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ENTERGY ARKANSAS, LLC - Annual Report: 2018 (Form 10-K)

Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)
 
 
 
X
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
 
 
 
For the Fiscal Year Ended December 31, 2018
 
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
(a Delaware corporation)
639 Loyola Avenue
New Orleans, Louisiana 70113
Telephone (504) 576-4000
72-1229752
 
1-35747

ENTERGY NEW ORLEANS, LLC
(a Texas limited liability company)
1600 Perdido Street
New Orleans, Louisiana 70112
Telephone (504) 670-3700
82-2212934
 
 
 
 
 
 
 
 
 
 
1-10764
ENTERGY ARKANSAS, LLC
(a Texas limited liability company)
425 West Capitol Avenue
Little Rock, Arkansas 72201
Telephone (501) 377-4000
83-1918668
 
1-34360

ENTERGY TEXAS, INC.
(a Texas corporation)
10055 Grogans Mill Road
The Woodlands, Texas 77380
Telephone (409) 981-2000
61-1435798
 
 
 
 
 
 
 
 
 
 
1-32718

ENTERGY LOUISIANA, LLC
(a Texas limited liability company)
4809 Jefferson Highway
Jefferson, Louisiana 70121
Telephone (504) 576-4000
47-4469646
 
1-09067

SYSTEM ENERGY RESOURCES, INC.
(an Arkansas corporation)
1340 Echelon Parkway
Jackson, Mississippi 39213
Telephone (601) 368-5000
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
 
 
 

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Securities registered pursuant to Section 12(b) of the Act:
Registrant
Title of Class
Name of Each Exchange
on Which Registered
 
 
 
Entergy Corporation
Common Stock, $0.01 Par Value – 189,580,512 shares outstanding at January 31, 2019
New York Stock Exchange, Inc.
Chicago Stock Exchange, Inc.
 
 
 
Entergy Arkansas, LLC
Mortgage Bonds, 4.90% Series due December 2052
New York Stock Exchange, Inc.
 
Mortgage Bonds, 4.75% Series due June 2063
New York Stock Exchange, Inc.
 
Mortgage Bonds, 4.875% Series due September 2066
New York Stock Exchange, Inc.
 
 
 
Entergy Louisiana, LLC
Mortgage Bonds, 5.25% Series due July 2052
New York Stock Exchange, Inc.
 
Mortgage Bonds, 4.70% Series due June 2063
New York Stock Exchange, Inc.
 
Mortgage Bonds, 4.875% Series due September 2066
New York Stock Exchange, Inc.
 
 
 
Entergy Mississippi, LLC
Mortgage Bonds, 4.90% Series due October 2066
New York Stock Exchange, Inc.
 
 
 
Entergy New Orleans, LLC
Mortgage Bonds, 5.0% Series due December 2052
New York Stock Exchange, Inc.
 
Mortgage Bonds, 5.50% Series due April 2066
New York Stock Exchange, Inc.
 
 
 
Entergy Texas, Inc.
Mortgage Bonds, 5.625% Series due June 2064
New York Stock Exchange, Inc.

Securities registered pursuant to Section 12(g) of the Act:
Registrant
Title of Class
 
 
Entergy Texas, Inc.
Common Stock, no par value


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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 registrant was required to submit such files).  Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [ ]


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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. o

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act.)  Yes o  No þ

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 2018 was $14.6 billion based on the reported last sale price of $80.79 per share for such stock on the New York Stock Exchange on June 29, 2018.  Entergy Corporation is the sole holder of the common stock of Entergy Texas, Inc. and System Energy Resources, Inc.  Entergy Corporation is the direct and indirect holder of the common membership interests of Entergy Utility Holding Company, LLC, which is the sole holder of the common membership interests of Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, LLC, and Entergy New Orleans, LLC.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders, to be held May 3, 2019, 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.
 
 
 
Part I. Item 1A.
Unresolved Staff Comments
Part I. Item 1B.
None

i
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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.
Part II. Item 8.
Part II. Item 8.

ii
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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 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.

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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, 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, 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;
•
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, 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 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, potential, or actual shutdown of 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;
•
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 or 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;

iv
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FORWARD-LOOKING INFORMATION (Continued)

•
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, 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, 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;
•
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 and 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;
•
federal income tax reform, including the enactment 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, especially in light of federal income tax reform;
•
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;
•
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 effect 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 (iii) competition from other companies offering products and services to Entergy’s customers based on new or emerging technologies or alternative sources of generation;
•
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;
•
Entergy’s ability to attract and retain talented management, directors, and employees with specialized skills;
•
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;

v
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FORWARD-LOOKING INFORMATION (Concluded)

•
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 of Pilgrim, 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;
•
factors that could lead to impairment of long-lived assets; and
•
the ability to successfully complete strategic transactions Entergy may undertake, including mergers, acquisitions, divestitures, or restructurings, regulatory or other limitations imposed as a result of any such strategic transaction, and the success of the business following any such strategic transaction.

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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
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
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

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DEFINITIONS (Continued)

Abbreviation or Acronym
Term
 
 
Indian Point 2
Unit 2 of Indian Point Energy Center (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
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), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
PPA
Purchased power agreement or power purchase agreement
PRP
Potentially responsible party (a person or entity that may be responsible for remediation of environmental contamination)
PUCT
Public Utility Commission of Texas
Registrant Subsidiaries
Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, LLC, Entergy New Orleans, LLC, Entergy Texas, Inc., and System Energy Resources, Inc.
River Bend
River Bend Station (nuclear), owned by Entergy Louisiana
RTO
Regional transmission organization
SEC
Securities and Exchange Commission

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DEFINITIONS (Concluded)

Abbreviation or Acronym
Term
 
 
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), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment, which ceased power production in December 2014 and was sold 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 or 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
2018
2017
2016
 
2018
2017
2016
Utility
87

85

83

 
93

92

89

Entergy Wholesale Commodities
13

15

17

 
11

12

15

Parent & Other
—

—

—

 
(4
)
(4
)
(4
)

See Note 13 to the financial statements for further financial information regarding Entergy’s business segments.
 
    
    


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Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis


Results of Operations

2018 Compared to 2017
  
Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2018 to 2017 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)
2017 Consolidated Net Income (Loss)

$773,148

 

($172,335
)
 

($175,460
)
 

$425,353

 
 
 
 
 
 
 
 
Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits)
(692,557
)
 
(192,471
)
 
(4
)
 
(885,032
)
Other operation and maintenance
85,239

 
(55,736
)
 
10,200

 
39,703

Asset write-offs, impairments, and related charges
—

 
(6,051
)
 
—

 
(6,051
)
Taxes other than income taxes
25,578

 
(1,446
)
 
264

 
24,396

Depreciation and amortization
23,141

 
(43,273
)
 
(404
)
 
(20,536
)
Other income
22,024

 
(221,550
)
 
(6,621
)
 
(206,147
)
Interest expense
5,618

 
9,980

 
29,407

 
45,005

Other expenses
(4,858
)
 
(26,644
)
 
—

 
(31,502
)
Income taxes
(1,527,164
)
 
(122,545
)
 
70,313

 
(1,579,396
)
2018 Consolidated Net Income (Loss)

$1,495,061

 

($340,641
)
 

($291,865
)
 

$862,555


(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 2018 include: 1) $532 million ($421 million net-of-tax) of impairment charges 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 reduce the size of the Entergy Wholesale Commodities’ merchant fleet; 2) a $170 million reduction of income tax expense and a regulatory liability of $40 million ($30 million net-of-tax) as a result of customer credits recognized by Utility, as a result of internal restructuring; 3) a $107 million reduction of income tax expense, recognized by Entergy Wholesale Commodities, as a result of a restructuring of the investment holdings in one of its nuclear plant decommissioning trust funds; 4) a $52 million income tax benefit, recognized by Entergy Louisiana, as a result of the settlement of the 2012-2013 IRS audit, associated with the Hurricane Katrina and Hurricane Rita contingent sharing obligation associated with the Louisiana Act 55 financing; and 5) a $23 million reduction of income tax expense, recognized by Entergy Wholesale Commodities, as a result of a state income tax audit. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” below for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet and see Note 14 to the financial statements for further discussion of the impairment and related charges. See Notes 2 and 3 to the financial statements for further discussion of the internal restructuring and customer credits. See Note 3 to the financial statements for further discussion of the IRS audit settlement, the state income tax audit, and restructuring of the decommissioning trust fund investment holdings.


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Management’s Financial Discussion and Analysis

Results of operations for 2017 include: 1) $538 million ($350 million net-of-tax) of impairment charges due to costs being charged 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 reduce the size of the Entergy Wholesale Commodities’ merchant fleet; 2) a reduction in net income of $181 million, including a $34 million net-of-tax reduction of regulatory liabilities, at Utility and $397 million at Entergy Wholesale Commodities and an increase in net income of $52 million at Parent and Other as a result of Entergy’s re-measurement of its deferred tax assets and liabilities not subject to the ratemaking process due to the enactment of the Tax Cuts and Jobs Act, in December 2017, which lowered the federal corporate income tax rate from 35% to 21%; and 3) a reduction in income tax expense, net of unrecognized tax benefits, of $373 million as a result of a change in the tax classification of legal entities that own Entergy Wholesale Commodities nuclear power plants. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” below for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet and see Note 14 to the financial statements for further discussion of the impairment and related charges. See Note 3 to the financial statements for further discussion of the effects of the Tax Cuts and Jobs Act and the change in the tax classification.

Net Revenue

Utility

Following is an analysis of the change in net revenue comparing 2018 to 2017.
  
Amount
  
(In Millions)
 
 
2017 net revenue

$6,318

Return of unprotected excess accumulated deferred income taxes to customers
(770
)
Grand Gulf recovery
(74
)
Regulatory credit in 2017 resulting from reduction of the federal corporate income tax rate
(56
)
Formula rate plan regulatory provisions
(44
)
Entergy Arkansas internal restructuring customer credits
(40
)
Retail electric price
4

Net wholesale revenue
57

Volume/weather
210

Other
20

2018 net revenue

$5,625


The return of unprotected excess accumulated deferred income taxes to customers resulted from activity in 2018 at the Utility operating companies and System Energy in response to the enactment of the Tax Cuts and Jobs Act. There is no effect on net income as the reductions in net revenue were offset by reductions in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.

The Grand Gulf recovery variance is primarily due to a reduction in depreciation expense recognized in third quarter 2018 upon FERC approval of the settlement in the Unit Power Sales Agreement proceeding, a reduction in income tax expense associated with the reduction in the federal income tax rate in 2018, and a reduction in recoverable decommissioning costs primarily attributable to changes in decommissioning trust fund activity. The reductions were partially offset by increases in other capacity costs. See Note 2 to the financial statements for a discussion of the Unit

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Management’s Financial Discussion and Analysis


Power Sales Agreement settlement. See Note 3 to the financial statements for a discussion of the effects of the Tax Cut and Jobs Act.

The regulatory credit in 2017 resulting from reduction of the federal corporate income tax rate variance is due to the reduction of the Vidalia purchased power agreement regulatory liability by $30.5 million and the reduction in 2017 of the Louisiana Act 55 financing savings obligation regulatory liabilities by $25 million, in each case, as a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, which lowered the federal corporate income tax rate from 35% to 21%. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements. See Note 8 to the financial statements for further discussion of the Vidalia purchased power agreement.
 
The formula rate plan regulatory provisions variance is due to provisions, recorded in the fourth quarter 2018 at Entergy Arkansas and Entergy Mississippi, for estimated reductions in future revenue expected to be reflected in upcoming formula rate plan filings based on actual results for 2018. See Note 2 to the financial statements for a discussion of the regulatory provisions related to these formula rate plan filings.

The Entergy Arkansas internal restructuring customer credits variance is due to a regulatory liability recorded by Entergy in December 2018 as a result of the internal restructuring of Entergy Arkansas. Pursuant to a settlement agreement approved by the APSC, Entergy Arkansas will credit retail customers $39.6 million over six years, beginning in 2019. See Note 2 to the financial statements for further discussion of the internal restructuring and customer credits.

The retail electric price variance is primarily due to:

•
an increase in formula rate plan rates effective with the first billing cycle of January 2018 at Entergy Arkansas, as approved by the APSC;
•
an increase in energy efficiency revenues primarily due to an increase in the Entergy Arkansas energy efficiency rider and a new Entergy Louisiana energy efficiency rider effective January 2018;
•
a base rate increase effective October 2018 at Entergy Texas, as approved by the PUCT;
•
an increase in formula rate plan revenues at Entergy Louisiana, implemented with the first billing cycle of September 2018; and
•
higher storm damage rider revenues at Entergy Mississippi.

The increases were substantially offset by regulatory charges recorded in 2018 to reflect the effects of regulatory agreements to return the benefits of the lower income tax rate in 2018 to Louisiana, New Orleans, and Texas customers.

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

The net wholesale revenue variance is primarily because of the regulatory lag experienced by certain Utility operating companies as a result of the change in the federal income tax rate in 2018 and its effect on wholesale rates. See Note 2 to the financial statements for discussion of regulatory activity regarding the Tax Cuts and Jobs Act.

The volume/weather variance is primarily due to an increase of 4,804 GWh, or 4%, in billed electricity usage, including the effect of more favorable weather on residential and commercial sales and an increase in industrial usage. The increase in industrial usage is primarily driven by small industrials sales, as well as continued growth from new customers and expansion projects, partially offset by decreased demand from existing customers.


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Management’s Financial Discussion and Analysis

Entergy Wholesale Commodities

Following is an analysis of the change in net revenue comparing 2018 to 2017.
  
Amount
  
(In Millions)
 
 
2017 net revenue

$1,469

FitzPatrick reimbursement agreement
(98
)
Nuclear realized price changes
(42
)
Nuclear volume
(23
)
Other
(29
)
2018 net revenue

$1,277


As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by $192 million in 2018 primarily due to:

•
a decrease resulting from the reimbursement agreement with Exelon pursuant to which Exelon reimbursed Entergy in the first quarter 2017 for specified out-of-pocket costs associated with preparing for the refueling and operation of FitzPatrick that otherwise would have been avoided had Entergy shut down FitzPatrick in January 2017. Revenues received from Exelon under the reimbursement agreement were offset by other operation and maintenance expenses and taxes other than income taxes and had no effect on net income. See Note 14 to the financial statements for discussion of the sale of FitzPatrick and the reimbursement agreement with Exelon;
•
lower realized wholesale energy prices, partially offset by higher capacity prices; and
•
lower volume in the Entergy Wholesale Commodities nuclear fleet primarily due to more non-refueling outage days in 2018 compared to 2017.

Following are key performance measures for Entergy Wholesale Commodities for 2018 and 2017.
 
2018
 
2017
Owned capacity (MW)
3,962
 
3,962
GWh billed
29,875
 
30,501
 
 
 
 
Entergy Wholesale Commodities Nuclear Fleet
 
 
 
Capacity factor
84%
 
83%
GWh billed
27,617
 
28,178
Average energy price ($/MWh)
$37.34
 
$41.60
Average capacity price ($/kW-month)
$6.80
 
$6.16
Refueling outage days:
 
 
 
FitzPatrick
—
 
42
Indian Point 2
33
 
—
Indian Point 3
—
 
66
Pilgrim
—
 
43
Palisades
61
 
27


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Management’s Financial Discussion and Analysis


Other Income Statement Items

Utility

Other operation and maintenance expenses increased from $2,416 million for 2017 to $2,501 million for 2018 primarily due to:

•
an increase of $33 million in energy efficiency expenses due to the timing of recovery from customers;
•
an increase of $23 million in fossil-fueled generation expenses primarily due to an overall higher scope of work performed in 2018 as compared to the prior year and higher long-term service agreement costs;
•
an increase of $15 million in transmission expenses primarily due to higher labor and contract costs to support industrial customers;
•
an increase of $14 million in information technology costs primarily due to higher software maintenance costs and higher labor costs, including contract labor;
•
an increase of $14 million in loss provisions, including an increase in asbestos loss provisions;
•
an increase of $6 million in storm damage provisions, primarily at Entergy Mississippi. See Note 2 to the financial statements for discussion of storm cost recovery;
•
a $6 million write-off of capitalized skylining tree hazard costs as a result of the settlement of the Entergy Texas rate case proceeding. See Note 2 to the financial statements for discussion of the rate case proceeding; and
•
a $6 million loss in 2018 on the sale of fuel oil inventory per an agreement approved by the MPSC in June 2018 resulting from the stipulation related to the effects of the Tax Cuts and Jobs Act. There is no effect on net income as the loss on the sale of fuel oil inventory is offset by a reduction in income tax expense. See Note 2 to the financial statements for discussion of the agreement.

The increase was partially offset by higher nuclear insurance refunds of $15 million and a $15 million gain on disposal from the sale of Entergy Louisiana’s Willow Glen Power Station. See Note 14 to the financial statements for discussion of the sale of Willow Glen.

Taxes other than income taxes increased primarily due to increases in ad valorem taxes and payroll taxes. Ad valorem taxes increased primarily due to higher assessments and lower capitalized taxes.

Depreciation and amortization expenses increased primarily due to additions to plant in service, partially offset by updated depreciation rates used in calculating Grand Gulf plant depreciation and amortization expenses under the Unit Power Sales Agreement as part of a settlement approved by the FERC in August 2018. See Note 2 to the financial statements for further discussion of the Unit Power Sales Agreement.

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 2018, which included the St. Charles Power Station and Lake Charles Power Station projects. The increase was partially offset by changes in decommissioning trust fund activity, including portfolio rebalancing of certain of the decommissioning trust funds in 2018 and 2017.
    
Entergy Wholesale Commodities

Other operation and maintenance expenses decreased from $864 million for 2017 to $808 million for 2018 primarily due to the absence of other operation and maintenance expenses from the FitzPatrick plant. The decrease was partially offset by an increase of $26 million in severance and retention costs as a result of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet and a gain on the sale of assets resulting from the sale in March 2017 of the 838 MW FitzPatrick plant to Exelon. Entergy sold the FitzPatrick plant for approximately $110 million, which included a $10 million non-refundable signing fee paid in August 2016, in addition to the assumption by Exelon of certain liabilities related to the FitzPatrick plant, resulting in a pre-tax gain of $16 million on the sale. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale

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Commodities Exit from the Merchant Power Business” below for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet. See Note 14 to the financial statements for discussion of the sale of FitzPatrick.

The asset write-offs, impairments, and related charges variance is primarily due to impairment charges of $532 million ($421 million net-of-tax) in 2018 compared to impairment charges of $538 million ($350 million net-of-tax) in 2017. The impairment charges are primarily 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 reduce the size of the Entergy Wholesale Commodities’ merchant fleet. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” below for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet. See Note 9 to the financial statements for a discussion of asset retirement obligations. See Note 14 to the financial statements for a discussion of impairment of long-lived assets.

Depreciation and amortization expenses decreased primarily due to the decision in the third quarter 2017 to continue operating Palisades until May 31, 2022. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” below for a discussion of the planned shutdown of Palisades.

Other income decreased primarily due to losses on decommissioning trust fund investments, including unrealized losses on equity investments, which, prior to 2018, were recorded to other comprehensive income. See Note 16 to the financial statements for discussion of the implementation of ASU No. 2016-01 “Financial Instruments (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities effective January 1, 2018.

Other expenses decreased primarily due to a reduction in deferred refueling outage amortization costs related to the impairments of the Indian Point 2, Palisades, and Indian Point 3 plants and related assets and the absence of decommissioning expense from the FitzPatrick plant after it was sold to Exelon in March 2017. See Note 14 to the financial statements for discussion of the sale of FitzPatrick and impairments and related charges.

Parent and Other

Interest expense increased primarily due to an increase in commercial paper outstanding, combined with higher variable interest rates on commercial paper in 2018. See Note 4 to the financial statements for discussion of Entergy’s commercial paper program.

Income Taxes

See Note 3 to the financial statements for a reconciliation of the federal statutory rates of 21% for 2018 and 35% for 2017 and 2016 to the effective income tax rates, and for additional discussion regarding income taxes.

The effective income tax rate for 2018 was 595%. The difference in the effective income tax rate versus the statutory rate of 21% for 2018 was primarily due to amortization of excess accumulated deferred income taxes, the tax effects of a restructuring within the Utility, and a restructuring of the investment holdings in one of the Entergy Wholesale Commodities’ nuclear plant decommissioning trusts for which additional tax basis is now recoverable. 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 restructuring.

The effective income tax rate for 2017 was 56.1%. The difference in the effective income tax rate versus the statutory rate of 35% for 2017 was primarily due to the enactment of the Tax Cuts and Jobs Act, signed by President

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Trump in December 2017, which changed the federal corporate income tax rate from 35% to 21% effective in 2018, partially offset by a change in the tax classification of legal entities that own Entergy Wholesale Commodities nuclear power plants, which resulted in both permanent and temporary differences under the income tax accounting standards. See Note 3 to the financial statements for further discussion of the effects of the Tax Cuts and Jobs Act and the change in tax classification.

2017 Compared to 2016
 
Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2017 to 2016 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)
2016 Consolidated Net Income (Loss)

$1,151,133

 

($1,493,124
)
 

($222,512
)
 

($564,503
)
 
 
 
 
 
 
 
 
Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits)
138,617

 
(73,433
)
 
(16
)
 
65,168

Other operation and maintenance
103,302

 
(26,954
)
 
4,869

 
81,217

Asset write-offs, impairments, and related charges
—

 
(2,297,265
)
 
—

 
(2,297,265
)
Taxes other than income taxes
38,897

 
(14,657
)
 
814

 
25,054

Depreciation and amortization
49,491

 
(6,731
)
 
31

 
42,791

Other income
59,930

 
108,128

 
1,962

 
170,020

Interest expense
(10,245
)
 
856

 
5,362

 
(4,027
)
Other expenses
24,859

 
12,874

 
—

 
37,733

Income taxes
370,228

 
1,045,783

 
(56,182
)
 
1,359,829

2017 Consolidated Net Income (Loss)

$773,148

 

($172,335
)
 

($175,460
)
 

$425,353


(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 2017 include: 1) $538 million ($350 million net-of-tax) of impairment charges due to costs being charged 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 reduce the size of the Entergy Wholesale Commodities’ merchant fleet; 2) a reduction in net income of $181 million, including a $34 million net-of-tax reduction of regulatory liabilities, at Utility and $397 million at Entergy Wholesale Commodities and an increase in net income of $52 million at Parent and Other as a result of Entergy’s re-measurement of its deferred tax assets and liabilities not subject to the ratemaking process due to the enactment of the Tax Cuts and Jobs Act, in December 2017, which lowered the federal corporate income tax rate from 35% to 21%; and 3) a reduction in income tax expense, net of unrecognized tax benefits, of $373 million as a result of a change in the tax classification of legal entities that own Entergy Wholesale Commodities nuclear power plants. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” below for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet and see Note 14 to the financial statements for further discussion of the

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impairment and related charges. See Note 3 to the financial statements for further discussion of the effects of the Tax Cuts and Jobs Act and the change in the tax classification.

Results of operations for 2016 include: 1) $2,836 million ($1,829 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ Palisades, Indian Point 2, and Indian Point 3 plants and related assets to their fair values; 2) a reduction of income tax expense, net of unrecognized tax benefits, of $238 million as a result of a change in the tax classification of a legal entity that owned one of the Entergy Wholesale Commodities nuclear power plants, income tax benefits as a result of the settlement of the 2010-2011 IRS audit, including a $75 million tax benefit recognized by Entergy Louisiana related to the treatment of the Vidalia purchased power agreement, and a $54 million net benefit recognized by Entergy Louisiana related to the treatment of proceeds received in 2010 for the financing of Hurricane Gustav and Hurricane Ike storm costs pursuant to Louisiana Act 55; and 3) a reduction in expenses of $100 million ($64 million net-of-tax) due to the effects of recording in 2016 the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. See Note 14 to the financial statements for further discussion of the impairment and related charges, see Note 3 to the financial statements for additional discussion of the income tax items, and see Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

Net Revenue

Utility

Following is an analysis of the change in net revenue comparing 2017 to 2016.
  
Amount
  
(In Millions)
 
 
2016 net revenue

$6,179

Retail electric price
91

Regulatory credit resulting from reduction of the
  federal corporate income tax rate
56

Grand Gulf recovery
27

Louisiana Act 55 financing savings obligation
17

Volume/weather
(61
)
Other
9

2017 net revenue

$6,318


The retail electric price variance is primarily due to:

•
the implementation of formula rate plan rates effective with the first billing cycle of January 2017 at Entergy Arkansas and an increase in base rates effective February 24, 2016, each as approved by the APSC. A significant portion of the base rate increase was related to the purchase of Power Block 2 of the Union Power Station in March 2016;
•
a provision recorded in 2016 related to the settlement of the Waterford 3 replacement steam generator prudence review proceeding;
•
the implementation of the transmission cost recovery factor rider at Entergy Texas, effective September 2016, and an increase in the transmission cost recovery factor rider rate, effective March 2017, as approved by the PUCT; and
•
an increase in rates at Entergy Mississippi, as approved by the MPSC, effective with the first billing cycle of July 2016.


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See Note 2 to the financial statements for further discussion of the rate proceedings and the Waterford 3 replacement steam generator prudence review proceeding. See Note 14 to the financial statements for discussion of the Union Power Station purchase.

The regulatory credit resulting from reduction of the federal corporate income tax rate variance is due to the reduction of the Vidalia purchased power agreement regulatory liability by $30.5 million and the reduction of the Louisiana Act 55 financing savings obligation regulatory liabilities by $25 million as a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, which lowered the federal corporate income tax rate from 35% to 21%. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

The Grand Gulf recovery variance is primarily due to increased recovery of higher operating costs.

The Louisiana Act 55 financing savings obligation variance results from a regulatory charge in 2016 for tax savings to be shared with customers per an agreement approved by the LPSC. The tax savings resulted from the 2010-2011 IRS audit settlement on the treatment of the Louisiana Act 55 financing of storm costs for Hurricane Gustav and Hurricane Ike. See Note 3 to the financial statements for additional discussion of the settlement and benefit sharing.

The volume/weather variance is primarily due to the effect of less favorable weather on residential and commercial sales, partially offset by an increase in industrial usage. The increase in industrial usage is primarily due to new customers in the primary metals industry and expansion projects and an increase in demand for existing customers in the chlor-alkali industry.

Entergy Wholesale Commodities

Following is an analysis of the change in net revenue comparing 2017 to 2016.
  
Amount
  
(In Millions)
 
 
2016 net revenue

$1,542

FitzPatrick sale
(158
)
Nuclear volume
(89
)
FitzPatrick reimbursement agreement
57

Nuclear fuel expenses
108

Other
9

2017 net revenue

$1,469


As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by approximately $73 million in 2017 primarily due to the absence of net revenue from the FitzPatrick plant after it was sold to Exelon in March 2017 and lower volume in the Entergy Wholesale Commodities nuclear fleet resulting from more outage days in 2017 as compared to 2016. The decrease was partially offset by an increase resulting from the reimbursement agreement with Exelon pursuant to which Exelon reimbursed Entergy for specified out-of-pocket costs associated with preparing for the refueling and operation of FitzPatrick that otherwise would have been avoided had Entergy shut down FitzPatrick in January 2017 and a decrease in nuclear fuel expenses primarily related to the impairments of the Indian Point 2, Indian Point 3, and Palisades plants and related assets. Revenues received from Exelon in 2017 under the reimbursement agreement are offset by other operation and maintenance expenses and taxes other than income taxes and had no effect on net income. See Note 14 to the financial statements for discussion of the sale of FitzPatrick, the reimbursement agreement with Exelon, and the impairments and related charges.


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Management’s Financial Discussion and Analysis

Following are key performance measures for Entergy Wholesale Commodities for 2017 and 2016.
 
2017
 
2016
Owned capacity (MW) (a)
3,962
 
4,800
GWh billed
30,501
 
35,881
 
 
 
 
Entergy Wholesale Commodities Nuclear Fleet
 
 
 
Capacity factor
83%
 
87%
GWh billed
28,178
 
33,551
Average energy price ($/MWh)
$41.60
 
$41.33
Average capacity price ($/kW-month)
$6.16
 
$4.64
Refueling outage days:
 
 
 
FitzPatrick
42
 
—
Indian Point 2
—
 
102
Indian Point 3
66
 
—
Pilgrim
43
 
—
Palisades
27
 
—

(a)
The reduction in owned capacity is due to Entergy’s sale of the 838 MW FitzPatrick plant to Exelon in March 2017. See Note 14 to the financial statements for discussion of the sale of FitzPatrick.

Other Income Statement Items

Utility

Other operation and maintenance expenses increased from $2,313 million for 2016 to $2,416 million for 2017 primarily due to:

•
an increase of $46 million in nuclear generation expenses primarily due to higher nuclear labor costs, including contract labor, to position the nuclear fleet to meet its operational goals, including additional training and initiatives to support management’s operational goals at Grand Gulf, partially offset by a decrease in regulatory compliance costs. The decrease in regulatory compliance costs is primarily related to additional NRC inspection activities in 2016 as a result of the NRC’s March 2015 decision to move ANO into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. See Note 8 to the financial statements for a discussion of the ANO stator incident and subsequent NRC reviews;
•
an increase of $24 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2017 as compared to the prior year;
•
an increase of $20 million in transmission and distribution expenses due to higher vegetation maintenance costs;
•
the effects of recording in 2016 final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded included the reimbursement of approximately $19 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; and
•
the deferral in the first quarter 2016 of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance, as approved by the APSC in February 2016 as part of the Entergy Arkansas 2015 rate case settlement. These costs are being amortized over a ten-year period beginning March 2016. See Note 2 to the financial statements for further discussion of the rate case settlement.


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Management’s Financial Discussion and Analysis


The increase was partially offset by a decrease of $23 million in fossil-fueled generation expenses primarily due to lower long-term service agreement costs.

Taxes other than income taxes increased primarily due to increases in ad valorem taxes, local franchise taxes, state franchise taxes, and employment taxes. Ad valorem taxes increased primarily due to higher assessments, including the assessment of ad valorem taxes on the Union Power Station beginning in 2017. Local franchise taxes increased primarily due to higher revenues in 2017 as compared to the prior year. State franchise taxes increased primarily due to a change in the Louisiana franchise tax law which became effective for 2017.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Union Power Station purchased in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase.

Other income increased primarily due to higher realized gains in 2017 as compared to the prior year on the decommissioning trust fund investments, including portfolio rebalancing in 2017, and an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2017, including the St. Charles Power Station project.

Other expenses increased primarily due to increases in deferred refueling outage amortization costs primarily associated with the most recent ANO plant outages compared to previous outages.

Entergy Wholesale Commodities

Other operation and maintenance expenses decreased from $890 million for 2016 to $864 million for 2017 primarily due to the absence of other operation and maintenance expenses from the FitzPatrick plant and a gain on the sale of assets resulting from the sale in March 2017 of the 838 MW FitzPatrick plant to Exelon. Entergy sold the FitzPatrick plant for approximately $110 million, which included a $10 million non-refundable signing fee paid in August 2016, in addition to the assumption by Exelon of certain liabilities related to the FitzPatrick plant, resulting in a pre-tax gain of $16 million on the sale. See Note 14 to the financial statements for discussion of the sale of FitzPatrick. The decrease was partially offset by:

•
FitzPatrick’s nuclear refueling outage expenses and expenditures for capital assets being classified as other operation and maintenance expenses as a result of the sale and reimbursement agreements Entergy entered into with Exelon. These costs would have not been incurred absent the sale agreement with Exelon because Entergy planned to shut the plant down in January 2017. The expenses are offset by revenue realized pursuant to the reimbursement agreement and had no effect on net income. See Note 14 to the financial statements for discussion of the sale and reimbursement agreements;
•
the effect of recording in 2016 final court decisions in litigation against the DOE for the reimbursement of spent nuclear fuel storage costs, which reduced other operation and maintenance expenses in 2016 by $60 million. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
•
an increase of $37 million in severance and retention costs in 2017 as compared to the prior year due to management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” below for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet.

The asset write-offs, impairments, and related charges variance is primarily due to $538 million ($350 million net-of-tax) of impairment charges in 2017 compared to $2,836 million ($1,829 million net-of-tax) of impairment and related charges in 2016. The impairment charges in 2017 are due to nuclear fuel spending, nuclear refueling outage spending, and expenditures for capital assets being charged 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 reduce the size of the Entergy Wholesale

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Commodities’ merchant fleet. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” below for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet. The impairment and related charges in 2016 were primarily to write down the carrying values of the Entergy Wholesale Commodities’ Palisades, Indian Point 2, and Indian Point 3 plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of the impairments and related charges.

Taxes other than income taxes decreased primarily due to the absence of ad valorem taxes from the FitzPatrick plant after it was sold to Exelon in March 2017. See Note 14 to the financial statements for discussion of the sale of FitzPatrick.
    
Other income increased primarily due to higher realized gains in 2017 as compared to the prior year on the decommissioning trust fund investments, including the result of portfolio rebalancing in 2017, and the increase in value realized upon the receipt from NYPA of the decommissioning trust funds for the Indian Point 3 and FitzPatrick plants in January 2017. See Note 9 to the financial statements for discussion of the trust transfer agreement with NYPA.

Other expenses increased primarily due to increases in decommissioning expenses primarily as a result of a trust transfer agreement Entergy entered into with NYPA in August 2016, which closed in January 2017, to transfer the decommissioning trusts and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy and revisions to the estimated decommissioning cost liabilities for the Entergy Wholesale Commodities’ Indian Point 2 and Palisades plants as a result of revised decommissioning cost studies in the fourth quarter 2016. The increase was partially offset by a reduction in deferred refueling outage amortization costs related to the impairments of the Indian Point 2, Indian Point 3, and Palisades plants and related assets. See Note 9 to the financial statements for discussion of the trust transfer agreement with NYPA and the revised decommissioning cost studies. See Note 14 to the financial statements for discussion of the impairments and related charges.

Income Taxes

See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% for 2017 and 2016 to the effective income tax rates, and for additional discussion regarding income taxes.

The effective income tax rate for 2017 was 56.1%. The difference in the effective income tax rate versus the statutory rate of 35% for 2017 was primarily due to the enactment of the Tax Cuts and Jobs Act, signed by President Trump in December 2017, which changed the federal corporate income tax rate from 35% to 21% effective in 2018, partially offset by a change in the tax classification of legal entities that own Entergy Wholesale Commodities nuclear power plants, which resulted in both permanent and temporary differences under the income tax accounting standards. See Note 3 to the financial statements for further discussion of the effects of the Tax Cuts and Jobs Act and the change in tax classification.

The effective income tax rate for 2016 was 59.1%. The difference in the effective income tax rate versus the statutory rate of 35% for 2016 was primarily due to a change in the tax classification of a legal entity that owned one of the Entergy Wholesale Commodities nuclear power plants and the reversal of a portion of the provision for uncertain tax positions as a result of the settlement of the 2010-2011 IRS audit, partially offset by state income taxes and certain book and tax differences related to utility plant items. See Note 3 to the financial statements for additional discussion of the change in the tax classification and the tax settlement.

Income Tax Legislation

On December 22, 2017, President Trump signed into law the Tax Cuts and Jobs Act (the Act). As a result of the Act, Entergy and the Registrant Subsidiaries re-measured their deferred tax assets and liabilities in December 2017 to reflect the reduction in the federal corporate income tax rate from 35% to 21% that was effective January 1, 2018. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 and 2018 results of

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operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses the regulatory proceedings that have considered the effects of the Act.

Entergy’s operating cash flows have been and will be reduced in the near-term by the Act, most significantly over the time that the Registrant Subsidiaries will return unprotected excess deferred income taxes to customers. Rate base is expected to increase over time as a consequence of the Act as the excess deferred income taxes are returned to customers. Entergy is financing its incremental cash requirements as a consequence of the Act through a combination of Registrant Subsidiary debt and Entergy Corporation debt and equity. In June 2018, Entergy Corporation 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 several counterparties. In December 2018, Entergy physically settled a portion of its obligations under the forward sale agreements by delivering 6.8 million shares of its common stock in exchange for cash proceeds of approximately $500 million. Entergy is required to settle its remaining obligations under the forward sale agreements with respect to the remaining 8.5 million shares of common stock on or prior to June 7, 2019.

Entergy Wholesale Commodities Exit from the Merchant Power Business

Entergy Wholesale Commodities includes the ownership of the following nuclear reactors as of December 31, 2018:
 
 
Location
 
Market
 
Capacity
 
Status
Vermont Yankee
 
Vernon, VT
 
ISO-NE
 
605 MW
 
Plant sold on January 11, 2019
Pilgrim
 
Plymouth, MA
 
ISO-NE
 
688 MW
 
Planned shutdown in 2019
Indian Point 2
 
Buchanan, NY
 
NYISO
 
1,028 MW
 
Planned shutdown in 2020
Indian Point 3
 
Buchanan, NY
 
NYISO
 
1,041 MW
 
Planned shutdown in 2021
Palisades
 
Covert, MI
 
MISO
 
811 MW
 
Planned shutdown in 2022

As discussed below, Entergy sold its FitzPatrick nuclear power plant to Exelon in March 2017 and the Vermont Yankee plant to NorthStar in January 2019. The Pilgrim and Palisades 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, which includes taking actions to reduce the size of the merchant fleet. 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. Management continues to look for ways to mitigate the operational and decommissioning risks associated with the merchant power business. Changes to current assumptions regarding the 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. These facilities are in various stages of the decommissioning process, and Big Rock Point is also under contract to be sold with the Palisades plant. In addition, Entergy Wholesale Commodities

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provides operations and management services, including decommissioning services, to nuclear power plants owned by other utilities 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 Sale 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 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 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. 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 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 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 related asset impairment and other charges in the fourth quarter 2018. See Note 9 to the financial statements herein 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.

Sale of Top Deer Investment

In November 2016, Entergy sold its 50% membership interest in Top Deer Wind Ventures, LLC, a wind-powered electric generation joint venture owned by Entergy in the Entergy Wholesale Commodities segment and accounted for as an equity method investment. Entergy sold its 50% membership interest in Top Deer for approximately $0.5 million and realized a pre-tax loss of $0.2 million on the sale.

Sale of FitzPatrick

In October 2015, Entergy determined that it would close the FitzPatrick plant. The original expectation was to shut down the FitzPatrick plant at the end of its fuel cycle in January 2017.

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. When Entergy

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purchased Indian Point 3 and FitzPatrick in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities.  NYPA and Entergy subsidiaries executed decommissioning agreements, which specified their decommissioning obligations. NYPA had the right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assigned the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. Under the original agreements, if the decommissioning liabilities were retained by NYPA, the Entergy subsidiaries would perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trust funds.  At the time of the acquisition of the plants Entergy recorded a contract asset that represented an estimate of the present value of the difference between the stipulated contract amount for decommissioning the plants less the decommissioning costs estimated in independent decommissioning cost studies.  The asset was increased by monthly accretion based on the applicable discount rate necessary to ultimately provide for the estimated future value of the decommissioning contract. The monthly accretion was recorded as interest income. As a result of the agreement with NYPA, in the third quarter 2016, Entergy removed the contract asset from its balance sheet, and recorded receivables for the beneficial interests in the decommissioning trust funds and asset retirement obligations for the decommissioning liabilities. The decommissioning trust funds for the Indian Point 3 and FitzPatrick plants were transferred to Entergy by NYPA in January 2017.

In August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon. NRC approval of the sale was received in March 2017. The transaction closed in March 2017 for a purchase price of $110 million, which included a $10 million non-refundable signing fee paid in August 2016, in addition to the assumption by Exelon of certain liabilities related to the FitzPatrick plant, resulting in a pre-tax gain on the sale of $16 million. At the transaction close, Exelon paid an additional $8 million for the proration of certain expenses prepaid by Entergy. See Note 14 to the financial statements for further discussion of the sale of FitzPatrick. As discussed in Note 3 to the financial statements, as a result of the sale of FitzPatrick, Entergy re-determined the plant’s tax basis, resulting in a $44 million income tax benefit in the first quarter 2017.

Planned Shutdown of Pilgrim

In October 2015, Entergy determined that it would close the Pilgrim plant. The decision came after management’s extensive analysis of the economics and operating life of the plant following the NRC’s decision in September 2015 to place the plant in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix. In January 2019 the NRC found that the Pilgrim plant had completed the corrective actions required to address the concerns that led to the plant’s placement in Column 4 and had demonstrated sustained improvement. The Pilgrim plant is expected to cease operations on May 31, 2019, at the end of its current fuel cycle. See Note 14 to the financial statements for discussion of the impairment charges associated with the decision to cease operations earlier than expected and see Note 8 for further discussion on the placement of Pilgrim in Column 4.

Planned Shutdown 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 will 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 may be extended up to four additional years for each unit by 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.

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

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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.

See Note 14 to the financial statements for further discussion of the impairment charges associated with management’s decision to shut down the Indian Point plants.

Planned Shutdown of Palisades

Most of the Palisades output is sold under a power purchase agreement (PPA) 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 and escalate each year, up to $61.50/MWh in 2022. 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 will continue 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 nuclear power plant permanently on 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. See Note 9 to the financial statements for discussion of the associated asset retirement obligation revision. See Note 14 to the financial statements for discussion of the updated calculation of the PPA liability amortization and discussion of the impairment charges associated with the decision to cease operations at Palisades.

Planned Sales of Pilgrim and Palisades

On July 30, 2018, Entergy entered into purchase and sale agreements with Holtec International to sell to a Holtec subsidiary (i) 100% of the equity interests in Entergy Nuclear Generation Company, the owner of Pilgrim, and (ii) 100% of the equity interests in Entergy Nuclear Palisades, LLC, the owner of Palisades and the Big Rock Point Site. The sales of Entergy Nuclear Generation Company and Entergy Nuclear Palisades will include the transfer of each entity’s nuclear decommissioning trust and obligation for spent fuel management and plant decommissioning. At the closing of each sale transaction, the Holtec subsidiary will pay $1,000 each (subject to adjustment for net liabilities and other amounts) for the equity interests in Entergy Nuclear Generation Company and Entergy Nuclear Palisades.

The Pilgrim transaction is subject to certain closing conditions, including: the permanent shutdown of Pilgrim and the transfer of all nuclear fuel from the reactor vessel to the spent nuclear fuel pool; NRC approval for the transfer of the operating and the independent spent fuel storage installation licenses; FERC approval for the change in control of the switchyard; receipt of a favorable private letter ruling from the IRS; the market value of the nuclear decommissioning trust for Pilgrim, less the hypothetical income tax on the aggregate unrealized gain of such fund

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assets at closing, equaling or exceeding a specified minimum amount; and, the Palisades purchase and sale agreement having not been terminated due to a breach by Holtec or its subsidiary.

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; the market value of the nuclear decommissioning trust for Palisades, less the hypothetical income tax on the aggregate unrealized gain of such fund assets at closing, equaling or exceeding a specified minimum amount; and, the Pilgrim transaction having closed.

Subject to the above conditions, the Pilgrim transaction is expected to close by the end of 2019 and the Palisades transaction is expected to close by the end of 2022. The Pilgrim transaction is expected currently to result in an approximate $120 million loss and the Palisades transaction is expected currently to result in an approximate $80 million gain based on the difference between Entergy’s net investment in each subsidiary and the sale price plus any agreed adjustments. The primary variables in the ultimate loss or gain that Entergy will incur are the values of the nuclear decommissioning trusts and the asset retirement obligations at closing, financial results from plant operations until the closing, and the level of any deferred tax balances at closing.

Costs Associated with Entergy Wholesale Commodities Strategic Transactions

Entergy incurred approximately $139 million in costs in 2018, $113 million in costs in 2017, and $95 million in costs in 2016 associated with management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet, 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 $120 million in 2019, and a total of approximately $110 million from 2020 through 2022 associated with these strategic transactions. See Note 13 to the financial statements for further discussion of these costs.

In 2018, Entergy Wholesale Commodities incurred $532 million, and in 2017 it incurred $538 million, 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 the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining estimated operating lives associated with management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet. Entergy expects to continue to incur costs associated with nuclear fuel-related spending and expenditures for capital assets and, except for Palisades, expects to continue to charge these costs to expense as incurred because Entergy expects the value of the plants to continue to be impaired. In 2016, Entergy Wholesale Commodities incurred impairment charges of $2.8 billion primarily to write down the carrying values of the Entergy Wholesale Commodities’ Palisades, Indian Point 2, and Indian Point 3 plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of these 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.


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Capital Structure

Entergy’s debt to capital ratio is balanced between equity and debt, as shown in the following table.
 
December 31,
2018
 
December 31,
2017
Debt to capital
66.7%
 
67.1%
Effect of excluding securitization bonds
(0.5%)
 
(0.8%)
Debt to capital, excluding securitization bonds (a)
66.2%

66.3%
Effect of subtracting cash
(0.6%)
 
(1.1%)
Net debt to net capital, excluding securitization bonds (a)
65.6%

65.2%

(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.

Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable and commercial paper, capital 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.

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, 2018. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2018. 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
 
2019
 
2020
 
2021
 
2022-2023
 
after 2023
 
 
(In Millions)
Utility
 

$1,336

 

$1,012

 

$1,908

 

$2,554

 

$16,282

Entergy Wholesale Commodities
 
4

 
142

 
—

 
—

 
—

Parent and Other
 
79

 
522

 
56

 
933

 
810

Total
 

$1,419

 

$1,676

 

$1,964

 

$3,487

 

$17,092


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 2023. 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, 2018 was 3.60% on the drawn portion of the facility.


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As of December 31, 2018, amounts outstanding and capacity available under the $3.5 billion credit facility are:
Capacity
 
Borrowings
 
Letters of Credit
 
Capacity Available
(In Millions)
$3,500
 
$220
 
$6
 
$3,274

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.

Entergy Corporation has a commercial paper program with a Board-approved program limit of up to $2 billion. As of December 31, 2018, Entergy Corporation had $1.942 billion of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2018 was 2.50%.

Capital lease obligations are a minimal part of Entergy’s overall capital structure. Following are Entergy’s payment obligations under those leases.
 
2019
 
2020
 
2021
 
2022-2023
 
after 2023
 
(In Millions)
Capital lease payments
$3
 
$3
 
$3
 
$6
 
$16

The capital 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, 2018 as follows:
Company
 
Expiration Date
 
Amount of Facility
 
Interest Rate (a)
 
Amount Drawn
 as of
December 31, 2018
 
Letters of Credit
Outstanding as of
December 31, 2018
Entergy Arkansas
 
April 2019
 
$20 million (b)
 
3.77%
 
—
 
—
Entergy Arkansas
 
September 2023
 
$150 million (c)
 
3.77%
 
—
 
—
Entergy Louisiana
 
September 2023
 
$350 million (c)
 
3.77%
 
—
 
—
Entergy Mississippi
 
May 2019
 
$10 million (d)
 
4.02%
 
—
 
—
Entergy Mississippi
 
May 2019
 
$35 million (d)
 
4.02%
 
—
 
—
Entergy Mississippi
 
May 2019
 
$37.5 million (d)
 
4.02%
 
—
 
—
Entergy New Orleans
 
November 2021
 
$25 million (c)
 
3.80%
 
—
 
$0.8 million
Entergy Texas
 
September 2023
 
$150 million (c)
 
4.02%
 
—
 
$1.3 million

(a)
The interest rate is the estimated interest rate as of December 31, 2018 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.

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(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.

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, 2018:
Company
 
 
Amount of Uncommitted Facility
 
Letter of Credit Fee
 
Letters of Credit Issued as of December 31, 2018 (a)
Entergy Arkansas
 
 
$25 million
 
0.70%
 
$1 million
Entergy Louisiana
 
 
$125 million
 
0.70%
 
$25.9 million
Entergy Mississippi
 
 
$40 million
 
0.70%
 
$16.7 million
Entergy New Orleans
 
 
$15 million
 
1.00%
 
$2 million
Entergy Texas
 
 
$50 million
 
0.70%
 
$20.9 million
(a)
As of December 31, 2018, letters of credit posted with MISO covered financial transmission right exposure of $0.2 million for Entergy Mississippi and $4.1 million for Entergy Texas. See Note 15 to the financial statements for discussion of financial transmission rights.

As of December 31, 2018, Entergy Nuclear Vermont Yankee had a credit facility guaranteed by Entergy Corporation with a borrowing capacity of $145 million that expires in November 2020. As of December 31, 2018, $139 million in cash borrowings were outstanding under the credit facility. The weighted average interest rate for the year ended December 31, 2018 was 3.50% on the drawn portion of the facility.  In anticipation of the transfer of Entergy Nuclear Vermont Yankee to NorthStar, the credit facility was assumed by Vermont Yankee Asset Retirement Management, LLC, Entergy Nuclear Vermont Yankee’s parent company that remains an Entergy subsidiary after the transfer, in January 2019 and the borrowing capacity was reduced to $139 million. See Note 4 to the financial statements for additional discussion of the Vermont Yankee credit facility. See Note 14 to the financial statements for discussion of the transfer of Entergy Nuclear Vermont Yankee to NorthStar.

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, 2018 on non-cancelable operating leases with a term over one year:
 
2019
 
2020
 
2021
 
2022-2023
 
after 2023
 
(In Millions)
Operating lease payments
$94
 
$82
 
$75
 
$108
 
$88

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


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Summary of Contractual Obligations of Consolidated Entities

Contractual Obligations
 
2019
 
2020-2021
 
2022-2023
 
after 2023
 
Total
 
 
(In Millions)
Long-term debt (a)
 

$1,419

 

$3,640

 

$3,487

 

$17,092

 

$25,638

Capital lease payments (b)
 

$3

 

$6

 

$6

 

$16

 

$31

Operating leases (b) (c)
 

$94

 

$157

 

$108

 

$88

 

$447

Purchase obligations (d)
 

$1,331

 

$2,301

 

$2,743

 

$3,340

 

$9,715


(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.

In addition to the contractual obligations stated above, Entergy currently expects to contribute approximately $176.9 million to its pension plans and approximately $47.6 million to other postretirement plans in 2019, although the 2019 required pension contributions will be known with more certainty when the January 1, 2019 valuations are completed, which is expected by April 1, 2019. 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 has $1,213 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 Funds Agreement

Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:
 
•
maintain System Energy’s equity capital at a minimum of 35% of its total capitalization (excluding short-term debt);
•
permit the continued commercial operation of Grand Gulf;
•
pay in full all System Energy indebtedness for borrowed money when due; and
•
enable System Energy to make payments on specific System Energy debt, under supplements to the agreement assigning System Energy’s rights in the agreement as security for the specific debt.

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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 2019 through 2021.
Planned construction and capital investments
 
2019
 
2020
 
2021
 
 
(In Millions)
Utility:
 
 
 
 
 
 
Generation
 

$1,915

 

$1,090

 

$1,515

Transmission
 
1,060

 
845

 
570

Distribution
 
1,040

 
1,095

 
1,325

Utility Support
 
515

 
405

 
325

Total
 
4,530

 
3,435

 
3,735

Entergy Wholesale Commodities
 
110

 
40

 
20

Total
 

$4,640

 

$3,475

 

$3,755


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, and includes spending for the nuclear and non-nuclear plants at Entergy Wholesale Commodities. 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, including the St. Charles Power Station, Lake Charles Power Station, Washington Parish Energy Center, Choctaw Generating Station, Sunflower Solar Facility, New Orleans Power Station, and Montgomery County Power Station, each discussed below, and potential construction of additional generation.
•
Entergy Wholesale Commodities investments such as component replacements, software and security, and dry cask storage.
•
Investments in Entergy’s 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.

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 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.

St. Charles Power Station

In August 2015, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by the construction of the St. Charles Power Station, a nominal 980 megawatt combined-cycle generating unit, on land adjacent to the existing Little Gypsy plant in St. Charles Parish, Louisiana. It is currently estimated to cost $869 million to construct, including transmission interconnection and other related costs. The LPSC issued an order approving certification of St. Charles Power Station in December 2016. Construction is in progress and commercial operation is expected to occur by mid-2019.

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Lake Charles Power Station

In November 2016, Entergy Louisiana filed an application with the LPSC seeking certification that the public convenience and necessity would be served by the construction of the Lake Charles Power Station, a nominal 994 megawatt combined-cycle generating unit in Westlake, Louisiana, on land adjacent to the existing Nelson plant in Calcasieu Parish. The current estimated cost of the Lake Charles Power Station is $872 million, including estimated costs of transmission interconnection and other related costs. In May 2017 the parties to the proceeding agreed to an uncontested stipulation finding that construction of the Lake Charles Power Station is in the public interest and authorizing an in-service rate recovery plan. In July 2017 the LPSC issued an order unanimously approving the stipulation and approved certification of the unit. Construction is in progress and commercial operation is expected to occur by mid-2020.

Washington Parish Energy Center

In April 2017, Entergy Louisiana signed an agreement with a subsidiary of Calpine Corporation for the construction and purchase of a peaking plant. Calpine will construct the plant, which will consist of two natural gas-fired combustion turbine units with a total nominal capacity of approximately 361 MW. The plant, named the Washington Parish Energy Center, will be located in Bogalusa, Louisiana and, subject to permits and approvals, is expected to be completed by 2021. Subject to regulatory approvals, Entergy Louisiana will purchase the plant once it is complete for an estimated total investment of approximately $261 million, including transmission and other related costs. In May 2017, Entergy Louisiana filed an application with the LPSC seeking certification of the plant. In April 2018 the parties reached a settlement recommending certification and cost recovery through the additional capacity mechanism of the formula rate plan, consistent with prior LPSC precedent with respect to the certification and recovery of plants previously acquired by Entergy Louisiana. The LPSC issued an order approving the settlement in May 2018.

Choctaw Generating Station

In August 2018, Entergy Mississippi announced that it signed an asset purchase agreement to acquire from a subsidiary of GenOn Energy Inc. the Choctaw Generating Station, an 810 MW natural gas fired combined-cycle turbine plant located near French Camp, Mississippi.  The purchase price is expected to be approximately $314 million.  Entergy Mississippi also expects to invest in various plant upgrades at the facility after closing and expects the total cost of the acquisition to be approximately $401 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.  These include regulatory approvals from the MPSC and the FERC. Clearance under the Hart-Scott-Rodino Antitrust Improvements Act has occurred.  In October 2018, Entergy Mississippi filed an application with the MPSC seeking approval of the acquisition and cost recovery. In a separate filing in October 2018, 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 non-fuel annual ownership costs of the Choctaw Generating Station, as well as to allow similar cost recovery treatment for other future capacity additions approved by the MPSC. Closing is expected to occur by the end of 2019.

Sunflower Solar Facility

In November 2018, Entergy Mississippi announced that it signed an agreement for the purchase of an approximately 100 MW to-be-constructed 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 will be built by Sunflower County Solar Project, LLC, a sub-subsidiary of Recurrent Energy,

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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 at 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 has 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.  Closing is expected to occur by the end of 2021.

New Orleans Power Station

In June 2016, Entergy New Orleans filed an application with the City Council seeking a public interest determination and authorization to construct the New Orleans Power Station, a 226 MW advanced combustion turbine in New Orleans, Louisiana, at the site of the existing Michoud generating facility, which was retired effective May 31, 2016. In January 2017 several intervenors filed testimony opposing the construction of the New Orleans Power Station on various grounds. In July 2017, Entergy New Orleans submitted a supplemental and amending application to the City Council seeking approval to construct either the originally proposed 226 MW advanced combustion turbine, or alternatively, a 128 MW unit composed of natural gas-fired reciprocating engines and a related cost recovery plan. The cost estimate for the alternative 128 MW unit is $210 million. In addition, the application renewed the commitment to pursue up to 100 MW of renewable resources to serve New Orleans. In March 2018 the City Council adopted a resolution approving construction of the 128 MW unit. The targeted commercial operation date is mid-2020, subject to receipt of all necessary permits. In April 2018 intervenors opposing the construction of the New Orleans Power Station filed with the City Council a request for rehearing, which was subsequently denied, and a petition for judicial review of the City Council’s decision, and also filed a lawsuit challenging the City Council’s approval based on Louisiana’s open meeting law. In May 2018 the City Council announced that it would initiate an investigation into allegations that Entergy New Orleans, Entergy, or some other entity paid or participated in paying certain attendees and speakers in support of the New Orleans Power Station to attend or speak at certain meetings organized by the City Council. In June 2018, Entergy New Orleans produced documents in response to a City Council resolution relating to this investigation. The City Council issued a request for qualifications for an investigator and in June 2018 selected two investigators. In October 2018 the investigators for the City Council released their report, concluding that individuals were paid to attend and/or speak in support of the New Orleans Power Station and that Entergy New Orleans “knew or should have known that such conduct occurred or reasonably might occur.”  The City Council held a special meeting on October 31, 2018 to allow the investigators to present the report and for the City Council to consider next steps.  At that meeting, the City Council issued a resolution requiring Entergy New Orleans to show cause why it should not be fined $5 million as a result of the findings in the report. In November 2018, Entergy New Orleans submitted its response to the show cause resolution, disagreeing with certain characterizations and omissions of fact in the report and asserting that the City Council could not legally impose the proposed fine.  Simultaneous with the filing of its response to the show cause resolution, Entergy New Orleans sent a letter to the City Council re-asserting that the City Council’s imposition of the proposed fine would be unlawful, but acknowledging that the actions of a subcontractor, which was retained by an Entergy New Orleans contractor without the knowledge or contractually-required consent of Entergy New Orleans, were contrary to Entergy’s values.  In that letter, Entergy New Orleans offered to donate $5 million to the City Council to resolve the show cause proceeding.  In January 2019, Entergy New Orleans submitted a new settlement proposal to the City Council. The proposal retains the components of the first offer but adds to it a commitment to make reasonable efforts to limit the costs of the project to the $210 million cost estimate with advanced notification of anticipated cost overruns, additional reporting requirements for cost and environmental items, and a commitment regarding reliability investment and to work with the New Orleans Sewerage and Water Board to provide a reliable source of power. In February 2019 the City Council approved a resolution approving the settlement proposal and allowing the construction of the New Orleans Power Station to commence.

Montgomery County Power Station

In October 2016, Entergy Texas filed an application with the PUCT seeking certification that the public convenience and necessity would be served by the construction of the Montgomery County Power Station, a nominal

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993 MW combined-cycle generating unit in Montgomery County, Texas on land adjacent to the existing Lewis Creek plant. The current estimated cost of the Montgomery County Power Station is $937 million, including approximately $111 million of transmission interconnection and network upgrades and other related costs. The independent monitor, who oversaw the request for proposal process, filed testimony and a report affirming that the Montgomery County Power Station was selected through an objective and fair request for proposal process that showed no undue preference to any proposal. In June 2017 parties to the proceeding filed an unopposed stipulation and settlement agreement. The stipulation contemplates that Entergy Texas’s level of cost-recovery for generation construction costs for Montgomery County Power Station is capped at $831 million, subject to certain exclusions such as force majeure events. Transmission interconnection and network upgrades and other related costs are not subject to the $831 million cap. In July 2017 the PUCT approved the stipulation. Subject to the timely receipt of other permits and approvals, commercial operation is estimated to occur by mid-2021.

Advanced Metering Infrastructure (AMI)

See Note 2 to the financial statements for discussion of filings made by the Utility operating companies regarding the deployment of AMI. The filings included estimates of implementation costs for AMI of $208 million for Entergy Arkansas, $330 million for Entergy Louisiana, $132 million for Entergy Mississippi, $75 million for Entergy New Orleans, and $132 million for Entergy Texas.

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 2019 meeting, the Board declared a dividend of $0.91 per share. Entergy paid $648 million in 2018, $629 million in 2017, and $612 million in 2016 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, 2018, $350 million of authority remains under the $500 million share repurchase program. The amount of repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities, or if limitations in the credit markets continue for a prolonged period.

Sources of Capital

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

•
internally generated funds;
•
cash on hand ($481 million as of December 31, 2018);
•
securities issuances;
•
bank financing under new or existing facilities or commercial paper; and
•
sales of assets.


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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.

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 borrowing limits for Entergy New Orleans are effective through October 2019. The current FERC-authorized short-term borrowing limits and long-term financing authorization for Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy are effective through November 2020. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2020. Entergy New Orleans also has obtained long-term financing authorization from the City Council that extends through October 2019. Entergy Arkansas, Entergy Louisiana, and System Energy each have obtained long-term financing authorization from the FERC that extends through November 2020 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.

Cash Flow Activity

As shown in Entergy’s Consolidated Statements of Cash Flows, cash flows for the years ended December 31, 2018, 2017, and 2016 were as follows:
 
2018
 
2017
 
2016
 
(In Millions)
Cash and cash equivalents at beginning of period

$781

 

$1,188

 

$1,351

 


 
 
 
 
Net cash provided by (used in):
 

 
 

 
 

Operating activities
2,385

 
2,624

 
2,999

Investing activities
(4,106
)
 
(3,841
)
 
(3,850
)
Financing activities
1,421

 
810

 
688

Net decrease in cash and cash equivalents
(300
)
 
(407
)
 
(163
)
 
 
 
 
 
 
Cash and cash equivalents at end of period

$481

 

$781

 

$1,188



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Operating Activities

2018 Compared to 2017

Net cash flow provided by operating activities decreased by $239 million in 2018 primarily due to:

•
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;
•
lower Entergy Wholesale Commodities net revenue in 2018 as compared to the same period in 2017 (except for revenues resulting from the FitzPatrick reimbursement agreement with Exelon). See Note 14 to the financial statements for discussion of the reimbursement agreement;
•
a decrease due to the timing of recovery of fuel and purchased power costs in 2018 as compared to the prior year. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;
•
an increase of $56 million in interest paid in 2018 as compared to the prior year resulting from an increase in interest expense;
•
income tax payments of $20 million in 2018 compared to income tax refunds of $13 million in 2017. Entergy made income tax payments in 2018 for estimated federal income taxes. Entergy received income tax refunds in 2017 resulting from the carryback of net operating losses; and
•
proceeds of $2 million received in 2018 compared to proceeds of $23 million received in 2017 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 decrease was partially offset by:

•
the effect of favorable weather on billed Utility sales in 2018;
•
the timing of collection of receivables from Utility customers;
•
a refund to customers in January 2017 of approximately $71 million as a result of the settlement approved by the LPSC related to the Waterford 3 replacement steam generator project. See Note 2 to the financial statements for discussion of the settlement and refund;
•
a decrease of $58 million in spending on nuclear refueling outages in 2018 as compared to the prior year; and
•
a decrease of $57 million in severance and retention payments in 2018 as compared to the prior year. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” above for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet.

2017 Compared to 2016

Net cash flow provided by operating activities decreased by $375 million in 2017 primarily due to:

•
lower Entergy Wholesale Commodities net revenue (except for revenues resulting from the FitzPatrick reimbursement agreement with Exelon) in 2017 as compared to prior year, as discussed above. See Note 14 to the financial statements for discussion of the reimbursement agreement;
•
an increase of $141 million in spending on nuclear refueling outages in 2017 as compared to the prior year;
•
an increase of $94 million in severance and retention payments in 2017 as compared to the prior year. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” above for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet;
•
a refund to customers in January 2017 of approximately $71 million as a result of the settlement approved by the LPSC related to the Waterford 3 replacement steam generator project. See Note 2 to the financial statements for discussion of the settlement and refund;

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•
proceeds of $23 million received in 2017 compared to proceeds of $102 million received in 2016 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; and
•
an increase of $20 million in pension contributions in 2017. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates” below and Note 11 to the financial statements for discussion of qualified pension and other postretirement benefits funding.

The decrease was partially offset by:

•
income tax refunds of $13 million in 2017 compared to income tax payments of $95 million in 2016. Entergy received income tax refunds in 2017 resulting from the carryback of net operating losses. Entergy made income tax payments in 2016 related to the effect of the 2006-2007 IRS audit and for jurisdictions that do not have net operating loss carryovers or jurisdictions in which the utilization of net operating loss carryovers are limited;
•
a decrease of $68 million in interest paid in 2017 as compared to the prior year primarily due to an interest payment of $60 million made in March 2016 related to the purchase of a beneficial interest in the Waterford 3 leased assets. See Note 10 to the financial statements for a discussion of Entergy Louisiana’s purchase of a beneficial interest in the Waterford 3 leased assets; and
•
an increase due to the timing of recovery of fuel and purchased power costs in 2017 as compared to the prior year. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery.

Investing Activities

2018 Compared to 2017

Net cash flow used in investing activities increased by $265 million in 2018 primarily due to:

•
an increase of $334 million in construction expenditures, primarily in the Utility business. The increase in construction expenditures in the Utility business is primarily due to an increase of $205 million in fossil-fueled generation construction expenditures primarily due to higher spending in 2018 on self-build projects in the Utility business and an increase of $88 million in nuclear construction expenditures primarily due to a higher scope of work performed during the Grand Gulf outage in 2018;
•
proceeds of $100 million from the sale in March 2017 of the FitzPatrick plant to Exelon. See Note 14 to the financial statements for a discussion of the sale of FitzPatrick; and
•
collateral posted to provide credit support to secure its obligations under agreements to sell power produced by Entergy Wholesale Commodities’ power plants.

The increase was partially offset by:

•
changes in the decommissioning trust funds, including portfolio rebalancing of certain decommissioning trust funds in 2018;
•
a decrease of $75 million in nuclear fuel purchases due to 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 $34 million in proceeds received from the DOE in 2018 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.



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2017 Compared to 2016

Net cash flow used in investing activities decreased by $9 million in 2017 primarily due to the purchase of the Union Power Station for approximately $949 million in March 2016 and proceeds of $100 million from the sale in March 2017 of the FitzPatrick plant to Exelon. See Note 14 to the financial statements for discussion of the Union Power Station purchase and the sale of FitzPatrick. The decrease was partially offset by:

•
an increase of $827 million in construction expenditures, primarily in the Utility business. The increase in construction expenditures in the Utility business is primarily due to an increase of $452 million in fossil-fueled generation construction expenditures primarily due to higher spending in 2017 on the St. Charles Power Station project and the Lake Charles Power Station project and a higher scope of work performed on various other fossil projects in 2017 as compared to 2016; an increase of $133 million in distribution construction expenditures primarily due to a higher scope of non-storm related work performed in 2017 as compared to 2016 and higher storm restoration spending in 2017; an increase of $102 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2017 as compared to 2016; an increase of $101 million in transmission construction expenditures primarily due to a higher scope of work performed on transmission projects in 2017 as compared to 2016; and an increase of $51 million due to increased spending on advanced metering infrastructure in 2017;
•
a decrease of $144 million in proceeds received from the DOE in 2017 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; and
•
a decrease of $63 million in nuclear fuel purchases due to 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.

Financing Activities

2018 Compared to 2017

Net cash flow provided by financing activities increased by $611 million in 2018 primarily due to:

•
long-term debt activity providing approximately $1,070 million of cash in 2018 compared to $224 million in 2017. Borrowings and repayments of borrowings on Entergy’s long-term credit facility are included in long-term debt activity; and
•
proceeds from the issuance of common stock of $499 million as a result of the settlement of equity forwards in 2018. See Note 7 to the financial statements for discussion of the equity forward sale agreements.

The increase was partially offset by a decrease of $647 million in net issuances of commercial paper in 2018 compared to 2017 and a net decrease of $152 million in 2018 in short-term borrowings by the nuclear fuel company variable interest entities.

2017 Compared to 2016

Net cash flow provided by financing activities increased by $122 million in 2017 primarily due to:

•
Entergy’s net issuances of $1,123 million of commercial paper in 2017 compared to net repayments of $78 million of commercial paper in 2016;
•
an increase of $95 million resulting from lower redemptions of preferred stock. In 2017, Entergy New Orleans redeemed its $7.8 million of 4.75% Series preferred stock, its $6 million of 5.56% Series preferred stock, and its $6 million of 4.36% Series preferred stock. In 2016, Entergy Arkansas redeemed its $75 million of 6.45% Series preferred stock and its $10 million of 6.08% Series preferred stock and Entergy Mississippi redeemed its $30 million of 6.25% Series preferred stock;

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•
an increase of $48 million in treasury stock issuances in 2017 primarily due to a larger amount of previously repurchased Entergy Corporation common stock issued in 2017 to satisfy stock option exercises; and
•
net borrowings of $41 million by the nuclear fuel company variable interest entities in 2017 compared to net repayments of $1 million in 2016.

The increase was partially offset by long-term debt activity providing approximately $224 million of cash in 2017 compared to providing approximately $1,489 million of cash in 2016. Borrowings and repayments of borrowings on Entergy’s long-term credit facility are included in long-term debt activity.

For the details of Entergy’s commercial paper program and the nuclear fuel company variable interest entities’ short-term borrowings, see Note 4 to the financial statements. See Note 5 to the financial statements for details of long-term debt.

Rate, Cost-recovery, and Other Regulation

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that the Utility operating companies and System Energy 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, the PUCT, and the FERC, 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
 
9.95% Electric (a); 9.45% - 10.45% Gas
Entergy Mississippi
 
9.28% - 11.36%
Entergy New Orleans
 
10.7% - 11.5% Electric; 10.25% - 11.25% Gas
Entergy Texas
 
9.65%

(a)
Based on 2017 test year. Authorized return on common equity for 2018 and 2019 test years will be 9.2% - 10.4%.

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 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

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System Agreement proceedings, the complaints filed with the FERC challenging System Energy’s return on equity, and the amendments to the Unit Power Sales Agreement approved by the FERC in 2018.

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, 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, 2018.


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Entergy Wholesale Commodities Nuclear Portfolio

 
 
2019
 
2020
 
2021
 
2022
Energy
 
 
 
 
 
 
 
 
Percent of planned generation under contract (a):
 
 
 
 
 
 
 
 
Unit-contingent (b)
 
98%
 
94%
 
91%
 
66%
Planned generation (TWh) (c) (d)
 
25.6
 
17.7
 
9.6
 
2.8
Average revenue per MWh on contracted volumes:
 
 
 
 
 
 
 
 
Expected based on market prices as of December 31, 2018
 
$39.7
 
$42.1
 
$56.8
 
$58.8
 
 
 
 
 
 
 
 
 
Capacity
 
 
 
 
 
 
 
 
Percent of capacity sold forward (e):
 
 
 
 
 
 
 
 
Bundled capacity and energy contracts (f)
 
26%
 
37%
 
68%
 
97%
Capacity contracts (g)
 
32%
 
5%
 
—%
 
—%
Total
 
58%
 
42%
 
68%
 
97%
Planned net MW in operation (average) (d)
 
3,167
 
2,195
 
1,158
 
338
Average revenue under contract per kW per month (applies to capacity contracts only)
 
$5.9
 
$2.3
 
$—
 
$—
 
 
 
 
 
 
 
 
 
Total Energy and Capacity Revenues (h)
 
 
 
 
 
 
 
 
Expected sold and market total revenue per MWh
 
$44.4
 
$45.1
 
$54.9
 
$47.3
Sensitivity: -/+ $10 per MWh market price change
 
$44.2 - $44.6
 
$44.9 - $45.3
 
$54.0 - $55.8
 
$43.9 - $50.8

(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, outage schedules, and expected market conditions that affect dispatch.
(d)
Assumes the planned shutdown of Pilgrim on May 31, 2019, planned shutdown of Indian Point 2 on April 30, 2020, 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 Pilgrim, Indian Point 2, 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.
(h)
Includes assumptions on converting a portion of the portfolio to contracted with fixed price cost or discount and excludes non-cash revenue from the amortization of the Palisades below-market purchased power agreement, mark-to-market activity, and service revenues.

Entergy estimates that a positive $10 per MWh change in the annual average energy price in the markets in which the Entergy Wholesale Commodities nuclear business sells power, based on the respective year-end market

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conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax income of $6 million in 2019 and would have had a corresponding effect on pre-tax income of $3 million in 2018. A negative $10 per MWh change in the annual average energy price in the markets based on the respective year-end market conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax income of ($6) million in 2019 and would have had a corresponding effect on pre-tax income of ($3) million in 2018.

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, 2018, based on power prices at that time, Entergy had liquidity exposure of $126 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $52 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, 2018, Entergy would have been required to provide approximately $69 million of additional cash or letters of credit under some of the agreements. As of December 31, 2018, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $310 million for a $1 per MMBtu increase in gas prices in both the short- and long-term markets.

As of December 31, 2018, substantially all of 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, to position Entergy’s nuclear fleet to meet its operational goals, including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems and the Fukushima event; the implementation of plans to cease merchant generation at all Entergy Wholesale Commodities nuclear plants 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 renewal and amendments, and decommissioning; the performance and capacity factors of these nuclear plants; 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.

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ANO

See Note 8 to the financial statements for discussion of the NRC’s decision in March 2015 to move ANO into the “multiple/repetitive degraded cornerstone column,” or Column 4, of the NRC’s Reactor Oversight Process Action Matrix, and the resulting significant additional NRC inspection activities at the ANO site. 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. This action followed NRC inspections to review ANO 1’s and ANO 2’s performance in addressing issues that had previously resulted in classification in Column 4.

Pilgrim

See Note 8 to the financial statements for discussion of the NRC’s decision in September 2015 to place Pilgrim in Column 4 of its Reactor Oversight Process Action Matrix due to its finding of continuing weaknesses in Pilgrim’s corrective action program that contributed to repeated unscheduled shutdowns and equipment failures.

Grand Gulf

Based on the plant’s performance indicators, in November 2016 the NRC placed Grand Gulf in the “regulatory response column,” or Column 2, of its Reactor Oversight Process Action Matrix. In August 2018 the NRC moved Grand Gulf into the “licensee response column,” or Column 1, of the NRC’s Reactor Oversight Process Action Matrix. This action followed NRC inspections to review Grand Gulf’s performance in addressing issues that had previously resulted in classification in Column 2. Based on performance indicator data for the third quarter 2018, Grand Gulf moved back to Column 2 due to a reduction in power to address an operational issue with a plant system that resulted in the threshold for one of the NRC’s performance indicators being exceeded.

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

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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 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, however, and affect current cost estimates. In addition, if regulations regarding nuclear decommissioning were to change, this could significantly 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

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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 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 and Trust Fund Investments

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 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.

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See Note 14 to the financial statements for a discussion of impairment conclusions related to the Entergy Wholesale Commodities nuclear plants.

Entergy evaluates 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 has occurred. The assessment of whether an investment in a 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. 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). 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. Effective January 1, 2018 with the adoption of ASU 2016-01, unrealized losses and gains on investments in equity securities held by the Entergy Wholesale Commodities’ nuclear decommissioning trust funds are recorded in earnings as they occur. See Note 16 to the financial statements for details on the decommissioning trust funds.

Taxation and Uncertain Tax Positions

Management exercises significant judgment in evaluating the potential tax effects of Entergy’s operations, transactions, and other events. Entergy accounts for uncertain income tax positions using a recognition model under a two-step approach with a more likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement. Management evaluates each tax position based on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether available information supports the assertion that the recognition threshold has been met. Additionally, measurement of unrecognized tax benefits to be recorded in the consolidated financial statements is based on the probability of different potential outcomes. Income tax expense and tax positions recorded could be significantly affected by events such as additional transactions contemplated or consummated by Entergy as well as audits by taxing authorities of the tax positions taken in transactions. Management believes that the financial statement tax balances are accounted for and adjusted appropriately each quarter as necessary in accordance with applicable authoritative guidance; however, the ultimate outcome of tax matters could result in favorable or unfavorable effects on the consolidated financial statements. Entergy’s income taxes, including unrecognized tax benefits, open audits, and other significant tax matters are discussed in Note 3 to the financial statements.

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Income Tax Legislation” above and 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.

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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 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 105% funded. The target pension asset allocation for 2018 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 2018 weighted average target postretirement asset allocation is 45% equity and 55% 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.


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Costs and Sensitivities

The estimated 2019 and actual 2018 qualified pension and other postretirement costs and related underlying assumptions and sensitivities are shown below:
Costs
 
Estimated 2019
 
2018
 
 
(In Millions)
Qualified pension cost
 
$248.4
 
$255.6
Other postretirement (income)/cost
 
  ($5.6)
 
$13.1
 
 
 
 
 
Assumptions
 
2019
 
2018
Discount rates
 
 
 
 
Qualified pension
 
 
 
 
Service cost
 
4.57%
 
3.89%
Interest cost
 
4.15%
 
3.44%
Other postretirement
 
 
 
 
Service cost
 
4.62%
 
3.88%
Interest cost
 
4.01%
 
3.33%
 
 
 
 
 
Expected long-term rates of return
 
 
 
 
Qualified pension assets
 
7.25%
 
7.50%
Other postretirement - non-taxable assets
 
6.50% - 7.25%
 
6.50% - 7.50%
Other postretirement - taxable assets - after tax rate
 
5.50%
 
5.50%
 
 
 
 
 
Weighted-average rate of future compensation
 
3.98%
 
3.98%
 
 
 
 
 
Assumed health care cost trend rates
 
 
 
 
Pre-65 retirees
 
6.59%
 
6.95%
Post-65 retirees
 
7.15%
 
7.25%
Ultimate rate
 
4.75%
 
4.75%
Year ultimate rate is reached and beyond
 
 
 
 
Pre-65 retirees
 
2027
 
2027
Post-65 retirees
 
2026
 
2027

Actual asset returns have an effect on Entergy’s qualified pension and other postretirement costs. In 2018, Entergy’s actual average annual return on qualified pension assets was approximately (5%) and for other postretirement assets was approximately (4%), as compared with the 2018 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 2019 Qualified Pension Cost
 
Impact on 2018 Qualified Projected Benefit Obligation
 
 
Increase/(Decrease)
Discount rate
 
(0.25%)
 
$21
 
$210
Rate of return on plan assets
 
(0.25%)
 
$14
 
$—
Rate of increase in compensation
 
0.25%
 
$7
 
$34


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Table of Contents
Entergy Corporation 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 millions):
Actuarial Assumption
 
Change in Assumption
 
Impact on 2019 Postretirement Benefit Cost
 
Impact on 2018 Accumulated Postretirement Benefit Obligation
 
 
Increase/(Decrease)
Discount rate
 
(0.25%)
 
$2
 
$37
Health care cost trend
 
0.25%
 
$3
 
$29

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. 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 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. Entergy determines the MRV of pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns. For other postretirement benefit plan assets Entergy uses fair value when determining MRV.

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

Funding

Entergy’s pension funding in 2018 was $383.5 million. Entergy estimates pension contributions will be approximately $176.9 million in 2019; although the 2019 required pension contributions will be known with more certainty when the January 1, 2019 valuations are completed, which is expected by April 1, 2019.

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.

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Table of Contents
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis


    
Entergy contributed $43.8 million to its postretirement plans in 2018 and plans to contribute $47.6 million in 2019.

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.

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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Table of Contents

ENTERGY CORPORATION AND SUBSIDIARIES
REPORT OF MANAGEMENT

Management of Entergy Corporation and its subsidiaries has prepared and is responsible for the financial statements and related financial information included in this document.  To meet this responsibility, management establishes and maintains a system of internal controls over financial reporting designed to provide reasonable assurance regarding the preparation and fair presentation of financial statements in accordance with generally accepted accounting principles. This system includes communication through written policies and procedures, an employee Code of Entegrity, and an organizational structure that provides for appropriate division of responsibility and training of personnel. This system is also tested by a comprehensive internal audit program.
 
Entergy management assesses the design and effectiveness of Entergy’s internal control over financial reporting on an annual basis. In making this assessment, management uses the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. The 2013 COSO Framework was utilized for management’s assessment. Management acknowledges, however, that all internal control systems, no matter how well designed, have inherent limitations and can provide only reasonable assurance with respect to financial statement preparation and presentation.

Entergy Corporation’s independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the effectiveness of Entergy Corporation’s internal control over financial reporting as of December 31, 2018.

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, 2018. 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










 
2018

2017

2016

2015

2014
 
(In Thousands, Except Percentages and Per Share Amounts)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$11,009,452



$11,074,481

 

$10,845,645

 

$11,513,251



$12,494,921

Net income (loss)

$862,555



$425,353

 

($564,503
)
 

($156,734
)


$960,257

Earnings (loss) per share:
 

 
 
 
 
 


 

Basic

$4.68



$2.29

 

($3.26
)
 

($0.99
)


$5.24

Diluted

$4.63



$2.28

 

($3.26
)
 

($0.99
)


$5.22

Dividends declared per share

$3.58



$3.50

 

$3.42

 

$3.34



$3.32

Return on common equity
10.08
%

5.12
%
 
(6.73
%)
 
(1.83
%)

9.58
%
Book value per share, year-end

$46.78



$44.28

 

$45.12

 

$51.89



$55.83

Total assets

$48,275,066



$46,707,149

 

$45,904,434

 

$44,647,681



$46,414,455

Long-term obligations (a)

$15,758,083



$14,535,077

 

$14,695,422

 

$13,456,742



$12,627,180
















(a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and subsidiary preferred stock without sinking fund that is not presented as equity on the balance sheet.










 
2018

2017

2016

2015

2014
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
Utility electric operating revenues:
 


 


 


 


 

Residential

$3,566



$3,355



$3,288



$3,518



$3,555

Commercial
2,426


2,480


2,362


2,516


2,553

Industrial
2,499


2,584


2,327


2,462


2,623

Governmental
226


231


217


223


227

Total retail
8,717


8,650


8,194


8,719


8,958

Sales for resale
300


253


236


249


330

Other
367


376


437


341


304

Total

$9,384



$9,279



$8,867



$9,309



$9,592

 
 
 
 
 
 
 
 
 
 
Utility billed electric energy sales (GWh):





 


 


 

Residential
37,107


33,834


35,112


36,068


35,932

Commercial
29,426


28,745


29,197


29,348


28,827

Industrial
48,384


47,769


45,739


44,382


43,723

Governmental
2,581


2,511


2,547


2,514


2,428

Total retail
117,498


112,859


112,595


112,312


110,910

Sales for resale
11,715


11,550


11,054


9,274


9,462

Total
129,213


124,409


123,649


121,586


120,372

 
 
 
 
 
 
 
 
 
 
Entergy Wholesale Commodities:
 


 


 


 


 

Operating revenues

$1,469

 

$1,657

 

$1,850

 

$2,062

 

$2,719

Billed electric energy sales (GWh)
29,875

 
30,501

 
35,881

 
39,745

 
44,424




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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, 2018 and 2017, the related consolidated statements of operations, comprehensive income (loss), cash flows, and changes in equity, for each of the three years in the period ended December 31, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, 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, 2018, 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, 2019, 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 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. 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.


