||||||
| System Energy | |||||||||||
| Audit Fees | $1,017,507 | $930,125 | |||||||||
| Audit-Related Fees (a) | — | — | |||||||||
| Total audit and audit-related fees | 1,017,507 | 930,125 | |||||||||
| Tax Fees | — | — | |||||||||
| All Other Fees | — | — | |||||||||
| Total Fees (c) | $1,017,507 | $930,125 | |||||||||
(a)Includes fees for employee benefit plan audits, consultation on financial accounting and reporting, and other attestation services.
(b)Includes fees for cybersecurity assessment and license fee for accounting research tool.
(c)100% of fees paid in 2020 and 2019 were pre-approved by the Entergy Corporation Audit Committee.
517
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.
bAll 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.
518
PART IV
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 542) | |||||
| 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 520 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.
519
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
Entergy Arkansas
Entergy Louisiana
| (b) 1 -- | |||||
| (b) 2 -- | |||||
| (b) 3 -- | |||||
Entergy Mississippi
Entergy New Orleans
(3) Articles of Incorporation and Bylaws
Entergy Corporation
| (a) 1 -- | |||||
| (a) 2 -- | |||||
520
System Energy
| (b) 1 -- | |||||
| (b) 2 -- | |||||
Entergy Arkansas
| (c) 1 -- | |||||
| (c) 2 -- | |||||
Entergy Louisiana
| (d) 1 -- | |||||
| (d) 2 -- | |||||
Entergy Mississippi
| (e) 1 -- | |||||
| (e) 2 -- | |||||
Entergy New Orleans
| (f) 1 -- | |||||
| (f) 2 -- | |||||
Entergy Texas
(4)Instruments Defining Rights of Security Holders, Including Indentures
Entergy Corporation
| (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. | ||||
521
| (a) 2 -- | |||||
| (a) 3 -- | |||||
| (a) 4 -- | |||||
| (a) 5 -- | |||||
| (a) 6 -- | |||||
| (a) 7 -- | |||||
| (a) 8 -- | |||||
| (a) 9 -- | |||||
| (a) 10 -- | |||||
| *(a) 11 -- | |||||
System Energy
| (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 -- | |||||
| (b) 3 -- | |||||
| (b) 4 -- | |||||
522
Entergy Arkansas
523
Entergy Louisiana
524
525
| (d) 19 -- | |||||
| (d) 20 -- | |||||
| (d) 21 -- | |||||
| (d) 22 -- | |||||
| (d) 23 -- | |||||
| *(d) 24 -- | |||||
Entergy Mississippi
Entergy New Orleans
526
| (f) 3 -- | |||||
| *(f) 4 -- | |||||
Entergy Texas
| (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 -- | |||||
| (g) 3 -- | |||||
| (g) 4 -- | |||||
| (g) 5 -- | |||||
| (g) 6 -- | |||||
| (g) 7 -- | |||||
| (g) 8 -- | |||||
| (g) 9 -- | |||||
| (g) 10 -- | |||||
| (g) 11 -- | |||||
527
| (g) 12 -- | |||||
| *(g) 13 -- | |||||
(10) Material Contracts
Entergy Corporation
| +(a)1-- | |||||
| +(a) 2 -- | |||||
| +(a) 3 -- | |||||
| +(a) 4 -- | |||||
| +(a) 5 -- | |||||
| +(a) 6 -- | |||||
| +(a) 7 -- | |||||
| +(a) 8 -- | |||||
| +(a) 9 -- | |||||
| +(a) 10 -- | |||||
| +(a) 11 -- | |||||
| +(a) 12 -- | |||||
| +(a) 13 -- | |||||
528
| +(a) 14 -- | |||||
| +(a) 15 -- | |||||
| +(a) 16 -- | |||||
| +(a) 17 -- | |||||
| +(a) 18 -- | |||||
| +(a) 19 -- | |||||
| +(a) 20 -- | |||||
| +(a) 21 -- | |||||
| +(a) 22 -- | |||||
| +(a) 23 -- | |||||
| +(a) 24 -- | |||||
| +(a) 25 -- | |||||
| +(a) 26 -- | |||||
| +(a) 27 -- | |||||
| +(a) 28 -- | |||||
| +(a) 29 -- | |||||
| +(a) 30 -- | |||||
529
| +(a) 31 -- | |||||
| +(a) 32 -- | |||||
| +(a) 33 -- | |||||
| +(a) 34 -- | |||||
| +(a) 35 -- | |||||