/s/ DELOITTE & TOUCHE LLP


New Orleans, Louisiana
February 26, 2019


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


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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
 
 
 
 
 
For the Years Ended December 31,
 
 
2018
 
2017
 
2016
 
 
  (In Thousands, Except Share Data)
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$9,384,111

 

$9,278,895

 

$8,866,659

Natural gas
 
156,436

 
138,856

 
129,348

Competitive businesses
 
1,468,905

 
1,656,730

 
1,849,638

TOTAL
 
11,009,452

 
11,074,481

 
10,845,645

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
2,147,793

 
1,991,589

 
1,809,200

Purchased power
 
1,658,799

 
1,427,950

 
1,220,527

Nuclear refueling outage expenses
 
153,826

 
168,151

 
208,678

Other operation and maintenance
 
3,346,397

 
3,306,694

 
3,225,477

Asset write-offs, impairments, and related charges
 
532,321

 
538,372

 
2,835,637

Decommissioning
 
388,508

 
405,685

 
327,425

Taxes other than income taxes
 
641,952

 
617,556

 
592,502

Depreciation and amortization
 
1,369,442

 
1,389,978

 
1,347,187

Other regulatory charges (credits) - net
 
301,049

 
(131,901
)
 
94,243

TOTAL
 
10,540,087

 
9,714,074

 
11,660,876

 
 
 
 
 
 
 
OPERATING INCOME (LOSS)
 
469,365

 
1,360,407

 
(815,231
)
 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
129,602

 
95,088

 
67,563

Interest and investment income
 
63,864

 
288,197

 
145,127

Miscellaneous - net
 
(129,754
)
 
(113,426
)
 
(112,851
)
TOTAL
 
63,712

 
269,859

 
99,839

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
768,322

 
707,212

 
700,545

Allowance for borrowed funds used during construction
 
(60,974
)
 
(44,869
)
 
(34,175
)
TOTAL
 
707,348

 
662,343

 
666,370

 
 
 
 
 
 
 
INCOME (LOSS) BEFORE INCOME TAXES
 
(174,271
)
 
967,923

 
(1,381,762
)
 
 
 
 
 
 
 
Income taxes
 
(1,036,826
)
 
542,570

 
(817,259
)
 
 
 
 
 
 
 
CONSOLIDATED NET INCOME (LOSS)
 
862,555

 
425,353

 
(564,503
)
 
 
 
 
 
 
 
Preferred dividend requirements of subsidiaries
 
13,894

 
13,741

 
19,115

 
 
 
 
 
 
 
NET INCOME (LOSS) ATTRIBUTABLE TO ENTERGY CORPORATION
 

$848,661

 

$411,612

 

($583,618
)
 
 
 
 
 
 
 
Earnings (loss) per average common share:
 
 

 
 

 
 

Basic
 

$4.68

 

$2.29

 

($3.26
)
Diluted
 

$4.63

 

$2.28

 

($3.26
)
 
 
 
 
 
 
 
Basic average number of common shares outstanding
 
181,409,597

 
179,671,797

 
178,885,660

Diluted average number of common shares outstanding
 
183,378,513

 
180,535,893

 
178,885,660

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 


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Table of Contents

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
 
 
 
For the Years Ended December 31,
 
2018
 
2017
 
2016
 
(In Thousands)
 
 
 
 
 
 
Net Income (Loss)

$862,555

 

$425,353

 

($564,503
)
 
 
 
 
 
 
Other comprehensive income (loss)
 

 
 

 
 

Cash flow hedges net unrealized gain (loss)
 

 
 

 
 

(net of tax expense (benefit) of $5,830, ($22,570), and ($55,298))
22,098

 
(41,470
)
 
(101,977
)
Pension and other postretirement liabilities
 

 
 

 
 

(net of tax expense (benefit) of $30,299, ($4,057), and ($3,952))
90,143

 
(61,653
)
 
(2,842
)
Net unrealized investment gains (losses)
 

 
 

 
 

(net of tax expense of $6,393, $80,069, and $57,277)
(28,771
)
 
115,311

 
62,177

Foreign currency translation
 

 
 

 
 

(net of tax benefit of $-, $403, and $689)
—

 
(748
)
 
(1,280
)
Other comprehensive income (loss)
83,470

 
11,440

 
(43,922
)
 
 
 
 
 
 
Comprehensive Income (Loss)
946,025

 
436,793

 
(608,425
)
Preferred dividend requirements of subsidiaries
13,894

 
13,741

 
19,115

Comprehensive Income (Loss) Attributable to Entergy Corporation

$932,131

 

$423,052

 

($627,540
)
 
 
 
 
 
 
See Notes to Financial Statements.
 

 
 

 
 



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Table of Contents

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
 
 
 
For the Years Ended December 31,
 
 
2018
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING ACTIVITIES
 
 
 
 
 
 
Consolidated net income (loss)
 

$862,555

 

$425,353

 

($564,503
)
Adjustments to reconcile consolidated net income (loss) to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 
2,040,555

 
2,078,578

 
2,123,291

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
(256,848
)
 
529,053

 
(836,257
)
Asset write-offs, impairments, and related charges
 
491,739

 
357,251

 
2,835,637

Changes in working capital:
 
 

 
 

 
 

Receivables
 
98,546

 
(97,637
)
 
(96,975
)
Fuel inventory
 
45,839

 
(3,043
)
 
38,210

Accounts payable
 
97,312

 
101,802

 
174,421

Prepaid taxes and taxes accrued
 
39,272

 
33,853

 
(28,963
)
Interest accrued
 
5,220

 
742

 
(7,335
)
Deferred fuel costs
 
(25,829
)
 
56,290

 
(241,896
)
Other working capital accounts
 
(164,173
)
 
(4,331
)
 
31,197

Changes in provisions for estimated losses
 
35,706

 
(3,279
)
 
20,905

Changes in other regulatory assets
 
189,193

 
595,504

 
(48,469
)
Changes in other regulatory liabilities
 
(803,323
)
 
2,915,795

 
158,031

Deferred tax rate change recognized as regulatory liability / asset
 
—

 
(3,665,498
)
 
—

Changes in pensions and other postretirement liabilities
 
(304,941
)
 
(130,686
)
 
(136,919
)
Other
 
34,424

 
(566,247
)
 
(421,676
)
Net cash flow provided by operating activities
 
2,385,247

 
2,623,500

 
2,998,699

 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 

 
 

 
 

Construction/capital expenditures
 
(3,942,010
)
 
(3,607,532
)
 
(2,780,222
)
Allowance for equity funds used during construction
 
130,195

 
96,000

 
68,345

Nuclear fuel purchases
 
(302,584
)
 
(377,324
)
 
(314,706
)
Payment for purchase of plant or assets
 
(26,623
)
 
(16,762
)
 
(949,329
)
Proceeds from sale of assets
 
24,902

 
100,000

 
—

Insurance proceeds received for property damages
 
18,270

 
26,157

 
20,968

Changes in securitization account
 
(5,844
)
 
1,323

 
4,007

Payments to storm reserve escrow account
 
(6,551
)
 
(2,878
)
 
(1,544
)
Receipts from storm reserve escrow account
 
—

 
11,323

 
—

Decrease (increase) in other investments
 
(54,500
)
 
1,078

 
9,055

Litigation proceeds for reimbursement of spent nuclear fuel storage costs
 
59,643

 
25,493

 
169,085

Proceeds from nuclear decommissioning trust fund sales
 
6,484,791

 
3,162,747

 
2,408,920

Investment in nuclear decommissioning trust funds
 
(6,485,676
)
 
(3,260,674
)
 
(2,484,627
)
Net cash flow used in investing activities
 
(4,105,987
)
 
(3,841,049
)
 
(3,850,048
)
 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 


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Table of Contents

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
 
 
 
For the Years Ended December 31,
 
 
2018
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Proceeds from the issuance of:
 
 
 
 
 
 
Long-term debt
 
8,035,536

 
1,809,390

 
6,800,558

Preferred stock of subsidiary
 
73,330

 
14,399

 
—

Treasury stock
 
103,315

 
80,729

 
33,114

Common stock
 
499,272

 
—

 
—

Retirement of long-term debt
 
(6,965,738
)
 
(1,585,681
)
 
(5,311,324
)
Repurchase / redemptions of preferred stock
 
(53,868
)
 
(20,599
)
 
(115,283
)
Changes in credit borrowings and commercial paper - net
 
364,031

 
1,163,296

 
(79,337
)
Other
 
26,453

 
(7,731
)
 
(6,872
)
Dividends paid:
 
 

 
 

 
 

Common stock
 
(647,704
)
 
(628,885
)
 
(611,835
)
Preferred stock
 
(14,185
)
 
(13,940
)
 
(20,789
)
Net cash flow provided by financing activities
 
1,420,442

 
810,978

 
688,232

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net decrease in cash and cash equivalents
 
(300,298
)
 
(406,571
)
 
(163,117
)
 
 
 
 
 
 
 
Cash and cash equivalents at beginning of period
 
781,273

 
1,187,844

 
1,350,961

 
 
 
 
 
 
 
Cash and cash equivalents at end of period
 

$480,975

 

$781,273

 

$1,187,844

 
 
 
 
 
 
 
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 

 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$734,845

 

$678,371

 

$746,779

Income taxes
 

$19,825

 

($13,375
)
 

$95,317

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 



49
Table of Contents

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2018
 
2017
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$56,690

 

$56,629

Temporary cash investments
 
424,285

 
724,644

Total cash and cash equivalents
 
480,975

 
781,273

Accounts receivable:
 
 

 
 

Customer
 
558,494

 
673,347

Allowance for doubtful accounts
 
(7,322
)
 
(13,587
)
Other
 
167,722

 
169,377

Accrued unbilled revenues
 
395,511

 
383,813

Total accounts receivable
 
1,114,405

 
1,212,950

Deferred fuel costs
 
27,251

 
95,746

Fuel inventory - at average cost
 
117,304

 
182,643

Materials and supplies - at average cost
 
752,843

 
723,222

Deferred nuclear refueling outage costs
 
230,960

 
133,164

Prepayments and other
 
234,326

 
156,333

TOTAL
 
2,958,064

 
3,285,331

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Investment in affiliates - at equity
 
—

 
198

Decommissioning trust funds
 
6,920,164

 
7,211,993

Non-utility property - at cost (less accumulated depreciation)
 
304,382

 
260,980

Other
 
437,265

 
441,862

TOTAL
 
7,661,811

 
7,915,033

 
 
 
 
 
PROPERTY, PLANT, AND EQUIPMENT
 
 

 
 

Electric
 
49,196,578

 
47,287,370

Property under capital lease
 
634,908

 
620,544

Natural gas
 
496,150

 
453,162

Construction work in progress
 
2,888,639

 
1,980,508

Nuclear fuel
 
861,272

 
923,200

TOTAL PROPERTY, PLANT AND EQUIPMENT
 
54,077,547

 
51,264,784

Less - accumulated depreciation and amortization
 
22,103,101

 
21,600,424

PROPERTY, PLANT AND EQUIPMENT - NET
 
31,974,446

 
29,664,360

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Other regulatory assets (includes securitization property of $360,790 as of December 31, 2018 and $485,031 as of December 31, 2017)
 
4,746,496

 
4,935,689

Deferred fuel costs
 
239,496

 
239,298

Goodwill
 
377,172

 
377,172

Accumulated deferred income taxes
 
54,593

 
178,204

Other
 
262,988

 
112,062

TOTAL
 
5,680,745

 
5,842,425

 
 
 
 
 
TOTAL ASSETS
 

$48,275,066

 

$46,707,149

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2018
 
2017
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Currently maturing long-term debt
 

$650,009

 

$760,007

Notes payable and commercial paper
 
1,942,339

 
1,578,308

Accounts payable
 
1,496,058

 
1,452,216

Customer deposits
 
411,505

 
401,330

Taxes accrued
 
254,241

 
214,967

Interest accrued
 
193,192

 
187,972

Deferred fuel costs
 
52,396

 
146,522

Obligations under capital leases
 
1,617

 
1,502

Pension and other postretirement liabilities
 
61,240

 
71,612

Current portion of unprotected excess accumulated deferred income taxes
 
248,127

 
—

Other
 
132,820

 
221,771

TOTAL
 
5,443,544

 
5,036,207

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
4,107,152

 
4,466,503

Accumulated deferred investment tax credits
 
213,101

 
219,634

Obligations under capital leases
 
20,378

 
22,015

Regulatory liability for income taxes-net
 
1,817,021

 
2,900,204

Other regulatory liabilities
 
1,620,254

 
1,588,520

Decommissioning and asset retirement cost liabilities
 
6,355,543

 
6,185,814

Accumulated provisions
 
514,107

 
478,273

Pension and other postretirement liabilities
 
2,616,085

 
2,910,654

Long-term debt (includes securitization bonds of $423,858 as of December 31, 2018 and $544,921 as of December 31, 2017)
 
15,518,303

 
14,315,259

Other
 
985,871

 
393,748

TOTAL
 
33,767,815

 
33,480,624

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
Subsidiaries’ preferred stock without sinking fund
 
219,402

 
197,803

 
 
 
 
 
 COMMON EQUITY
 
 

 
 

Common stock, $.01 par value, authorized 500,000,000 shares; issued 261,587,009 shares in 2018 and 254,752,788 shares in 2017
 
2,616

 
2,548

Paid-in capital
 
5,951,431

 
5,433,433

Retained earnings
 
8,721,150

 
7,977,702

Accumulated other comprehensive loss
 
(557,173
)
 
(23,531
)
Less - treasury stock, at cost (72,530,866 shares in 2018 and 74,235,135 shares in 2017)
 
5,273,719

 
5,397,637

TOTAL
 
8,844,305

 
7,992,515

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$48,275,066

 

$46,707,149

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 



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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2018, 2017, and 2016
 
 
 
 
 
 
 
 

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, 2015

$—

 

$2,548

 

($5,552,379
)
 

$5,403,758

 

$9,393,913

 

$8,951

 

$9,256,791

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Consolidated net income (loss)
19,115

 
—

 
—

 
—

 
(583,618
)
 
—

 
(564,503
)
Other comprehensive loss
—

 
—

 
—

 
—

 
—

 
(43,922
)
 
(43,922
)
Common stock issuances related to stock plans
—

 
—

 
53,795

 
13,487

 
—

 
—

 
67,282

Common stock dividends declared
—

 
—

 
—

 
—

 
(611,835
)
 
—

 
(611,835
)
Subsidiaries' capital stock redemptions
—

 
—

 
—

 
—

 
(2,889
)
 
—

 
(2,889
)
Preferred dividend requirements of subsidiaries
(19,115
)
 
—

 
—

 
—

 
—

 
—

 
(19,115
)
Balance at December 31, 2016

$—

 

$2,548

 

($5,498,584
)
 

$5,417,245

 

$8,195,571

 

($34,971
)
 

$8,081,809

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Consolidated net income
13,741

 
—

 
—

 
—

 
411,612

 
—

 
425,353

Other comprehensive income
—

 
—

 
—

 
—

 
—

 
11,440

 
11,440

Common stock issuances related to stock plans
—

 
—

 
100,947

 
16,188

 
—

 
—

 
117,135

Common stock dividends declared
—

 
—

 
—

 
—

 
(628,885
)
 
—

 
(628,885
)
Subsidiaries' capital stock redemptions
—

 
—

 
—

 
—

 
(596
)
 
—

 
(596
)
Preferred dividend requirements of subsidiaries
(13,741
)
 
—

 
—

 
—

 
—

 
—

 
(13,741
)
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
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
(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

 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 

 
 

 
 

 
 


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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

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Mississippi, and Texas, respectively.  Entergy Louisiana also distributes natural gas to retail customers in and around Baton Rouge, Louisiana.  Entergy New Orleans sells both electric power and natural gas to retail customers in the City of New Orleans. The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power generated by plants owned by subsidiaries in that segment.

Entergy recognizes revenue from electric power and natural gas sales when power or gas is delivered to customers.  To the extent that deliveries have occurred but a bill has not been issued, Entergy’s Utility operating companies accrue an estimate of the revenues 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 prices in effect in Entergy’s Utility operating companies’ various jurisdictions.  Changes are made to the inputs in the estimate as needed to reflect changes in billing practices.  Each month the estimated unbilled revenue amounts are recorded as revenue and unbilled accounts receivable, and the prior month’s estimate is reversed.  Therefore, changes in price and volume differences resulting from factors such as weather affect the calculation of unbilled revenues from one period to the next, and may result in variability in reported revenues from one period to the next as prior estimates are reversed and new estimates recorded.

For sales under rates implemented subject to refund, Entergy reduces revenue by accruing estimated amounts for probable refunds when Entergy believes it is probable that revenues will be refunded to customers based upon the status of the rate proceeding.

See Note 19 to the financial statements for details of Entergy’s and the Registrant Subsidiaries’ revenues.

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 billed 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

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Notes to Financial Statements


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 computed by allowing a return 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.

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.  Substantially all of the Registrant Subsidiaries’ plant is subject to mortgage liens.

Electric plant includes the portions of Grand Gulf and Waterford 3 that were sold and leased back in prior periods.  For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions. In March 2016, Entergy Louisiana completed the first step in a two-step transaction to purchase the undivided interests in Waterford 3 that were previously being leased by acquiring a beneficial interest in the Waterford 3 leased assets. In February 2017 the leases were terminated and the leased assets transferred to Entergy Louisiana. See Note 10 to the financial statements for further discussion of Entergy Louisiana’s purchase of the Waterford 3 leased assets.

Net property, plant, and equipment for Entergy (including property under capital lease and associated accumulated amortization) by business segment and functional category, as of December 31, 2018 and 2017, is shown below:
2018
 
Entergy
 
Utility
 
Entergy Wholesale Commodities
 
Parent & Other
 
 
(In Millions)
Production
 
 

 
 

 
 

 
 

Nuclear
 

$7,096

 

$6,964

 

$132

 

$—

Other
 
4,171

 
4,069

 
102

 
—

Transmission
 
6,592

 
6,590

 
2

 
—

Distribution
 
8,343

 
8,343

 
—

 
—

Other
 
2,022

 
2,011

 
2

 
9

Construction work in progress
 
2,889

 
2,815

 
74

 
—

Nuclear fuel
 
861

 
754

 
107

 
—

Property, plant, and equipment - net
 

$31,974

 

$31,546

 

$419

 

$9



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Entergy Corporation and Subsidiaries
Notes to Financial Statements


2017
 
Entergy
 
Utility
 
Entergy Wholesale Commodities
 
Parent & Other
 
 
(In Millions)
Production
 
 

 
 

 
 

 
 

Nuclear
 

$6,946

 

$6,694

 

$252

 

$—

Other
 
4,215

 
4,118

 
97

 
—

Transmission
 
5,844

 
5,842

 
2

 
—

Distribution
 
8,000

 
8,000

 
—

 
—

Other
 
1,755

 
1,748

 
3

 
4

Construction work in progress
 
1,981

 
1,951

 
30

 
—

Nuclear fuel
 
923

 
822

 
101

 
—

Property, plant, and equipment - net
 

$29,664

 

$29,175

 

$485

 

$4


Depreciation rates on average depreciable property for Entergy approximated 2.8% in 2018, 3% in 2017, and 2.8% in 2016.  Included in these rates are the depreciation rates on average depreciable Utility property of 2.6% in 2018, 2.6% in 2017, and 2.6% in 2016, and the depreciation rates on average depreciable Entergy Wholesale Commodities property of 18.6% in 2018, 22.3% in 2017, and 5.2% in 2016. The increased depreciation rate in 2017 for Entergy Wholesale Commodities reflects the significantly reduced remaining estimated operating lives associated with management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet. The decreased depreciation rate in 2018 for Entergy Wholesale Commodities is due to the decision in the third quarter 2017 to continue operating Palisades until May 31, 2022.

Entergy amortizes nuclear fuel using a units-of-production method.  Nuclear fuel amortization is included in fuel expense in the income statements. 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 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 $177 million as of December 31, 2018 and $167 million as of December 31, 2017.

Construction expenditures included in accounts payable is $311 million as of December 31, 2018 and $368 million as of December 31, 2017.

Net property, plant, and equipment for the Registrant Subsidiaries (including property under capital lease and associated accumulated amortization) by company and functional category, as of December 31, 2018 and 2017, is shown below:

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Entergy Corporation and Subsidiaries
Notes to Financial Statements


2018
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Millions)
Production
 
 
 
 
 
 
 
 
 
 
 
 
Nuclear
 

$1,494

 

$3,725

 

$—

 

$—

 

$—

 

$1,745

Other
 
820

 
2,029

 
509

 
196

 
515

 
—

Transmission
 
1,792

 
2,571

 
1,046

 
78

 
1,063

 
40

Distribution
 
2,329

 
2,882

 
1,342

 
471

 
1,319

 
—

Other
 
311

 
699

 
242

 
233

 
193

 
39

Construction work in progress
 
244

 
1,865

 
128

 
147

 
325

 
70

Nuclear fuel
 
221

 
298

 
—

 
—

 
—

 
235

Property, plant, and equipment - net
 

$7,211

 

$14,069

 

$3,267

 

$1,125

 

$3,415

 

$2,129

2017
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Millions)
Production
 
 
 
 
 
 
 
 
 
 
 
 
Nuclear
 

$1,368

 

$3,664

 

$—

 

$—

 

$—

 

$1,660

Other
 
806

 
2,016

 
560

 
207

 
531

 
—

Transmission
 
1,650

 
2,148

 
900

 
81

 
1,021

 
42

Distribution
 
2,226

 
2,748

 
1,316

 
440

 
1,270

 
—

Other
 
247

 
592

 
203

 
204

 
168

 
39

Construction work in progress
 
281

 
1,281

 
149

 
47

 
102

 
70

Nuclear fuel
 
277

 
337

 
—

 
—

 
—

 
208

Property, plant, and equipment - net
 

$6,855

 

$12,786

 

$3,128

 

$979

 

$3,092

 

$2,019


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
2018
2.5%
 
2.3%
 
3.2%
 
3.5%
 
2.7%
 
1.9%
2017
2.5%
 
2.3%
 
3.1%
 
3.5%
 
2.6%
 
2.8%
2016
2.5%
 
2.3%
 
3.1%
 
3.4%
 
2.5%
 
2.8%

Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $161.2 million as of December 31, 2018 and $152.3 million as of December 31, 2017. 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, 2018 and $0.5 million as of December 31, 2017.  Non-utility property - at cost (less accumulated depreciation) for Entergy Texas is reported net of accumulated depreciation of $4.9 million as of December 31, 2018 and $4.9 million as of December 31, 2017.

As of December 31, 2018, construction expenditures included in accounts payable are $35.7 million for Entergy Arkansas, $104.6 million for Entergy Louisiana, $13.6 million for Entergy Mississippi, $5.8 million for Entergy New Orleans, $55.6 million for Entergy Texas, and $26.3 million for System Energy. As of December 31, 2017, construction expenditures included in accounts payable are $58.8 million for Entergy Arkansas, $160.4 million for Entergy Louisiana, $17.1 million for Entergy Mississippi, $2.5 million for Entergy New Orleans, $32.8 million for Entergy Texas, and $33.9 million for System Energy.

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Entergy Corporation and Subsidiaries
Notes to Financial Statements



Jointly-Owned Generating Stations

Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties. All parties are required to provide their own financing.  The investments, fuel expenses, and other operation and maintenance expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests.  As of December 31, 2018, the subsidiaries’ investment and accumulated depreciation in each of these generating stations were as follows:


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Notes to Financial Statements


Generating Stations
 
Fuel Type
 
Total Megawatt Capability (a)
 
Ownership
 
Investment
 
Accumulated Depreciation
 
 
 
 
 
 
 
 
 
(In Millions)
Utility business:
 
 
 
 
 
 
 
 
 
 
 
Entergy Arkansas -
 
 
 
 
 
 
 
 
 
 
 
  Independence
Unit 1
 
Coal
 
810

 
31.50
%
 

$141

 

$103

  Independence
Common Facilities
 
Coal
 
 
 
15.75
%
 

$35

 

$28

  White Bluff
Units 1 and 2
 
Coal
 
1,637

 
57.00
%
 

$553

 

$368

  Ouachita (b)
Common Facilities
 
Gas
 


 
66.67
%
 

$173

 

$151

  Union (c)
Units 1 and 2 Common Facilities
 
Gas
 


 
50.00
%
 

$1

 

$—

  Union (c)
Common Facilities
 
Gas
 
 
 
25.00
%
 

$29

 

$4

Entergy Louisiana -
 
 
 
 
 
 
 

 
 
 
 
  Roy S. Nelson
Unit 6
 
Coal
 
550

 
40.25
%
 

$282

 

$200

  Roy S. Nelson
Unit 6 Common Facilities
 
Coal
 
 
 
20.83
%
 

$19

 

$8

  Big Cajun 2
Unit 3
 
Coal
 
581

 
24.15
%
 

$151

 

$120

  Big Cajun 2
Unit 3 Common Facilities
 
Coal
 
 
 
8.05
%
 

$5

 

$2

  Ouachita (b)
Common Facilities
 
Gas
 


 
33.33
%
 

$90

 

$76

  Acadia
Common Facilities
 
Gas
 


 
50.00
%
 

$20

 

$1

  Union (c)
Common Facilities
 
Gas
 
 
 
50.00
%
 

$57

 

$5

Entergy Mississippi -
 
 
 
 
 
 
 

 
 
 
 
  Independence
Units 1 and 2 and Common Facilities
 
Coal
 
1,652

 
25.00
%
 

$270

 

$158

Entergy New Orleans -
 
 
 
 
 
 
 
 
 
 
 
  Union (c)
Units 1 and 2 Common Facilities
 
Gas
 


 
50.00
%
 

$1

 

$—

  Union (c)
Common Facilities
 
Gas
 
 
 
25.00
%
 

$29

 

$4

Entergy Texas -
 
 
 
 
 
 
 

 
 
 
 
  Roy S. Nelson
Unit 6
 
Coal
 
550

 
29.75
%
 

$201

 

$116

  Roy S. Nelson
Unit 6 Common Facilities
 
Coal
 
 
 
15.39
%
 

$7

 

$3

  Big Cajun 2
Unit 3
 
Coal
 
581

 
17.85
%
 

$113

 

$77

  Big Cajun 2
Unit 3 Common Facilities
 
Coal
 
 
 
5.95
%
 

$3

 

$1

System Energy -
 
 
 
 
 
 
 

 
 
 
 
  Grand Gulf (d)
Unit 1
 
Nuclear
 
1,391

 
90.00
%
 

$5,036

 

$3,212

Entergy Wholesale Commodities:
 
 
 
 
 
 
 

 
 
 
 
  Independence
Unit 2
 
Coal
 
842

 
14.37
%
 

$74

 

$52

  Independence
Common Facilities
 
Coal
 
 
 
7.18
%
 

$17

 

$12

  Roy S. Nelson
Unit 6
 
Coal
 
550

 
10.90
%
 

$114

 

$64

  Roy S. Nelson
Unit 6 Common Facilities
 
Coal
 
 
 
5.64
%
 

$2

 

$1


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(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.
(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 10 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.  Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, LLC, and Entergy New Orleans, LLC are not members of the Entergy Corporation consolidated federal income tax filing group but, rather, are included in the Entergy Utility Holding Company, LLC consolidated federal income tax filing group.  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,
 
2018
 
2017
 
2016
 
(In Millions, Except Per Share Data)
 
 
 
$/share
 
 
 
$/share
 
 
 
$/share
Net income (loss) attributable to Entergy Corporation

$848.7

 
 

 

$411.6

 
 

 

($583.6
)
 
 

Basic shares and earnings (loss) per average common share
181.4

 

$4.68

 
179.7

 

$2.29

 
178.9

 

($3.26
)
Average dilutive effect of:
 

 
 

 
 

 
 

 
 

 
 

Stock options
0.3

 
(0.01
)
 
0.2

 
—

 
—

 
—

Other equity plans
0.7

 
(0.02
)
 
0.6

 
(0.01
)
 
—

 
—

Equity forwards
1.0

 
(0.02
)
 
—

 
—

 
—

 
—

Diluted shares and earnings (loss) per average common shares
183.4

 

$4.63

 
180.5

 

$2.28

 
178.9

 

($3.26
)

The calculation of diluted earnings (loss) per share excluded 956,550 options outstanding at December 31, 2018, 2,927,512 options outstanding at December 31, 2017, and 7,137,210 options outstanding at December 31, 2016 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, which 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, and 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 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 based on accounts receivable agings, historical experience, and other currently available evidence.  Utility operating company customer accounts receivable are written off consistent with approved regulatory requirements.

Investments

Entergy records decommissioning trust funds on the balance sheet at their fair value. Effective January 1, 2018, with the adoption of ASU 2016-01, 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, 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 Pilgrim, Indian Point 1, Indian Point 2, Indian Point 3, Vermont Yankee, and Palisades do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains/(losses) recorded on the equity securities in the

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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 are 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 are recognized in earnings. 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).  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 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.  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

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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 held by regulated businesses may be 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 their long-lived assets are impaired, and their 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 because their undiscounted cash flows are insufficient to recover the carrying amount of these capital additions.  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 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.


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New Accounting Pronouncements

In February 2016 the FASB issued ASU No. 2016-02, “Leases (Topic 842).”  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.  In January 2018 the FASB issued ASU No. 2018-01, “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842,” providing entities the option to elect not to evaluate existing land easements that are not currently accounted for under the previous lease standard. In July 2018 the FASB issued ASU No. 2018-11, “Leases (Topic 842): Targeted Improvements,” which is intended to simplify the transition requirements giving entities the option to apply the transition provisions of the new standard at the date of adoption instead of at the earliest comparative period presented and provides a practical expedient for the separation of lease and nonlease components for lessors. Entergy adopted ASU 2016-02 along with the practical expedients provided by ASU 2018-01 and 2018-11 in the first quarter 2019. Entergy does not expect that ASU 2016-02 will materially affect its results of operations, financial position, or cash flows. In adopting the standard, in January 2019 Entergy recognized right-of-use assets and corresponding lease liabilities totaling approximately $263 million for Entergy and the following right-of-use assets and corresponding lease liabilities for the Registrant Subsidiaries: $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.

In June 2016 the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” The ASU requires entities to record a valuation allowance on financial instruments recorded at amortized cost or classified as available-for-sale debt securities for the total credit losses expected over the life of the instrument. Increases and decreases in the valuation allowance will be recognized immediately in earnings. ASU 2016-13 is effective for Entergy for the first quarter 2020. Entergy is evaluating ASU 2016-13 for the expected effects on its results of operations, financial position, and cash flows.
    
In August 2017 the FASB issued ASU No. 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.”  The ASU makes a number of amendments to hedge accounting, most significantly changing the recognition and presentation of highly effective hedges.  Upon adoption of the standard there will no longer be separate recognition or presentation of the ineffective portion of highly effective hedges.  In addition, the ASU allows entities to designate a contractually-specified component as the hedged risk, simplifies the process for assessing the effectiveness of hedges, and adds additional disclosure requirements for hedges.  ASU 2017-12 was effective for Entergy for the first quarter 2019. Entergy expects that ASU 2017-12 will affect its net income by eliminating volatility in earnings related to the ineffective portion of designated hedges on nuclear power sales.  Entergy 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.

In September 2018 the FASB issued ASU No. 2018-15, “Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service.”  The ASU requires entities to capitalize implementation costs associated with cloud computing arrangements classified as hosting arrangements and amortize those costs over the contract term.  These costs are required to be capitalized in the same line as prepayments of the costs, and subsequently amortized in the same lines as the hosting service element of the arrangement.  ASU 2018-15 is effective for Entergy for the first quarter 2020.  Entergy does not expect to early adopt the standard.  Entergy expects that it will elect to adopt ASU 2018-15 on a prospective basis, which will affect its statement of financial position by presenting implementation costs for hosting arrangements as prepayments, and net income by amortizing those costs as operation and maintenance expense over the contract term of the arrangement. Entergy is evaluating ASU 2018-15 for other effects on its results of operations, financial position, or cash flows.



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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, 2018 and 2017:
 
Other Regulatory Assets

Entergy
 
2018
 
2017
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)

$2,611.5

 

$2,642.3

Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)
814.3

 
746.0

Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 – Storm Cost Recovery Filings with Retail Regulators) (Note 5)
452.7

 
558.9

Removal costs - recovered through depreciation rates (Note 9)
375.8

 
436.5

Opportunity Sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)
116.3

 
109.8

Unamortized loss on reacquired debt - recovered over term of debt
74.5

 
82.9

Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)
52.1

 
73.7

Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators
39.0

 
86.4

New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) (b)
29.0

 
36.4

Transition to competition costs - recovered over a 15-year period through February 2021
26.7

 
37.7

Other
154.6

 
125.1

Entergy Total

$4,746.5

 

$4,935.7


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Entergy Arkansas
 
2018
 
2017
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)

$747.2

 

$757.0

Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)
381.7

 
345.2

Removal costs - recovered through depreciation rates (Note 9)
138.3

 
176.9

Opportunity sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)
116.3

 
109.8

Storm damage costs - recovered either through securitization or retail rates (Note 5 - Entergy Arkansas Securitization Bonds)
60.7

 
76.2

Unamortized loss on reacquired debt - recovered over term of debt
21.2

 
24.3

Retail rate deferrals - recovered through rate riders as rates are redetermined annually
20.5

 
28.2

ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (Note 2 - Retail Rate Proceedings) (b)
12.6

 
14.4

Other
36.5

 
35.4

Entergy Arkansas Total

$1,535.0

 

$1,567.4


Entergy Louisiana
 
2018
 
2017
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (a)

$711.8

 

$724.6

Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)
232.9

 
218.6

Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)
49.8

 
71.4

New nuclear generation development costs - recovery through formula rate plan December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (b)
28.5

 
35.8

Unamortized loss on reacquired debt - recovered over term of debt
22.5

 
24.7

Storm damage costs - recovered through retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)
17.9

 
14.3

Business combination external costs deferral - recovery through formula rate plan December 2015 through November 2025 (b)
12.4

 
14.1

River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC)
11.0

 
12.9

Other
18.3

 
29.4

Entergy Louisiana Total

$1,105.1

 

$1,145.8



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Entergy Mississippi
 
2018
 
2017
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)

$215.9

 

$218.7

Removal costs - recovered through depreciation rates (Note 9)
63.5

 
91.6

Attorney General litigation costs (Note 2 - Mississippi Attorney General Complaint) (b)
23.6

 
9.3

Retail rate deferrals - recovered through rate riders as rates are redetermined annually
16.6

 
49.4

Unamortized loss on reacquired debt - recovered over term of debt
16.2

 
17.6

Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)
7.2

 
7.6

Other
—

 
3.7

Entergy Mississippi Total

$343.0

 

$397.9


Entergy New Orleans
 
2018
 
2017
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)

$96.2

 

$102.8

Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators)
70.4

 
82.3

Removal costs - recovered through depreciation rates (Note 9)
49.3

 
44.8

Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)
4.5

 
4.3

Unamortized loss on reacquired debt - recovered over term of debt
2.6

 
3.0

Rate case costs - recovered over a 6-year period through September 2021 (Note 2 - Retail Rate Proceedings)
1.9

 
2.6

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

 
4.4

Other
4.9

 
7.2

Entergy New Orleans Total

$229.8

 

$251.4



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Entergy Texas
 
2018
 
2017
 
(In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds)

$303.6

 

$386.1

Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
171.8

 
169.2

Removal costs - recovered through depreciation rates (Note 9)
50.9

 
55.2

Transition to competition costs - recovered over a 15-year period through February 2021
26.7

 
37.7

Neches and Sabine costs - recovered over a ten-year period through September 2028 (Note 2 - Retail Rate Proceedings) (b)
23.6

 
—

Unamortized loss on reacquired debt - recovered over term of debt
8.2

 
8.7

Other
13.2

 
4.5

Entergy Texas Total

$598.0

 

$661.4


System Energy
 
2018
 
2017
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (a)

$179.3

 

$202.7

Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a)
186.9

 
169.1

Removal costs - recovered through depreciation rates (Note 9)
76.4

 
67.9

Unamortized loss on reacquired debt - recovered over term of debt
3.8

 
4.6

System Energy Total

$446.4

 

$444.3


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

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Other Regulatory Liabilities

Entergy
 
2018
 
2017
 
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)

$815.9

 

$989.3

Vidalia purchased power agreement (Note 8) (b)
139.7

 
151.6

Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)
111.1

 
124.8

Income tax rate change - returned to electric and gas customers through retail rates (Note 2 - Retail Rate Proceedings)
74.7

 
—

Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)
67.9

 
67.9

Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)
50.8

 
65.8

Grand Gulf over-recovery - will be refunded through rate riders as rates are redetermined annually
48.6

 
—

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)
44.4

 
—

Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)
39.6

 
—

Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
39.1

 
36.7

Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)
31.9

 
—

Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement
25.0

 
32.1

Removal costs - returned to customers through depreciation rates (Note 9)
18.8

 
32.4

Other
68.4

 
43.5

Entergy Total

$1,620.3

 

$1,588.5


Entergy Arkansas
 
2018
 
2017
 
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)

$297.2

 

$354.0

Internal restructuring guaranteed customer credits (Note 2 - Retail Rate Proceedings)
39.6

 
—

Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)
35.1

 
—

Grand Gulf over-recovery - will be refunded through rate riders as rates are redetermined annually
26.0

 
—

Other
4.8

 
9.6

Entergy Arkansas Total

$402.7

 

$363.6



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Entergy Louisiana
 
2018
 
2017
 
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)

$274.1

 

$323.7

Vidalia purchased power agreement (Note 8) (b)
139.7

 
151.6

Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)
111.1

 
124.8

Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)
50.8

 
65.8

Income tax rate change - returned to electric customers through retail rates September 2018 through August 2019 (Note 2 - Retail Rate Proceedings)
49.9

 
—

Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
39.1

 
36.7

Excess decommissioning recovery for Willow Glen - (Note 14 - Dispositions)
31.9

 
—

Removal costs - returned to customers through depreciation rates (Note 9)
18.8

 
32.4

Other
33.4

 
26.1

Entergy Louisiana Total

$748.8

 

$761.1


Entergy Mississippi
 
2018
 
2017
 
(In Millions)
Grand Gulf Over-Recovery - returned to customers through rate riders when rates are redetermined annually

$22.6

 

$—

Future formula rate plan revenue reductions (Note 2 - Retail Rate Proceedings)
9.3

 
—

Other
1.7

 
0.9

Entergy Mississippi Total

$33.6

 

$0.9


Entergy Texas
 
2018
 
2017
 
(In Millions)
Income tax rate change - refunded through a rate rider (Note 2 - Retail Rate Proceedings)

$23.1

 

$—

Advanced metering system surcharge (Note 2 - Advanced Metering Infrastructure (AMI) Filings)
16.5

 
—

Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically
4.2

 
4.8

Other
4.1

 
2.1

Entergy Texas Total

$47.9

 

$6.9



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System Energy
 
2018
 
2017
 
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)

$244.6

 

$311.6

Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)
67.9

 
67.9

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

Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement
25.0

 
32.1

System Energy Total

$381.9

 

$456.0


(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 $25.0 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 will be 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 to be credited or billed to customers during the billing month of January 2020, with any residual amounts of over- or under-returned unprotected excess accumulated deferred income taxes to be flowed through Entergy Arkansas’s energy cost recovery rider. In March 2018 the APSC approved the tax adjustment rider effective with the first billing cycle of April 2018.

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 existing formula rate plan rider for its customers to realize the remaining benefits of the Tax Act. Entergy Arkansas’s formula rate plan rider includes a netting adjustment that compares 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

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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.

Entergy Louisiana

In a 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 will be 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. Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the allowed return on rate base. The stipulation approved in June 2018 provides 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 any true-up to be 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 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. In November 2018, Entergy Mississippi’s annual redetermination of the annual factor to be applied under the power management rider included an insignificant true-up to the amount of unprotected excess accumulated deferred income taxes. In January 2019 the MPSC approved the proposed power management cost factor effective for February 2019 bills.

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

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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. In both a memorandum issued prior to the open meeting when the order was discussed and during the discussions at the open meeting regarding the order, the PUCT indicated that it would consider utility earnings in determining the treatment of the liability and the effects of the Tax Act. 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. Entergy Texas also stated that it would be inappropriate for the PUCT to require a refund of the reduction in income tax expense in 2018 resulting from the Act on a retroactive basis and without a comprehensive review of Entergy Texas’s cost of service and earned return on equity.

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 will 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 will 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 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 larger customers and over a period of four years for other customers.

System Energy

In a filing made with the FERC in March 2018, Entergy proposed revisions to the Unit Power Sales Agreement, among other agreements, to reflect the effects of the Tax Act. In the filing System Energy proposed to return all of its 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 are ongoing.


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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, 2018 and 2017 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.
 
2018
 
2017
 
(In Millions)
Entergy Arkansas (a)

$86.5

 

$130.4

Entergy Louisiana (b)

$136.7

 

$96.7

Entergy Mississippi

$8.0

 

$32.4

Entergy New Orleans (b)

$2.8

 

($3.7
)
Entergy Texas

($19.7
)
 

($67.3
)

(a)
Includes $67.3 million in 2018 and $67.1 million in 2017 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

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 below.

In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update were effective July 2016 through June 2017.

In May 2017, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected a credit amount of $0.3 million resulting from a compliance filing pursuant to the FERC’s September 2016 order. Additionally, the redetermined rate reflected recovery of the production cost allocation rider true-up adjustment of the 2016 unrecovered retail balance in the amount of $0.3 million. Because of the small effect of the 2017 production cost allocation rider update, Entergy Arkansas proposed to reduce the effective period of the update to one month, July 2017. After the one month collection period, rates were set to zero for all rate classes for the period August 2017 through June 2018.

In May 2018, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the 2017 under-recovered retail balance and a $2.8 million payment by Entergy Arkansas associated with a compliance filing pursuant to a March 2018 FERC order related to 2010 production costs. The rates for the 2018 production cost allocation rider update are effective July 2018 through June 2019.

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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 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

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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.

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 December 2011 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates.  The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009.  In March 2016 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $8.6 million, plus interest, to customers and realign the recovery of approximately $12.7 million from Entergy Gulf States Louisiana’s fuel adjustment clause to base rates. In September 2016 the LPSC staff filed testimony stating that it was no longer recommending a disallowance of $3.4 million of the $8.6 million discussed above, but otherwise maintained the positions from its report. Subsequently, the parties entered into a settlement, which was approved by the LPSC in November 2016. The settlement recognized the dry cask storage recovery method issue, which was addressed in the separate proceeding approved by the LPSC in October 2017, provided for a refund of $5 million, which was made to legacy Entergy Gulf States Louisiana customers in December 2016, and resolved all other issues raised in the audit.

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 is evaluating the staff’s recommended disallowance.

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 is evaluating the staff’s recommended disallowance.

In June 2016 the LPSC staff provided notice of audits of Entergy Louisiana’s fuel adjustment clause filings and purchased gas adjustment clause filings. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and will also include a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includes 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. Discovery commenced in March 2017. No report of audit has been issued.

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.  Discovery commenced in September 2018.  No report of audit has been issued.


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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 November 2015, 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 a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi should file a revised fuel factor with the MPSC no later than February 1, 2016. Pursuant to that order, Entergy Mississippi submitted a revised fuel factor. Additionally, because Entergy Mississippi’s projected over-recovery balance for the period ending January 31, 2016 was $68 million, in February 2016, Entergy Mississippi filed for another interim adjustment to the energy cost factor effective April 2016 to flow through to customers the projected over-recovery balance over a six-month period. That interim adjustment was approved by the MPSC in February 2016 effective for April 2016 bills.

In November 2016, 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 less than $2 million as of September 30, 2016. In January 2017 the MPSC approved the annual factor effective with February 2017 bills. Also 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 its order, the MPSC expressly reserved the right to review and determine the recoverability of any and all purchased power expenditures made during fiscal year 2016. The MPSC hired independent auditors to conduct an annual operations audit and a financial audit. The independent auditors issued their audit reports in December 2017. The audit reports included several recommendations for action by Entergy Mississippi but did not recommend any cost disallowances. In January 2018 the MPSC certified the audit reports to the Mississippi Legislature. In November 2017 the Public Utilities Staff separately engaged a consultant to review the outage at the Grand Gulf Nuclear Station that began in 2016. The review is currently in progress.

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. Entergy Mississippi proposed a two-tiered energy cost factor designed to promote overall rate stability throughout 2018 particularly during the summer months. 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.

Mississippi Attorney General Complaint

The Mississippi Attorney General filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution.  The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand.  Entergy believes the complaint is unfounded.  In December 2008 the defendant Entergy companies removed the Attorney General’s lawsuit to U.S. District Court in Jackson, Mississippi. In June 2010 the MPSC authorized the deferral of certain legal expenses associated with this litigation until it is resolved. As of December 31, 2018, Entergy Mississippi has a regulatory asset of $23.6 million for these deferred legal expenses. Pre-trial and settlement conferences were held in October 2018. In October 2018 the District Court rescheduled the trial to April 2019.

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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 July 2015 certain parties filed briefs in a PUCT proceeding asserting that Entergy Texas should refund to retail customers an additional $10.9 million in bandwidth remedy payments Entergy Texas received related to calendar year 2006 production costs.  In October 2015 an ALJ issued a proposal for decision recommending that the additional bandwidth remedy payments be refunded to retail customers. In January 2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a motion for rehearing of the PUCT’s decision, which the PUCT denied. In March 2016, Entergy Texas filed a complaint in Federal District Court for the Western District of Texas and a petition in the Travis County (State) District Court appealing the PUCT’s decision. The pending appeals did not stay the PUCT’s decision. In April 2016, Entergy Texas filed with the PUCT an application to refund to customers approximately $56.2 million. The refund resulted from (i) $41.8 million of fuel cost recovery over-collections through February 2016, (ii) the $10.9 million in bandwidth remedy payments, discussed above, that Entergy Texas received related to calendar year 2006 production costs, and (iii) $3.5 million in bandwidth remedy payments that Entergy Texas received related to 2006-2008 production costs. In June 2016, Entergy Texas filed an unopposed settlement agreement that added additional over-recovered fuel costs for the months of March and April 2016. The settlement resulted in a $68 million refund. The ALJ approved the refund on an interim basis and it was made to most customers over a four-month period beginning with the first billing cycle of July 2016. In July 2016 the PUCT issued an order approving the interim refund. The federal appeal of the PUCT’s January 2016 decision was heard in December 2016, and the Federal District Court granted Entergy Texas’s requested relief. In January 2017 the PUCT and an intervenor filed petitions for appeal of the Federal District Court ruling to the U.S. Court of Appeals for the Fifth Circuit. Oral argument was held before the Fifth Circuit in February 2018. In April 2018 the Fifth Circuit reversed the decision of the Federal District Court, reinstating the original PUCT decision. In October 2018, Entergy Texas filed notice of nonsuit in its appeal to the Travis County District Court regarding the PUCT’s January 2016 decision.

In July 2016, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period April 1, 2013 through March 31, 2016. During the reconciliation period, Entergy Texas incurred approximately $1.77 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 over-recovery balance of approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2016. Entergy Texas also noted, however, that the estimated $19.3 million over collection was being refunded to customers as a portion of the interim fuel refund beginning with the first billing cycle of July 2016, discussed above. Entergy Texas also requested a prudence finding for each of the fuel-related contracts and arrangements entered into or modified during the reconciliation period that have not been reviewed by the PUCT in a prior proceeding. In December 2016, Entergy Texas entered into a stipulation and settlement agreement resulting

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in a $6 million disallowance not associated with any particular issue raised and a refund of the over-recovery balance of $21 million as of November 30, 2016, to most customers beginning April 2017 through June 2017. This settlement was developed concurrently with the stipulation and settlement agreement in the 2016 transmission cost recovery factor rider amendment discussed below, and the terms and conditions in both settlements are interdependent. The fuel reconciliation settlement was approved by the PUCT in March 2017 and the refunds were made.

In June 2017, Entergy Texas filed an application for a fuel refund of approximately $30.7 million for the months of December 2016 through April 2017. For most customers, the refunds flowed through bills for the months of July 2017 through September 2017. The fuel refund was approved by the PUCT in August 2017.

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.
    
Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2015 Base Rate Filing
 
In April 2015, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing notified the APSC of Entergy Arkansas’s intent to implement a forward test year formula rate plan pursuant to Arkansas legislation passed in 2015, and requested a retail rate increase of $268.4 million, with a net increase in revenue of $167 million. The filing requested a 10.2% return on common equity. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors in the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposed a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a +/- 50 basis point band around the 9.75% allowed return on common equity. A significant portion of the rate increase is related to Entergy Arkansas’s acquisition in March 2016 of Union Power Station Power Block 2 for a base purchase price of $237 million. The settlement agreement also provided for amortization over a 10-year period of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance. In February 2016 the APSC approved the settlement with one exception that reduced the retail rate increase proposed in the settlement by $5 million. The settling parties agreed to the APSC modifications in February 2016. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. In March 2016, Entergy Arkansas made a compliance filing regarding the new rates that included an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. The interim base rate adjustment surcharge was designed to recover a total of $21.1 million over the nine-month period from April 2016 through December 2016.

2016 Formula Rate Plan Filing
    
In July 2016, Entergy Arkansas filed with the APSC its 2016 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2017 test period to be below the formula rate plan bandwidth. The filing requested a $67.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%. In October 2016, Entergy Arkansas filed with the APSC revised formula rate plan attachments with an updated request for a $54.4 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016

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a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved a settlement agreement and the $54.4 million revenue requirement increase with approximately $25 million of the $54.4 million revenue requirement subject to possible future adjustment and refund to customers with interest. The APSC requested supplemental information for some of Entergy Arkansas’s requested nuclear expenditures. In December 2016 the APSC approved Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2017. In April 2017, Entergy Arkansas filed a motion consented to by all parties requesting that it be permitted to submit the supplemental information requested by the APSC in conjunction with its 2017 formula rate plan filing, which was subsequently made in July 2017 and is discussed below. In May 2017 the APSC approved the joint motion and proposal to review Entergy Arkansas’s supplemental information on a concurrent schedule with the 2017 formula rate plan filing. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and recovery of the 2017 and 2018 nuclear costs.

2017 Formula Rate Plan Filing

In July 2017, Entergy Arkansas filed with the APSC its 2017 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2018 test period to be below the formula rate plan bandwidth.  The filing projected a $129.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%.  Entergy Arkansas’s formula rate plan is subject to a four percent annual revenue constraint and the projected annual revenue requirement increase exceeded the four percent, resulting in a proposed increase for the 2017 formula rate plan of $70.9 million. In October 2017, Entergy Arkansas filed with the APSC revised formula rate plan attachments that projected a $126.2 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors. The revised formula rate plan filing included a proposed $71.1 million revenue requirement increase based on a revision to the four percent constraint calculation. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and the $71.1 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2018.
 
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 shows 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 includes 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 includes 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 exceeds the constraint, the resulting increase is 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, which included additional actual revenues for 2018. 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 certain 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. An additional schedule was issued by the APSC for briefing other contested issues, the outcome of which did not affect the 2018 filing but could affect future Entergy Arkansas formula rate plan filings. That briefing was completed in February 2019, and the APSC has not indicated when a decision on those issues can be expected.

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Similar to the 2018 filing, the formula rate plan filing that will be made in 2019 to set the formula rates for the 2020 calendar year will include a netting adjustment that will compare projected costs and sales for 2018 that were approved in the 2017 formula rate plan filing to actual 2018 costs and sales data. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflects the estimate of the historical year netting adjustment that will be included in the 2019 filing to reflect the change in formula rate plan revenues associated with actual 2018 results when compared to the allowed rate of return on equity. 

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. Entergy Arkansas also filed a notice with the Missouri Public Service Commission in December 2017 out of an abundance of caution, although Entergy Arkansas does not serve any retail customers in Missouri. In April 2018 the Missouri Public Service Commission approved Entergy Arkansas’s filing. 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.
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Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
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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

2015 Formula Rate Plan Filing

In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflected an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue was required. The following other adjustments, however, were required under the formula rate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of

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$0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and an increase of $11 million to the MISO cost recovery mechanism. Rates were implemented with the first billing cycle of September 2016, subject to refund. Following implementation of the as-filed rates in September 2016, there were several interim updates to Entergy Louisiana’s formula rate plan, including the one submitted in December 2016, reflecting implementation of the settlement of the Waterford 3 replacement steam generator project prudence review described below. In June 2017 the LPSC staff and Entergy Louisiana filed a joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of the May 2016 evaluation report, interim updates, and corresponding proceedings with no changes to rates already implemented.

2016 Formula Rate Plan Filing

In May 2017, Entergy Louisiana filed its formula rate plan evaluation report for its 2016 calendar year operations. The evaluation report reflected an earned return on common equity of 9.84%. As such, no adjustment to base formula rate plan revenue was required. Adjustments, however, were required under the formula rate plan; the 2016 formula rate plan evaluation report showed a decrease in formula rate plan revenue of approximately $16.9 million, comprised of a decrease in legacy Entergy Louisiana formula rate plan revenue of $3.5 million, a decrease in legacy Entergy Gulf States Louisiana formula rate plan revenue of $9.7 million, and a decrease in incremental formula rate plan revenue of $3.7 million. Additionally, the formula rate plan evaluation report called for a decrease of $40.5 million in the MISO cost recovery revenue requirement from $46.8 million to $6.3 million. Rates reflecting these adjustments were implemented with the first billing cycle of September 2017, subject to refund. In September 2017 the LPSC issued its report indicating that no changes to Entergy Louisiana’s original formula rate plan evaluation report were required but reserved for several issues, including Entergy Louisiana’s September 2017 update to its formula rate plan evaluation report.  In July 2018, Entergy Louisiana and the LPSC staff filed an unopposed joint report setting forth a correction to the annualization calculation, the effect of which was a net $3.5 million revenue requirement reduction and indicating that there are no outstanding issues with the 2016 formula rate plan report, the supplemental report, or the interim updates.  In September 2018 the LPSC approved the unopposed joint report.

Formula Rate Plan Extension Through 2019 Test Year

In August 2017, Entergy Louisiana filed a request with the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications of its terms.  Those modifications include: a one-time resetting of base rates to the midpoint of the band at Entergy Louisiana’s authorized return on equity of 9.95% for the 2017 test year; narrowing of the formula rate plan bandwidth from a total of 160 basis points to 80 basis points; and a forward-looking mechanism that would allow Entergy Louisiana to recover certain transmission-related costs contemporaneously with when those projects begin delivering benefits to customers.  In April 2018 the LPSC approved an unopposed joint motion filed by Entergy Louisiana and the LPSC staff that settled the matter. The settlement extended the formula rate plan for three years, providing for rates through at least August 2021. In addition to retaining the major features of the traditional formula rate plan, substantive features of the extended formula rate plan include:

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a mid-point reset of formula rate plan revenues to a 9.95% earned return on common equity for the 2017 test year and for the St. Charles Power Station when it enters commercial operation;
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a 9.8% target earned return on common equity for the 2018 and 2019 test years;
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narrowing of the common equity bandwidth to plus or minus 60 basis points around the target earned return on common equity;
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a cap on potential revenue increase of $35 million for the 2018 evaluation period, and $70 million for the cumulative 2018 and 2019 evaluation periods, on formula rate plan cost of service rate increases (the cap excludes rate changes associated with the transmission recovery mechanism described below and rate changes associated with additional capacity);
•
a framework for the flow back of certain tax benefits created by the Tax Act to customers, as described in “Regulatory activity regarding the Tax Cuts and Jobs Act” above; and

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•
a transmission recovery mechanism providing for the opportunity to recover certain transmission-related expenditures in excess of $100 million annually for projects placed in service up to one month prior to rate change outside of sharing that is designed to operate in a fashion similar to the additional capacity mechanism.
 
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 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.

Waterford 3 Replacement Steam Generator Project

Following the completion of the Waterford 3 replacement steam generator project, the LPSC undertook a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs. In July 2014 the LPSC staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana.  An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent.  Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. Entergy Louisiana believed that the replacement steam generator costs were prudently incurred and applicable legal principles supported their recovery in rates.  Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the

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incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation had not yet been considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy Louisiana recorded in the fourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to reflect that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery. Entergy Louisiana maintained that the ALJ’s recommendation contained significant factual and legal errors.

In October 2016 the parties reached a settlement in this matter. The settlement was approved by the LPSC in December 2016. The settlement effectively provided for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The refund to customers of approximately $71 million as a result of the settlement approved by the LPSC was made to customers in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016 related to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provided that Entergy Louisiana could retain the value associated with potential service credits agreed to by the project contractor, to the extent they are realized in the future. Following a review by the parties, an unopposed joint report of proceedings was filed by the LPSC staff and Entergy Louisiana in May 2017 and the LPSC accepted the joint report of proceedings resolving the matter.

Union Power Station and Deactivation or Retirement Decisions for Entergy Louisiana Plants

In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of Union Power Station for an aggregate purchase price of approximately $475 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.

As a term of the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station, Entergy Louisiana agreed to make a filing with the LPSC to review its decisions to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to retire Little Gypsy 1.  In January 2016, Entergy Louisiana made its compliance filing with the LPSC. Entergy Louisiana, LPSC staff, and intervenors participated in a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisions for these four units in addition to information on the current deactivation decisions for the ten-year planning horizon. Parties requested further proceedings on the prudence of the decision to deactivate Willow Glen 2 and 4.  No party contested the prudence of the decision to deactivate Willow Glen 2 and 4 or suggested reactivation of these units; however, issues were raised related to Entergy Louisiana’s decision to give up its transmission service rights in MISO for Willow Glen 2 and 4 rather than placing the units into suspended status for the three-year term permitted by MISO. In March 2018 the LPSC adopted the ALJ’s recommended order finding that Entergy Louisiana did not demonstrate that its decision to permanently surrender transmission rights for the mothballed (not retired) Willow Glen 2 and 4 units was reasonable and that Entergy Louisiana should hold customers harmless from increased transmission expenses should those units be reactivated. Because no party or the LPSC suggested that Willow Glen 2 and 4 should be reactivated and because the cost to return those units to service far exceeded the revenue the units were expected to generate in MISO, Entergy Louisiana retired Willow Glen 2 and 4 in March 2018. Entergy Louisiana submitted a compliance filing regarding retirement of Willow Glen 2 and 4, and the LPSC closed the proceeding.

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Retail Rates - Gas 

2016 Rate Stabilization Plan Filing

In January 2017, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2016. The filing of the evaluation report for test year 2016 reflected an earned return on common equity of 6.37%. In April 2017 the LPSC approved a joint report of proceedings and Entergy Louisiana submitted a revised evaluation report reflecting a $1.2 million annual increase in revenue with rates implemented with the first billing cycle of May 2017.
    
2017 Rate Stabilization Plan Filing

In January 2018, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2017.  The filing of the evaluation report for the test year 2017 reflected an earned return on common equity of 9.06%.  This earned return is below the earnings sharing band of the rate stabilization plan and results in a rate increase of $0.1 million.  Due to the enactment in late-December 2017 of the Tax Cuts and Jobs Act, Entergy Louisiana did not have adequate time to reflect the effects of this tax legislation in the rate stabilization plan.  In April 2018, Entergy Louisiana filed a supplemental evaluation report for the test year ended September 2017, reflecting the effects of the Tax Act, including a proposal to use the unprotected excess accumulated deferred income taxes to offset approximately $1.4 million of storm restoration deferred operation and maintenance costs incurred by Entergy Louisiana in connection with the August 2016 flooding disaster in its gas service area. The supplemental filing reflects an earned return on common equity of 10.79%. As-filed rates from the supplemental filing were implemented, subject to refund, with customers receiving a cost reduction of approximately $0.7 million effective with bills rendered on and after the first billing cycle of May 2018, as well as a $0.2 million reduction in the gas infrastructure rider effective with bills rendered on and after the first billing cycle of July 2018. The proceeding is currently in its discovery phase. A procedural schedule has not been established.

2018 Rate Stabilization Plan Filing

In January 2019, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2018. The filing of the evaluation report for the test year 2018 reflected an earned return on common equity of 2.69%. This earned return is below the earning sharing band of the gas rate stabilization plan and results in a rate increase of $2.8 million. Entergy Louisiana will make a compliance filing in April 2019 and rates will be implemented during the first billing cycle of May 2019.

Filings with the MPSC (Entergy Mississippi)

Formula Rate Plan Filings

In March 2016, Entergy Mississippi submitted its formula rate plan 2016 test year filing showing Entergy Mississippi’s projected earned return for the 2016 calendar year to be below the formula rate plan bandwidth. The filing showed a $32.6 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 9.96%, within the formula rate plan bandwidth. In June 2016 the MPSC approved Entergy Mississippi’s joint stipulation with the Mississippi Public Utilities Staff. The joint stipulation provided for a total revenue increase of $23.7 million. The revenue increase included a $19.4 million increase through the formula rate plan, resulting in a return on common equity point of adjustment of 10.07%. The revenue increase also included $4.3 million in incremental ad valorem tax expenses to be collected through an updated ad valorem tax adjustment rider. The revenue increase and ad valorem tax adjustment rider were effective with the July 2016 bills.

In March 2017, Entergy Mississippi submitted its formula rate plan 2017 test year filing and 2016 look-back filing showing Entergy Mississippi’s earned return for the historical 2016 calendar year and projected earned return

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for the 2017 calendar year to be within the formula rate plan bandwidth, resulting in no change in rates. In June 2017, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a stipulation that confirmed that Entergy Mississippi’s earned returns for both the 2016 look-back filing and 2017 test year were within the respective formula rate plan bandwidths. In June 2017 the MPSC approved the stipulation, which resulted in no change in rates.

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.

Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the performance-adjusted allowed return on rate base.  In fourth quarter 2018, Entergy Mississippi recorded a provision of $9.3 million that reflects the estimate of the difference between the 2018 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 October 2018, 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 non-fuel annual ownership costs of the Choctaw Generating Station, as well as to allow similar cost recovery treatment for other future capacity additions, such as the Sunflower Solar Facility, that are approved by the MPSC.

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.
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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.

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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

As a provision of the settlement agreement approved by the City Council in May 2015 providing for the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the provision of service to Entergy Louisiana’s customers in Algiers, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions included continued implementation of the then-remaining two years of the four-year phased-in rate increase for the Algiers area and certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of the settlement agreement allowed for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorized Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.

In addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy from Ninemile 6 (Ninemile PPA), which commenced operation in December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed only to Entergy New Orleans customers outside of Algiers.

In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the purchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the terms of the purchased power and capacity acquisition cost recovery rider to recover the non-fuel purchased power expense from Ninemile 6, the revenue requirement associated with the purchase of Power Block 1 of the Union Power Station, and a credit to customers of $400 thousand monthly beginning June 2016 in recognition of the decrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.

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

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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 (estimated to be August 2019). 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. Entergy New Orleans is seeking approval of a permanent and stable source of funding for Energy Smart as part of its base rate case filed in September 2018.

In September 2018, Entergy New Orleans filed an electric and gas base rate case with the City Council. The filing requests 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 requests 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 includes a proposed gas rate decrease of $142 thousand. Entergy New Orleans’s rates reflect 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 ending 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’s request for a change in rates is based on the projected twelve months ending December 31, 2018.

The filing’s major provisions include: (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 have recommended, among other things, overall rate reductions of approximately $33 million in electric rates and $3.8 million in gas rates. Certain intervenors have recommended overall rate reductions of up to approximately $49 million in electric rates and $5 million in gas rates. The procedural schedule calls for an evidentiary hearing to be held in June 2019.


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Internal Restructuring

In July 2016, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy New Orleans, Inc. to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. In May 2017 the City Council adopted a resolution approving the proposed internal restructuring pursuant to an agreement in principle with the City Council advisors and certain intervenors. Pursuant to the agreement in principle, Entergy New Orleans would credit retail customers $10 million in 2017, $1.4 million in the first quarter of the year after the transaction closes, and $117,500 each month in the second year after the transaction closes until such time as new base rates go into effect as a result of the then-anticipated 2018 base rate case (which has subsequently been filed). Entergy New Orleans began crediting retail customers in June 2017. In June 2017 the FERC approved the transaction and, pursuant to the agreement in principle, Entergy New Orleans will provide additional credits to retail customers of $5 million in each of the years 2018, 2019, and 2020.

In November 2017, Entergy New Orleans 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.

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 electricity 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), 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

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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.

Distribution Cost Recovery Factor (DCRF) Rider

In June 2017, Entergy Texas filed an application to amend its DCRF rider by increasing the total collection from $8.65 million to approximately $19 million. In July 2017, Entergy Texas, the PUCT staff, and the two other parties in the proceeding entered into an unopposed stipulation and settlement agreement resulting in an amended DCRF annual revenue requirement of $18.3 million. In September 2017 the PUCT issued its final order approving the unopposed stipulation and settlement agreement. The amended DCRF rider rates became effective for usage on and after September 1, 2017. DCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the discussion of the 2018 base rate case.
    
Transmission Cost Recovery Factor (TCRF) Rider

In September 2015, Entergy Texas filed for a TCRF rider requesting a $13 million increase, incremental to base rates. Testimony was filed in November 2015, with the PUCT staff and other parties proposing various disallowances involving, among other things, MISO charges, vegetation management costs, and bad debt expenses that would reduce the requested increase by approximately $2 million. In addition to those recommended disallowances, a number of parties recommended that Entergy Texas’s request be reduced by an additional $3.4 million to account for load growth since base rates were last set. In February 2016 a State Office of Administrative Hearings ALJ issued a proposal for decision recommending that the PUCT disallow approximately $2 million from Entergy Texas’s $13 million request, but recommending that the PUCT not accept the load growth offset. In June 2016 the PUCT indicated that it would take up in a future rulemaking project the issue of whether a load growth adjustment should apply to a TCRF. In July 2016 the PUCT issued an order generally accepting the proposal for decision but declining to adjust the TCRF baseline in two instances as recommended by the ALJ, which resulted in a total annual allowance of approximately $10.5 million. The PUCT also ordered its staff and Entergy Texas to track all spare autotransformer transfers going forward so that it could address the appropriate accounting treatment and prudence of such transfers in Entergy Texas’s next base rate case. Entergy Texas implemented the TCRF rider beginning with September 2016 bills.

In September 2016, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed amended TCRF rider was designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount included the approximately $10.5 million annually that Entergy Texas was previously authorized to collect through the TCRF rider, as discussed above. In December 2016, concurrent with the 2016 fuel reconciliation stipulation and settlement agreement discussed above, Entergy Texas and the PUCT staff reached a settlement agreeing to the amended TCRF annual revenue requirement of $29.5 million. As discussed above, the terms of the two settlements are interdependent. The PUCT approved the settlement and issued a final order in March 2017. Entergy Texas implemented the amended TCRF rider beginning with bills covering usage on and after March 20, 2017. TCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the 2018 base rate case discussion.


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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. The proceeding is currently ongoing at the PUCT.

Advanced Metering Infrastructure (AMI) Filings

Entergy Arkansas

In September 2016, Entergy Arkansas filed an application seeking a finding from the APSC that Entergy Arkansas’s deployment of AMI is in the public interest. Entergy Arkansas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Arkansas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $208 million. The filing identified a number of quantified and unquantified benefits, and Entergy Arkansas provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal net benefit to customers of $406 million. Entergy Arkansas also sought to continue to include in rate base the remaining book value of existing meters, which was approximately $57 million at December 31, 2015, that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Arkansas proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Deployment of the communications network began in 2018. Entergy Arkansas proposed to include the AMI deployment costs and the quantified benefits in future formula rate plan filings, and the 2018 costs were approved in the 2017 formula rate plan filing. In August 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement. In October 2017 the APSC issued an order finding that Entergy Arkansas’s AMI deployment is in the public interest and approving the settlement agreement subject to a minor modification. Entergy Arkansas expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized over 15 years.

Entergy Louisiana

In November 2016, Entergy Louisiana filed an application seeking a finding from the LPSC that Entergy Louisiana’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy Louisiana proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing included an estimate of implementation costs for AMI of $330 million. The filing identified a number of quantified and unquantified benefits, and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate base the remaining book value, approximately $92 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for the new advanced meters, the three-year deployment of which began in 2019. Deployment of the communications network began in 2018. Entergy Louisiana proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. The parties reached an uncontested stipulation permitting implementation of Entergy Louisiana’s proposed AMI system, with modifications to the proposed customer charge. In July 2017 the LPSC approved the stipulation. Entergy Louisiana expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized at current depreciation rates.

Entergy Mississippi

In November 2016, Entergy Mississippi filed an application seeking an order from the MPSC granting a certificate of public convenience and necessity and finding that Entergy Mississippi’s deployment of AMI is in the public interest. Entergy Mississippi proposed to replace existing meters with advanced meters that enable two-way data communication; to design and build a secure and reliable network to support such communications; and to

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implement support systems. AMI is intended to serve as the foundation of Entergy Mississippi’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, and Entergy Mississippi provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal benefit to customers of $496 million over a 15-year period, which when netted against the costs of AMI results in $183 million of net customer benefits. Entergy Mississippi also sought to continue to include in rate base the remaining book value, approximately $56 million at December 31, 2015, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019, subject to approval by the MPSC. Deployment of the communications network began in 2018. Entergy Mississippi proposed to include the AMI deployment costs and the quantified benefits in existing rate mechanisms, primarily through future formula rate plan filings and/or future energy cost recovery rider schedule re-determinations, as applicable. In May 2017 the Mississippi Public Utilities Staff and Entergy Mississippi entered into and filed a joint stipulation supporting Entergy Mississippi’s filing, and the MPSC issued an order approving the filing without material changes, finding that Entergy Mississippi’s deployment of AMI is in the public interest and granting a certificate of public convenience and necessity. The MPSC order also confirmed that Entergy Mississippi shall continue to include in rate base the remaining book value of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. In June 2018, as part of the order approving the joint stipulation between the Mississippi Public Utilities Staff and Entergy Mississippi addressing Entergy Mississippi’s 2018 formula rate plan evaluation report and the ratemaking effects of the Tax Act, the MPSC approved the acceleration of the recovery of substantially all of Entergy Mississippi’s existing customer meters in anticipation of AMI deployment.
 
Entergy New Orleans

In October 2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest.  Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems.  AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid.  The filing included an estimate of implementation costs for AMI of $75 million. The filing identified a number of quantified and unquantified benefits, and Entergy New Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million.  Entergy New Orleans also sought to continue to include in rate base the remaining book value, approximately $21 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates.  Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which began in 2019.  Deployment of the information technology infrastructure began in 2017 and deployment of the communications network began in 2018.  Entergy New Orleans proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022.  The City Council’s advisors filed testimony in May 2017 recommending the adoption of AMI subject to certain modifications, including the denial of Entergy New Orleans’s proposed customer charge as a cost recovery mechanism. In January 2018 a settlement was reached between the City Council’s advisors and Entergy New Orleans. In February 2018 the City Council approved the settlement, which deferred cost recovery to the 2018 Entergy New Orleans rate case, but also stated that an adjustment for 2018-2019 AMI costs can be filed in the rate case and that, for all subsequent AMI costs, the mechanism to be approved in the 2018 rate case will allow for the timely recovery of such costs. In April 2018 the City Council adopted a resolution directing Entergy New Orleans to explore the options for accelerating the deployment of AMI. In June 2018 the City Council approved a one-year acceleration of AMI in its service area for an incremental $4.4 million.

Entergy Texas

In April 2017 the Texas legislature enacted legislation that extends statutory support for AMI deployment to Entergy Texas and directs that if Entergy Texas elects to deploy AMI, it shall do so as rapidly as practicable. In July 2017, Entergy Texas filed an application seeking an order from the PUCT approving Entergy Texas’s deployment of

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AMI. Entergy Texas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Texas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, with Entergy Texas showing that its AMI deployment is expected to produce nominal net operational cost savings to customers of $33 million. Entergy Texas also sought to continue to include in rate base the remaining book value, approximately $41 million at December 31, 2016, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Texas proposed a seven-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Entergy Texas also proposed a surcharge tariff to recover the reasonable and necessary costs it has and will incur under the deployment plan for the full deployment of advanced meters. Further, Entergy Texas sought approval of fees that would be charged to customers who choose to opt out of receiving service through an advanced meter and instead receive electric service with a non-standard meter. In October 2017, Entergy Texas and other parties entered into and filed an unopposed stipulation and settlement agreement, permitting deployment of AMI with limited modifications. The PUCT approved the stipulation and settlement agreement in December 2017. Entergy Texas implemented the AMI surcharge tariff beginning with January 2018 bills. As of December 31, 2018, Entergy Texas has a regulatory liability related to the collection of the surcharge from customers. Consistent with the approval, deployment of the communications network began in 2018 and deployment of the advanced meters will begin in March 2019. Entergy Texas expects to recover the remaining net book value of its existing meters through a regulatory asset to be amortized at current depreciation rates.

System Agreement Cost Equalization Proceedings

Prior to its final termination in 2016, the Utility operating companies historically engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement.  Entergy Arkansas terminated its participation in the System Agreement in December 2013. Entergy Mississippi terminated its participation in the System Agreement in November 2015. The System Agreement terminated with respect to its remaining participants in August 2016.

Although the System Agreement has terminated, certain of the Utility operating companies’ retail regulators continue to pursue 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.

In June 2005 the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing.  The decision included, among other things:

•
The FERC’s conclusion that the System Agreement no longer roughly equalized total production costs among the Utility operating companies.
•
In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs would have to be within +/- 11% of Entergy System average total annual production costs.
•
In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant would not reflect the actual Vidalia price for the year but be priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs.
•
The remedy ordered by the FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs with the first reallocation payments made in 2007.

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bandwidth.  This was accomplished by payments from Utility operating companies whose production costs were more than 11% below Entergy System average production costs to Utility operating companies whose production costs were more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs were farthest above the Entergy System average.

The LPSC, APSC, MPSC, and the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit.  Entergy and the City of New Orleans intervened in the various appeals.  The D.C. Circuit issued its decision in April 2008.  The D.C. Circuit concluded that the FERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005.  The D.C. Circuit remanded the case to the FERC for further proceedings on those two issues.

In October 2011 the FERC issued an order addressing the D.C. Circuit remand on the two issues.  On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003.  Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that this refund ruling will be held in abeyance pending the outcome of the rehearing requests in the interruptible load proceeding.  On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered.  Pursuant to the October 2011 order, Entergy was required to calculate bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and accepted by the FERC in an April 2007 order.  

In March 2015, in light of a December 2014 decision by the D.C. Circuit in the interruptible load proceeding, Entergy filed with the FERC a motion to establish a briefing schedule on refund issues and an initial brief addressing refund issues. The initial brief argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in this proceeding. In October 2015 the FERC issued three orders related to the commencement of the remedy on June 1, 2005 and the inclusion of interest for the period June 1, 2005 through December 31, 2005. Specifically, the FERC rejected Entergy’s request for rehearing of its decision to include interest for the seven-month period. The FERC also rejected Entergy’s request for rehearing of the order rejecting the compliance filing with regard to the issue of interest. Finally, the FERC set for hearing and settlement procedures the 2014 compliance filing that included the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005. In setting the compliance filing for hearing, the FERC rejected the APSC’s protest that Entergy Arkansas should not be subject to the filing because Entergy Arkansas would be making the payments during a period following its exit from the System Agreement. In January 2018 the D.C. Circuit affirmed the FERC decision that Entergy Arkansas was subject to the filing.

In December 2011, Entergy filed with the FERC its compliance filing that provided the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order.  The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests. The filing showed the following payments/receipts among the Utility operating companies:

 
Payments (Receipts)
 
(In Millions)
Entergy Arkansas
$156
Entergy Louisiana
($75)
Entergy Mississippi
($33)
Entergy New Orleans
($5)
Entergy Texas
($43)

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Entergy Arkansas made its payment in January 2012.  In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million be collected from customers over the 22-month period from March 2012 through December 2013.  In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund.  The LPSC and the APSC requested rehearing of the FERC’s October 2011 order.  

In February 2014 the FERC issued a rehearing order addressing its October 2011 order. The FERC denied the LPSC’s request for rehearing on the issues of whether the bandwidth remedy should be made effective earlier than June 1, 2005, and whether refunds should be ordered for the 20-month refund effective period. The FERC granted the LPSC’s rehearing request on the issue of interest on the bandwidth payments/receipts for the June - December 2005 period, requiring that interest be accrued from June 1, 2006 until the date those bandwidth payments/receipts are made. Also in February 2014 the FERC issued an order rejecting the December 2011 compliance filing that calculated the bandwidth payments/receipts for the June - December 2005 period. The FERC order required a new compliance filing that calculates the bandwidth payments/receipts for the June - December 2005 period based on monthly data for the seven individual months including interest pursuant to the February 2014 rehearing order. Entergy sought rehearing of the February 2014 order with respect to the FERC’s determinations regarding interest. In April 2014 the LPSC filed a petition for review of the FERC’s October 2011 and February 2014 orders with the U.S. Court of Appeals for the D.C. Circuit. In August 2017 the D.C. Circuit issued a decision denying the LPSC’s appeal of the FERC’s October 2011 and February 2014 orders. On the issue of the FERC’s implementation of the prospective remedy as of June 2005 and whether the bandwidth remedy should be extended for an additional 17 months in years 2004-2005, the D.C. Circuit affirmed the FERC’s implementation of the remedy and denied the LPSC’s appeal. On the issue of whether the operating companies should be required to issue refunds for the 20-month period from September 2001 to May 2003, the D.C. Circuit granted the FERC’s request for agency reconsideration and remanded that issue back to the FERC for further proceedings as requested by all parties to the appeal. In response to the D.C. Circuit’s remand, various parties filed briefs with the FERC addressing whether the FERC should require the Utility operating companies to issue refunds for the 20-month refund period from September 2001 to May 2003. The LPSC has argued in favor of such remands and Entergy has opposed the LPSC’s request. The briefing was completed in September 2018 and the matter is pending before the FERC.

In April and May 2014, Entergy filed with the FERC an updated compliance filing that provided the payments and receipts among the Utility operating companies pursuant to the FERC’s February 2014 orders.  The filing showed the following net payments and receipts, including interest, among the Utility operating companies:
 
Payments (Receipts)
 
(In Millions)
Entergy Arkansas
$68
Entergy Louisiana
($10)
Entergy Mississippi
($11)
Entergy New Orleans
$2
Entergy Texas
($49)

These payments were made in May 2014. The LPSC, City Council, and APSC filed protests.

The hearing on the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005 occurred in July 2016. The presiding judge issued an initial decision in November 2016. In the initial decision, the presiding judge agreed with the Utility operating companies’ position that: (1) interest on the bandwidth payments for the 2005 test period should be accrued from June 1, 2006 until the date that the bandwidth payments for that calculation are paid, which is consistent with how the Utility operating companies performed the calculation; and (2) a portion of Entergy Louisiana’s 2001-vintage Louisiana state net operating loss accumulated deferred income tax that results from

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the Vidalia tax deduction should be excluded from the 2005 test period bandwidth calculation. Various participants filed briefs on exceptions and/or briefs opposing exceptions related to the initial decision, including the LPSC, the APSC, the FERC trial staff, and Entergy Services. In May 2018 the FERC issued an order affirming the initial decision and ordered a comprehensive recalculation of the bandwidth payments/receipts for the seven months June 1, 2005 through December 31, 2005 and a recalculation of the 2006 and 2007 test years as a result of limited revisions. Entergy filed the comprehensive recalculation of the bandwidth payments/receipts for the seven months June 1, 2005 through December 31, 2005 and the 2006 and 2007 test years in July 2018. The filing shows the additional following payments and receipts among the Utility operating companies:
 
Payments (Receipts)
 
(In Millions)
Entergy Arkansas
($4)
Entergy Louisiana
($23)
Entergy Mississippi
$16
Entergy New Orleans
$5
Entergy Texas
$6

These payments were made in July 2018. In January 2019 the FERC denied the LPSC’s request for rehearing of the May 2018 order.

Rough Production Cost Equalization Rates

Each May from 2007 through 2016 Entergy filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding.  These filings showed the following payments/receipts among the Utility operating companies were necessary to achieve rough production cost equalization as defined by the FERC’s orders:
 
Payments (Receipts)
 
2007
 
2008
 
2009
 
2010
 
2011
 
2012
 
2013
 
2014
 
(In Millions)
Entergy Arkansas

$252

 

$252

 

$390

 

$41

 

$77

 

$41

 

$—

 

$—

Entergy Louisiana

($211
)
 

($160
)
 

($247
)
 

($22
)
 

($12
)
 

($41
)
 

$—

 

$—

Entergy Mississippi

($41
)
 

($20
)
 

($24
)
 

($19
)
 

($40
)
 

$—

 

$—

 

$—

Entergy New Orleans

$—

 

($7
)
 

$—

 

$—

 

($25
)
 

$—

 

($15
)
 

($15
)
Entergy Texas

($30
)
 

($65
)
 

($119
)
 

$—

 

$—

 

$—

 

$15

 

$15


The Utility operating companies recorded accounts payable or accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy.  When accounts payable were recorded, a corresponding regulatory asset was recorded for the right to collect the payments from customers. When accounts receivable were recorded, a corresponding regulatory liability was recorded for the obligations to pass the receipts on to customers.  No payments were required in 2016 or 2015 to implement the FERC’s remedy based on calendar year 2015 production costs and 2014 production costs, respectively. The System Agreement terminated in August 2016.

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas.  Entergy Texas recovered its 2013 rough production cost equalization payment over three years beginning April 2014. Entergy Texas included its 2014 rough production cost equalization payment as a component of an interim fuel refund made in 2014. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs.


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The following rough production cost equalization rate proceedings are still ongoing or were ongoing during the period 2016-2018.

2010 Rate Filing Based on Calendar Year 2009 Production Costs

In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010.  Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which also filed protests.  In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund.  After an abeyance of the proceeding schedule, a hearing was held in March 2014 and in December 2015 the FERC issued an order. Among other things, the December 2015 order directed Entergy to submit a compliance filing. In January 2016 the LPSC, the APSC, and Entergy filed requests for rehearing of the FERC’s December 2015 order. In February 2016, Entergy submitted the compliance filing ordered in the December 2015 order.  The result of the true-up payments and receipts for the recalculation of production costs resulted in the following payments/receipts among the Utility operating companies:
 
Payments (Receipts)
 
(In Millions)
Entergy Arkansas
$2
Entergy Louisiana
$6
Entergy Mississippi
($4)
Entergy New Orleans
($1)
Entergy Texas
($3)
 
In September 2016 the FERC accepted the February 2016 compliance filing subject to a further compliance filing made in November 2016. The further compliance filing was required as a result of an order issued in September 2016 ruling on the January 2016 rehearing requests filed by the LPSC, the APSC, and Entergy. In the order addressing the rehearing requests, the FERC granted the LPSC’s rehearing request and directed that interest be calculated on the payment/receipt amounts. The FERC also granted the APSC’s and Entergy’s rehearing request and ordered the removal of both securitized asset accumulated deferred income taxes and contra-securitization accumulated deferred income taxes from the calculation. In November 2016, Entergy submitted its compliance filing in response to the FERC’s order on rehearing. The compliance filing included a revised calculation of the bandwidth true-up payments and receipts based on 2009 test year data and interest calculations. The LPSC protested the interest calculations. In November 2017 the FERC issued an order rejecting the November 2016 compliance filing. The FERC determined that the payments detailed in the November 2016 compliance filing did not include adequate interest for the payments from Entergy Arkansas to Entergy Louisiana because it did not include interest on the principal portion of the payment that was made in February 2016. In December 2017, Entergy recalculated the interest pursuant to the November 2017 order. As a result of the recalculations, Entergy Arkansas owed very minor payments to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.


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2011 Rate Filing Based on Calendar Year 2010 Production Costs

In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding.  Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest.  In July 2011 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2011, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2011 rate filing with the 2012, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2012 Rate Filing Based on Calendar Year 2011 Production Costs

In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding.  Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest.  In August 2012 the FERC accepted Entergy’s proposed rates for filing, effective June 2012, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2012 rate filing with the 2011, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2013 Rate Filing Based on Calendar Year 2012 Production Costs

In May 2013, Entergy filed with the FERC the 2013 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments related to including the outcome of a related FERC proceeding in the 2013 cost equalization calculation. In August 2013 the FERC issued an order accepting the 2013 rates, effective June 1, 2013, subject to refund. After an abeyance of the proceeding schedule, in December 2014 the FERC consolidated the 2013 rate filing with the 2011, 2012, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2014 Rate Filing Based on Calendar Year 2013 Production Costs

In May 2014, Entergy filed with the FERC the 2014 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments. In December 2014 the FERC issued an order accepting the 2014 rates, effective June 1, 2014, subject to refund, set the proceeding for hearing procedures, and consolidated the 2014 rate filing with the 2011, 2012, and 2013 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

Consolidated 2011, 2012, 2013, and 2014 Rate Filing Proceedings

As discussed above, in December 2014 the FERC consolidated the 2011, 2012, 2013, and 2014 rate filings for settlement and hearing procedures. In May 2015, Entergy filed direct testimony in the consolidated rate filings and the LPSC filed direct testimony concerning its complaint proceeding that is consolidated with the rate filings, challenging certain components of the pending bandwidth calculations for prior years. Hearings occurred in November 2015, and the ALJ issued an initial decision in July 2016. In the initial decision, the ALJ generally agreed with Entergy’s bandwidth calculations with one exception on the accounting related to the Waterford 3 sale/leaseback. In March 2018 the FERC issued an order affirming the initial decision. In April 2018 the LPSC requested rehearing of the FERC’s March 2018 order affirming the ALJ’s initial decision. Entergy filed in May 2018 the bandwidth true-up payments and receipts for the 2011-2014 rate filings (table does not net to zero due to rounding):

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Payments (Receipts)
 
(In Millions)
Entergy Arkansas
$3
Entergy Louisiana
$3
Entergy Mississippi
($1)
Entergy New Orleans
$1
Entergy Texas
($5)

These payments were made in May 2018. The LPSC request for rehearing is pending.

Utility Operating Company Termination of System Agreement Participation

Entergy Arkansas and Entergy Mississippi ceased participating in the System Agreement effective December 18, 2013 and November 7, 2015, respectively. Entergy Louisiana, Entergy New Orleans, and Entergy Texas terminated participation in the System Agreement on August 31, 2016, which resulted in the termination of the System Agreement in its entirety pursuant to a settlement agreement approved by the FERC in December 2015.

In December 2013 the FERC set one issue for hearing involving whether and how the benefits associated with settlement with Union Pacific regarding certain coal delivery issues should be allocated among Entergy Arkansas and the other Utility operating companies post-termination of the System Agreement. In December 2014 a FERC ALJ issued an initial decision finding that Entergy Arkansas would realize benefits after December 18, 2013 from the 2008 settlement agreement between Entergy Services, Entergy Arkansas, and Union Pacific, related to certain coal delivery issues. In March 2016 the FERC issued an opinion affirming the December 2014 initial decision with regard to the determination that there were benefits related to the Union Pacific settlement, which were realized post-Entergy Arkansas’s December 2013 withdrawal from the System Agreement, that should be shared with the other Utility operating companies utilizing the methodology proposed by the MPSC and trued-up to actual coal volumes purchased. In May 2016, Entergy made a compliance filing that provided the calculation of Union Pacific settlement benefits utilizing the methodology adopted by the initial decision, trued-up for the actual volumes of coal purchased. The payments were made in May 2016. In August 2016 the FERC issued an order accepting Entergy’s compliance filing. Also in August 2016 the APSC filed a petition for review of the FERC’s March 2016 and August 2016 orders with the U.S. Court of Appeals for the D.C. Circuit. In June 2018 the D.C. Circuit denied the APSC’s petition.

Interruptible Load Proceeding

In April 2007 the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads.  In its opinion the D.C. Circuit concluded that the FERC: (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time.  The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds.  The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change.  In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996.  In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC’s orders.  The LPSC filed a protest to the refund report in December 2007.  The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due refunds under the decision.  The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit.


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Following the filing of petitioners’ initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC’s decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC.  The D.C. Circuit granted the FERC’s unopposed motion in June 2009.  In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies.  In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate.  The APSC, the MPSC, and Entergy requested rehearing of the FERC’s decision.  In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds.  The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.”  The LPSC requested rehearing of the FERC’s June 2011 decision.  In July 2011 the refunds made in the fourth quarter 2008 described above were reversed. In October 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding.  Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs were due.  

In March 2013 the FERC issued an order denying the LPSC’s request for rehearing of the FERC’s June 2011 order wherein the FERC concluded it would exercise its discretion and not order refunds in the interruptible load proceeding. Based on its review of the LPSC’s request for rehearing and the briefs filed as part of the paper hearing established in October 2011, the FERC affirmed its earlier ruling and declined to order refunds under the circumstances of the case. In May 2013 the LPSC filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit seeking review of FERC orders in the interruptible load proceeding that concluded that the FERC would exercise its discretion and not order refunds in the proceeding. Oral argument was held on the appeal in the D.C. Circuit in September 2014. In December 2014 the D.C. Circuit issued an order on the LPSC’s appeal and remanded the case back to the FERC. The D.C. Circuit rejected the LPSC’s argument that there is a presumption in favor of refunds, but it held that the FERC had not adequately explained its decision to deny refunds and directed the FERC “to consider the relevant factors and weigh them against one another.” In March 2015, Entergy filed with the FERC an initial brief on remand to address the December 2014 decision by the D.C. Circuit. The initial brief on remand argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in the interruptible load proceeding.

In April 2016 the FERC issued an order on remand that addressed the December 2014 decision by the D.C. Circuit in the interruptible load proceeding. The order on remand affirmed the FERC’s denial of refunds for the 15-month refund effective period. The FERC explained and clarified its policies regarding refunds and concluded that the evidence in the record demonstrated that the relevant equitable factors favored not requiring refunds in this case. The FERC also noted that, under Section 206(c) of the Federal Power Act, in a Section 206 proceeding involving two or more electric utility companies of a registered holding company system, the FERC may order refunds only if it determines the refunds would not cause the registered holding company to experience any reduction in revenues resulting from an inability of an electric utility company in the system to recover the resulting increase in costs. The FERC stated it was not able to find that the Entergy system would not experience a reduction in revenues if refunds were awarded in this proceeding, which further supported the denial of refunds. In May 2016 the LPSC filed a request for rehearing of the FERC’s April 2016 order. In September 2016 the FERC issued an order denying the LPSC’s request for rehearing and reaffirming its denial of refunds for the 15-month refund effective period. The LPSC appealed the April and September 2016 orders to the U.S. Court of Appeals for the D.C. Circuit. In March 2018 the D.C. Circuit issued an order denying the LPSC’s appeal and affirming the FERC’s decision that it would be inequitable to award refunds in the proceeding. In April 2018 the LPSC sought rehearing en banc of the D.C. Circuit’s order denying the LPSC’s appeal. In May 2018 the D.C. Circuit denied the LPSC’s rehearing request. In August 2018 the LPSC filed with the Supreme Court of the United States a petition for a writ of certiorari to review the judgment of the D.C. Circuit. In November 2018 the Supreme Court of the United States denied the LPSC’s petition for a writ of certiorari to review the judgment of the D.C. Circuit, effectively terminating the interruptible load proceeding.

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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 addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the

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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’s 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’s appeal and held all of the appeals in abeyance pending final resolution of the related proceeding before the FERC.

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

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Complaints Against System Energy

Return on Equity 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 the FERC to institute 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. System Energy is recording a provision against revenue for the potential outcome of this proceeding. In September 2017 the FERC established a refund effective date of January 23, 2017, consolidated the return on equity complaint with the proceeding described in Unit Power Sales Agreement below, 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 effective date 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 System Energy’s return on equity, with a refund effective date of April 2018. The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and MPSC complaint for hearing. The consolidated hearing has been scheduled for September 2019, and the parties are required to address 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 complaint, and System Energy submitted a response to the amended complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings.

Grand Gulf Sale-leaseback Renewal Complaint

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

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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 2018. The hearing has been scheduled for November 2019.

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 proposed amendments would result in lower charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. The proposed changes are 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. System Energy requested that the FERC accept the amendments effective October 1, 2017.

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. The FERC also consolidated the Unit Power Sales Agreement amendment proceeding with the proceeding described in “Return on Equity Complaints” above, and directed the parties to engage in settlement proceedings before an ALJ. 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.
 

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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.  The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages.  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 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.

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

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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.

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

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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.  In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company LLC, a wholly-owned Entergy subsidiary, to a third party in exchange for $51 million plus accrued but unpaid distributions on the units.  The 500,000 preferred membership units are mandatorily redeemable in January 2112.

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 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. As of April 30, 2016, Entergy Mississippi’s storm damage provision balance was less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with November 2016 bills. As of July 31, 2017, the balance in Entergy Mississippi’s accumulated storm damage provision was again less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with September 2017 bills. As of June 30, 2018, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with August 2018 bills.
  
Entergy New Orleans

In August 2012, Hurricane Isaac caused extensive damage to Entergy New Orleans’s service area. In January 2015 the City Council issued a resolution approving the terms of a joint agreement in principle filed by Entergy New Orleans, Entergy Louisiana, and the City Council Advisors determining, among other things, that Entergy New Orleans’s prudently-incurred storm recovery costs were $49.3 million, of which $31.7 million, net of reimbursements from the storm reserve escrow account, remained recoverable from Entergy New Orleans’s electric customers. The resolution also directed Entergy New Orleans to file an application to securitize the unrecovered City Council-approved storm recovery costs of $31.7 million pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act (Louisiana Act 64). In addition, the resolution found that it was reasonable for Entergy New Orleans to include in the principal amount of its potential securitization the costs to fund and replenish Entergy New Orleans’s storm reserve in an amount that achieved the City Council-approved funding level of $75 million. In January 2015, in compliance with that directive, Entergy New Orleans filed with the City Council an application requesting that the City Council grant a financing order authorizing the financing of Entergy New Orleans’s storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 64. In May 2015 the parties entered into an agreement in principle and the City Council issued a financing order authorizing Entergy New Orleans to issue storm recovery bonds in the aggregate amount of $98.7 million, including $31.8 million for recovery of Entergy New Orleans’s Hurricane Isaac storm recovery costs, including carrying costs, $63.9 million to fund and replenish Entergy New Orleans’s storm reserve, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to the financial statements for discussion of the issuance of the securitization bonds in July 2015.


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New Nuclear Generation Development Costs

Entergy Louisiana

Entergy Louisiana and Entergy Gulf States Louisiana were developing a project option for new nuclear generation at River Bend.  In March 2010, Entergy Louisiana and Entergy Gulf States Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend.  At its June 2012 meeting the LPSC voted to uphold an ALJ recommendation that the request of Entergy Louisiana and Entergy Gulf States Louisiana be declined on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification.  The LPSC directed that Entergy Louisiana and Entergy Gulf States Louisiana be permitted to seek recovery of these costs in their upcoming rate case filings that were subsequently filed in February 2013. In the resolution of the rate case proceeding the LPSC provided for an eight-year amortization of costs incurred in connection with the potential development of new nuclear generation at River Bend, without carrying costs, beginning in December 2014, provided, however, that amortization of these costs shall not result in a future rate increase. As of December 31, 2018, Entergy Louisiana has a regulatory asset of $28.5 million on its balance sheet related to these new nuclear generation development costs.




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

Income taxes for 2018, 2017, and 2016 for Entergy Corporation and Subsidiaries consist of the following:
 
2018
 
2017
 
2016
 
(In Thousands)
Current:
 
 
 
 
 
Federal

$36,848

 

$29,595

 

$45,249

Foreign
—

 
—

 
68

State
7,274

 
15,478

 
(14,960
)
Total
44,122

 
45,073

 
30,357

Deferred and non-current - net
(1,074,416
)
 
505,010

 
(840,465
)
Investment tax credit adjustments - net
(6,532
)
 
(7,513
)
 
(7,151
)
Income taxes

($1,036,826
)
 

$542,570

 

($817,259
)
    
Income taxes for 2018, 2017, and 2016 for Entergy’s Registrant Subsidiaries consist of the following:
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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2017
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Federal
 

$16,086

 

($84,250
)
 

($8,845
)
 

($30,635
)
 

$6,034

 

$47,674

State
 
9,191

 
1,480

 
(924
)
 
(728
)
 
310

 
5,314

Total
 
25,277

 
(82,770
)
 
(9,769
)
 
(31,363
)
 
6,344

 
52,988

Deferred and non-current - net
 
69,753

 
572,988

 
83,501

 
62,946

 
43,102

 
19,243

Investment tax credit adjustments - net
 
(1,226
)
 
(4,920
)
 
187

 
1,695

 
(965
)
 
(2,262
)
Income taxes
 

$93,804

 

$485,298

 

$73,919

 

$33,278

 

$48,481

 

$69,969


2016
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Federal
 

($14,748
)
 

($124,113
)
 

$10,603

 

($91,067
)
 

$19,656

 

$29,628

State
 
2,805

 
10,757

 
2,257

 
566

 
1,374

 
(25,825
)
Total
 
(11,943
)
 
(113,356
)
 
12,860

 
(90,501
)
 
21,030

 
3,803

Deferred and non-current - net
 
120,942

 
208,157

 
46,984

 
119,345

 
42,982

 
71,051

Investment tax credit adjustments - net
 
(1,226
)
 
(5,067
)
 
4,010

 
(139
)
 
(915
)
 
(3,793
)
Income taxes
 

$107,773

 

$89,734

 

$63,854

 

$28,705

 

$63,097

 

$71,061



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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 2018, 2017, and 2016 are:
 
2018
 
2017
 
2016
 
(In Thousands)
Net income (loss) attributable to Entergy Corporation

$848,661

 

$411,612

 

($583,618
)
Preferred dividend requirements of subsidiaries
13,894

 
13,741

 
19,115

Consolidated net income (loss)
862,555

 
425,353

 
(564,503
)
Income taxes
(1,036,826
)
 
542,570

 
(817,259
)
Income (loss) before income taxes

($174,271
)
 

$967,923

 

($1,381,762
)
Computed at statutory rate (21% for 2018) (35% for 2017 and 2016)

($36,597
)
 

$338,773

 

($483,617
)
Increases (reductions) in tax resulting from:
 

 
 

 
 

State income taxes net of federal income tax effect
21,398

 
44,179

 
40,581

Regulatory differences - utility plant items
(37,507
)
 
39,825

 
33,581

Equity component of AFUDC
(27,216
)
 
(33,282
)
 
(23,647
)
Amortization of investment tax credits
(8,304
)
 
(10,204
)
 
(10,889
)
Flow-through / permanent differences
439

 
8,727

 
(19,307
)
Tax legislation enactment (a)
—

 
560,410

 
—

Amortization of excess ADIT (a)
(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
(8,404
)
 
—

 
—

Entergy Wholesale Commodities nuclear decommissioning trust restructuring (d)
(106,833
)
 
—

 
—

Entergy Wholesale Commodities restructuring (d)
—

 
(373,277
)
 
(237,760
)
Act 55 financing settlement (e)
—

 
—

 
(63,477
)
FitzPatrick disposition
—

 
(44,344
)
 
—

Provision for uncertain tax positions (e)
24,569

 
8,756

 
(67,119
)
Valuation allowance
2,211

 
—

 
11,411

Other - net
2,657

 
3,007

 
2,984

Total income taxes as reported

($1,036,826
)
 

$542,570

 

($817,259
)
Effective Income Tax Rate
595.0
%
 
56.1
%
 
59.1
%

(a)
See “Other Tax Matters - Tax Cuts and Jobs Act” below for discussion of the amortization of excess ADIT in 2018 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 settlement.
(d)
See “Other Tax Matters - Entergy Wholesale Commodities Restructuring” below for discussion of the Entergy Wholesale Commodities nuclear decommissioning trust restructuring in 2018 and the Entergy Wholesale Commodities restructuring in 2016 and 2017.
(e)
See “Income Tax Audits - 2010-2011 IRS Audit” below for discussion of the settlement and the most significant items for 2016.


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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 2018, 2017, and 2016 are:
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
 
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
)%


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Notes to Financial Statements


2017
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Net income
 

$139,844

 

$316,347

 

$110,032

 

$44,553

 

$76,173

 

$78,596

Income taxes
 
93,804

 
485,298

 
73,919

 
33,278

 
48,481

 
69,969

Pretax income
 

$233,648

 

$801,645

 

$183,951

 

$77,831

 

$124,654

 

$148,565

Computed at statutory rate (35%)
 

$81,777

 

$280,576

 

$64,383

 

$27,241

 

$43,629

 

$51,998

Increases (reductions) in tax resulting from:
 
 

 
 

 
 

 
 

 
 

 
 

State income taxes net of federal income tax effect
 
11,586

 
31,927

 
6,202

 
2,842

 
527

 
5,635

Regulatory differences - utility plant items
 
7,220

 
12,168

 
1,356

 
619

 
5,581

 
12,880

Equity component of AFUDC
 
(6,458
)
 
(18,020
)
 
(3,383
)
 
(847
)
 
(2,353
)
 
(2,221
)
Amortization of investment tax credits
 
(1,201
)
 
(4,871
)
 
(160
)
 
(124
)
 
(951
)
 
(2,896
)
Flow-through / permanent differences
 
3,098

 
3,774

 
1,567

 
(3,352
)
 
1,428

 
(276
)
Tax legislation enactment (b)
 
(3,090
)
 
217,258

 
3,492

 
6,153

 
2,981

 
(69
)
Non-taxable dividend income
 
—

 
(44,658
)
 
—

 
—

 
—

 
—

Provision for uncertain tax positions
 
200

 
5,700

 
228

 
600

 
(2,617
)
 
4,800

Other - net
 
672

 
1,444

 
234

 
146

 
256

 
118

Total income taxes as reported
 

$93,804

 

$485,298

 

$73,919

 

$33,278

 

$48,481

 

$69,969

Effective Income Tax Rate
 
40.1
%
 
60.5
%
 
40.2
%
 
42.8
%
 
38.9
%
 
47.1
%

2016
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Net income
 

$167,212

 

$622,047

 

$109,184

 

$48,849

 

$107,538

 

$96,744

Income taxes
 
107,773

 
89,734

 
63,854

 
28,705

 
63,097

 
71,061

Pretax income
 

$274,985

 

$711,781

 

$173,038

 

$77,554

 

$170,635

 

$167,805

Computed at statutory rate (35%)
 

$96,245

 

$249,123

 

$60,563

 

$27,144

 

$59,722

 

$58,732

Increases (reductions) in tax resulting from:
 
 

 
 

 
 

 
 

 
 

 
 

State income taxes net of federal income tax effect
 
11,652

 
29,014

 
5,592

 
3,543

 
449

 
7,001

Regulatory differences - utility plant items
 
10,971

 
8,094

 
(1,154
)
 
2,329

 
4,140

 
9,201

Equity component of AFUDC
 
(5,985
)
 
(9,774
)
 
(2,030
)
 
(412
)
 
(2,666
)
 
(2,780
)
Amortization of investment tax credits
 
(1,201
)
 
(5,019
)
 
(160
)
 
(132
)
 
(900
)
 
(3,476
)
Flow-through / permanent differences
 
(3,848
)
 
(980
)
 
764

 
(3,609
)
 
634

 
(883
)
Act 55 financing settlement (d)
 
—

 
(61,620
)
 
—

 
—

 
(454
)
 
—

Non-taxable dividend income
 
—

 
(44,658
)
 
—

 
—

 
—

 
—

Provision for uncertain tax positions (d)
 
(717
)
 
(75,871
)
 
50

 
(300
)
 
1,926

 
3,151

Other - net
 
656

 
1,425

 
229

 
142

 
246

 
115

Total income taxes as reported
 

$107,773

 

$89,734

 

$63,854

 

$28,705

 

$63,097

 

$71,061

Effective Income Tax Rate
 
39.2
%
 
12.6
%
 
36.9
%
 
37.0
%
 
37.0
%
 
42.3
%

(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 ADIT in 2018 and the tax legislation enactment in 2017.
(c)
See “Income Tax Audits - 2012-2013 IRS Audit” below for discussion of the settlement for Entergy Louisiana.

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Notes to Financial Statements


(d)
See “Income Tax Audits - 2010-2011 IRS Audit” below for discussion of the most significant items for Entergy Louisiana.

Significant components of accumulated deferred income taxes and taxes accrued for Entergy Corporation and Subsidiaries as of December 31, 2018 and 2017 are as follows:
 
 
2018
 
2017
 
(In Thousands)
Deferred tax liabilities:
 
 
 
Plant basis differences - net

($3,835,211
)
 

($3,963,798
)
Regulatory assets
(370,484
)
 
—

Nuclear decommissioning trusts/receivables
(1,128,140
)
 
(1,657,808
)
Pension, net funding
(307,626
)
 
(350,743
)
Combined unitary state taxes
(9,440
)
 
(24,645
)
Power purchase agreements
(73,335
)
 
(19,621
)
Deferred fuel
(29,953
)
 
—

Other
(248,997
)
 
(249,327
)
Total
(6,003,186
)
 
(6,265,942
)
Deferred tax assets:
 

 
 

Nuclear decommissioning liabilities
1,070,583

 
964,945

Regulatory liabilities
895,756

 
841,370

Pension and other post-employment benefits
305,736

 
343,817

Sale and leaseback
121,473

 
122,397

Compensation
86,461

 
75,217

Accumulated deferred investment tax credit
57,643

 
59,285

Provision for allowances and contingencies
135,631

 
126,391

Unbilled/deferred revenues
43,762

 
—

Net operating loss carryforwards
628,165

 
467,255

Capital losses and miscellaneous tax credits
20,549

 
16,738

Valuation allowance
(243,726
)
 
(137,283
)
Other
125,522

 
54,058

Total
3,247,555

 
2,934,190

Non-current accrued taxes (including unrecognized tax benefits)
(1,296,928
)
 
(956,547
)
Accumulated deferred income taxes and taxes accrued

($4,052,559
)
 

($4,288,299
)

Entergy’s estimated tax attributes carryovers and their expiration dates as of December 31, 2018 are as follows:

Carryover Description
 
Carryover Amount
 
Year(s) of expiration
 
 
 
 
 
Federal net operating losses before 1/1/2018
 
$11.1 billion
 
2023-2037
Federal net operating losses - 1/1/2018 forward
 
$6.4 billion
 
N/A
State net operating losses
 
$20.4 billion
 
2019-2038
Miscellaneous federal and state credits
 
$115.6 million
 
2019-2037

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Notes to Financial Statements



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. Because it is more likely than not that the benefit from certain state net operating loss and credit carryovers will not be utilized, valuation allowances of $179 million as of December 31, 2018 and $106 million as of December 31, 2017 have been provided on the deferred tax assets relating to these state net operating loss and credit carryovers. Additionally, valuation allowances totaling $64 million as of December 31, 2018 and $31 million as of December 31, 2017 have been provided on deferred tax assets related to federal and state jurisdictions in which Entergy does not currently expect to be able to utilize separate company tax return losses, preventing realization of such deferred tax assets.

Significant components of accumulated deferred income taxes and taxes accrued for the Registrant Subsidiaries as of December 31, 2018 and 2017 are as follows:
2018
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Deferred tax liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
Plant basis differences - net
 

($966,791
)
 

($1,893,831
)
 

($579,319
)
 

($135,143
)
 

($544,282
)
 

($403,809
)
Regulatory assets
 
(169,482
)
 
(74,917
)
 
(1,732
)
 
(20,009
)
 
(57,777
)
 
(46,627
)
Nuclear decommissioning trusts/receivables
 
(77,664
)
 
(71,470
)
 
—

 
—

 
—

 
(86,882
)
Pension, net funding
 
(91,962
)
 
(92,693
)
 
(24,398
)
 
(11,885
)
 
(20,331
)
 
(18,898
)
Deferred fuel
 
(5,801
)
 
(6,974
)
 
(11,819
)
 
(1,701
)
 
(2,835
)
 
(312
)
Other
 
(41,025
)
 
(34,700
)
 
(13,443
)
 
(7,640
)
 
(6,085
)
 
(4,544
)
Total
 
(1,352,725
)
 
(2,174,585
)
 
(630,711
)
 
(176,378
)
 
(631,310
)
 
(561,072
)
Deferred tax assets:
 
 

 
 

 
 

 
 

 
 

 
 

Regulatory liabilities
 
247,964

 
339,126

 
72,570

 
40,181

 
86,032

 
110,370

Nuclear decommissioning liabilities
 
99,479

 
48,738

 
—

 
—

 
—

 
46,643

Pension and other post-employment benefits
 
(19,068
)
 
80,102

 
(5,405
)
 
(11,371
)
 
(14,215
)
 
(632
)
Sale and leaseback
 
—

 
18,999

 
—

 
—

 


 
102,481

Accumulated deferred investment tax credit
 
8,599

 
33,928

 
2,541

 
579

 
2,347

 
9,649

Provision for allowances and contingencies
 
9,877

 
81,108

 
13,412

 
23,962

 
5,579

 
—

Power purchase agreements
 
(17,223
)
 
19,385

 
1,140

 
12,155

 
(18
)
 
—

Unbilled/deferred revenues
 
7,471

 
(17,345
)
 
5,527

 
636

 
7,016

 
—

Compensation
 
1,708

 
1,959

 
1,265

 
512

 
995

 
(260
)
Net operating loss carryforwards
 
6,338

 
20,118

 
4,896

 
480

 
261

 
—

Other
 
7,977

 
23,412

 
1,610

 
12,181

 
2,127

 
4

Total
 
353,122

 
649,530

 
97,556

 
79,315

 
90,124

 
268,255

Non-current accrued taxes (including unrecognized tax benefits)
 
(85,942
)
 
(701,666
)
 
(18,714
)
 
(226,532
)
 
(11,349
)
 
(512,479
)
Accumulated deferred income taxes and taxes accrued
 

($1,085,545
)
 

($2,226,721
)
 

($551,869
)
 

($323,595
)
 

($552,535
)
 

($805,296
)

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Notes to Financial Statements


2017
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Deferred tax liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
Plant basis differences - net
 

($1,289,827
)
 

($1,583,100
)
 

($571,682
)
 

($85,515
)
 

($526,596
)
 

($359,931
)
Nuclear decommissioning trusts/receivables
 
(181,911
)
 
(164,395
)
 
—

 
—

 
—

 
(119,184
)
Pension, net funding
 
(99,971
)
 
(102,138
)
 
(26,413
)
 
(13,040
)
 
(20,700
)
 
(21,871
)
Deferred fuel
 
(16,530
)
 
(1,329
)
 
(19,005
)
 
(1,894
)
 
—

 
(272
)
Other
 
(23,079
)
 
(98,307
)
 
(11,306
)
 
(23,610
)
 
(8,236
)
 
(5,955
)
Total
 
(1,611,318
)
 
(1,949,269
)
 
(628,406
)
 
(124,059
)
 
(555,532
)
 
(507,213
)
Deferred tax assets:
 
 

 
 

 
 

 
 

 
 

 
 

Regulatory liabilities
 
227,489

 
368,156

 
102,676

 
23,526

 
25,428

 
91,271

Nuclear decommissioning liabilities
 
132,464

 
58,891

 
—

 
—

 
—

 
63,180

Pension and other post-employment benefits
 
(16,252
)
 
98,596

 
(4,865
)
 
(9,618
)
 
(12,044
)
 
(516
)
Sale and leaseback
 
—

 
19,915

 
—

 
—

 
—

 
102,482

Accumulated deferred investment tax credit
 
8,913

 
35,323

 
2,212

 
488

 
2,516

 
9,832

Provision for allowances and contingencies
 
4,367

 
80,516

 
11,898

 
24,234

 
4,383

 
—

Power purchase agreements
 
—

 
(6,924
)
 
1,129

 
—

 
—

 
—

Unbilled/deferred revenues
 
6,195

 
(18,263
)
 
4,847

 
1,811

 
7,736

 
—

Compensation
 
2,566

 
4,387

 
1,466

 
723

 
1,224

 
332

Net operating loss carryforwards
 
16,172

 
44

 
10,255

 
—

 
1,690

 
—

Capital losses and miscellaneous tax credits
 
2,678

 
—

 
5,736

 
—

 
—

 
—

Other
 
473

 
21,922

 
1,307

 
388

 
1,133

 
—

Total
 
385,065

 
662,563

 
136,661

 
41,552

 
32,066

 
266,581

Non-current accrued taxes (including unrecognized tax benefits)
 
35,584

 
(763,665
)
 
2,939

 
(200,795
)
 
(21,176
)
 
(535,788
)
Accumulated deferred income taxes and taxes accrued
 

($1,190,669
)
 

($2,050,371
)
 

($488,806
)
 

($283,302
)
 

($544,642
)
 

($776,420
)


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Notes to Financial Statements


The Registrant Subsidiaries’ estimated tax attributes carryovers and their expiration dates as of December 31, 2018 are as follows:
 
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
 
 
 
 
 
 
 
 
 
 
 
Federal net operating losses
 
$4.2 billion
 
$4.3 billion
 
$1.8 billion
 
$1 billion
 
$—
 
$96 million
Year(s) of expiration
 
N/A
 
2035-2037
 
N/A
 
2037
 
N/A
 
N/A
 
 
 
 
 
 
 
 
 
 
 
 
 
State net operating losses
 
$4.4 billion
 
$5.1 billion
 
$1.8 billion
 
$1.1 billion
 
$—
 
$190 million
Year(s) of expiration
 
2023
 
2035-2037
 
2038
 
2037
 
N/A
 
2038
 
 
 
 
 
 
 
 
 
 
 
 
 
Misc. federal credits
 
$—
 
$3.3 million
 
$—
 
$—
 
$1.4 million
 
$2.9 million
Year(s) of expiration
 
N/A
 
2035-2037
 
N/A
 
N/A
 
2029-2037
 
2029-2037
 
 
 
 
 
 
 
 
 
 
 
 
 
State credits
 
$—
 
$—
 
$—
 
$—
 
$2.9 million
 
$9.6 million
Year(s) of expiration
 
N/A
 
N/A
 
N/A
 
N/A
 
2027
 
2019-2022

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:
 
2018
 
2017
 
2016
 
(In Thousands)
Gross balance at January 1

$4,871,846

 

$3,909,855

 

$2,611,585

Additions based on tax positions related to the current year
2,276,614

 
1,120,687

 
1,532,782

Additions for tax positions of prior years
506,142

 
283,683

 
368,404

Reductions for tax positions of prior years
(274,600
)
 
(442,379
)
 
(265,653
)
Settlements
(198,520
)
 
—

 
(337,263
)
Gross balance at December 31
7,181,482

 
4,871,846

 
3,909,855

Offsets to gross unrecognized tax benefits:
 

 
 

 
 

Carryovers and refund claims
(5,957,992
)
 
(3,945,524
)
 
(2,922,085
)
Cash paid to taxing authorities
(10,000
)
 
(10,000
)
 
(10,000
)
Unrecognized tax benefits net of unused tax attributes, refund claims and payments (a)

$1,213,490

 

$916,322

 

$977,770


(a)
Potential tax liability above what is payable on tax returns

The balances of unrecognized tax benefits include $2,161 million, $1,462 million, and $1,240 million as of December 31, 2018, 2017, and 2016, 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 $5,020

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Notes to Financial Statements


million, $3,410 million, and $2,670 million as of December 31, 2018, 2017, and 2016, 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, 2018, 2017, and 2016 accrued balance for the possible payment of interest is approximately $44 million, $38 million, and $30 million, respectively. Interest (net-of-tax) of $7 million, $8 million, and $9 million was recorded in 2018, 2017, and 2016, respectively.

A reconciliation of the Registrant Subsidiaries’ beginning and ending amount of unrecognized tax benefits for 2018, 2017, and 2016 is as follows:
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


2017
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Gross balance at January 1, 2017
 

$2,503

 

$2,440,339

 

$12,206

 

$166,230

 

$15,946

 

$472,372

Additions based on tax positions related to the current year (a)
 
8,974

 
32,843

 
2,105

 
509,183

 
1,747

 
909

Additions for tax positions of prior years
 
3,682

 
235,331

 
1,267

 
13,364

 
3,115

 
1,432

Reductions for tax positions of prior years
 
(132,875
)
 
(190,056
)
 
(456
)
 
(9,233
)
 
(4,409
)
 
(29,202
)
Gross balance at December 31, 2017
 
(117,716
)
 
2,518,457

 
15,122

 
679,544

 
16,399

 
445,511

Offsets to gross unrecognized tax benefits:
 
 

 
 

 
 

 
 

 
 

 
 

Loss carryovers
 
—

 
(1,591,907
)
 
(15,122
)
 
(441,374
)
 
(638
)
 
(12,536
)
Unrecognized tax benefits net of unused tax attributes and payments
 

($117,716
)
 

$926,550

 

$—

 

$238,170

 

$15,761

 

$432,975



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2016
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Gross balance at January 1, 2016
 

$25,445

 

$1,690,661

 

$19,482

 

$53,897

 

$13,462

 

$478,318

Additions based on tax positions related to the current year (a)
 
16,868

 
931,720

 
2,662

 
33,912

 
2,002

 
5,318

Additions for tax positions of prior years
 
2,463

 
157,586

 
336

 
129,784

 
2,888

 
601

Reductions for tax positions of prior years
 
(41,957
)
 
(144,068
)
 
(10,219
)
 
(29,821
)
 
(1,849
)
 
(10,266
)
Settlements
 
(316
)
 
(195,560
)
 
(55
)
 
(21,542
)
 
(557
)
 
(1,599
)
Gross balance at December 31, 2016
 
2,503

 
2,440,339

 
12,206

 
166,230

 
15,946

 
472,372

Offsets to gross unrecognized tax benefits:
 
 

 
 

 
 

 
 

 
 

 
 

Loss carryovers
 
—

 
(1,783,093
)
 
(2,373
)
 
(27,320
)
 
(376
)
 
(90,028
)
Unrecognized tax benefits net of unused tax attributes and payments
 

$2,503

 

$657,246

 

$9,833

 

$138,910

 

$15,570

 

$382,344


(a)
The primary additions for Entergy Mississippi in 2018, Entergy New Orleans in 2017 and Entergy Louisiana in 2016 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,
 
2018
 
2017
 
2016
 
(In Millions)
Entergy Arkansas

$85.4

 

$2.6

 

$3.6

Entergy Louisiana

$594.0

 

$575.8

 

$473.3

Entergy Mississippi

$1.5

 

$—

 

$—

Entergy New Orleans

$246.2

 

$31.7

 

$33.6

Entergy Texas

$5.1

 

$4.4

 

$7.0

System Energy

$—

 

$—

 

$—


Accrued balances for the possible payment of interest related to unrecognized tax benefits are as follows:
 
December 31,
 
2018
 
2017
 
2016
 
(In Millions)
Entergy Arkansas

$1.7

 

$1.6

 

$1.4

Entergy Louisiana

$17.9

 

$14.1

 

$8.4

Entergy Mississippi

$1.2

 

$1.0

 

$0.8

Entergy New Orleans

$2.7

 

$2.1

 

$1.5

Entergy Texas

$0.9

 

$0.4

 

$1.2

System Energy

$13.2

 

$8.5

 

$3.7



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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 2018, 2017, or 2016. Interest (net-of-tax) was recorded as follows:
 
2018
 
2017
 
2016
 
(In Millions)
Entergy Arkansas

$0.2

 

$0.2

 

$—

Entergy Louisiana

$3.8

 

$5.7

 

($0.9
)
Entergy Mississippi

$0.2

 

$0.2

 

$0.4

Entergy New Orleans

$0.6

 

$0.6

 

($0.3
)
Entergy Texas

$0.5

 

($0.8
)
 

$0.7

System Energy

$4.7

 

$4.8

 

$5.2


Income Tax Audits

Entergy and its subsidiaries file U.S. federal and various state and foreign income tax returns.  IRS examinations are complete for years before 2014. All state taxing authorities’ examinations are complete for years before 2012. Entergy regularly negotiates with the IRS to achieve settlements.  The resolution of audit issues could result in significant changes to the amounts of unrecognized tax benefits in the next twelve months.

2010-2011 IRS Audit

The IRS completed its examination of the 2010 and 2011 tax years and issued its 2010-2011 Revenue Agent Report (RAR) in June 2016. Entergy agreed to all proposed adjustments contained in the RAR. As a result of the issuance of the RAR, Entergy Louisiana was able to recognize previously unrecognized tax benefits as follows:

•
Entergy and the IRS agreed that $148.6 million of the proceeds received by Entergy Louisiana in 2010 from the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, for the financing of Hurricane Gustav and Hurricane Ike storm costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55) were not taxable. Because the treatment of the financing is settled, Entergy recognized previously unrecognized tax benefits totaling $63.5 million, of which Entergy Louisiana recorded $61.6 million. In accordance with the terms of a previous settlement agreement approved by the LPSC, Entergy Louisiana has a regulatory liability of $13.5 million ($10 million net-of-tax) for Entergy Louisiana’s obligation to pay to customers savings associated with the Act 55 financing.
•
Entergy and the IRS agreed upon the tax treatment of Entergy Louisiana’s regulatory liability related to the Vidalia purchased power agreement. As a result, Entergy Louisiana recognized a previously unrecognized tax benefit of $74.5 million.

2012-2013 IRS Audit

The IRS completed its examination of the 2012 and 2013 tax years and issued its 2012-2013 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.


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Other Tax Matters

Tax Cuts and Jobs Act

Deferred tax liabilities and assets have been adjusted for the effect of the enactment of the Tax Cuts and Jobs Act (the Act), signed by President Trump on December 22, 2017. The most significant effect of the Act for Entergy and the Registrant Subsidiaries is 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 Act limits the deduction for net business interest expense in certain circumstances. The new limitation does not apply to interest expense, however, that is properly allocable to a trade or business that furnishes or sells electrical energy, gas, or steam through a local distribution system, or transports gas or steam by pipeline if the rates for such furnishing or sale are subject to ratemaking by a government entity or instrumentality or by a public utility commission. The IRS issued proposed regulations relating to this limitation in November 2018. The regulations are generally proposed to be effective for taxable years ending after the date the Treasury decision adopting the regulations as final is published in the Federal Register. Taxpayers may apply the rules of the proposed regulations to a taxable year beginning after December 31, 2017, so long as taxpayers consistently apply the rules of the proposed regulations. The regulations contain guidance on the application of the interest expense limitation, including methodologies for allocating the interest expense limitation. As a result of this provision of the Act, Entergy recorded limitations in 2018 which did not have a material effect on the financial position, results of operations, or cash flows of Entergy and the Registrant Subsidiaries.
The Act extends and modifies the additional first-year depreciation deduction (bonus depreciation). Conversely, the Act excludes from bonus-eligible qualified property any property used in a trade or business that furnishes or sells electrical energy, gas, or steam through a local distribution system, or transportation of gas or steam by pipeline if the rates for furnishing those services are subject to ratemaking by a government entity or instrumentality or by a public utility commission. Accordingly, the extension of bonus depreciation and modifications generally do not apply to Entergy or the Registrant Subsidiaries for property acquired and placed in service after 2017.
The Act limits 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. Prior law generally provided a two-year carryback and 20-year carryforward for NOLs. The Act does not allow a carryback period but does provide for the indefinite carryforward of NOLs arising in tax years ending after December 31, 2017. 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 Act 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 Act includes performance-based compensation in the annual computation of the section 162 limitation.  The changes are expected to result in an increase in disallowed compensation expense, but this limitation is not expected to have a material effect on Entergy or the Registrant Subsidiaries.
Other provisions that are not expected to have a material effect on Entergy or the Registrant Subsidiaries include the following:
•
repeal of the corporate alternative minimum tax (AMT),
•
modification to the capital contribution rules under Internal Revenue Code section 118,
•
repeal of domestic production activities deduction, and
•
fundamental changes to the taxation of multinational entities.

With respect to the federal corporate income tax rate change from 35% to 21%, Entergy and the Registrant Subsidiaries recorded a regulatory liability associated with the decrease in the net accumulated deferred income tax

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liability, which is often referred to as “excess ADIT,” a significant portion of which has been paid to customers in 2018 in the form of lower rates. Entergy’s December 31, 2018 balance sheet reflects a regulatory liability of $2.1 billion 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 2018. 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, 2018 balance sheets reflect net regulatory liabilities for income taxes as follows: Entergy Arkansas, $605 million; Entergy Louisiana, $612 million; Entergy Mississippi, $246 million; Entergy New Orleans, $86 million; Entergy Texas, $352 million; and System Energy, $163 million.
Excess ADIT is generally classified into two categories: 1) the portion that is subject to the normalization requirements of the Act, i.e., “protected”, and 2) the portion that is not subject to such normalization provisions, referred to as “unprotected”. The Act provides that the normalization method of accounting for income taxes is required for excess ADIT associated with public utility property. The Act 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, 2018, includes protected excess ADIT as follows: Entergy Arkansas, $521 million; Entergy Louisiana, $812 million; Entergy Mississippi, $271 million; Entergy New Orleans, $59 million; Entergy Texas, $237 million; and System Energy, $202 million. The Registrant Subsidiaries’ net regulatory liability for income taxes as of December 31, 2017, includes protected excess ADIT as follows: Entergy Arkansas, $554 million; Entergy Louisiana, $782 million; Entergy Mississippi, $274 million; Entergy New Orleans, $71 million; Entergy Texas, $276 million; and System Energy, $217 million.
During 2018, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy 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, 2018, includes unprotected excess ADIT as follows: Entergy Arkansas, $117 million; Entergy Louisiana, $295 million; Entergy Mississippi, $0; Entergy New Orleans, $25 million; Entergy Texas, $171 million; and System Energy, $4 million. Entergy Texas’s unprotected excess ADIT balance reflects the effect of the settlement of Entergy Texas’s 2018 base rate case, which established the amount of unprotected excess ADIT that will be returned to customers. The Registrant Subsidiaries’ net regulatory liability for income taxes as of December 31, 2017, includes unprotected excess ADIT as follows: Entergy Arkansas, $467 million; Entergy Louisiana, $410 million; Entergy Mississippi, $162 million; Entergy New Orleans, $37 million; Entergy Texas, $198 million; and System Energy, $76 million.
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.
Not all of Entergy’s excess ADIT is included in ratemaking. Consequently, Entergy recorded a net decrease in deferred tax assets of $560 million for which there is a corresponding charge to income tax expense for the year ended December 31, 2017. The corresponding income tax expense (or benefit) recorded by the Registrant Subsidiaries

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was as follows: Entergy Arkansas, ($3 million); Entergy Louisiana, $217 million; Entergy Mississippi, $3 million; Entergy New Orleans, $6 million; Entergy Texas, $3 million; and System Energy, $0.
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 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 Act, 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 the Act 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 the Act; 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.
Entergy Wholesale Commodities Restructuring

The tax classification of the entity that owned FitzPatrick changed in the second quarter 2016.  The change in tax classification required Entergy to recognize the plant’s 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 $238 million. The accrual of the nuclear decommissioning liability also required Entergy to recognize a gain for income tax purposes, a significant portion of which resulted in an increase in tax basis of the assets. Recognition of the gain and the increase in tax basis of the assets represents a tax accounting temporary difference. Entergy sold FitzPatrick on March 31, 2017. The removal of the contingencies regarding the sale of the plant and the receipt of NRC approval for the sale allowed Entergy to re-determine the plant’s tax basis. The re-determined basis resulted in a $44 million income tax benefit in the first quarter 2017.

In the second quarter 2017, Entergy changed the tax classification of legal entities that own Entergy Wholesale Commodities nuclear power plants. The change in tax classification required Entergy to recognize the plants’ 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 $373 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 tax basis of the assets. Recognition of the gain and the increase in tax basis of the assets represents a tax accounting temporary difference.

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.


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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 the companies’ nuclear decommissioning costs will be treated as production costs of electricity includable in cost of goods sold. The new method results in a reduction of taxable income of $1.2 billion for System Energy and $2.2 billion for Entergy Louisiana. In the fourth quarter 2018, Entergy Arkansas adopted the same tax method of accounting for its nuclear decommissioning costs which resulted in a $2.2 billion reduction in taxable income.

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 $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.

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.


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 2023.  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, 2018 was 3.60% 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, 2018.

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Capacity
 
Borrowings
 
Letters of Credit
 
Capacity Available
(In Millions)
$3,500
 
$220
 
$6
 
$3,274

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, 2018, Entergy Corporation had $1.942 billion of commercial paper outstanding.  The weighted-average interest rate for the year ended December 31, 2018 was 2.50%.

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2018 as follows:
Company
 
Expiration Date
 
Amount of Facility
 
Interest Rate (a)
 
 Amount Drawn as of December 31, 2018
 
Letters of Credit Outstanding as of December 31, 2018
Entergy Arkansas
 
April 2019
 
$20 million (b)
 
3.77%
 
—
 
—
Entergy Arkansas
 
September 2023
 
$150 million (c)
 
3.77%
 
—
 
—
Entergy Louisiana
 
September 2023
 
$350 million (c)
 
3.77%
 
—
 
—
Entergy Mississippi
 
May 2019
 
$10 million (d)
 
4.02%
 
—
 
—
Entergy Mississippi
 
May 2019
 
$35 million (d)
 
4.02%
 
—
 
—
Entergy Mississippi
 
May 2019
 
$37.5 million (d)
 
4.02%
 
—
 
—
Entergy New Orleans
 
November 2021
 
$25 million (c)
 
3.80%
 
—
 
$0.8 million
Entergy Texas
 
September 2023
 
$150 million (c)
 
4.02%
 
—
 
$1.3 million

(a)
The interest rate is the estimated interest rate as of December 31, 2018 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 0.225% 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, 2018:

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Company
 
Amount of Uncommitted Facility
 
Letter of Credit Fee
 
Letters of Credit Issued as of December 31, 2018 (a)
Entergy Arkansas
 
$25 million
 
0.70%
 
$1.0 million
Entergy Louisiana
 
$125 million
 
0.70%
 
$25.9 million
Entergy Mississippi
 
$40 million
 
0.70%
 
$16.7 million
Entergy New Orleans
 
$15 million
 
1.00%
 
$2.0 million
Entergy Texas
 
$50 million
 
0.70%
 
$20.9 million

(a)
As of December 31, 2018, letters of credit posted with MISO covered financial transmission right exposure of $0.2 million for Entergy Mississippi and $4.1 million for Entergy Texas. See Note 15 to the financial statements for discussion of financial transmission rights.
 
The short-term borrowings of the Registrant Subsidiaries are limited to amounts authorized by the FERC.  The current FERC-authorized limits for Entergy New Orleans are effective through October 31, 2019. The current FERC-authorized limits for Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy are effective through November 8, 2020. 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, 2018 (aggregating both internal and external short-term borrowings) for the Registrant Subsidiaries:

 
Authorized
 
Borrowings
 
(In Millions)
Entergy Arkansas
$250
 
$183
Entergy Louisiana
$450
 
—
Entergy Mississippi
$175
 
—
Entergy New Orleans
$150
 
—
Entergy Texas
$200
 
$22
System Energy
$200
 
—

Entergy Nuclear Vermont Yankee Credit Facilities

As of December 31, 2018, Entergy Nuclear Vermont Yankee had a credit facility guaranteed by Entergy Corporation with a borrowing capacity of $145 million that expires in November 2020. Entergy Nuclear Vermont Yankee did not have the ability to issue letters of credit against the credit facility. The facility provided working capital to Entergy Nuclear Vermont Yankee for general business purposes including, without limitation, the decommissioning of Vermont Yankee.  As of December 31, 2018, $139 million in cash borrowings were outstanding under the credit facility.  The weighted average interest rate for the year ended December 31, 2018 was 3.50% on the drawn portion of the facility.  In anticipation of the transfer of Entergy Nuclear Vermont Yankee to NorthStar, in January 2019 the credit facility was assumed by Vermont Yankee Asset Retirement Management, LLC, Entergy Nuclear Vermont Yankee’s parent company that remains an Entergy subsidiary after the transfer, and the borrowing capacity was reduced to $139 million. The commitment fee is currently 0.20% of the undrawn commitment amount.  See Note 14 to the financial statements for discussion of the transfer of Entergy Nuclear Vermont Yankee to NorthStar.


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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, 2018:
Company
 
Expiration Date
 
Amount of Facility
 
Weighted Average Interest Rate on Borrowings (a)
 
Amount Outstanding as of December 31, 2018
 
 
(Dollars in Millions)
Entergy Arkansas VIE
 
September 2021
 
$80
 
3.48%
 
$59.6
Entergy Louisiana River Bend VIE
 
September 2021
 
$105
 
3.44%
 
$38.6
Entergy Louisiana Waterford VIE
 
September 2021
 
$105
 
3.35%
 
$82.0
System Energy VIE
 
September 2021
 
$120
 
3.44%
 
$113.9

(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 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 0.10% 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.

The nuclear fuel company variable interest entities had notes payable that are included in debt on the respective balance sheets as of December 31, 2018 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
 
3.38% Series R due August 2020
 
$70 million
Entergy Louisiana Waterford VIE
 
3.92% Series H due February 2021
 
$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
 
$100 million

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 November 2020 for issuances by its nuclear fuel company variable interest entities.



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Notes to Financial Statements


NOTE 5.  LONG - TERM DEBT (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Long-term debt for Entergy Corporation and subsidiaries as of December 31, 2018 and 2017 consisted of:
Type of Debt and Maturity
 
Weighted Average Interest Rate December 31, 2018
 
Interest Rate Ranges at December 31,
 
Outstanding at December 31,
2018
 
2017
 
2018
 
2017
 
 
 
 
 
 
 
 
(In Thousands)
Mortgage Bonds
 
 
 
 
 
 
 
 
 
 
2018-2022
 
3.86%
 
2.55%-7.125%
 
2.55%-7.125%
 

$1,875,000

 

$2,550,000

2023-2027
 
3.71%
 
2.40%-5.59%
 
2.40%-5.59%
 
4,735,000

 
4,735,000

2028-2038
 
3.63%
 
2.85%-4.52%
 
2.85%-3.25%
 
2,240,000

 
1,125,000

2044-2066
 
4.88%
 
4.20%-5.625%
 
4.70%-5.625%
 
3,560,000

 
2,960,000

Governmental Bonds (a)
 
 
 
 
 
 
 
 
 
 
2021-2022
 
5.28%
 
2.375%-5.875%
 
2.375%-5.875%
 
179,000

 
179,000

2028-2030
 
3.45%
 
3.375%-3.50%
 
3.375%-3.50%
 
198,680

 
198,680

Securitization Bonds
 
 
 
 
 
 
 
 
 
 
2019-2027
 
3.79%
 
2.04%-5.93%
 
2.04%-5.93%
 
429,118

 
551,499

Variable Interest Entities Notes Payable (Note 4)
 
 
 
 
 
 
 
 
 
 
2018-2023
 
3.44%
 
3.17%-3.92%
 
3.17%-3.92%
 
360,000

 
345,000

Entergy Corporation Notes
 
 
 
 
 
 
 
 
 
 
due September 2020
 
n/a
 
5.125%
 
5.125%
 
450,000

 
450,000

due July 2022
 
n/a
 
4.00%
 
4.00%
 
650,000

 
650,000

due September 2026
 
n/a
 
2.95%
 
2.95%
 
750,000

 
750,000

5 Year Credit Facility (Note 4)
 
n/a
 
3.60%
 
2.55%
 
220,000

 
210,000

Vermont Yankee Credit Facility (Note 4)
 
n/a
 
3.50%
 
2.64%
 
139,000

 
103,500

Entergy Arkansas VIE Credit Facility (Note 4)
 
n/a
 
3.48%
 
2.87%
 
59,600

 
24,900

Entergy Louisiana River Bend VIE Credit Facility (Note 4)
 
n/a
 
3.44%
 
2.38%
 
38,600

 
65,650

Entergy Louisiana Waterford VIE Credit Facility (Note 4)
 
n/a
 
3.35%
 
2.64%
 
82,000

 
36,360

System Energy VIE Credit Facility (Note 4)
 
n/a
 
3.44%
 
2.52%
 
113,900

 
50,000

Long-term DOE Obligation (b)
 
—
 
—
 
—
 
186,864

 
183,435

Grand Gulf Lease Obligation (c)
 
n/a
 
(d)
 
(d)
 
34,352

 
34,356

Unamortized Premium and Discount - Net
 
 
 
 
 
 
 
(14,784
)
 
(13,911
)
Unamortized Debt Issuance Costs
 
 
 
 
 
 
 
(130,612
)
 
(126,033
)
Other
 
 
 
 
 
 
 
12,594

 
12,830

Total Long-Term Debt
 
 
 
 
 
 
 
16,168,312

 
15,075,266

Less Amount Due Within One Year
 
 
 
 
 
 
 
650,009

 
760,007

Long-Term Debt Excluding Amount Due Within One Year
 
 
 
 
 
 
 

$15,518,303

 

$14,315,259

Fair Value of Long-Term Debt (c)
 
 
 
 
 
 
 

$15,880,239

 

$15,367,453


(a)
Consists of pollution control revenue bonds and environmental revenue bonds, some of which are secured by collateral mortgage bonds.

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Notes to Financial Statements


(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 fair value excludes lease obligations of $34 million at System Energy and long-term DOE obligations of $187 million at Entergy Arkansas, and includes debt due within one year.  Fair values are classified as Level 2 in the fair value hierarchy discussed in Note 15 to the financial statements and are based on prices derived from inputs such as benchmark yields and reported trades.
(d)
See Note 10 to the financial statements for detail of payments under the Grand Gulf lease obligation.

The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2018, for the next five years are as follows:
 
Amount
 
(In Thousands)
2019

$650,000

2020

$934,000

2021

$1,340,792

2022

$1,065,237

2023

$1,715,523


Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through November 2020.  Entergy New Orleans has obtained long-term financing authorization from the FERC and the City Council that extends through October 2019. Entergy Arkansas has also obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2020.

Capital Funds Agreement

Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:

•
maintain System Energy’s equity capital at a minimum of 35% of its total capitalization (excluding short-term debt);
•
permit the continued commercial operation of Grand Gulf;
•
pay in full all System Energy indebtedness for borrowed money when due; and
•
enable System Energy to make payments on specific System Energy debt, under a supplement to the agreement assigning System Energy’s rights in the agreement as security for the specific debt.


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Notes to Financial Statements


Long-term debt for the Registrant Subsidiaries as of December 31, 2018 and 2017 consisted of:
 
 
2018
 
2017
 
 
(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
 
250,000

 
—

4.95% Series due December 2044
 
250,000

 
250,000

4.90% Series due December 2052
 
200,000

 
200,000

4.75% Series due June 2063
 
125,000

 
125,000

4.875% Series due September 2066
 
410,000

 
410,000

Total mortgage bonds
 
2,810,000

 
2,560,000

Governmental Bonds (a):
 
 
 
 
2.375% Series due 2021, Independence County (d)
 
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 2021, weighted avg rate 3.48%
 
59,600

 
24,900

Total variable interest entity notes payable and credit facility
 
189,600

 
154,900

Securitization Bonds:
 
 
 
 
2.30% Series Senior Secured due August 2021
 
21,692

 
35,764

Total securitization bonds
 
21,692

 
35,764

Other:
 
 
 
 
Long-term DOE Obligation (b)
 
186,864

 
183,435

Unamortized Premium and Discount – Net
 
4,408

 
5,307

Unamortized Debt Issuance Costs
 
(33,831
)
 
(34,049
)
Other
 
2,026

 
2,042

Total Long-Term Debt
 
3,225,759

 
2,952,399

Less Amount Due Within One Year
 
—

 
—

Long-Term Debt Excluding Amount Due Within One Year
 

$3,225,759

 

$2,952,399

Fair Value of Long-Term Debt (c)
 

$3,002,627

 

$2,865,844



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2018
 
2017
 
 
(In Thousands)
Entergy Louisiana
 
 
 
 
Mortgage Bonds:
 
 
 
 
6.0% Series due May 2018
 

$—

 

$375,000

6.50% Series due September 2018
 
—

 
300,000

3.95% Series due October 2020
 
250,000

 
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

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

3.05% Series due June 2031
 
325,000

 
325,000

4.0% Series due March 2033
 
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
 
600,000

 
—

5.25% Series due July 2052
 
200,000

 
200,000

4.70% Series due June 2063
 
100,000

 
100,000

4.875% Series due September 2066
 
270,000

 
270,000

Total mortgage bonds
 
6,365,000

 
5,690,000

Governmental Bonds (a):
 
 
 
 
3.375 % Series due 2028, Louisiana Public Facilities Authority (d)
 
83,680

 
83,680

3.50% Series due 2030, Louisiana Public Facilities Authority (d)
 
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

 
70,000

3.92% Series H due February 2021
 
40,000

 
40,000

3.22% Series I due December 2023
 
20,000

 
20,000

Credit Facility due September 2021, weighted avg rate 3.44%
 
38,600

 
65,650

Credit Facility due September 2021, weighted avg rate 3.35%
 
82,000

 
36,360

Total variable interest entity notes payable and credit facilities
 
250,600

 
232,010

Securitization Bonds:
 
 
 
 
2.04% Series Senior Secured due September 2023
 
56,910

 
79,228

Total securitization bonds
 
56,910

 
79,228

Other:
 
 
 
 
Unamortized Premium and Discount - Net
 
(14,955
)
 
(13,877
)
Unamortized Debt Issuance Costs
 
(57,011
)
 
(48,540
)
Other
 
6,544

 
6,570

Total Long-Term Debt
 
6,805,768

 
6,144,071

Less Amount Due Within One Year
 
2

 
675,002

Long-Term Debt Excluding Amount Due Within One Year
 

$6,805,766

 

$5,469,069

Fair Value of Long-Term Debt (c)
 

$6,834,134

 

$6,389,774



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Notes to Financial Statements


 
 
2018
 
2017
 
 
(In Thousands)
Entergy Mississippi
 
 
 
 
Mortgage Bonds:
 
 
 
 
6.64% Series due July 2019
 

$150,000

 

$150,000

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

 
—

4.90% Series due October 2066
 
260,000

 
260,000

Total mortgage bonds
 
1,340,000

 
1,285,000

Other:
 
 
 
 
Unamortized Premium and Discount – Net
 
(989
)
 
(1,155
)
Unamortized Debt Issuance Costs
 
(13,261
)
 
(13,723
)
Total Long-Term Debt
 
1,325,750

 
1,270,122

Less Amount Due Within One Year
 
150,000

 
—

Long-Term Debt Excluding Amount Due Within One Year
 

$1,175,750

 

$1,270,122

Fair Value of Long-Term Debt (c)
 

$1,276,452

 

$1,285,741


 
 
2018
 
2017
 
 
(In Thousands)
Entergy New Orleans
 
 
 
 
Mortgage Bonds:
 
 
 
 
5.10% Series due December 2020
 

$25,000

 

$25,000

3.9% Series due July 2023
 
100,000

 
100,000

4.0% Series due June 2026
 
85,000

 
85,000

4.51% Series due September 2033
 
60,000

 
—

5.0% Series due December 2052
 
30,000

 
30,000

5.50% Series due April 2066
 
110,000

 
110,000

Total mortgage bonds
 
410,000

 
350,000

Securitization Bonds:
 
 
 
 
       2.67% Series Senior Secured due June 2027
 
65,666

 
76,707

Total securitization bonds
 
65,666


76,707

Other:
 
 
 
 
Payable to associated company due November 2035
 
16,346

 
18,423

Unamortized Premium and Discount – Net
 
(168
)
 
(206
)
Unamortized Debt Issuance Costs
 
(8,140
)
 
(8,054
)
Total Long-Term Debt
 
483,704

 
436,870

Less Amount Due Within One Year
 
1,979

 
2,077

Long-Term Debt Excluding Amount Due Within One Year
 

$481,725

 

$434,793

Fair Value of Long-Term Debt (c)
 

$491,569

 

$455,968


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2018
 
2017
 
 
(In Thousands)
Entergy Texas
 
 
 
 
Mortgage Bonds:
 
 
 
 
7.125% Series due February 2019
 

$500,000

 

$500,000

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

5.15% Series due June 2045
 
250,000

 
250,000

5.625% Series due June 2064
 
135,000

 
135,000

Total mortgage bonds
 
1,235,000

 
1,235,000

Securitization Bonds:
 
 
 
 
3.65% Series Senior Secured, Series A due August 2019
 
—

 
30,769

5.93% Series Senior Secured, Series A due June 2022
 
81,237

 
110,431

4.38% Series Senior Secured, Series A due November 2023
 
203,613

 
218,600

Total securitization bonds
 
284,850

 
359,800

Other:
 
 
 
 
Unamortized Premium and Discount - Net
 
(992
)
 
(1,498
)
Unamortized Debt Issuance Costs
 
(9,145
)
 
(10,366
)
Other
 
4,022

 
4,214

Total Long-Term Debt
 
1,513,735

 
1,587,150

Less Amount Due Within One Year
 
500,000

 
—

Long-Term Debt Excluding Amount Due Within One Year
 

$1,013,735

 

$1,587,150

Fair Value of Long-Term Debt (c)
 

$1,528,828

 

$1,661,902


 
 
2018
 
2017
 
 
(In Thousands)
System Energy
 
 
 
 
Mortgage Bonds:
 
 
 
 
4.1% Series due April 2023
 

$250,000

 

$250,000

Total mortgage bonds
 
250,000

 
250,000

Governmental Bonds (a):
 
 
 
 
5.875% 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):
 
 
 
 
3.78% Series I due October 2018
 
—

 
85,000

3.42% Series J due April 2021
 
100,000

 
—

Credit Facility due September 2021, weighted avg rate 3.44%
 
113,900

 
50,000

Total variable interest entity notes payable and credit facility
 
213,900

 
135,000

Other:
 
 
 
 
Grand Gulf Lease Obligation (e)
 
34,352

 
34,356

Unamortized Premium and Discount – Net
 
(328
)
 
(415
)
Unamortized Debt Issuance Costs
 
(1,176
)
 
(1,455
)
Other
 
2

 
2

Total Long-Term Debt
 
630,750

 
551,488

Less Amount Due Within One Year
 
6

 
85,004

Long-Term Debt Excluding Amount Due Within One Year
 

$630,744

 

$466,484

Fair Value of Long-Term Debt (c)
 

$596,123

 

$529,119


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Notes to Financial Statements



(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 fair value excludes lease obligations of $34 million at System Energy and long-term DOE obligations of $187 million at Entergy Arkansas, and includes debt due within one year.  Fair values are classified as Level 2 in the fair value hierarchy discussed in Note 15 to the financial statements and are based on prices derived from inputs such as benchmark yields and reported trades.
(d)
The bonds are secured by a series of collateral mortgage bonds.
(e)
See Note 10 to the financial statements for detail of payments under the Grand Gulf lease obligation.

The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2018, for the next five years are as follows:
 
Entergy
Arkansas
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
Entergy
Texas
 
System
Energy
 
(In Thousands)
2019

$—

 

$—

 

$150,000

 

$—

 

$500,000

 

$—

2020

$—

 

$320,000

 

$—

 

$25,000

 

$—

 

$—

2021

$566,292

 

$360,600

 

$—

 

$—

 

$200,000

 

$213,900

2022

$—

 

$200,000

 

$—

 

$—

 

$81,237

 

$134,000

2023

$290,000

 

$401,910

 

$250,000

 

$100,000

 

$203,613

 

$250,000


Entergy Texas Debt Issuance

In January 2019, Entergy Texas issued $300 million of 4.00% Series first mortgage bonds due March 2029 and $400 million of 4.50% Series first mortgage bonds due March 2039. Entergy Texas used the proceeds to repay at maturity its $500 million of 7.125% Series first mortgage bonds due February 2019 and for general corporate purposes.

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.  The bonds have a coupon of 2.30%.  Although the principal amount is not due until August 2021, Entergy Arkansas Restoration Funding expects to make principal payments on the bonds over the next two years in the amount of $14.4 million for 2019 and $7.3 million for 2020. 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.  The creditors of Entergy Arkansas do not have recourse to the assets or revenues of Entergy Arkansas Restoration Funding, including the storm recovery property, and the creditors of Entergy Arkansas Restoration Funding do not have recourse to the assets or revenues of Entergy Arkansas.  Entergy Arkansas has no payment obligations to Entergy Arkansas Restoration Funding except to remit storm recovery charge collections.

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

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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 over the next three years in the amounts of $22.7 million for 2019, $23.2 million for 2020, and $11 million for 2021.  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 five years in the amounts of $11.2 million for 2019, $11.6 million for 2020, $11.9 million for 2021, $12.2 million for 2022, and $12.5 million for 2023. With the proceeds, Entergy New Orleans Storm Recovery Funding purchased from Entergy New Orleans the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy New Orleans balance sheet. The creditors of Entergy New Orleans do not have recourse to the assets or revenues of Entergy New Orleans Storm Recovery Funding, including the storm recovery property, and the creditors of Entergy New Orleans Storm Recovery Funding do not have recourse to the assets or revenues of Entergy New Orleans. Entergy New Orleans has no payment obligations to Entergy New Orleans Storm Recovery Funding except to remit storm recovery charge collections.

Entergy Texas Securitization Bonds - Hurricane Rita

In April 2007 the PUCT issued a financing order authorizing the issuance of securitization bonds to recover $353 million of Entergy Texas’s Hurricane Rita reconstruction costs and up to $6 million of transaction costs, offset by $32 million of related deferred income tax benefits.  In June 2007, Entergy Gulf States Reconstruction Funding I, LLC, a company that is now wholly-owned and consolidated by Entergy Texas, issued $329.5 million of senior secured transition bonds (securitization bonds) as follows:
 
Amount
 
(In Thousands)
Senior Secured Transition Bonds, Series A:
 

Tranche A-1 (5.51%) due October 2013

$93,500

Tranche A-2 (5.79%) due October 2018
121,600

Tranche A-3 (5.93%) due June 2022 (a)
114,400

Total senior secured transition bonds

$329,500


(a)     As of December 31, 2018 the remaining amount outstanding on Tranche A-3 was $81.2 million.


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Although the principal amount of each tranche is not due until the dates given above, Entergy Gulf States Reconstruction Funding expects to make principal payments on the bonds over the next three years in the amounts of $30.9 million for 2019, $32.8 million for 2020, and $17.5 million for 2021. All of the scheduled principal payments for 2019-2021 are for Tranche A-3. Tranche A-1 and Tranche A-2 have been paid.

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 follows:
 
Amount
 
(In Thousands)
Senior Secured Transition Bonds:
 

Tranche A-1 (2.12%) due February 2016

$182,500

Tranche A-2 (3.65%) due August 2019
144,800

Tranche A-3 (4.38%) due November 2023 (a)
218,600

Total senior secured transition bonds

$545,900


(a)     As of December 31, 2018 the remaining amount outstanding on Tranche A-3 was $203.6 million.

Although the principal amount of each tranche is not due until the dates given above, Entergy Texas Restoration Funding expects to make principal payments on the bonds over the next four years in the amount of $47.6 million for 2019, $49.8 million for 2020, $52 million for 2021, and $54.3 million for 2022. All of the scheduled principle payments for 2019-2022 are for Tranche A-3. Tranche A-1 and Tranche A-2 have been paid.

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.



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NOTE 6.   PREFERRED EQUITY (Entergy Corporation, Entergy Arkansas, and Entergy Mississippi)

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, 2018 and 2017 are presented below.  
 
 
Shares/Units
Authorized
 
Shares/Units
Outstanding
 
 
 
 
 
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
Entergy Corporation
 
 
 
 
 
 
 
(Dollars in Thousands)
Utility:
 
 
 
 
 
 
 
 
 
 
 
 
Preferred Stock or Preferred Membership Interests without sinking fund:
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Arkansas, 4.32%-4.72% Series
 
—

 
313,500

 
—

 
313,500

 

$—

 

$31,350

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

 
14,398

Entergy Utility Holding Company, LLC, 6.75% Series (c)
 
75,000

 
—

 
75,000

 
—

 
73,362

 
—

Entergy Mississippi, 4.36%-4.92% Series
 
—

 
203,807

 
—

 
203,807

 
—

 
20,381

Total Utility Preferred Stock or Preferred Membership Interests without sinking fund
 
200,000

 
642,307

 
200,000

 
642,307

 
195,153

 
173,554

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 without sinking fund
 
450,000

 
892,307

 
450,000

 
892,307

 

$219,402

 

$197,803


(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, 2018. 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, 2018. 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, 2018. 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 $1,638 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, 2017. The dividends are cumulative and payable quarterly. The preferred stock is redeemable on or after December 16, 2023, at Entergy Finance

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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.
 
The number of shares and units authorized and outstanding and dollar value of preferred stock for Entergy Arkansas and Entergy Mississippi as of December 31, 2018 and 2017 are presented below.  

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.  
 
 
Shares
Authorized
and Outstanding
 
 
 
Call Price per
Share as of
December 31,
 
 
2018
 
2017
 
2018
 
2017
 
2018
Entergy Arkansas Preferred Stock
 
 
 
 
 
(Dollars in Thousands)
 
 
Without sinking fund:
 
 
 
 
 
 
 
 
 
 
Cumulative, $100 par value:
 
 
 
 
 
 
 
 
 
 
4.32% Series (a)
 
—

 
70,000

 

$—

 

$7,000

 

$—

4.72% Series (a)
 
—

 
93,500

 
—

 
9,350

 

$—

4.56% Series (a)
 
—

 
75,000

 
—

 
7,500

 

$—

4.56% 1965 Series (a)
 
—

 
75,000

 
—

 
7,500

 

$—

Total without sinking fund
 
—

 
313,500

 

$—

 

$31,350

 
 

(a)
In November 2018, Entergy Arkansas redeemed all of its preferred membership interests as part of a multi-step internal restructuring. See Note 2 to the financial statements for a discussion of Entergy Arkansas’s internal restructuring.
 
 
Shares
Authorized
and Outstanding
 
 
 
Call Price per
Share as of
December 31,
 
 
2018
 
2017
 
2018
 
2017
 
2018
Entergy Mississippi Preferred Stock
 
 
 
 
 
(Dollars in Thousands)
 
 
Without sinking fund:
 
 
 
 
 
 
 
 
 
 
Cumulative, $100 par value:
 
 
 
 
 
 
 
 
 
 
4.36% Series (b)
 
—

 
59,920

 

$—

 

$5,992

 

$—

4.56% Series (b)
 
—

 
43,887

 
—

 
4,389

 

$—

4.92% Series (b)
 
—

 
100,000

 
—

 
10,000

 

$—

Total without sinking fund
 
—

 
203,807

 

$—

 

$20,381

 
 

(b)
In November 2018, Entergy Mississippi redeemed all of its preferred membership interests as part of a multi-step internal restructuring. See Note 2 to the financial statements for a discussion of Entergy Mississippi’s internal restructuring.

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.  Prior to December 1, 2018, Entergy Arkansas’s and Entergy Mississippi’s respective articles of incorporation each provided, generally, that

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the holders of each such company’s preferred securities could elect a majority of the respective company’s board of directors if dividends were not paid for a year, until such time as the dividends in arrears were paid.  Therefore, Entergy Arkansas and Entergy Mississippi presented their preferred securities outstanding between liabilities and shareholders’ equity on the balance sheet.  In November 2018, each of Entergy Arkansas and Entergy Mississippi redeemed its outstanding preferred securities as part of a multi-step process to undertake an internal restructuring. See Note 2 to the financial statements for a discussion of Entergy Arkansas’s and Entergy Mississippi’s internal restructuring.

The outstanding preferred securities of Entergy Arkansas and Entergy Mississippi, and Entergy Utility Holding Company (a Utility subsidiary) and Entergy Finance Holding (an Entergy Wholesale Commodities subsidiary), whose preferred holders also have protective rights, are similarly presented between liabilities and equity on Entergy’s consolidated balance sheets.  The preferred dividends or distributions paid by all subsidiaries are reflected for all periods presented outside of consolidated net income.


NOTE 7.   COMMON EQUITY (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Common Stock

Common stock and treasury stock shares activity for Entergy for 2018, 2017, and 2016 is as follows:
 
2018
 
2017
 
2016
 
Common
Shares
Issued
 

Treasury
Shares
 
Common
Shares
Issued
 
 
Treasury
Shares
 
Common
Shares
Issued
 
 
Treasury
Shares
Beginning Balance, January 1
254,752,788

 
74,235,135

 
254,752,788

 
75,623,363

 
254,752,788

 
76,363,763

Issuances:
 

 
 

 
 

 
 

 
 

 
 

Equity forwards settled
6,834,221

 
—

 
—

 
—

 
—

 
—

Employee Stock-Based Compensation Plans
—

 
(1,683,174
)
 
—

 
(1,377,363
)
 
—

 
(729,073
)
Directors’ Plan
—

 
(21,095
)
 
—

 
(10,865
)
 
—

 
(11,327
)
Ending Balance, December 31
261,587,009

 
72,530,866

 
254,752,788

 
74,235,135

 
254,752,788

 
75,623,363


Entergy Corporation reissues treasury shares to meet the requirements of the Stock Plan for Outside Directors (Directors’ Plan), three Equity Ownership 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, 2018, $350 million of authority remains under the $500 million share repurchase program.

Dividends declared per common share were $3.58 in 2018, $3.50 in 2017, and $3.42 in 2016.

System Energy paid its parent, Entergy Corporation, distributions out of its common stock of $57 million in 2018 and $21 million in 2017.


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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 require 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 is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements.

On December 12, 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 approximately $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. 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.

Entergy is required to settle its remaining obligations under the forward sale agreements with respect to the remaining 8,448,171 shares of common stock on a settlement date or dates on or prior to June 7, 2019.

Until settlement of the remaining equity forwards, earnings per share dilution resulting from the agreements, if any, will be determined under the treasury stock method. Share dilution occurs when the average market price of Entergy’s common stock is higher than the average forward sales price. If Entergy had elected to net share settle the remaining forward sale agreements as of December 31, 2018, Entergy would have been required to deliver 1.3 million shares.

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 herein 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

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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 Corporation received dividend payments and distributions from subsidiaries totaling $27 million in 2018, $201 million in 2017, and $165 million in 2016.

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, 2018 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, 2017

($37,477
)
 

($531,099
)
 

$545,045

 

($23,531
)
Implementation of accounting standards
—

 
—

 
(632,617
)
 
(632,617
)
Beginning balance, January 1, 2018

($37,477
)
 

($531,099
)
 

($87,572
)
 

($656,148
)
 
 
 
 
 
 
 
 
Other comprehensive income (loss) before reclassifications
(31,933
)
 
26,702

 
(46,574
)
 
(51,805
)
Amounts reclassified from accumulated other comprehensive income (loss)
54,031

 
63,441

 
17,803

 
135,275

Net other comprehensive income (loss) for the period
22,098

 
90,143

 
(28,771
)
 
83,470

Reclassification pursuant to ASU 2018-02
(7,756
)
 
(90,966
)
 
114,227

 
15,505

Ending balance, December 31, 2018

($23,135
)
 

($531,922
)
 

($2,116
)
 

($557,173
)


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The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 2017 by component:
 
Cash flow
hedges
net
unrealized
gain (loss)
 
Pension
and
other
postretirement
liabilities
 

Net
unrealized
investment
gain (loss)
 
Foreign
currency
translation
 
Total
Accumulated
Other
Comprehensive
Income (Loss)
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
Beginning balance, January 1, 2017

$3,993



($469,446
)


$429,734



$748

 

($34,971
)
Other comprehensive income (loss) before reclassifications
28,602

 
(104,029
)
 
171,099

 
(748
)
 
94,924

Amounts reclassified from
accumulated other comprehensive income (loss)
(70,072
)
 
42,376

 
(55,788
)
 
—

 
(83,484
)
Net other comprehensive income (loss) for the period
(41,470
)
 
(61,653
)
 
115,311

 
(748
)
 
11,440

Ending balance, December 31, 2017

($37,477
)
 

($531,099
)
 

$545,045

 

$—

 

($23,531
)

The following table presents changes in accumulated other comprehensive income (loss) for Entergy Louisiana for the year ended December 31, 2018:
 
 
Pension and Other
Postretirement Liabilities
 
 
(In Thousands)
 
 
 
Beginning balance, January 1, 2018
 

($46,400
)
Other comprehensive income (loss) before reclassifications
 
52,299

Amounts reclassified from accumulated other comprehensive income (loss)
 
(2,003
)
Net other comprehensive income (loss) for the period
 
50,296

 
 
 
Reclassification pursuant to ASU 2018-02
 

($10,049
)
 
 
 
Ending balance, December 31, 2018
 

($6,153
)


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The following table presents changes in accumulated other comprehensive income (loss) for Entergy Louisiana for the year ended December 31, 2017:

 
Pension and Other
Postretirement Liabilities

 
(In Thousands)



Beginning balance, January 1, 2017
 

($48,442
)
Other comprehensive income (loss) before reclassifications
 
3,462

Amounts reclassified from accumulated other comprehensive income (loss)
 
(1,420
)
Net other comprehensive income (loss) for the period
 
2,042

Ending balance, December 31, 2017
 

($46,400
)

Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy for the years ended December 31, 2018 and 2017 are as follows:
 
 
Amounts reclassified from AOCI
 
Income Statement Location
 
 
2018
 
2017
 
 
 
 
(In Thousands)
 
 
Cash flow hedges net unrealized gain (loss)
 
 
 
 
 
 
Power contracts
 

($68,067
)
 

$108,606

 
Competitive business operating revenues
Interest rate swaps
 
(327
)
 
(803
)
 
Miscellaneous - net
Total realized gain (loss) on cash flow hedges
 
(68,394
)
 
107,803

 
 
 
 
14,363

 
(37,731
)
 
Income taxes
Total realized gain (loss) on cash flow hedges (net of tax)
 

($54,031
)
 

$70,072

 
 
 
 
 
 

 
 
Pension and other postretirement liabilities
 
 

 
 

 
 
Amortization of prior-service costs
 

$21,700

 

$26,251

 
(a)
Amortization of loss
 
(99,186
)
 
(86,002
)
 
(a)
Settlement loss
 
(3,207
)
 
(7,544
)
 
(a)
Total amortization
 
(80,693
)
 
(67,295
)
 
 
 
 
17,252

 
24,919

 
Income taxes
Total amortization (net of tax)
 

($63,441
)
 

($42,376
)
 
 
 
 
 
 

 
 
Net unrealized investment gain (loss)
 
 
 

 
 
Realized gain (loss)
 

($28,170
)
 

$109,388

 
Interest and investment income
 
 
10,367

 
(53,600
)
 
Income taxes
Total realized investment gain (loss) (net of tax)
 

($17,803
)
 

$55,788

 
 
 
 
 
 

 
 
Total reclassifications for the period (net of tax)
 

($135,275
)
 

$83,484

 
 
(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.
    


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Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy Louisiana for the years ended December 31, 2018 and 2017 are as follows:
 
 
Amounts reclassified from AOCI
 
Income Statement Location
 
 
2018
 
2017
 
 
 
 
(In Thousands)
 
 
 
 
 
 
 
 
 
Pension and other postretirement liabilities
 
 
 
 
 
 
Amortization of prior-service costs
 

$7,735

 

$7,734

 
(a)
Amortization of loss
 
(5,025
)
 
(5,327
)
 
(a)
Total amortization
 
2,710

 
2,407

 
 
 
 
(707
)
 
(987
)
 
Income taxes
Total amortization (net of tax)
 
2,003

 
1,420

 
 
 
 
 
 

 
 
Total reclassifications for the period (net of tax)
 

$2,003

 

$1,420

 
 
(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 $137.6 million in 2018, $122.9 million in 2017, and $158.7 million in 2016.  If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $130 million in 2019, and a total of $1.57 billion for the years 2020 through 2031.  Entergy Louisiana currently recovers the costs of the purchased energy through its fuel adjustment clause.

In an LPSC-approved settlement related to tax benefits from the tax treatment of the Vidalia contract, Entergy Louisiana agreed to credit rates by $11 million each year for up to 10 years, beginning in October 2002.  In October 2011 the LPSC approved a settlement under which Entergy Louisiana agreed to provide credits to customers by crediting billings an additional $20.235 million per year for 15 years beginning January 2012.  Entergy Louisiana recorded a regulatory charge and a corresponding regulatory liability to reflect this obligation.  The settlement agreement allowed for an adjustment to the credits if, among other things, there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Vidalia purchased power regulatory liability was reduced by $30.5 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

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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.
 
Pilgrim NRC Oversight and Planned Shutdown

In September 2015 the NRC placed Pilgrim in its “multiple/repetitive degraded cornerstone column,” or Column 4, of its Reactor Oversight Process Action Matrix due to its finding of continuing weaknesses in Pilgrim’s corrective action program that contributed to repeated unscheduled shutdowns and equipment failures. Entergy incurred costs of approximately $59 million through 2018 in support of Pilgrim’s response to the enhanced NRC inspection. In January 2019 the NRC found that Pilgrim had completed the corrective actions required to address the concerns that led to its placement in Column 4 and had demonstrated sustained improvement.

Entergy determined in October 2015 that it would close Pilgrim no later than June 1, 2019 because of poor market conditions that led to reduced revenues, a poor market design that failed to properly compensate nuclear generators for the benefits they provide, and increased operational costs. The decision came after management’s extensive analysis of the economics and operating life of the plant following the NRC’s decision to place the plant in Column 4. Entergy determined in April 2016 that it intended to refuel Pilgrim in 2017 and then cease operations May 31, 2019. Pilgrim currently has approximately 677 MW of Capacity Supply Obligations in ISO New England through May 2019.

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See Note 14 to the financial statements for discussion of the impairment of the Pilgrim plant and related long-lived assets.

Spent Nuclear Fuel Litigation

Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors.  Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982.  The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date.  Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense.  Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants.  Following the defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit Court of Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014. Management cannot predict the potential timing or magnitude of future spent fuel fee revisions that may occur.

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 2016 and 2018 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE.