| +(a) 36 -- | |||||
| +(a) 37 -- | |||||
| +(a) 38-- | |||||
| +(a)39-- | |||||
| *+(a) 40 -- | |||||
| +(a) 41 -- | |||||
| +(a) 42 -- | |||||
| +(a) 43 -- | |||||
| +(a) 44 -- | |||||
| +(a) 45 -- | |||||
| *+(a) 46 -- | |||||
System Energy
| (b) 1 -- | |||||
| (b) 2 -- | |||||
| (b) 3 -- | |||||
530
| (b) 4 -- | |||||
| (b) 5 -- | |||||
| (b) 6 -- | |||||
| (b) 7 -- | |||||
| (b) 8 -- | 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) 9 -- | |||||
| (b) 10 -- | |||||
| (b) 11 -- | |||||
| (b) 12 -- | |||||
| (b) 13 -- | |||||
| (b) 14 -- | |||||
Entergy Louisiana
(14) Code of Ethics
Entergy Corporation
(23) Consents of Experts and Counsel
531
(31) Rule 13a-14(a)/15d-14(a) Certifications
| *(a) | |||||
| *(b) | |||||
| *(c) | |||||
| *(d) | |||||
| *(e) | |||||
| *(f) | |||||
| *(g) | |||||
| *(h) | |||||
| *(i) | |||||
| *(j) | |||||
| *(k) | |||||
| *(l) | |||||
| *(m) | |||||
| *(n) | |||||
(32) Section 1350 Certifications
| **(a) | |||||
| **(b) | |||||
| **(c) | |||||
| **(d) | |||||
| **(e) | |||||
| **(f) | |||||
| **(g) | |||||
| **(h) | |||||
| **(i) | |||||
| **(j) | |||||
| **(k) | |||||
532
| **(l) | |||||
| **(m) | |||||
| **(n) | |||||
(101) Interactive Data File
| *INS - | Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | ||||
| *SCH - | Inline XBRL Schema Document. | ||||
| *CAL - | Inline XBRL Calculation Linkbase Document. | ||||
| *DEF - | Inline XBRL Definition Linkbase Document. | ||||
| *LAB - | Inline XBRL Label Linkbase Document. | ||||
| *PRE - | Inline XBRL Presentation Linkbase Document. | ||||
*(104) Cover Page Interactive Data File (formatted in Inline XBRL and contained in Exhibits 101)
_________________
| * | Filed herewith. | |||||||
| ** | Furnished, not filed, herewith. | |||||||
| + | Management contracts or compensatory plans or arrangements. | |||||||
533
ENTERGY CORPORATION
SIGNATURES
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 | |||||
By /s/ Kimberly A. Fontan | |||||
| Kimberly A. Fontan | |||||
| Senior Vice President and Chief Accounting Officer | |||||
| Date: February 26, 2021 | |||||
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.
| Signature | Title | Date | ||||||
/s/ Kimberly A. Fontan Kimberly A. Fontan | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 26, 2021 | ||||||
Leo P. Denault (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President and Chief Financial Officer; Principal Financial Officer); John R. Burbank, Patrick J. Condon, Kirkland H. Donald, Brian W. Ellis, Philip L. Frederickson, Alexis M. Herman, M. Elise Hyland, Stuart L. Levenick, Blanche L. Lincoln, and Karen A. Puckett (Directors).
By: /s/ Kimberly A. Fontan | February 26, 2021 | ||||
| (Kimberly A. Fontan, Attorney-in-fact) | |||||
534
ENTERGY ARKANSAS, LLC
SIGNATURES
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 | |||||
By /s/ Kimberly A. Fontan | |||||
| Kimberly A. Fontan | |||||
| Senior Vice President and Chief Accounting Officer | |||||
| Date: February 26, 2021 | |||||
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.
| Signature | Title | Date | ||||||
/s/ Kimberly A. Fontan Kimberly A. Fontan | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 26, 2021 | ||||||
Laura R. Landreaux (Chair of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Paul D. Hinnenkamp and Roderick K. West (Directors).