In December 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $81 million in favor of Entergy Nuclear Indian Point 3 and Entergy Nuclear FitzPatrick in the first round Indian Point 3/FitzPatrick damages case, and Entergy received the payment from the U.S. Treasury in June 2016. The effect of recording the Indian Point 3 proceeds was a reduction to plant, other operation and maintenance expense, and depreciation expense. The Indian Point 3 damages awarded included $45 million related to costs previously capitalized and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $45 million, Entergy recorded $8 million as a reduction to previously-recorded depreciation expense. Entergy reduced its Indian Point 3 plant asset balance by the remaining $37 million. The effect of recording the FitzPatrick proceeds was a reduction to plant and other operation and maintenance expense. The FitzPatrick damages awarded included $32 million related to costs previously capitalized and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $32 million, Entergy recorded $1 million as a reduction to previously-recorded depreciation expense, a $10 million reduction to bring its remaining FitzPatrick plant asset balance to zero, and the excess was recorded as a reduction to other operations and maintenance expense. See Note 14 to the financial statements for further discussion on the fair value analysis performed for FitzPatrick and the related impairment charge.

In April 2016 the U.S. Court of Federal Claims issued a partial judgment in the amount of $42 million in favor of Entergy Louisiana and against the DOE in the first round River Bend damages case. Entergy Louisiana received payment from the U.S. Treasury in August 2016. The effects of recording the final judgment in the third quarter 2016 were reductions to plant, nuclear fuel expense, other operation and maintenance expense, and depreciation expense. The River Bend damages awarded included $17 million related to costs previously capitalized, $23 million related to costs previously recorded as nuclear fuel expense, and $2 million related to costs previously recorded as other operation

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and maintenance expense. Of the $17 million, Entergy Louisiana recorded $3 million as a reduction to previously-recorded depreciation expense. Entergy Louisiana reduced its River Bend plant asset balance by the remaining $14 million. In September 2016 the U.S. Court of Federal Claims issued a further judgment in the River Bend case in the amount of $5 million. Entergy Louisiana recorded a receivable for that amount, and subsequently received payment from the U.S. Treasury in January 2017. The River Bend damages awarded included $2 million related to costs previously recorded as nuclear fuel expense and $3 million related to costs previously recorded as other operation and maintenance expense. In May 2017 the U.S. Court of Federal Claims issued a final judgment in the first round River Bend damages case for $0.6 million, awarding certain cask loading costs that had not previously been adjudicated by the court.

In May 2016, Entergy Nuclear Vermont Yankee and the DOE entered into a stipulation agreement and the U.S. Court of Federal Claims issued a judgment in the amount of $19 million in favor of Entergy Nuclear Vermont Yankee and against the DOE in the second round Vermont Yankee damages case. Entergy received payment from the U.S. Treasury in June 2016. The effect of recording the proceeds was a reduction to other operation and maintenance expense and depreciation expense. The damages awarded included $15 million related to costs previously capitalized and $4 million related to costs previously recorded as other operation and maintenance expense. Of the $15 million, Entergy recorded $2 million as a reduction to previously-recorded depreciation expense. The remaining $13 million would have been recorded as a reduction to Vermont Yankee’s plant asset balance, but was recorded as a reduction to other operation and maintenance expense because Vermont Yankee’s plant asset balance is fully impaired.

In June 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $49 million in favor of System Energy and against the DOE in the second round Grand Gulf damages case. System Energy received payment from the U.S. Treasury in August 2016. The effects of recording the judgment in the third quarter 2016 were reductions to plant, nuclear fuel expense, other operation and maintenance expense, and depreciation expense. The amounts of Grand Gulf damages awarded related to System Energy’s 90% ownership of Grand Gulf included $16 million related to costs previously capitalized, $19 million related to costs previously recorded as nuclear fuel expense, and $9 million related to costs previously recorded as other operation and maintenance expense. Of the $16 million, System Energy recorded $5 million as a reduction to previously-recorded depreciation expense. System Energy reduced its Grand Gulf plant asset balance by the remaining $11 million.

In July 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $31 million in favor of Entergy Arkansas and against the DOE in the second round ANO damages case. Entergy Arkansas received payment from the U.S. Treasury in October 2016. The effects of recording the judgment were reductions to plant, nuclear fuel expense, and other operation and maintenance expense. The ANO damages awarded included $6 million related to costs previously capitalized, $19 million related to costs previously recorded as nuclear fuel expense, $5 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.

In August 2016 the U.S. Court of Federal Claims issued a partial judgment in the amount of $53 million in favor of Entergy Louisiana and against the DOE in the first round Waterford 3 damages case. Entergy Louisiana received payment from the U.S. Treasury in November 2016. The effects of recording the judgment were reductions to plant, nuclear fuel expense, other operation and maintenance expense, and depreciation expense. The Waterford 3 damages awarded included $41 million related to costs previously capitalized, $10 million related to costs previously recorded as nuclear fuel expense, and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $41 million, Entergy Louisiana recorded $3 million as a reduction to previously-recorded depreciation expense.

In September 2016 the U.S. Court of Federal Claims issued a judgment in the Entergy Nuclear Palisades case in the amount of $14 million. Entergy Nuclear Palisades recorded a receivable for that amount, and subsequently received payment from the U.S. Treasury in January 2017. The effects of recording the judgment were reductions to plant and other operation and maintenance expenses. The Palisades damages awarded included $11 million related to costs previously capitalized and $3 million related to costs previously recorded as other operation and maintenance expense. Of the $11 million, Entergy recorded $1 million as a reduction to previously-recorded depreciation expense.

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Entergy reduced its Palisades plant asset balance by the remaining $10 million. The Court previously issued a partial judgment in the case in the amount of $21 million, which was paid by the U.S. Treasury in October 2015.

In October 2016 the U.S. Court of Federal Claims issued a judgment in the second round Entergy Nuclear Indian Point 2 case in the amount of $34 million. Entergy Nuclear Indian Point 2 recorded a receivable for that amount, and subsequently received payment from the U.S. Treasury in January 2017. The effects of recording the judgment were reductions to plant and other operation and maintenance expenses. The Indian Point 2 damages awarded included $14 million related to costs previously capitalized, $15 million related to costs previously recorded as other operation and maintenance expense, $3 million related to previously recorded decommissioning expense, and $2 million related to costs previously recorded as taxes other than income taxes. Of the $14 million, Entergy recorded $3 million as a reduction to previously-recorded depreciation expense. Entergy reduced its Indian Point 2 plant asset balance by the remaining $11 million.

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 of recording the proceeds 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.

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 (prior to January 1, 2017, the primary level of insurance was $375 million).  If this amount is not sufficient to cover claims arising from an accident, the second level, Secondary Financial Protection, applies. In 2016 the NRC approved Vermont Yankee’s exemption request to lower their limits from $375 million to $100 million effective April 15, 2016.
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 $1.238 billion).  This retrospective 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

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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 2020.

Currently, 99 nuclear reactors are participating in the Secondary Financial Protection program.  Effective April 15, 2016 the NRC granted Vermont Yankee’s exemption request and it was allowed to withdraw from participation in this layer of financial protection. The Secondary Financial Protection program provides approximately $14 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 five nuclear power reactors and the ownership of the shutdown Indian Point 1 reactor and Big Rock Point facility.

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 occurrence that is shared among the plants. Property damage from earthquake and volcanic eruption 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 (Pilgrim, Palisades, Indian Point 2, Indian Point 3, Vermont Yankee, and Big Rock Point) have property damage insurance limits as follows: Vermont Yankee - $50 million per occurrence; Big Rock Point - $500 million per occurrence; Pilgrim and Palisades - $1.115 billion per occurrence; and Indian Point - $1.6 billion per occurrence. For losses that are considered non-nuclear in nature, the property damage insurance limit at Pilgrim, Palisades, and Indian Point is $500 million and at Vermont Yankee is $50 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, but property damage from earthquake and volcanic eruption at Indian Point is excluded from the first $500 million. Property damage from wind at Pilgrim 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, but property damage from flood, earthquake, and volcanic eruption at Pilgrim is excluded from the first $500 million. Property damage from wind, flood, earthquake, and volcanic eruption at Vermont Yankee, Palisades, and 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 $50 million.

The value of the insured property at the time of an accident at Pilgrim, Palisades, and Vermont Yankee has been changed from replacement cost to actual cash value.

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

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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. For non-nuclear events, the maximum indemnity, under this policy, is limited to $327.6 million per occurrence. 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, 2018, the maximum amounts of such possible assessments per occurrence were as follows:
 
Assessments
 
(In Millions)
Utility:
 
Entergy Arkansas
$42.3
Entergy Louisiana
$52.3
Entergy Mississippi
$0.12
Entergy New Orleans
$0.12
Entergy Texas
N/A
System Energy
$22.7
 
 
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.  

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

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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, including the Entergy Wholesale Commodities segment.  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 2020.

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 federal and state courts, primarily by contractor employees who worked in the 1940-1980s timeframe, primarily against Entergy Texas, and to a lesser extent the other Utility operating companies, as premises owners of power plants, for damages caused by alleged exposure to asbestos.  Many other defendants are named in these lawsuits as well.  Currently, there are approximately 200 lawsuits involving approximately 400 claimants.  Management believes that adequate provisions have been established to cover any exposure.  Additionally, negotiations continue with insurers to recover reimbursements.  Management believes that loss exposure has been and will continue to be handled so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position, results of operation, or cash flows of the Utility operating companies.

Grand Gulf - Related Agreements

Capital Funds Agreement (Entergy Corporation and System Energy)

System Energy has entered into agreements with Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans whereby they are obligated to purchase their respective entitlements of capacity and energy from System Energy’s interest in Grand Gulf, and to make payments that, together with other available funds, are adequate to cover System Energy’s operating expenses.  System Energy would have to secure funds from other sources, including Entergy Corporation’s obligations under the Capital Funds Agreement, to cover any shortfalls from payments received from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under these agreements.


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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 2018 under the agreement are approximately $14.1 million for Entergy Arkansas, $5.6 million for Entergy Louisiana, $12.2 million for Entergy Mississippi, and $6.9 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 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.



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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 recovered in rates:
 
December 31,
 
2018
 
2017
 
(In Millions)
Entergy Arkansas
$138.3
 
$176.9
Entergy Louisiana
($18.8)
 
($32.4)
Entergy Mississippi
$63.5
 
$91.6
Entergy New Orleans
$49.3
 
$44.8
Entergy Texas
$50.9
 
$55.2
System Energy
$76.4
 
$67.9


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The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2018 and 2017 by Entergy were as follows:
 
Liabilities as
of December 31,
2017
 
 
 
Accretion
 
Change in
Cash Flow
Estimate
 
 
 
Spending
 
Liabilities as
of December 31,
2018
 
 
(In Millions)
 
Utility:
 
 
 
 
 
 
 
 
 
 
Entergy Arkansas

$981.2

 

$60.4

 

$8.9

 

($2.1
)
 

$1,048.4

 
Entergy Louisiana
1,140.5

 
63.2

 
85.4

 
(8.8
)
 
1,280.3

 
Entergy Mississippi
9.2

 
0.5

 
0.5

 
(1.0
)
 
9.2

 
Entergy New Orleans
3.1

 
0.2

 
—

 
—

 
3.3

 
Entergy Texas
6.8

 
0.4

 
—

 
—

 
7.2

 
System Energy
861.7

 
34.3

 
—

 
—

 
896.0

 
Total
3,002.5

 
159.0

 
94.8

 
(11.9
)
 
3,244.4

 
 
 
 
 
 
 
 
 
 
 
 
Entergy Wholesale Commodities:
 
 
 
 
 
 
 
 
Big Rock Point
38.9

 
3.2

 
—

 
(2.4
)
 
39.7

 
Indian Point 1
217.6

 
18.6

 
—

 
(8.3
)
 
227.9

 
Indian Point 2
708.7

 
60.6

 
—

 
(1.3
)
 
768.0

 
Indian Point 3
694.5

 
58.0

 
—

 
(1.9
)
 
750.6

 
Palisades
470.4

 
39.6

 
—

 
(2.0
)
 
508.0

 
Pilgrim
651.4

 
58.6

 
117.5

 
(11.0
)
 
816.5

 
Vermont Yankee
401.5

 
25.9

 
293.0

 
(152.5
)
 
567.9

(b)
Other (a)
0.3

 
—

 
0.1

 
—

 
0.4

 
Total
3,183.3

 
264.5

 
410.6

 
(179.4
)
 
3,679.0

 
 
 
 
 
 
 
 
 
 
 
 
Entergy Total

$6,185.8

 

$423.5

 

$505.4

 

($191.3
)
 

$6,923.4

 



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Liabilities as
of December 31,
2016
 
 
 
Accretion
 
Change in
Cash Flow
Estimate
 
 
 
Spending
 
Dispositions
 
Liabilities as
of December 31,
2017
 
(In Millions)
Utility:
 
 
 
 
 
 
 
 
 
 
 
Entergy Arkansas

$924.4

 

$56.8

 

$—

 

$—

 

$—

 

$981.2

Entergy Louisiana
1,082.7

 
57.8

 
—

 
—

 
—

 
1,140.5

Entergy Mississippi
8.7

 
0.5

 
—

 
—

 
—

 
9.2

Entergy New Orleans
2.9

 
0.2

 
—

 
—

 
—

 
3.1

Entergy Texas
6.5

 
0.3

 
—

 
—

 
—

 
6.8

System Energy
854.2

 
43.4

 
(35.9
)
 
—

 
—

 
861.7

Total
2,879.4

 
159.0

 
(35.9
)
 
—

 
—

 
3,002.5

 
 
 
 
 
 
 
 
 
 
 
 
Entergy Wholesale Commodities:
 
 
 
 
 
 
 
 
 
Big Rock Point
37.9

 
3.1

 
—

 
(2.1
)
 
—

 
38.9

FitzPatrick
714.3

(c)
13.9

 
—

 
(0.9
)
 
(727.3
)
(d)
—

Indian Point 1
207.6

 
17.7

 
—

 
(7.7
)
 
—

 
217.6

Indian Point 2
653.1

 
55.8

 
—

 
(0.2
)
 
—

 
708.7

Indian Point 3
641.1

 
53.5

 
—

 
(0.1
)
 
—

 
694.5

Palisades
500.3

 
41.3

 
(68.7
)
 
(2.5
)
 
—

 
470.4

Pilgrim
602.3

 
52.8

 
—

 
(3.7
)
 
—

 
651.4

Vermont Yankee
470.5

 
34.4

 
—

 
(103.4
)
 
—

 
401.5

Other (a)
0.3

 
—

 
—

 
—

 
—

 
0.3

Total
3,827.4

 
272.5

 
(68.7
)
 
(120.6
)
 
(727.3
)
 
3,183.3

 
 
 
 
 
 
 
 
 
 
 
 
Entergy Total

$6,706.8

 

$431.5

 

($104.6
)
 

($120.6
)
 

($727.3
)
 

$6,185.8


(a)
See “Coal Combustion Residuals” below for additional discussion regarding the asset retirement obligations related to coal combustion residuals management.
(b)
The Vermont Yankee asset retirement obligation was classified as held for sale within other non-current liabilities on the consolidated balance sheet as of December 31, 2018. See Note 14 to the financial statements for discussion of the sale of the Vermont Yankee plant to NorthStar in January 2019.
(c)
The FitzPatrick asset retirement obligation was classified as held for sale within other non-current liabilities on the consolidated balance sheet as of December 31, 2016. See Note 14 to the financial statements for discussion of the sale of the FitzPatrick plant to Exelon in March 2017.
(d)
See Note 14 to the financial statements for discussion of the sale of the FitzPatrick plant to Exelon in March 2017.

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 2018, 2017, and 2016, Entergy updated decommissioning cost estimates for certain nuclear power plants.


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Utility

In the second quarter 2017, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $35.9 million reduction in its decommissioning cost liability, along with a corresponding reduction in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the first quarter 2018, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for River Bend as a result of a revised decommissioning cost study. The revised estimate resulted in an $85.4 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 life of the unit.

Entergy Wholesale Commodities

Indian Point

In the fourth quarter 2016, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liabilities for Indian Point 1, Indian Point 2, and Indian Point 3 as a result of revised decommissioning cost studies. The revised estimates resulted in a $392 million increase in the decommissioning cost liabilities, along with a corresponding increase in the related asset retirement cost assets. The increase in the estimated decommissioning cost liabilities resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations of the Indian Point 2 plant no later than April 2020 and the Indian Point 3 plant no later than April 2021. The asset retirement cost assets were included in the carrying value that was written down to fair value in the fourth quarter 2016. See Note 14 to the financial statements for discussion of the impairment of the value and planned shutdown of Indian Point Energy Center.

Palisades

In the fourth quarter 2016, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Palisades as a result of a revised decommissioning cost study. The revised estimate resulted in a $129 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations of the plant on October 1, 2018, subject to regulatory approval. The asset retirement cost asset was included in the Palisades carrying value that was written down to fair value in the fourth quarter 2016. See Note 14 to the financial statements for discussion of the impairment of the value and planned shutdown of the Palisades plant.

In the third quarter 2017, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Palisades. The revised estimate resulted in a $68.7 million reduction in its decommissioning cost liability, along with a corresponding reduction in the plant asset. The reduction in its estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to continue to operate the plant until May 31, 2022.

Pilgrim

The Pilgrim plant is expected to cease 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.


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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.

NRC Filings for Planned Shutdown Activities

As the Entergy Wholesale Commodities nuclear plants individually approach and begin decommissioning, the Entergy Wholesale Commodities plant owners will submit filings with the NRC for planned shutdown activities. These filings with the NRC will determine whether any other financial assurance may be required. The plants’ 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, the Entergy Wholesale Commodities 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, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met.

Decommissioning Trust Funds and Regulatory Assets

Entergy maintains decommissioning trust funds that are committed to meeting its obligations for the costs of decommissioning the nuclear power plants.  The fair values of the decommissioning trust funds and the related asset retirement obligation regulatory assets (liabilities) of Entergy as of December 31, 2018 and 2017 are as follows:
 
2018
 
2017
 
Decommissioning
Trust Fair Values
 
Regulatory
Asset (Liability)
 
Decommissioning
Trust Fair Values
 
Regulatory
Asset (Liability)
 
(In Millions)
 
(In Millions)
Utility:
 
 
 
 
 
 
 
ANO 1 and ANO 2

$912.0

 
$375.9
 

$944.9

 

$337.9

River Bend

$803.4

 
($27.4)
 

$818.2

 

($30.6
)
Waterford 3

$481.6

 
$204.9
 

$493.9

 

$188.9

Grand Gulf

$869.5

 
$186.9
 

$905.7

 

$169.1

Entergy Wholesale Commodities

$3,853.7

 
$—
 

$4,049.3

 

$—


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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 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. In September 2017 the EPA agreed to reconsider certain provisions of the coal combustion residuals (CCR) rule in light of the WIIN Act. In March 2018 the EPA published its proposed revisions to the CCR rule with comments due at the end of April 2018. In July 2018 the EPA released its initial revisions extending certain deadlines and incorporating some risk-based standards.  The EPA is expected to release additional revisions in another rulemaking.  In August 2018 the D.C. Circuit vacated several provisions of the CCR rule on the basis that they were inconsistent with the Resource Conservation and Recovery Act and remanded the matter to the EPA to conduct further rulemaking.

In 2018 revisions to the CCR asset retirement obligations were made as a result of revised closure and post-closure cost estimates. The revised estimates resulted in increases of $8.9 million at Entergy Arkansas, $0.5 million at Entergy Mississippi, and $0.1 million at Entergy Wholesale Commodities in decommissioning cost liabilities, along with corresponding increases in related asset retirement cost assets that will be depreciated over the remaining useful lives of the respective units.



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NOTE 10.   LEASES  (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

General

As of December 31, 2018, Entergy had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities with minimum lease payments as follows (excluding power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf sale and leaseback transaction, all of which are discussed elsewhere):
 
Year
 
Operating
Leases
 
Capital
Leases
 
 
(In Thousands)
2019
 

$94,043

 

$2,887

2020
 
82,191

 
2,887

2021
 
75,147

 
2,887

2022
 
60,808

 
2,887

2023
 
47,391

 
2,887

Years thereafter
 
88,004

 
16,117

Minimum lease payments
 
447,584

 
30,552

Less:  Amount representing interest
 
—

 
8,555

Present value of net minimum lease payments
 

$447,584

 

$21,997


Total rental expenses for all leases (excluding power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf and Waterford 3 sale and leaseback transactions) amounted to $47.8 million in 2018, $53.1 million in 2017, and $44.4 million in 2016.

As of December 31, 2018 the Registrant Subsidiaries had non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities with minimum lease payments as follows (excluding power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf lease obligation, all of which are discussed elsewhere):

Operating Leases
 
 
Year
 
 
Entergy
Arkansas
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
(In Thousands)
2019
 

$20,421

 

$25,970

 

$9,344

 

$2,493

 

$5,744

2020
 
13,918

 
21,681

 
8,763

 
2,349

 
4,431

2021
 
11,931

 
19,514

 
7,186

 
1,901

 
3,625

2022
 
9,458

 
15,756

 
5,675

 
1,314

 
2,218

2023
 
7,782

 
12,092

 
2,946

 
1,043

 
1,561

Years thereafter
 
23,297

 
22,003

 
4,417

 
2,323

 
2,726

Minimum lease payments
 

$86,807

 

$117,016

 

$38,331

 

$11,423

 

$20,305



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Rental Expenses
 
 
Year
 
 
Entergy
Arkansas
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
 
(In Millions)
2018
 

$6.2

 

$20.2

 

$4.6

 

$2.5

 

$3.1

 

$1.9

2017
 

$7.5

 

$23.0

 

$5.6

 

$2.5

 

$3.4

 

$2.2

2016
 

$8.0

 

$17.8

 

$4.0

 

$0.9

 

$2.8

 

$1.6


In addition to the above 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, $4 million in 2017, and $3.4 million in 2016 for Entergy Arkansas and $0.4 million in 2018, $0.3 million in 2017, and $0.3 million in 2016 for Entergy Louisiana.  Oil tank facilities lease payments for Entergy Mississippi were $0.1 million in 2018, $1.6 million in 2017, and $1.6 million in 2016.

On January 1, 2019, Entergy implemented ASU No. 2016-02, “Leases (Topic 842)” along with the practical expedients provided by ASU No. 2018-01, “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842,” and ASU No. 2018-11, “Leases (Topic 842): Targeted Improvements.”  See Note 1 to the financial statements for further discussion of ASU No. 2016-02.

Power Purchase Agreements

As of December 31, 2018, Entergy Texas had a power purchase agreement that is accounted for as an operating lease under the accounting standards. The lease payments are recovered in fuel expense in accordance with regulatory treatment. The minimum lease payments under the power purchase agreement are as follows:

Year
 
Entergy Texas (a)
 
Entergy
 
 
(In Thousands)
2019
 

$31,159

 

$31,159

2020
 
31,876

 
31,876

2021
 
32,609

 
32,609

2022
 
10,180

 
10,180

Minimum lease payments
 

$105,824

 

$105,824


(a)
Amounts reflect 100% of minimum payments. Under a separate contract, which expires May 31, 2022, Entergy Louisiana purchases 50% of the capacity and energy from the power purchase agreement from Entergy Texas.

Total capacity expense under the power purchase agreement accounted for as an operating lease at Entergy Texas was $30.5 million in 2018, $34.1 million in 2017, and $26.1 million in 2016.

Sales and Leaseback Transactions

Waterford 3 Lease Obligation

In 1989, in three separate but substantially identical transactions, Entergy Louisiana sold and leased back undivided interests in Waterford 3 for the aggregate sum of $353.6 million.  The leases were scheduled to expire in July 2017.  Entergy Louisiana was required to report the sale-leaseback as a financing transaction in its financial statements.

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In December 2015, Entergy Louisiana agreed to purchase the undivided interests in Waterford 3 that were previously being leased. The purchase was accomplished in a two-step transaction in which Entergy Louisiana first acquired the equity participant’s beneficial interest in the leased assets, followed by a termination of the leases and transfer of the leased assets to Entergy Louisiana when the outstanding lessor debt is paid.

In March 2016, Entergy Louisiana completed the first step in the two-step transaction by acquiring the equity participant’s beneficial interest in the leased assets. Entergy Louisiana paid $60 million in cash and $52 million through the issuance of a non-interest bearing collateral trust mortgage note, payable in installments through July 2017. Entergy Louisiana continued to make payments on the lessor debt that remained outstanding and which matured in January 2017. The combination of payments on the $52 million collateral trust mortgage note issued and the debt service on the lessor debt was equal in timing and amount to the remaining lease payments due from the closing of the transaction through the end of the lease term in July 2017.

Throughout the term of the lease, Entergy Louisiana had accrued a liability for the amount it expected to pay to retain the use of the undivided interests in Waterford 3 at the end of the lease term. Since the sale-leaseback transaction was accounted for as a financing transaction, the accrual of this liability was accounted for as additional interest expense. As of December 2015, the balance of this liability was $62.7 million. Upon entering into the agreement to purchase the equity participant’s beneficial interest in the undivided interests, Entergy Louisiana reduced the balance of the liability to $60 million, and recorded the $2.7 million difference as a credit to interest expense. The $60 million remaining liability was eliminated upon payment of the cash portion of the purchase price in 2016.

As of December 31, 2016, Entergy Louisiana, in connection with the Waterford 3 lease obligation, had a future minimum lease payment (reflecting an interest rate of 8.09%) of $57.5 million, including $2.3 million in interest, due January 2017 that was recorded as long-term debt.

In February 2017 the leases were terminated and the leased assets were conveyed to Entergy Louisiana.

Grand Gulf Lease Obligations

In 1988, in two separate but substantially identical transactions, System Energy sold and leased back undivided ownership interests in Grand Gulf for the aggregate sum of $500 million.  The initial term of the leases expired in July 2015.  System Energy renewed the leases in December 2013 for fair market value with renewal terms expiring in July 2036. At the end of the new lease renewal terms, System Energy has the option to repurchase the leased interests in Grand Gulf or renew the leases at fair market value.  In the event that System Energy does not renew or purchase the interests, System Energy would surrender such interests and their associated entitlement of Grand Gulf’s capacity and energy.

System Energy is required to report the sale-leaseback as a financing transaction in its financial statements.  For financial reporting purposes, System Energy expenses the interest portion of the lease obligation and the plant depreciation.  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 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, 2018 and 2017.


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As of December 31, 2018, 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)
 
 
2019

$17,188

2020
17,188

2021
17,188

2022
17,188

2023
17,188

Years thereafter
223,437

Total
309,377

Less: Amount representing interest
275,025

Present value of net minimum lease payments

$34,352



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)

Entergy implemented ASU No. 2017-07, “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost” effective January 1, 2018. The ASU requires entities to report the service cost component of defined benefit pension cost and postretirement benefit cost (net benefit cost) in the same line item as other compensation costs arising from services rendered during the period.  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. The amendment regarding the presentation of net benefit cost was required to be applied retrospectively for all periods presented. In addition, the ASU allows only the service cost component of net benefit cost to be eligible for capitalization on a prospective basis. In accordance with the regulatory treatment of net benefit cost of the Registrant Subsidiaries, a regulatory asset/liability will be recorded in other regulatory assets/liabilities for the non-service cost components of net benefit cost that would have been capitalized.

Qualified Pension Plans

Entergy has eight 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.  Effective as of the close of business on December 31, 2016, the Entergy Corporation Retirement Plan IV for Non-Bargaining Employees (Non-Bargaining Plan IV) was merged with and into Non-Bargaining Plan II. At the close of business on December 31, 2016, the liabilities for the accrued benefits and the assets attributable to such liabilities of all participants in Non-Bargaining Plan IV were assumed by and transferred to Non-Bargaining Plan II. There was no loss of vesting or benefit options or reduction of accrued benefits to affected participants as a result of this plan merger. Non-bargaining employees whose most recent date of hire is after June 30, 2014 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

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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 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.

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.


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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 2018, 2017, and 2016 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:
 
2018
 
2017
 
2016
 
(In Thousands)
Net periodic pension cost:
 

 
 

 
 

Service cost - benefits earned during the period

$155,010

 

$133,641

 

$143,244

Interest cost on projected benefit obligation
267,415

 
260,824

 
261,613

Expected return on assets
(442,142
)
 
(408,225
)
 
(389,465
)
Amortization of prior service cost
398

 
261

 
1,079

Recognized net loss
274,104

 
227,720

 
195,298

Curtailment loss
—

 
—

 
3,084

Settlement charges
828

 
—

 
—

Net periodic pension costs

$255,613

 

$214,221

 

$214,853

Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
 
 
 
 
 
Arising this period:
 
 
 
 
 
Net loss

$394,951

 

$368,067

 

$203,229

Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
 
 
 
 
 
Amortization of prior service cost
(398
)
 
(261
)
 
(1,079
)
Acceleration of prior service cost to curtailment
—

 
—

 
(1,045
)
Amortization of net loss
(274,932
)
 
(227,720
)
 
(195,298
)
Total

$119,621

 

$140,086

 

$5,807

Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)

$375,234

 

$354,307

 

$220,660

Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year:
 
 
 
 
 
Prior service cost

$—

 

$398

 

$261

Net loss

$233,677

 

$274,104

 

$227,720


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The Registrant Subsidiaries’ total 2018, 2017, and 2016 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:
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 (income)/cost, regulatory asset, and/or AOCI (before tax)
 

$63,940

 

$35,950

 

$15,598

 

$324

 

$17,776

 

($2,313
)
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
 

$47,361

 

$46,571

 

$12,416

 

$6,117

 

$9,335

 

$11,400



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Notes to Financial Statements


2017
 
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
 

$20,358

 

$27,698

 

$5,890

 

$2,500

 

$5,455

 

$6,145

Interest cost on projected benefit obligation
 
51,776

 
59,235

 
14,927

 
7,163

 
13,569

 
12,364

Expected return on assets
 
(81,707
)
 
(92,067
)
 
(24,526
)
 
(11,199
)
 
(24,722
)
 
(18,650
)
Recognized net loss
 
46,560

 
49,417

 
12,213

 
6,632

 
9,241

 
11,857

Net pension cost
 

$36,987

 

$44,283

 

$8,504

 

$5,096

 

$3,543

 

$11,716

Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
 
 
 
 
 
 
 
 
 
 
 
 
Arising this period:
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
 

$51,569

 

$57,510

 

$14,681

 

$8,601

 

$1,109

 

$27,733

Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
 
 
 
 
 
 
 
 
 
 
 
 
Amortization of net loss
 
(46,560
)
 
(49,417
)
 
(12,213
)
 
(6,632
)
 
(9,241
)
 
(11,857
)
Total
 

$5,009

 

$8,093

 

$2,468

 

$1,969

 

($8,132
)
 

$15,876

Total recognized as net periodic pension (income)/ cost, regulatory asset, and/or AOCI (before tax)
 

$41,996

 

$52,376

 

$10,972

 

$7,065

 

($4,589
)
 

$27,592

Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
 

$53,650

 

$57,800

 

$14,438

 

$7,816

 

$10,503

 

$14,859



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Notes to Financial Statements


2016
 
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
 

$20,724

 

$28,194

 

$6,250

 

$2,625

 

$5,664

 

$6,263

Interest cost on projected benefit obligation
 
52,219

 
59,478

 
15,245

 
7,256

 
14,228

 
11,966

Expected return on assets
 
(79,087
)
 
(88,383
)
 
(23,923
)
 
(10,748
)
 
(24,248
)
 
(17,836
)
Recognized net loss
 
43,745

 
47,783

 
11,938

 
6,460

 
9,358

 
10,415

Net pension cost
 

$37,601

 

$47,072

 

$9,510

 

$5,593

 

$5,002

 

$10,808

Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
 
 
 
 
 
 
 
 
 
 
 
 
Arising this period:
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
 

$60,968

 

$46,742

 

$10,942

 

$5,463

 

$3,816

 

$20,805

Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
 
 
 
 
 
 
 
 
 
 
 
 
Amortization of net loss
 
(43,745
)
 
(47,783
)
 
(11,938
)
 
(6,460
)
 
(9,358
)
 
(10,415
)
Total
 

$17,223

 

($1,041
)
 

($996
)
 

($997
)
 

($5,542
)
 

$10,390

Total recognized as net periodic pension (income)/cost, regulatory asset, and/or AOCI (before tax)
 

$54,824

 

$46,031

 

$8,514

 

$4,596

 

($540
)
 

$21,198

Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
 

$46,560

 

$49,417

 

$12,213

 

$6,632

 

$9,241

 

$11,857



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Notes to Financial Statements


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, 2018 and 2017 are as follows:
 
2018
 
2017
 
(In Thousands)
Change in Projected Benefit Obligation (PBO)
 

 
 

Balance at January 1

$7,987,087

 

$7,142,567

Service cost
155,010

 
133,641

Interest cost
267,415

 
260,824

Settlement lump sum payments
(1,794
)
 
—

Actuarial (gain)/loss
(395,242
)
 
767,849

Employee contributions
—

 
40

Benefits paid
(607,559
)
 
(317,834
)
Balance at December 31

$7,404,917

 

$7,987,087

Change in Plan Assets
 

 
 

Fair value of assets at January 1

$6,071,316

 

$5,171,202

Actual return on plan assets
(348,051
)
 
808,007

Employer contributions
383,503

 
409,901

Employee contributions
—

 
40

Settlements
(1,794
)
 
—

Benefits paid
(607,559
)
 
(317,834
)
Fair value of assets at December 31

$5,497,415

 

$6,071,316

Funded status

($1,907,502
)
 

($1,915,771
)
Amount recognized in the balance sheet
 
 
 
Non-current liabilities

($1,907,502
)
 

($1,915,771
)
Amount recognized as a regulatory asset
 
 
 
Net loss

$2,468,987

 

$2,418,206

Amount recognized as AOCI (before tax)
 
 
 
Prior service cost

$—

 

$398

Net loss
737,004

 
667,766

 

$737,004

 

$668,164



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Notes to Financial Statements


Qualified pension obligations, plan assets, funded status, amounts recognized in the Balance Sheets for the Registrant Subsidiaries as of December 31, 2018 and 2017 are as follows:
2018
 
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
 

$1,580,756

 

$1,785,700

 

$457,549

 

$217,896

 

$410,720

 

$384,049

Service cost
 
24,757

 
33,783

 
7,286

 
2,693

 
6,356

 
7,102

Interest cost
 
52,017

 
59,761

 
15,075

 
7,253

 
13,390

 
12,907

Actuarial loss
 
(79,621
)
 
(133,520
)
 
(26,611
)
 
(18,844
)
 
(21,656
)
 
(37,842
)
Benefits paid
 
(134,101
)
 
(145,808
)
 
(39,210
)
 
(17,808
)
 
(39,206
)
 
(27,182
)
Balance at December 31
 

$1,443,808

 

$1,599,916

 

$414,089

 

$191,190

 

$369,604

 

$339,034

Change in Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair value of assets at
January 1
 

$1,205,668

 

$1,365,741

 

$360,842

 

$165,747

 

$363,523

 

$274,432

Actual return on plan assets
 
(66,787
)
 
(75,926
)
 
(19,849
)
 
(9,221
)
 
(19,686
)
 
(15,520
)
Employer contributions
 
64,062

 
71,919

 
14,933

 
7,250

 
10,883

 
13,786

Benefits paid
 
(134,101
)
 
(145,808
)
 
(39,210
)
 
(17,808
)
 
(39,206
)
 
(27,182
)
Fair value of assets at December 31
 

$1,068,842

 

$1,215,926

 

$316,716

 

$145,968

 

$315,514

 

$245,516

Funded status
 

($374,966
)
 

($383,990
)
 

($97,373
)
 

($45,222
)
 

($54,090
)
 

($93,518
)
Amounts recognized in the balance sheet (funded status)
 
 
 
 
 
 
 
 
 
 
 
 
Non-current liabilities
 

($374,966
)
 

($383,990
)
 

($97,373
)
 

($45,222
)
 

($54,090
)
 

($93,518
)
Amounts recognized as regulatory asset
 
 
 
 
 
 
 
 
 
 
 
 

Net loss
 

$727,703

 

$686,138

 

$196,683

 

$91,448

 

$159,030

 

$168,559

Amounts recognized as AOCI (before tax)
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
 

$—

 

$43,796

 

$—

 

$—

 

$—

 

$—



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Notes to Financial Statements


2017
 
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
 

$1,454,310

 

$1,624,233

 

$419,201

 

$197,464

 

$386,366

 

$335,381

Service cost
 
20,358

 
27,698

 
5,890

 
2,500

 
5,455

 
6,145

Interest cost
 
51,776

 
59,235

 
14,927

 
7,163

 
13,569

 
12,364

Actuarial loss
 
131,729

 
147,704

 
38,726

 
19,507

 
25,339

 
45,471

Benefits paid
 
(77,417
)
 
(73,170
)
 
(21,195
)
 
(8,738
)
 
(20,009
)
 
(15,312
)
Balance at December 31
 

$1,580,756

 

$1,785,700

 

$457,549

 

$217,896

 

$410,720

 

$384,049

Change in Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair value of assets at January 1
 

$1,041,592

 

$1,169,147

 

$314,349

 

$142,488

 

$317,576

 

$235,144

Actual return on plan assets
 
161,868

 
182,261

 
48,572

 
22,104

 
48,952

 
36,387

Employer contributions
 
79,625

 
87,503

 
19,116

 
9,893

 
17,004

 
18,213

Benefits paid
 
(77,417
)
 
(73,170
)
 
(21,195
)
 
(8,738
)
 
(20,009
)
 
(15,312
)
Fair value of assets at December 31
 

$1,205,668

 

$1,365,741

 

$360,842

 

$165,747

 

$363,523

 

$274,432

Funded status
 

($375,088
)
 

($419,959
)
 

($96,707
)
 

($52,149
)
 

($47,197
)
 

($109,617
)
Amounts recognized in the balance sheet (funded status)
 
 
 
 
 
 
 
 
 
 
 
 
Non-current liabilities
 

($375,088
)
 

($419,959
)
 

($96,707
)
 

($52,149
)
 

($47,197
)
 

($109,617
)
Amounts recognized as regulatory asset
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
 

$706,783

 

$701,324

 

$191,877

 

$96,913

 

$145,412

 

$185,774

Amounts recognized as AOCI  (before tax)
 
 

 
 
 
 
 
 
 
 
 
 
Net loss
 

$—

 

$44,765

 

$—

 

$—

 

$—

 

$—


Accumulated Pension Benefit Obligation

The accumulated benefit obligation for Entergy’s qualified pension plans was $6.9 billion and $7.4 billion at December 31, 2018 and 2017, respectively.

The qualified pension accumulated benefit obligation for each of the Registrant Subsidiaries for their employees as of December 31, 2018 and 2017 was as follows:
 
December 31,
 
2018
 
2017
 
(In Thousands)
Entergy Arkansas

$1,362,425

 

$1,492,876

Entergy Louisiana

$1,481,158

 

$1,652,939

Entergy Mississippi

$387,635

 

$430,268

Entergy New Orleans

$179,907

 

$205,316

Entergy Texas

$347,852

 

$387,083

System Energy

$317,848

 

$359,258



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Notes to Financial Statements


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.

Entergy uses a December 31 measurement date for its postretirement benefit plans.

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 investments is allocated to the plans and participating Registrant Subsidiary based on their portion of net assets in the pooled accounts.


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Notes to Financial Statements


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 2018, 2017, and 2016 other postretirement benefit costs, including amounts capitalized and amounts recognized as a regulatory asset and/or other comprehensive income, included the following components:
 
2018
 
2017
 
2016
 
(In Thousands)
Other postretirement costs:
 
 
 
 
 
Service cost - benefits earned during the period

$27,129

 

$26,915

 

$32,291

Interest cost on accumulated postretirement benefit obligation (APBO)
50,725

 
55,838

 
56,331

Expected return on assets
(41,493
)
 
(37,630
)
 
(41,820
)
Amortization of prior service credit
(37,002
)
 
(41,425
)
 
(45,490
)
Recognized net loss
13,729

 
21,905

 
18,214

Net other postretirement benefit cost

$13,088

 

$25,603

 

$19,526

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

$—

 

($2,564
)
 

($20,353
)
Net (gain)/loss
(274,354
)
 
(66,922
)
 
49,805

Amounts reclassified from regulatory asset and /or AOCI to net periodic benefit cost in the current year:
 
 
 
 
 
Amortization of prior service credit
37,002

 
41,425

 
45,490

Amortization of net loss
(13,729
)
 
(21,905
)
 
(18,214
)
Total

($251,081
)
 

($49,966
)
 

$56,728

Total recognized as net periodic benefit income/(cost), regulatory asset, and/or AOCI (before tax)

($237,993
)
 

($24,363
)
 

$76,254

Estimated amortization amounts from regulatory asset and/or AOCI to net periodic benefit cost in the following year
 
 
 
 
 
Prior service credit

($35,377
)
 

($37,002
)
 

($41,425
)
Net loss

$1,430

 

$13,729

 

$21,905



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Notes to Financial Statements


Total 2018, 2017, and 2016 other postretirement benefit costs of the Registrant Subsidiaries, including amounts capitalized and deferred, for their employees included the following components:
2018
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
 
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 pension 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 cost, regulatory asset, and/or AOCI (before tax)
 

($38,431
)
 

($55,870
)
 

($8,992
)
 

($4,046
)
 

($15,272
)
 

($6,589
)
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost  in the following year
 
 
 
 
 
 
 
 
 
 
 
 
Prior service credit
 

($4,950
)
 

($7,349
)
 

($1,756
)
 

($682
)
 

($2,243
)
 

($1,450
)
Net (gain)/loss
 

$576

 

($695
)
 

$723

 

$231

 

$485

 

$354



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Notes to Financial Statements


2017
 
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
 

$3,451

 

$6,373

 

$1,160

 

$567

 

$1,488

 

$1,278

Interest cost on APBO
 
9,020

 
12,101

 
2,759

 
1,874

 
4,494

 
2,236

Expected return on assets
 
(15,836
)
 
—

 
(4,801
)
 
(4,635
)
 
(8,720
)
 
(2,869
)
Amortization of prior service credit
 
(5,110
)
 
(7,735
)
 
(1,823
)
 
(745
)
 
(2,316
)
 
(1,513
)
Recognized net loss
 
4,460

 
1,859

 
1,675

 
418

 
3,303

 
1,560

Net other postretirement benefit (income)/cost
 

($4,015
)
 

$12,598

 

($1,030
)
 

($2,521
)
 

($1,751
)
 

$692

Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
 
 
 
 
 
 
 
 
 
 
 
 
Arising this period:
 
 
 
 
 
 
 
 
 
 
 
 
Net (gain)/loss
 

($29,534
)
 

($1,256
)
 

$506

 

($7,342
)
 

($22,255
)
 

($5,459
)
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension 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
 
(4,460
)
 
(1,859
)
 
(1,675
)
 
(418
)
 
(3,303
)
 
(1,560
)
Total
 

($28,884
)
 

$4,620

 

$654

 

($7,015
)
 

($23,242
)
 

($5,506
)
Total recognized as net periodic other postretirement income/(cost), regulatory asset, and/or AOCI (before tax)
 

($32,899
)
 

$17,218

 

($376
)
 

($9,536
)
 

($24,993
)
 

($4,814
)
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost  in the following year
 
 
 
 
 
 
 
 
 
 
 
 
Prior service credit
 

($5,110
)
 

($7,735
)
 

($1,823
)
 

($745
)
 

($2,316
)
 

($1,513
)
Net loss
 

$1,154

 

$1,550

 

$1,508

 

$137

 

$823

 

$932



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Notes to Financial Statements


2016
 
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
 

$3,913

 

$7,476

 

$1,543

 

$622

 

$1,590

 

$1,337

Interest cost on APBO
 
9,297

 
13,041

 
2,835

 
1,791

 
4,154

 
2,117

Expected return on assets
 
(17,855
)
 
—

 
(5,517
)
 
(4,617
)
 
(9,575
)
 
(3,257
)
Amortization of prior service credit
 
(5,472
)
 
(7,787
)
 
(934
)
 
(745
)
 
(2,722
)
 
(1,570
)
Recognized net loss
 
4,256

 
2,926

 
893

 
146

 
2,148

 
1,149

Net other postretirement benefit (income)/cost
 

($5,861
)
 

$15,656

 

($1,180
)
 

($2,803
)
 

($4,405
)
 

($224
)
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 the period
 

($1,007
)
 

($4,647
)
 

($6,219
)
 

$—

 

$—

 

$—

Net (gain)/loss
 
3,331

 
(13,117
)
 
8,715

 
5,717

 
13,378

 
4,997

Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
 
 
 
 
 
 
 
 
 
 
 
 
Amortization of prior service credit
 
5,472

 
7,787

 
934

 
745

 
2,722

 
1,570

Amortization of net loss
 
(4,256
)
 
(2,926
)
 
(893
)
 
(146
)
 
(2,148
)
 
(1,149
)
Total
 

$3,540

 

($12,903
)
 

$2,537

 

$6,316

 

$13,952

 

$5,418

Total recognized as net periodic other postretirement income/(cost), regulatory asset, and/or AOCI (before tax)
 

($2,321
)
 

$2,753

 

$1,357

 

$3,513

 

$9,547

 

$5,194

Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost  in the following year
 
 
 
 
 
 
 
 
 
 
 
 
Prior service credit
 

($5,110
)
 

($7,739
)
 

($1,824
)
 

($745
)
 

($2,316
)
 

($1,513
)
Net loss
 

$4,460

 

$1,859

 

$1,675

 

$418

 

$3,303

 

$1,560



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Notes to Financial Statements


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, 2018 and 2017 are as follows:
 
2018
 
2017
 
(In Thousands)
Change in APBO
 

 
 

Balance at January 1

$1,563,487

 

$1,568,963

Service cost
27,129

 
26,915

Interest cost
50,725

 
55,838

Plan amendments
—

 
(2,564
)
Plan participant contributions
37,049

 
35,080

Actuarial gain
(346,429
)
 
(23,409
)
Benefits paid
(99,785
)
 
(97,829
)
Medicare Part D subsidy received
443

 
493

Balance at December 31

$1,232,619

 

$1,563,487

Change in Plan Assets
 

 
 

Fair value of assets at January 1

$659,327

 

$596,660

Actual return on plan assets
(30,582
)
 
81,143

Employer contributions
43,773

 
44,273

Plan participant contributions
37,049

 
35,080

Benefits paid
(99,785
)
 
(97,829
)
Fair value of assets at December 31

$609,782

 

$659,327

Funded status

($622,837
)
 

($904,160
)
Amounts recognized in the balance sheet
 
 
 
Current liabilities

($44,276
)
 

($45,237
)
Non-current liabilities
(578,561
)
 
(858,923
)
Total funded status

($622,837
)
 

($904,160
)
Amounts recognized as a regulatory asset
 
 
 
Prior service credit

($25,778
)
 

($40,461
)
Net loss
51,774

 
144,966

 

$25,996

 

$104,505

Amounts recognized as AOCI (before tax)
 
 
 
Prior service credit

($42,730
)
 

($65,047
)
Net loss
(33,569
)
 
161,322

 

($76,299
)
 

$96,275



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Notes to Financial Statements


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, 2018 and 2017 are as follows:
2018
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Change in APBO
 
 
 
 
 
 
 
 
 
 
 
 
Balance at January 1
 

$249,019

 

$345,389

 

$84,621

 

$53,548

 

$116,702

 

$61,381

Service cost
 
3,170

 
6,225

 
1,284

 
516

 
1,319

 
1,223

Interest cost
 
7,986

 
11,154

 
2,731

 
1,669

 
3,754

 
1,998

Plan participant contributions
 
8,136

 
8,162

 
2,233

 
1,171

 
2,565

 
1,837

Actuarial gain
 
(61,960
)
 
(73,249
)
 
(16,762
)
 
(10,847
)
 
(27,527
)
 
(11,985
)
Benefits paid
 
(18,581
)
 
(22,476
)
 
(5,145
)
 
(4,078
)
 
(8,516
)
 
(5,685
)
Medicare Part D subsidy received
 
60

 
64

 
14

 
8

 
13

 
22

Balance at December 31
 

$187,830

 

$275,269

 

$68,976

 

$41,987

 

$88,310

 

$48,791

Change in Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair value of assets at January 1
 

$274,678

 

$—

 

$82,433

 

$85,504

 

$154,171

 

$49,124

Actual return on plan assets
 
(12,373
)
 
—

 
(3,755
)
 
(4,616
)
 
(7,182
)
 
(2,175
)
Employer contributions
 
195

 
14,314

 
87

 
3,793

 
3,808

 
569

Plan participant contributions
 
8,136

 
8,162

 
2,233

 
1,171

 
2,565

 
1,837

Benefits paid
 
(18,581
)
 
(22,476
)
 
(5,145
)
 
(4,078
)
 
(8,516
)
 
(5,685
)
Fair value of assets at December 31
 

$252,055

 

$—

 

$75,853

 

$81,774

 

$144,846

 

$43,670

Funded status
 

$64,225

 

($275,269
)
 

$6,877

 

$39,787

 

$56,536

 

($5,121
)
Amounts recognized in the balance sheet
 
 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 

$—

 

($17,740
)
 

$—

 

$—

 

$—

 

$—

Non-current liabilities
 
64,225

 
(257,529
)
 
6,877

 
39,787

 
56,536

 
(5,121
)
Total funded status
 

$64,225

 

($275,269
)
 

$6,877

 

$39,787

 

$56,536

 

($5,121
)
Amounts recognized in regulatory asset
 
 
 
 
 
 
 
 
 
 
 
 
Prior service credit
 

($11,465
)
 

$—

 

($4,864
)
 

($681
)
 

($3,665
)
 

($2,304
)
Net loss
 
9,021

 
—

 
15,945

 
3,151

 
13,094

 
8,774

 
 

($2,444
)
 

$—

 

$11,081

 

$2,470

 

$9,429

 

$6,470

Amounts recognized in AOCI (before tax)
 
 
 
 
 
 
 
 
 
 
 
 
Prior service credit
 

$—

 

($12,264
)
 

$—

 

$—

 

$—

 

$—

Net gain
 
—

 
(23,214
)
 
—

 
—

 
—

 
—

 
 

$—

 

($35,478
)
 

$—

 

$—

 

$—

 

$—




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Notes to Financial Statements


2017
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Change in APBO
 
 
 
 
 
 
 
 
 
 
 
 
Balance at January 1
 

$258,787

 

$342,500

 

$78,485

 

$55,515

 

$127,700

 

$62,498

Service cost
 
3,451

 
6,373

 
1,160

 
567

 
1,488

 
1,278

Interest cost
 
9,020

 
12,101

 
2,759

 
1,874

 
4,494

 
2,236

Plan participant contributions
 
7,875

 
7,855

 
2,160

 
1,151

 
2,453

 
1,779

Actuarial (gain)/loss
 
(11,691
)
 
(1,256
)
 
5,858

 
(899
)
 
(12,469
)
 
(2,233
)
Benefits paid
 
(18,497
)
 
(22,273
)
 
(5,823
)
 
(4,670
)
 
(6,980
)
 
(4,205
)
Medicare Part D subsidy received
 
74

 
89

 
22

 
10

 
16

 
28

Balance at December 31
 

$249,019

 

$345,389

 

$84,621

 

$53,548

 

$116,702

 

$61,381

Change in Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair value of assets at January 1
 

$250,926

 

$—

 

$75,945

 

$74,236

 

$137,069

 

$44,885

Actual return on plan assets
 
33,679

 
—

 
10,153

 
11,078

 
18,506

 
6,095

Employer contributions
 
695

 
14,418

 
(2
)
 
3,709

 
3,123

 
570

Plan participant contributions
 
7,875

 
7,855

 
2,160

 
1,151

 
2,453

 
1,779

Benefits paid
 
(18,497
)
 
(22,273
)
 
(5,823
)
 
(4,670
)
 
(6,980
)
 
(4,205
)
Fair value of assets at December 31
 

$274,678

 

$—

 

$82,433

 

$85,504

 

$154,171

 

$49,124

Funded status
 

$25,659

 

($345,389
)
 

($2,188
)
 

$31,956

 

$37,469

 

($12,257
)
Amounts recognized in the balance sheet
 
 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 

$—

 

($18,794
)
 

$—

 

$—

 

$—

 

$—

Non-current liabilities
 
25,659

 
(326,595
)
 
(2,188
)
 
31,956

 
37,469

 
(12,257
)
Total funded status
 

$25,659

 

($345,389
)
 

($2,188
)
 

$31,956

 

$37,469

 

($12,257
)
Amounts recognized in regulatory asset
 
 
 
 
 
 
 
 
 
 
 
 
Prior service credit
 

($16,574
)
 

$—

 

($6,687
)
 

($1,427
)
 

($5,980
)
 

($3,819
)
Net loss
 
42,394

 
—

 
25,247

 
4,269

 
24,478

 
16,386

 
 

$25,820

 

$—

 

$18,560

 

$2,842

 

$18,498

 

$12,567

Amounts recognized in AOCI (before tax)
 
 
 
 
 
 
 
 
 
 
 
 
Prior service credit
 

$—

 

($19,999
)
 

$—

 

$—

 

$—

 

$—

Net loss
 
—

 
51,585

 
—

 
—

 
—

 
—

 
 

$—

 

$31,586

 

$—

 

$—

 

$—

 

$—



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Notes to Financial Statements


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 $24.4 million in 2018, $37.6 million in 2017, and $24.9 million in 2016.  In 2018, 2017, and 2016 Entergy recognized $7.7 million, $20.3 million, and $8.1 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 $147 million as of December 31, 2018 of which $17 million was a current liability and $130 million was a non-current liability. The projected benefit obligation was $162.3 million as of December 31, 2017 of which $26.4 million was a current liability and $136 million was a non-current liability.  The accumulated benefit obligation was $131.9 million and $144.7 million as of December 31, 2018 and 2017, respectively. The unamortized prior service cost and net loss are recognized in regulatory assets ($51.9 million at December 31, 2018 and $55.2 million at December 31, 2017) and accumulated other comprehensive income before taxes ($19.2 million at December 31, 2018 and $35.9 million at December 31, 2017).

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 2018, 2017, and 2016, was as follows:
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
(In Thousands)
2018

$474

 

$180

 

$300

 

$81

 

$650

2017

$679

 

$185

 

$251

 

$73

 

$499

2016

$1,819

 

$231

 

$236

 

$65

 

$504


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. Included in the 2017 net periodic pension cost above are settlement charges of $269 thousand for Entergy Arkansas related to the lump sum benefits paid out of the plan. Included in the 2016 net periodic pension cost above are settlement charges of $1.4 million and $1 thousand for Entergy Arkansas and Entergy Mississippi, 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, 2018 and 2017 was as follows:
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
(In Thousands)
2018

$2,752

 

$1,881

 

$2,732

 

$206

 

$7,952

2017

$4,221

 

$2,061

 

$2,737

 

$583

 

$8,913



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Notes to Financial Statements


The accumulated benefit obligation for their employees for the non-qualified plans as of December 31, 2018 and 2017 was as follows:
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
(In Thousands)
2018

$2,519

 

$1,881

 

$2,427

 

$206

 

$7,724

2017

$3,825

 

$2,061

 

$2,250

 

$519

 

$8,602


The following amounts were recorded on the balance sheet as of December 31, 2018 and 2017:
2018
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
 
(In Thousands)
Current liabilities
 

($198
)
 

($229
)
 

($128
)
 

($16
)
 

($672
)
Non-current liabilities
 
(2,554
)
 
(1,652
)
 
(2,604
)
 
(191
)
 
(7,280
)
Total funded status
 

($2,752
)
 

($1,881
)
 

($2,732
)
 

($207
)
 

($7,952
)
Regulatory asset/(liability)
 

$1,314

 

$79

 

$1,009

 

($579
)
 

($517
)
Accumulated other comprehensive income (before taxes)
 

$—

 

$5

 

$—

 

$—

 

$—


2017
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
 
(In Thousands)
Current liabilities
 

($376
)
 

($231
)
 

($135
)
 

($21
)
 

($788
)
Non-current liabilities
 
(3,845
)
 
(1,830
)
 
(2,603
)
 
(562
)
 
(8,125
)
Total funded status
 

($4,221
)
 

($2,061
)
 

($2,738
)
 

($583
)
 

($8,913
)
Regulatory asset/(liability)
 

$2,995

 

$166

 

$1,186

 

($140
)
 

$133

Accumulated other comprehensive income (before taxes)
 

$—

 

$11

 

$—

 

$—

 

$—



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Notes to Financial Statements


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, 2018:
 
Qualified Pension Costs
 
Other Postretirement Costs
 
Non-Qualified Pension Costs
 
Total
 
(In Thousands)
Entergy
 
 
 
 
 
 
 
Amortization of prior service cost

($398
)
 

$22,379

 

($281
)
 

$21,700

Amortization of loss
(87,828
)
 
(7,730
)
 
(3,628
)
 
(99,186
)
Settlement loss
(828
)
 
—

 
(2,379
)
 
(3,207
)
 

($89,054
)
 

$14,649

 

($6,288
)
 

($80,693
)
Entergy Louisiana
 
 
 
 
 
 
 
Amortization of prior service cost

$—

 

$7,735

 

$—

 

$7,735

Amortization of loss
(3,468
)
 
(1,550
)
 
(7
)
 
(5,025
)
 

($3,468
)
 

$6,185

 

($7
)
 

$2,710


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, 2017:
 
Qualified Pension Costs
 
Other Postretirement Costs
 
Non-Qualified Pension Costs
 
Total
 
(In Thousands)
Entergy
 
 
 
 
 
 
 
Amortization of prior service cost

($261
)


$26,867

 

($355
)
 

$26,251

Amortization of loss
(73,800
)
 
(8,805
)
 
(3,397
)
 
(86,002
)
Settlement loss
—

 
—

 
(7,544
)
 
(7,544
)
 

($74,061
)
 

$18,062

 

($11,296
)
 

($67,295
)
Entergy Louisiana
 
 
 
 
 
 
 
Amortization of prior service cost

$—



$7,735

 

($1
)
 

$7,734

Amortization of loss
(3,459
)
 
(1,859
)
 
(9
)
 
(5,327
)
 

($3,459
)
 

$5,876

 

($10
)
 

$2,407


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 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.

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Notes to Financial Statements



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.  Entergy determines the MRV of pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns.  For other postretirement benefit plan assets Entergy uses fair value when determining MRV.

Qualified Pension and Other Postretirement Plans’ Assets

The Plan Administrator’s trust asset investment strategy is to invest the assets in a manner whereby long-term earnings on the assets (plus cash contributions) provide adequate funding for retiree benefit payments.  The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense.

In the optimization studies, the Plan Administrator formulates assumptions about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes.  The future market assumptions used in the optimization study are determined by examining historical market characteristics of the various asset classes and making adjustments to reflect future conditions expected to prevail over the study period.

The target asset allocation for pension adjusts dynamically based on the 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, 2018 and 2017 and the target asset allocation and ranges for 2018 are as follows:
Pension Asset Allocation
 
Target
 
Range
 
Actual 2018
 
Actual 2017
Domestic Equity Securities
 
39%
 
32%
to
46%
 
40%
 
45%
International Equity Securities
 
19%
 
15%
to
23%
 
18%
 
20%
Fixed Income Securities
 
42%
 
39%
to
45%
 
41%
 
34%
Other
 
0%
 
0%
to
10%
 
1%
 
1%

Postretirement Asset Allocation
 
Non-Taxable and Taxable
 
 
Target
 
Range
 
Actual 2018
 
Actual 2017
Domestic Equity Securities
 
27%
 
22%
to
32%
 
27%
 
30%
International Equity Securities
 
18%
 
13%
to
23%
 
17%
 
20%
Fixed Income Securities
 
55%
 
50%
to
60%
 
56%
 
50%
Other
 
0%
 
0%
to
5%
 
0%
 
0%


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

The expected long-term rate of return for the qualified pension plans’ assets is based primarily on the geometric average of the historical annual performance of a representative portfolio weighted by the target asset allocation defined in the table above, along with other indications of expected return on assets. The time period reflected is a long dated period spanning several decades.

The expected long-term rate of return for the non-taxable postretirement trust assets is determined using the same methodology described above for pension assets, but the aggregate asset allocation specific to the non-taxable postretirement assets is used.

For the taxable postretirement trust assets, the investment allocation includes tax-exempt fixed income securities.  This asset allocation, in combination with the same methodology employed to determine the expected return for other postretirement assets (as described above), and with a modification to reflect applicable taxes, is used to produce the expected long-term rate of return for taxable postretirement trust assets.

Concentrations of Credit Risk

Entergy’s investment guidelines mandate the avoidance of risk concentrations.  Types of concentrations specified to be avoided include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, geographic area and individual security issuance.  As of December 31, 2018, 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.

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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, 2018, and December 31, 2017, a summary of the investments held in the master trusts for Entergy’s qualified pension and other postretirement plans in which the Registrant Subsidiaries participate.

Qualified Defined Benefit Pension Plan Trusts
2018
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Thousands)
Short-term investments
 

$—

 

$7,715

(a)

$—

 

$7,715

Equity securities:
 
 
 
 
 
 
 
 
Corporate stocks:
 
 
 
 
 
 
 
 
Preferred
 
8,250

(b)
—

 
—

 
8,250

Common
 
695,003

(b)
—

(b)
—

 
695,003

Common collective trusts (c)
 


 


 


 
2,408,053

Registered investment companies
 
108,740

(d)
—

 
—

 
108,740

Fixed income securities:
 
 
 
 
 
 
 
 
U.S. Government securities
 
—

(b)
675,880

(a)
—

 
675,880

Corporate debt instruments
 
—

 
619,310

(a)
—

 
619,310

Registered investment companies (e)
 
29,374

(d)
2,697

(d)
—

 
931,439

Other
 
1,866

(f)
48,482

(f)
—

 
50,348

Other:
 
 
 
 
 
 
 
 
Insurance company general account (unallocated contracts)
 
—

 
39,322

(g)
—

 
39,322

Total investments
 

$843,233

 

$1,393,406

 

$—

 

$5,544,060

Cash
 
 
 
 
 
 
 
2,591

Other pending transactions
 
 
 
 
 
 
 
5,956

Less: Other postretirement assets included in total investments
 
 
 
 
 
 
 
(55,192
)
Total fair value of qualified pension assets
 
 
 
 
 
 
 

$5,497,415



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2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Thousands)
Equity securities:
 
 
 
 
 
 
 
 
Corporate stocks:
 
 
 
 
 
 
 
 
Preferred
 

$11,461

(b)

$—

 

$—

 

$11,461

Common
 
663,923

(b)
34

(b)
—

 
663,957

Common collective trusts (c)
 


 


 


 
3,198,799

Registered investment companies
 
125,174

(d)
—

 
—

 
125,174

Fixed income securities:
 
 
 
 
 
 
 
 
U.S. Government securities
 
—

(b)
638,832

(a)
—

 
638,832

Corporate debt instruments
 
—

 
619,735

(a)
—

 
619,735

Registered investment companies (e)
 
45,768

(d)
2,735

(d)
—

 
764,251

Other
 
46

(f)
62,559

(f)
—

 
62,605

Other:
 
 
 
 
 
 
 
 
Insurance company general account (unallocated contracts)
 
—

 
37,994

(g)
—

 
37,994

Total investments
 

$846,372

 

$1,361,889

 

$—

 

$6,122,808

Cash
 
 
 
 
 
 
 
1,508

Other pending transactions
 
 
 
 
 
 
 
5,179

Less: Other postretirement assets included in total investments
 
 
 
 
 
 
 
(58,179
)
Total fair value of qualified pension assets
 
 
 
 
 
 
 

$6,071,316


Other Postretirement Trusts
2018
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Thousands)
Equity securities:
 
 
 
 
 
 
 
 
Common collective trust (c)
 
 
 
 
 
 
 

$244,729

Fixed income securities:
 
 
 
 
 
 
 
 

U.S. Government securities
 
63,174

(b)
80,039

(a)
—

 
143,213

Corporate debt instruments
 
—

 
105,989

(a)
—

 
105,989

Registered investment companies
 
2,442

(d)
—

 
—

 
2,442

Other
 
—

 
56,980

(f)
—

 
56,980

Total investments
 

$65,616

 

$243,008

 

$—

 

$553,353

Other pending transactions
 
 
 
 
 
 
 
1,237

Plus:  Other postretirement assets included in the investments of the qualified pension trust
 
 
 
 
 
 
 
55,192

Total fair value of other postretirement assets
 
 
 
 
 
 
 

$609,782



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2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Thousands)
Equity securities:
 
 
 
 
 
 
 
 
Common collective trust (c)
 
 
 
 
 
 
 

$300,139

Fixed income securities:
 
 
 
 
 
 
 
 

U.S. Government securities
 
81,602

(b)
76,790

(a)
—

 
158,392

Corporate debt instruments
 
—

 
92,869

(a)
—

 
92,869

Registered investment companies
 
3,127

(d)
—

 
—

 
3,127

Other
 
—

 
45,627

(f)
—

 
45,627

Total investments
 

$84,729

 

$215,286

 

$—

 

$600,154

Other pending transactions
 
 
 
 
 
 
 
994

Plus:  Other postretirement assets included in the investments of the qualified pension trust
 
 
 
 
 
 
 
58,179

Total fair value of other postretirement assets
 
 
 
 
 
 
 

$659,327


(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.
(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.
(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, 2018, 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)
 
 
 
 
 
 
 
2019

$552,111

 

$16,964

 

$78,232

 

$865

2020

$437,699

 

$14,679

 

$80,312

 

$977

2021

$461,562

 

$10,563

 

$81,718

 

$1,102

2022

$467,822

 

$17,805

 

$82,624

 

$1,229

2023

$480,531

 

$17,578

 

$82,337

 

$1,370

2024 - 2028

$2,481,536

 

$68,687

 

$400,498

 

$9,007


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)
 
 
 
 
 
 
 
 
 
 
 
 
2019
 

$100,948

 

$145,515

 

$30,687

 

$18,436

 

$34,401

 

$20,792

2020
 

$91,941

 

$101,275

 

$27,376

 

$12,476

 

$27,273

 

$19,907

2021
 

$92,675

 

$104,465

 

$27,023

 

$12,555

 

$27,137

 

$20,628

2022
 

$94,051

 

$106,307

 

$27,348

 

$12,938

 

$27,420

 

$21,678

2023
 

$94,474

 

$107,771

 

$27,773

 

$13,250

 

$27,797

 

$21,970

2024 - 2028
 

$479,455

 

$547,028

 

$139,930

 

$64,413

 

$129,657

 

$114,223

Estimated Future Non-Qualified Pension Benefits Payments
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
 
(In Thousands)
Year(s)
 
 
 
 
 
 
 
 
 
 
2019
 

$198

 

$229

 

$128

 

$16

 

$672

2020
 

$295

 

$217

 

$306

 

$16

 

$733

2021
 

$254

 

$204

 

$203

 

$16

 

$753

2022
 

$503

 

$194

 

$213

 

$15

 

$686

2023
 

$356

 

$180

 

$191

 

$15

 

$904

2024 - 2028
 

$1,295

 

$711

 

$1,633

 

$72

 

$3,481



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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)
 
 
 
 
 
 
 
 
 
 
 
 
2019
 

$13,709

 

$17,933

 

$4,320

 

$3,634

 

$5,802

 

$3,082

2020
 

$13,520

 

$18,306

 

$4,508

 

$3,576

 

$5,964

 

$3,068

2021
 

$13,444

 

$18,526

 

$4,615

 

$3,468

 

$6,109

 

$3,160

2022
 

$13,183

 

$18,714

 

$4,689

 

$3,326

 

$6,206

 

$3,163

2023
 

$12,926

 

$18,842

 

$4,686

 

$3,251

 

$6,207

 

$3,126

2024 - 2028
 

$61,088

 

$91,994

 

$23,192

 

$14,573

 

$29,810

 

$14,814


Estimated Future Medicare Part D Subsidy
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Year(s)
 
 
 
 
 
 
 
 
 
 
 
 
2019
 

$192

 

$193

 

$66

 

$39

 

$71

 

$28

2020
 

$216

 

$215

 

$72

 

$42

 

$77

 

$34

2021
 

$239

 

$240

 

$79

 

$44

 

$84

 

$39

2022
 

$264

 

$265

 

$85

 

$46

 

$91

 

$46

2023
 

$291

 

$292

 

$92

 

$48

 

$97

 

$54

2024 - 2028
 

$1,836

 

$1,919

 

$559

 

$270

 

$599

 

$394


Contributions

Entergy currently expects to contribute approximately $176.9 million to its qualified pension plans and approximately $47.6 million to other postretirement plans in 2019.  The expected 2019 pension and other postretirement plan contributions of the Registrant Subsidiaries for their employees are shown below.  The 2019 required pension contributions will be known with more certainty when the January 1, 2019 valuations are completed, which is expected by April 1, 2019.

The Registrant Subsidiaries expect to contribute approximately the following to the qualified pension and other postretirement plans for their employees in 2019:
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
(In Thousands)
Pension Contributions

$27,112

 

$26,451

 

$7,701

 

$1,800

 

$1,645

 

$8,285

Other Postretirement Contributions

$501

 

$17,933

 

$123

 

$2,140

 

$56

 

$20



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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, 2018 and 2017 were as follows:
 
2018
 
2017
Weighted-average discount rate:
 
 
 
Qualified pension
4.37% - 4.52% Blended 4.47%
 
3.70% - 3.82% Blended 3.78%
Other postretirement
4.42%
 
3.72%
Non-qualified pension
3.98%
 
3.34%
Weighted-average rate of increase in future compensation levels
3.98%
 
3.98%
Assumed health care trend rate:
 
 
 
Pre-65
6.59%
 
6.95%
Post-65
7.15%
 
7.25%
Ultimate rate
4.75%
 
4.75%
Year ultimate rate is reached and beyond:

 
 
    Pre-65
2027
 
2027
    Post-65
2026
 
2027

The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2018, 2017, and 2016 were as follows:
 
2018
 
2017
 
2016
Weighted-average discount rate:
 
 
 
 
 
Qualified pension:
 
 
 
 
 
    Service cost
3.89%
 
4.75%
 
5.00%
    Interest cost
3.44%
 
3.73%
 
3.90%
Other postretirement:
 
 
 
 
 
    Service cost
3.88%
 
4.60%
 
4.92%
    Interest cost
3.33%
 
3.61%
 
3.78%
Non-qualified pension:
 
 
 
 
 
    Service cost
3.35%
 
3.65%
 
3.65%
    Interest cost
2.76%
 
3.10%
 
3.10%
Weighted-average rate of increase in future compensation levels
3.98%
 
3.98%
 
4.23%
Expected long-term rate of return on plan assets:
 
 
 
 
 
Pension assets
7.50%
 
7.50%
 
7.75%
Other postretirement non-taxable assets
6.50% - 7.50%
 
6.50% - 7.50%
 
7.75%
Other postretirement taxable assets
5.50%
 
5.75%
 
6.00%
Assumed health care trend rate:
 
 
 
 
 
Pre-65
6.95%
 
6.55%
 
6.75%
Post-65
7.25%
 
7.25%
 
7.55%
Ultimate rate
4.75%
 
4.75%
 
4.75%
Year ultimate rate is reached and beyond:

 

 

    Pre-65
2027
 
2026
 
2024
    Post-65
2027
 
2026
 
2024
    

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In 2016, Entergy refined its approach to estimating the service cost and interest cost components of qualified pension, other postretirement, and non-qualified pension costs. Under the refined approach, instead of using the weighted-average obligation discount rates at the beginning of the year, 2016 service cost and interest costs’ expected cash flows were discounted by the applicable spot rates. The refinement in approach was a change in accounting estimate and, accordingly, the effect was reflected prospectively. The measurement of the benefit obligation was not affected.
    
With respect to the mortality assumptions, Entergy used the RP-2014 Employee and Healthy Annuitant Tables (adjusted to base year 2006) with a fully generational MP-2018 projection scale, in determining its December 31, 2018 pension plans’ PBOs and other postretirement benefit APBO. Entergy used the RP-2014 Employee and Healthy Annuitant Tables (adjusted to base year 2006) with a fully generational MP-2017 projection scale, in determining its December 31, 2017 pension plans’ PBOs and other postretirement benefit APBO. 

Entergy’s health care cost trend is affected by both medical cost inflation, and with respect to capped costs, the effects of general inflation. A one percentage point change in Entergy’s assumed health care cost trend rate for 2018 would have the following effects:
 
 
1 Percentage Point Increase
 
1 Percentage Point Decrease
2018
 
Impact on the APBO
 
Impact on the sum of service costs and interest cost
 
Impact on the APBO
 
Impact on the sum of service costs and interest cost
 
 
Increase /(Decrease)
(In Thousands)
Entergy Corporation and its subsidiaries
 

$120,335

 

$9,254

 

($100,393
)
 

($7,593
)

The Registrant Subsidiaries’ health care cost trend is affected by both medical cost inflation, and with respect to capped costs, the effects of general inflation. A one percentage point change in the assumed health care cost trend rate for 2018 would have the following effects for the Registrant Subsidiaries for their employees:
 
 
1 Percentage Point Increase
 
1 Percentage Point Decrease
2018
 
Impact on the APBO
 
Impact on the sum of service costs and interest cost
 
Impact on the APBO
 
Impact on the sum of service costs and interest cost
 
 
Increase/(Decrease)
(In Thousands)
Entergy Arkansas
 

$15,906

 

$1,129

 

($13,323
)
 

($942
)
Entergy Louisiana
 

$27,684

 

$2,112

 

($23,071
)
 

($1,732
)
Entergy Mississippi
 

$6,768

 

$460

 

($5,665
)
 

($379
)
Entergy New Orleans
 

$3,281

 

$217

 

($2,784
)
 

($180
)
Entergy Texas
 

$8,673

 

$605

 

($7,292
)
 

($498
)
System Energy
 

$5,537

 

$416

 

($4,578
)
 

($339
)

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.


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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. Effective as of the close of business on December 31, 2017, the Savings Plan of Entergy Corporation and Subsidiaries IV (Entergy Savings Plan IV) was merged into the System Savings Plan and all of the assets of Entergy Savings Plan IV were transferred to the System Savings Plan.   

Entergy’s subsidiaries’ contributions to defined contribution plans collectively were $54.3 million in 2018, $49.1 million in 2017, and $47 million in 2016.  The majority of the contributions were to the System Savings Plan.

The Registrant Subsidiaries’ 2018, 2017, and 2016 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)
2018
 

$3,985

 

$5,450

 

$2,307

 

$795

 

$1,992

2017
 

$3,741

 

$5,079

 

$2,133

 

$731

 

$1,865

2016
 

$3,528

 

$4,746

 

$1,997

 

$708

 

$1,778



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 Ownership Plans which are shareholder-approved stock-based compensation plans.  Effective May 8, 2015, Entergy’s shareholders approved the 2015 Equity Ownership Plan (2015 Plan).  The maximum number of common shares that can be issued from the 2015 Plan for stock-based awards is 6,900,000 with no more than 1,500,000 available for incentive stock option grants.  The 2015 Plan applies to awards granted on or after May 8, 2015 and awards expire ten years from the date of grant. As of December 31, 2018, there were 2,006,268 authorized shares remaining for stock-based awards, including 1,500,000 for incentive stock option grants.

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:
 
2018
 
2017
 
2016
 
(In Millions)
Compensation expense included in Entergy’s consolidated net income
$4.3
 
$4.4
 
$4.4
Tax benefit recognized in Entergy’s consolidated net income
$1.1
 
$1.7
 
$1.7
Compensation cost capitalized as part of fixed assets and inventory
$0.7
 
$0.7
 
$0.7


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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:
 
2018
 
2017
 
2016
Stock price volatility
17.44%
 
18.39%
 
20.38%
Expected term in years
7.33
 
7.35
 
7.25
Risk-free interest rate
2.54%
 
2.31%
 
1.77%
Dividend yield
4.75%
 
4.75%
 
4.50%
Dividend payment per share
$3.58
 
$3.50
 
$3.42

Stock price volatility is calculated based upon the daily public stock price volatility of Entergy Corporation common stock over a period equal to the expected term of the award.  The expected term of the options is based upon historical option exercises and the weighted average life of options when exercised and the estimated weighted average life of all vested but unexercised options.  In 2008, Entergy implemented stock ownership guidelines for its senior executive officers.  These guidelines require an executive officer to own shares of Entergy Corporation common stock equal to a specified multiple of his or her salary.  Until an executive officer achieves this ownership position the executive officer is required to retain 75% of the net-of-tax net profit upon exercise of the option to be held in Entergy Corporation common stock.  The reduction in fair value of the stock options due to this restriction is based upon an estimate of the call option value of the reinvested gain discounted to present value over the applicable reinvestment period. 

A summary of stock option activity for the year ended December 31, 2018 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, 2018
5,164,854

 
$83.26
 
 
 
 
Options granted
687,400

 
$78.08
 
 
 
 
Options exercised
(1,419,087
)
 
$72.76
 
 
 
 
Options forfeited/expired
(1,439,834
)
 
$108.00
 
 
 
 
Options outstanding as of December 31, 2018
2,993,333

 
$75.14
 
$32,708,805
 
6.48 years
Options exercisable as of December 31, 2018
1,709,905

 
$75.64
 
$17,826,376
 
4.99 years
Weighted-average grant-date fair value of options granted during 2018
$6.99
 
 
 
 
 
 

The weighted-average grant-date fair value of options granted during the year was $6.54 for 2017 and $7.40 for 2016.  The total intrinsic value of stock options exercised was $19 million during 2018, $11 million during 2017, and $5 million during 2016.  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, 2018.  The aggregate intrinsic value of the stock options outstanding as of December 31, 2018 was $33 million. The intrinsic value of “in the money” stock options is $34 million as of December 31, 2018. 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 $4 million during 2018, $6 million during 2017, and $5 million during 2016. Cash received from option exercises was $103 million for the year ended December 31, 2018. The tax benefits realized from options exercised was $5 million for the year ended December 31, 2018.


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The following table summarizes information about stock options outstanding as of December 31, 2018:
 
 
 
Options Outstanding
 
Options Exercisable
Range of
 
As of
 
Weighted-Average Remaining Contractual Life-Yrs.
 
Weighted Average Exercise Price
 
Number Exercisable as of
 
Weighted Average Exercise Price
Exercise Prices
 
12/31/2018
 
 
 
12/31/2018
 

$51
 -
$64.99
 
322,500

 
4.71
 
$63.70
 
322,500

 
$63.70

$65
 -
$78.99
 
2,229,833

 
6.81
 
$73.88
 
946,405

 
$73.07

$79
 -
$91.99
 
441,000

 
6.08
 
$89.90
 
441,000

 
$89.90

$51
 -
$91.99
 
2,993,333

 
6.48
 
$75.14
 
1,709,905

 
$75.64

Stock-based compensation cost related to non-vested stock options outstanding as of December 31, 2018 not yet recognized is approximately $5 million and is expected to be recognized over a weighted-average period of 1.68 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 2018 the Board approved and Entergy granted 333,850 restricted stock awards under the 2015 Equity Ownership Plan.  The restricted stock awards were made effective as of January 25, 2018 and were valued at $78.08 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, 2018:
 
Shares
 
Weighted-Average Grant Date Fair Value Per Share
Outstanding shares at January 1, 2018
709,611

 
$72.92
Granted
364,306

 
$77.75
Vested
(332,614
)
 
$75.54
Forfeited
(47,777
)
 
$73.37
Outstanding shares at December 31, 2018
693,526

 
$74.17

The following table includes financial information for restricted stock for each of the years presented:
 
2018
 
2017
 
2016
 
(In Millions)
Compensation expense included in Entergy’s consolidated net income
$19.8
 
$19.7
 
$19.8
Tax benefit recognized in Entergy’s consolidated net income
$5.1
 
$7.6
 
$7.6
Compensation cost capitalized as part of fixed assets and inventory
$5.7
 
$5.2
 
$4.5

The total fair value of the restricted stock awards granted was $28 million, $29 million, and $29 million for the years ended December 31, 2018, 2017, and 2016.


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The total fair value of the restricted stock awards vested was $25 million, $24 million, and $23 million for the years ended December 31, 2018, 2017, and 2016, 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 one share of Entergy Corporation common stock at the end of the three-year performance period, plus dividends accrued during the performance period. 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 2018-2020 performance period, a cumulative Utility earnings metric was added to the Long-Term Performance Unit Program to supplement the relative total shareholder return measure that historically has been used in this program with each measure equally weighted. For each metric, there is no payout for performance that falls within the lowest quartile of performance.  For top quartile performance, a maximum payout of 200% of target is earned.

In January 2018 the Board approved and Entergy granted 182,408 performance units under the 2015 Equity Ownership and Long-Term Cash Incentive Plan.  The performance units were made effective as of January 25, 2018, and half were valued at $78.08 per share, the closing price of Entergy’s common stock on that date; and half were valued at $86.75 per share. Shares of the 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.

The following table includes information about the long-term performance units outstanding at the target level as of December 31, 2018:
 
Shares
 
Weighted-Average Grant Date Fair Value Per Share
Outstanding shares at January 1, 2018
534,151

 
$83.60
Granted
199,859

 
$82.03
Vested
(50,812
)
 
$99.02
Forfeited
(116,572
)
 
$95.51
Outstanding shares at December 31, 2018
566,626

 
$79.21

The following table includes financial information for the long-term performance units for each of the years presented:
 
2018
 
2017
 
2016
 
(In Millions)
Compensation expense included in Entergy’s consolidated net income
$11.5
 

$10.8

 

$12.3

Tax benefit recognized in Entergy’s consolidated net income
$2.9
 

$4.2

 

$4.8

Compensation cost capitalized as part of fixed assets and inventory
$3.3
 

$3.0

 

$2.9

    
The total fair value of the long-term performance units granted was $16 million, $19 million, and $21 million for the years ended December 31, 2018, 2017, and 2016, respectively.

In January 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. In January 2017, Entergy issued 86,964 shares of Entergy Corporation common stock at a share price of $71.89 for awards earned

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and dividends accrued under the 2014-2016 Long-Term Performance Unit Program. In January 2016, Entergy issued 54,103 shares of Entergy Corporation common stock at a share price of $68.09 for awards earned and dividends accrued under the 2013-2015 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 39 months.  As of December 31, 2018, there were 186,763 unvested restricted stock units that are expected to vest over an average period of 18 months.

The following table includes information about the restricted stock unit awards outstanding as of December 31, 2018:
 
Shares
 
Weighted-Average Grant Date Fair Value Per Share
Outstanding shares at January 1, 2018
201,570

 
$75.48
Granted
22,850

 
$79.11
Vested
(37,657
)
 
$72.97
Outstanding shares at December 31, 2018
186,763

 
$76.43

The following table includes financial information for restricted stock unit awards for each of the years presented:
 
2018
 
2017
 
2016
 
(In Millions)
Compensation expense included in Entergy’s consolidated net income
$2.9
 
$2.5
 
$2.2
Tax benefit recognized in Entergy’s consolidated net income
$0.7
 
$1.0
 
$0.8
Compensation cost capitalized as part of fixed assets and inventory
$0.7
 
$0.6
 
$0.4

The total fair value of the restricted stock unit awards granted was $2 million, $3 million, and $5 million for the years ended December 31, 2018, 2017, and 2016, respectively.

The total fair value of the restricted stock unit awards vested was $3 million, $0.4 million, and $2 million for the years ended December 31, 2018, 2017, and 2016, 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, 2018 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 is as follows:
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

Cash paid for long-lived asset additions
 

$3,987,424

 

$283,707

 

$86

 

$—

 

$4,271,217


2017
 
 
 
Utility
 
Entergy Wholesale Commodities*
 
 
 
All Other
 
 
 
Eliminations
 
 
 
Consolidated
 
 
(In Thousands)
Operating revenues
 

$9,417,866

 

$1,656,730

 

$—

 

($115
)
 

$11,074,481

Asset write-offs, impairments, and related charges
 

$—

 

$538,372

 

$—

 

$—

 

$538,372

Depreciation, amortization, & decommissioning
 

$1,345,906

 

$448,079

 

$1,678

 

$—

 

$1,795,663

Interest and investment income
 

$218,317

 

$224,121

 

$21,669

 

($175,910
)
 

$288,197

Interest expense
 

$547,301

 

$23,714

 

$139,619

 

($48,291
)
 

$662,343

Income taxes
 

$794,616

 

($146,480
)
 

($105,566
)
 

$—

 

$542,570

Consolidated net income (loss)
 

$773,148

 

($172,335
)
 

($47,840
)
 

($127,620
)
 

$425,353

Total assets
 

$42,978,669

 

$5,638,009

 

$1,011,612

 

($2,921,141
)
 

$46,707,149

Investment in affiliates - at equity
 

$198

 

$—

 

$—

 

$—

 

$198

Cash paid for long-lived asset additions
 

$3,680,513

 

$320,667

 

$438

 

$—

 

$4,001,618



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2016
 
 
 
Utility
 
Entergy Wholesale Commodities*
 
 
 
All Other
 
 
 
Eliminations
 
 
 
Consolidated
 
 
(In Thousands)
Operating revenues
 

$8,996,106

 

$1,849,638

 

$—

 

($99
)
 

$10,845,645

Asset write-offs, impairments, and related charges
 

$—

 

$2,835,637

 

$—

 

$—

 

$2,835,637

Depreciation, amortization, & decommissioning
 

$1,298,043

 

$374,922

 

$1,647

 

$—

 

$1,674,612

Interest and investment income
 

$189,994

 

$108,466

 

$27,385

 

($180,718
)
 

$145,127

Interest expense
 

$557,546

 

$22,858

 

$139,090

 

($53,124
)
 

$666,370

Income taxes
 

$424,388

 

($1,192,263
)
 

($49,384
)
 

$—

 

($817,259
)
Consolidated net income (loss)
 

$1,151,133

 

($1,493,124
)
 

($94,917
)
 

($127,595
)
 

($564,503
)
Total assets
 

$41,098,751

 

$6,696,038

 

$1,283,816

 

($3,174,171
)
 

$45,904,434

Investment in affiliates - at equity
 

$198

 

$—

 

$—

 

$—

 

$198

Cash paid for long-lived asset additions
 

$3,754,225

 

$289,639

 

$393

 

$—

 

$4,044,257


Businesses marked with * are sometimes referred to as the “competitive businesses.”  Eliminations are primarily intersegment activity.  Almost all of Entergy’s goodwill is related to the Utility segment.
 
On December 29, 2014, the Vermont Yankee plant ceased power production and entered its decommissioning phase. In December 2015, Rhode Island State Energy Center, a natural gas-fired combined cycle generating plant, was sold. In October 2015 management announced the intention to shut down the FitzPatrick plant in 2017 and the Pilgrim plant in 2019, earlier than previously expected. In 2016 management announced the planned sale of Vermont Yankee in 2018, the planned sale of FitzPatrick in 2017, and the planned amendment of the Consumers Energy PPA to terminate early, in May 2018, and the subsequent plan to shut down the Palisades plant in 2018, earlier than expected. In January 2017 management announced a settlement with New York State to shut down Indian Point 2 in 2020 and Indian Point 3 in 2021, both earlier than expected. In March 2017 the FitzPatrick plant was sold to Exelon. In September 2017 management announced the termination of the PPA amendment agreement with Consumers Energy and the revised plan to continue to operate Palisades under the current PPA and to shut down Palisades permanently on May 31, 2022. In July 2018, Entergy entered into a purchase and sale agreement with Holtec International to sell 100% of the equity interests in Entergy Nuclear Generation Company, the owner of Pilgrim, and 100% of the equity interests in Entergy Nuclear Palisades, LLC, the owner of Palisades and the Big Rock Point Site. The Pilgrim transaction is expected to close by the end of 2019, and the Palisades transaction is expected to close by the end of 2022. In December 2018 the Vermont Public Utility Commission approved the sale of Vermont Yankee and, in January 2019, Vermont Yankee was sold to NorthStar.

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 while they are owned by Entergy.
 
These decisions and 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 statement of operations.


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Total restructuring charges in 2018, 2017, and 2016 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, 2015
 

$—

 

$—

 

$—

Restructuring costs accrued
 
74

 
21

 
95

Non-cash portion
 
(3
)
 
—

 
(3
)
Cash paid out
 
1

 
—

 
1

Balance as of December 31, 2016
 

$70

 

$21

 

$91

Restructuring costs accrued
 
113

 
—

 
113

Non-cash portion
 
—

 
(7
)
 
(7
)
Cash paid out
 
100

 
—

 
100

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


In addition, Entergy Wholesale Commodities incurred $532 million in 2018 and $538 million in 2017 of impairment 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 $120 million in 2019 and a total of approximately $110 million from 2020 through 2022 associated with these strategic transactions.

Geographic Areas

For the years ended December 31, 2018, 2017, and 2016, the amount of revenue Entergy derived from outside of the United States was insignificant.  As of December 31, 2018 and 2017, 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.



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NOTE 14.  ACQUISITIONS, DISPOSITIONS, AND IMPAIRMENT OF LONG-LIVED ASSETS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans)

Acquisitions

Union Power Station

In March 2016, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans purchased the Union Power Station, a 1,980 MW (summer rating) power generation facility located near El Dorado, Arkansas, from Union Power Partners, L.P. The Union Power Station consists of four natural gas-fired, combined-cycle gas turbine power blocks, each rated at 495 MW (summer rating). Entergy Louisiana purchased two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy New Orleans each purchased one power block and a 25% undivided ownership interest in such related assets. The aggregate purchase price for the Union Power Station was approximately $949 million (approximately $237 million for each power block and associated assets).

Palisades Purchased Power Agreement

Entergy’s purchase of the Palisades plant in 2007 included a unit-contingent, 15-year purchased power agreement (PPA) with Consumers Energy for 100% of the plant’s output, excluding any future uprates.  Prices under the PPA range from $43.50/MWh in 2007 to $61.50/MWh in 2022, and the average price under the PPA is $51/MWh.  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 $6 million in 2018, $28 million in 2017, and $13 million in 2016.  Amounts to be amortized to revenue through the remaining life of the agreement will be approximately $10 million in 2019, $11 million in 2020, $12 million in 2021, and $5 million in 2022.

Dispositions

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 assumed a regulatory liability of $5.7 million. 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 the customer excess 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

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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. 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 are 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.

FitzPatrick

In August 2016, Entergy entered into an agreement to sell the FitzPatrick plant, an 838 MW nuclear power plant owned by Entergy in the Entergy Wholesale Commodities segment. In March 2017 the NRC approved the sale of the plant to Exelon. The transaction closed in March 2017 for a purchase price of $110 million, which included a $10 million non-refundable signing fee paid in August 2016, in addition to the assumption by Exelon of certain liabilities related to the FitzPatrick plant, resulting in a pre-tax gain on the sale of $16 million. At the transaction close, Exelon paid an additional $8 million for the proration of certain expenses prepaid by Entergy. The disposition-date fair value of the decommissioning trust fund was $805 million, classified within other deferred debits, and the disposition-date fair value of the asset retirement obligation was $727 million, classified within other non-current liabilities. The transaction also included property, plant, and equipment with a net book value of zero, materials and supplies, and prepaid assets.

As part of the transaction, Entergy entered into a reimbursement agreement with Exelon pursuant to which Exelon reimbursed Entergy for specified out-of-pocket costs associated with Entergy’s operation of FitzPatrick prior to closing of the sale. In the first quarter 2017, Entergy billed Exelon for reimbursement of $98 million of other operation and maintenance expenses, $7 million in lost operating revenues, and $3 million in taxes other than income taxes, partially offset by a $10 million defueling credit to Exelon.

As discussed in Note 3 to the financial statements, as a result of the sale of FitzPatrick on March 31, 2017, Entergy redetermined the plant’s tax basis, resulting in a $44 million income tax benefit in the first quarter 2017.

Top Deer

In November 2016, Entergy sold its 50% membership interest in Top Deer Wind Ventures, LLC, a wind-powered electric generation joint venture owned by Entergy in the Entergy Wholesale Commodities segment and accounted for as an equity method investment. Entergy sold its 50% membership interest in Top Deer for approximately $0.5 million and realized a pre-tax loss of $0.2 million on the sale.


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Impairment of Long-lived Assets

2017 and 2018 Impairments

In 2017 and 2018, Entergy continued to execute its strategy to reduce the size of Entergy Wholesale Commodities’ merchant fleet, with planned shutdowns of Pilgrim by May 31, 2019, Indian Point 2 by April 30, 2020, Indian Point 3 by April 30, 2021, and Palisades on May 31, 2022. The remaining two Entergy Wholesale Commodities’ nuclear plants, FitzPatrick and Vermont Yankee, 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.

In 2018, Entergy Wholesale Commodities incurred $532 million, and in 2017 it incurred $538 million, 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 reduce the size of the Entergy Wholesale Commodities’ merchant fleet. Entergy expects to continue to incur costs associated with nuclear fuel-related spending, expenditures for capital assets and, except for Palisades, expects to continue to charge these costs to expense as incurred because Entergy expects the value of the plants to continue to be impaired.

With respect to Palisades, Entergy and Consumers Energy had agreed to amend the existing PPA to terminate early, on May 31, 2018. In September 2017, however, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy will continue 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 on 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 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.

2018 Pilgrim Impairment

The Pilgrim plant is expected to cease 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.

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.


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2016 Palisades and Indian Point Impairments

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. As a result of the planned PPA termination and its intention to shut down the plant, Entergy tested the recoverability of the plant and related assets as of December 31, 2016. Entergy and Consumers Energy subsequently agreed, in September 2017, to terminate the PPA amendment agreement and Entergy now intends to shut down the Palisades plant permanently on May 31, 2022.

Indian Point 2 and Indian Point 3 had an application pending for renewed NRC licenses.  Various parties, including the State of New York, expressed opposition to renewal of the licenses.  Under federal law, nuclear power plants may continue to operate beyond their original license expiration dates while their timely filed renewal applications are pending NRC approval.  Indian Point 2 reached the expiration date of its original NRC operating license on September 28, 2013, and Indian Point 3 reached the expiration date of its original NRC operating license on December 12, 2015. Upon expiration of their operating licenses, each plant entered into a period of extended operation under the timely renewal rule.

In January 2017, Entergy announced that it reached a settlement with New York State to shut down Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021, and resolve all New York State-initiated legal challenges to Indian Point’s operating license renewal. As part of the settlement, New York State agreed to issue Indian Point’s water quality certification and Coastal Zone Management Act consistency certification and to withdraw its objection to license renewal before the NRC. New York State also agreed to issue a water discharge permit, which is required regardless of whether the plant is seeking a renewed NRC license. The shutdowns are conditioned, among other things, upon such actions being taken by New York State. As a result of its evaluation of alternatives to the continued operation of the Indian Point plants, and taking into consideration the status of negotiations with the State of New York, Entergy tested the recoverability of the plants and related assets as of December 31, 2016.

The tests for Palisades and Indian Point indicated that the probability-weighted undiscounted net cash flows did not exceed the carrying values of the plants and related assets as of December 31, 2016.

As of December 31, 2016 the estimated fair value of the Palisades plant and related long-lived assets was $206 million, while the carrying value was $558 million, resulting in an impairment charge of $352 million. Materials and supplies were evaluated and written down by $48 million. In summary, as of December 31, 2016, the total impairment loss and related charges for Palisades was $400 million ($258 million net-of-tax). The pre-impairment carrying value of $558 million included the effect of a $129 million increase in Palisades’ estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from the change in expectation regarding the timing of decommissioning cash flows. See Note 9 to the financial statements for further discussion regarding the Palisades decommissioning cost revision.

As of December 31, 2016 the estimated fair value of the Indian Point plants and related long-lived assets was $433 million, while the carrying value was $2,619 million, resulting in an impairment charge of $2,186 million. Materials and supplies were evaluated and written down by $157 million. In summary, as of December 31, 2016, the total impairment loss and related charges for Indian Point was $2,343 million ($1,511 million net-of-tax). The pre-impairment carrying value of $2,619 million included the effect of a $392 million increase in Indian Point’s estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from the change in expectation regarding the timing of decommissioning cash flows. See Note 9 to the financial statements for further discussion regarding the Indian Point decommissioning cost revision.


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Overall Regarding All Impairments

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.

The fair value analyses for Palisades and Indian Point in 2016 were performed based on the income approach, a discounted cash flow method, to determine the amount of impairment. The estimates of fair value were based on the prices that Entergy would expect to receive in hypothetical sales of Palisades and Indian Point plants and related assets to a market participant. In order to determine these prices, Entergy used significant observable inputs, including quoted forward power and gas prices, where available. Significant unobservable inputs, such as projected long-term pre-tax operating margins (cash basis) and estimated weighted-average costs of capital, were also used in the estimation of fair value. In addition, Entergy made certain assumptions regarding future tax deductions associated with the plants and related assets, the amount and timing of recoveries from future litigation with the DOE related to spent fuel storage costs, and the expected operating life of the plant.  Based on the use of significant unobservable inputs, the fair value measurement for the entirety of the asset group, and for each type of asset within the asset group, are classified as Level 3 in the fair value hierarchy discussed in Note 15 to the financial statements.

The following table sets forth a description of significant unobservable inputs used in the valuation of the Palisades and Indian Point plants and related assets:
Significant Unobservable Inputs
 
Amount
 
Weighted-Average
2016
 
 
 
 
Weighted-average cost of capital
 
 
 
 
Indian Point (a)
 
7.0%-7.5%
 
7.2%
Palisades
 
6.5%
 
6.5%
 
 
 
 
 
Long-term pre-tax operating margin (cash basis)
 
 
 
 
Indian Point
 
19.7%
 
19.7%
Palisades (b) (c)
 
17.8%-38.8%
 
34.6%

(a)
The cash flows extending through the 2021 shutdown at Indian Point 3 were assigned a higher discount factor to incorporate the increased risk associated with longer operations.
(b)
Most of the Palisades output is sold under a 15-year power purchase agreement, entered at the plant’s acquisition in 2007, that expires in 2022. The power purchase agreement prices currently exceed market prices and escalate each year, up to $61.50/MWh in 2022.
(c)
The fair value of Palisades at December 31, 2016 is based on the probability weighting of whether the PPA will terminate before the originally scheduled termination in 2022.

Entergy’s Accounting Policy and Entergy Wholesale Commodities Accounting groups, which report to the Chief Accounting Officer, were primarily responsible for determining the valuation of the Palisades and Indian Point plants and related assets, in consultation with external advisors. Entergy’s Accounting Policy group obtained and reviewed information from other Entergy departments with expertise on the various inputs and assumptions that were necessary to calculate the fair values of the asset groups.



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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 also uses a combination of financial contracts, including swaps, collars, and options, to mitigate commodity price risk.  When the market price falls, the combination of instruments 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, 2018 is approximately 2.25 years.  Planned generation currently under contract from Entergy Wholesale Commodities nuclear power plants is 98% for 2019, of which approximately 73% is sold under financial derivatives and the remainder under normal purchase/normal sale contracts. 

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Total planned generation for 2019 is 25.6 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, 2018, derivative contracts with six counterparties were in a liability position (approximately $34 million total). In addition to the corporate guarantee, $19 million in cash collateral was required to be posted by the Entergy subsidiary to its counterparties. As of December 31, 2017, derivative contracts with eight counterparties were in a liability position (approximately $65 million total). In addition to the corporate guarantee, $1 million in cash collateral was required to be posted by the Entergy subsidiary to its counterparties and $4 million in cash collateral and $34 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 has executed natural gas swaps and options as of December 31, 2018 is 5 years for Entergy Louisiana. The maximum length of time over which Entergy has executed natural gas swaps as of December 31, 2018 is 10 months for Entergy Mississippi and 10 months for Entergy New Orleans. The total volume of natural gas swaps and options outstanding as of December 31, 2018 is 45,276,000 MMBtu for Entergy, including 36,540,000 MMBtu for Entergy Louisiana, 8,160,000 MMBtu for Entergy Mississippi, and 576,000 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 2018, Entergy participated in the annual financial transmission rights auction process for the MISO planning year of June 1, 2018 through May 31, 2019. Financial transmission rights are derivative instruments which 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, 2018 is 47,313 GWh for Entergy, including 10,511 GWh for Entergy Arkansas, 20,452 GWh for Entergy Louisiana, 6,222 GWh for Entergy Mississippi, 2,330 GWh for Entergy New Orleans, and 7,600 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

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Commodities as of December 31, 2018 and December 31, 2017. Letters of credit posted with MISO covered the financial transmission rights exposure for Entergy Mississippi and Entergy Texas as of December 31, 2018 and Entergy Arkansas, Entergy Mississippi, and Entergy Texas as of December 31, 2017.

The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 2018 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
 
Fair Value (a)
 
Offset (b)
 
Net (c) (d)
 
Business
 
 
 
 
(In Millions)
 
 
Derivatives designated as hedging instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Prepayments and other (current portion)
 
$32
 
($32)
 
$—
 
Entergy Wholesale Commodities
Electricity swaps and options

Other deferred debits and other assets (non-current portion)
 
$7
 
($7)
 
$—
 
Entergy Wholesale Commodities
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Other current liabilities (current portion)
 
$54
 
($33)
 
$21
 
Entergy Wholesale Commodities
Electricity swaps and options
 
Other non-current liabilities (non-current portion)
 
$20
 
($7)
 
$13
 
Entergy Wholesale Commodities
Derivatives not designated as hedging instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Prepayments and other (current portion)
 
$4
 
($2)
 
$2
 
Entergy Wholesale Commodities
Electricity swaps and options
 
Other deferred debits and other assets (non-current portion)
 
$1
 
$—
 
$1
 
Entergy Wholesale Commodities
Natural gas swaps and options
 
Other deferred debits and other assets (non-current portion)
 
$2
 
$—
 
$2
 
Utility
Financial transmission rights
 
Prepayments and other
 
$16
 
($1)
 
$15
 
Utility and Entergy Wholesale Commodities
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Other current liabilities (current portion)
 
$1
 
($1)
 
$—
 
Entergy Wholesale Commodities
Natural gas swaps and options
 
Other current liabilities
 
$1
 
$—
 
$1
 
Utility


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The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 2017 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
 
Fair Value (a)
 
Offset (b)
 
Net (c) (d)
 
Business
 
 
 
 
(In Millions)
 
 
Derivatives designated as hedging instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Prepayments and other (current portion)
 
$19
 
($19)
 
$—
 
Entergy Wholesale Commodities
Electricity swaps and options
 
Other deferred debits and other assets (non-current portion)
 
$19
 
($14)
 
$5
 
Entergy Wholesale Commodities
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Other current liabilities (current portion)
 
$86
 
($20)
 
$66
 
Entergy Wholesale Commodities
Electricity swaps and options
 
Other non-current liabilities (non-current portion)
 
$17
 
($14)
 
$3
 
Entergy Wholesale Commodities
Derivatives not designated as hedging instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Prepayments and other (current portion)
 
$9
 
($9)
 
$—
 
Entergy Wholesale Commodities
Financial transmission rights
 
Prepayments and other
 
$22
 
($1)
 
$21
 
Utility and Entergy Wholesale Commodities
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Other current liabilities (current portion)
 
$9
 
($8)
 
$1
 
Entergy Wholesale Commodities
Natural gas swaps
 
Other current liabilities
 
$6
 
$—
 
$6
 
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 $19 million posted as of December 31, 2018 and $1 million posted and $4 million held as of December 31, 2017. Also excludes letters of credit in the amount of $4 million posted as of December 31, 2018 and $34 million in letters of credit held as of December 31, 2017.

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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, 2018, 2017, and 2016 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)
2018
 
 
 
 
 
 
Electricity swaps and options
 
($40)
 
Competitive business operating revenues
 
($68)
 
 
 
 
 
 
 
2017
 
 
 
 
 
 
Electricity swaps and options
 
$44
 
Competitive business operating revenues
 
$109
 
 
 
 
 
 
 
2016
 
 
 
 
 
 
Electricity swaps and options
 
$135
 
Competitive business operating revenues
 
$293

(a)
Before taxes of ($14) million, $38 million, and $103 million, for the years ended December 31, 2018, 2017, and 2016, respectively

At each reporting period, Entergy measures its hedges for ineffectiveness. Any ineffectiveness is recognized in earnings during the period. The ineffective portion of cash flow hedges is recorded in competitive businesses operating revenues. The change in fair value of Entergy’s cash flow hedges due to ineffectiveness was ($5.9) million, ($3) million, and ($356) thousand for the years ended December 31, 2018, 2017, and 2016, respectively.
   
Based on market prices as of December 31, 2018, unrealized gains (losses) recorded in accumulated other comprehensive income on cash flow hedges relating to power sales totaled ($28) million of net unrealized losses.  Approximately ($17) 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, 2018, 2017, and 2016 are as follows:
Instrument
 
Amount of gain (loss) recognized in accumulated other comprehensive income
 
Income Statement location
 
Amount of gain (loss) recorded in the income statement
 
 
(In Millions)
 
 
 
(In Millions)
2018
 
 
 
 
 
 
Natural gas swaps and options
 
$—
 
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
 
 
 
 
 
 
 
2017
 
 
 
 
 
 
Natural gas swaps
 
$—
 
Fuel, fuel-related expenses, and gas purchased for resale
(a)
($31)
Financial transmission rights
 
$—
 
Purchased power expense
(b)
$139
Electricity swaps and options
 
$—
(c)
Competitive business operating revenues
 
$—
 
 
 
 
 
 
 
2016
 
 
 
 
 
 
Natural gas swaps
 
$—
 
Fuel, fuel-related expenses, and gas purchased for resale
(a)
$11
Financial transmission rights
 
$—
 
Purchased power expense
(b)
$125
Electricity swaps and options
 
$—
(c)
Competitive business operating revenues
 
($11)

(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)
Amount of gain recognized in accumulated other comprehensive income from electricity swaps and options de-designated as hedged items.




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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, 2018 and 2017 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)
 
 
2018
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Natural gas swaps and options
 
Prepayments and other
 
$0.3
 
$—
 
$0.3
 
Entergy Louisiana
Natural gas swaps and options
 
Other deferred debits and other assets
 
$1.6
 
$—
 
$1.6
 
Entergy Louisiana
 
 
 
 
 
 
 
 
 
 
 
Financial transmission rights
 
Prepayments and other
 
$3.6
 
($0.2)
 
$3.4
 
Entergy Arkansas
Financial transmission rights
 
Prepayments and other
 
$8.4
 
($0.1)
 
$8.3
 
Entergy Louisiana
Financial transmission rights
 
Prepayments and other
 
$2.2
 
$—
 
$2.2
 
Entergy Mississippi
Financial transmission rights
 
Prepayments and other
 
$1.3
 
$—
 
$1.3
 
Entergy New Orleans
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
Financial transmission rights
 
Other current liabilities
 
$0.9
 
($1.4)
 
($0.5)
 
Entergy Texas
 
 
 
 
 
 
 
 
 
 
 
Natural gas swaps and options
 
Other current liabilities
 
$1.1
 
$—
 
$1.1
 
Entergy Louisiana
Natural gas swaps
 
Other current liabilities
 
$0.1
 
$—
 
$0.1
 
Entergy New Orleans



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Instrument
 
Balance Sheet Location
 
Gross Fair Value (a)
 
Offsetting Position (b)
 
Net Fair Value (c) (d)
 
Registrant
 
 
 
 
 
 
 
 
 
 
 
2017
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Financial transmission rights
 
Prepayments and other
 
$3.2
 
($0.2)
 
$3.0
 
Entergy Arkansas
Financial transmission rights
 
Prepayments and other
 
$11.0
 
($0.8)
 
$10.2
 
Entergy Louisiana
Financial transmission rights
 
Prepayments and other
 
$2.1
 
$—
 
$2.1
 
Entergy Mississippi
Financial transmission rights
 
Prepayments and other
 
$2.2
 
$—
 
$2.2
 
Entergy New Orleans
Financial transmission rights
 
Prepayments and other
 
$3.6
 
($0.2)
 
$3.4
 
Entergy Texas
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
Natural gas swaps
 
Other current liabilities
 
$5.0
 
$—
 
$5.0
 
Entergy Louisiana
Natural gas swaps
 
Other current liabilities
 
$1.2
 
$—
 
$1.2
 
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, 2018, letters of credit posted with MISO covered financial transmission rights exposure of $0.2 million for Entergy Mississippi, and $4.1 million for Entergy Texas. As of December 31, 2017, letters of credit posted with MISO covered financial transmission rights exposure of $0.2 million for Entergy Arkansas, $0.1 million for Entergy Mississippi, and $0.05 million for Entergy Texas.


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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, 2018, 2017, and 2016 are as follows:
Instrument
 
Income Statement Location
 
Amount of gain (loss) recorded in the income statement
 
Registrant
 
 
 
 
(In Millions)
 
 
2018
 
 
 
 
 
 
Natural gas swaps and options
 
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
 
 
 
 
 
 
 
2017
 
 
 
 
 
 
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
($25.4)
(a)
Entergy Louisiana
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
($5.2)
(a)
Entergy Mississippi
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
($0.3)
(a)
Entergy New Orleans
 
 
 
 
 
 
 
Financial transmission rights
 
Purchased power
 
$41.7
(b)
Entergy Arkansas
Financial transmission rights
 
Purchased power
 
$45.8
(b)
Entergy Louisiana
Financial transmission rights
 
Purchased power
 
$18.9
(b)
Entergy Mississippi
Financial transmission rights
 
Purchased power
 
$9.1
(b)
Entergy New Orleans
Financial transmission rights
 
Purchased power
 
$22.3
(b)
Entergy Texas
 
 
 
 
 
 
 
2016
 
 
 
 
 
 
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
$8.4
(a)
Entergy Louisiana
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
$3.1
(a)
Entergy Mississippi
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
($0.4)
(a)
Entergy New Orleans
 
 
 
 
 
 
 
Financial transmission rights
 
Purchased power
 
$23.2
(b)
Entergy Arkansas
Financial transmission rights
 
Purchased power
 
$69.7
(b)
Entergy Louisiana
Financial transmission rights
 
Purchased power
 
$16.6
(b)
Entergy Mississippi
Financial transmission rights
 
Purchased power
 
$4.1
(b)
Entergy New Orleans
Financial transmission rights
 
Purchased power
 
$10.2
(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;
–
inputs other than quoted prices that are observable for the asset or liability; or

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–
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 Business Unit Risk Control group and the Accounting Policy and Entergy Wholesale Commodities Accounting group.  The primary functions of the Business Unit Risk Control group 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 Business Unit Risk Control group is also responsible for managing the energy trading and risk management system, forecasting revenues, forward positions and analysis.  The Accounting Policy and Entergy Wholesale Commodities Accounting group performs functions related to market and counterparty settlements, revenue reporting and analysis and financial accounting. The Business Unit Risk Control group reports to the Vice President and Treasurer while the Accounting Policy and 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 Business Unit Risk Control group calculates the mark-to-market for electricity swaps and options.  The Business Unit Risk Control group 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 implied volatilities.  Moreover, on at least a monthly 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

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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 Business Unit Risk Control group.  The values are calculated internally and verified against the data published by MISO. Entergy’s Accounting Policy and Entergy Wholesale Commodities Accounting groups 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 Business Unit Risk Control groups report to the Vice President and Treasurer.  The Accounting Policy and Entergy Wholesale Commodities Accounting groups report 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, 2018 and December 31, 2017.  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.

2018
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$424

 

$—

 

$—

 

$424

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
1,686

 
—

 
—

 
1,686

Debt securities
 
1,259

 
1,625

 
—

 
2,884

Common trusts (b)
 
 
 
 
 
 
 
2,350

Power contracts
 
—

 
—

 
3

 
3

Securitization recovery trust account
 
51

 
—

 
—

 
51

Escrow accounts
 
403

 
—

 
—

 
403

Gas hedge contracts
 
—

 
2

 
—

 
2

Financial transmission rights
 
—

 
—

 
15

 
15

 
 

$3,823

 

$1,627

 

$18

 

$7,818

Liabilities:
 
 
 
 
 
 
 
 
Power contracts
 

$—

 

$—

 

$34

 

$34

Gas hedge contracts
 
1

 
—

 
—

 
1

 
 

$1

 

$—

 

$34

 

$35






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2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$725

 

$—

 

$—

 

$725

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
526

 
—

 
—

 
526

Debt securities
 
1,125

 
1,425

 
—

 
2,550

Common trusts (b)
 
 
 
 
 
 
 
4,136

Power contracts
 
—

 
—

 
5

 
5

Securitization recovery trust account
 
45

 
—

 
—

 
45

Escrow accounts
 
406

 
—

 
—

 
406

Financial transmission rights
 
—

 
—

 
21

 
21

 
 

$2,827

 

$1,425

 

$26

 

$8,414

Liabilities:
 
 
 
 
 
 
 
 
Power contracts
 

$—

 

$—

 

$70

 

$70

Gas hedge contracts
 
6

 
—

 
—

 
6

 
 

$6

 

$—

 

$70

 

$76


(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 9 to the financial statements for additional information on the investment portfolios.
(b)
Common trust funds are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. The fund administrator of these investments allows daily trading at the net asset value and trades settle at a later date.

The following table sets forth a reconciliation of changes in the net assets (liabilities) for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the years ended December 31, 2018, 2017, and 2016:
 
2018
 
2017
 
2016
 
Power Contracts
Financial transmission rights
 
Power Contracts
Financial transmission rights
 
Power Contracts
Financial transmission rights
 
(In Millions)
Balance as of January 1,

($65
)

$21

 

$5


$21

 

$189


$23

Total gains (losses) for the period (a)
 
 
 
 
 
 
 
 
Included in earnings
2

(1
)
 
(3
)
1

 
(10
)
—

Included in other comprehensive income
(40
)
—

 
44

—

 
135

—

Included as a regulatory liability/asset
—

80

 
—

76

 
—

68

Issuances of financial transmission rights
—

46

 
—

62

 
—

55

Settlements
72

(131
)
 
(111
)
(139
)
 
(309
)
(125
)
Balance as of December 31,

($31
)

$15

 

($65
)

$21

 

$5


$21


(a)
Change in unrealized gains or losses for the period included in earnings for derivatives held at the end of the reporting period is ($3.5) million, $0.9 million, and $0.2 million for the years ended December 31, 2018, 2017, and 2016, respectively.

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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, 2018:
Transaction Type
 
Fair Value as of December 31, 2018
 
Significant Unobservable Inputs
 
Range from Average %
 
Effect on Fair Value
 
 
(In Millions)
 
 
 
 
 
(In Millions)
Power contracts - electricity swaps
 
($31)
 
Unit contingent discount
 
+/- 4% - 4.75%
 
($3) - ($4)
 
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 that are accounted for at fair value on a recurring basis as of December 31, 2018 and December 31, 2017.  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.

Entergy Arkansas

2018
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 

$4.0

 

$—

 

$—

 

$4.0

Debt securities
 
94.8

 
286.5

 
—

 
381.3

Common trusts (b)
 
 
 
 
 
 
 
526.7

Securitization recovery trust account
 
4.7

 
—

 
—

 
4.7

Financial transmission rights
 
—

 
—

 
3.4

 
3.4

 
 

$103.5

 

$286.5

 

$3.4

 

$920.1


2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 

$11.7

 

$—

 

$—

 

$11.7

Debt securities
 
115.8

 
232.4

 
—

 
348.2

Common trusts (b)
 
 
 
 
 
 
 
585.0

Securitization recovery trust account
 
3.7

 
—

 
—

 
3.7

Escrow accounts
 
2.4

 
—

 
—

 
2.4

Financial transmission rights
 
—

 
—

 
3.0

 
3.0

 
 

$133.6

 

$232.4

 

$3.0

 

$954.0


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Entergy Louisiana

2018
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$43.1

 

$—

 

$—

 

$43.1

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
13.3

 
—

 
—

 
13.3

Debt securities
 
162.0

 
370.9

 
—

 
532.9

Common trusts (b)
 
 
 
 
 
 
 
738.8

Escrow accounts
 
289.5

 
—

 
—

 
289.5

Securitization recovery trust account
 
3.6

 
—

 
—

 
3.6

Gas hedge contracts
 
—

 
1.9

 
—

 
1.9

Financial transmission rights
 
—

 
—

 
8.3

 
8.3

 
 

$511.5

 

$372.8

 

$8.3

 

$1,631.4

 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
Gas hedge contracts
 

$0.7

 

$0.4

 

$—

 

$1.1


2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$30.1

 

$—

 

$—

 

$30.1

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
15.2

 
—

 
—

 
15.2

Debt securities
 
143.3

 
350.5

 
—

 
493.8

Common trusts (b)
 
 
 
 
 
 
 
803.1

Escrow accounts
 
289.5

 
—

 
—

 
289.5

Securitization recovery trust account
 
2.0

 
—

 
—

 
2.0

Financial transmission rights
 
—

 
—

 
10.2

 
10.2

 
 

$480.1

 

$350.5

 

$10.2

 

$1,643.9

 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
Gas hedge contracts
 

$5.0

 

$—

 

$—

 

$5.0


Entergy Mississippi
2018
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$36.9

 

$—

 

$—

 

$36.9

Escrow accounts
 
32.4

 
—

 
—

 
32.4

Financial transmission rights
 
—

 
—

 
2.2

 
2.2

 
 

$69.3

 

$—

 

$2.2

 

$71.5



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2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$4.5

 

$—

 

$—

 

$4.5

Escrow accounts
 
32.0

 
—

 
—

 
32.0

Financial transmission rights
 
—

 
—

 
2.1

 
2.1

 
 

$36.5

 

$—

 

$2.1

 

$38.6

 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
Gas hedge contracts
 

$1.2

 

$—

 

$—

 

$1.2


Entergy New Orleans

2018
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$19.7

 

$—

 

$—

 

$19.7

Securitization recovery trust account
 
2.2

 
—

 
—

 
2.2

Escrow accounts
 
80.9

 
—

 
—

 
80.9

Financial transmission rights
 
—

 
—

 
1.3

 
1.3

 
 

$102.8

 

$—

 

$1.3

 

$104.1

 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
Gas hedge contracts
 

$0.1

 

$—

 

$—

 

$0.1


2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$32.7

 

$—

 

$—

 

$32.7

Securitization recovery trust account
 
1.5

 
—

 
—

 
1.5

Escrow accounts
 
81.9

 
—

 
—

 
81.9

Financial transmission rights
 
—

 
—

 
2.2

 
2.2

 
 

$116.1

 

$—

 

$2.2

 

$118.3

 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
Gas hedge contracts
 

$0.2

 

$—

 

$—

 

$0.2


Entergy Texas

2018
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Securitization recovery trust account
 

$40.2

 

$—

 

$—

 

$40.2

 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
Financial transmission rights
 

$—

 

$—

 

$0.5

 

$0.5



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2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$115.5

 

$—

 

$—

 

$115.5

Securitization recovery trust account
 
37.7

 
—

 
—

 
37.7

Financial transmission rights
 
—

 
—

 
3.4

 
3.4

 
 

$153.2

 

$—

 

$3.4

 

$156.6


System Energy

2018
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$95.6

 

$—

 

$—

 

$95.6

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
4.4

 
—

 
—

 
4.4

Debt securities
 
224.5

 
139.7

 
—

 
364.2

Common trusts (b)
 
 
 
 
 
 
 
500.9

 
 

$324.5

 

$139.7

 

$—

 

$965.1


2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$287.1

 

$—

 

$—

 

$287.1

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
3.1

 
—

 
—

 
3.1

Debt securities
 
187.2

 
143.3

 
—

 
330.5

Common trusts (b)
 
 
 
 
 
 
 
572.1

 
 

$477.4

 

$143.3

 

$—

 

$1,192.8


(a)
The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices.  Fixed income securities are held in various governmental and corporate securities.  See Note 9 to the financial statements for additional information on the investment portfolios.
(b)
Common trust funds are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. The fund administrator of these investments allows daily trading at the net asset value and trades settle at a later date.



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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, 2018.

Entergy Arkansas
 
Entergy Louisiana

Entergy Mississippi

Entergy New Orleans

Entergy Texas
 
(In Millions)

 
 











Balance as of January 1,

$3.0

 

$10.2

 

$2.1

 

$2.2

 

$3.4

Issuances of financial transmission rights
11.8

 
20.0

 
4.5

 
3.7

 
6.1

Gains (losses) included as a regulatory liability/asset
13.9

 
50.8

 
21.9

 
9.2

 
(16.0
)
Settlements
(25.3
)
 
(72.7
)
 
(26.3
)
 
(13.8
)
 
6.0

Balance as of December 31,

$3.4

 

$8.3

 

$2.2

 

$1.3

 

($0.5
)

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, 2017.
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
(In Millions)
 
 
 
 
 
 
 
 
 
 
Balance as of January 1,

$5.4

 

$8.5

 

$3.2

 

$1.1

 

$3.1

Issuances of financial transmission rights
8.9

 
31.0

 
9.6

 
5.0

 
7.1

Gains included as a regulatory liability/asset
30.4

 
16.5

 
8.2

 
5.2

 
15.5

Settlements
(41.7
)
 
(45.8
)
 
(18.9
)
 
(9.1
)
 
(22.3
)
Balance as of December 31,

$3.0

 

$10.2

 

$2.1

 

$2.2

 

$3.4



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, Pilgrim, Indian Point 1, Indian Point 2, Indian Point 3, Vermont Yankee, and Palisades. Entergy’s nuclear decommissioning trust funds invest in equity securities, fixed-rate debt securities, and cash and cash equivalents.

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 ASU using a modified retrospective method, and Entergy recorded an adjustment increasing retained earnings and increasing accumulated other comprehensive loss 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. Beginning in 2018, 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. In accordance with the regulatory treatment of the decommissioning trust funds of the

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Registrant Subsidiaries, an offsetting amount of unrealized gains/(losses) will continue to be recorded in other regulatory liabilities/assets.

As discussed in Note 14 to the financial statements, in January 2019, Entergy completed the sale of the Vermont Yankee plant to NorthStar. As part of the transaction, Entergy transferred the Vermont Yankee decommissioning trust fund to NorthStar. As of December 31, 2018, the value of the decommissioning trust fund was $532 million.

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 Pilgrim, Indian Point 1, Indian Point 2, Indian Point 3, Vermont Yankee, and Palisades 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 are 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 are recognized in earnings. 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, 2018 on equity securities still held as of December 31, 2018 were ($249) million. The equity securities are generally held in funds that are designed to approximate or somewhat exceed the return of the Standard Poor’s 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 index or the Russell 3000 Index. The debt securities are generally held in individual government and credit issuances.

The available-for-sale securities held as of December 31, 2018 and 2017 are summarized as follows:
 
 
Fair Value
 
Total Unrealized Gains
 
Total Unrealized Losses
 
 
(In Millions)
2018
 
 
 
 
 
 
Debt Securities (a)
 

$2,495

 

$19

 

$35

 
 
 
 
 
 
 
2017
 
 
 
 
 
 
Equity Securities
 

$4,662

 

$2,131

 

$1

Debt Securities
 
2,550

 
44

 
16

Total
 

$7,212

 

$2,175

 

$17


(a)
Debt securities presented herein do not include the $389 million of debt securities held in the wholly-owned registered investment company, which are not accounted for as available-for-sale.    
    
The unrealized gains/(losses) above are reported before deferred taxes of $472 million as of December 31, 2017 for equity securities, and ($1) million as of December 31, 2018 and $7 million as of December 31, 2017 for debt securities. The amortized cost of available-for-sale debt securities was $2,511 million as of December 31, 2018 and $2,539 million as of December 31, 2017.  As of December 31, 2018, available-for-sale debt securities have an average

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coupon rate of approximately 3.19%, an average duration of approximately 4.50 years, and an average maturity of approximately 7.93 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, 2018:
 
Fair Value
 
Gross Unrealized Losses
 
(In Millions)
Less than 12 months

$652

 

$9

More than 12 months
782

 
26

Total

$1,434

 

$35


The fair value and gross unrealized losses of available-for-sale securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2017:
 
Equity Securities
 
Debt Securities
 
Fair Value
 
Gross Unrealized Losses
 
Fair Value
 
Gross Unrealized Losses
 
(In Millions)
Less than 12 months

$8

 

$1

 

$1,099

 

$7

More than 12 months
—

 
—

 
265

 
9

Total

$8

 

$1

 

$1,364

 

$16


The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2018 and 2017 are as follows:
 
2018
 
2017
 
(In Millions)
less than 1 year

$199

 

$74

1 year - 5 years
1,066

 
902

5 years - 10 years
544

 
812

10 years - 15 years
77

 
147

15 years - 20 years
78

 
100

20 years+
531

 
515

Total

$2,495

 

$2,550


During the years ended December 31, 2018, 2017, and 2016, proceeds from the dispositions of available-for-sale securities amounted to $2,406 million, $3,163 million, and $2,409 million, respectively.  During the years ended December 31, 2018, 2017, and 2016, gross gains of $7 million, $149 million, and $32 million, respectively, and gross losses of $47 million, $13 million, and $13 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, 2018 are $471 million for Indian Point 1, $598 million for Indian Point 2, $781 million for Indian Point 3, $444 million for Palisades, $1,028 million for Pilgrim, and $532 million for Vermont Yankee. The fair values of the decommissioning trust funds related to the Entergy Wholesale Commodities nuclear plants as of December 31, 2017 are $491 million for Indian Point 1, $621 million for Indian Point 2, $798 million for Indian Point 3, $458

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million for Palisades, $1,068 million for Pilgrim, and $613 million for Vermont Yankee. 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, 2018 and 2017 are summarized as follows:
 
 
Fair Value
 
Total Unrealized Gains
 
Total Unrealized Losses
 
 
(In Millions)
2018
 
 
 
 
 
 
Debt Securities
 

$381.3

 

$0.6

 

$8.2

 
 
 
 
 
 
 
2017
 
 
 
 
 
 
Equity Securities
 

$596.7

 

$354.9

 

$—

Debt Securities
 
348.2

 
2.1

 
3.0

Total
 

$944.9

 

$357.0

 

$3.0


The amortized cost of available-for-sale debt securities was $389 million as of December 31, 2018 and $349.1 million as of December 31, 2017.  As of December 31, 2018, the available-for-sale debt securities have an average coupon rate of approximately 2.87%, an average duration of approximately 4.75 years, and an average maturity of approximately 7.34 years.

The unrealized gains/(losses) recognized during the year ended December 31, 2018 on equity securities still held as of December 31, 2018 were ($49.3) million. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index.  A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.

The fair value and gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2018:
 
Fair Value
 
Gross Unrealized Losses
 
(In Millions)
Less than 12 months

$65.8

 

$0.5

More than 12 months
231.1

 
7.7

Total

$296.9

 

$8.2



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The fair value and gross unrealized losses of available-for-sale securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2017:
 
Equity Securities
 
Debt Securities
 
Fair Value
 
Gross Unrealized Losses
 
Fair Value
 
Gross Unrealized Losses
 
(In Millions)
Less than 12 months

$—

 

$—

 

$168.0

 

$1.2

More than 12 months
—

 
—

 
41.4

 
1.8

Total

$—

 

$—

 

$209.4

 

$3.0


The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2018 and 2017 are as follows:
 
2018
 
2017
 
(In Millions)
less than 1 year

$32.5

 

$13.0

1 year - 5 years
170.3

 
123.4

5 years - 10 years
114.0

 
180.6

10 years - 15 years
10.3

 
4.8

15 years - 20 years
8.1

 
3.4

20 years+
46.1

 
23.0

Total

$381.3

 

$348.2


During the years ended December 31, 2018, 2017, and 2016, proceeds from the dispositions of available-for-sale securities amounted to $82.1 million, $339.4 million, and $197.4 million, respectively.  During the years ended December 31, 2018, 2017, and 2016, gross gains of $0.1 million, $17.7 million, and $1.8 million, respectively, and gross losses of $2.9 million, $0.6 million, and $0.8 million, respectively, related to available-for-sale securities were reclassified out of other regulatory liabilities/assets into earnings.

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, 2018 and 2017 are summarized as follows:
 
 
Fair Value
 
Total Unrealized Gains
 
Total Unrealized Losses
 
 
(In Millions)
2018
 
 
 
 
 
 
Debt Securities
 

$532.9

 

$4.1

 

$6.0

 
 
 
 
 
 
 
2017
 
 
 
 
 
 
Equity Securities
 

$818.3

 

$461.2

 

$—

Debt Securities
 
493.8

 
10.9

 
3.6

Total
 

$1,312.1

 

$472.1

 

$3.6



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The amortized cost of available-for-sale debt securities was $534.8 million as of December 31, 2018 and $490 million as of December 31, 2017.  As of December 31, 2018, the available-for-sale debt securities have an average coupon rate of approximately 4.04%, an average duration of approximately 6.51 years, and an average maturity of approximately 13.59 years.

The unrealized gains/(losses) recognized during the year ended December 31, 2018 on equity securities still held as of December 31, 2018 were ($61.6) 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, 2018:
 
Fair Value
 
Gross Unrealized Losses
 
(In Millions)
Less than 12 months

$170.1

 

$2.1

More than 12 months
145.8

 
3.9

Total

$315.9

 

$6.0


The fair value and gross unrealized losses of available-for-sale securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2017:
 
Equity Securities
 
Debt Securities
 
Fair Value
 
Gross Unrealized Losses
 
Fair Value
 
Gross Unrealized Losses
 
(In Millions)
Less than 12 months

$—

 

$—

 

$135.3

 

$1.1

More than 12 months
—

 
—

 
84.4

 
2.5

Total

$—

 

$—

 

$219.7

 

$3.6


The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2018 and 2017 are as follows:
 
2018
 
2017
 
(In Millions)
less than 1 year

$31.1

 

$23.2

1 year - 5 years
130.5

 
122.8

5 years - 10 years
111.0

 
109.3

10 years - 15 years
29.0

 
52.7

15 years - 20 years
37.1

 
50.7

20 years+
194.2

 
135.1

Total

$532.9

 

$493.8


During the years ended December 31, 2018, 2017, and 2016, proceeds from the dispositions of available-for-sale securities amounted to $401.7 million, $231.3 million, and $219.2 million, respectively.  During the years ended December 31, 2018, 2017, and 2016, gross gains of $2.1 million, $12 million, and $3.9 million, respectively, and gross

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losses of $7.5 million, $0.4 million, and $0.4 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, 2018 and 2017 are summarized as follows:
 
 
Fair Value
 
Total Unrealized Gains
 
Total Unrealized Losses
 
 
(In Millions)
2018
 
 
 
 
 
 
Debt Securities
 

$364.2

 

$2.9

 

$5.8

 
 
 
 
 
 
 
2017
 
 
 
 
 
 
Equity Securities
 

$575.2

 

$308.6

 

$—

Debt Securities
 
330.5

 
4.2

 
1.2

Total
 

$905.7

 

$312.8

 

$1.2


The amortized cost of available-for-sale debt securities was $367.1 million as of December 31, 2018 and $327.5 million as of December 31, 2017.  As of December 31, 2018, the available-for-sale debt securities have an average coupon rate of approximately 3.15%, an average duration of approximately 6.05 years, and an average maturity of approximately 8.86 years.

The unrealized gains/(losses) recognized during the year ended December 31, 2018 on equity securities still held as of December 31, 2018 were ($40.7) 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, 2018:
 
Fair Value
 
Gross Unrealized Losses
 
(In Millions)
Less than 12 months

$89.7

 

$2.4

More than 12 months
79.8

 
3.4

Total

$169.5

 

$5.8



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The fair value and gross unrealized losses of available-for-sale securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2017:
 
Equity Securities
 
Debt Securities
 
Fair Value
 
Gross Unrealized Losses
 
Fair Value
 
Gross Unrealized Losses
 
(In Millions)
Less than 12 months

$—

 

$—

 

$196.9

 

$1.0

More than 12 months
—

 
—

 
10.4

 
0.2

Total

$—

 

$—

 

$207.3

 

$1.2


The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2018 and 2017 are as follows:
 
2018
 
2017
 
(In Millions)
less than 1 year

$22.8

 

$4.1

1 year - 5 years
188.0

 
173.0

5 years - 10 years
73.4

 
78.5

10 years - 15 years
5.2

 
1.0

15 years - 20 years
10.2

 
6.9

20 years+
64.6

 
67.0

Total

$364.2

 

$330.5


During the years ended December 31, 2018, 2017, and 2016, proceeds from the dispositions of available-for-sale securities amounted to $361.9 million, $565.4 million, and $499.3 million, respectively.  During the years ended December 31, 2018, 2017, and 2016, gross gains of $0.5 million, $1.4 million, and $3.5 million, respectively, and gross losses of $6.1 million, $3.3 million, and $1.7 million, respectively, related to available-for-sale securities were reclassified out of other regulatory liabilities/assets into earnings.

Other-than-temporary impairments and unrealized gains and losses

Entergy evaluates 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 has occurred.  The assessment of whether an investment in a 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).  Entergy did not have any material other-than-temporary impairments relating to credit losses on debt securities for the years ended December 31, 2018, 2017, and 2016. 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.


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

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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 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. The creditors of Entergy Arkansas do not have recourse to the assets or revenues of Entergy Arkansas Restoration Funding, including the storm recovery property, and the creditors of Entergy Arkansas Restoration Funding do not have recourse to the assets or revenues of Entergy Arkansas.  Entergy Arkansas has no payment obligations to Entergy Arkansas Restoration Funding except to remit storm recovery charge collections. 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

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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.

Entergy Louisiana was considered to hold a variable interest in the lessor from which it leased an undivided interest in the Waterford 3 nuclear plant. After Entergy Louisiana acquired a beneficial interest in the leased assets in March 2016, however, the lessor was no longer considered a variable interest entity. Entergy Louisiana made payments on its lease, including interest, of $9.2 million through March 2016.  See Note 10 to the financial statements for a discussion of Entergy Louisiana’s purchase of the Waterford 3 leased assets.

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 10 to the financial statements. System Energy made payments on its lease, including interest, of $17.2 million in 2018, $17.2 million in 2017, and $17.2 million in 2016.  The lessor is a bank acting in the capacity of owner trustee for the benefit of equity investors in the transaction pursuant to trust agreement entered solely for the purpose of facilitating the lease transaction.  It is possible that System Energy may be considered as the primary beneficiary of the lessor, but it is unable to apply the authoritative accounting guidance with respect to this VIE because the lessor is not required to, and could not, provide the necessary financial information to consolidate the lessor.  Because System Energy accounts for this leasing arrangement as a capital financing, however, System Energy believes that consolidating the lessor would not materially affect the financial statements.  In the 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,

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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)
2018

$104.3

 

$299.0

 

$2.5

 

$—

 

$58.8

 

$456.7

2017

$127.8

 

$282.4

 

$1.7

 

$—

 

$57.9

 

$633.5

2016

$49.4

 

$376.6

 

$2.9

 

$30.3

 

$180.2

 

$548.3


Intercompany Operating Expenses
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
(In Millions)
2018

$471.9

 

$627.8

 

$266.8

 

$256.4

 

$240.2

 

$176.5

2017

$510.2

 

$619.5

 

$310.5

 

$286.1

 

$234.6

 

$197.0

2016

$467.4

 

$670.8

 

$256.5

 

$276.7

 

$343.7

 

$146.0


Intercompany Interest and Investment Income
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
 
(In Millions)
 
 
 
 
 
 
 
 
 
 
 
 
2018

$0.4

 

$128.2

 

$—

 

$—

 

$0.2

 

$1.2

2017

$—

 

$128.0

 

$—

 

$0.2

 

$—

 

$0.9

2016

$—

 

$127.7

 

$0.1

 

$—

 

$—

 

$0.1


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 $24 million in 2018, $24.6 million in 2017, and $24.7 million in 2016.

Entergy’s operating transactions with its other equity method investees were not significant in 2018, 2017, or 2016.

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NOTE 19.  REVENUE RECOGNITION (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Revenue Recognition

Entergy implemented ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” effective January 1, 2018. Topic 606 requires entities to “recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.” The ASU details a five-step model that should be followed to achieve the core principle. This accounting was applied to all contracts using the modified retrospective method, which requires an adjustment to retained earnings for the cumulative effect of adopting the standard as of the effective date. Because the standard did not result in any material change in how Entergy recognizes revenue, however, no adjustment to retained earnings was required. Similarly, there was no effect on revenues recognized under Topic 606 for the year ended December 31, 2018.

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 year ended December 31, 2018 were as follows:

 
 
2018
 
 
(In Thousands)
Utility:
 
 
Residential
 

$3,565,522

Commercial
 
2,426,477

Industrial
 
2,499,227

Governmental
 
225,882

    Total billed retail
 
8,717,108

 
 
 
Sales for resale (a)
 
299,567

Other electric revenues (b)
 
326,910

Non-customer revenues (c)
 
40,526

    Total electric revenues
 
9,384,111

 
 
 
Natural gas
 
156,436

 
 
 
Entergy Wholesale Commodities:
 
 
Competitive businesses sales (a)
 
1,547,994

Non-customer revenues (c)
 
(79,089
)
    Total competitive businesses
 
1,468,905

 
 
 
    Total operating revenues
 

$11,009,452



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The Registrant Subsidiaries’ total revenues for the year ended December 31, 2018 were as follows:
2018
 
Entergy
Arkansas
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New
Orleans
 
Entergy
Texas
 
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
 
Residential
 

$807,098

 

$1,244,413

 

$578,568

 

$261,585

 

$673,858

Commercial
 
425,523

 
941,321

 
461,832

 
217,182

 
380,619

Industrial
 
434,387

 
1,462,462

 
175,056

 
33,371

 
393,951

Governmental
 
16,537

 
68,587

 
43,747

 
72,058

 
24,953

    Total billed retail
 
1,683,545


3,716,783


1,259,203


584,196


1,473,381

 
 
 
 
 
 
 
 
 
 
 
Sales for resale (a)
 
248,861

 
356,603

 
25,812

 
29,506

 
97,478

Other electric revenues (b)
 
111,875

 
144,978

 
39,897

 
4,718

 
31,413

Non-customer revenues (c)
 
16,362

 
14,177

 
10,200

 
6,313

 
3,630

    Total electric revenues
 
2,060,643

 
4,232,541

 
1,335,112

 
624,733

 
1,605,902

 
 
 
 
 
 
 
 
 
 
 
Natural gas
 
—

 
63,779

 
—

 
92,657

 
—

 
 
 
 
 
 
 
 
 
 
 
    Total operating revenues
 

$2,060,643

 

$4,296,320

 

$1,335,112

 

$717,390

 

$1,605,902


(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.
(c)
Non-customer 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. Energy is provided 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

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such as weather affect the calculation of unbilled revenues from one period to the other. This may result in variability of reported revenues from one period to the next as prior estimates are reversed and new estimates recorded.

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 non-customer revenue 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.

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.

Most 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 2022. The PPA prices are for a set price per MWh and escalate each year, up to $61.50/MWh in 2022. 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. Additionally, as the PPA pricing was considered below-market at the time of acquisition, a liability was recorded for the fair value of the below-market PPA, and is being amortized to revenue over the life of the agreement.

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.


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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 some excise taxes.  Entergy presents these taxes on a net basis, excluding them from revenues.


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 2018 and 2017 for Entergy Corporation and subsidiaries were:
 
Operating Revenues
 
Operating Income (Loss)
 
Consolidated Net Income (Loss)
 
Net Income (Loss) Attributable to Entergy Corporation
 
(In Thousands)
2018:
 
 
 
First Quarter

$2,723,881

 

$335,664

 

$136,200

 

$132,761

Second Quarter

$2,668,770

 

$91,597

 

$248,860

 

$245,421

Third Quarter

$3,104,319

 

$271,035

 

$539,818

 

$536,379

Fourth Quarter

$2,512,482

 

($228,931
)
 

($62,323
)
 

($65,900
)
2017:
 
 
 
First Quarter

$2,588,458

 

$195,493

 

$86,051

 

$82,605

Second Quarter

$2,618,550

 

$168,839

 

$413,368

 

$409,922

Third Quarter

$3,243,628

 

$759,003

 

$401,644

 

$398,198

Fourth Quarter

$2,623,845

 

$237,072

 

($475,710
)
 

($479,113
)


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Earnings (loss) per average common share
 
2018
 
2017
 
Basic
 
Diluted
 
Basic
 
Diluted
First Quarter

$0.73

 

$0.73

 

$0.46

 

$0.46

Second Quarter

$1.36

 

$1.34

 

$2.28

 

$2.27

Third Quarter

$2.96

 

$2.92

 

$2.22

 

$2.21

Fourth Quarter

($0.37
)
 

($0.36
)
 

($2.67
)
 

($2.66
)

Results of operations for 2018 include: 1) $532 million ($421 million net-of-tax) of impairment charges 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 reduce the size of the Entergy Wholesale Commodities’ merchant fleet; 2) a $170 million reduction of income tax expense and a regulatory liability of $40 million ($30 million net-of-tax) as a result of customer credits recognized by Utility, as a result of internal restructuring; 3) a $107 million reduction of income tax expense, recognized by Entergy Wholesale Commodities, as a result of a restructuring of the investment holdings in one of its nuclear plant decommissioning trust funds; 4) a $52 million income tax benefit, recognized by Entergy Louisiana, as a result of the settlement of the 2012-2013 IRS audit, associated with the Hurricane Katrina and Hurricane Rita contingent sharing obligation associated with the Louisiana Act 55 financing; and 5) a $23 million reduction of income tax expense, recognized by Entergy Wholesale Commodities, as a result of a state income tax audit. See Note 14 to the financial statements for further discussion of the impairment and related charges. See Notes 2 and 3 to the financial statements for further discussion of the internal restructuring and customer credits. See Note 3 to the financial statements for further discussion of the IRS audit settlement, the state income tax audit, and restructuring of the decommissioning trust fund investment holdings.

Results of operations for 2017 include: 1) $538 million ($350 million net-of-tax) of impairment charges due to costs being charged 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 reduce the size of the Entergy Wholesale Commodities’ merchant fleet; 2) a reduction in net income of $181 million, including a $34 million net-of-tax reduction of regulatory liabilities, at Utility and $397 million at Entergy Wholesale Commodities and an increase in net income of $52 million at Parent and Other as a result of Entergy’s re-measurement of its deferred tax assets and liabilities not subject to the ratemaking process due to the enactment of the Tax Cuts and Jobs Act, in December 2017, which lowered the federal corporate income tax rate from 35% to 21%; and 3) a reduction in income tax expense, net of unrecognized tax benefits, of $373 million as a result of a change in the tax classification of legal entities that own Entergy Wholesale Commodities nuclear power plants. See Note 14 to the financial statements for further discussion of the impairment and related charges. See Note 3 to the financial statements for further discussion of the effects of the Tax Cuts and Jobs Act and the change in the tax classification.


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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 2018 and 2017 were:

Operating Revenues
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
(In Thousands)
2018:
 
 
 
 
 
 
 
 
 
 
 
First Quarter

$551,024

 

$1,029,344

 

$315,743

 

$188,275

 

$348,940

 

$148,443

Second Quarter

$494,605

 

$1,072,788

 

$353,689

 

$178,446

 

$403,486

 

$112,456

Third Quarter

$568,399

 

$1,206,612

 

$367,734

 

$200,182

 

$477,231

 

$78,965

Fourth Quarter

$446,615

 

$987,576

 

$297,946

 

$150,487

 

$376,245

 

$116,843

2017:
 
 
 
 
 
 
 
 
 
 
 
First Quarter

$474,351

 

$880,783

 

$258,443

 

$168,989

 

$363,927

 

$154,787

Second Quarter

$496,662

 

$1,083,434

 

$291,212

 

$176,222

 

$378,488

 

$164,956

Third Quarter

$673,226

 

$1,290,494

 

$349,197

 

$199,017

 

$432,909

 

$156,106

Fourth Quarter

$495,680

 

$1,045,839

 

$299,377

 

$171,842

 

$369,569

 

$157,609


Operating Income (Loss)
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
(In Thousands)
2018:
 
 
 
 
 
 
 
 
 
 
 
First Quarter

$66,647

 

$141,319

 

$41,432

 

$17,869

 

$41,082

 

$30,941

Second Quarter

$26,501

 

$150,160

 

($63,801
)
 

$27,943

 

$58,637

 

$23,406

Third Quarter

$34,785

 

$236,518

 

$45,215

 

$21,544

 

$99,966

 

($17,879
)
Fourth Quarter

($82,704
)
 

$147,774

 

$23,600

 

$6,836

 

$6,741

 

$7,212

2017:
 
 
 
 
 
 
 
 
 
 
 
First Quarter

$42,696

 

$158,766

 

$40,159

 

$21,983

 

$38,620

 

$42,482

Second Quarter

$72,625

 

$200,018

 

$55,795

 

$27,823

 

$47,802

 

$43,035

Third Quarter

$173,270

 

$298,674

 

$84,813

 

$33,771

 

$78,993

 

$38,980

Fourth Quarter

$18,180

 

$217,179

 

$43,049

 

$12,832

 

$34,143

 

$42,486



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Net Income (Loss)
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
(In Thousands)
2018:
 
 
 
 
 
 
 
 
 
 
 
First Quarter

$36,255

 

$111,593

 

$22,843

 

$10,882

 

$17,350

 

$22,308

Second Quarter

$82,556

 

$184,358

 

$38,242

 

$18,269

 

$30,789

 

$23,387

Third Quarter

$128,890

 

$218,308

 

$50,733

 

$21,407

 

$65,846

 

$22,972

Fourth Quarter

$5,006

 

$161,355

 

$14,260

 

$2,594

 

$48,250

 

$25,442

2017:
 
 
 
 
 
 
 
 
 
 
 
First Quarter

$14,304

 

$94,378

 

$17,158

 

$10,978

 

$10,854

 

$20,347

Second Quarter

$38,550

 

$124,479

 

$28,303

 

$14,882

 

$21,101

 

$19,350

Third Quarter

$92,638

 

$186,284

 

$46,545

 

$18,529

 

$39,588

 

$20,583

Fourth Quarter

($5,648
)
 

($88,794
)
 

$18,026

 

$164

 

$4,630

 

$18,316


Earnings (Loss) Applicable to Common Equity
 
Entergy Arkansas
 
Entergy Mississippi
 
Entergy New Orleans
 
(In Thousands)
2018:
 
 
 
 
 
First Quarter

$35,898

 

$22,605

 

$10,882

Second Quarter

$82,199

 

$38,003

 

$18,269

Third Quarter

$128,533

 

$50,495

 

$21,407

Fourth Quarter

$4,828

 

$14,141

 

$2,594

2017:
 
 
 
 
 
First Quarter

$13,947

 

$16,920

 

$10,737

Second Quarter

$38,193

 

$28,064

 

$14,641

Third Quarter

$92,281

 

$46,307

 

$18,288

Fourth Quarter

($6,005
)
 

$17,788

 

$46




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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 nearly 9,000 MW of nuclear power. Entergy delivers electricity to 2.9 million utility customers in Arkansas, Louisiana, Mississippi, and Texas.  Entergy had annual revenues of $11 billion in 2018 and had more than 13,000 employees as of December 31, 2018.

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 or 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 a world-class utility business that creates sustainable value for its customers, employees, communities, and owners.  Entergy’s current scope includes electricity generation, transmission, and distribution as well as natural gas distribution.  Entergy focuses on operational excellence with an emphasis on safety, reliability, customer service, sustainability, cost efficiency, risk management, and engaged employees.  Entergy also continually seeks opportunities to grow its utility business to benefit all stakeholders and to optimize its portfolio of assets in an ever-dynamic market.  The Utility business segment will continue to modernize its operations, maintain reliability, and better serve its customers while growing the business. The Entergy Wholesale Commodities business segment will 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 wholly-owned 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, 2018, 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
 
711

 
25
%
 
 
 
 
Entergy Louisiana
Portions of Louisiana
 
1,084

 
37
%
 
93

 
46
%
Entergy Mississippi
Portions of Mississippi
 
450

 
15
%
 
 
 
 
Entergy New Orleans
City of New Orleans
 
202

 
7
%
 
107

 
54
%
Entergy Texas
Portions of Texas
 
454

 
16
%
 
 
 
 
Total customers
 
 
2,901

 
100
%
 
200

 
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 July 20, 2018, Entergy reached a 2018 peak demand of 21,587 MWh, compared to the 2017 peak of 21,671 MWh recorded on July 20, 2017.  Selected electric energy sales data is shown in the table below:

Selected 2018 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
22,525

 
56,150

 
13,691

 
5,914

 
19,220

 
—

 
117,498

Sales for resale:
 
 
 
 
 
 
 
 
 
 
 
 
 
Affiliates
1,773

 
5,498

 
—

 
—

 
1,516

 
6,264

 
—

Others
6,447

 
1,762

 
1,060

 
1,484

 
962

 
—

 
11,715

Total
30,745

 
63,410

 
14,751

 
7,398

 
21,698

 
6,264

 
129,213

Average use per residential customer (kWh)
13,916

 
15,521

 
15,515

 
13,219

 
15,448

 
—

 
14,956


(a)
Includes the effect of intercompany eliminations.

The following table illustrates the Utility operating companies’ 2018 combined electric sales volume as a percentage of total electric sales volume, and 2018 combined electric revenues as a percentage of total 2018 electric revenue, each by customer class.
Customer Class
 
% of Sales Volume
 
% of Revenue
Residential
 
28.7
 
38.0
Commercial
 
22.8
 
25.9
Industrial (a)
 
37.4
 
26.6
Governmental
 
2.0
 
2.4
Wholesale/Other
 
9.1
 
7.1

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


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See “Selected Financial Data” for each of the Utility operating companies for the detail of their sales by customer class for 2014-2018.

Selected 2018 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 11,183,773 and 7,205,692 Mcf, respectively, of natural gas to retail customers in 2018.  In 2018, 99% of Entergy Louisiana’s operating revenue was derived from the electric utility business, and only 1% from the natural gas distribution business.  For Entergy New Orleans, 87% of operating revenue was derived from the electric utility business and 13% from the natural gas distribution business in 2018.  

Following is data concerning Entergy New Orleans’s 2018 retail operating revenue sources.
Customer Class
 
Electric Operating Revenue
 
Natural Gas Operating Revenue
Residential
 
45%
 
48%
Commercial
 
37%
 
27%
Industrial
 
6%
 
6%
Governmental/Municipal
 
12%
 
19%


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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
 
$7.547 (a)
 
9.25% - 10.25%
 
5.25%
 
36.55%
 
- forward test year formula rate plan

- riders: MISO, capacity, Grand
Gulf, tax adjustment, energy
efficiency, fuel and purchased power
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Louisiana (electric)
 
$9.7 (b)
 
9.95% (c)
 
7.23%
 
49.1%
 
- formula rate plan through 2019 test
year

- riders/specific recovery: MISO,
capacity, transmission, fuel
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Louisiana (gas)
 
$0.0645 (d)
 
9.45% - 10.45%
 
7.25%
 
49.53%
 
- gas rate stabilization plan

- rider: gas infrastructure
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Mississippi
 
$2.413 (e)
 
9.28% - 11.36%
 
7.13%
 
48.05%
 
- 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, grid
modernization, restructuring credit
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy New Orleans (electric)
 
$0.299 (f)
 
10.7% - 11.5%
 
8.58%
 
50.08%
 
- rate case

- riders/specific recovery: fuel,
   capacity
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy New Orleans (gas)
 
$0.089 (g)
 
10.25% - 11.25%
 
8.40%
 
50.08%
 
- rate case

- rider: purchased gas
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Texas
 
$2.446 (h)
 
9.65%
 
7.73%
 
50.9%
 
- rate case

- riders: fuel, distribution and
   transmission, rate case expenses,
   AMI surcharge, limited-term Tax
   Act, federal income tax, among
   others
 
 
 
 
 
 
 
 
 
 
 
 
 
System Energy
 
$1.429 (i)
 
10.94% (j)
 
8.89%
 
65%
 
- monthly cost of service
 

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(a)
Based on 2019 forward test year.
(b)
Based on December 31, 2017 test year and excludes approximately $520 million transmission plant through August 31, 2018, included in transmission rider.
(c)
Authorized return on common equity for 2018 and 2019 test years will be 9.8%.
(d)
Based on September 30, 2017 test year.
(e)
Based on 2018 forward test year.
(f)
Based on December 31, 2011 test year and excludes approximately $228 million first-year average rate base for Union.
(g)
Based on December 31, 2011 test year.
(h)
Based on December 31, 2017 adjusted test year
(i)
Based on calculation as of December 31, 2018.
(j)
See Note 2 to the financial statements for discussion of ongoing proceedings at the FERC challenging System Energy’s authorized return on common equity.

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.

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 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. 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.


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Retail Rates - Gas

In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of 10.45% 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.

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.

Storm Cost Recovery

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

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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.

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

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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 Region, although it does not prevent Entergy Texas from joining another power region.  The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding exist.  Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of 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.

Entergy Texas and the other parties to the PUCT proceeding to determine the design of the competitive generation tariff were involved in negotiations throughout 2011 and 2012 with the objective of resolving as many disputed issues as possible regarding the tariff.  The PUCT determined that unrecovered costs that could 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 PUCT also ruled that the amount of customer load that may be included in the competitive generation service program is limited to 115 MW.  After additional negotiations, and ultimately the scheduling of a hearing to resolve remaining contested issues, the PUCT issued the order approving the competitive generation service rider in July 2013. Entergy Texas filed for rehearing of the PUCT’s July 2013 order, which the PUCT denied. Entergy Texas has since filed its appeal of that PUCT order to the Travis County District Court, which found in favor of the PUCT in an order issued in October 2014. In November 2014, Entergy Texas appealed the District Court’s order which moves the appeal to the Third Court of Appeals. Entergy Texas and opposing parties filed briefs and responses in the first quarter 2015. Oral argument was held in May 2015. In March 2016 the Court of Appeals upheld the District Court’s ruling favoring the PUCT. In May 2016, Entergy Texas filed with the Texas Supreme Court a petition for review of the Court of Appeals ruling. In January 2017, Entergy Texas filed its petitioner’s brief on the merits with the Texas Supreme Court. In June 2017 the Texas Supreme Court denied Entergy Texas’s petition in this matter.


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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.

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.

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 during 2019-2058.

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, 2018, is indicated below:

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Owned and Leased Capability MW(a)
Company
 
Total
 
Gas/Oil
 
Nuclear
 
Coal
 
Hydro
 
Solar
Entergy Arkansas
 
5,196

 
2,118

 
1,817

 
1,188

 
73

 
—

Entergy Louisiana
 
9,143

 
6,646

 
2,135

 
362

 
—

 
—

Entergy Mississippi
 
2,796

 
2,382

 
—

 
413

 
—

 
1

Entergy New Orleans
 
508

 
507

 
—

 
—

 
—

 
1

Entergy Texas
 
2,376

 
2,109

 
—

 
267

 
—

 
—

System Energy
 
1,252

 
—

 
1,252

 
—

 
—

 
—

Total
 
21,271

 
13,762

 
5,204

 
2,230

 
73

 
2


(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 21,568 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, environmental regulations, public policy goals, 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 5,723 MW of new long-term resources and the deactivation of over 4,834 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.

Other Generation Resources

RFP Procurements

The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as longer-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 June 2005 purchase of the 718 MW, gas-fired Perryville plant, of which 35% of the output is sold to Entergy Texas;
•
Entergy Arkansas’s September 2008 purchase of the 789 MW, combined-cycle, gas-fired Ouachita Generating Facility. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns one-third of the facility;
•
Entergy Arkansas’s November 2012 purchase of the 620 MW, combined-cycle, gas-fired Hot Spring Energy facility;
•
Entergy Mississippi’s November 2012 purchase of the 450 MW, combined-cycle, gas-fired Hinds Energy facility;
•
Entergy Louisiana’s construction of the 560 MW, combined-cycle, gas turbine Ninemile 6 generating facility at its existing Ninemile Point electric generating station. The facility reached commercial operation in December 2014;

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•
Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine St. Charles generating facility at its existing Little Gypsy electric generating station. Entergy Louisiana received regulatory approval from the LPSC in December 2016 and the facility is scheduled to be in service by mid-2019;
•
Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County generating facility at its existing Lewis Creek electric generating station. Entergy Texas received regulatory approval from the PUCT in July 2017 and the facility is scheduled to be in service by mid-2021;
•
Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station. Entergy Louisiana received regulatory approval from the LPSC in July 2017 and the facility is scheduled to be in service by mid-2020;
•
In August 2018, Entergy New Orleans executed an asset acquisition agreement, subject to applicable regulatory approvals and closing conditions, structured as a build-own-transfer for a 50 MW solar photovoltaic electric generating facility located in Washington Parish, Louisiana. Entergy New Orleans also executed an agreement to purchase a project that will be developed. The New Orleans Solar Station is expected to be a 20 MW solar photovoltaic electric generating facility. Both the build-own-transfer and the New Orleans Solar Station were filed, in July 2018, as a package with the agreement with St. James Solar, LLC, discussed below, for regulatory approval in an effort to satisfy the commitment to transact for 100 MW of renewable resources; and
•
In October 2018, Entergy Mississippi signed an asset acquisition agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic facility located in Sunflower County, Mississippi. In December 2018, Entergy Mississippi filed for regulatory approval.

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 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 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 December 2009, Entergy Texas and Exelon Generation Company, LLC executed a 10-year agreement for 150-300 MW from the Frontier Generating Station located in Grimes County, Texas;
•
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 pet 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;

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•
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 will begin in May 2020;
•
In November 2017, Entergy Louisiana and LA3 West Baton Rouge, LLC 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 agreement is expected to begin in March 2020; and
•
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. As discussed above, the purchased power agreement was filed as a package for regulatory approval in July 2018 and the application is pending approval.

In February 2019, Entergy Arkansas provided notice that it intends to issue an RFP for solar photovoltaic resources. This RFP is seeking up to 200 MW through an asset acquisition under a build-own-transfer transaction structure that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Arkansas’s 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; and 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). 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 under advanced development approximately 60 miles north of New Orleans on a partially developed site Calpine has owned since 2001. 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 with Entergy Louisiana, which will purchase the plant upon completion by 2021 for a fixed payment to reimburse construction costs plus an associated premium.

The Choctaw Generating Station is an 810 MW natural gas fired combined-cycle turbine plant located near French Camp, Mississippi. In October 2018, Entergy Mississippi filed an application with the MPSC seeking approval of the acquisition and cost recovery. The application is pending. The transaction is anticipated to close by the end of 2019, subject to required regulatory approvals and closing conditions.

Interconnections

The Utility operating companies’ generating units are interconnected by a transmission system operating at various voltages up to 500 kV.  These generating units consist primarily of steam-electric production facilities and are

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provided dispatch instructions by MISO. 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 the 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 reliability standards within the SERC Region.

Gas Property

As of December 31, 2018, 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, 2018, 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 is owned by GSG&T, Inc., a subsidiary of Entergy Texas, and is not subject to its mortgage lien.  Lewis Creek is leased to and operated by Entergy Texas.

Fuel Supply

The sources of generation and average fuel cost per kWh for the Utility operating companies and System Energy for the years 2016-2018 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
2018
 
39
 
2.84

 
27
 
0.84

 
9
 
2.24

 
8
 
5.23

 
17
 
3.71

2017
 
38
 
2.60

 
26
 
0.86

 
8
 
2.35

 
8
 
4.02

 
20
 
3.09

2016
 
41
 
2.44

 
28
 
0.63

 
7
 
2.65

 
9
 
3.71

 
15
 
3.13



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Actual 2018 and projected 2019 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)
 
2018
 
2019
 
2018
 
2019
 
2018
 
2019
 
2018
 
2019
 
2018
 
2019
Entergy Arkansas (a)
29
%
 
31
%
 
47
%
 
53
%
 
20
%
 
15
%
 
—

 
1
%
 
4
%
 
—
Entergy Louisiana
39
%
 
53
%
 
29
%
 
28
%
 
3
%
 
4
%
 
9
%
 
15
%
 
20
%
 
—
Entergy Mississippi (b)
48
%
 
56
%
 
16
%
 
31
%
 
16
%
 
13
%
 
—

 
—

 
20
%
 
—
Entergy New Orleans (b)
52
%
 
53
%
 
33
%
 
44
%
 
2
%
 
2
%
 
1
%
 
1
%
 
12
%
 
—
Entergy Texas
34
%
 
31
%
 
9
%
 
16
%
 
6
%
 
10
%
 
29
%
 
43
%
 
22
%
 
—
System Energy (c)
—

 
—

 
100
%
 
100
%
 
—

 
—

 
—

 
—

 
—

 
—
Utility (a) (b)
39
%
 
45
%
 
27
%
 
35
%
 
9
%
 
9
%
 
8
%
 
11
%
 
17
%
 
—

(a)
Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2018 and is expected to provide about less than 1% of its generation in 2019.
(b)
Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2018 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2019.
(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 2018 is not projected for 2019.

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 2019, 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-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 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 use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.


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Coal

Entergy Arkansas has committed to eight one- to three-year and two spot contracts that will supply approximately 85% of the total coal supply needs in 2019.  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 2019.  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 2019.

Entergy Louisiana has committed to five one- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2019.  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 2019.  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 2019.

For the year 2018, coal transportation delivery rates to Entergy Arkansas-and Entergy Louisiana-operated coal-fired units performed moderately lower than the previous years. However, delivery rates somewhat improved toward the end of the year and additional railcar capacity helped make up some delivery short falls. It is expected that delivery times will improve in 2019. 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 2019.  Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.

Nuclear Fuel

The nuclear fuel cycle consists of the following:

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

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

Based upon currently planned fuel cycles, the nuclear units in both the Utility and Entergy Wholesale Commodities segments 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.  The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment

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has been adjusted to reflect reduced overall requirements related to the planned permanent shutdowns of the Palisades, Pilgrim, Indian Point 2, and Indian Point 3 plants. 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 three 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 2018 under a firm contract from Sequent Energy Management L.P.  The gas is delivered through a combination of intrastate and interstate pipelines.

As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements.  Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.

Federal Regulation of the Utility

State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies.  The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy

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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. Entergy Arkansas terminated its participation in the System Agreement in December 2013. Entergy Mississippi terminated its participation in the System Agreement in November 2015. The System Agreement terminated with respect to its remaining participants in August 2016.

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 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 December 1995, System Energy commenced a rate proceeding at the FERC.  In July

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2001 the rate proceeding 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 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

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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 one 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.

Capital Funds Agreement

System Energy and Entergy Corporation have entered into the Capital Funds Agreement, whereby Entergy Corporation has agreed to supply System Energy with sufficient capital to (i) maintain System Energy’s equity capital at an amount equal to a minimum of 35% of its total capitalization (excluding short-term debt) and (ii) permit the continued commercial operation of Grand Gulf and pay in full all indebtedness for borrowed money of System Energy when due.

Entergy Corporation has entered into various supplements to the Capital Funds Agreement. System Energy has assigned its rights under such a supplement as security for its one outstanding series of first mortgage bonds. The supplement provides that permitted indebtedness for borrowed money incurred by System Energy in connection with the financing of Grand Gulf may be secured by System Energy’s rights under the Capital Funds Agreement on a pro rata basis (except for the Specific Payments, as defined below). In addition, in the supplements to the Capital Funds

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Agreement relating to the specific indebtedness being secured, Entergy Corporation has agreed to make cash capital contributions directly to System Energy sufficient to enable System Energy to make payments when due on such indebtedness (Specific Payments). However, if there is an event of default, Entergy Corporation must make those payments directly to the holders of indebtedness benefiting from the supplemental agreements. The payments (other than the Specific Payments) must be made pro rata according to the amount of the respective obligations benefiting from the supplemental agreements.

The Capital Funds Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, upon obtaining the consent, if required, of those holders of System Energy’s indebtedness then outstanding who have received the assignments of the Capital Funds Agreement. No such consent would be required to terminate the Capital Funds Agreement or the supplement thereto at this time.

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 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

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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. See Note 2 to the financial statements for additional discussion of the business combination.

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,

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and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.

Entergy Mississippi Internal Restructuring

In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:

•
Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•
Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
•
Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•
Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.

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 services, to nuclear power plants owned by other utilities 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 or sale of each of the Entergy Wholesale Commodities nuclear power plants.


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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
Pilgrim (a)
 
ISO-NE
 
1972
 
July 1999
 
Plymouth, MA
 
688 MW - Boiling Water
 
2032 (a)
Indian Point 3 (b)
 
NYISO
 
1976
 
Nov. 2000
 
Buchanan, NY
 
1,041 MW - Pressurized Water
 
2025 (b)
Indian Point 2 (b)
 
NYISO
 
1974
 
Sept. 2001
 
Buchanan, NY
 
1,028 MW - Pressurized Water
 
2024 (b)
Vermont Yankee (c)
 
ISO-NE
 
1972
 
July 2002
 
Vernon, VT
 
605 MW - Boiling Water
 
2032 (c)
Palisades (d)
 
MISO
 
1971
 
Apr. 2007
 
Covert, MI
 
811 MW - Pressurized Water
 
2031 (d)

(a)
The Pilgrim plant is expected to cease operations on May 31, 2019, at the end of its current fuel cycle.
(b)
The Indian Point 2 and Indian Point 3 plants are expected to cease operation by April 30, 2020 and April 30, 2021, respectively.
(c)
On December 29, 2014, the Vermont Yankee plant ceased power production. In January 2019, the Vermont Yankee plant was sold to NorthStar.
(d)
The Palisades plant is expected to cease operations on May 31, 2022.

See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the operation and planned shutdown or sale of each of the 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, and Big Rock Point is also under contract to be sold with the Palisades plant.

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 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 interests in unconsolidated joint ventures.

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Independent System Operators

The Pilgrim plant falls under the authority of the Independent System Operator New England (ISO-NE) and 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 ISO-NE, 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.

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.

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 Consolidated Edison and Consumers Energy, companies from which Entergy purchased plants, and ISO-NE, NYISO, and MISO. Substantially all of 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 ISO-NE and NYISO markets are highly competitive. Entergy Wholesale Commodities has numerous competitors in New England and 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 England and New York power markets is affected by, among other factors, the amount of generation and transmission capacity in

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these markets. MISO does not have a centralized clearing capacity market, but load serving entities do meet the majority of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. The majority of Palisades’ current output is contracted to Consumers Energy through 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. Refueling outages are generally in the spring and fall, and cause volumetric decreases during those seasons. 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, 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.