By: /s/ Kimberly A. Fontan | February 26, 2021 | ||||
| (Kimberly A. Fontan, Attorney-in-fact) | |||||
535
ENTERGY LOUISIANA, LLC
SIGNATURES
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 | |||||
By /s/ Kimberly A. Fontan | |||||
| Kimberly A. Fontan | |||||
| Senior Vice President and Chief Accounting Officer | |||||
| Date: February 26, 2021 | |||||
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.
| Signature | Title | Date | ||||||
/s/ Kimberly A. Fontan Kimberly A. Fontan | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 26, 2021 | ||||||
Phillip R. May, Jr. (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Paul D. Hinnenkamp and Roderick K. West (Directors).
By: /s/ Kimberly A. Fontan | February 26, 2021 | ||||
| (Kimberly A. Fontan, Attorney-in-fact) | |||||
536
ENTERGY MISSISSIPPI, LLC
SIGNATURES
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 | |||||
By /s/ Kimberly A. Fontan | |||||
| Kimberly A. Fontan | |||||
| Senior Vice President and Chief Accounting Officer | |||||
| Date: February 26, 2021 | |||||
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.
| Signature | Title | Date | ||||||
/s/ Kimberly A. Fontan Kimberly A. Fontan | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 26, 2021 | ||||||
Haley R. Fisackerly (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Paul D. Hinnenkamp and Roderick K. West (Directors).
By: /s/ Kimberly A. Fontan | February 26, 2021 | ||||
| (Kimberly A. Fontan, Attorney-in-fact) | |||||
537
ENTERGY NEW ORLEANS, LLC
SIGNATURES
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 | |||||
By /s/ Kimberly A. Fontan | |||||
| Kimberly A. Fontan | |||||
| Senior Vice President and Chief Accounting Officer | |||||
| Date: February 26, 2021 | |||||
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.
| Signature | Title | Date | ||||||
/s/ Kimberly A. Fontan Kimberly A. Fontan | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 26, 2021 | ||||||
David D. Ellis (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Paul D. Hinnenkamp and Roderick K. West (Directors).
By: /s/ Kimberly A. Fontan | February 26, 2021 | ||||
| (Kimberly A. Fontan, Attorney-in-fact) | |||||
538
ENTERGY TEXAS, INC.
SIGNATURES
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. | |||||
By /s/ Kimberly A. Fontan | |||||
| Kimberly A. Fontan | |||||
| Senior Vice President and Chief Accounting Officer | |||||
| Date: February 26, 2021 | |||||
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.
| Signature | Title | Date | ||||||
/s/ Kimberly A. Fontan Kimberly A. Fontan | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 26, 2021 | ||||||
Sallie T. Rainer (Chair of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Paul D. Hinnenkamp and Roderick K. West (Directors).
By: /s/ Kimberly A. Fontan | February 26, 2021 | ||||
| (Kimberly A. Fontan, Attorney-in-fact) | |||||
539
SYSTEM ENERGY RESOURCES, INC.
SIGNATURES
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.
| SYSTEM ENERGY RESOURCES, INC. | |||||
By /s/ Kimberly A. Fontan | |||||
| Kimberly A. Fontan | |||||
| Senior Vice President and Chief Accounting Officer | |||||
| Date: February 26, 2021 | |||||
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.
| Signature | Title | Date | ||||||
/s/ Kimberly A. Fontan Kimberly A. Fontan | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 26, 2021 | ||||||
Roderick K. West (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); A. Christopher Bakken, III and Steven C. McNeal (Directors).
By: /s/ Kimberly A. Fontan | February 26, 2021 | ||||
| (Kimberly A. Fontan, Attorney-in-fact) | |||||
540
EXHIBIT 23(a)
CONSENTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No. 333-233403 on Form S-3 and in Registration Statements Nos. 333-140183, 333-174148, 333-204546, 333-231800 and 333-251819 on Form S-8 of our reports dated February 26, 2021, 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, 2020.
We consent to the incorporation by reference in Registration Statement No. 333-233403-05 on Form S-3 of our reports dated February 26, 2021, 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, 2020.
We consent to the incorporation by reference in Registration Statement No. 233403-04 on Form S-3 of our reports dated February 26, 2021, 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, 2020.
We consent to the incorporation by reference in Registration Statement No. 233403-03 on Form S-3 of our reports dated February 26, 2021, relating to the financial statements and financial statement schedule of Entergy Mississippi, LLC appearing in this Annual Report on Form 10‑K of Entergy Mississippi, LLC for the year ended December 31, 2020.
We consent to the incorporation by reference in Registration Statement No. 233403-02 on Form S-3 of our reports dated February 26, 2021, 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, 2020.
We consent to the incorporation by reference in Registration Statement No. 233403-01 on Form S-3 of our report dated February 26, 2021, 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, 2020.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2021
541
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors of
Entergy Corporation and Subsidiaries
Opinion on the Financial Statement Schedule
We have audited the consolidated financial statements of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2020 and 2019, and for each of the three years in the period ended December 31, 2020, and the Corporation’s internal control over financial reporting as of December 31, 2020, and have issued our reports thereon dated February 26, 2021. 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.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2021
542
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors of
Entergy Texas, Inc. and Subsidiaries
To the member and Board of Directors of
Entergy Arkansas, LLC and Subsidiaries
Entergy Louisiana, LLC and Subsidiaries
Entergy Mississippi, LLC
Entergy New Orleans, LLC and Subsidiaries
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 New Orleans, LLC and Subsidiaries, and Entergy Texas, Inc. and Subsidiaries, and we have also audited the financial statements of Entergy Mississippi, LLC (collectively the “Companies”) as of December 31, 2020 and 2019, and for each of the three years in the period ended December 31, 2020, and have issued our reports thereon dated February 26, 2021. 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.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2021
543
INDEX TO FINANCIAL STATEMENT SCHEDULES
| Schedule | Page | |||||||
| II | Valuation and Qualifying Accounts 2020, 2019, and 2018: | |||||||
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
| ENTERGY CORPORATION AND SUBSIDIARIES | ||||||||||||||||||||||||||
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | ||||||||||||||||||||||||||
| For the Years Ended December 31, 2020, 2019, and 2018 | ||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||
| Column A | Column B | Column C | Column D | Column E | ||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Balance at | Additions | Changes | Balance | |||||||||||||||||||||||
| Description | Beginning of Period | Charged to Income (1) | Deductions (2) | at End of Period | ||||||||||||||||||||||
| Allowance for doubtful accounts | ||||||||||||||||||||||||||
| 2020 | $7,404 | $111,687 | $1,297 | $117,794 | ||||||||||||||||||||||
| 2019 | $7,322 | $2,806 | $2,724 | $7,404 | ||||||||||||||||||||||
| 2018 | $13,587 | $3,936 | $10,201 | $7,322 | ||||||||||||||||||||||
| Notes: | ||||||||||||||||||||||||||
| (1) A portion of the charges to income are deferred as a regulatory asset. | ||||||||||||||||||||||||||
| (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. | ||||||||||||||||||||||||||
S-2
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES | ||||||||||||||||||||||||||
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | ||||||||||||||||||||||||||
| For the Years Ended December 31, 2020, 2019, and 2018 | ||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||
| Column A | Column B | Column C | Column D | Column E | ||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Balance at | Additions | Changes | Balance | |||||||||||||||||||||||
| Description | Beginning of Period | Charged to Income (1) | Deductions (2) | at End of Period | ||||||||||||||||||||||
| Allowance for doubtful accounts | ||||||||||||||||||||||||||
| 2020 | $1,169 | $17,307 | $142 | $18,334 | ||||||||||||||||||||||
| 2019 | $1,264 | $1,000 | $1,095 | $1,169 | ||||||||||||||||||||||
| 2018 | $1,063 | $810 | $609 | $1,264 | ||||||||||||||||||||||