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.

Entergy Nuclear, Inc. can pursue service agreements with other nuclear power plant owners who seek the advantages of Entergy’s scale and expertise but do not necessarily want to sell their assets. 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. Entergy Nuclear, Inc. provided decommissioning services for the Maine Yankee nuclear power plant.

TLG Services, a subsidiary of Entergy Nuclear, Inc., 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.


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Regulation of Entergy’s Business

Federal Power Act

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

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

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

Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 70 MW of capacity.

State Regulation

Utility

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

•
utility service;
•
retail rates;
•
fuel cost recovery;
•
reasonable and adequate service;
•
leasing;
•
the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;
•
depreciation rates;
•
certificates of convenience and necessity and certificates of environmental compatibility and public need; 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 the retail rate or regulatory scheme in Missouri.


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Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:

•
utility service;
•
retail rates and charges;
•
standards of service;
•
certification of generating facilities and certain transmission projects;
•
certification of power or capacity purchase contracts;
•
audit of the fuel adjustment charge, environmental adjustment charge, avoided cost payment to Qualifying Facilities, energy efficiency rider, and purchased gas adjustment charge;
•
integrated resource planning;
•
utility mergers and acquisitions and other changes of control; and
•
depreciation and other matters.

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

•
utility service;
•
service areas;
•
facilities;
•
certification of generating facilities and certain transmission projects;
•
retail rates;
•
fuel cost recovery;
•
depreciation rates; and
•
mergers and 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;
•
standards of service;
•
depreciation and other matters;
•
integrated resource planning;
•
audit of fuel adjustment charge, environmental adjustment charge, and purchased gas adjustment charge;
•
issuance and sale of certain securities; and
•
mergers and 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 service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
•
customer service standards;
•
certification of certain transmission and generation projects; and
•
extensions of service into new areas.


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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 Pilgrim, Indian Point Energy Center, and Palisades. Substantial capital expenditures, increased operating expenses, and/or higher decommissioning costs at Entergy’s nuclear plants because of revised safety requirements of the NRC could be required in the future.

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, 2018 of $186.9 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick and 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 previous owners 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 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.

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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. Management cannot predict the potential timing or magnitude of future spent fuel fee revisions that may occur.

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. Through 2018, Entergy’s subsidiaries won and collected on judgments against the government totaling over $500 million.

In April 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $29 million in favor of Entergy Arkansas and against the DOE in the second round ANO damages case. Also in April 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $44 million in favor of System Energy and against the DOE in the second round Grand Gulf damages case. In June 2015, Entergy Arkansas and System Energy appealed to the U.S. Court of Appeals for the Federal Circuit portions of those decisions relating to cask loading costs. In April 2016 the Federal Circuit issued a decision in both appeals in favor of Entergy Arkansas and System Energy, and remanded the cases back to the U.S. Court of Federal Claims. In June 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $49 million in favor of System Energy and against the DOE in the second round Grand Gulf damages case, and Entergy received the payment from the U.S. Treasury in August 2016. In July 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $31 million in favor of Entergy Arkansas and against the DOE in the second round ANO damages case, and Entergy received payment from the U.S. Treasury in October 2016.
 
In December 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $81 million in favor of Entergy Nuclear Indian Point 3 and Entergy Nuclear FitzPatrick in the first round Indian Point 3/FitzPatrick damages case, and Entergy received the payment from the U.S. Treasury in June 2016.

In January 2016 the U.S. Court of Federal Claims issued a judgment in the amount of $49 million in favor of Entergy Louisiana and against the DOE in the first round Waterford 3 damages case. In April 2016, Entergy Louisiana appealed to the U.S. Court of Appeals for the Federal Circuit the portion of that decision relating to cask loading costs. After the ANO and Grand Gulf appeal was rendered, the U.S. Court of Appeals for the Federal Circuit remanded the Waterford 3 case back to the U.S. Court of Federal Claims for decision in accordance with the U.S. Court of Appeals ruling on cask loading costs. In August 2016 the U.S. Court of Federal Claims issued a final judgment in the Waterford 3 case in the amount of $53 million, and Entergy Louisiana received the payment from the U.S. Treasury in November 2016.

In April 2016 the U.S. Court of Federal Claims issued a partial judgment in the amount of $42 million in favor of Entergy Louisiana and against the DOE in the first round River Bend damages case, reserving the issue of cask loading costs pending resolution of the appeal on the same issues in the Entergy Arkansas and System Energy cases. Entergy Louisiana received payment from the U.S. Treasury in August 2016. In September 2016 the U.S. Court of Federal Claims issued a further judgment in the River Bend case in the amount of $5 million. Entergy Louisiana received the payment from the U.S. Treasury in January 2017. In May 2017 the U.S. Court of Federal Claims issued a final judgment in the first round River Bend damages case for $0.6 million, awarding certain cask loading costs that had not previously been adjudicated by the court.
    
In May 2016, Entergy Nuclear Vermont Yankee and the DOE entered into a stipulated agreement and the U.S. Court of Federal Claims issued a judgment in the amount of $19 million in favor of Entergy Nuclear Vermont Yankee

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and against the DOE in the second round Vermont Yankee damages case. Entergy received payment from the U.S. Treasury in June 2016.

In September 2016 the U.S. Court of Federal Claims issued a final judgment in the Entergy Nuclear Palisades case in the amount of $14 million. Entergy Nuclear Palisades received payment from the U.S. Treasury in January 2017.

In October 2016 the U.S. Court of Federal Claims issued a judgment in the second round Entergy Nuclear Indian Point 2 case in the amount of $34 million. Entergy Nuclear Indian Point 2 received payment from the U.S. Treasury in January 2017.

In September 2018 the DOE submitted an offer of judgment to resolve claims in the second round of the 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.

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.

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 FitzPatrick in 2002, at River Bend in 2005, at Grand Gulf in 2006, at Indian Point and Vermont Yankee in 2008, at Waterford 3 in 2011, and at Pilgrim in 2015.  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 July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend and in December 2010 the PUCT approved increased decommissioning collections for the Texas 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, which has now occurred. In December 2016 the APSC ordered continued collections for decommissioning for ANO 2, while finding that ANO 1’s decommissioning was adequately funded without continued collections. In December 2017 the APSC ordered continued collections for decommissioning for ANO 2, and again found that ANO 1’s decommissioning was adequately funded without continued collections. 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 the proposal subject to refund, and appointed a settlement judge to oversee settlement negotiations in the case. 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.


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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.

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 2018 filings with the NRC were made for certain Entergy subsidiaries’ nuclear plants reporting on decommissioning funding.  Those reports showed that decommissioning funding for each of those nuclear plants met the NRC’s financial assurance and planning requirements.

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

Price-Anderson Act

The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect the public in the event of a nuclear power plant accident.  The costs of this insurance are borne by the nuclear power industry.  Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025.  The Price-Anderson Act limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $137.6 million per reactor (with 99 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. ANO 1, ANO 2, Waterford 3, River Bend, Indian Point 2, Indian Point 3, and Palisades are in Column 1. Grand Gulf is in Column 2. Pilgrim is in Column 4 and was subject to an extensive, but limited, set of required NRC inspections that were completed in 2018 with a finding by the NRC in January 2019 that the corrective actions required to address the concerns that led to placement in Column 4 had

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been completed and that Pilgrim had demonstrated sustained improvement. See Note 8 to the financial statements for further discussion of the placement of Pilgrim in Column 4 of the NRC’s matrix.

Environmental Regulation

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

Clean Air Act and Subsequent Amendments

The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other  facilities.  Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements.  These programs include:

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New source review and preconstruction permits for new sources of criteria air pollutants, greenhouse gases, and significant modifications to existing facilities;
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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;
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Hazardous air pollutant emissions reduction programs;
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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. Entergy has an established process for identifying modifications requiring additional permitting approval and follows 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 Environmental Quality. 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

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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 2018 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 District of Arkansas. For further information about the settlement, see “Regional Haze” discussed below.
 
Ozone Nonattainment

Entergy Texas operates one fossil-fueled generating facility (Lewis Creek) and is in the process of permitting and constructing one fossil-fueled facility (Montgomery County Power Station) in a geographic area that is not in attainment with the applicable national ambient air quality standards (NAAQS) for ozone.  The nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area.  Areas in nonattainment are 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.

The Houston-Galveston-Brazoria area was originally classified as “moderate” nonattainment under the 1997 8-hour ozone standard with an attainment date of June 15, 2010.  In June 2007 the Texas governor petitioned the EPA to reclassify Houston-Galveston-Brazoria from “moderate” to “severe” and the EPA granted the request in October 2008.  In February 2015 the Texas Commission on Environmental Quality (TCEQ) submitted a request to the EPA for a finding that the Houston-Galveston-Brazoria area is in attainment with the 1997 8-hour ozone standard. The EPA issued this finding in December 2015. In April 2015 the EPA revoked the 1997 ozone NAAQS, and in May 2016 the EPA issued a proposed rule approving a substitute for the Houston-Galveston-Brazoria area. This redesignation indicated that the area has attained the revoked 1997 8-hour ozone NAAQS due to permanent and enforceable emission reductions and that it will maintain that NAAQS for 10 years from the date of the approval. Final approval, which was effective in December 2016, resulted in the area no longer being subject to any remaining anti-backsliding or nonattainment new source review requirements associated with the revoked 1997 NAAQS. In February 2018 the U.S. Court of Appeals for the D.C. Circuit opined that the EPA violated the Clean Air Act by revoking the 1997 standard and by creating the process that allowed states to avoid certain anti-backsliding provisions of the Act. Opponents filed a legal challenge to the December 2016 redesignation based on the February 2018 D.C. Circuit decision. The lawsuit has created much uncertainty and the TCEQ recently submitted a request to the EPA that the Houston-Galveston-Brazoria area be re-designated to attainment for the revoked 1997 standards.

In March 2008 the EPA revised the eight-hour NAAQS for ozone, creating the potential for additional counties and parishes in which Entergy operates to be placed in nonattainment status.  In April 2012 the EPA released its final nonattainment designations for the 2008 ozone NAAQS.  In Entergy’s utility service area, the Houston-Galveston-Brazoria, Texas; Baton Rouge, Louisiana; and Memphis, Tennessee/Mississippi/Arkansas areas were designated as in “marginal” nonattainment. In August 2015 and January 2016, the EPA proposed determinations that the Baton Rouge and Memphis areas had attained the 2008 standard. In May 2016 the EPA finalized those determinations and extended the Houston-Galveston-Brazoria area’s attainment date for the 2008 ozone standard to July 20, 2016 and reclassified the Baton Rouge area as attainment for ozone under the 2008 8-hour ozone standard. In December 2016 the EPA determined that the Houston-Galveston-Brazoria area had failed to attain the 2008 ozone standard by the 2016 attainment date. This finding reclassified the Houston-Galveston-Brazoria area from marginal to “moderate” and set the attainment deadline as July 20, 2018. In May 2018 the EPA published a proposed rule approving the Houston-Galveston-Brazoria attainment demonstration (a forward-looking model projecting attainment) for the 2008 8-hour ozone standard.

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However, in November 2018, the EPA signed a proposed rule determining that the area had failed to attain the 2008 standard by the July 20, 2018 attainment deadline. This determination will reclassify the Houston-Galveston-Brazoria area from “moderate” to “serious” and set the attainment deadline as July 20, 2021. Upon issuance of the final rule, the reclassification will become effective 30 days after publication in the Federal Register.

In October 2015 the EPA issued a final rule again lowering the primary and secondary NAAQS for ozone, this time to a level of 70 parts per billion. States were required to assess their attainment status and recommend designations to the EPA. In May 2018 the EPA designated Montgomery County, Texas, which is in the Houston-Galveston-Brazoria area, and in which Entergy’s Lewis Creek plant operates, as marginal non-attainment. The final designations were effective in August 2018. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the new standard and, where necessary, in planning for compliance. The State of Texas is required to develop plans intended to return the area to a condition of attainment by August 2021.

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.  The EPA designations for counties in attainment and nonattainment were originally due in June 2012, but the EPA indicated that it would delay designations except for those areas with existing monitoring data from 2009 to 2011 indicating violations of the new standard. In August 2013 the EPA issued final designations for these areas. In Entergy’s utility service territory, only St. Bernard Parish in Louisiana is designated as nonattainment for the SO2 1-hour national ambient air quality standard of 75 parts per billion. Entergy does not have a generation asset in that parish. In July 2016 the EPA finalized another round of designations for areas with newly monitored violations of the 2010 standard and those with stationary sources that emit over a threshold amount of SO2. Counties and parishes in which Entergy owns and operates fossil generating facilities that were included in this round of designations include Independence County and Jefferson County, Arkansas and Calcasieu Parish, Louisiana. Independence County and Calcasieu Parish were designated “unclassifiable,” and Jefferson County was designated “unclassifiable/attainment.” 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 January 2018 the EPA published a final rule designating a third round of attainment and nonattainment areas. Evangeline Parish, Louisiana, was designated nonattainment. Entergy does not have a generation asset in that parish. Additional capital projects or operational changes may be required to continue operating Entergy facilities in areas eventually designated as in nonattainment of the standard or designated as contributing to nonattainment areas. In May 2018 the EPA released a proposed rule that would retain the standard at 75 parts per billion, which was set in 2010. In November 2018 the EPA proposed to designate Independence County as “unclassifiable/attainment.” Final EPA action is pending.

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 December 2018 the EPA signed a proposed 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. However, the proposal does not seek to revise the MATS rule at this time. 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 July 2015 the D.C. Circuit invalidated the allowance budgets created by the EPA for several states, including Texas, and remanded that portion of the rule to the EPA for further action. The court did not stay or vacate the rule in the interim. CSAPR remains in effect.

The CSAPR Phase 1 implementation became effective January 1, 2015. Entergy has developed a compliance plan that could, over time, include both installation of controls at certain facilities and an emission allowance procurement strategy.

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, which remains pending.

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 Environmental Quality 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 has 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 CSAPR ozone-season emission trading program. Arkansas has finalized a Part II SIP which is under review by the EPA and is currently pending a state administrative appeal. In November 2018 the EPA proposed to finalize the Part II SIP without any substantive changes. Additionally, on December 31, 2018, the ALJ issued a Recommended Decision granting the Arkansas Department of Environmental Quality’s and Entergy’s Motions for Summary Judgment, which will resolve the administrative appeal if adopted by the Arkansas Pollution Control and Ecology Commission. 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 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 burn coal by December 31, 2030.

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In January 2018 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 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. The Arkansas Attorney General and the Arkansas Affordable Entergy Coalition have filed motions to intervene. The court has not acted on the intervention requests. 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 investigation, and Entergy Arkansas filed a motion to dismiss the application. Briefing is ongoing.

In Louisiana, Entergy worked with the Louisiana Department of Environmental Quality (LDEQ) and the EPA to revise the Louisiana SIP for regional haze, which was 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 three years from the effective date of the final EPA approval. The EPA’s final approval decision was issued in December 2017 and is on appeal to the U.S. Court of Appeals for the Fifth Circuit.

New and Existing Source Performance Standards for Greenhouse Gas Emissions

As a part of a climate plan announced in June 2013, the EPA was directed to (i) reissue proposed carbon pollution standards for new power plants by September 20, 2013, with finalization of the rules to occur in a timely manner; (ii) issue proposed carbon pollution standards, regulations, or guidelines, as appropriate, for modified, reconstructed, and existing power plants no later than June 1, 2014; (iii) finalize those rules by no later than June 1, 2015; and (iv) include in the guidelines addressing existing power plants a requirement that states submit to the EPA the implementation plans required under Section 111(d) of the Clean Air Act and its implementing regulations by no later than June 30, 2016. In January 2014 the EPA issued the proposed New Source Performance Standards rule for new sources. In June 2014 the EPA issued proposed standards for existing power plants.  Entergy was actively engaged in the rulemaking process, and submitted comments to the EPA in December 2014. The EPA issued the final rules for both new and existing sources in August 2015, and they were published in the Federal Register in October 2015. The existing source rule, also called the Clean Power Plan, requires states to develop plans for compliance with the EPA’s emission standards. In February 2016 the U.S. Supreme Court issued a stay halting the effectiveness of the rule until the rule is reviewed by the D.C. Circuit and by the U.S. Supreme Court, if further review is granted. In March 2017 the current administration issued an executive order entitled “Promoting Energy Independence and Economic Growth” instructing the EPA to review and then to suspend, revise, or rescind the Clean Power Plan, if appropriate. The EPA subsequently asked the D.C. Circuit to hold the challenges to the Clean Power Plan and the greenhouse gas new source performance standards in abeyance and signed a notice of withdrawal of the proposed federal plan, model trading rules, and the Clean Energy Incentive Program. The court placed the litigation in abeyance in April 2017. The EPA

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Administrator also sent a letter to the affected governors explaining that states are not currently required to meet Clean Power Plan deadlines, some of which have passed. In October 2017 the EPA proposed a new rule that would repeal the Clean Power Plan on the grounds that it exceeds the EPA’s statutory authority under the Clean Air Act. In December 2017 the EPA issued an advanced notice of proposed rulemaking regarding section 111(d), seeking comment on the form and content of a replacement for the Clean Power Plan, if one is promulgated. In August 2018 the EPA published its proposal to replace the Clean Power Plan. The Affordable Clean Energy (ACE) Rule, which in its current form focuses on existing coal-fired electric generating units, proposes to determine that heat rate improvements are the best system of emission reductions. The rule also proposes revisions to the New Source Review program to prevent that program from being a barrier to installing heat rate improvement projects under ACE. Additionally, the rule provides states more discretion in determining how the best system for emission reductions applies to individual units, including technical feasibility and the remaining useful life of the facility. Comments on the proposal were due in October 2018. Entergy will continue to be engaged in this rulemaking process.

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 state and federal level to codify renewable portfolio standards, a clean energy standard, 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 PCBs;
•
efforts by certain external groups to encourage reporting and disclosure of carbon dioxide emissions and risk;
•
the listing of additional species as threatened or endangered, the protection of critical habitat for these species, and developments in the legal protection of eagles and migratory birds; and
•
the regulation of the management, disposal, and beneficial reuse of coal combustion residuals.

Entergy continues to support national legislation that would increase planning certainty for electric utilities while addressing carbon dioxide emissions in a responsible and flexible manner.  By virtue of its proportionally large investment in low-emitting gas-fired and nuclear 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 in the future, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions.  These voluntary actions included establishment of a formal program to stabilize owned power plant carbon dioxide emissions at 2000

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levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases as well as its ownership share of generation.  Entergy 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.  Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the United States were approximately 43.7 million tons in 2018 and 39.9 tons in 2017.
    
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 2018 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for seventeen consecutive years.

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 (NPDES) permit program 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.

NPDES Permits and Section 401 Water Quality Certifications

NPDES permits are subject to renewal every five years.  Consequently, Entergy is currently in various stages of the data evaluation and discharge permitting process for its power plants.  

316(b) Cooling Water Intake Structures

The EPA finalized regulations in July 2004 governing the intake of water at large existing power plants employing cooling water intake structures. The rule sought to reduce perceived impacts on aquatic resources by requiring covered facilities to implement technology or other measures to meet EPA-targeted reductions in water use and corresponding perceived aquatic impacts. Entergy, other industry members and industry groups, environmental groups, and a coalition of northeastern and mid-Atlantic states challenged various aspects of the rule. After litigation, the EPA issued a new final 316(b) rule in August 2014. Entergy is implementing a compliance plan for each affected facility in accordance with the requirements of the final rule.

Entergy filed a petition for review of the final rule as a co-petitioner with the Utility Water Act Group. The U.S. Court of Appeals for the Second Circuit heard oral argument in September 2017 and rendered its decision in July 2018. The U.S. Court of Appeals upheld the rule in its entirety. Environmental petitioners petitioned the Second Circuit for a panel rehearing or rehearing en banc, which was denied.

Federal Jurisdiction of Waters of the United States

In September 2013 the EPA and the U.S. Army Corps of Engineers announced the intention to propose a rule to clarify federal Clean Water Act jurisdiction over waters of the United States. The announcement was made in conjunction with the EPA’s release of a draft scientific report on the “connectivity” of waters that the agency said would inform the rulemaking. This report was finalized in January 2015. The final rule was published in the Federal Register in June 2015. The rule could significantly increase the number and types of waters included in the EPA’s and the U.S.

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Army Corps of Engineers’ jurisdiction, which in turn could pose additional permitting and pollutant management burdens on Entergy’s operations. The final rule was challenged in various federal courts by several parties, including most states. In February 2017 the current administration issued an executive order instructing the EPA and the U.S. Army Corps of Engineers to review the Waters of the United States rule and to revise or rescind, as appropriate. The 2015 rule now is stayed throughout Entergy’s utility service territory by actions of the United States District Courts. In December 2018 the EPA released a prepublication copy of its revised definition of Waters of the United States which proposes to narrow the scope of the Clean Water Act jurisdiction, as compared to the 2015 rule. Comments will be due 60 days after publication in the Federal Register.

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, Pilgrim, 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.

In February 2016, Entergy disclosed that elevated tritium levels had been detected in samples from several monitoring wells that are part of Indian Point’s groundwater monitoring program.  Investigation of the source of elevated tritium determined that the source was related to a temporary system to process water in preparation for the regularly scheduled refueling outage at Indian Point 2. The system was secured and is no longer in use and additional measures have been taken to prevent reoccurrence should the system be needed again. In June 2016, Indian Point detected trace amounts of cobalt 58 in a single well. This was associated with the draining and disassembly of a temporary heat exchanger operated in support of the Indian Point 2 outage. Oversight by the NRC and other federal/state government bodies continues. The NRC has issued a green notice of violation related to the adequacy of Entergy’s controls to prevent the introduction of radioactivity into the site groundwater. Entergy completed corrective actions and is working with the NRC on the closure of the notice of violation.

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 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

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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 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, 2018, Entergy has recorded asset retirement obligations related to CCR management of $18.4 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. In September 2017 the EPA agreed to reconsider certain provisions of the CCR rule in light of the WIIN Act. In March 2018 the EPA published its proposed revisions to the CCR rule with comments due at the end of April 2018. In July 2018 the EPA released its initial revisions extending certain deadlines and incorporating some risk-based standards. The EPA is expected to release additional revisions in another rulemaking. In August 2018 the D.C. Circuit vacated several provisions of the CCR rule on the basis that they were inconsistent with the Resource Conservation and Recovery Act and remanded the matter to the EPA to conduct further rulemaking.

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. In order to meet these regulations, one of two recycle ponds at White Bluff commenced closure in October 2018. Additionally, the second recycle pond at White Bluff is planned for closure on or before October 31, 2020. Any potential requirements for corrective action or operational changes under the new EPA 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.

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

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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.  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 and is continuing.  The EPA released the second Five Year Review in 2015. The EPA indicated that the current 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 a waterloo barrier. The estimated cost for this remedy is approximately $2 million. Entergy is awaiting comments and direction from the EPA on the Focused Feasibility Study and potential remedy selection.  In early 2017 the EPA indicated that the new remedial method, a waterloo barrier, may not be necessary and requested revisions to the Focused Feasibility Study. The EPA plans to provide comments on the revised 2017 Focused Feasibility Study in the next Five Year Review in 2020. Entergy is continuing discussions with the EPA regarding the ongoing actions at the site.

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 exists 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.  Remediation activities continue at the site.

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 Texas Commission on Environmental Quality (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. Additional direction is expected from the TCEQ regarding final remediation requirements for the site. 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 has 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. Entergy has developed and is implementing a response plan addressing the TCEQ’s requests.

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

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in personal injury, property damage, and business tort cases.  The litigation environment in these states poses a significant business risk to Entergy.

Ratepayer and Fuel Cost Recovery Lawsuits  (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

Mississippi Attorney General Complaint

See Note 2 to the financial statements for a discussion of this proceeding.
 
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.

Employees

Employees are an integral part of Entergy’s commitment to serving customers.  As of December 31, 2018, Entergy subsidiaries employed 13,688 people.

Utility:
 

Entergy Arkansas
1,258

Entergy Louisiana
1,656

Entergy Mississippi
713

Entergy New Orleans
278

Entergy Texas
600

System Energy
—

Entergy Operations
3,479

Entergy Services
3,525

Entergy Nuclear Operations
2,127

Other subsidiaries
52

Total Entergy
13,688


Approximately 4,700 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.

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.


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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 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

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 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 that could result in delays in effecting rate changes and uncertainty as to ultimate results.
 
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’ 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.  Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings. 

The base rates of Entergy Texas are established largely in traditional base rate case proceedings. Apart from base rate proceedings, Entergy Texas has also filed to use rate riders to recover the revenue requirements associated with certain authorized historical costs. For example, Entergy Texas has recovered distribution-related capital investments through the distribution cost recovery factor rider mechanism, transmission-related capital investments and certain non-fuel MISO charges through the transmission cost recovery factor rider mechanism, and MISO fuel and energy-related costs through the fixed fuel factor mechanism. Entergy Texas is also required to make a filing every three years, 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.

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 unless Entergy Arkansas requests, and the APSC approves, the extension of the formula rate plan tariff for an additional five years through 2026. In the event that Entergy Arkansas’s formula rate plan is terminated or is not extended beyond the initial term, Entergy Arkansas could file an

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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 has been 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. 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. Currently, based on a settlement agreement approved by the City Council, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented in connection with the most recent base rate case that is filed regarding its electric and gas operations. Entergy New Orleans filed its most recent rate case in September 2018 and expects a decision by the City Council later in 2019, with rates to become effective as of August 2019.

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 allows monthly adjustments to reflect the current operating costs of, and investment in, 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 authorized return on equity and capital structure. See Note 2 to the financial statements for further discussion of the proceedings.

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.

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, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs.  Regulators may also 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

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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.
 
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 number of outstanding System Agreement proceedings at the FERC 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 power in certain regions and/or the economic value of such sales, 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. MISO is currently evaluating through its stakeholder process potential changes in the transmission project criteria in MISO. These changes, if adopted, could potentially result in a larger volume of competitively bid and regionally cost allocated transmission projects. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from these projects, there is a risk that the Utility operating companies’ business and financial position could be harmed as a result of lost investment opportunities and other effects that flow from an increased number of competitive projects being approved

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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 and the allocation of transmission upgrade costs, 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 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 could have material effects on Entergy and those Utility operating companies affected by severe weather.

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.

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 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 fossil 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, System Energy, and the Entergy Wholesale Commodities nuclear plant owners 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.

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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 and average approximately 30 days in duration.  Plant maintenance and upgrades are often scheduled during such planned outages, which often 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.  Lower than forecasted capacity factors may cause Entergy Wholesale Commodities to experience reduced revenues and may also create damages risk with certain hedge products as previously discussed.

Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities 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 2019 and beyond.  The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment is being adjusted to reflect reduced overall requirements related to the planned permanent shutdown of the Palisades, Pilgrim, Indian Point 2 and Indian Point 3 plants over the next three years. 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 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, System Energy, and Entergy Wholesale Commodities.

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 deteriorating economic conditions or international sanctions could restrict the ability of such suppliers to continue to supply fuel or provide such services.  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, System Energy, and Entergy Wholesale Commodities.

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

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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 and Note 8 to the financial statements.

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 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.


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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 99 reactors currently 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 $1.238 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, 2018, the maximum annual assessment amounts total $118 million for the Utility plants.  Retrospective premium insurance

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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 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 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.  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

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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 Pilgrim and Palisades (which will include the transfer of each entity’s decommissioning trust), 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.

Changes in NRC regulations or other binding regulatory requirements may cause increased funding requirements for nuclear plant decommissioning trusts.

NRC regulations require certain minimum financial assurance requirements for meeting obligations to decommission nuclear power plants.  Those financial assurance requirements may change from time to time, and certain changes may result in a material increase in the financial assurance required for decommissioning the Utility operating companies’, System Energy’s, and owners of Entergy Wholesale Commodities nuclear power plants.  Such changes could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms.  For further information regarding nuclear decommissioning costs, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 9 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, in particular in the northern United States, which is where most of the current fleet of Entergy Wholesale Commodities nuclear power plants is located.  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, financial condition, and liquidity.

(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, 2018, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 98% in 2019, 94% in 2020, 91% in 2021, and 66% in 2022 of its generation portfolio’s planned energy output, reflecting the planned shutdown or sale of the Entergy Wholesale Commodities nuclear power plants by mid-2022.


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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 (or requested operating licenses for Indian Point 2 and Indian Point 3).

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.

Among the factors that could affect market prices for electricity and fuel, all of which are beyond Entergy’s control to a significant degree, are:

•
prevailing market prices for natural gas, uranium (and its conversion, enrichment, and fabrication), coal, oil, and other fuels used in electric generation plants, including associated transportation costs, and supplies of such commodities;
•
seasonality and realized weather deviations compared to normalized weather forecasts;
•
availability of competitively priced alternative energy sources and the requirements of a renewable portfolio standard;
•
changes in production and storage levels of natural gas, lignite, coal and crude oil, and refined products;
•
liquidity in the general wholesale electricity market, including the number of creditworthy counterparties available and interested in entering into forward sales agreements for Entergy’s full hedging term;
•
the actions of external parties, such as the FERC and local independent system operators and other state or Federal energy regulatory bodies, that may impose price limitations and other mechanisms to address some of the volatility in the energy markets;
•
electricity transmission, competing generation or fuel transportation constraints, inoperability, or inefficiencies;

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•
the general demand for electricity, which may be significantly affected by national and regional economic conditions;
•
weather conditions affecting demand for electricity or availability of hydroelectric power or fuel supplies;
•
the rate of growth in demand for electricity as a result of population changes, regional economic conditions, and the implementation of conservation programs or distributed generation;
•
regulatory policies of state agencies that affect the willingness of Entergy Wholesale Commodities customers to enter into long-term contracts generally, and contracts for energy in particular;
•
increases in supplies due to actions of current Entergy Wholesale Commodities competitors or new market entrants, including the development of new generation facilities, expansion of existing generation facilities, the disaggregation of vertically integrated utilities, and improvements in transmission that allow additional supply to reach Entergy Wholesale Commodities’ nuclear markets;
•
union and labor relations;
•
changes in Federal and state energy and environmental laws and regulations and other initiatives, such as the Regional Greenhouse Gas Initiative, including but not limited to, the price impacts of proposed emission controls;
•
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; and
•
natural disasters, terrorist actions, wars, embargoes, and other catastrophic events.

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 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

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Commodities business’ generation facilities that sell energy and capacity into the wholesale power markets. Further, the New York Independent System Operator could determine that the timing of the shutdown of the Indian Point units could be inconsistent with its market power rules, and impose certain penalties that could affect Entergy Wholesale Commodities. 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.

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 assets of the Entergy Wholesale Commodities business are subject to further impairment in connection with the closure or sale of its nuclear power plants. Moreover, prior to the closure or 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 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 and Trust Fund Investments” 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.


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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, and Hurricane Isaac in 2012.  The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, higher than expected pension contributions, 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.

The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses.  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.


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Most of Entergy Corporation’s and its subsidiaries’ large customers, 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, 2018, based on power prices at that time, Entergy had liquidity exposure of $126 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $52 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, 2018, Entergy would have been required to provide approximately $69 million of additional cash or letters of credit under some of the agreements. As of December 31, 2018, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $310 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 recently enacted Tax Cuts and Jobs Act of 2017 significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The legislation and interpretive guidance from the IRS are unclear in certain respects and will require further interpretations and implementing regulations by the IRS, as well as state tax authorities, and the legislation could be subject to potential amendments and technical corrections, any of which could lessen or increase certain impacts of the legislation.

As further described in Note 3 to the financial statements, Entergy recorded a reduction of certain of its net deferred income tax assets (including the value of its net operating loss carryforwards) and regulatory liabilities, resulting in a charge against earnings in the fourth quarter 2017 of $526 million, including a $34 million net-of-tax reduction of regulatory liabilities, and Entergy and the Utility operating companies recorded a reduction of approximately $3.7 billion on a consolidated basis in certain of its net deferred tax liabilities and a corresponding increase in net regulatory liabilities. As a result of amortization of accumulated deferred income taxes and payment of such amounts to customers in 2018, Entergy’s net regulatory liability for income taxes balance is $2.1 billion as of December 31, 2018. 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.

Entergy believes that interpretations and implementing regulations by the IRS, as well as potential amendments and technical corrections, could result in lessening the impacts of certain aspects of this legislation. If Entergy is unable to successfully pursue avenues to manage the effects of the new tax legislation, or if additional interpretations, regulations, amendments, or technical corrections exacerbate the effects of the legislation, the legislation could have a material effect on Entergy’s results of operations, financial condition, and cash flows.

For further information regarding the effects of the Act, see the “Income Tax Legislation” section of Management’s Financial Discussion and Analysis for Entergy. Also, Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 and 2018 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses the regulatory proceedings that have considered the effects of the 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.


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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 complete strategic transactions, including merger, acquisition, divestiture, joint venture, restructuring or other strategic transactions, is subject to significant risks, including the risk that required regulatory or governmental approvals may not be obtained, risks relating to unknown or undisclosed problems or liabilities, and the risk that for these or other reasons, Entergy and its subsidiaries may be unable to achieve some or all of the benefits that they anticipate from such transactions.

From time to time, 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 announced that on July 30, 2018, it entered into purchase and sale agreements with Holtec International to sell to a Holtec subsidiary (i) 100% of the equity interests in Entergy Nuclear Generation Company, the owner of the Pilgrim Nuclear Power Station, and (ii) 100% of the equity interests in Entergy Nuclear Palisades, LLC, the owner of the Palisades Nuclear Power Plant and the Big Rock Point Site. In addition, as part of Entergy’s plan to exit the merchant power business, it plans to shut down its remaining merchant nuclear power plants by mid-2022. Last, as further described in the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy, 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 financial condition, 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:

•
the disposition of a business or asset may involve continued financial involvement in the divested business, such as through continuing equity ownership, transition service agreements, guarantees, indemnities, or other current or contingent financial obligations;
•
Entergy may encounter difficulty in finding buyers or executing alternative exit strategies on acceptable terms in a timely manner when it decides to sell an asset or a business, which could delay the accomplishment of its strategic objectives. Alternatively, Entergy may dispose of a business or asset at a price or on terms that are less than what it had anticipated, or with the exclusion of assets that must be divested or run off separately;
•
the disposition of a business could result in impairments and related write-offs of the carrying values of the relevant assets;
•
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;
•
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

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to them, 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 may not be successful in managing these or any other significant risks that it may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on its business.

The construction of, and capital improvements to, power generation facilities involve substantial risks.  Should construction or capital improvement 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 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 and escalating costs for materials, labor, and environmental compliance.  Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors not performing as required under their 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 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 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.

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

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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 are currently 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 are potentially 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 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 North American Electric Reliability Corporation (NERC), the SERC Reliability Corporation (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 may seek 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.

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, moderate temperatures in either season tend to decrease usage of energy and resulting revenues.  Seasonal pricing differentials, coupled with higher consumption levels, 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 or storms,  however, may stress the Utility operating companies’ generation facilities and transmission and distribution

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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 lower 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 economic conditions, weather, customer bill sizes (large bills tend to induce conservation), 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 demand from Entergy. 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 increasing adoption of energy efficient appliances, new building codes, distributed energy resources, energy storage, demand side management and new technologies such as rooftop solar are having a more permanent effect of 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 usage per customer in the residential and commercial classes, and further advances have the potential to 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 based on new or emerging technologies. In addition, electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity prices; however, they are sensitive to changes in conditions in the markets in which its customers operate.  Any negative change in any of these or other factors has 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 and environmental and regulatory obligations intended to compel greenhouse gas emission reductions or increase renewable energy requirements or to place a price on greenhouse gas emissions 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.  In 2010, the EPA promulgated its first regulations controlling greenhouse gas emissions from certain vehicles and from new and significantly modified stationary sources of emissions, including electric generating units.  During 2012 and 2014, the EPA proposed CO2 emission standards for new and existing sources. The EPA finalized these standards in 2015; however, in subsequent years the EPA has proposed to repeal and replace certain of those regulations. 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. 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 or renewable energy requirements can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects; 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

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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 deny or defer timely recovery of these costs.  Future changes in environmental regulation governing the emission of CO2 and other greenhouse gases or mix of generation sources could make some of Entergy’s electric generating units uneconomical to maintain or operate, and could increase the difficulty that Entergy and its subsidiaries have with obtaining or maintaining required environmental regulatory approvals, which could also materially affect the financial condition, results of operations and liquidity of Entergy and its subsidiaries.  In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change.  These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.

In 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.

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.

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.


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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, in particular Louisiana, Mississippi, and Texas, 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.

Domestic or international terrorist attacks, cyber attacks, and failures or breaches of Entergy’s and its subsidiaries’ or their suppliers’ technology systems may adversely affect Entergy’s results of operations.

As an operator of critical infrastructure, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism and cyber attacks, by domestic or foreign actors, whether as a direct act against one of Entergy’s generation, transmission or distribution facilities, or operations centers, or infrastructure and information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions. In addition, Entergy has increased its use of and reliance on the Internet in connection with its initiatives, including smart-grid-related projects. The Internet is inherently vulnerable and subject to disability or failure due to malicious activity, viruses, and other types of security events that would heighten the risk of a cyber attack. 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 its business. While malware was discovered on Entergy’s business network in 2018, and was remediated on a timely basis, it did not affect Entergy’s operational systems, generation plants (including nuclear), or transmission and distribution networks, nor did it have a material effect on Entergy’s business operations. Additionally, within Entergy’s industry, there have been attacks on energy infrastructure. Although it appears that the impact of such attacks on operations has been minimal to date, there may be more attacks in the future and the impact of such attacks may be significant. This risk may be enhanced by the efforts of cyber actors associated with governments that have carried out campaigns of cyber-enabled theft targeting global technology service providers and their customers. The Utility operating companies also face heightened risk of an act or threat by cyber criminals intent on accessing personal information for the purpose of committing identity theft, taking company-sensitive data, or disrupting their ability to operate.

Entergy and its subsidiaries operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure in accordance with mandatory and prescriptive reliability and security standards. Despite the implementation of multiple layers of security by Entergy and its subsidiaries, technology systems remain vulnerable to potential existing and new threats that could lead to

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unauthorized access to or loss of availability of critical systems essential to the reliable operation of Entergy’s electric system. Moreover, the functionality of Entergy’s technology systems depends on both its and third-party systems to which Entergy is connected directly or indirectly (such as systems belonging to suppliers, vendors and contractors, including cloud-service providers supporting business operations). While Entergy has processes in place to assess systems of certain of these suppliers, vendors and contractors, Entergy does not ultimately control the adequacy of their defenses against cyber and other attacks, but has implemented oversight measures to assess maturity and manage third-party risk. 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 may be unable to perform critical business functions that are essential to the company’s well-being and the health, safety, and security needs of its customers. In addition, an attack on its information technology infrastructure may result in a loss of its confidential, sensitive, and proprietary information, including personal information of its customers, employees, vendors, and others in Entergy’s care.
    
Any such attacks, failures or breaches could have a material effect on Entergy’s and the Utility operating companies’ business, financial condition, results of operations or reputation. Insurance may not be adequate to cover losses that might arise in connection with these events. The risk of such attacks, failures, or breaches may cause Entergy and the Utility operating companies to incur increased capital and operating costs to implement increased security for its power generation, transmission, and distribution assets and other facilities, such as additional physical facility security and security personnel, and for systems to protect its information technology and network infrastructure systems. 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 are affected by the amount of gas sold to customers.  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.  When purchased gas cost charges increase substantially reflecting higher gas procurement costs incurred by Entergy New Orleans, 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.

(System Energy)

System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on affiliated companies for all of its revenues.

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 authorized return on equity and capital structure. See Note 2 to the financial statements for further discussion of the proceedings.


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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 (including the Capital Funds Agreement), see Notes 8 and 10 to the 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 payments of dividends or distributions to Entergy Corporation by its subsidiaries in turn depend 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.  Provisions in the articles of incorporation of certain of Entergy Corporation’s subsidiaries restrict the payment of cash dividends to Entergy Corporation.  For further information regarding dividend or distribution restrictions to Entergy Corporation, see Note 7 to the financial statements.


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ENTERGY ARKANSAS, LLC AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

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. Entergy Arkansas also filed a notice with the Missouri Public Service Commission in December 2017 out of an abundance of caution, although Entergy Arkansas does not serve any retail customers in Missouri. In April 2018 the Missouri Public Service Commission approved Entergy Arkansas’s filing. 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.

Results of Operations

Net Income

2018 Compared to 2017

Net income increased $112.9 million primarily due to a lower effective income tax rate and higher net revenue, each after excluding the effect of the return of unprotected excess accumulated deferred income taxes to customers which is offset in income taxes, partially offset by higher other operation and maintenance expenses, higher depreciation and amortization expenses, and lower other income.

2017 Compared to 2016

Net income decreased $27.4 million primarily due to higher nuclear refueling outage expenses, higher depreciation and amortization expenses, higher taxes other than income taxes, and higher interest expense, partially offset by higher other income.


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Net Revenue

2018 Compared to 2017

Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory credits.  Following is an analysis of the change in net revenue comparing 2018 to 2017.
 
Amount
 
(In Millions)
 
 
2017 net revenue

$1,522.6

Return of unprotected excess accumulated deferred income taxes to customers
(367.7
)
Formula rate plan regulatory provision
(35.1
)
Retail electric price
84.8

Volume/weather
86.5

Other
14.7

2018 net revenue

$1,305.8


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. There is no effect on net income as the reduction in net revenue 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 formula rate plan regulatory provision is due to a provision recorded in the fourth quarter 2018 in connection with the 2019 formula rate plan filing that will be made in July 2019 associated with 2018. The provision is the estimate of the historical year netting adjustment that will be included in the 2019 filing to reflect the change in formula rate plan revenues associated with actual 2018 results when compared to the allowed rate of return on common equity. See Note 2 to the financial statements for a discussion of the formula rate plan.
    
The retail electric price variance is primarily due to an increase in formula rate plan rates effective with the first billing cycle of January 2018 and an increase in the energy efficiency rider effective January 2018, each as approved by the APSC. See Note 2 to the financial statements for further discussion of the formula rate plan filing.
    
The volume/weather variance is primarily due to an increase of 1,637 GWh, or 8%, in billed electricity usage, including the effect of more favorable weather on residential and commercial sales and an increase in industrial usage. The increase in industrial usage is primarily due to a new customer in the primary metals industry and an increase in demand from mid-size to small customers.    
    
2017 Compared to 2016

Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits).  Following is an analysis of the change in net revenue comparing 2017 to 2016.

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Amount
 
(In Millions)
 
 
2016 net revenue

$1,520.5

Retail electric price
33.8

Opportunity sales
5.6

Asset retirement obligation
(14.8
)
Volume/weather
(29.0
)
Other
6.5

2017 net revenue

$1,522.6


The retail electric price variance is primarily due to the implementation of formula rate plan rates effective with the first billing cycle of January 2017 and an increase in base rates effective February 24, 2016, each as approved by the APSC. A significant portion of the base rate increase was related to the purchase of Power Block 2 of the Union Power Station in March 2016. The increase was partially offset by decreases in the energy efficiency rider, as approved by the APSC, effective April 2016 and January 2017. See Note 2 to the financial statements for further discussion of the rate case and formula rate plan filings. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.

The opportunity sales variance results from the estimated net revenue effect of the 2017 and 2016 FERC orders in the opportunity sales proceeding attributable to wholesale customers. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding.

The asset retirement obligation affects net revenue because Entergy Arkansas records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and decommissioning trust fund earnings plus asset retirement obligation-related costs collected in revenue. The variance is primarily caused by a decrease in regulatory credits because of an increase in decommissioning trust fund earnings, including portfolio rebalancing for the ANO 1 and ANO 2 decommissioning trust funds.
    
The volume/weather variance is primarily due to the effect of less favorable weather on residential and commercial sales during the billed and unbilled sales periods. The decrease was partially offset by an increase of 733 GWh, or 11%, in industrial usage primarily due to a new customer in the primary metals industry.

Other Income Statement Variances

2018 Compared to 2017

Other operation and maintenance expenses increased primarily due to:

•
an increase of $16 million in energy efficiency costs;
•
an increase of $10.4 million in fossil-fueled generation expenses primarily due to higher long-term service agreement costs and higher labor costs in 2018 as compared to 2017;
•
an increase of $4.4 million in information technology expenses primarily due to higher labor costs and higher contract costs; and
•
an increase of $4 million as a result of the amount of transmission costs allocated by MISO.

The increase was partially offset by higher nuclear insurance refunds of $6.5 million and the receipts of stator-related settlements of $6.2 million in 2018.

Depreciation and amortization expenses increased primarily due to additions to plant in service.


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Other income decreased primarily due to changes in decommissioning trust fund investment activity, including portfolio rebalancings for the decommissioning trust funds in 2018 and 2017.

2017 Compared to 2016

Nuclear refueling outage expenses increased primarily due to the amortization of higher costs associated with the most recent outages compared to previous outages.

Other operation and maintenance expenses increased primarily due to:

•
the deferral in the first quarter 2016 of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance, as approved by the APSC as part of the 2015 rate case settlement. These costs are being amortized over a ten-year period beginning March 2016. See Note 2 to the financial statements for further discussion of the rate case settlement;
•
an increase of $9.5 million in transmission and distribution expenses primarily due to higher vegetation maintenance costs and higher labor costs, including contract labor;
•
an increase of $5.9 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2017 as compared to 2016; and
•
the effect of recording in July 2016 the final court decision in a lawsuit against the DOE related to spent nuclear fuel storage costs. The damages awarded included the reimbursement of $5.5 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense. See Note 8 to the financial statements for further discussion of Entergy Arkansas’s spent nuclear fuel litigation.

The increase was partially offset by:

•
a decrease of $16 million in nuclear generation expenses primarily due to a decrease in regulatory compliance costs compared to the prior year, partially offset by higher nuclear labor costs, including contract labor, to position the nuclear fleet to meet its operational goals. The decrease in regulatory compliance costs is primarily related to NRC inspection activities in 2016 as a result of the NRC’s March 2015 decision to move ANO into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. See Note 8 to the financial statements for a discussion of the ANO stator incident and subsequent NRC reviews;
•
a decrease of $11.5 million in energy efficiency expenses primarily due to the timing of recovery from customers; and
•
a decrease of $5.2 million in fossil-fueled generation expenses primarily due to lower long-term service agreement costs, partially offset by an overall higher scope of work including plant outages in 2017 as compared to 2016.

Taxes other than income taxes increased primarily due to an increase in ad valorem taxes primarily due to higher assessments and higher millage rates and an increase in local franchise taxes primarily due to higher billing factors.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including Power Block 2 of the Union Power Station purchased in March 2016. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.

Other income increased primarily due to higher realized gains in 2017 compared to 2016 on the decommissioning trust fund investments, including portfolio rebalancings for the decommissioning trust funds.

Interest expense increased primarily due to:

•
an increase of $3.3 million in estimated interest expense recorded in connection with the opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding;

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and
•
the issuance in May 2017 of $220 million of 3.5% Series first mortgage bonds and the issuance in June 2016 of $55 million of 3.5% Series first mortgage bonds, partially offset by the redemption in July 2016 of $60 million of 6.38% Series first mortgage bonds and the redemption in February 2016 of $175 million of 5.66% Series first mortgage bonds. See Note 5 to the financial statements for further discussion of long-term debt.

Income Taxes

The effective income tax rates for 2018, 2017, and 2016 were 669.7%, 40.1%, and 39.2%, respectively. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2018 was primarily due to the amortization of excess accumulated deferred income taxes. See Note 3 to the financial statements for a reconciliation of the federal statutory rates of 21% for 2018 and 35% for 2017 and 2016 to the effective income tax rates.

Income Tax Legislation

See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 and 2018 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses the regulatory proceedings that have considered the effects of the Act.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2018, 2017, and 2016 were as follows:
 
2018
 
2017
 
2016
 
(In Thousands)
Cash and cash equivalents at beginning of period

$6,216

 

$20,509

 

$9,135

 
 
 
 
 
 
Net cash provided by (used in):
 
 
 

 
 

Operating activities
211,825

 
555,556

 
676,511

Investing activities
(688,727
)
 
(829,312
)
 
(947,995
)
Financing activities
470,805

 
259,463

 
282,858

Net increase (decrease) in cash and cash equivalents
(6,097
)
 
(14,293
)
 
11,374

 
 
 
 
 
 
Cash and cash equivalents at end of period

$119

 

$6,216

 

$20,509


Operating Activities

Net cash flow provided by operating activities decreased $343.7 million in 2018 primarily due to:

•
the return of unprotected excess accumulated deferred income taxes to customers. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act;
•
payments of $135 million to the other Utility operating companies as a result of a compliance filing made in response to the FERC’s October 2018 order in the opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding; and

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•
income tax payments of $44.4 million in 2018 compared to income tax refunds of $8.1 million in 2017. Entergy Arkansas had income tax payments in 2018 and income tax refunds in 2017 in accordance with an intercompany income tax allocation agreement. The income tax payments in 2018 primarily resulted from the settlement of the 2012-2013 audit. The income tax refunds in 2017 resulted from the utilization of Entergy Arkansas’s net operating losses.

The decrease was partially offset by:

•
the timing of recovery of fuel and purchased power costs;
•
the effect of favorable weather on billed sales;
•
the timing of collection of receivables from customers; and
•
a decrease of $15.6 million in pension contributions in 2018. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Net cash flow provided by operating activities decreased $121 million in 2017 primarily due to income tax refunds of $8.1 million in 2017 compared to income tax refunds of $135.7 million in 2016. Entergy Arkansas had income tax refunds in 2016 and 2017 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2017 resulted from the utilization of Entergy Arkansas’s net operating losses. The 2016 income tax refunds resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit. See Note 3 to the financial statements for a discussion of the income tax audit.

Investing Activities

Net cash flow used in investing activities decreased $140.6 million in 2018 primarily due to:

•
a decrease of $62.4 million in nuclear construction expenditures primarily due to a lower scope of work performed on various nuclear projects in 2018 as compared to 2017;
•
a decrease of $55.8 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
•
a decrease of $23.5 million in fossil-fueled generation construction expenditures primarily due to the timing of outages and a lower scope of work performed on various projects in 2018 as compared to 2017.

Net cash flow used in investing activities decreased $118.7 million in 2017 primarily due to the purchase of Power Block 2 of the Union Power Station in March 2016 for approximately $237 million and a decrease of $35.5 million in transmission construction expenditures primarily due to a lower scope of work performed in 2017 as compared to 2016. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.

The decrease was partially offset by:

•
an increase of $50.4 million in nuclear construction expenditures primarily due to a higher scope of work performed on various nuclear projects in 2017 as compared to 2016;
•
an increase of $37.7 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;
•
an increase of $32.9 million in information technology construction expenditures primarily due to increased spending on substation technology upgrades;
•
an increase of $22.3 million in fossil-fueled generation construction expenditures primarily due to a higher scope of work performed on various projects in 2017 as compared to 2016; and
•
an increase of $11.2 million due to increased spending on advanced metering infrastructure.


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Financing Activities

Entergy Arkansas’s cash provided by financing activities increased $211.3 million in 2018 primarily due to:

•
a $350 million capital contribution from Entergy Corporation in May 2018 in anticipation of the return of unprotected excess accumulated deferred income taxes to customers and upcoming planned capital investments;
•
the repayment, in 2017, of Entergy Arkansas nuclear fuel company variable interest entity’s $60 million of 2.62% Series K notes;
•
the repayment, in 2017, of $54.7 million of 1.55% pollution control revenue bonds;
•
net long-term borrowings of $34.7 million in 2018 on the Entergy Arkansas nuclear fuel company variable interest entity credit facility; and
•
the issuance of $250 million of 4.0% Series first mortgage bonds in May 2018 as compared to the issuance of $220 million of 3.5% Series first mortgage bonds in May 2017.

The increase was partially offset by:

•
net repayments of short-term borrowings of $50 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2018 as compared to net short-term borrowings of $50 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2017;
•
money pool activity;
•
an increase of $76.8 million in common equity distributions paid in 2018 primarily to maintain Entergy Arkansas’s target capital structure; and
•
the redemption of $31 million of preferred stock in 2018 in connection with the internal restructuring. See Note 2 to the financial statements for further discussion of the internal restructuring and Note 6 to the financial statements for details of preferred stock activity.

Increases in Entergy Arkansas’s payable to the money pool are a source of cash flow, and Entergy Arkansas’s payable to the money pool increased by $16.6 million in 2018 compared to increasing by $114.9 million in 2017. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.

Net cash flow provided by financing activities decreased $23.4 million in 2017 primarily due to:

•
a $200 million capital contribution received from Entergy Corporation in March 2016 primarily in anticipation of Entergy Arkansas’s purchase of Power Block 2 of the Union Power Station;
•
the net issuance of $119.1 million of long-term debt in 2017 compared to the net issuance of $189.1 million of long-term debt in 2016; and
•
$15 million in common stock dividends paid in 2017 primarily to maintain Entergy Arkansas’s target capital structure. There were no common stock dividends paid in 2016 in anticipation of the purchase of Power Block 2 of the Union Power Station.

The decrease was partially offset by:

•
money pool activity;
•
the redemptions of $75 million of 6.45% Series preferred stock and $10 million of 6.08% Series preferred stock in 2016; and
•
net short-term borrowings of $50 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2017 compared to net repayments of $11.7 million in 2016.

Increases in Entergy Arkansas’s payable to the money pool are a source of cash flow, and Entergy Arkansas’s payable to the money pool increased by $114.9 million in 2017 compared to decreasing by $1.5 million in 2016.

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

Capital Structure

Entergy Arkansas’s debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio for Entergy Arkansas is primarily due to the $350 million capital contribution from Entergy Corporation in 2018.

 
December 31,
2018
 
December 31,
2017
Debt to capital
52.0%
 
55.5%
Effect of excluding the securitization bonds
(0.2%)
 
(0.3%)
Debt to capital, excluding securitization bonds (a)
51.8%
 
55.2%
Effect of subtracting cash
—%
 
—%
Net debt to net capital, excluding securitization bonds (a)
51.8%
 
55.2%

(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 and long-term debt, including the currently maturing portion. Capital consists of debt, preferred stock without sinking fund, and common 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 are 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 targeted 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 targeted capital structure.  In addition, in certain infrequent circumstances, such as 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 the targeted 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.
 
2019
 
2020
 
2021
 
(In Millions)
Planned construction and capital investment:
 
 
 

 
 

Generation

$210

 

$220

 

$385

Transmission
145

 
95

 
65

Distribution
245

 
270

 
290

Utility Support
130

 
100

 
75

Total

$730

 

$685

 

$815


Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2019
 
2020-2021
 
2022-2023
 
after 2023
 
Total
 
(In Millions)
Long-term debt (a)

$136

 

$780

 

$489

 

$4,128

 

$5,533

Operating leases

$20

 

$26

 

$17

 

$24

 

$87

Purchase obligations (b)

$525

 

$966

 

$619

 

$3,800

 

$5,910


(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 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 $27.1 million to its qualified pension plans and approximately $501 thousand to its other postretirement health care and life insurance plans in 2019, although the 2019 required pension contributions will be known with more certainty when the January 1, 2019 valuations are completed, which is expected by April 1, 2019.  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 $124.8 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, such as 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 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.

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


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Advanced Metering Infrastructure (AMI)

In September 2016, Entergy Arkansas filed an application seeking a finding from the APSC that Entergy Arkansas’s deployment of AMI is in the public interest. Entergy Arkansas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Arkansas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $208 million. The filing identified a number of quantified and unquantified benefits, and Entergy Arkansas provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal net benefit to customers of $406 million. Entergy Arkansas also sought to continue to include in rate base the remaining book value of existing meters, which was approximately $57 million at December 31, 2015, that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Arkansas proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Deployment of the communications network began in 2018. Entergy Arkansas proposed to include the AMI deployment costs and the quantified benefits in future formula rate plan filings, and the 2018 costs were approved in the 2017 formula rate plan filing. In June 2017 the APSC staff and Arkansas Attorney General filed direct testimony. The APSC staff generally supported Entergy Arkansas’s AMI deployment conditioned on various recommendations. The Arkansas Attorney General’s consultant primarily recommended denial of Entergy Arkansas’s application but alternatively suggested recommendations in the event the APSC approves Entergy Arkansas’s proposal. Entergy Arkansas filed rebuttal testimony in June 2017, substantially accepting the APSC staff’s recommendations. In August 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement. In October 2017 the APSC issued an order finding that Entergy Arkansas’s AMI deployment is in the public interest and approving the settlement agreement subject to a minor modification. Entergy Arkansas expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized over 15 years.

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;
•
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.

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 payables to the money pool were as follows as of December 31 for each of the following years.
2018
 
2017
 
2016
 
2015
(In Thousands)
$182,738
 
$166,137
 
$51,232
 
$52,742

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


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Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in September 2023. Entergy Arkansas also has a $20 million credit facility scheduled to expire in April 2019.  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, 2018, 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, 2018, 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 2021.  As of December 31, 2018, $59.6 million in loans were outstanding under the Entergy Arkansas nuclear fuel company variable interest entity credit facility. 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 November 2020 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 November 2020. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2020.

State and Local Rate Regulation and Fuel-Cost Recovery

Retail Rates

2015 Base Rate Filing
 
In April 2015, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing notified the APSC of Entergy Arkansas’s intent to implement a forward test year formula rate plan pursuant to Arkansas legislation passed in 2015, and requested a retail rate increase of $268.4 million, with a net increase in revenue of $167 million. The filing requested a 10.2% return on common equity. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors in the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposed a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a +/- 50 basis point band around the 9.75% allowed return on common equity. A significant portion of the rate increase is related to Entergy Arkansas’s acquisition in March 2016 of Union Power Station Power Block 2 for a base purchase price of $237 million. The settlement agreement also provided for amortization over a 10-year period of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance. In February 2016 the APSC approved the settlement with one exception that reduced the retail rate increase proposed in the settlement by $5 million. The settling parties agreed to the APSC modifications in February 2016. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. In March 2016, Entergy Arkansas made a compliance filing regarding the new rates that included an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. The interim base rate adjustment surcharge was designed to recover a total of $21.1 million over the nine-month period from April 2016 through December 2016.


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2016 Formula Rate Plan Filing

In July 2016, Entergy Arkansas filed with the APSC its 2016 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2017 test period to be below the formula rate plan bandwidth. The filing requested a $67.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%. In October 2016, Entergy Arkansas filed with the APSC revised formula rate plan attachments with an updated request for a $54.4 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved a settlement agreement and the $54.4 million revenue requirement increase with approximately $25 million of the $54.4 million revenue requirement subject to possible future adjustment and refund to customers with interest. The APSC requested supplemental information for some of Entergy Arkansas’s requested nuclear expenditures. In December 2016 the APSC approved Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2017. In April 2017, Entergy Arkansas filed a motion consented to by all parties requesting that it be permitted to submit the supplemental information requested by the APSC in conjunction with its 2017 formula rate plan filing, which was subsequently made in July 2017 and is discussed below. In May 2017 the APSC approved the joint motion and proposal to review Entergy Arkansas’s supplemental information on a concurrent schedule with the 2017 formula rate plan filing. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and recovery of the 2017 and 2018 nuclear costs.

2017 Formula Rate Plan Filing

In July 2017, Entergy Arkansas filed with the APSC its 2017 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2018 test period to be below the formula rate plan bandwidth.  The filing projected a $129.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%.  Entergy Arkansas’s formula rate plan is subject to a four percent annual revenue constraint and the projected annual revenue requirement increase exceeded the four percent, resulting in a proposed increase for the 2017 formula rate plan of $70.9 million. In October 2017, Entergy Arkansas filed with the APSC revised formula rate plan attachments that projected a $126.2 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors. The revised formula rate plan filing included a proposed $71.1 million revenue requirement increase based on a revision to the four percent constraint calculation. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the proceeding and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and the $71.1 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2018.

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 shows 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 includes 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 includes 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 exceeds the constraint, the resulting increase is limited to four percent of total revenue, which originally was $65.4 million but was increased to $66.7

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million based upon the APSC staff’s updated calculation of 2018 revenue, which included additional actual revenues for 2018. 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 certain 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. An additional schedule was issued by the APSC for briefing other contested issues, the outcome of which did not affect the 2018 filing but could affect future Entergy Arkansas formula rate plan filings. That briefing was completed in February 2019, and the APSC has not indicated when a decision on those issues can be expected.

Similar to the 2018 filing, the formula rate plan filing that will be made in 2019 to set the formula rates for the 2020 calendar year will include a netting adjustment that will compare projected costs and sales for 2018 that were approved in the 2017 formula rate plan filing to actual 2018 costs and sales data. In the fourth quarter 2018 Entergy Arkansas recorded a provision of $35.1 million that reflects the estimate of the historical year netting adjustment that will be included in the 2019 filing to reflect the change in formula rate plan revenues associated with actual 2018 results when compared to the allowed rate of return on equity. 

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.  

In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update were effective July 2016 through June 2017.

In May 2017, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected a credit amount of $0.3 million resulting from a compliance filing pursuant to the FERC’s September 2016 order. Additionally, the redetermined rate reflected recovery of the production cost allocation rider true-up adjustment of the 2016 unrecovered retail balance in the amount of $0.3 million. Because of the small effect of the 2017 production cost allocation rider update, Entergy Arkansas proposed to reduce the effective period of the update to one month, July 2017. After the one month collection period, rates were set to zero for all rate classes for the period August 2017 through June 2018.

In May 2018, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the 2017 under-recovered retail balance and a $2.8 million payment by Entergy Arkansas associated with a compliance filing pursuant to a March 2018 FERC order related to 2010 production costs. The rates for the 2018 production cost allocation rider update are effective July 2018 through June 2019.

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.


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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 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.

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

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July 2009 the Utility operating companies filed a response to the complaint arguing among other things that the System Agreement contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company.  The FERC subsequently ordered a hearing in the proceeding.

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

The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith.  The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load but provides a different allocation authority.  The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement.  The FERC in its decision established further hearing procedures to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision. The hearing was held in May 2013 and the ALJ issued an initial decision in August 2013. The LPSC, the APSC, the City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that the FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.

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

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

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Services’s appeal and held all of the appeals in abeyance pending final resolution of the related proceeding before the FERC.

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

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

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requirements, both for capital investments and operational needs, to position Entergy’s nuclear fleet to meet its operational goals, including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems and the Fukushima event; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license renewal and amendments, and decommissioning; the performance and capacity factors of these nuclear plants; 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 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.

See Note 8 to the financial statements for discussion of the NRC’s decision in March 2015 to move ANO into the “multiple/repetitive degraded cornerstone column,” or Column 4, of the NRC’s Reactor Oversight Process Action Matrix, and the resulting significant additional NRC inspection activities at the ANO site. 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. This action followed NRC inspections to review ANO 1’s and ANO 2’s performance in addressing issues that had previously resulted in classification in the “multiple/repetitive degraded cornerstone column,” or Column 4.

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.

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.

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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 and Trust Fund Investments

See “Impairment of Long-lived Assets and Trust Fund Investments” 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 and trust fund investments.

Taxation and Uncertain Tax Positions

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

Qualified Pension and Other Postretirement Benefits

Entergy Arkansas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are 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 2019 Qualified Pension Cost
 
Impact on 2018 Qualified Projected Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$2,620
 
$39,773
Rate of return on plan assets
 
(0.25%)
 
$2,782
 
$—
Rate of increase in compensation
 
0.25%
 
$1,338
 
$6,238

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 2019 Postretirement Benefit Cost
 
Impact on 2018 Accumulated Postretirement Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$59
 

$5,337

Health care cost trend
 
0.25%
 
$220
 

$3,805



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Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis


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

Costs and Funding

Total qualified pension cost for Entergy Arkansas in 2018 was $43 million.  Entergy Arkansas anticipates 2019 qualified pension cost to be $44.4 million. Entergy Arkansas contributed $64.1 million to its qualified pension plan in 2018 and estimates pension contributions will be approximately $27.1 million in 2019, although the 2019 required pension contributions will be known with more certainty when the January 1, 2019 valuations are completed, which is expected by April 1, 2019.

Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 2018 was $10.2 million.  Entergy Arkansas expects 2019 postretirement health care and life insurance benefit income of approximately $12.5 million.  Entergy Arkansas contributed $195 thousand to its other postretirement plans in 2018 and estimates 2019 contributions will be approximately $501 thousand.
  
Federal Healthcare Legislation

See “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.

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 members 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, 2018 and 2017, the related consolidated statements of income, cash flows and changes in member’s equity (pages 325 through 330 and applicable items in pages 53 through 237), for each of the three years in the period ended December 31, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, 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.


/s/ DELOITTE & TOUCHE LLP


New Orleans, Louisiana
February 26, 2019


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


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ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS
 
 
 
 
 
For the Years Ended December 31,
 
 
2018
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$2,060,643

 

$2,139,919

 

$2,086,608

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
517,245

 
402,777

 
325,036

Purchased power
 
252,390

 
230,652

 
233,350

Nuclear refueling outage expenses
 
77,915

 
83,968

 
56,650

Other operation and maintenance
 
724,831

 
694,157

 
693,181

Decommissioning
 
60,420

 
56,860

 
53,610

Taxes other than income taxes
 
104,771

 
103,662

 
93,109

Depreciation and amortization
 
292,649

 
277,146

 
264,215

Other regulatory charges (credits) - net
 
(14,807
)
 
(16,074
)
 
7,737

TOTAL
 
2,015,414

 
1,833,148

 
1,726,888

 
 
 
 
 
 
 
OPERATING INCOME
 
45,229

 
306,771

 
359,720

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
16,557

 
18,452

 
17,099

Interest and investment income
 
25,406

 
35,882

 
19,087

Miscellaneous - net
 
(14,874
)
 
(13,967
)
 
(14,838
)
TOTAL
 
27,089

 
40,367

 
21,348

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
124,459

 
122,075

 
115,311

Allowance for borrowed funds used during construction
 
(7,781
)
 
(8,585
)
 
(9,228
)
TOTAL
 
116,678

 
113,490

 
106,083

 
 
 
 
 
 
 
INCOME (LOSS) BEFORE INCOME TAXES
 
(44,360
)
 
233,648

 
274,985

 
 
 
 
 
 
 
Income taxes
 
(297,067
)
 
93,804

 
107,773

 
 
 
 
 
 
 
NET INCOME
 
252,707

 
139,844

 
167,212

 
 
 
 
 
 
 
Preferred dividend requirements
 
1,249

 
1,428

 
5,270

 
 
 
 
 
 
 
EARNINGS APPLICABLE TO COMMON EQUITY
 

$251,458

 

$138,416

 

$161,942

 
 
 
 
 
 
 
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,
 

2018

2017

2016
 

(In Thousands)
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$252,707

 

$139,844

 

$167,212

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 
443,698

 
427,394

 
414,933

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
129,524

 
67,711

 
201,219

Changes in assets and liabilities:
 
 

 
 

 
 

Receivables
 
4,294

 
(23,397
)
 
(39,118
)
Fuel inventory
 
6,210

 
3,402

 
29,929

Accounts payable
 
(126,405
)
 
16,011

 
143,645

Prepaid taxes and taxes accrued
 
9,568

 
40,127

 
37,485

Interest accrued
 
678

 
1,635

 
(3,303
)
Deferred fuel costs
 
43,869

 
33,190

 
(105,741
)
Other working capital accounts
 
(30,118
)
 
15,087

 
(46,490
)
Provisions for estimated losses
 
14,250

 
16,047

 
13,130

Other regulatory assets
 
32,460

 
(76,762
)
 
(95,464
)
Other regulatory liabilities
 
(341,682
)
 
1,043,507

 
62,994

Deferred tax rate change recognized as regulatory liability/asset
 
—

 
(1,047,837
)
 
—

Pension and other postretirement liabilities
 
(40,157
)
 
(70,826
)
 
(36,805
)
Other assets and liabilities
 
(187,071
)
 
(29,577
)
 
(67,115
)
Net cash flow provided by operating activities
 
211,825

 
555,556

 
676,511

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(660,044
)
 
(735,816
)
 
(666,289
)
Allowance for equity funds used during construction
 
17,013

 
19,211

 
17,754

Nuclear fuel purchases
 
(99,417
)
 
(151,424
)
 
(102,050
)
Proceeds from sale of nuclear fuel
 
54,810

 
51,029

 
39,313

Proceeds from nuclear decommissioning trust fund sales
 
300,801

 
339,434

 
197,390

Investment in nuclear decommissioning trust funds
 
(315,163
)
 
(352,138
)
 
(213,093
)
Payment for purchase of plant
 
—

 
—

 
(237,323
)
Insurance proceeds
 
14,790

 
—

 
10,404

Other
 
(1,517
)
 
392

 
5,899

Net cash flow used in investing activities
 
(688,727
)

(829,312
)

(947,995
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
958,434

 
294,656

 
817,563

Retirement of long-term debt
 
(690,488
)
 
(175,560
)
 
(628,433
)
Capital contribution from parent
 
350,000

 
—

 
200,000

Redemption of preferred stock
 
(32,660
)
 
—

 
(85,283
)
Change in money pool payable - net
 
16,601

 
114,905

 
(1,510
)
Changes in short-term borrowings - net
 
(49,974
)
 
49,974

 
(11,690
)
Distributions/dividends paid:
 
 

 
 

 
 

Common equity
 
(91,751
)
 
(15,000
)
 
—

Preferred stock
 
(1,606
)
 
(1,428
)
 
(6,631
)
Other
 
12,249

 
(8,084
)
 
(1,158
)
Net cash flow provided by financing activities
 
470,805

 
259,463

 
282,858

Net increase (decrease) in cash and cash equivalents
 
(6,097
)
 
(14,293
)
 
11,374

Cash and cash equivalents at beginning of period
 
6,216

 
20,509

 
9,135

Cash and cash equivalents at end of period
 

$119

 

$6,216

 

$20,509

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 
 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$118,731

 

$115,162

 

$112,912

Income taxes
 

$44,393

 

($8,141
)
 

($135,709
)
See Notes to Financial Statements.

 


 


 


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ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2018
 
2017
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$118

 

$6,184

Temporary cash investments
 
1

 
32

Total cash and cash equivalents
 
119

 
6,216

Securitization recovery trust account
 
4,666

 
3,748

Accounts receivable:
 
 

 
 

Customer
 
94,348

 
110,016

Allowance for doubtful accounts
 
(1,264
)
 
(1,063
)
Associated companies
 
48,184

 
38,765

Other
 
64,393

 
65,209

Accrued unbilled revenues
 
108,092

 
105,120

Total accounts receivable
 
313,753

 
318,047

Deferred fuel costs
 
19,235

 
63,302

Fuel inventory - at average cost
 
23,148

 
29,358

Materials and supplies - at average cost
 
196,314

 
192,853

Deferred nuclear refueling outage costs
 
78,966

 
56,485

Prepayments and other
 
14,553

 
12,108

TOTAL
 
650,754

 
682,117

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Decommissioning trust funds
 
912,049

 
944,890

Other
 
5,480

 
3,160

TOTAL
 
917,529

 
948,050

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
11,611,041

 
11,059,538

Construction work in progress
 
243,731

 
280,888

Nuclear fuel
 
220,602

 
277,345

TOTAL UTILITY PLANT
 
12,075,374

 
11,617,771

Less - accumulated depreciation and amortization
 
4,864,818

 
4,762,352

UTILITY PLANT - NET
 
7,210,556

 
6,855,419

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Other regulatory assets (includes securitization property of $14,329 as of December 31, 2018 and $28,583 as of December 31, 2017)
 
1,534,977

 
1,567,437

Deferred fuel costs
 
67,294

 
67,096

Other
 
20,486

 
13,910

TOTAL
 
1,622,757

 
1,648,443

 
 
 
 
 
TOTAL ASSETS
 

$10,401,596

 

$10,134,029

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2018
 
2017
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Short-term borrowings
 

$—

 

$49,974

Accounts payable:
 
 

 
 

Associated companies
 
251,768

 
365,915

Other
 
187,387

 
215,942

Customer deposits
 
99,053

 
97,687

Taxes accrued
 
56,889

 
47,321

Interest accrued
 
18,893

 
18,215

Current portion of unprotected excess accumulated deferred income taxes
 
99,316

 
—

Other
 
23,943

 
29,922

TOTAL
 
737,249

 
824,976

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
1,085,545

 
1,190,669

Accumulated deferred investment tax credits
 
32,903

 
34,104

Regulatory liability for income taxes - net
 
505,748

 
985,823

Other regulatory liabilities
 
402,668

 
363,591

Decommissioning
 
1,048,428

 
981,213

Accumulated provisions
 
48,979

 
34,729

Pension and other postretirement liabilities
 
313,295

 
353,274

Long-term debt (includes securitization bonds of $20,898 as of December 31, 2018 and $34,662 as of December 31, 2017)
 
3,225,759

 
2,952,399

Other
 
17,919

 
5,147

TOTAL
 
6,681,244

 
6,900,949

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
Preferred stock without sinking fund
 
—

 
31,350

 
 
 
 
 
EQUITY
 
 

 
 

Member's equity
 
2,983,103

 
2,376,754

TOTAL
 
2,983,103

 
2,376,754

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$10,401,596

 

$10,134,029

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 



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ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY
For the Years Ended December 31, 2018, 2017, and 2016
 
 
 
 
 
Member's Equity
 
(In Thousands)
 
 
Balance at December 31, 2015

$1,891,658

Net income
167,212

Capital contributions from parent
200,000

Capital stock redemption
(283
)
Preferred stock dividends
(5,270
)
Balance at December 31, 2016

$2,253,317

Net income
139,844

Common equity distributions
(15,000
)
Preferred stock dividends
(1,428
)
Other
21

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

 
 
See Notes to Financial Statements.
 



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ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
 
 
2018
 
2017
 
2016
 
2015
 
2014
 
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 

$2,060,643

 

$2,139,919

 

$2,086,608

 

$2,253,564

 

$2,172,391

Net income
 

$252,707

 

$139,844

 

$167,212

 

$74,272

 

$121,392

Total assets
 

$10,401,596

 

$10,134,029

 

$9,606,117

 

$8,747,774

 

$8,777,655

Long-term obligations (a)
 

$3,225,759

 

$2,983,749

 

$2,746,435

 

$2,691,189

 

$2,757,423

 
 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund.
 
 
 
 
 
 
 
 
 
 
 
 
 
2018
 
2017
 
2016
 
2015
 
2014
 
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
 
Electric Operating Revenues:
 
 

 
 

 
 

 
 

 
 

Residential
 

$807

 

$768

 

$789

 

$824

 

$755

Commercial
 
426

 
495

 
495

 
515

 
461

Industrial
 
434

 
472

 
446

 
477

 
424

Governmental
 
17

 
19

 
18

 
20

 
18

Total retail
 
1,684

 
1,754

 
1,748

 
1,836

 
1,658

Sales for resale:
 
 

 
 

 
 

 
 

 
 

Associated companies
 
104

 
128

 
49

 
128

 
131

Non-associated companies
 
145

 
121

 
118

 
195

 
282

Other
 
128

 
137

 
172

 
95

 
101

Total
 

$2,061

 

$2,140

 

$2,087

 

$2,254

 

$2,172

 
 
 
 
 
 
 
 
 
 
 
Billed Electric Energy Sales (GWh):
 
 
 
 

 
 

 
 

 
 

Residential
 
8,248

 
7,298

 
7,618

 
8,016

 
8,070

Commercial
 
5,967

 
5,825

 
5,988

 
6,020

 
5,934

Industrial
 
8,071

 
7,528

 
6,795

 
6,889

 
6,808

Governmental
 
239

 
237

 
237

 
235

 
238

Total retail
 
22,525

 
20,888

 
20,638

 
21,160

 
21,050

Sales for resale:
 
 

 
 

 
 

 
 

 
 

Associated companies
 
1,773

 
1,782

 
1,609

 
2,239

 
2,299

Non-associated companies
 
6,447

 
6,549

 
7,115

 
7,980

 
8,003

Total
 
30,745

 
29,219

 
29,362

 
31,379

 
31,352



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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

2018 Compared to 2017

Net income increased $359.3 million primarily due to a lower effective income tax rate and higher other income, partially offset by higher depreciation and amortization expenses and higher other operation and maintenance expenses.

2017 Compared to 2016

Net income decreased $305.7 million primarily due to the effect of the enactment of the Tax Cuts and Jobs Act, in December 2017, which resulted in a decrease of $182.6 million in net income in 2017, and the effect of a settlement with the IRS related to the 2010-2011 IRS audit, which resulted in a $136.1 million reduction of income tax expense in 2016. Also contributing to the decrease in net income were higher other operation and maintenance expenses. The decrease was partially offset by higher net revenue and higher other income. See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act and the IRS audit.

Net Revenue

2018 Compared to 2017

Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2018 to 2017.
 
Amount
 
(In Millions)
 
 
2017 net revenue

$2,560.5

Return of unprotected excess accumulated deferred
  income taxes to customers
(141.1
)
Regulatory credit in 2017 resulting from reduction of
  the federal corporate income tax rate
(55.5
)
Retail electric price
(32.3
)
Volume/weather
68.7

Other
15.9

2018 net revenue

$2,416.2


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. There is no effect on net income as the reduction in net revenue 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 regulatory credit in 2017 resulting from reduction of the federal corporate income tax rate variance is due to the reduction of the Vidalia purchased power agreement regulatory liability by $30.5 million and the reduction in 2017 of the Louisiana Act 55 financing savings obligation regulatory liabilities by $25 million, as a result of the

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Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis


enactment of the Tax Cuts and Jobs Act, in December 2017, which lowered the federal corporate income tax rate from 35% to 21%. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

The retail electric price variance is primarily due to regulatory charges of $73.1 million recorded in 2018 to reflect the effects of a provision in the settlement reached in the formula rate plan extension proceeding to return the benefits of the lower federal income tax rate in 2018 to customers. Partially offsetting the decrease were increases resulting from an increase in retail formula rate plan revenues, implemented with the first billing cycle of September 2018, and increases resulting from lower Grand Gulf purchased power expenses. See Note 2 to the financial statements for further discussion of the formula rate plan extension proceeding.

The volume/weather variance is primarily due to an increase of 907 GWh, or 2%, in billed electricity usage, including the effect of more favorable weather on residential and commercial sales. The increase was partially offset by a decrease in industrial usage primarily due to a decrease in demand from existing customers.

2017 Compared to 2016

Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2017 to 2016.
 
Amount
 
(In Millions)
 
 
2016 net revenue

$2,438.4

Regulatory credit resulting from reduction of the
  federal corporate income tax rate
55.5

Retail electric price
42.8

Louisiana Act 55 financing savings obligation
17.2

Volume/weather
(12.4
)
Other
19.0

2017 net revenue

$2,560.5


The regulatory credit resulting from reduction of the federal corporate income tax rate variance is due to the reduction of the Vidalia purchased power agreement regulatory liability by $30.5 million and the reduction of the Louisiana Act 55 financing savings obligation regulatory liabilities by $25 million as a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, which lowered the federal corporate income tax rate from 35% to 21%. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

The retail electric price variance is primarily due to an increase in formula rate plan revenues, implemented with the first billing cycle of March 2016, to collect the estimated first-year revenue requirement related to the purchase of Power Blocks 3 and 4 of the Union Power Station in March 2016 and a provision recorded in 2016 related to the settlement of the Waterford 3 replacement steam generator prudence review proceeding. See Note 2 to the financial statements for further discussion of the formula rate plan revenues and the Waterford 3 replacement steam generator prudence review proceeding.

The Louisiana Act 55 financing savings obligation variance results from a regulatory charge recorded in 2016 for tax savings to be shared with customers per an agreement approved by the LPSC. The tax savings resulted from the 2010-2011 IRS audit settlement on the treatment of the Louisiana Act 55 financing of storm costs for Hurricane Gustav and Hurricane Ike. See Note 3 to the financial statements for additional discussion of the settlement and benefit sharing.


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The volume/weather variance is primarily due to the effect of less favorable weather on residential and commercial sales and decreased usage during the unbilled sales period. The decrease was partially offset by an increase of 1,237 GWh, or 4%, in industrial usage primarily due to an increase in demand from existing customers and expansion projects in the chemicals industry.

Other Income Statement Variances

2018 Compared to 2017

Other operation and maintenance expenses increased primarily due to:

•
an increase of $11.9 million in fossil-fueled generation expenses primarily due to an overall higher scope of work performed during plant outages in 2018 as compared to 2017;
•
an increase of $11.7 million in energy efficiency costs primarily due to the implementation of a new energy efficiency program in January 2018;
•
an increase of $9 million in information technology expenses primarily due to higher software maintenance costs and higher contract costs;
•
an increase of $8.3 million in transmission expenses primarily due to higher labor and contract costs to support industrial customers;
•
an increase of $7.2 million in loss provisions; and
•
an increase of $7 million in nuclear generation expenses primarily due to higher nuclear labor costs to position the nuclear fleet to meet its operational goals and a higher scope of work performed during plant outages in 2018 as compared to 2017.

The increase was partially offset by:

•
a $14.8 million gain as a result of the sale of Willow Glen Power Plant
•
a decrease of $7.4 million as a result of the amortization through November 2017 of deferred MISO implementation costs, as approved by the LPSC;
•
higher nuclear insurance refunds of $4.2 million in 2018; and
•
a decrease of $3.7 million in compensation and benefits costs primarily due to lower incentive-based compensation accruals in 2018 as compared to 2017.

Taxes other than income taxes increased primarily due to increases in ad valorem taxes and payroll taxes. Ad valorem taxes increased primarily due to higher assessments.

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 2018, which included the St. Charles Power Station and Lake Charles Power Station projects. The increase was partially offset by a change in decommissioning trust fund investment activity, including portfolio rebalancing of certain of the decommissioning trust funds in 2017.

2017 Compared to 2016

Other operation and maintenance expenses increased primarily due to:

•
an increase of $17.8 million in nuclear generation expenses primarily due to higher nuclear labor costs, including contract labor, to position the nuclear fleet to meet its operational goals, partially offset by a lower scope of work performed during plant outages in 2017;
•
an increase of $9.5 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2017 as compared to the prior year;

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•
an increase of $4.1 million as a result of the amount of transmission costs allocated by MISO. See Note 2 to the financial statements for further information on the recovery of these costs;
•
an increase of $3.6 million in transmission and distribution expenses due to higher vegetation maintenance costs; and
•
an increase of $3.2 million in write-offs of customer accounts.