| Notes: | ||||||||||||||||||||||||||
| (1) A portion of the charges to income are deferred as a regulatory asset. | ||||||||||||||||||||||||||
| (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. | ||||||||||||||||||||||||||
S-3
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | ||||||||||||||||||||||||||
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | ||||||||||||||||||||||||||
| For the Years Ended December 31, 2020, 2019, and 2018 | ||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||
| Column A | Column B | Column C | Column D | Column E | ||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Balance at | Additions | Changes | Balance | |||||||||||||||||||||||
| Description | Beginning of Period | Charged to Income (1) | Deductions (2) | at End of Period | ||||||||||||||||||||||
| Allowance for doubtful accounts | ||||||||||||||||||||||||||
| 2020 | $1,902 | $44,542 | $751 | $45,693 | ||||||||||||||||||||||
| 2019 | $1,813 | $762 | $673 | $1,902 | ||||||||||||||||||||||
| 2018 | $8,430 | $2,395 | $9,012 | $1,813 | ||||||||||||||||||||||
| Notes: | ||||||||||||||||||||||||||
| (1) A portion of the charges to income are deferred as a regulatory asset. | ||||||||||||||||||||||||||
| (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. | ||||||||||||||||||||||||||
S-4
| ENTERGY MISSISSIPPI, LLC | ||||||||||||||||||||||||||
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | ||||||||||||||||||||||||||
| For the Years Ended December 31, 2020, 2019, and 2018 | ||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||
| Column A | Column B | Column C | Column D | Column E | ||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Balance at | Additions | Changes | Balance | |||||||||||||||||||||||
| Description | Beginning of Period | Charged to Income (1) | Deductions (2) | at End of Period | ||||||||||||||||||||||
| Allowance for doubtful accounts | ||||||||||||||||||||||||||
| 2020 | $636 | $19,081 | $190 | $19,527 | ||||||||||||||||||||||
| 2019 | $563 | $406 | $333 | $636 | ||||||||||||||||||||||
| 2018 | $574 | $265 | $276 | $563 | ||||||||||||||||||||||
| Notes: | ||||||||||||||||||||||||||
| (1) A portion of the charges to income are deferred as a regulatory asset. | ||||||||||||||||||||||||||
| (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. | ||||||||||||||||||||||||||
S-5
| ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES | ||||||||||||||||||||||||||
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | ||||||||||||||||||||||||||
| For the Years Ended December 31, 2020, 2019, and 2018 | ||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||
| Column A | Column B | Column C | Column D | Column E | ||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Balance at | Additions | Changes | Balance | |||||||||||||||||||||||
| Description | Beginning of Period | Charged to Income (1) | Deductions (2) | at End of Period | ||||||||||||||||||||||
| Allowance for doubtful accounts | ||||||||||||||||||||||||||
| 2020 | $3,226 | $14,204 | $— | $17,430 | ||||||||||||||||||||||
| 2019 | $3,222 | $316 | $312 | $3,226 | ||||||||||||||||||||||
| 2018 | $3,057 | $187 | $22 | $3,222 | ||||||||||||||||||||||
| Notes: | ||||||||||||||||||||||||||
| (1) A portion of the charges to income are deferred as a regulatory asset. | ||||||||||||||||||||||||||
| (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. | ||||||||||||||||||||||||||
S-6
| ENTERGY TEXAS, INC. AND SUBSIDIARIES | ||||||||||||||||||||||||||
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | ||||||||||||||||||||||||||
| For the Years Ended December 31, 2020, 2019, and 2018 | ||||||||||||||||||||||||||
| (In Thousands) | ||||||||||||||||||||||||||
| Column A | Column B | Column C | Column D | Column E | ||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Balance at | Additions | Changes | Balance | |||||||||||||||||||||||
| Description | Beginning of Period | Charged to Income (1) | Deductions (2) | at End of Period | ||||||||||||||||||||||
| Allowance for doubtful accounts | ||||||||||||||||||||||||||
| 2020 | $471 | $16,554 | $215 | $16,810 | ||||||||||||||||||||||
| 2019 | $461 | $321 | $311 | $471 | ||||||||||||||||||||||
| 2018 | $463 | $279 | $281 | $461 | ||||||||||||||||||||||
| Notes: | ||||||||||||||||||||||||||
| (1) A portion of the charges to income are deferred as a regulatory asset. | ||||||||||||||||||||||||||
| (2) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. | ||||||||||||||||||||||||||
S-7