Taxes other than income taxes increased primarily due to increases in ad valorem taxes, state franchise taxes, and payroll taxes. Ad valorem taxes increased primarily due to higher assessments, including the assessment of Arkansas ad valorem taxes on the Union Power Station beginning in 2017. State franchise taxes increased primarily due to a change in the Louisiana franchise tax law which became effective in 2017.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including Power Blocks 3 and 4 of the Union Power Station purchased in March 2016, and the effects of recording in third quarter 2016 final court decisions in the River Bend and Waterford 3 lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $6 million of spent nuclear fuel storage costs previously recorded as depreciation expense. See Note 14 to the financial statements for discussion of the Union Power Station purchase. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

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 2017, which includes the St. Charles Power Station project, and higher realized gains in 2017 on the River Bend decommissioning trust fund investments, including portfolio rebalancing to the 30% interest in River Bend formerly owned by Cajun.

Interest expense decreased primarily due to an increase in the allowance for borrowed funds used during construction due to higher construction work in progress in 2017, which includes the St. Charles Power Station project.

Income Taxes

The effective income tax rate for 2018 was (8.8%). The difference in the effective income tax rate versus the federal statutory rate of 21% for 2018 was primarily due to the amortization of excess accumulated deferred income taxes and an IRS audit settlement for the 2012-2013 tax returns. See Note 3 to the financial statements for a reconciliation of the federal statutory rates of 21% to the effective income tax rates.

The effective income tax rate for 2017 was 60.5%. The difference in the effective income tax rate versus the statutory rate of 35% for 2017 was primarily due to the enactment of the Tax Cuts and Jobs Act, signed by President Trump in December 2017, which changed the federal corporate income tax rate from 35% to 21% effective in 2018. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rate.

The effective income tax rate for 2016 was 12.6%. The difference in the effective income tax rate of 12.6% versus the statutory rate of 35% for 2016 was primarily due to the reversal of a portion of the provision for uncertain tax positions as a result of the settlement of the 2010-2011 IRS audit in the second quarter 2016 and book and tax differences related to the non-taxable income distributions earned on preferred membership interests, partially offset by state income taxes. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rate.


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Income Tax Legislation

See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 and 2018 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses the regulatory proceedings that have considered the effects of the Act.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2018, 2017, and 2016 were as follows:
 
2018
 
2017
 
2016
 
(In Thousands)
Cash and cash equivalents at beginning of period

$35,907

 

$213,850

 

$35,102

 
 
 
 
 
 
Net cash provided by (used in):
 
 
 

 
 

Operating activities
1,395,204

 
1,337,545

 
1,037,912

Investing activities
(1,878,208
)
 
(1,787,409
)
 
(1,474,065
)
Financing activities
490,461

 
271,921

 
614,901

Net increase (decrease) in cash and cash equivalents
7,457

 
(177,943
)
 
178,748

 
 
 
 
 
 
Cash and cash equivalents at end of period

$43,364

 

$35,907

 

$213,850


Operating Activities

Net cash flow provided by operating activities increased $57.7 million in 2018 primarily due to:

•
a decrease of $76.5 million in spending on nuclear fueling outages;
•
a refund to customers in January 2017 of approximately $71 million as a result of the settlement approved by the LPSC related to the Waterford 3 replacement steam generator project. See Note 2 to the financial statements for discussion of the settlement and refund;
•
the receipt of $58.6 million from Entergy Arkansas as a result of a compliance filing made in response to the FERC’s October 2018 order in the Entergy Arkansas opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding; and
•
the timing of collection of receivables from customers.

The increase was partially offset by:

•
a decrease of $129 million in income tax refunds in 2018 as compared to the same period in 2017. Entergy Louisiana received income tax refunds in 2018 and 2017 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2018 and 2017 resulted from the utilization of Entergy Louisiana’s net operating loss;
•
the return of unprotected excess accumulated deferred income taxes to customers. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act; and
•
the timing of recovery of fuel and purchased power costs.


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Net cash flow provided by operating activities increased $299.6 million in 2017 primarily due to:
    
•
income tax refunds of $234.2 million in 2017 compared to income tax payments of $156.6 million in 2016. Entergy Louisiana received income tax refunds in 2017 and made income tax payments in 2016 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2017 resulted from the utilization of Entergy Louisiana’s net operating losses. The income tax payments in 2016 resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit, payments for state taxes resulting from the effect of the final settlement of the 2006-2007 IRS audit, and the effect of net operating loss limitations. See Note 3 to the financial statements for a discussion of the 2010-2011 IRS audit;
•
an increase due to the timing of recovery of fuel and purchased power costs; and
•
an interest payment of $60 million made in March 2016 related to the purchase of a beneficial interest in the Waterford 3 leased assets.

The increase was partially offset by:

•
a refund to customers in January 2017 of approximately $71 million as a result of the settlement approved by the LPSC related to the Waterford 3 replacement steam generator project. See Note 2 to the financial statements for discussion of the settlement and refund;
•
an increase of $62.8 million in spending on nuclear refueling outages; and
•
proceeds of $37.8 million received in August 2016 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 $90.8 million in 2018 primarily due to:

•
an increase of $67.8 million in transmission construction expenditures primarily due to a higher scope of work performed in 2018 as compared to 2017;
•
an increase of $65.5 million in fossil-fueled generation expenditures primarily due to higher spending on the Lake Charles Power Station project in 2018, partially offset by lower spending on the St. Charles Power Station project in 2018; and
•
money pool activity.

The increase was partially offset by a decrease of $97.5 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.

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 $35.7 million in 2018 compared to decreasing by $11.3 million in 2017. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.

Net cash flow used in investing activities increased $313.3 million in 2017 primarily due to:

•
an increase of $364.3 million in fossil-fueled generation construction expenditures primarily due to higher spending on the St. Charles Power Station and Lake Charles Power Station projects in 2017;
•
an increase of $148.9 million in transmission construction expenditures due to a higher scope of work performed in 2017;
•
an increase of $144.9 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;

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•
proceeds of $57.9 million received in 2016 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;
•
an increase of $53.6 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2017;
•
an increase of $30.4 million in distribution construction expenditures due to increased spending on digital technology improvements within the customer contact centers;
•
an increase of $19.9 million due to increased spending on advanced metering infrastructure; and
•
an increase of $12.3 million due to various information technology projects and upgrades in 2017.

The increase was partially offset by:

•
the purchase of Power Blocks 3 and 4 of the Union Power Station for an aggregate purchase price of approximately $475 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;
•
money pool activity; and
•
an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2017.

Decreases in Entergy Louisiana’s receivable from the money pool are a source of cash flow, and Entergy Louisiana’s receivable from the money pool decreased by $11.3 million in 2017 compared to increasing by $16.3 million in 2016.

Financing Activities

Net cash flow provided by financing activities increased $218.5 million in 2018 primarily due to:

•
the issuance of $750 million of 4.00% Series collateral trust mortgage bonds in March 2018. A portion of the proceeds was used to repay $375 million of 6.0% Series first mortgage bonds in May 2018;
•
the issuance of $600 million of 4.20% collateral trust mortgage bonds in August 2018. A portion of the proceeds was used to repay $300 million of 6.5% Series first mortgage bonds in September 2018;
•
the redemption of $25 million of 3.25% Series G nuclear fuel company variable interest entity notes payable in June 2017;
•
the redemption of $75 million of 3.25% Series Q nuclear fuel company variable interest entity notes payable in July 2017; and
•
the termination of $57.5 million of the Waterford 3 lease obligation and $42.7 million of Waterford Series collateral trust mortgage notes in 2017.

The increase was partially offset by:

•
the issuance of $450 million of 3.12% collateral trust mortgage bonds in May 2017. A portion of the proceeds was used to repay $45.3 million of Waterford Series collateral trust mortgage bonds;
•
net repayments of short-term borrowings of $43.5 million on the nuclear fuel company variable interest entities’ credit facilities in 2018 compared to net short-term borrowings of $39.7 million in 2017;
•
net repayments of long-term borrowings of $18.6 million on the nuclear fuel company variable interest entities’ credit facilities in 2018 compared to net long-term borrowings of $102 million in 2017; and
•
an increase of $36.8 million in common equity distributions in 2018 primarily to maintain Entergy Louisiana’s targeted capital structure.

Net cash flow provided by financing activities decreased $343 million in 2017 primarily due to the net issuance of $325.6 million of long-term debt in 2017 compared to the net issuance of $961.2 million in 2016. The decrease was partially offset by:

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•
a decrease of $194.3 million of common equity distributions primarily as a result of higher construction expenditures and higher nuclear fuel purchases in 2017; and
•
net borrowings of $39.7 million on the nuclear fuel company variable interest entities’ credit facilities in 2017 compared to net repayments of $56.6 million in 2016
            
See Note 5 to the financial statements for details of long-term debt.

Capital Structure

Entergy Louisiana’s debt to capital ratio is balanced between equity and debt, as shown in the following table.
 
December 31,
2018
 
December 31,
2017
Debt to capital
53.6
%
 
53.8
%
Effect of excluding securitization bonds
(0.3
%)
 
(0.3
%)
Debt to capital, excluding securitization bonds (a)
53.3
%
 
53.5
%
Effect of subtracting cash
(0.1
%)
 
(0.1
%)
Net debt to net capital, excluding securitization bonds (a)
53.2
%
 
53.4
%

(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 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 targeted 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 targeted capital structure.  In addition, in certain infrequent circumstances, such as 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 the targeted 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.


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Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.
 
2019
 
2020
 
2021
 
(In Millions)
Planned construction and capital investment:
 
 
 
 
 
Generation

$610

 

$325

 

$625

Transmission
460

 
405

 
265

Distribution
390

 
400

 
530

Utility Support
175

 
135

 
100

Total

$1,635

 

$1,265

 

$1,520


Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2019
 
2020-2021
 
2022-2023
 
After 2023
 
Total
 
(In Millions)
Long-term debt (a)

$301

 

$1,245

 

$1,033

 

$8,502

 

$11,081

Operating leases

$26

 

$41

 

$28

 

$22

 

$117

Purchase obligations (b)

$730

 

$1,347

 

$2,410

 

$5,043

 

$9,530


(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 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 $26.5 million to its qualified pension plans and approximately $17.9 million to its other postretirement health care and life insurance plans in 2019, although the 2019 required pension contributions will be known with more certainty when the January 1, 2019 valuations are completed, which is expected by April 1, 2019. 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 Louisiana has $802.3 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 Louisiana includes specific investments, such as the Washington Parish Energy Center, St. Charles Power Station, and Lake Charles Power Station, each discussed below; transmission projects 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; resource planning, including potential generation projects; system improvements; investments in River Bend and Waterford 3; software and security; and other investments. Entergy’s Utility supply plan initiative will continue to seek to transform its generation portfolio with new or repowered 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. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing

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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.

St. Charles Power Station

In August 2015, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by the construction of the St. Charles Power Station, a nominal 980 megawatt combined-cycle generating unit, on land adjacent to the existing Little Gypsy plant in St. Charles Parish, Louisiana. It is currently estimated to cost $869 million to construct, including transmission interconnection and other related costs. The LPSC issued an order approving certification of St. Charles Power Station in December 2016. Construction is in progress and commercial operation is expected to occur by mid-2019.

Lake Charles Power Station

In November 2016, Entergy Louisiana filed an application with the LPSC seeking certification that the public convenience and necessity would be served by the construction of the Lake Charles Power Station, a nominal 994 megawatt combined-cycle generating unit in Westlake, Louisiana, on land adjacent to the existing Nelson plant in Calcasieu Parish. The current estimated cost of the Lake Charles Power Station is $872 million, including estimated costs of transmission interconnection and other related costs. In May 2017 the parties to the proceeding agreed to an uncontested stipulation finding that construction of the Lake Charles Power Station is in the public interest and authorizing an in-service rate recovery plan. In July 2017 the LPSC issued an order unanimously approving the stipulation and approved certification of the unit. Construction is in progress and commercial operation is expected to occur by mid-2020.

Washington Parish Energy Center

In April 2017, Entergy Louisiana signed an agreement with a subsidiary of Calpine Corporation for the construction and purchase of a peaking plant. Calpine will construct the plant, which will consist of two natural gas-fired combustion turbine units with a total nominal capacity of approximately 361 MW. The plant, named the Washington Parish Energy Center, will be located in Bogalusa, Louisiana and, subject to permits and approvals, is expected to be completed by 2021. Subject to regulatory approvals, Entergy Louisiana will purchase the plant once it is complete for an estimated total investment of approximately $261 million, including transmission and other related costs. In May 2017, Entergy Louisiana filed an application with the LPSC seeking certification of the plant. In April 2018 the parties reached a settlement recommending certification and cost recovery through the additional capacity mechanism of the formula rate plan, consistent with prior LPSC precedent with respect to the certification and recovery of plants previously acquired by Entergy Louisiana. The LPSC issued an order approving the settlement in May 2018.

Advanced Metering Infrastructure (AMI)
    
In November 2016, Entergy Louisiana filed an application seeking a finding from the LPSC that Entergy Louisiana’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy Louisiana proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing included an estimate of implementation costs for AMI of $330 million. The filing identified a number of quantified and unquantified benefits, and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate base the remaining book value, approximately $92 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for the new advanced

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meters, the three-year deployment of which began in 2019. Deployment of the communications network began in 2018. Entergy Louisiana proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. The parties reached an uncontested stipulation permitting implementation of Entergy Louisiana’s proposed AMI system, with modifications to the proposed customer charge. In July 2017 the LPSC approved the stipulation. Entergy Louisiana expects to recover the undepreciated balance of its existing meters through a regulatory asset at current depreciation rates.

Sources of Capital

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

•
internally generated funds;
•
cash on hand;
•
debt or preferred membership interest issuances;
•
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.
    
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 the money pool were as follows as of December 31 for each of the following years.
2018
 
2017
 
2016
 
2015
(In Thousands)
$46,845
 
$11,173
 
$22,503
 
$6,154

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 2023. 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, 2018, 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, 2018, a $25.9 million letter of credit was 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 2021. As of December 31, 2018, $38.6 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, 2018, $82 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.


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Entergy Louisiana obtained authorizations from the FERC through November 2020 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 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

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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

2015 Formula Rate Plan Filing

In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflected an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue was required. The following other adjustments, however, were required under the formula rate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and an increase of $11 million to the MISO cost recovery mechanism. Rates were implemented with the first billing cycle of September 2016, subject to refund. Following implementation of the as-filed rates in September 2016, there were several interim updates to Entergy Louisiana’s formula rate plan, including the one submitted in December 2016, reflecting implementation of the settlement of the Waterford 3 replacement steam generator project prudence review described below. In June 2017 the LPSC staff and Entergy Louisiana filed a joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of the May 2016 evaluation report, interim updates, and corresponding proceedings with no changes to rates already implemented.

2016 Formula Rate Plan Filing

In May 2017, Entergy Louisiana filed its formula rate plan evaluation report for its 2016 calendar year operations. The evaluation report reflected an earned return on common equity of 9.84%. As such, no adjustment to base formula rate plan revenue was required. Adjustments, however, were required under the formula rate plan; the 2016 formula rate plan evaluation report showed a decrease in formula rate plan revenue of approximately $16.9 million, comprised of a decrease in legacy Entergy Louisiana formula rate plan revenue of $3.5 million, a decrease in legacy Entergy Gulf States Louisiana formula rate plan revenue of $9.7 million, and a decrease in incremental formula rate plan revenue of $3.7 million. Additionally, the formula rate plan evaluation report called for a decrease of $40.5 million in the MISO cost recovery revenue requirement from $46.8 million to $6.3 million. Rates reflecting these adjustments were implemented with the first billing cycle of September 2017, subject to refund. In September 2017 the LPSC issued its report indicating that no changes to Entergy Louisiana’s original formula rate plan evaluation report were required but reserved for several issues, including Entergy Louisiana’s September 2017 update to its formula rate plan evaluation report. In July 2018, Entergy Louisiana and the LPSC staff filed an unopposed joint report setting forth a correction to the annualization calculation, the effect of which was a net $3.5 million revenue requirement reduction and indicating that there are no outstanding issues with the 2016 formula rate plan report, the supplemental report, or the interim updates. In September 2018 the LPSC approved the unopposed joint report.


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Formula Rate Plan Extension Through 2019 Test Year


In August 2017, Entergy Louisiana filed a request with the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications to its terms.  Those modifications include: a one-time resetting of base rates to the midpoint of the band at Entergy Louisiana’s authorized return on equity of 9.95% for the 2017 test year; narrowing of the formula rate plan bandwidth from a total of 160 basis points to 80 basis points; and a forward-looking mechanism that would allow Entergy Louisiana to recover certain transmission-related costs contemporaneously with when those projects begin delivering benefits to customers.  In April 2018, the LPSC approved an unopposed joint motion filed by Entergy Louisiana and the LPSC staff that settles the matter. The settlement extends the formula rate plan for three years, providing for rates through at least August 2021. In addition to retaining the major features of the traditional formula rate plan, some of the more substantive features of the extended formula rate plan include:

•
a mid-point reset of formula rate plan revenues to a 9.95% earned return on common equity for the 2017 test year and for the St. Charles Power Station when it enters commercial operation;
•
a 9.8% target earned return on common equity for the 2018 and 2019 test years;
•
narrowing of the common equity bandwidth to plus or minus 60 basis points around the earned return on common equity;
•
a cap on potential revenue increase of $35 million for the 2018 evaluation period, and $70 million for the cumulative 2018 and 2019 evaluation periods, on formula rate plan cost of service rate increases (the cap excludes rate changes associated with the transmission recovery mechanism described below and rate changes associated with additional capacity);
•
a framework for the flow back of certain tax benefits created by the Tax Act to customers; and
•
a transmission recovery mechanism providing for the opportunity to recover certain transmission related expenditures in excess of $100 million for projects placed in service up to one month prior to rate change outside of sharing that is designed to operate in a fashion similar to the additional capacity mechanism.

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 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.

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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.

Waterford 3 Replacement Steam Generator Project

Following the completion of the Waterford 3 replacement steam generator project, the LPSC undertook a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs. In July 2014 the LPSC staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana.  An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent.  Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. Entergy Louisiana believed that the replacement steam generator costs were prudently incurred and applicable legal principles supported their recovery in rates.  Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation had not yet been considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy Louisiana recorded in the fourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to reflect that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery. Entergy Louisiana maintained that the ALJ’s recommendation contained significant factual and legal errors.

In October 2016 the parties reached a settlement in this matter. The settlement was approved by the LPSC in December 2016. The settlement effectively provided for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The refund to customers of approximately $71 million as a result of the settlement approved by the LPSC was made to customers in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016 related to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provided that Entergy Louisiana could retain the value associated with potential service credits agreed to by the project contractor, to the extent they are realized in the future. Following a review by the parties, an unopposed joint report of proceedings was filed by the LPSC staff and Entergy Louisiana in May 2017 and the LPSC accepted the joint report of proceedings resolving the matter.

Union Power Station and Deactivation or Retirement Decisions for Entergy Louisiana Plants

In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that

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acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of Union Power Station for an aggregate purchase price of approximately $475 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.

As a term of the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station, Entergy Louisiana agreed to make a filing with the LPSC to review its decisions to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to retire Little Gypsy 1.  In January 2016, Entergy Louisiana made its compliance filing with the LPSC. Entergy Louisiana, LPSC staff, and intervenors participated in a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisions for these four units in addition to information on the current deactivation decisions for the ten-year planning horizon. Parties requested further proceedings on the prudence of the decision to deactivate Willow Glen 2 and 4.  No party contested the prudence of the decision to deactivate Willow Glen 2 and 4 or suggested reactivation of these units; however, issues were raised related to Entergy Louisiana’s decision to give up its transmission service rights in MISO for Willow Glen 2 and 4 rather than placing the units into suspended status for the three-year term permitted by MISO. In March 2018 the LPSC adopted the ALJ’s recommended order finding that Entergy Louisiana did not demonstrate that its decision to permanently surrender transmission rights for the mothballed (not retired) Willow Glen 2 and 4 units was reasonable and that Entergy Louisiana should hold customers harmless from increased transmission expenses should those units be reactivated. Because no party or the LPSC suggested that Willow Glen 2 and 4 should be reactivated and because the cost to return those units to service far exceeded the revenue the units were expected to generate in MISO, Entergy Louisiana retired Willow Glen 2 and 4 in March 2018. Entergy Louisiana submitted a compliance filing regarding retirement of Willow Glen 2 and 4, and the LPSC closed the proceeding.

Retail Rates - Gas

2016 Rate Stabilization Plan Filing

In January 2017, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2016. The filing of the evaluation report for test year 2016 reflected an earned return on common equity of 6.37%. In April 2017 the LPSC approved a joint report of proceedings and Entergy Louisiana submitted a revised evaluation report reflecting a $1.2 million annual increase in revenue with rates implemented with the first billing cycle of May 2017.

2017 Rate Stabilization Plan Filing

In January 2018, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2017.  The filing of the evaluation report for the test year 2017 reflected an earned return on common equity of 9.06%.  This earned return is below the earnings sharing band of the rate stabilization plan and results in a rate increase of $0.1 million.  Due to the enactment in late-December 2017 of the Tax Cuts and Jobs Act, Entergy Louisiana did not have adequate time to reflect the effects of this tax legislation in the rate stabilization plan. In April 2018, Entergy Louisiana filed a supplemental evaluation report for the test year ended September 2017, reflecting the effects of the Tax Act, including a proposal to use the unprotected excess accumulated deferred income taxes to offset approximately $1.4 million of storm restoration deferred operation and maintenance costs incurred by Entergy Louisiana in connection with the August 2016 flooding disaster in its gas service area. The supplemental filing reflects an earned return on common equity of 10.79%. As-filed rates from the supplemental filing were implemented, subject to refund, with customers receiving a cost reduction of approximately $0.7 million effective with bills rendered on and after the first billing cycle of May 2018, as well as a $0.2 million reduction in the gas infrastructure rider effective with bills rendered on and after the first billing cycle of July 2018. The proceeding is currently in its discovery phase. A procedural schedule has not been established.


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2018 Rate Stabilization Plan Filing

In January 2019, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2018. The filing of the evaluation report for the test year 2018 reflected an earned return on common equity of 2.69%. This earned return is below the earning sharing band of the gas rate stabilization plan and results in a rate increase of $2.8 million. Entergy Louisiana will make a compliance filing in April 2019 and rates will be implemented during the first billing cycle of 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 December 2011 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates.  The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009.  In March 2016 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $8.6 million, plus interest, to customers and realign the recovery of approximately $12.7 million from Entergy Gulf States Louisiana’s fuel adjustment clause to base rates. In September 2016 the LPSC staff filed testimony stating that it was no longer recommending a disallowance of $3.4 million of the $8.6 million discussed above, but otherwise maintained the positions from its report. Subsequently, the parties entered into a settlement, which was approved by the LPSC in November 2016. The settlement recognized the dry cask storage recovery method issue, which was addressed in the separate proceeding approved by the LPSC in October 2017, provided for a refund of $5 million, which was made to legacy Entergy Gulf States Louisiana customers in December 2016, and resolved all other issues raised in the audit.

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 is evaluating the staff’s recommended disallowance.

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 is evaluating the staff’s recommended disallowance.

In June 2016 the LPSC staff provided notice of audits of Entergy Louisiana’s fuel adjustment clause filings and purchased gas adjustment clause filings. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and will also include a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includes 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. Discovery commenced in March 2017. No report of audit has been issued.


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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.  Discovery commenced in September 2018.  No report of audit has been issued.

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, including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems and the Fukushima event; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license renewal and amendments, and decommissioning; the performance and capacity factors of these nuclear plants; 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.
        
In December 2018 the NRC renewed Waterford 3’s operating license until 2044 and River Bend’s operating license until 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.


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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.

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 first quarter 2018, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for River Bend as a result of a revised decommissioning cost study. The revised estimate resulted in an $85.4 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 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 and Trust Fund Investments

See “Impairment of Long-lived Assets and Trust Fund Investments” 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 and trust fund investments.

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).

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Actuarial Assumption
 
Change in Assumption
 
Impact on 2019 Qualified Pension Cost
 
Impact on 2018 Projected Qualified Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$3,117
 
$42,612
Rate of return on plan assets
 
(0.25%)
 
$3,124
 
$—
Rate of increase in compensation
 
0.25%
 
$1,712
 
$8,597

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 2019 Postretirement Benefit Cost
 
Impact on 2018 Accumulated postretirement Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$695
 
$8,073
Health care cost trend
 
0.25%
 
$1,087
 
$6,610

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

Costs and Funding

Total qualified pension cost for Entergy Louisiana in 2018 was $52.1 million.  Entergy Louisiana anticipates 2019 qualified pension cost to be $48.6 million.  Entergy Louisiana contributed $71.9 million to its pension plans in 2018 and estimates pension contributions will be approximately $26.5 million in 2019, although the 2019 required pension contributions will be known with more certainty when the January 1, 2019 valuations are completed, which is expected by April 1, 2019.

Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 2018 were $11.2 million.  Entergy Louisiana expects 2019 postretirement health care and life insurance benefit costs of approximately $7.2 million.  Entergy Louisiana contributed $14.3 million to its other postretirement plans in 2018 and estimates that 2019 contributions will be approximately $17.9 million.

Federal Healthcare Legislation

See “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.

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 members 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, 2018 and 2017, the related consolidated statements of income, comprehensive income, cash flows, and changes in equity (pages 353 through 358 and applicable items in pages 53 through 237), for each of the three years in the period ended December 31, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, 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.


/s/ DELOITTE & TOUCHE LLP


New Orleans, Louisiana
February 26, 2019


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,
 
 
2018
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$4,232,541

 

$4,246,020

 

$4,126,343

Natural gas
 
63,779

 
54,530

 
50,705

TOTAL
 
4,296,320

 
4,300,550

 
4,177,048

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
915,410

 
912,060

 
804,433

Purchased power
 
960,272

 
980,070

 
890,058

Nuclear refueling outage expenses
 
51,626

 
52,074

 
51,361

Other operation and maintenance
 
959,185

 
941,604

 
897,661

Decommissioning
 
53,736

 
49,457

 
46,944

Taxes other than income taxes
 
183,745

 
175,359

 
165,665

Depreciation and amortization
 
492,179

 
467,369

 
451,290

Other regulatory charges (credits) - net
 
4,396

 
(152,080
)
 
44,131

TOTAL
 
3,620,549

 
3,425,913

 
3,351,543

 
 
 
 
 
 
 
OPERATING INCOME
 
675,771

 
874,637

 
825,505

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
79,922

 
51,485

 
27,925

Interest and investment income
 
141,882

 
164,550

 
154,778

Miscellaneous - net
 
(27,530
)
 
(39,756
)
 
(37,715
)
TOTAL
 
194,274

 
176,279

 
144,988

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
288,658

 
275,185

 
273,283

Allowance for borrowed funds used during construction
 
(39,616
)
 
(25,914
)
 
(14,571
)
TOTAL
 
249,042

 
249,271

 
258,712

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
621,003

 
801,645

 
711,781

 
 
 
 
 
 
 
Income taxes
 
(54,611
)
 
485,298

 
89,734

 
 
 
 
 
 
 
NET INCOME
 

$675,614

 

$316,347

 

$622,047

 
 
 
 
 
 
 
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,
 
 
2018
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
 
 
Net Income
 

$675,614

 

$316,347

 

$622,047

 
 
 
 
 
 
 
Other comprehensive income
 
 

 
 

 
 

Pension and other postretirement liabilities
 
 

 
 

 
 

(net of tax expense of $17,743, $234, and $5,034)
 
50,296

 
2,042

 
7,970

Other comprehensive income
 
50,296

 
2,042

 
7,970

 
 
 
 
 
 
 
Comprehensive Income
 

$725,910

 

$318,389

 

$630,017

 
 
 
 
 
 
 
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,
 
 
2018
 
2017
 
2016
 
 
(In Thousands)
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$675,614

 

$316,347

 

$622,047

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 
662,390

 
621,018

 
620,211

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
174,063

 
575,804

 
178,549

Changes in working capital:
 
 

 
 

 
 

Receivables
 
89,701

 
(53,829
)
 
(102,200
)
Fuel inventory
 
5,310

 
11,010

 
(2,693
)
Accounts payable
 
11,372

 
58,880

 
(36,720
)
Prepaid taxes and taxes accrued
 
12,711

 
128,261

 
(235,246
)
Interest accrued
 
7,922

 
(70
)
 
1,218

Deferred fuel costs
 
(40,036
)
 
23,236

 
(17,023
)
Other working capital accounts
 
(5,809
)
 
(30,911
)
 
6,462

Changes in provisions for estimated losses
 
8,307

 
(8,324
)
 
490

Changes in other regulatory assets
 
40,765

 
492,696

 
57,579

Changes in other regulatory liabilities
 
(125,185
)
 
605,453

 
62,351

Deferred tax rate change recognized as regulatory liability/asset
 
—

 
(1,207,808
)
 
—

Changes in pension and other postretirement liabilities
 
(106,269
)
 
(32,309
)
 
(52,559
)
Other
 
(15,652
)
 
(161,909
)
 
(64,554
)
Net cash flow provided by operating activities
 
1,395,204

 
1,337,545

 
1,037,912

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(1,805,641
)
 
(1,662,835
)
 
(1,030,416
)
Allowance for equity funds used during construction
 
79,922

 
51,485

 
27,925

Insurance proceeds
 
3,480

 
5,305

 
10,564

Nuclear fuel purchases
 
(111,329
)
 
(197,829
)
 
(73,618
)
Proceeds from the sale of nuclear fuel
 
53,603

 
42,634

 
63,304

Payment for purchase of plant
 
—

 
—

 
(474,670
)
Payments to storm reserve escrow account
 
(4,770
)
 
(2,110
)
 
(1,063
)
Receipts from storm reserve escrow account
 
4

 
8,835

 
—

Changes in securitization account
 
(1,655
)
 
880

 
351

Proceeds from nuclear decommissioning trust fund sales
 
1,055,690

 
231,293

 
219,182

Investment in nuclear decommissioning trust funds
 
(1,097,204
)
 
(266,592
)
 
(257,209
)
Changes in money pool receivable - net
 
(35,672
)
 
11,330

 
(16,349
)
Proceeds from sale of assets
 
11,987

 
—

 
—

Payment for purchase of assets
 
(26,623
)
 
(9,805
)
 
—

Litigation proceeds for reimbursement of spent nuclear fuel storage costs
 
—

 
—

 
57,934

Net cash flow used in investing activities
 
(1,878,208
)
 
(1,787,409
)
 
(1,474,065
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
2,319,799

 
733,344

 
2,450,063

Retirement of long-term debt
 
(1,664,354
)
 
(407,736
)
 
(1,488,870
)
Changes in short-term borrowings - net
 
(43,540
)
 
39,746

 
(56,562
)
Distributions paid:
 
 

 
 

 
 

Common equity
 
(128,000
)
 
(91,250
)
 
(285,500
)
Other
 
6,556

 
(2,183
)
 
(4,230
)
Net cash flow provided by financing activities
 
490,461

 
271,921

 
614,901

Net increase (decrease) in cash and cash equivalents
 
7,457

 
(177,943
)
 
178,748

Cash and cash equivalents at beginning of period
 
35,907

 
213,850

 
35,102

Cash and cash equivalents at end of period
 

$43,364

 

$35,907

 

$213,850

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 

 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$272,335

 

$266,871

 

$324,456

Income taxes
 

($105,157
)
 

($234,199
)
 

$156,605

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 


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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2018
 
2017
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$252

 

$5,836

Temporary cash investments
 
43,112

 
30,071

Total cash and cash equivalents
 
43,364

 
35,907

Accounts receivable:
 
 

 
 

Customer
 
199,903

 
254,308

Allowance for doubtful accounts
 
(1,813
)
 
(8,430
)
Associated companies
 
123,363

 
143,524

Other
 
60,879

 
60,893

Accrued unbilled revenues
 
167,052

 
153,118

Total accounts receivable
 
549,384

 
603,413

Fuel inventory
 
34,418

 
39,728

Materials and supplies - at average cost
 
324,627

 
299,881

Deferred nuclear refueling outage costs
 
24,406

 
65,711

Prepayments and other
 
38,715

 
34,035

TOTAL
 
1,014,914

 
1,078,675

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Investment in affiliate preferred membership interests
 
1,390,587

 
1,390,587

Decommissioning trust funds
 
1,284,996

 
1,312,073

Storm reserve escrow account
 
289,525

 
284,759

Non-utility property - at cost (less accumulated depreciation)
 
286,555

 
245,255

Other
 
14,927

 
18,999

TOTAL
 
3,266,590

 
3,251,673

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
20,532,312

 
19,678,536

Natural gas
 
211,421

 
191,899

Construction work in progress
 
1,864,582

 
1,281,452

Nuclear fuel
 
298,022

 
337,402

TOTAL UTILITY PLANT
 
22,906,337

 
21,489,289

Less - accumulated depreciation and amortization
 
8,837,596

 
8,703,047

UTILITY PLANT - NET
 
14,068,741

 
12,786,242

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Other regulatory assets (includes securitization property of $49,753 as of December 31, 2018 and $71,367 as of December 31, 2017)
 
1,105,077

 
1,145,842

Deferred fuel costs
 
168,122

 
168,122

Other
 
28,371

 
18,310

TOTAL
 
1,301,570

 
1,332,274

 
 
 
 
 
TOTAL ASSETS
 

$19,651,815

 

$18,448,864

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2018
 
2017
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Currently maturing long-term debt
 

$2

 

$675,002

Short-term borrowings
 
—

 
43,540

Accounts payable:
 
 

 
 

Associated companies
 
102,749

 
126,685

Other
 
390,367

 
404,374

Customer deposits
 
155,314

 
150,623

Taxes accrued
 
30,868

 
18,157

Interest accrued
 
83,450

 
75,528

Deferred fuel costs
 
31,411

 
71,447

Current portion of unprotected excess accumulated deferred income taxes
 
31,457

 
—

Other
 
49,202

 
79,037

TOTAL
 
874,820

 
1,644,393

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
2,226,721

 
2,050,371

Accumulated deferred investment tax credits
 
116,999

 
121,870

Regulatory liability for income taxes - net
 
581,001

 
725,368

Other regulatory liabilities
 
748,784

 
761,059

Decommissioning
 
1,280,272

 
1,140,461

Accumulated provisions
 
310,755

 
302,448

Pension and other postretirement liabilities
 
643,171

 
748,384

Long-term debt (includes securitization bonds of $55,682 as of December 31, 2018 and $77,736 as of December 31, 2017)
 
6,805,766

 
5,469,069

Other
 
160,608

 
176,637

TOTAL
 
12,874,077

 
11,495,667

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
EQUITY
 
 

 
 

Member’s equity
 
5,909,071

 
5,355,204

Accumulated other comprehensive loss
 
(6,153
)
 
(46,400
)
TOTAL
 
5,902,918

 
5,308,804

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$19,651,815

 

$18,448,864

 
 
 
 
 
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, 2018, 2017, and 2016
 
 
 
 
 
 
 
Common Equity
 
 
 
 
Member’s Equity
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
(In Thousands)
 
 
 
 
 
 
 
Balance at December 31, 2015
 

$4,793,724

 

($56,412
)
 

$4,737,312

Net income
 
622,047

 
—

 
622,047

Other comprehensive income
 
—

 
7,970

 
7,970

Distributions to parent
 
(285,500
)
 
—

 
(285,500
)
Other
 
(20
)
 
—

 
(20
)
Balance at December 31, 2016
 

$5,130,251

 

($48,442
)
 

$5,081,809

Net income
 
316,347

 
—

 
316,347

Other comprehensive income
 
—

 
2,042

 
2,042

Distributions declared on common equity
 
(91,250
)
 
—

 
(91,250
)
Other
 
(144
)
 
—

 
(144
)
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

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
2018
 
2017
 
2016
 
2015
 
2014
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$4,296,320

 

$4,300,550

 

$4,177,048

 

$4,417,146

 

$4,740,504

Net income

$675,614

 

$316,347

 

$622,047

 

$446,639

 

$446,022

Total assets

$19,651,815

 

$18,448,864

 

$17,701,271

 

$16,387,447

 

$16,423,825

Long-term obligations (a)

$6,805,766

 

$5,469,069

 

$5,612,593

 

$4,806,790

 

$4,882,813

 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (excluding currently maturing debt).
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2018
 
2017
 
2016
 
2015
 
2014
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
Electric Operating Revenues:
 

 
 

 
 

 
 

 
 

Residential

$1,244

 

$1,198

 

$1,196

 

$1,292

 

$1,358

Commercial
941

 
956

 
930

 
989

 
1,044

Industrial
1,462

 
1,534

 
1,350

 
1,420

 
1,569

Governmental
69

 
69

 
67

 
67

 
70

Total retail
3,716

 
3,757

 
3,543

 
3,768

 
4,041

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
295

 
278

 
368

 
406

 
427

Non-associated companies
62

 
64

 
50

 
36

 
80

Other
160

 
147

 
165

 
152

 
121

Total

$4,233

 

$4,246

 

$4,126

 

$4,362

 

$4,669

 
 
 
 
 
 
 
 
 
 
Billed Electric Energy Sales (GWh):
 

 
 

 
 

 
 

 
 

Residential
14,494

 
13,357

 
13,810

 
14,399

 
14,415

Commercial
11,578

 
11,342

 
11,478

 
11,700

 
11,555

Industrial
29,255

 
29,754

 
28,517

 
27,713

 
27,025

Governmental
823

 
790

 
794

 
756

 
732

Total retail
56,150

 
55,243

 
54,599

 
54,568

 
53,727

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
5,498

 
4,793

 
7,345

 
7,500

 
6,240

Non-associated companies
1,762

 
1,711

 
1,690

 
770

 
1,051

Total
63,410

 
61,747

 
63,634

 
62,838

 
61,018

 
 
 
 
 
 
 
 
 
 


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ENTERGY MISSISSIPPI, LLC

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

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.

Results of Operations

Net Income

2018 Compared to 2017

Net income increased $16 million primarily due to a lower effective income tax rate and higher net revenue, after excluding the effect of the return of unprotected excess accumulated deferred income taxes to customers which is offset in income taxes. The increase is partially offset by higher other operation and maintenance expenses, higher depreciation and amortization expenses, and higher taxes other than income taxes.

2017 Compared to 2016

Net income increased $0.8 million primarily due to higher other income, lower other operation and maintenance expenses, and lower interest expense, substantially offset by higher depreciation and amortization expenses and a higher effective income tax rate.


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Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis

Net Revenue

2018 Compared to 2017

Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2018 to 2017.
 
Amount
 
(In Millions)
 
 
2017 net revenue

$703.1

Return of unprotected excess accumulated deferred income taxes to customers
(153.0
)
Provision for formula rate plan look-back evaluation
(9.3
)
Retail electric price
4.2

Volume/weather
17.6

2018 net revenue

$562.6


The return of unprotected excess accumulated deferred income taxes to customers is due to a regulatory charge recorded in June 2018 that resulted in a $127.2 million reduction in net utility plant and the return of unprotected excess accumulated deferred income taxes through customer bill credits over a three-month period from July 2018 through September 2018, each per an agreement approved by the MPSC in June 2018, resulting from the stipulation related to the effects of the Tax Cuts and Jobs Act. There is no effect on net income as the reductions in net revenue are 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 provision for formula rate plan look-back evaluation results from a regulatory provision recorded in fourth quarter 2018 in connection with the formula rate plan look-back evaluation report filing that will be made in March 2019.  The provision reflects the estimate of the difference between the 2018 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.

The retail electric price variance is primarily due to higher storm damage rider revenues. Entergy Mississippi resumed billing the storm damage rider effective with the September 2017 billing cycle and ceased billing the storm damage rider effective with the August 2018 billing cycle.  See Note 2 to the financial statements for further discussion of the storm damage rider.

The volume/weather variance is primarily due to an increase of 643 GWh, or 5%, in billed electricity usage, including the effect of more favorable weather on residential sales.

2017 Compared to 2016

Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory credits. Following is an analysis of the change in net revenue comparing 2017 to 2016.

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Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis


 
Amount
 
(In Millions)
 
 
2016 net revenue

$705.4

Volume/weather
(18.2
)
Retail electric price
13.5

Other
2.4

2017 net revenue

$703.1


The volume/weather variance is primarily due to the effect of less favorable weather on residential and commercial sales.

The retail electric price variance is primarily due to a $19.4 million net annual increase in rates, effective with the first billing cycle of July 2016, and an increase in the energy efficiency rider, effective with the first billing cycle of February 2017, each as approved by the MPSC. The increase was partially offset by decreased storm damage rider revenues due to resetting the storm damage provision to zero beginning with the November 2016 billing cycle. Entergy Mississippi resumed billing the storm damage rider effective with the September 2017 billing cycle. See Note 2 to the financial statements for further discussion of the formula rate plan and the storm damage rider.

Other Income Statement Variances

2018 Compared to 2017

Other operation and maintenance expenses increased primarily due to:

•
a $5.8 million loss on the sale of fuel oil inventory per an agreement approved by the MPSC in June 2018 resulting from the stipulation related to the effects of the Tax Act. There is no effect on net income as the loss on the sale of fuel oil inventory is offset by a reduction in income tax expense. See Note 2 to the financial statements for discussion of the agreement;
•
an increase of $5.2 million in storm damage provisions. See Note 2 to the financial statements for a discussion of storm cost recovery;
•
an increase of $3.1 million in fossil-fueled generation expenses primarily due to an overall higher scope of work done during plant outages;
•
an increase of $2.7 million in customer service costs primarily due to write-offs of customer accounts and higher contract costs; and
•
an increase of $2.1 million in vegetation maintenance costs.

The increase was partially offset by a decrease of $2.4 million in compensation and benefits costs primarily due to lower incentive-based compensation accruals in 2018 as compared to 2017.

Taxes other than income taxes increased primarily due to an increase in ad valorem taxes and an increase in local franchise taxes. Ad valorem taxes increased primarily due to higher assessments and higher millage rates. Local franchise taxes increased primarily due to higher residential and commercial revenues in 2018 as compared to 2017.

Depreciation and amortization expenses increased primarily due to additions to plant in service.

Interest expense increased primarily due to the issuance of $150 million of 3.25% Series first mortgage bonds in November 2017.


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Entergy Mississippi, LLC
Management’s Financial Discussion and Analysis

2017 Compared to 2016

Other operation and maintenance expenses decreased primarily due to:

•
a decrease of $12 million in fossil-fueled generation expenses primarily due to lower long-term service agreement costs and a lower scope of work done during plant outages in 2017 as compared to the same period in 2016; and
•
a decrease of $3.6 million in storm damage provisions. See Note 2 to the financial statements for a discussion of storm cost recovery.

The decrease was partially offset by an increase of $4.8 million in energy efficiency costs and an increase of $2.7 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2017 as compared to the prior year.

Depreciation and amortization expenses increased primarily due to additions to plant in service.

Other income increased primarily due to interest income recorded in connection with the opportunity sales proceeding, interest income recorded on the deferred fuel balance, and an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2017 as compared to 2016. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding.

Interest expense decreased primarily due to the refinancing at lower interest rates of certain first mortgage bonds in 2016 and the retirement, at maturity, of $125 million of 3.25% Series first mortgage bonds in June 2016. See Note 5 to the financial statements for details of long-term debt.

Income Taxes

The effective income tax rates for 2018, 2017, and 2016 were (41,237%), 40.2%, and 36.9%, respectively. The difference in the effective income tax rate of (41,237%) versus the federal statutory rate of 21% for 2018 was primarily due to the flow through of excess accumulated deferred income taxes. See Note 3 to the financial statements for a reconciliation of the federal statutory rates of 21% for 2018 and 35% for 2017 and 2016 to the effective income tax rates.

Income Tax Legislation

See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 and 2018 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses the regulatory proceedings that have considered the effects of the Act.


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Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2018, 2017, and 2016 were as follows:
 
2018
 
2017
 
2016
 
(In Thousands)
Cash and cash equivalents at beginning of period

$6,096

 

$76,834

 

$145,605

 
 
 
 
 
 
Net cash provided by (used in):
 

 
 

 
 

Operating activities
418,382

 
226,585

 
212,280

Investing activities
(419,453
)
 
(417,226
)
 
(289,444
)
Financing activities
31,929

 
119,903

 
8,393

Net increase (decrease) in cash and cash equivalents
30,858

 
(70,738
)
 
(68,771
)
 
 
 
 
 
 
Cash and cash equivalents at end of period

$36,954

 

$6,096

 

$76,834


Operating Activities

Net cash flow provided by operating activities increased $191.8 million in 2018 primarily due to:

•
the receipt of $36.2 million from Entergy Arkansas as a result of a compliance filing made in response to the FERC’s October 2018 order in the Entergy Arkansas opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding;
•
the timing of collection of receivables from customers;
•
the timing of recovery of fuel and purchased power costs;
•
$26.2 million in proceeds from the sale of fuel oil inventory in 2018;
•
the effect of favorable weather on billed sales; and
•
the timing of collection of storm damage rider revenues. See Note 2 to the financial statements for further discussion of the storm damage rider.

The increase was partially offset by the return of unprotected excess accumulated deferred income taxes to customers. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.

Net cash flow provided by operating activities increased $14.3 million in 2017 primarily due to the timing of recovery of fuel and purchased power costs in 2017 as compared to 2016 and an increase of $12.6 million in income tax refunds in 2017 as compared to 2016. Entergy Mississippi had income tax refunds in 2017 and 2016 in accordance with an intercompany income tax allocation agreement. The 2017 income tax refunds were primarily due to the utilization of Entergy Mississippi’s federal net operating losses and state income tax refunds resulting from the carryback of net operating losses. The increase was partially offset by the timing of payments to vendors.

Investing Activities

Net cash flow used in investing activities increased $2.2 million in 2018 primarily due to:

•
money pool activity;
•
an increase of $9 million in information technology construction expenditures primarily due to increased spending on various technology projects;
•
an increase of $8.4 million in distribution construction expenditures primarily due to increased spending on advanced metering infrastructure; and

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•
several individually insignificant items.

The increase was partially offset by:

•
a decrease of $35.7 million in transmission construction expenditures primarily due to a lower scope of work performed in 2018;
•
a decrease of $17.1 million in fossil-fueled generation construction expenditures primarily due to a lower scope of work performed in 2018; and
•
a decrease of $15.2 million in storm spending in 2018.

Increases in Entergy Mississippi’s receivable from the money pool are a use of cash flow, and Entergy Mississippi’s receivable from the money pool increased by $39.7 million in 2018 compared to decreasing by $9 million in 2017. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.

Net cash flow used in investing activities increased $127.8 million in 2017 primarily due to:

•
an increase of $48.4 million in transmission construction expenditures primarily due to a higher scope of work performed in 2017 as compared to 2016;
•
an increase of $39.2 million in fossil-fueled generation construction expenditures primarily due to a higher scope of work performed in 2017 as compared to 2016; and
•
an increase of $30.2 million in distribution construction expenditures primarily due to an increase in storm spending in 2017 as compared to 2016 and increased spending on digital technology improvements within the customer contact centers.

Financing Activities

Net cash flow provided by financing activities decreased $88 million primarily due to:

•
the issuance of $150 million of 3.25% Series first mortgage bonds in November 2017; and
•
the redemption of $20 million of preferred stock in 2018 in connection with the internal restructuring. See Note 2 to the financial statements for further discussion of the internal restructuring and Note 6 to the financial statements for details of preferred stock activity.

The decrease was partially offset by:

•
the issuance of $55 million of 4.52% Series first mortgage bonds in December 2018;
•
a decrease of $16 million in common equity distributions paid in 2018 resulting from Entergy Mississippi’s historical and planned capital investments; and
•
an increase in advances received from customers for transmission projects.

Net cash flow provided by financing activities increased $111.5 million in 2017 primarily due to the issuance of $150 million of 3.25% Series first mortgage bonds in November 2017 and the redemption of $30 million of preferred stock in 2016, partially offset by the net issuance of $61.4 million of long-term debt in 2016.

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


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Capital Structure

Entergy Mississippi’s debt to capital ratio is balanced between equity and debt, as shown in the following table.
  
 
December 31,
2018
 
December 31,
2017
Debt to capital
50.6
%
 
51.5
%
Effect of subtracting cash
(0.7
%)
 
(0.2
%)
Net debt to net capital
49.9
%
 
51.3
%

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, preferred stock without sinking fund, and common 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.

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 targeted 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 targeted capital structure.  In addition, in certain infrequent circumstances, such as 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 the targeted 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.
 
2019
 
2020
 
2021
 
(In Millions)
Planned construction and capital investment:
 
 
 
 
 
Generation

$405

 

$50

 

$225

Transmission
145

 
140

 
135

Distribution
160

 
160

 
140

Utility Support
75

 
55

 
35

Total

$785

 

$405

 

$535



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Following are the amounts of Entergy Mississippi’s existing debt obligations and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2019
 
2020-2021
 
2022-2023
 
After 2023
 
Total
 
(In Millions)
Long-term debt (a)

$197

 

$84

 

$331

 

$1,590

 

$2,202

Operating leases

$9

 

$16

 

$9

 

$4

 

$38

Purchase obligations (b)

$219

 

$400

 

$371

 

$3,851

 

$4,841


(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 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 $7.7 million to its qualified pension plans and approximately $123 thousand to other postretirement health care and life insurance plans in 2019, although the 2019 required pension contributions will be known with more certainty when the January 1, 2019 valuations are completed, which is expected by April 1, 2019.  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 Mississippi has $30.5 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 Choctaw Generating Station and the Sunflower Solar Facility, each discussed below; 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 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.  

Choctaw Generating Station

In August 2018, Entergy Mississippi announced that it signed an asset purchase agreement to acquire from a subsidiary of GenOn Energy Inc. the Choctaw Generating Station, an 810 MW natural gas fired combined-cycle turbine plant located near French Camp, Mississippi.  The purchase price is expected to be approximately $314 million.  Entergy Mississippi also expects to invest in various plant upgrades at the facility after closing and expects the total cost of the acquisition to be approximately $401 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.  These include regulatory approvals from the MPSC and the FERC. Clearance under the Hart-Scott-Rodino Antitrust Improvements Act has occurred.  In October 2018, Entergy Mississippi filed an application with the MPSC seeking approval of the acquisition and cost recovery. In a separate filing in October 2018, Entergy Mississippi proposed revisions to its formula rate plan that would provide for a mechanism, the interim capacity rate adjustment mechanism,

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in the formula rate plan 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 additions approved by the MPSC. Closing is expected to occur by the end of 2019.

Sunflower Solar Facility

In November 2018, Entergy Mississippi announced that it signed an agreement for the purchase of an approximately 100 MW to-be-constructed 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 will be built by Sunflower County Solar Project, LLC, a sub-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 at 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 has 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.  Closing is expected to occur by the end of 2021.

Advanced Metering Infrastructure (AMI)

In November 2016, Entergy Mississippi filed an application seeking an order from the MPSC granting a certificate of public convenience and necessity and finding that Entergy Mississippi’s deployment of AMI is in the public interest. Entergy Mississippi proposed to replace existing meters with advanced meters that enable two-way data communication; to design and build a secure and reliable network to support such communications; and to implement support systems. AMI is intended to serve as the foundation of Entergy Mississippi’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, and Entergy Mississippi provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal benefit to customers of $496 million over a 15-year period, which when netted against the costs of AMI results in $183 million of net customer benefits. Entergy Mississippi also sought to continue to include in rate base the remaining book value, approximately $56 million at December 31, 2015, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019, subject to approval by the MPSC. Deployment of the communications network began in 2018. Entergy Mississippi proposed to include the AMI deployment costs and the quantified benefits in existing rate mechanisms, primarily through future formula rate plan filings and/or future energy cost recovery rider schedule re-determinations, as applicable. In May 2017 the Mississippi Public Utilities Staff and Entergy Mississippi entered into and filed a joint stipulation supporting Entergy Mississippi’s filing, and the MPSC issued an order approving the filing without material changes, finding that Entergy Mississippi’s deployment of AMI is in the public interest and granting a certificate of public convenience and necessity. The MPSC order also confirmed that Entergy Mississippi shall continue to include in rate base the remaining book value of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. In June 2018, as part of the order approving the joint stipulation between the Mississippi Public Utilities Staff and Entergy Mississippi addressing Entergy Mississippi’s 2018 formula rate plan evaluation report and the ratemaking effects of the Tax Act, the MPSC approved the acceleration of the recovery of substantially all of Entergy Mississippi’s existing customer meters in anticipation of AMI deployment.


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Sources of Capital

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

•
internally generated funds;
•
cash on hand;
•
debt or preferred membership interest issuances;
•
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 the money pool were as follows as of December 31 for each of the following years.
2018
 
2017
 
2016
 
2015
(In Thousands)
$41,380
 
$1,633
 
$10,595
 
$25,930

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 May 2019. No borrowings were outstanding under the credit facilities as of December 31, 2018.  In addition, Entergy Mississippi is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2018, $16.7 million of letters of credit were outstanding under Entergy Mississippi’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

Entergy Mississippi obtained authorization from the FERC through November 2020 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.

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.

Formula Rate Plan Filings

In March 2016, Entergy Mississippi submitted its formula rate plan 2016 test year filing showing Entergy Mississippi’s projected earned return for the 2016 calendar year to be below the formula rate plan bandwidth. The filing showed a $32.6 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 9.96%, within the formula rate plan bandwidth. In June 2016 the MPSC approved Entergy Mississippi’s joint stipulation with the Mississippi Public Utilities Staff. The joint stipulation

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provided for a total revenue increase of $23.7 million. The revenue increase included a $19.4 million increase through the formula rate plan, resulting in a return on common equity point of adjustment of 10.07%. The revenue increase also included $4.3 million in incremental ad valorem tax expenses to be collected through an updated ad valorem tax adjustment rider. The revenue increase and ad valorem tax adjustment rider were effective with the July 2016 bills.

In March 2017, Entergy Mississippi submitted its formula rate plan 2017 test year filing and 2016 look-back filing showing Entergy Mississippi’s earned return for the historical 2016 calendar year and projected earned return for the 2017 calendar year to be within the formula rate plan bandwidth, resulting in no change in rates. In June 2017, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a stipulation that confirmed that Entergy Mississippi’s earned returns for both the 2016 look-back filing and 2017 test year were within the respective formula rate plan bandwidths. In June 2017 the MPSC approved the stipulation, which resulted in no change in rates.

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 Note 2 to the financial statements for additional discussion regarding the treatment of the effects of the lower federal corporate income tax rate.

Entergy Mississippi’s formula rate plan includes a look-back evaluation report filing in March 2019 that will compare actual 2018 results to the performance-adjusted allowed return on rate base.  In fourth quarter 2018, Entergy Mississippi recorded a provision of $9.3 million that reflects the estimate of the difference between the 2018 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 October 2018, 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 non-fuel annual ownership costs of the Choctaw Generating Station, as well as to allow similar cost recovery treatment for other future capacity additions, such as the Sunflower Solar facility, that are approved by the MPSC.

Internal Restructuring

See “Internal Restructuring” above for additional discussion of Entergy Mississippi’s internal restructuring. 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 November 2015, 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 a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi should file a revised fuel

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factor with the MPSC no later than February 1, 2016. Pursuant to that order, Entergy Mississippi submitted a revised fuel factor. Additionally, because Entergy Mississippi’s projected over-recovery balance for the period ending January 31, 2016 was $68 million, in February 2016, Entergy Mississippi filed for another interim adjustment to the energy cost factor effective April 2016 to flow through to customers the projected over-recovery balance over a six-month period. That interim adjustment was approved by the MPSC in February 2016 effective for April 2016 bills.

In November 2016, 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 less than $2 million as of September 30, 2016. Also, in January 2017 the MPSC approved the annual factor effective with February 2017 bills. Also 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 its order, the MPSC expressly reserved the right to review and determine the recoverability of any and all purchased power expenditures made during fiscal year 2016. The MPSC hired independent auditors to conduct an annual operations audit and a financial audit. The independent auditors issued their audit reports in December 2017. The audit reports included several recommendations for action by Entergy Mississippi but did not recommend any cost disallowances. In January 2018 the MPSC certified the audit reports to the Mississippi Legislature. In November 2017 the Public Utilities Staff separately engaged a consultant to review the outage at the Grand Gulf Nuclear Station that began in 2016. The review is currently in progress.

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. Entergy Mississippi proposed a two-tiered energy cost factor designed to promote overall rate stability throughout 2018 particularly during the summer months. 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.

Mississippi Attorney General Complaint

The Mississippi Attorney General filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution.  The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand.  Entergy believes the complaint is unfounded.  In December 2008 the defendant Entergy companies removed the Attorney General’s lawsuit to U.S. District Court in Jackson, Mississippi. In June 2010 the MPSC authorized the deferral of certain legal expenses associated with this litigation until it is resolved. As of December 31, 2018, Entergy Mississippi has a regulatory asset of $23.6 million for these deferred legal expenses. Pre-trial and settlement conferences were held in October 2018. In October 2018 the District Court rescheduled the trial to April 2019.

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. As of April 30, 2016, Entergy Mississippi’s storm damage provision balance was less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with November 2016 bills. As of July 31, 2017, the balance in Entergy Mississippi’s accumulated storm damage provision was again less than $10 million, therefore

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Entergy Mississippi resumed billing the monthly storm damage provision effective with September 2017 bills. As of June 30, 2018, Entergy Mississippi’s storm damage provision balance exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with August 2018 bills.

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 and Trust Fund Investments

See “Impairment of Long-lived Assets and Trust Fund Investments” 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 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 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 2019 Qualified Pension Cost
 
Impact on 2018 Projected Qualified Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$755
 
$11,196
Rate of return on plan assets
 
(0.25%)
 
$823
 
$—
Rate of increase in compensation
 
0.25%
 
$392
 
$1,940

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 2019 Postretirement Benefit Cost
 
Impact on 2018 Accumulated Postretirement Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$153
 
$2,004
Health care cost trend
 
0.25%
 
$248
 
$1,617

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

Costs and Funding

Total qualified pension cost for Entergy Mississippi in 2018 was $10.8 million. Entergy Mississippi anticipates 2019 qualified pension cost to be $11.3 million.  Entergy Mississippi contributed $14.9 million to its qualified pension plans in 2018 and estimates 2019 pension contributions will be approximately $7.7 million, although the 2019 required pension contributions will be known with more certainty when the January 1, 2019 valuations are completed, which is expected by April 1, 2019.

Total postretirement health care and life insurance benefit income for Entergy Mississippi in 2018 was $1.5 million. Entergy Mississippi expects 2019 postretirement health care and life insurance benefit income of approximately $425 thousand. Entergy Mississippi contributed $87 thousand to its other postretirement plans in 2018 and estimates that 2019 contributions will be approximately $123 thousand.


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Federal Healthcare Legislation

See “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.

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 members 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, 2018 and 2017, the related statements of income, cash flows and changes in member’s equity (pages 376 through 380 and applicable items in pages 53 through 237), for each of the three years in the period ended December 31, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, 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.


/s/ DELOITTE & TOUCHE LLP


New Orleans, Louisiana
February 26, 2019


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,
 
 
2018
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$1,335,112

 

$1,198,229

 

$1,094,649

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
260,198

 
185,816

 
95,090

Purchased power
 
364,575

 
328,463

 
297,902

Other operation and maintenance
 
261,613

 
240,738

 
248,019

Taxes other than income taxes
 
101,999

 
95,051

 
94,482

Depreciation and amortization
 
152,577

 
143,479

 
136,214

Other regulatory charges (credits) - net
 
147,704

 
(19,134
)
 
(3,721
)
TOTAL
 
1,288,666

 
974,413

 
867,986

 
 
 
 
 
 
 
OPERATING INCOME
 
46,446

 
223,816

 
226,663

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
8,710

 
9,667

 
5,801

Interest and investment income
 
135

 
85

 
656

Miscellaneous - net
 
(2,732
)
 
(2,232
)
 
(5,955
)
TOTAL
 
6,113

 
7,520

 
502

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
55,905

 
51,260

 
57,114

Allowance for borrowed funds used during construction
 
(3,651
)
 
(3,875
)
 
(2,987
)
TOTAL
 
52,254

 
47,385

 
54,127

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
305

 
183,951

 
173,038

 
 
 
 
 
 
 
Income taxes
 
(125,773
)
 
73,919

 
63,854

 
 
 
 
 
 
 
NET INCOME
 
126,078

 
110,032

 
109,184

 
 
 
 


 
 
Preferred dividend requirements and other
 
834

 
953

 
2,443

 
 
 
 
 
 
 
EARNINGS APPLICABLE TO COMMON EQUITY
 

$125,244

 

$109,079

 

$106,741

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 





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ENTERGY MISSISSIPPI, LLC
STATEMENTS OF CASH FLOWS
 
 
 
 
 
For the Years Ended December 31,
 
 
2018
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$126,078

 

$110,032

 

$109,184

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation and amortization
 
152,577

 
143,479

 
136,214

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
56,502

 
84,816

 
60,986

Changes in assets and liabilities:
 
 

 
 

 
 

Receivables
 
37,762

 
(29,528
)
 
(28,819
)
Fuel inventory
 
33,675

 
5,266

 
401

Accounts payable
 
(7,472
)
 
3,595

 
33,733

Taxes accrued
 
(5,291
)
 
18,803

 
20,579

Interest accrued
 
(2,670
)
 
1,248

 
822

Deferred fuel costs
 
24,428

 
(25,487
)
 
(114,711
)
Other working capital accounts
 
(9,902
)
 
5,115

 
(5,222
)
Provisions for estimated losses
 
6,378

 
(9,676
)
 
6,378

Other regulatory assets
 
54,860

 
(17,412
)
 
(3,626
)
Other regulatory liabilities
 
(131,856
)
 
405,395

 
(2,986
)
     Deferred tax rate change recognized as regulatory liability/asset
 
—

 
(452,429
)
 
—

Pension and other postretirement liabilities
 
(8,405
)
 
(8,055
)
 
(10,648
)
Other assets and liabilities
 
91,718

 
(8,577
)
 
9,995

Net cash flow provided by operating activities
 
418,382

 
226,585

 
212,280

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(387,293
)
 
(427,616
)
 
(310,356
)
Allowance for equity funds used during construction
 
8,710

 
9,667

 
5,801

Changes in money pool receivable - net
 
(39,747
)
 
8,962

 
15,335

Payment for purchase of assets
 
—

 
(6,958
)
 
—

Other
 
(1,123
)
 
(1,281
)
 
(224
)
Net cash flow used in investing activities
 
(419,453
)
 
(417,226
)
 
(289,444
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
54,449

 
148,185

 
623,812

Retirement of long-term debt
 
—

 
—

 
(562,400
)
Redemption of preferred stock
 
(21,208
)
 
—

 
(30,000
)
Distributions/dividends paid:
 
 

 
 

 
 

Common equity
 
(10,000
)
 
(26,000
)
 
(24,000
)
Preferred stock
 
(993
)
 
(953
)
 
(2,755
)
Other
 
9,681

 
(1,329
)
 
3,736

Net cash flow provided by financing activities
 
31,929

 
119,903

 
8,393

Net increase (decrease) in cash and cash equivalents
 
30,858

 
(70,738
)
 
(68,771
)
Cash and cash equivalents at beginning of period
 
6,096

 
76,834

 
145,605

Cash and cash equivalents at end of period
 

$36,954

 

$6,096

 

$76,834

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 
 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$56,037

 

$47,631

 

$53,693

Income taxes
 

($19,118
)
 

($25,043
)
 

($12,487
)
See Notes to Financial Statements.
 
 

 
 

 
 


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ENTERGY MISSISSIPPI, LLC
BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2018
 
2017
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$11

 

$1,607

Temporary cash investments
 
36,943

 
4,489

Total cash and cash equivalents
 
36,954

 
6,096

Accounts receivable:
 
 

 
 

Customer
 
73,205

 
72,039

Allowance for doubtful accounts
 
(563
)
 
(574
)
Associated companies
 
51,065

 
45,081

Other
 
8,647

 
9,738

Accrued unbilled revenues
 
50,171

 
54,256

Total accounts receivable
 
182,525

 
180,540

Deferred fuel costs
 
8,016

 
32,444

Fuel inventory - at average cost
 
11,931

 
45,606

Materials and supplies - at average cost
 
47,255

 
42,571

Prepayments and other
 
9,365

 
7,041

TOTAL
 
296,046

 
314,298

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Non-utility property - at cost (less accumulated depreciation)
 
4,576

 
4,592

Escrow accounts
 
32,447

 
31,969

TOTAL
 
37,023

 
36,561

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
4,780,720

 
4,660,297

Property under capital lease
 
—

 
125

Construction work in progress
 
128,149

 
149,367

TOTAL UTILITY PLANT
 
4,908,869

 
4,809,789

Less - accumulated depreciation and amortization
 
1,641,821

 
1,681,306

UTILITY PLANT - NET
 
3,267,048

 
3,128,483

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Other regulatory assets
 
343,049

 
397,909

Other
 
3,638

 
2,124

TOTAL
 
346,687

 
400,033

 
 
 
 
 
TOTAL ASSETS
 

$3,946,804

 

$3,879,375

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY MISSISSIPPI, LLC
BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2018
 
2017
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Currently maturing long-term debt
 

$150,000

 

$—

Accounts payable:
 
 

 
 

Associated companies
 
42,928

 
55,689

Other
 
79,117

 
77,326

Customer deposits
 
85,085

 
83,654

Taxes accrued
 
77,552

 
82,843

Interest accrued
 
20,231

 
22,901

Other
 
7,526

 
12,785

TOTAL
 
462,439

 
335,198

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
551,869

 
488,806

Accumulated deferred investment tax credits
 
10,186

 
8,867

Regulatory liability for income taxes - net
 
246,402

 
411,011

Other regulatory liabilities
 
33,622

 
869

Asset retirement cost liabilities
 
9,206

 
9,219

Accumulated provisions
 
51,142

 
44,764

Pension and other postretirement liabilities
 
93,100

 
101,498

Long-term debt
 
1,175,750

 
1,270,122

Other
 
20,862

 
10,770

TOTAL
 
2,192,139

 
2,345,926

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
Preferred stock without sinking fund
 
—

 
20,381

 
 
 
 
 
EQUITY
 
 

 
 

Member's equity
 
1,292,226

 
1,177,870

TOTAL
 
1,292,226

 
1,177,870

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$3,946,804

 

$3,879,375

 
 
 
 
 
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, 2018, 2017, and 2016
 
 
 
 
 
Member's Equity
 
(In Thousands)
 
 
Balance at December 31, 2015

$1,012,050

Net income
109,184

Common equity distributions
(24,000
)
Preferred stock dividends
(2,443
)
Balance at December 31, 2016

$1,094,791

Net income
110,032

Common equity distributions
(26,000
)
Preferred stock dividends
(953
)
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

 
 
See Notes to Financial Statements.
 



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ENTERGY MISSISSIPPI, LLC
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
2018
 
2017
 
2016
 
2015
 
2014
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$1,335,112

 

$1,198,229

 

$1,094,649

 

$1,396,985

 

$1,524,193

Net income

$126,078

 

$110,032

 

$109,184

 

$92,708

 

$74,821

Total assets

$3,946,804

 

$3,879,375

 

$3,602,140

 

$3,477,407

 

$3,358,625

Long-term obligations (a)

$1,175,750

 

$1,290,503

 

$1,141,924

 

$972,058

 

$1,097,182

 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and preferred stock without sinking fund.
 
 
 
 
 
 
 
 
 
 
 
2018
 
2017
 
2016
 
2015
 
2014
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
Electric Operating Revenues:
 

 
 

 
 

 
 

 
 

Residential

$579

 

$502

 

$459

 

$565

 

$585

Commercial
462

 
423

 
374

 
465

 
481

Industrial
175

 
159

 
134

 
164

 
175

Governmental
44

 
41

 
38

 
47

 
47

Total retail
1,260

 
1,125

 
1,005

 
1,241

 
1,288

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
1

 
—

 
1

 
75

 
153

Non-associated companies
25

 
18

 
30

 
10

 
14

Other
49

 
55

 
59

 
71

 
69

Total

$1,335

 

$1,198

 

$1,095

 

$1,397

 

$1,524

 
 
 
 
 
 
 
 
 
 
Billed Electric Energy Sales (GWh):
 
 
 

 
 

 
 

 
 

Residential
5,829

 
5,308

 
5,617

 
5,661

 
5,672

Commercial
4,865

 
4,783

 
4,894

 
4,913

 
4,821

Industrial
2,559

 
2,536

 
2,493

 
2,283

 
2,297

Governmental
438

 
421

 
439

 
433

 
414

Total retail
13,691

 
13,048

 
13,443

 
13,290

 
13,204

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
—

 
—

 
—

 
1,419

 
2,657

Non-associated companies
1,060

 
857

 
1,021

 
261

 
193

Total
14,751

 
13,905

 
14,464

 
14,970

 
16,054



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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

2018 Compared to 2017

Net income increased $8.6 million primarily due to a lower effective income tax rate and higher net revenue, after excluding the effect of the return of unprotected excess accumulated deferred income taxes to customers which is offset in income taxes, partially offset by higher other operation and maintenance expenses, lower other income, and higher depreciation and amortization expenses.

2017 Compared to 2016

Net income decreased $4.3 million primarily due to higher taxes other than income taxes, lower net revenue, and a higher effective income tax rate, partially offset by lower other operation and maintenance expenses and higher other income.

Net Revenue

2018 Compared to 2017

Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 2018 to 2017.
 
Amount
 
(In Millions)
 
 
2017 net revenue

$311.9

Return of unprotected excess accumulated deferred income taxes to customers
(13.4
)
Net gas revenue
2.9

Volume/weather
10.7

Other
(1.5
)
2018 net revenue

$310.6

    
The return of unprotected excess accumulated deferred income taxes to customers is primarily due to the return of unprotected excess accumulated deferred income taxes through the fuel adjustment clause beginning in July 2018. There is no effect on net income as the reduction in net revenue 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 net gas revenue variance is primarily due to the effect of more favorable weather on residential and commercial sales.

The volume/weather variance is primarily due to an increase of 292 GWh, or 5%, in billed electricity usage, including the effect of more favorable weather on residential and commercial sales and a 1% increase in the average number of electric customers.


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Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis


2017 Compared to 2016

Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 2017 to 2016.
 
Amount
 
(In Millions)
 
 
2016 net revenue

$317.2

Retail electric price
(6.4
)
Volume/weather
(4.3
)
Other
5.4

2017 net revenue

$311.9

    
The retail electric price variance is primarily due to a net decrease in the purchased power and capacity acquisition cost recovery rider. There was a decrease in the rider primarily due to credits to customers as part of the Entergy New Orleans internal restructuring agreement in principle, effective with the first billing cycle of June 2017, partially offset by lower credits to customers in 2017 related to the retirement of Michoud Units 2 and 3. See Note 2 to the financial statements for further discussion of the credits associated with Entergy New Orleans’s internal restructuring and the Michoud retirement.

The volume/weather variance is primarily due to the effect of less favorable weather on residential and commercial sales, partially offset by an increase in residential and commercial usage resulting from a 1% increase in the average number of residential and commercial electric customers.
    
Other Income Statement Variances

2018 Compared to 2017

Other operation and maintenance expenses increased primarily due to:

•
an increase of $2.9 million in distribution expenses primarily due to higher contract labor costs;
•
an increase of $2.8 million in energy efficiency costs;
•
an increase of $2.2 million in gas operation expenses primarily due to higher labor costs, including contract labor;
•
an increase of $2.1 million in loss provisions;
•
an increase of $2.1 million in information technology costs primarily due to higher software maintenance costs and higher contract costs; and
•
an increase of $1.9 million in customer service costs primarily due to higher write-offs of customer accounts in 2018.

Depreciation and amortization expenses increased primarily due to additions to plant in service.

Other income decreased primarily due to the accrual in fourth quarter 2018 of a $5 million settlement offer in the New Orleans Power Station show cause proceeding. See “Liquidity and Capital Resources - Uses of Capital - New Orleans Power Station” below for discussion of the New Orleans Power Station proceedings.


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Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis


2017 Compared to 2016

Other operation and maintenance expenses decreased primarily due to:

•
a decrease of $7.9 million in fossil-fueled generation expenses primarily due to lower outage costs at Power Block 1 of the Union Power Station in 2017 as compared to 2016, the deactivation of Michoud Units 2 and 3 effective May 2016, and asbestos loss provisions in 2016;
•
a decrease of $4.5 million in other loss provisions; and
•
a decrease of $2.8 million due to lower write-offs of uncollectible customer accounts.

The decrease was partially offset by:

•
an increase of $4 million in distribution expenses primarily due to higher labor costs, including contract labor, and higher vegetation maintenance costs; and
•
an increase of $1.3 million in energy efficiency costs.

Taxes other than income taxes increased primarily due to an increase in ad valorem taxes and higher local franchise taxes. Ad valorem taxes increased primarily due to higher assessments, including the assessment of Arkansas ad valorem taxes on the Union Power Station beginning in 2017. Local franchise taxes increased primarily due to higher electric retail revenues in 2017 as compared to 2016.

Other income increased primarily due to a decrease in charitable contributions made in 2017 as compared to 2016.
    
Income Taxes

The effective income tax rates for 2018, 2017, and 2016 were (4.8%), 42.8%, and 37.0%, respectively. The difference in the effective income tax rate of (4.8%) versus the federal statutory rate of 21% for 2018 was primarily due to the amortization of excess accumulated deferred income taxes. See Note 3 to the financial statements for a reconciliation of the federal statutory rates of 21% for 2018 and 35% for 2017 and 2016 to the effective income tax rates.

Income Tax Legislation

See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 and 2018 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses the regulatory proceedings that have considered the effects of the Act.


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Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis


Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2018, 2017, and 2016 were as follows:
 
2018
 
2017
 
2016
 
(In Thousands)
Cash and cash equivalents at beginning of period

$32,741

 

$103,068

 

$88,876

 
 
 
 
 
 
Net cash provided by (used in):
 

 
 

 
 

Operating activities
171,778

 
127,797

 
205,211

Investing activities
(207,616
)
 
(109,500
)
 
(322,681
)
Financing activities
22,774

 
(88,624
)
 
131,662

Net increase (decrease) in cash and cash equivalents
(13,064
)

(70,327
)

14,192

 
 
 
 
 
 
Cash and cash equivalents at end of period

$19,677



$32,741



$103,068


Operating Activities

Net cash flow provided by operating activities increased $44 million in 2018 primarily due to:

•
an increase of $31.1 million in 2018 of income tax refunds. Entergy New Orleans had income tax refunds in 2018 and 2017 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2018 resulted from the utilization of Entergy New Orleans’s net operating loss; and
•
the receipt of $7 million from Entergy Arkansas as a result of a compliance filing made in response to the FERC’s October 2018 order in the Entergy Arkansas opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding.

The increase was partially offset by the return of unprotected excess accumulated deferred income taxes to customers. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.

Net cash flow provided by operating activities decreased $77.4 million in 2017 primarily due to a decrease of $77.3 million in income tax refunds in 2017 compared to 2016 and the timing of collections of receivables from customers and payments to vendors. Entergy New Orleans had income tax refunds in 2017 and 2016 in accordance with an intercompany income tax allocation agreement. The 2016 income tax refunds resulted primarily from deductible temporary differences. The decrease was partially offset by an increase due to the timing of recovery of fuel and purchased power costs.

Investing Activities
    
Net cash flow used in investing activities increased $98.1 million in 2018 primarily due to an increase of $74.5 million in fossil-fueled generation construction expenditures due to higher spending on the New Orleans Power Station project in 2018 as compared to 2017 and money pool activity.

Increases in Entergy New Orleans’s receivable from the money pool are a use of cash flow, and Entergy New Orleans’s receivable from the money pool increased by $9.3 million in 2018 compared to decreasing by $1.5 million in 2017. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.


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Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis


Net cash flow used in investing activities decreased $213.2 million in 2017 primarily due to the purchase of Power Block 1 of the Union Power Station for approximately $237 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase. The decrease was partially offset by an increase of $16.7 million in distribution construction expenditures primarily due to a higher scope of work performed in 2017 as compared to 2016.
    
Financing Activities

Entergy New Orleans’s financing activities provided $22.8 million of cash in 2018 compared to using $88.6 million of cash in 2017 primarily due to the following activity:

•
the issuance of $60 million of 4.51% Series first mortgage bonds in September 2018;
•
a decrease of $50.5 million in common equity distributions in 2018 as compared to 2017. Common equity distributions were lower in 2018 primarily as a result of the construction of the New Orleans Power Station, as discussed below, and the excess accumulated deferred income taxes being returned to customers as a result of the enactment of the Tax Cuts and Jobs act in December 2017. See Note 2 to the financial statements for discussion of regulatory proceedings related to the enactment of the Tax Cuts and Jobs Act;
•
$20 million in capital contributions received from Entergy Corporation in 2017. The 2017 contribution was made in consideration of Entergy New Orleans’s upcoming capital requirements; and
•
the redemption of $19.8 million of preferred stock in 2017 in connection with the internal restructuring, as discussed below.

Entergy New Orleans’s financing activities used $88.6 million of cash in 2017 compared to providing $131.7 million of cash in 2016 primarily due to the following activity:

•
the issuance of $110 million of 5.50% Series first mortgage bonds in March 2016;
•
an increase of $55.5 million in common equity distributions in 2017 as compared to 2016. Common equity distributions in 2017 increased primarily as a result of Entergy New Orleans’s cash position in excess of its working capital requirements. There were no common equity distributions in first quarter 2016 in anticipation of the purchase of Power Block 1 of the Union Power Station in March 2016;
•
a decrease of $27.8 million in capital contributions received from Entergy Corporation in 2017 compared to 2016. The 2017 contribution was made in consideration of Entergy New Orleans’s upcoming capital requirements. The 2016 contribution was made in anticipation of Entergy New Orleans’s purchase of Power Block 1 of the Union Power Station; and
•
the redemptions of $7.8 million of 4.75% Series preferred stock, $6 million of 5.56% Series preferred stock, and $6 million of 4.36% Series preferred stock in 2017 in connection with the internal restructuring, as discussed below.

See Note 14 to the financial statements for discussion of the Union Power Station purchase.

Capital Structure

Entergy New Orleans’s debt to capital ratio is balanced between equity and debt as shown in the following table. The increase in the debt to capital ratio is primarily due to the issuance of long-term debt in 2018. 

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December 31, 2018
 
December 31, 2017
Debt to capital
52.1
%
 
51.3
%
Effect of excluding securitization bonds
(3.5
%)
 
(4.7
%)
Debt to capital, excluding securitization bonds (a)
48.6
%
 
46.6
%
Effect of subtracting cash
(1.2
%)
 
(2.4
%)
Net debt to net capital, excluding securitization bonds (a)
47.4
%
 
44.2
%

(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, long-term debt, including the currently maturing portion, and the long-term payable due to an associated company. Capital consists of debt and common 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 targeted 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 targeted capital structure.  In addition, in certain infrequent circumstances, such as 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 the targeted capital structure.

Uses of Capital

Entergy New Orleans requires capital resources for:

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

Following are the amounts of Entergy New Orleans’s planned construction and other capital investments.
 
2019
 
2020
 
2021
 
(In Millions)
Planned construction and capital investment:
 
 
 
 
 
Generation

$110

 

$65

 

$100

Transmission
15

 
10

 
5

Distribution
90

 
95

 
110

Utility Support
25

 
15

 
20

Total

$240

 

$185

 

$235


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Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2019
 
2020-2021
 
2022-2023
 
After 2023
 
Total
 
(In Millions)
Long-term debt (a)

$34

 

$92

 

$163

 

$704

 

$993

Operating leases

$3

 

$4

 

$2

 

$2

 

$11

Purchase obligations (b)

$199

 

$397

 

$409

 

$2,770

 

$3,775


(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 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 $1.8 million to its qualified pension plan and approximately $2.1 million to other postretirement health care and life insurance plans in 2019, although the 2019 required pension contributions will be known with more certainty when the January 1, 2019 valuations are completed, which is expected by April 1, 2019. 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 $265.9 million of unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy New Orleans includes specific investments such as the New Orleans Power Station discussed below; 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; 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. 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.

New Orleans Power Station

In June 2016, Entergy New Orleans filed an application with the City Council seeking a public interest determination and authorization to construct the New Orleans Power Station, a 226 MW advanced combustion turbine in New Orleans, Louisiana, at the site of the existing Michoud generating facility, which was retired effective May 31, 2016. In January 2017 several intervenors filed testimony opposing the construction of the New Orleans Power Station on various grounds. In July 2017, Entergy New Orleans submitted a supplemental and amending application to the City Council seeking approval to construct either the originally proposed 226 MW advanced combustion turbine, or alternatively, a 128 MW unit composed of natural gas-fired reciprocating engines and a related cost recovery plan. The cost estimate for the alternative 128 MW unit is $210 million. In addition, the application renewed the commitment to pursue up to 100 MW of renewable resources to serve New Orleans. In March 2018 the City Council adopted a

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resolution approving construction of the 128 MW unit. The targeted commercial operation date is mid-2020, subject to receipt of all necessary permits. In April 2018 intervenors opposing the construction of the New Orleans Power Station filed with the City Council a request for rehearing, which was subsequently denied, and a petition for judicial review of the City Council’s decision, and also filed a lawsuit challenging the City Council’s approval based on Louisiana’s open meeting law. In May 2018 the City Council announced that it would initiate an investigation into allegations that Entergy New Orleans, Entergy, or some other entity paid or participated in paying certain attendees and speakers in support of the New Orleans Power Station to attend or speak at certain meetings organized by the City Council. In June 2018, Entergy New Orleans produced documents in response to a City Council resolution relating to this investigation. The City Council issued a request for qualifications for an investigator and in June 2018 selected two investigators. In October 2018 the investigators for the City Council released their report, concluding that individuals were paid to attend and/or speak in support of the New Orleans Power Station and that Entergy New Orleans “knew or should have known that such conduct occurred or reasonably might occur.”  The City Council held a special meeting on October 31, 2018 to allow the investigators to present the report and for the City Council to consider next steps.  At that meeting, the City Council issued a resolution requiring Entergy New Orleans to show cause why it should not be fined $5 million as a result of the findings in the report. In November 2018, Entergy New Orleans submitted its response to the show cause resolution, disagreeing with certain characterizations and omissions of fact in the report and asserting that the City Council could not legally impose the proposed fine.  Simultaneous with the filing of its response to the show cause resolution, Entergy New Orleans sent a letter to the City Council re-asserting that the City Council’s imposition of the proposed fine would be unlawful, but acknowledging that the actions of a subcontractor, which was retained by an Entergy New Orleans contractor without the knowledge or contractually-required consent of Entergy New Orleans, were contrary to Entergy’s values.  In that letter, Entergy New Orleans offered to donate $5 million to the City Council to resolve the show cause proceeding.  In January 2019, Entergy New Orleans submitted a new settlement proposal to the City Council. The proposal retains the components of the first offer but adds to it a commitment to make reasonable efforts to limit the costs of the project to the $210 million cost estimate with advanced notification of anticipated cost overruns, additional reporting requirements for cost and environmental items, and a commitment regarding reliability investment and to work with the New Orleans Sewerage and Water Board to provide a reliable source of power. In February 2019 the City Council approved a resolution approving the settlement proposal and allowing the construction of the New Orleans Power Station to commence.

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 conditioned-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 of the proceeding.


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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 August 2018 the City Council approved a procedural schedule opening discovery that was designed to encourage settlement by December 2018. 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 Orleans Parish project. The City Council approved a motion to allow parties to continue settlement discussions until April 2019.

Advanced Metering Infrastructure (AMI)

In October 2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest.  Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems.  AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid.  The filing included an estimate of implementation costs for AMI of $75 million. The filing identified a number of quantified and unquantified benefits, and Entergy New Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million.  Entergy New Orleans also sought to continue to include in rate base the remaining book value, approximately $21 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates.  Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which began in 2019.  Deployment of the information technology infrastructure began in 2017 and deployment of the communications network began in 2018.  Entergy New Orleans proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022.  The City Council’s advisors filed testimony in May 2017 recommending the adoption of AMI subject to certain modifications, including the denial of Entergy New Orleans’s proposed customer charge as a cost recovery mechanism. In January 2018 a settlement was reached between the City Council’s advisors and Entergy New Orleans. In February 2018 the City Council approved the settlement, which deferred cost recovery to the 2018 Entergy New Orleans rate case, but also stated that an adjustment for 2018-2019 AMI costs can be filed in the rate case and that, for all subsequent AMI costs, the mechanism to be approved in the 2018 rate case will allow for the timely recovery of such costs. In April 2018 the City Council adopted a resolution directing Entergy New Orleans to explore the options for accelerating the deployment of AMI. In June 2018 the City Council approved a one-year acceleration of AMI in its service area for an incremental $4.4 million.

Sources of Capital

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

•
internally generated funds;
•
cash on hand;
•
debt and preferred membership interest issuances;
•
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.


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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 the money pool were as follows as of December 31 for each of the following years.
2018
 
2017
 
2016
 
2015
(In Thousands)
$22,016
 
$12,723
 
$14,215
 
$15,794

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, 2018, there were no cash borrowings and a $0.8 million letter of credit was 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, 2018, a $2 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 October 2019 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 October 2019.

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

As a provision of the settlement agreement approved by the City Council in May 2015 providing for the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the provision of service to Entergy Louisiana’s customers in Algiers, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions included continued implementation of the then-remaining two years of the four-year phased-in rate increase for the Algiers area and certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of the settlement agreement allowed for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorized Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.

In addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy from Ninemile 6 (Ninemile PPA), which commenced operation in

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December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed only to Entergy New Orleans customers outside of Algiers.

In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the purchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the terms of the purchased power and capacity acquisition cost recovery rider to recover the non-fuel purchased power expense from Ninemile 6, the revenue requirement associated with the purchase of Power Block 1 of the Union Power Station, and a credit to customers of $400 thousand monthly beginning June 2016 in recognition of the decrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.

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 (estimated to be August 2019). 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. Entergy New Orleans is seeking approval of a permanent and stable source of funding for Energy Smart as part of its base rate case filed in September 2018.

In September 2018, Entergy New Orleans filed an electric and gas base rate case with the City Council. The filing requests 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 requests 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 includes a proposed gas rate decrease of $142 thousand. Entergy New Orleans’s rates reflect 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

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Tax Act would flow.  Entergy New Orleans included cost of service studies for electric and gas operations for the twelve months ending 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’s request for a change in rates is based on the projected twelve months ending December 31, 2018.

The filing’s major provisions include: (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 have recommended, among other things, overall rate reductions of approximately $33 million in electric rates and $3.8 million in gas rates. Certain intervenors have recommended overall rate reductions of up to approximately $49 million in electric rates and $5 million in gas rates. The procedural schedule calls for an evidentiary hearing to be held in June 2019.

Internal Restructuring

In July 2016, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy New Orleans, Inc. to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. In May 2017 the City Council adopted a resolution approving the proposed internal restructuring pursuant to an agreement in principle with the City Council advisors and certain intervenors. Pursuant to the agreement in principle, Entergy New Orleans would credit retail customers $10 million in 2017, $1.4 million in the first quarter of the year after the transaction closes, and $117,500 each month in the second year after the transaction closes until such time as new base rates go into effect as a result of the then-anticipated 2018 base rate case (which has subsequently been filed). Entergy New Orleans began crediting retail customers in June 2017. In June 2017 the FERC approved the transaction and, pursuant to the agreement in principle, Entergy New Orleans will provide additional credits to retail customers of $5 million in each of the years 2018, 2019, and 2020.

In November 2017, Entergy New Orleans 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.

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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 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.

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.

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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 and Trust Fund Investments

See “Impairment of Long-lived Assets and Trust Fund Investments” 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 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).

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Actuarial Assumption
 
Change in Assumption
 
Impact on 2019 Qualified Pension Cost
 
Impact on 2018 Projected Qualified Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$306
 
$4,917
Rate of return on plan assets
 
(0.25%)
 
$372
 
$—
Rate of increase in compensation
 
0.25%
 
$162
 
$746

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 2019 Postretirement Benefit Cost
 
Impact on 2018 Accumulated Postretirement Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
($5)
 
$1,036
Health care cost trend
 
0.25%
 
$44
 
$788

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

Costs and Funding

Total qualified pension cost for Entergy New Orleans in 2018 was $5.8 million. Entergy New Orleans anticipates 2019 qualified pension cost to be $5.1 million.  Entergy New Orleans contributed $7.3 million to its pension plans in 2018 and estimates 2019 pension contributions will be approximately $1.8 million, although the 2019 required pension contributions will be known with more certainty when the January 1, 2019 valuations are completed, which is expected by April 1, 2019.

Total postretirement health care and life insurance benefit income for Entergy New Orleans in 2018 was $3.7 million.  Entergy New Orleans expects 2019 postretirement health care and life insurance benefit income of approximately $3.6 million.  Entergy New Orleans contributed $3.8 million to its other postretirement plans in 2018 and estimates 2019 contributions will be approximately $2.1 million.

Federal Healthcare Legislation

See “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.

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 members 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, 2018 and 2017, the related consolidated statements of income, cash flows, and changes in member’s equity (pages 398 through 402 and applicable items in pages 53 through 237), for each of the three years in the period ended December 31, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, 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.


/s/ DELOITTE & TOUCHE LLP


New Orleans, Louisiana
February 26, 2019


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



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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS
 
 
 
 
 
For the Years Ended December 31,
 
 
2018
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$624,733

 

$631,744

 

$586,820

Natural gas
 
92,657

 
84,326

 
78,643

TOTAL
 
717,390

 
716,070

 
665,463

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
114,787

 
111,082

 
40,489

Purchased power
 
270,634

 
282,178

 
299,551

Other operation and maintenance
 
124,293

 
107,977

 
116,457

Taxes other than income taxes
 
56,141

 
54,590

 
48,078

Depreciation and amortization
 
55,930

 
52,945

 
51,737

Other regulatory charges - net
 
21,413

 
10,889

 
8,258

TOTAL
 
643,198

 
619,661

 
564,570

 
 
 
 
 
 
 
OPERATING INCOME
 
74,192

 
96,409

 
100,893

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
5,941

 
2,418

 
1,178

Interest and investment income
 
604

 
707

 
256

Miscellaneous - net
 
(10,444
)
 
(1,269
)
 
(4,158
)
TOTAL
 
(3,899
)
 
1,856

 
(2,724
)
 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
21,772

 
21,281

 
21,061

Allowance for borrowed funds used during construction
 
(2,195
)
 
(847
)
 
(446
)
TOTAL
 
19,577

 
20,434

 
20,615

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
50,716

 
77,831

 
77,554

 
 
 
 
 
 
 
Income taxes
 
(2,436
)
 
33,278

 
28,705

 
 
 
 
 
 
 
NET INCOME
 
53,152

 
44,553

 
48,849

 
 
 
 
 
 
 
Preferred dividend requirements and other
 
—

 
841

 
965

 
 
 
 
 
 
 
EARNINGS APPLICABLE TO COMMON EQUITY
 

$53,152

 

$43,712

 

$47,884

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 




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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
 
 
 
For the Years Ended December 31,
 
 
2018
 
2017
 
2016
 
 
(In Thousands)
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$53,152

 

$44,553

 

$48,849

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation and amortization
 
55,930

 
52,945

 
51,737

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
24,548

 
64,036

 
140,283

Changes in assets and liabilities:
 
 

 
 

 
 

Receivables
 
15,724

 
(18,058
)
 
(3,888
)
Fuel inventory
 
357

 
(49
)
 
71

Accounts payable
 
(385
)
 
1,874

 
15,434

Prepaid taxes and taxes accrued
 
30,547

 
(22,100
)
 
(1,685
)
Interest accrued
 
879

 
44

 
534

Deferred fuel costs
 
(6,486
)
 
12,592

 
(33,839
)
Other working capital accounts
 
4,146

 
(2,711
)
 
4,165

Provisions for estimated losses
 
1,511

 
(3,430
)
 
4,326

Other regulatory assets
 
21,637

 
16,673

 
(2,784
)
Other regulatory liabilities
 
(28,459
)
 
110,147

 
(3,997
)
Deferred tax rate change recognized as regulatory liability/asset
 
—

 
(111,170
)
 
—

Pension and other postretirement liabilities
 
(15,134
)
 
(15,994
)
 
(6,859
)
Other assets and liabilities
 
13,811

 
(1,555
)
 
(7,136
)
Net cash flow provided by operating activities
 
171,778

 
127,797

 
205,211

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(202,186
)
 
(115,584
)
 
(90,512
)
Allowance for equity funds used during construction
 
5,941

 
2,418

 
1,178

Payment for purchase of plant
 
—

 
—

 
(237,335
)
Investments in affiliates
 
—

 
—

 
(38
)
Changes in money pool receivable - net
 
(9,293
)
 
1,492

 
1,579

Payments to storm reserve escrow account
 
(1,311
)
 
(597
)
 
(438
)
Receipts from storm reserve escrow account
 
3

 
2,488

 
3

Changes in securitization account
 
(770
)
 
283

 
2,882

Net cash flow used in investing activities
 
(207,616
)
 
(109,500
)
 
(322,681
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
59,234

 
—

 
240,604

Retirement of long-term debt
 
(11,042
)
 
(10,600
)
 
(132,526
)
Repayment of long-term payable due to associated company
 
(2,077
)
 
(2,104
)
 
(4,973
)
Redemption of preferred stock
 
—

 
(20,599
)
 
—

Capital contributions from parent
 
—

 
20,000

 
47,750

Distributions/dividends paid:
 
 

 
 

 
 

Common equity
 
(23,750
)
 
(74,250
)
 
(18,720
)
Preferred stock
 
—

 
(1,083
)
 
(965
)
Other
 
409

 
12

 
492

Net cash flow provided by (used in) financing activities
 
22,774

 
(88,624
)
 
131,662

Net increase (decrease) in cash and cash equivalents
 
(13,064
)
 
(70,327
)
 
14,192

Cash and cash equivalents at beginning of period
 
32,741

 
103,068

 
88,876

Cash and cash equivalents at end of period
 

$19,677

 

$32,741

 

$103,068

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 

 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$19,840

 

$20,180

 

$19,317

Income taxes
 

($39,781
)
 

($8,660
)
 

($85,962
)
See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2018
 
2017
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents
 
 
 
 
Cash
 

$26

 

$30

Temporary cash investments
 
19,651

 
32,711

Total cash and cash equivalents
 
19,677

 
32,741

Securitization recovery trust account
 
2,224

 
1,455

Accounts receivable:
 
 

 
 

Customer
 
43,890

 
51,006

Allowance for doubtful accounts
 
(3,222
)
 
(3,057
)
Associated companies
 
27,938

 
22,976

Other
 
4,090

 
6,471

Accrued unbilled revenues
 
18,907

 
20,638

Total accounts receivable
 
91,603

 
98,034

Fuel inventory - at average cost
 
1,533

 
1,890

Materials and supplies - at average cost
 
12,133

 
10,381

Prepaid taxes
 
—

 
26,479

Prepayments and other
 
6,905

 
8,030

TOTAL
 
134,075


179,010

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Non-utility property at cost (less accumulated depreciation)
 
1,016

 
1,016

Storm reserve escrow account
 
80,853

 
79,546

Other
 
—

 
2,373

TOTAL
 
81,869

 
82,935

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
1,364,091

 
1,302,235

Natural gas
 
284,728

 
261,263

Construction work in progress
 
146,668

 
46,993

TOTAL UTILITY PLANT
 
1,795,487

 
1,610,491

Less - accumulated depreciation and amortization
 
670,135

 
631,178

UTILITY PLANT - NET
 
1,125,352

 
979,313

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Deferred fuel costs
 
4,080

 
4,080

Other regulatory assets (includes securitization property of $60,453 as of December 31, 2018 and $72,095 as of December 31, 2017)
 
229,796

 
251,433

Other
 
1,416

 
1,065

TOTAL
 
235,292

 
256,578

 
 
 
 
 
TOTAL ASSETS
 

$1,576,588

 

$1,497,836

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
December 31,
 
 
2018
 
2017
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Payable due to associated company
 

$1,979

 

$2,077

Accounts payable:
 
 

 
 

Associated companies
 
43,416

 
47,472

Other
 
36,686

 
29,777

Customer deposits
 
28,667

 
28,442

Taxes accrued
 
4,068

 
—

Interest accrued
 
6,366

 
5,487

Deferred fuel costs
 
1,288

 
7,774

Current portion of unprotected excess accumulated deferred income taxes
 
25,301

 
—

Other
 
9,521

 
7,351

TOTAL CURRENT LIABILITIES
 
157,292

 
128,380

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
323,595

 
283,302

Accumulated deferred investment tax credits
 
2,219

 
2,323

Regulatory liability for income taxes - net
 
60,249

 
119,259

Asset retirement cost liabilities
 
3,291

 
3,076

Accumulated provisions
 
86,594

 
85,083

Pension and other postretirement liabilities
 
5,626

 
20,755

Long-term debt (includes securitization bonds of $63,620 as of December 31, 2018 and $74,419 as of December 31, 2017)
 
467,358

 
418,447

Long-term payable due to associated company
 
14,367

 
16,346

Other
 
11,047

 
5,317

TOTAL NON-CURRENT LIABILITIES
 
974,346

 
953,908

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
EQUITY
 
 

 
 

Member's equity
 
444,950

 
415,548

TOTAL
 
444,950

 
415,548

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$1,576,588

 

$1,497,836

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 



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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY
For the Years Ended December 31, 2018, 2017, and 2016
 
 
 
 
 
Member’s Equity
 
(In Thousands)
 
 
Balance at December 31, 2015

$350,032

Net income
48,849

Capital contributions from parent
47,750

Common equity distributions
(18,720
)
Preferred stock dividends
(965
)
Balance at December 31, 2016

$426,946

Net income
44,553

Capital contributions from parent
20,000

Common equity distributions
(74,250
)
Preferred stock dividends
(841
)
Other
(860
)
Balance at December 31, 2017

$415,548

Net income
53,152

Common equity distributions
(23,750
)
Balance at December 31, 2018

$444,950

 
 
See Notes to Financial Statements.
 



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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
2018
 
2017
 
2016
 
2015
 
2014
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$717,390

 

$716,070

 

$665,463

 

$671,446

 

$735,192

Net income

$53,152

 

$44,553

 

$48,849

 

$44,925

 

$31,030

Total assets

$1,576,588

 

$1,497,836

 

$1,494,569

 

$1,215,144

 

$1,014,916

Long-term obligations (a)

$481,725

 

$434,793

 

$466,670

 

$357,687

 

$323,280

 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (including the long-term payable to associated company and excluding currently maturing debt) and preferred stock without sinking fund.
 
 
 
 
 
 
 
 
 
 
 
2018
 
2017
 
2016
 
2015
 
2014
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
Electric Operating Revenues:
 

 
 

 
 

 
 

 
 

Residential

$262

 

$250

 

$231

 

$220

 

$230

Commercial
217

 
228

 
206

 
186

 
196

Industrial
33

 
36

 
33

 
30

 
33

Governmental
72

 
77

 
69

 
64

 
67

Total retail
584

 
591

 
539

 
500

 
526

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
—

 
—

 
30

 
66

 
78

Non-associated companies
30

 
29

 
3

 
—

 
4

Other
11

 
12

 
15

 
18

 
17

Total

$625

 

$632

 

$587

 

$584

 

$625

 
 
 
 
 
 
 
 
 
 
Billed Electric Energy Sales (GWh):
 
 
 

 
 

 
 

 
 

Residential
2,401

 
2,155

 
2,231

 
2,301

 
2,262

Commercial
2,270

 
2,248

 
2,268

 
2,257

 
2,181

Industrial
448

 
429

 
441

 
463

 
455

Governmental
795

 
790

 
794

 
825

 
783

Total retail
5,914

 
5,622

 
5,734

 
5,846

 
5,681

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
—

 
—

 
1,071

 
1,644

 
1,379

Non-associated companies
1,484

 
1,703

 
141

 
11

 
18

Total
7,398

 
7,325

 
6,946

 
7,501

 
7,078

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



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Table of Contents


ENTERGY TEXAS, INC. AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

2018 Compared to 2017

Net income increased $86.1 million primarily due to a lower effective income tax rate and higher net revenue, partially offset by higher depreciation and amortization expenses and higher other operation and maintenance expenses.

2017 Compared to 2016

Net income decreased $31.4 million primarily due to lower net revenue, higher depreciation and amortization expenses, higher other operation and maintenance expenses, and higher taxes other than income taxes.

Net Revenue

2018 Compared to 2017

Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 2018 to 2017.
 
Amount
 
(In Millions)
 
 

2017 net revenue

$626.8

Volume/weather
26.4

Purchased power capacity
17.9

Retail electric price
(0.1
)
Return of unprotected excess accumulated deferred income taxes to customers

(14.6
)
Other
(1.0
)
2018 net revenue

$655.4


The volume/weather variance is primarily due to an increase of 1,162 GWh, or 6%, in billed electricity usage, including the effect of more favorable weather on residential sales and an increase in industrial usage. The increase in industrial usage is primarily due to new customers in the chemicals and wood products industries and an increase in demand from cogeneration customers and mid-size to small customers.

The purchased power capacity variance is primarily due to decreased purchased power capacity costs under Entergy Texas’s purchased power agreements with Entergy Louisiana.

The retail electric price variance is primarily due to a regulatory charge of $25.4 million recorded in the fourth quarter 2018 to reflect the effects of a provision in the settlement reached in the 2018 rate case proceeding, as approved by the PUCT, to return the benefits of the lower federal income tax rate in 2018 to customers. Partially offsetting the decrease was an annual base rate increase of $53.2 million effective October 2018 and an increase in the distribution cost recovery factor rider rate in September 2017, each as approved by the PUCT. See Note 2 to the financial statements for further discussion of the rate case and the distribution cost recovery factor rider filings.

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Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis


The return of unprotected excess accumulated deferred income taxes to customers resulted from the return in the fourth quarter 2018 of unprotected excess accumulated deferred income taxes through a rider effective October 2018. There is no effect on net income as the reduction in net revenue 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.

2017 Compared to 2016

Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 2017 to 2016.
 
Amount
 
(In Millions)
 
 

2016 net revenue

$644.2

Net wholesale revenue
(35.1
)
Purchased power capacity
(5.9
)
Transmission revenue
(5.4
)
Reserve equalization
5.6

Retail electric price
19.0

Other
4.4

2017 net revenue

$626.8


The net wholesale revenue variance is primarily due to lower net capacity revenues resulting from the termination of the purchased power agreements between Entergy Louisiana and Entergy Texas in August 2016.

The purchased power capacity variance is primarily due to increased expenses due to capacity cost changes for ongoing purchased power capacity contracts.

The transmission revenue variance is primarily due to a decrease in the amount of transmission revenues allocated by MISO.

The reserve equalization variance is due to the absence of reserve equalization expenses in 2017 as a result of Entergy Texas’s exit from the System Agreement in August 2016. See Note 2 to the financial statements for a discussion of the System Agreement.

The retail electric price variance is primarily due to the implementation of the transmission cost recovery factor rider in September 2016 and an increase in the transmission cost recovery factor rider rate in March 2017, each as approved by the PUCT. See Note 2 to the financial statements for further discussion of the transmission cost recovery factor rider filing.

Other Income Statement Variances

2018 Compared to 2017

Other operation and maintenance expenses increased primarily due to:
 
•
the write-off of $6 million in capitalized skylining tree hazard costs as a result of the settlement of the rate case proceeding. See Note 2 to the financial statements for further discussion of the rate case proceeding;

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Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis


•
an increase of $3.5 million in energy efficiency costs primarily due to the timing of recovery from customers; and
•
an increase of $1.4 million in transmission expenses primarily due to higher labor and contract costs to support industrial customers.

The increase was partially offset by a decrease of $2.8 million in compensation and benefits costs primarily due to lower incentive-based compensation accruals in 2018 as compared to 2017 and a gain of $2.1 million on the sale of assets in 2018.

Depreciation and amortization expenses increased primarily due to additions to plant in service.

2017 Compared to 2016

Other operation and maintenance expenses increased primarily due to:

•
an increase of $5.1 million in transmission and distribution expenses primarily due to higher vegetation maintenance costs;
•
an increase of $4.3 million in fossil-fueled generation expenses primarily due to a higher scope of work performed during plant outages in 2017 as compared to 2016; and
•
an increase of $2.8 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2017 as compared to 2016.

The increase was partially offset by a decrease of $4.5 million due to the absence of transmission equalization expenses, as allocated under the System Agreement, as a result of Entergy Texas’s exit from the System Agreement in August 2016.

Taxes other than income taxes increased primarily due to an increase in ad valorem taxes resulting from higher assessments and a true-up to the sales and use tax accruals recorded in 2016 resulting from an audit settlement.

Depreciation and amortization expenses increased primarily due to additions to plant in service.

Income Taxes

The effective income tax rates for 2018, 2017, and 2016 were (19.3%), 38.9%, and 37.0%, respectively. The difference in the effective income tax rate of (19.3%) versus the federal statutory rate of 21% for 2018 was primarily due to the flow through and amortization of excess accumulated deferred income taxes, along with the effect on income tax expense of the resolution of Entergy Texas’s 2018 base rate proceeding. See Note 3 to the financial statements for a reconciliation of the federal statutory rates of 21% for 2018 and 35% for 2017 and 2016 to the effective income tax rates.

Income Tax Legislation

See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 and 2018 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses the regulatory proceedings that have considered the effects of the Act.


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Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2018, 2017, and 2016 were as follows:
 
2018
 
2017
 
2016
 
(In Thousands)
Cash and cash equivalents at beginning of period

$115,513

 

$6,181

 

$2,182

 
 
 
 
 
 
Net cash provided by (used in):
 

 
 

 
 

Operating activities
331,753

 
301,396

 
306,601

Investing activities
(395,973
)
 
(383,176
)
 
(330,191
)
Financing activities
(51,237
)
 
191,112

 
27,589

Net increase (decrease) in cash and cash equivalents
(115,457
)
 
109,332

 
3,999

 
 
 
 
 
 
Cash and cash equivalents at end of period

$56

 

$115,513

 

$6,181


Operating Activities

Net cash flow provided by operating activities increased $30.4 million in 2018 primarily due to:

•
the receipt of $33.2 million from Entergy Arkansas as a result of a compliance filing made in response to the FERC’s October 2018 order in the Entergy Arkansas opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the Entergy Arkansas opportunity sales proceeding;
•
the effect of favorable weather on billed sales;
•
a decrease of $18.4 million in storm spending in 2018 as compared to 2017 primarily as a result of Hurricane Harvey in 2017; and
•
a decrease of $6.1 million in pension contributions in 2018 as compared to 2017. See “Critical Accounting Estimates” below and in Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

The increase was partially offset by:

•
income tax payments of $20.8 million in 2018 compared to income tax refunds of $21.1 million in 2017. The income tax payments in 2018 and the income tax refunds in 2017 were in accordance with an intercompany income tax allocation agreement.  The income tax payments in 2018 primarily resulted from the settlement of the 2012-2013 IRS audit. The income tax refunds in 2017 primarily resulted from deductible temporary differences;
•
the timing of recovery of fuel and purchased power costs; and
•
the return of unprotected excess accumulated deferred income taxes to customers. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.

Net cash flow provided by operating activities decreased $5.2 million in 2017 primarily due to lower net income, the timing of recovery of fuel and purchased power costs, and an increase of $13.7 million in storm spending primarily as a result of Hurricane Harvey. The decrease was partially offset by income tax refunds of $21.1 million in 2017 compared to income tax payments of $28.5 million in 2016. Entergy Texas had income tax refunds in 2017 and income tax payments in 2016 in accordance with an intercompany income tax allocation agreement.  The income tax refunds in 2017 primarily resulted from deductible temporary differences. The income tax payments in 2016 resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit. See Note 3 to the financial statements for a discussion of the income tax audit.

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Investing Activities

Net cash flow used in investing activities increased $12.8 million in 2018 primarily due to an increase of $110.1 million in fossil-fueled generation construction expenditures primarily due to the increase in spending on the Montgomery County Power Station and an increase of $13.7 million in transmission construction expenditures primarily due to a higher scope of work performed in 2018 as compared to 2017. The increase was partially offset by a decrease of $24.6 million in distribution construction expenditures primarily due to the decreased storm spending in 2018 as compared to 2017 primarily as a result of Hurricane Harvey and money pool activity.

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 $44.9 million in 2018 compared to increasing by $44.2 million in 2017. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
 
Net cash flow used in investing activities increased $53 million in 2017 primarily due to:

•
money pool activity;
•
an increase of $34.9 million in distribution construction expenditures primarily due to increased storm spending primarily as a result of Hurricane Harvey and spending on digital technology improvements within the customer contact centers;
•
an increase of $24.4 million in fossil-fueled generation construction expenditures primarily due to a higher scope of work performed in 2017 as compared to 2016; and
•
an increase of $8.5 million in spending on advanced metering infrastructure.

The increase was partially offset by a decrease of $51.7 million in transmission construction expenditures primarily due to a lower scope of work performed in 2017 as compared to 2016.

Increases in Entergy Texas’s receivable from the money pool are a use of cash flow, and Entergy Texas’s receivable from the money pool increased by $44.2 million in 2017 compared to increasing by $0.7 million in 2016.
  
Financing Activities

Entergy Texas’s financing activities used $51.2 million of cash in 2018 compared to providing $191.1 million of cash in 2017 primarily due to the issuance of $150 million of 3.45% Series first mortgage bonds in November 2017 and a $115 million capital contribution received from Entergy Corporation in December 2017 in anticipation of upcoming construction expenditures, partially offset by money pool activity.

Increases in Entergy Texas’s payable to the money pool are a source of cash flow, and Entergy Texas’s payable to the money pool increased by $22.4 million in 2018.
    
Net cash flow provided by financing activities increased $163.5 million in 2017 primarily due to:

•
a $115 million capital contribution received from Entergy Corporation in December 2017 in anticipation of upcoming construction expenditures;
•
the issuance of $150 million of 3.45% Series first mortgage bonds in November 2017 compared to the issuance of $125 million of 2.55% Series first mortgage bonds in March 2016; and
•
money pool activity.

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 by $22.1 million in 2016.


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Capital Structure

Entergy Texas’s debt to capital ratio is balanced between equity and debt, as shown in the following table. The decrease in the debt to capital ratio for Entergy Texas is primarily due to the increase in retained earnings.
 
 
December 31,
2018
 
December 31,
2017
Debt to capital
51.6
%
 
55.7
%
Effect of excluding the securitization bonds
(5.2
%)
 
(6.3
%)
Debt to capital, excluding securitization bonds (a)
46.4
%
 
49.4
%
Effect of subtracting cash
—
%
 
(2.5
%)
Net debt to net capital, excluding securitization bonds (a)
46.4
%
 
46.9
%
(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 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 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 targeted 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 targeted capital structure. In addition, Entergy Texas may receive equity contributions to maintain the targeted capital structure for certain circumstances such as 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.
 
2019
 
2020
 
2021
 
(In Millions)
Planned construction and capital investment:
 
 
 
 
 
Generation

$435

 

$260

 

$115

Transmission
295

 
195

 
100

Distribution
155

 
170

 
255

Utility Support
60

 
35

 
25

Total

$945

 

$660

 

$495


Following are the amounts of Entergy Texas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2019
 
2020-2021
 
2022-2023
 
After 2023
 
Total
 
(In Millions)
Long-term debt (a)

$626

 

$426

 

$107

 

$1,143

 

$2,302

Operating leases (b)

$5

 

$8

 

$4

 

$3

 

$20

Purchase obligations (c)

$277

 

$491

 

$498

 

$1,282

 

$2,548


(a)
Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.
(b)
Does not include power purchase agreements that are accounted for as leases that are included in purchase obligations.
(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 $1.6 million to its qualified pension plans and approximately $56 thousand to other postretirement health care and life insurance plans in 2019, although the 2019 required pension contributions will be known with more certainty when the January 1, 2019 valuations are completed, which is expected by April 1, 2019. 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 $14.6 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 Texas includes specific investments such as the Montgomery County Power Station; 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; 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. Management provides more information on long-term debt in Note 5 to the financial statements.

As a wholly-owned subsidiary, Entergy Texas dividends its earnings to Entergy Corporation at a percentage determined monthly.  


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Montgomery County Power Station

In October 2016, Entergy Texas filed an application with the PUCT seeking certification that the public convenience and necessity would be served by the construction of the Montgomery County Power Station, a nominal 993 MW combined-cycle generating unit in Montgomery County, Texas on land adjacent to the existing Lewis Creek plant. The current estimated cost of the Montgomery County Power Station is $937 million, including approximately $111 million of transmission interconnection and network upgrades and other related costs. The independent monitor, who oversaw the request for proposal process, filed testimony and a report affirming that the Montgomery County Power Station was selected through an objective and fair request for proposal process that showed no undue preference to any proposal. In June 2017 parties to the proceeding filed an unopposed stipulation and settlement agreement. The stipulation contemplates that Entergy Texas’s level of cost-recovery for generation construction costs for Montgomery County Power Station is capped at $831 million, subject to certain exclusions such as force majeure events. Transmission interconnection and network upgrades and other related costs are not subject to the $831 million cap. In July 2017 the PUCT approved the stipulation. Subject to the timely receipt of other permits and approvals, commercial operation is estimated to occur by mid-2021.

Advanced Metering Infrastructure (AMI)

In April 2017 the Texas legislature enacted legislation that extends statutory support for AMI deployment to Entergy Texas and directs that if Entergy Texas elects to deploy AMI, it shall do so as rapidly as practicable. In July 2017, Entergy Texas filed an application seeking an order from the PUCT approving Entergy Texas’s deployment of AMI. Entergy Texas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Texas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, with Entergy Texas showing that its AMI deployment is expected to produce nominal net operational cost savings to customers of $33 million. Entergy Texas also sought to continue to include in rate base the remaining book value, approximately $41 million at December 31, 2016, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Texas proposed a seven-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Entergy Texas also proposed a surcharge tariff to recover the reasonable and necessary costs it has and will incur under the deployment plan for the full deployment of advanced meters. Further, Entergy Texas sought approval of fees that would be charged to customers who choose to opt out of receiving service through an advanced meter and instead receive electric service with a non-standard meter. In October 2017, Entergy Texas and other parties entered into and filed an unopposed stipulation and settlement agreement, permitting deployment of AMI with limited modifications. The PUCT approved the stipulation and settlement agreement in December 2017. Entergy Texas implemented the AMI surcharge tariff beginning with January 2018 bills. As of December 31, 2018, Entergy Texas has a regulatory liability related to the collection of the surcharge from customers. Consistent with the approval, deployment of the communications network began in 2018 and deployment of the advanced meters will begin in March 2019. Entergy Texas expects to recover the remaining net book value of its existing meters through a regulatory asset to be amortized at current depreciation rates.

Sources of Capital

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

•
internally generated funds;
•
cash on hand;
•
debt or preferred stock issuances;
•
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

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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.
2018
 
2017
 
2016
 
2015
(In Thousands)
($22,389)
 
$44,903
 
$681
 
($22,068)

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 2023. 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, 2018, 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, 2018, a $20.9 million letter of credit was 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 November 2020 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.

In January 2019, Entergy Texas issued $300 million of 4.0% Series first mortgage bonds and $400 million of 4.5% Series first mortgage bonds due March 2029 and 2039, respectively. Entergy Texas used the proceeds to pay, at maturity, its $500 million of 7.125% Series first mortgage bonds due February 2019 and for general corporate purposes.

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), 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

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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.

Distribution Cost Recovery Factor (DCRF) Rider

In June 2017, Entergy Texas filed an application to amend its DCRF rider by increasing the total collection from $8.65 million to approximately $19 million. In July 2017, Entergy Texas, the PUCT staff, and the two other parties in the proceeding entered into an unopposed stipulation and settlement agreement resulting in an amended DCRF annual revenue requirement of $18.3 million. In September 2017 the PUCT issued its final order approving the unopposed stipulation and settlement agreement. The amended DCRF rider rates became effective for usage on and after September 1, 2017. DCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as described above in the 2018 base rate case discussion.
    
Transmission Cost Recovery Factor (TCRF) Rider

In September 2015, Entergy Texas filed for a TCRF rider requesting a $13 million increase, incremental to base rates. Testimony was filed in November 2015, with the PUCT staff and other parties proposing various disallowances involving, among other things, MISO charges, vegetation management costs, and bad debt expenses that would reduce the requested increase by approximately $2 million. In addition to those recommended disallowances, a number of parties recommended that Entergy Texas’s request be reduced by an additional $3.4 million to account for load growth since base rates were last set. In February 2016 a State Office of Administrative Hearings ALJ issued a proposal for decision recommending that the PUCT disallow approximately $2 million from Entergy Texas’s $13 million request, but recommending that the PUCT not accept the load growth offset. In June 2016 the PUCT indicated that it would take up in a future rulemaking project the issue of whether a load growth adjustment should apply to a TCRF. In July 2016 the PUCT issued an order generally accepting the proposal for decision but declining to adjust the TCRF baseline in two instances as recommended by the ALJ, which resulted in a total annual allowance of approximately $10.5 million. The PUCT also ordered its staff and Entergy Texas to track all spare autotransformer transfers going forward so that it could address the appropriate accounting treatment and prudence of such transfers in Entergy Texas’s next base rate case. Entergy Texas implemented the TCRF rider beginning with September 2016 bills.

In September 2016, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed amended TCRF rider was designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount included the approximately $10.5 million annually that Entergy Texas was previously authorized to collect through the TCRF rider, as discussed above. In December 2016, concurrent with the 2016 fuel reconciliation stipulation and settlement agreement discussed below, Entergy Texas and the PUCT staff reached a settlement agreeing to the amended TCRF annual revenue requirement of $29.5 million. As discussed below, the terms of the two settlements are interdependent. The PUCT approved the settlement and issued a final order in March 2017. Entergy Texas implemented the amended TCRF rider beginning with bills covering usage on and after March 20, 2017. TCRF rates were set to zero upon implementation of new base rates on October 17, 2018, as discussed above in the 2018 base rate case discussion.


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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. The proceeding is currently ongoing at the PUCT.

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 and September based on the market price of natural gas and changes in fuel mix.  The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT.

In July 2015 certain parties filed briefs in the open proceeding asserting that Entergy Texas should refund to retail customers an additional $10.9 million in bandwidth remedy payments Entergy Texas received related to calendar year 2006 production costs.  In October 2015 an ALJ issued a proposal for decision recommending that the additional $10.9 million in bandwidth remedy payments be refunded to retail customers. In January 2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a motion for rehearing of the PUCT’s decision, which the PUCT denied. In March 2016, Entergy Texas filed a complaint in Federal District Court for the Western District of Texas and a petition in the Travis County (State) District Court appealing the PUCT’s decision. The pending appeals did not stay the PUCT’s decision. In April 2016, Entergy Texas filed with the PUCT an application to refund to customers approximately $56.2 million. The refund resulted from (i) $41.8 million of fuel cost recovery over-collections through February 2016, (ii) the $10.9 million in bandwidth remedy payments, discussed above, that Entergy Texas received related to calendar year 2006 production costs, and (iii) $3.5 million in bandwidth remedy payments that Entergy Texas received related to 2006-2008 production costs. In June 2016, Entergy Texas filed an unopposed settlement agreement that added additional over-recovered fuel costs for the months of March and April 2016. The settlement resulted in a $68 million refund. The ALJ approved the refund on an interim basis and it was made to most customers over a four-month period beginning with the first billing cycle of July 2016. In July 2016 the PUCT issued an order approving the interim refund. The federal appeal of the PUCT’s January 2016 decision was heard in December 2016, and the Federal District Court granted Entergy Texas’s requested relief. In January 2017 the PUCT and an intervenor filed petitions for appeal to the U.S. Court of Appeals for the Fifth Circuit of the Federal District Court ruling. Oral argument was held before the Fifth Circuit in February 2018. In April 2018 the Fifth Circuit reversed the decision of the Federal District Court, reinstating the original PUCT decision. In October 2018, Entergy Texas filed a notice of nonsuit in its appeal to the Travis County District Court regarding the PUCT’s January 2016 decision.

In July 2016, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period April 1, 2013 through March 31, 2016. Under a recent PUCT rule change, a fuel reconciliation is required to be filed at least once every three years and outside of a base rate case filing. During the reconciliation period, Entergy Texas incurred approximately $1.77 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 over-recovery balance of approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2016. Entergy Texas also noted, however, that the estimated $19.3 million over collection was being refunded to customers as a portion of the interim fuel refund beginning with the first billing cycle of July 2016, discussed above. Entergy Texas also requested a prudence finding for each of the fuel-related contracts and arrangements entered into or modified during the reconciliation period that have not been reviewed by the PUCT in a prior proceeding. In December 2016, Entergy Texas entered into a stipulation and settlement agreement resulting in a $6 million disallowance not associated with any particular issue raised and a refund of the over-recovery balance of $21 million as of November 30, 2016, to most customers beginning April 2017 through June 2017. This settlement was developed concurrently with the stipulation and settlement agreement in the 2016 transmission cost recovery factor rider amendment discussed above, and the terms and conditions in both settlements are interdependent. The fuel reconciliation settlement was approved by the PUCT in March 2017 and the refunds were made.


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In June 2017, Entergy Texas filed an application for a fuel refund of approximately $30.7 million for the months of December 2016 through April 2017. For most customers, the refunds flowed through bills for the months of July 2017 through September 2017. The fuel refund was approved by the PUCT in August 2017.

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.

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 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.


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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 and Trust Fund Investments

See “Impairment of Long-lived Assets and Trust Fund Investments” 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).
Actuarial Assumption
 
Change in Assumption
 
Impact on 2019 Qualified Pension Cost
 
Impact on 2018 Qualified Projected Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$569
 
$8,976
Rate of return on plan assets
 
(0.25%)
 
$807
 
$—
Rate of increase in compensation
 
0.25%
 
$308
 
$1,513

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 2019 Postretirement Benefit Cost
 
Impact on 2018 Accumulated Postretirement Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
($5)
 
$2,485
Health care cost trend
 
0.25%
 
$117
 
$2,074

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


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Costs and Funding

Total qualified pension cost for Entergy Texas in 2018 was $4.2 million. Entergy Texas anticipates 2019 qualified pension cost to be $5.7 million. Entergy Texas contributed $10.9 million to its qualified pension plans in 2018 and estimates 2019 pension contributions will be approximately $1.6 million, although the 2019 required pension contributions will be known with more certainty when the January 1, 2019 valuations are completed, which is expected by April 1, 2019.

Total postretirement health care and life insurance benefit income for Entergy Texas in 2018 was $6.2 million. Entergy Texas expects 2019 postretirement health care and life insurance benefit income to approximate $6.9 million. Entergy Texas contributed $3.8 million to its other postretirement plans in 2018 and estimates 2019 contributions will be approximately $56 thousand.

Federal Healthcare Legislation

See “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.

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
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, 2018 and 2017, the related consolidated statements of income, cash flows, and changes in common equity (pages 419 through 424 and applicable items in pages 53 through 237), for each of the three years in the period ended December 31, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, 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.


/s/ DELOITTE & TOUCHE LLP


New Orleans, Louisiana
February 26, 2019


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,
 
 
2018
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$1,605,902

 

$1,544,893

 

$1,615,619

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
204,830

 
225,517

 
271,968

Purchased power
 
614,012

 
610,279

 
616,597

Other operation and maintenance
 
238,400

 
230,437

 
221,620

Taxes other than income taxes
 
82,033

 
79,254

 
70,973

Depreciation and amortization
 
128,534

 
117,520

 
107,026

Other regulatory charges - net
 
131,667

 
82,328

 
82,879

TOTAL
 
1,399,476

 
1,345,335

 
1,371,063

 
 
 
 
 
 
 
OPERATING INCOME
 
206,426

 
199,558

 
244,556

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
9,723

 
6,722

 
7,617

Interest and investment income
 
2,188

 
981

 
987

Miscellaneous - net
 
(655
)
 
14

 
308

TOTAL
 
11,256

 
7,717

 
8,912

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
87,203

 
86,719

 
87,776

Allowance for borrowed funds used during construction
 
(5,513
)
 
(4,098
)
 
(4,943
)
TOTAL
 
81,690

 
82,621

 
82,833

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
135,992

 
124,654

 
170,635

 
 
 
 
 
 
 
Income taxes
 
(26,243
)
 
48,481

 
63,097

 
 
 
 
 
 
 
NET INCOME
 

$162,235

 

$76,173

 

$107,538

 
 
 
 
 
 
 
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,
 
 
2018
 
2017
 
2016
 
 
(In Thousands)
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$162,235

 

$76,173

 

$107,538

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation and amortization
 
128,534

 
117,520

 
107,026

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
(39,545
)
 
42,119

 
20,794

Changes in assets and liabilities:
 
 

 
 

 
 

Receivables
 
(17,099
)
 
(15,934
)
 
(9,300
)
Fuel inventory
 
64

 
(25,054
)
 
9,765

Accounts payable
 
43,319

 
32,842

 
(22,462
)
Prepaid taxes and taxes accrued
 
7,854

 
30,308

 
10,018

Interest accrued
 
(1,201
)
 
(421
)
 
(3,229
)
Deferred fuel costs
 
(47,604
)
 
12,758

 
29,419

Other working capital accounts
 
1,328

 
(7,852
)
 
(3,354
)
Provisions for estimated losses
 
3,741

 
2,531

 
(1,735
)
Other regulatory assets
 
63,350

 
184,574

 
74,389

Other regulatory liabilities
 
(19,336
)
 
410,968

 
2,106

Deferred tax rate change recognized as regulatory liability/asset
 
—

 
(520,547
)
 
—

Pension and other postretirement liabilities
 
(13,135
)
 
(49,445
)
 
(10,204
)
Other assets and liabilities
 
59,248

 
10,856

 
(4,170
)
Net cash flow provided by operating activities
 
331,753

 
301,396

 
306,601

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(451,988
)
 
(348,027
)
 
(337,963
)
Allowance for equity funds used during construction
 
9,861

 
6,874

 
7,743

Proceeds from sale of assets
 
3,753

 
—

 
—

Insurance proceeds
 
—

 
2,431

 
—

Changes in money pool receivable - net
 
44,903

 
(44,222
)
 
(681
)
Changes in securitization account
 
(2,502
)
 
(232
)
 
710

Net cash flow used in investing activities
 
(395,973
)
 
(383,176
)
 
(330,191
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
—

 
148,277

 
123,502

Retirement of long-term debt
 
(74,950
)

(71,683
)

(68,593
)
Capital contributions from parent
 
—

 
115,000

 
—

Change in money pool payable - net
 
22,389

 
—

 
(22,068
)
Other
 
1,324

 
(482
)
 
(5,252
)
Net cash flow provided by (used in) financing activities
 
(51,237
)
 
191,112

 
27,589

Net increase (decrease) in cash and cash equivalents
 
(115,457
)
 
109,332

 
3,999

Cash and cash equivalents at beginning of period
 
115,513

 
6,181

 
2,182

Cash and cash equivalents at end of period
 

$56

 

$115,513

 

$6,181

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 

 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 
$85,719

 

$84,556

 

$88,489

Income taxes
 

$20,787

 

($21,107
)
 

$28,523

See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2018
 
2017
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$26

 

$32

Temporary cash investments
 
30

 
115,481

Total cash and cash equivalents
 
56

 
115,513

Securitization recovery trust account
 
40,185

 
37,683

Accounts receivable:
 
 

 
 

Customer
 
69,714

 
74,382

Allowance for doubtful accounts
 
(461
)
 
(463
)
Associated companies
 
64,441

 
90,629

Other
 
12,275

 
9,831

Accrued unbilled revenues
 
51,288

 
50,682

Total accounts receivable
 
197,257

 
225,061

Fuel inventory - at average cost
 
42,667

 
42,731

Materials and supplies - at average cost
 
41,883

 
38,605

Prepayments and other
 
15,903

 
19,710

TOTAL
 
337,951

 
479,303

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Investments in affiliates - at equity
 
448

 
457

Non-utility property - at cost (less accumulated depreciation)
 
376

 
376

Other
 
19,218

 
19,235

TOTAL
 
20,042

 
20,068

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
4,773,984

 
4,569,295

Construction work in progress
 
325,193

 
102,088

TOTAL UTILITY PLANT
 
5,099,177

 
4,671,383

Less - accumulated depreciation and amortization
 
1,684,569

 
1,579,387

UTILITY PLANT - NET
 
3,414,608

 
3,091,996

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

  Other regulatory assets (includes securitization property of $236,336 as of December 31, 2018 and $313,123 as of December 31, 2017)
 
598,048

 
661,398

Other
 
29,371

 
26,973

TOTAL
 
627,419

 
688,371

 
 
 
 
 
TOTAL ASSETS
 

$4,400,020

 

$4,279,738

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2018
 
2017
 
 
(In Thousands)
CURRENT LIABILITIES
 
 
 
 
Currently maturing long-term debt
 

$500,000

 

$—

Accounts payable:
 
 
 
 
Associated companies
 
119,371

 
59,347

Other
 
150,679

 
126,095

Customer deposits
 
43,387

 
40,925

Taxes accrued
 
53,513

 
45,659

Interest accrued
 
24,355

 
25,556

Current portion of unprotected excess accumulated deferred income taxes
 
87,627

 
—

Deferred fuel costs
 
19,697

 
67,301

Other
 
6,353

 
8,132

TOTAL
 
1,004,982

 
373,015

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
552,535

 
544,642

Accumulated deferred investment tax credits
 
11,176

 
11,983

Regulatory liability for income taxes - net
 
264,623

 
412,620

Other regulatory liabilities
 
47,884

 
6,850

Asset retirement cost liabilities
 
7,222

 
6,835

Accumulated provisions
 
13,856

 
10,115

Pension and other postretirement liabilities
 
4,834

 
17,853

Long-term debt (includes securitization bonds of $283,659 as of December 31, 2018 and $358,104 as of December 31, 2017)
 
1,013,735

 
1,587,150

Other
 
56,771

 
48,508

TOTAL
 
1,972,636

 
2,646,556

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
COMMON EQUITY
 
 

 
 

Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2018 and 2017
 
49,452

 
49,452

Paid-in capital
 
596,994

 
596,994

Retained earnings
 
775,956

 
613,721

TOTAL
 
1,422,402

 
1,260,167

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$4,400,020

 

$4,279,738

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 



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Table of Contents

ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY
For the Years Ended December 31, 2018, 2017, and 2016
 
 
 
 
 
Common Equity
 
 
 
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Total
 
(In Thousands)
 
 
 
 
 
 
 
 
Balance at December 31, 2015

$49,452

 

$481,994

 

$430,010

 

$961,456

Net income
—

 
—

 
107,538

 
107,538

Balance at December 31, 2016

$49,452

 

$481,994

 

$537,548

 

$1,068,994

Net income
—

 
—

 
76,173

 
76,173

Capital contributions from parent
—

 
115,000

 
—

 
115,000

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

 
 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY TEXAS, INC. AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
2018
 
2017
 
2016
 
2015
 
2014
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$1,605,902

 

$1,544,893

 

$1,615,619

 

$1,707,203

 

$1,851,982

Net income

$162,235

 

$76,173

 

$107,538

 

$69,625

 

$74,804

Total assets

$4,400,020

 

$4,279,738

 

$4,033,081

 

$3,898,582

 

$3,897,989

Long-term obligations (a)

$1,013,735

 

$1,587,150

 

$1,508,407

 

$1,451,967

 

$1,268,835

 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (excluding currently maturing debt).
 
 
 
 
 
 
 
 
 
 
 
2018
 
2017
 
2016
 
2015
 
2014
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
Electric Operating Revenues:
 

 
 

 
 

 
 

 
 

Residential

$674

 

$636

 

$613

 

$633

 

$654

Commercial
381

 
378

 
356

 
369

 
384

Industrial
394

 
384

 
365

 
372

 
422

Governmental
25

 
25

 
24

 
25

 
26

Total retail
1,474

 
1,423

 
1,358

 
1,399

 
1,486

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
59

 
58

 
178

 
259

 
316

Non-associated companies
39

 
22

 
40

 
14

 
23

Other
34

 
42

 
40

 
35

 
27

Total

$1,606

 

$1,545

 

$1,616

 

$1,707

 

$1,852

 
 
 
 
 
 
 
 
 
 
Billed Electric Energy Sales (GWh):
 
 
 

 
 

 
 

 
 

Residential
6,135

 
5,716

 
5,836

 
5,889

 
5,810

Commercial
4,747

 
4,548

 
4,570

 
4,548

 
4,471

Industrial
8,052

 
7,521

 
7,493

 
7,036

 
7,140

Governmental
286

 
273

 
283

 
276

 
277

Total retail
19,220

 
18,058

 
18,182

 
17,749

 
17,698

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
1,516

 
1,534

 
4,625

 
5,853

 
4,763

Non-associated companies
962

 
729

 
1,086

 
254

 
200

Total
21,698

 
20,321

 
23,893

 
23,856

 
22,661



425
Table of Contents


SYSTEM ENERGY RESOURCES, INC.

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

System Energy’s principal asset currently 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.

Results of Operations

Net Income

2018 Compared to 2017

Net income increased $15.5 million primarily due to the increase in operating revenues resulting from changes in rate base, as compared to prior year, and a lower effective income tax rate.

2017 Compared to 2016

Net income decreased $18.1 million primarily due to provisions against revenue recorded in 2017 in connection with the complaint against System Energy’s return on equity and a higher effective income tax rate in 2017. See “Federal Regulation - Complaints Against System Energy” below for further discussion of the complaint against System Energy.

Income Taxes

The effective income tax rates for 2018, 2017, and 2016 were (102.7%), 47.1%, and 42.3%, respectively. The difference in the effective income tax rate of (102.7%) versus the federal statutory rate of 21% for 2018 was primarily due to the amortization of excess accumulated deferred income taxes. The difference in the effective income tax rate of 47.1% versus the federal statutory rate of 35% for 2017 was primarily due to certain book and tax differences related to utility plant items and state income taxes. See Note 3 to the financial statements for a reconciliation of the federal statutory rates of 21% for 2018 and 35% for 2017 and 2016 to the effective income tax rates.

Income Tax Legislation

See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 and 2018 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses the regulatory proceedings that have considered the effects of the Act.


426
Table of Contents
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis


Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2018, 2017, and 2016 were as follows:
 
2018
 
2017
 
2016
 
(In Thousands)
Cash and cash equivalents at beginning of period

$287,187

 

$245,863

 

$230,661

 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 

Operating activities
101,328

 
371,278

 
341,939

Investing activities
(286,161
)
 
(174,250
)
 
(232,602
)
Financing activities
(6,669
)
 
(155,704
)
 
(94,135
)
Net increase (decrease) in cash and cash equivalents
(191,502
)
 
41,324

 
15,202

 
 
 
 
 
 
Cash and cash equivalents at end of period

$95,685

 

$287,187

 

$245,863


Operating Activities

Net cash flow provided by operating activities decreased $270 million in 2018 primarily due to:

•
the return of unprotected excess accumulated deferred income taxes;
•
income tax payments of $54 million in 2018 compared to income tax refunds of $2.2 million in 2017. System Energy made income tax payments in 2018 and received income tax refunds in 2017 in accordance with an intercompany income tax allocation agreement. The income tax payments in 2018 were from the results of operations and the inclusion of taxable temporary differences in the computation of taxable income; and
•
an increase in spending of $51.5 million on nuclear refueling outages in 2018 as compared to the prior year.

Net cash flow provided by operating activities increased $29.3 million in 2017 primarily due to:

•
a decrease in spending of $35.7 million on nuclear refueling outages in 2017 as compared to the prior year;
•
the timing of collection of receivables; and
•
a decrease of $9.9 million in interest paid in 2017.

The increase was partially offset by:

•
proceeds of $28.4 million received in August 2016 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; and
•
a decrease of $21.3 million in income tax refunds in 2017. System Energy received income tax refunds in 2017 and 2016 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2017 and 2016 resulted primarily from the adoption of a new accounting method for income tax purposes in which System Energy will treat its nuclear decommissioning costs as production costs of electricity includable in cost of goods sold. See Note 3 to the financial statements for further discussion of the adoption of the new accounting method.


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Table of Contents
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis

Investing Activities

Net cash flow used in investing activities increased $111.9 million in 2018 primarily due to:

•
an increase of $114.4 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and
•
an increase of $110.4 million in nuclear construction expenditures primarily as a result of a higher scope of work performed during the Grand Gulf outage in 2018.

The increase was partially offset by money pool activity and changes in the decommissioning trust fund investments including portfolio rebalancing of the Grand Gulf decommissioning trust fund in 2018.

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 $4.5 million in 2018 compared to increasing by $77.9 million in 2017.  The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.

Net cash flow used in investing activities decreased $58.4 million in 2017 primarily due to a decrease of $159.4 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle. The decrease was partially offset by money pool activity and proceeds of $15.8 million received in August 2016 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.

Increases in System Energy’s receivable from the money pool are a use of cash flow and System Energy’s receivable from the money pool increased by $77.9 million in 2017 compared to decreasing by $6.1 million in 2016.  

Financing Activities

Net cash flow used in financing activities decreased $149 million in 2018 primarily due to:

•
the issuance in March 2018 of $100 million of 3.42% Series J notes by the System Energy nuclear fuel company variable interest entity;
•
an increase of net long-term borrowings of $63.9 million in 2018 on the nuclear fuel company variable interest entity’s credit facility;
•
the payment in February 2017, at maturity, of $50 million of the System Energy nuclear fuel company variable interest entity’s 4.02% Series H notes;
•
a decrease of $38.9 million in common stock dividends and distributions in 2018 in order to maintain the targeted capital structure; and
•
net repayments of short-term borrowings of $17.8 million on the nuclear fuel company variable interest entity’s credit facility in 2018 compared to net repayments of short-term borrowings of $49.1 million on the nuclear fuel variable interest entity’s credit facility in 2017.

The decrease was offset by:

•
the payment in October 2018, at maturity, of $85 million of the System Energy nuclear fuel company variable interest entity’s 3.78% Series I notes; and
•
net long-term borrowings of $50 million in 2017 on the nuclear fuel company variable interest entity’s credit facility.


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Table of Contents
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis



Net cash flow used in financing activities increased $61.6 million in 2017 primarily due to:

•
net repayments of short-term borrowings of $49.1 million on the nuclear fuel company variable interest entity’s credit facility in 2017 as compared to net short-term borrowings of $66.9 million on the nuclear fuel variable interest entity’s credit facility in 2016; and
•
the payment in February 2017, at maturity, of $50 million of the System Energy nuclear fuel company variable interest entity’s 4.02% Series H notes.

The increase was partially offset by:

•
net long-term borrowings of $50 million in 2017 on the nuclear fuel company variable interest entity’s credit facility;
•
a decrease of $32.4 million in common stock dividends and distributions in 2017 in order to maintain System Energy’s targeted capital structure; and
•
the repayment in May 2016 of $22 million of 5.875% pollution control revenue bonds due 2022 issued on behalf of System Energy.

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

Capital Structure

System Energy’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio for System Energy is primarily due to the issuance in March 2018 of $100 million of 3.42% Series J notes by the System Energy nuclear fuel company variable interest entity.
 
December 31,
2018
 
December 31,
2017
Debt to capital
46.1
%
 
44.5
%
Effect of subtracting cash
(4.0
%)
 
(16.0
%)
Net debt to net capital
42.1
%
 
28.5
%

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.

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 both, in appropriate amounts to maintain the targeted capital structure.  To the extent that operating cash flows are insufficient to support planned investments, System Energy may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure.


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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
•
dividend, distribution, and interest payments.

Following are the amounts of System Energy’s planned construction and other capital investments.
 
2019
 
2020
 
2021
 
(In Millions)
Planned construction and capital investment:
 
 
 
 
 
Generation

$145

 

$170

 

$65

Utility Support
10

 
10

 
10

Total

$155

 

$180

 

$75


Following are the amounts of System Energy’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2019
 
2020-2021
 
2022-2023
 
After 2023
 
Total
 
(In Millions)
Long-term debt (a)

$43

 

$295

 

$433

 

$223

 

$994

Purchase obligations (b)

$11

 

$39

 

$34

 

$—

 

$84


(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 $8.3 million to its qualified pension plans and approximately $20 thousand to other postretirement health care and life insurance plans in 2019, although the 2019 required pension contributions will be known with more certainty when the January 1, 2019 valuations are completed, which is expected by April 1, 2019. 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 $425.3 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 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.  


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Sources of Capital

System Energy’s sources to meet its capital requirements include:

•
internally generated funds;
•
cash on hand;
•
debt issuances; 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.
2018
 
2017
 
2016
 
2015
(In Thousands)
$107,122
 
$111,667
 
$33,809
 
$39,926

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 2021. As of December 31, 2018, $113.9 million in letters of credit to support a like amount of commercial paper issued 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 November 2020 for the following:

•
short-term borrowings not to exceed an aggregate amount of $200 million at any time outstanding;
•
long-term borrowings and security issuances; and
•
borrowings by its nuclear fuel company variable interest entity.

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

Federal Regulation

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

Complaints Against System Energy

Return on Equity 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

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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 current capital market and other considerations indicate that it is excessive. The complaint requests the FERC to institute 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. System Energy is recording a provision against revenue for the potential outcome of this proceeding. In September 2017 the FERC established a refund effective date of January 23, 2017, consolidated the return on equity complaint with the proceeding described in Unit Power Sales Agreement below, 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 effective date 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 July 2018 the LPSC answered System Energy’s motion to dismiss.

In August 2018 the FERC issued an order dismissing the LPSC’s request to investigate System Energy’s capital structure and setting for hearing System Energy’s return on equity, with a refund effective date of April 2018. The portion of the LPSC’s complaint dealing with return on equity was subsequently consolidated with the APSC and MPSC complaint for hearing. The consolidated hearing has been scheduled for September 2019, and the parties are required to address an order (issued in a separate proceeding for 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 complaint, and System Energy submitted a response to the amended complaint in October 2018. In January 2019 the FERC set the amended complaint for settlement and hearing proceedings.

Grand Gulf Sale-leaseback Renewal Complaint

In May 2018 the LPSC filed a complaint against System Energy and Entergy Services related to System Energy’s renewal in 2015 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

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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 2018. The hearing has been scheduled for November 2019.

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 proposed amendments would result in lower charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. The proposed changes are 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. System Energy requested that the FERC accept the amendments effective October 1, 2017.

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. The FERC also consolidated the Unit Power Sales Agreement amendment proceeding with the proceeding described in “Return on Equity Complaints” above, and directed the parties to engage in settlement proceedings before an ALJ. 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 Entergy’s nuclear fleet to meet its operational goals, including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems and the Fukushima event; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license renewal and amendments, and

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decommissioning; the performance and capacity factors of these nuclear plants; 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 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.
 
Based on the plant’s performance indicators, in November 2016 the NRC placed Grand Gulf in the “regulatory response column,” or Column 2, of its Reactor Oversight Process Action Matrix. In August 2018 the NRC moved Grand Gulf into the “licensee response column,” or Column 1, of the NRC’s Reactor Oversight Process Action Matrix. This action followed NRC inspections to review Grand Gulf’s performance in addressing issues that had previously resulted in classification in Column 2. Based on performance indicator data for the third quarter 2018, Grand Gulf moved back to Column 2 due to a reduction in power to address an operational issue with a plant system that resulted in the threshold for one of the NRC’s performance indicators being exceeded.

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 and Trust Fund Investments

See “Impairment of Long-lived Assets and Trust Fund Investments” 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 and trust fund investments.

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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.

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 2019 Qualified Pension Cost
 
Impact on 2018 Projected Qualified Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$705
 
$9,814
Rate of return on plan assets
 
(0.25%)
 
$646
 
$—
Rate of increase in compensation
 
0.25%
 
$331
 
$1,472

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 2019 Postretirement Benefit Cost
 
Impact on 2018 Accumulated Postretirement Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$125
 
$1,543
Health care cost trend
 
0.25%
 
$195
 
$1,318

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

Costs and Funding

Total qualified pension cost for System Energy in 2018 was $14.9 million.  System Energy anticipates 2019 qualified pension cost to be $12.3 million.  System Energy contributed $13.8 million to its pension plans in 2018 and estimates 2019 pension contributions will approximate $8.3 million, although the 2019 required pension contributions will be known with more certainty when the January 1, 2019 valuations are completed, which is expected by April 1, 2019.

Total postretirement health care and life insurance benefit income for System Energy in 2018 was $490 thousand. System Energy expects 2019 postretirement health care and life insurance benefit cost to approximate $1.7

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million. System Energy contributed $569 thousand to its other postretirement plans in 2018 and expects 2019 contributions to approximate $20 thousand.

Federal Healthcare Legislation

See “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.

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, 2018 and 2017, the related statements of income, cash flows, and changes in common equity (pages 438 through 442 and applicable items in pages 53 through 237), for each of the three years in the period ended December 31, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, 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.


/s/ DELOITTE & TOUCHE LLP


New Orleans, Louisiana
February 26, 2019


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,
 
 
2018
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$456,707

 

$633,458

 

$548,291

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
64,778

 
71,700

 
27,416

Nuclear refueling outage expenses
 
20,715

 
17,968

 
19,512

Other operation and maintenance
 
196,505

 
207,344

 
147,976

Decommissioning
 
34,336

 
43,347

 
50,797

Taxes other than income taxes
 
28,090

 
26,180

 
25,195

Depreciation and amortization
 
97,527

 
137,767

 
136,195

Other regulatory credits - net
 
(28,924
)
 
(37,831
)
 
(45,041
)
TOTAL
 
413,027

 
466,475

 
362,050

 
 
 
 
 
 
 
OPERATING INCOME
 
43,680

 
166,983

 
186,241

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
8,750

 
6,345

 
7,944

Interest and investment income
 
35,985

 
17,538

 
14,793

Miscellaneous - net
 
(5,775
)
 
(6,711
)
 
(5,644
)
TOTAL
 
38,960

 
17,172

 
17,093

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
38,424

 
37,141

 
37,529

Allowance for borrowed funds used during construction
 
(2,218
)
 
(1,551
)
 
(2,000
)
TOTAL
 
36,206

 
35,590

 
35,529

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
46,434

 
148,565

 
167,805

 
 
 
 
 
 
 
Income taxes
 
(47,675
)
 
69,969

 
71,061

 
 
 
 
 
 
 
NET INCOME
 

$94,109

 

$78,596

 

$96,744

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 



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SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF CASH FLOWS
 
 
 
 
 
For the Years Ended December 31,
 
 
2018
 
2017
 
2016
 
 
(In Thousands)
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$94,109

 

$78,596

 

$96,744

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 
186,719

 
240,962

 
224,879

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
24,040

 
7,827

 
99,531

Changes in assets and liabilities:
 
 

 
 

 
 

Receivables
 
18,169

 
9,210

 
(15,846
)
Accounts payable
 
(7,067
)
 
15,969

 
2,720

Prepaid taxes and taxes accrued
 
(51,999
)
 
62,466

 
(6,555
)
Interest accrued
 
(94
)
 
(660
)
 
(134
)
Other working capital accounts
 
(45,415
)
 
12,083

 
(15,470
)
Other regulatory assets
 
(2,044
)
 
60,012

 
(58,279
)
Other regulatory liabilities
 
(156,802
)
 
331,251

 
33,438

Deferred tax rate change recognized as regulatory liability/asset
 
—

 
(325,707
)
 
—

Pension and other postretirement liabilities
 
(23,235
)
 
4,024

 
5,586

Other assets and liabilities
 
64,947

 
(124,755
)
 
(24,675
)
Net cash flow provided by operating activities
 
101,328

 
371,278

 
341,939

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(194,696
)
 
(91,705
)
 
(88,037
)
Allowance for equity funds used during construction
 
8,750

 
6,345

 
7,944

Nuclear fuel purchases
 
(125,272
)
 
(49,728
)
 
(151,068
)
Proceeds from the sale of nuclear fuel
 
30,634

 
69,516

 
11,467

Proceeds from nuclear decommissioning trust fund sales
 
573,561

 
565,416

 
499,252

Investment in nuclear decommissioning trust funds
 
(583,683
)
 
(596,236
)
 
(534,083
)
Changes in money pool receivable - net
 
4,545

 
(77,858
)
 
6,117

Litigation proceeds for reimbursement of spent nuclear fuel storage costs
 
—

 
—

 
15,806

Net cash flow used in investing activities
 
(286,161
)
 
(174,250
)
 
(232,602
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
741,785

 
150,100

 
—

Retirement of long-term debt
 
(662,904
)
 
(150,103
)
 
(22,002
)
Changes in short-term credit borrowings - net
 
(17,830
)
 
(49,063
)
 
66,893

Common stock dividends and distributions
 
(67,720
)
 
(106,610
)
 
(139,000
)
Other
 
—

 
(28
)
 
(26
)
Net cash flow used in financing activities
 
(6,669
)
 
(155,704
)
 
(94,135
)
Net increase (decrease) in cash and cash equivalents
 
(191,502
)
 
41,324

 
15,202

Cash and cash equivalents at beginning of period
 
287,187

 
245,863

 
230,661

Cash and cash equivalents at end of period
 

$95,685

 

$287,187

 

$245,863

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 

 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$17,183

 

$26,251

 

$36,152

Income taxes
 

$53,956

 

($2,227
)
 

($23,565
)
See Notes to Financial Statements.
 
 

 
 

 
 


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SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2018
 
2017
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$68

 

$78

Temporary cash investments
 
95,617

 
287,109

Total cash and cash equivalents
 
95,685

 
287,187

Accounts receivable:
 
 

 
 

Associated companies
 
148,571

 
170,149

Other
 
5,390

 
6,526

Total accounts receivable
 
153,961

 
176,675

Materials and supplies - at average cost
 
97,225

 
88,424

Deferred nuclear refueling outage costs
 
44,424

 
7,908

Prepaid taxes
 
5,415

 
—

Prepayments and other
 
2,985

 
2,489

TOTAL
 
399,695

 
562,683

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Decommissioning trust funds
 
869,543

 
905,686

TOTAL
 
869,543

 
905,686

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
4,433,346

 
4,327,849

Property under capital lease
 
602,770

 
588,281

Construction work in progress
 
70,156

 
69,937

Nuclear fuel
 
234,889

 
207,513

TOTAL UTILITY PLANT
 
5,341,161

 
5,193,580

Less - accumulated depreciation and amortization
 
3,212,080

 
3,175,018

UTILITY PLANT - NET
 
2,129,081

 
2,018,562

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Other regulatory assets
 
446,371

 
444,327

Other
 
4,124

 
7,629

TOTAL
 
450,495

 
451,956

 
 
 
 
 
TOTAL ASSETS
 

$3,848,814

 

$3,938,887

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2018
 
2017
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Currently maturing long-term debt
 

$6

 

$85,004

Short-term borrowings
 
—

 
17,830

Accounts payable:
 
 

 
 

Associated companies
 
11,031

 
16,878

Other
 
47,565

 
62,868

Taxes accrued
 
—

 
46,584

Interest accrued
 
13,295

 
13,389

Current portion of unprotected excess accumulated deferred income taxes
 
4,426

 
—

Other
 
2,832

 
2,434

TOTAL
 
79,155

 
244,987

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
805,296

 
776,420

Accumulated deferred investment tax credits
 
38,673

 
39,406

Regulatory liability for income taxes - net
 
158,998

 
246,122

Other regulatory liabilities
 
381,887

 
455,991

Decommissioning
 
896,000

 
861,664

Pension and other postretirement liabilities
 
98,639

 
121,874

Long-term debt
 
630,744

 
466,484

Other
 
22,224

 
15,130

TOTAL
 
3,032,461

 
2,983,091

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
COMMON EQUITY
 
 

 
 

Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2018 and 2017
 
601,850

 
658,350

Retained earnings
 
135,348

 
52,459

TOTAL
 
737,198

 
710,809

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$3,848,814

 

$3,938,887

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 



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SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF CHANGES IN COMMON EQUITY
For the Years Ended December 31, 2018, 2017, and 2016
 
 
 
 
 
Common Equity
 
 
 
Common Stock
 
Retained Earnings
 
Total
 
(In Thousands)
 
 
 
 
 
 
Balance at December 31, 2015

$719,350

 

$61,729

 

$781,079

Net income
—

 
96,744

 
96,744

Common stock dividends and distributions
(40,000
)
 
(99,000
)
 
(139,000
)
Balance at December 31, 2016

$679,350

 

$59,473

 

$738,823

Net income
—

 
78,596

 
78,596

Common stock dividends and distributions
(21,000
)
 
(85,610
)
 
(106,610
)
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

 
 
 
 
 
 
See Notes to Financial Statements.
 

 
 

 
 



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SYSTEM ENERGY RESOURCES, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
2018
 
2017
 
2016
 
2015
 
2014
 
(Dollars In Thousands)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$456,707

 

$633,458

 

$548,291

 

$632,405

 

$664,364

Net income

$94,109

 

$78,596

 

$96,744

 

$111,318

 

$96,334

Total assets

$3,848,814

 

$3,938,887

 

$3,927,712

 

$3,728,875

 

$3,826,193

Long-term obligations (a)

$630,744

 

$466,484

 

$501,129

 

$572,665

 

$630,603

Electric energy sales (GWh)
6,264

 
6,675

 
5,384

 
10,547

 
9,219

 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (excluding currently maturing debt).


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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 2018 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.

EXECUTIVE OFFICERS OF ENTERGY CORPORATION

Executive Officers
Name
 
Age
 
Position
 
Period
Leo P. Denault (a)
 
59
 
Chairman of the Board and Chief Executive Officer of Entergy Corporation
 
2013-Present
 
 
 
 
 
 
 
A. Christopher Bakken, III (a)
 
57
 
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)
 
57
 
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)
 
47
 
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

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Name
 
Age
 
Position
 
Period
Roderick K. West (a)
 
50
 
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)
 
57
 
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
 
 
 
 
Vice President, Capital Project Management and Technology of Entergy Services, Inc.
 
2013-2015
 
 
 
 
 
 
 
Alyson M. Mount (a)
 
48
 
Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
 
2012-Present
 
 
 
 
 
 
 
Peter S. Norgeot, Jr. (a)
 
53
 
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
 
 
 
 
Vice President, Power Plant Operations, Steam of Entergy Services
 
2014-2015
 
 
 
 
 
 
 
Donald W. Vinci (a)
 
60
 
Executive Vice President and Chief Administrative Officer of Entergy Corporation
 
2016-Present
 
 
 
 
Senior Vice President, Human Resources and Chief Diversity Officer of Entergy Corporation
 
2013-2016

(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 is provided as of December 31, 2018.


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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, 2019, there were 24,919 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)
 
 
 
 
 
 
 
 
 
 
10/01/2018 - 10/31/2018
 
—

 

$—

 
—

 

$350,052,918

11/01/2018 - 11/30/2018
 
—

 

$—

 
—

 

$350,052,918

12/01/2018 - 12/31/2018
 
—

 

$—

 
—

 

$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 2018, Entergy withheld 70,517 shares of its common stock at $76.83 per share, 43,342 shares of its common stock at $78.29 per share, and 16,660 shares of its common stock at $78.51 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.


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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, 2018, 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.


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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, 2018.  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, 2018.

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, 2018 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

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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, 2018, 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, 2018, 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, 2018 of the Corporation and our report dated February 26, 2019 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, 2019

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PART III

Item 10.  Directors and Executive Officers 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 “Item 1 – Election of Directors” contained in the Proxy Statement of Entergy Corporation, to be filed in connection with its Annual Meeting of Stockholders to be held May 3, 2019, 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
 
45
 
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 Entergy Corporation Officers Section in Part I.
 
 
Andrew S. Marsh
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Roderick K. West
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
 
 
 
 
 
 
 
Officers
 
 
 
 
 
 
A. Christopher Bakken, III
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Marcus V. Brown
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Leo P. Denault
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Paul D. Hinnenkamp
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Laura R. Landreaux
 
 
 
See information under the Entergy Arkansas Directors Section above.
 
 
Andrew S. Marsh
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Alyson M. Mount
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Donald W. Vinci
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Roderick K. West
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 

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ENTERGY LOUISIANA, LLC
Directors
 
 
 
 
 
 
Phillip R. May, Jr.
 
56
 
President and Chief Executive Officer of Entergy Louisiana
 
2013-Present
 
 
 
 
Director of Entergy Louisiana
 
2013-Present
 
 
 
 
 
 
 
Paul D. Hinnenkamp
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Andrew S. Marsh
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Roderick K. West
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
 
 
 
 
 
 
 
Officers
 
 
 
 
 
 
A. Christopher Bakken, III
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Marcus V. Brown
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Leo P. Denault
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Paul D. Hinnenkamp
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Andrew S. Marsh
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Phillip R. May, Jr.
 
 
 
See information under the Entergy Louisiana Directors Section above.
 
 
Alyson M. Mount
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Donald W. Vinci
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Roderick K. West
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 

ENTERGY MISSISSIPPI, LLC
Directors
 
 
 
 
 
 
Haley R. Fisackerly
 
53
 
President and Chief Executive Officer of Entergy Mississippi
 
2008-Present
 
 
 
 
Director of Entergy Mississippi
 
2008-Present
 
 
 
 
 
 
 
Paul D. Hinnenkamp
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Andrew S. Marsh
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Roderick K. West
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 

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Officers
 
 
 
 
 
 
Marcus V. Brown
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Leo P. Denault
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Haley R. Fisackerly
 
 
 
See information under the Entergy Mississippi Directors Section above.
 
 
Paul D. Hinnenkamp
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Andrew S. Marsh
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Alyson M. Mount
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Donald W. Vinci
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Roderick K. West
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 

ENTERGY NEW ORLEANS, LLC
Directors
 
 
 
 
 
 
David D. Ellis
 
51
 
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 Entergy Corporation Officers Section in Part I.
 
 
Andrew S. Marsh
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Roderick K. West
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 

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Officers
 
 
 
 
 
 
Marcus V. Brown
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Leo P. Denault
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
David D. Ellis
 
 
 
See information under the Entergy New Orleans Directors Section above.
 
 
Paul D. Hinnenkamp
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Andrew S. Marsh
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Alyson M. Mount
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Donald W. Vinci
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Roderick K. West
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
ENTERGY TEXAS, INC.
Directors
 
 
 
 
 
 
Sallie T. Rainer
 
57
 
President and Chief Executive Officer of Entergy Texas
 
2012-Present
 
 
 
 
Director of Entergy Texas
 
2012-Present
 
 
 
 
 
 
 
Paul D. Hinnenkamp
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Andrew S. Marsh
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Roderick K. West
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Officers
 
 
 
 
 
 
Marcus V. Brown
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Leo P. Denault
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Paul D. Hinnenkamp
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Andrew S. Marsh
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Alyson M. Mount
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Sallie T. Rainer
 
 
 
See information under the Entergy Texas Directors Section above.
 
 
Donald W. Vinci
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Roderick K. West
 
 
 
See information under the Entergy Corporation Officers Section 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 Louisiana, LLC and Entergy New Orleans, LLC are, and in the case of Entergy Arkansas, LLC and Entergy Mississippi, LLC will be, elected annually to serve by the unanimous

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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, 2018.

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
Blanche L. Lincoln
Karen A. Puckett

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 combined two separate but similarly worded codes that applied to members of the Entergy Corporation Board of Directors and to officers and employees, respectively.  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

The Corporate Governance Committee will consider candidates identified by current directors, management, third-party search firms engaged by the Corporate Governance Committee and Entergy Corporation’s shareholders. 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;

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•
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.

Section 16(a) Beneficial Ownership Reporting Compliance

Information called for by this item concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held on May 3, 2019, under the heading “Section 16(a) Beneficial Ownership Reporting Compliance,” which information is incorporated herein by reference.


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Item 11.  Executive Compensation

ENTERGY CORPORATION

Information concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement under the headings “Compensation Discussion and Analysis,” “Executive Compensation Tables,” “2019 Director Nominees,” “Personnel Committee Interlocks and Insider Participation,” and “2018 Non-Employee Director Compensation,” all of which information is incorporated herein by reference.

ENTERGY ARKANSAS, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND ENTERGY TEXAS

COMPENSATION DISCUSSION AND ANALYSIS

In this section, the compensation earned in 2018 by the following executive officers (referred to herein as “Named Executive Officers”) is discussed.
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(2)
President and Chief Executive Officer, Entergy New Orleans
Haley R. Fisackerly
President and Chief Executive Officer, Entergy Mississippi
Laura R. Landreaux(3)
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
Charles L. Rice, Jr.(2)
Former President and Chief Executive Officer, Entergy New Orleans
Richard C. Riley(3)
Former President and Chief Executive Officer, Entergy Arkansas
Roderick K. West(2)
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. No additional compensation was paid in 2018 to any of these officers for their service as Named Executive Officers of the Utility operating companies.
(2)
Mr. Rice is included in the Executive Compensation section of this Form 10-K because he served as President and Chief Executive Officer, Entergy New Orleans for a portion of 2018. Mr. Ellis became President and Chief Executive Officer, New Orleans in December 2018, and for a portion of 2018, Mr. West served as interim President and Chief Executive Officer, Entergy New Orleans.
(3)
Mr. Riley is included in the Executive Compensation section of this Form 10-K because he served as President and Chief Executive Officer, Entergy Arkansas for a portion of 2018. Ms. Landreaux succeeded Mr. Riley as President and Chief Executive Officer, Entergy Arkansas in July 2018.




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Entergy Corporation’s Executive Compensation Programs and 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 investors on executive compensation.

 Executive Compensation Best Practices:

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 under the Annual Incentive Plan and Long-Term Performance Unit Program for members of the Office of the Chief Executive
*
Minimum vesting periods for equity-based awards
*
Long-term compensation mix weighted more toward performance units than service-based equity awards
*
All long-term performance units settled in shares of Entergy Corporation common stock
*
Rigorous stock ownership requirements
*
Executives required to hold substantially all equity compensation received by Entergy Corporation until stock ownership guidelines are met
*
Annual Say on Pay vote
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, other than relocation benefits available to all eligible employees, and club dues for some of the Named Executive Officers.
*
No option repricing or cash buy-outs for underwater options
*
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 hedging or pledging of Entergy Corporation common stock
*
No unusual or excessive perquisites
*
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
Entergy Corporation’s Pay for Performance Philosophy

Entergy Corporation’s executive compensation programs are based on a philosophy of pay for performance that is embodied in the design of its annual and long-term incentive plans. It believes the executive pay programs described in this section and in the accompanying tables have played a significant role in the ability to drive strong financial and operational results and to attract and retain a highly experienced and successful management team.

•
Annual Incentive Plan incentivizes and rewards the achievement of financial metrics that are deemed by the Entergy Corporation Personnel Committee to be consistent with the overall goals and strategic direction that the Entergy Corporation Board has approved for Entergy Corporation.

•
Long-term incentive programs further align the interests of the executives and Entergy Corporation’s shareholders by directly tying the value of equity awards granted to executives under these programs to Entergy Corporation’s stock price performance, relative total shareholder return, and beginning in 2018, cumulative adjusted utility earnings growth. The long-term incentives consist of three components - performance units, stock options and restricted stock.


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By incentivizing officers to achieve important financial and operational objectives and create long-term shareholder value, Entergy Corporation believes these programs play a key role in creating sustainable value for the benefit of all of its stakeholders, including its owners, customers, employees, and communities.

2018 Incentive Pay Outcomes
    
Entergy Corporation believes the 2018 incentive pay outcomes for the Named Executive Officers demonstrated the application of Entergy Corporation’s pay for performance philosophy.
Annual Incentive Plan
    
Awards under the Executive Annual Incentive Plan, or Annual Incentive Plan, are tied to Entergy Corporation’s financial and operational performance through the Entergy Achievement Multiplier (EAM), which is the performance metric used to determine the maximum funding available for awards under the plan. The 2018 EAM was determined based in equal part on Entergy Corporation’s success in achieving its consolidated operational earnings per share and consolidated operational operating cash flow goals set at the beginning of the year. These goals were approved by the Personnel Committee based on Entergy Corporation’s financial plan and the Board’s overall goals for Entergy Corporation and were consistent with its published earnings guidance.

2018 Annual Incentive Plan Payout

For 2018, the Personnel Committee, based on the recommendation of the Finance Committee, determined that management exceeded its consolidated operational earnings per share goal of $6.55 per share by $2.03 per share, but fell short of its consolidated operational operating cash flow goal of $3.000 billion by approximately $180 million. Based on the targets and ranges previously established by the Personnel Committee, these results resulted in a calculated EAM of 134%.

After considering individual performance, including not only the role played by each of the Named Executive Officers who are members of the Office of the Chief Executive in advancing Entergy Corporation’s strategies and delivering the strong financial results achieved in 2018, but also each such individual’s degree of accountability for certain operational and regulatory challenges Entergy Corporation experienced in 2018, the Personnel Committee approved payouts ranging from 115% to 122% of target for each of the Named Executive Officers who are members of the Office of the Chief Executive.

After the EAM was established to determine overall funding for the Annual Incentive Plan, 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 Named Executive Officers who are not members of the Office of the Chief Executive by their immediate supervisor based on the individual officer’s key accountabilities, accomplishments, and performance. This resulted in payouts that ranged from 0% of target to 118% of target for the Named Executive Officers who are not members of Entergy Corporation’s Office of the Chief Executive.
Long-Term Incentives
    
Long term incentives consist of three components:

•
Long-Term Performance Unit Program - Units are granted with performance measured over a three-year period based on Entergy Corporation’s total shareholder return in relation to the total shareholder return of the companies included in the Philadelphia Utility Index, and beginning with the 2018-2020 performance period, a cumulative utility earnings metric. Payouts, if any, are based on Entergy Corporation’s performance on these measures against pre-established performance goals.

•
Stock Options - Incentivizes executives to take actions that increase the market value of Entergy Corporation’s common stock and directly aligns with the value shareholders receive over the same period of time; and


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•
Restricted Stock - Increases executive stock ownership and is an effective retention mechanism.

Long-Term Performance Unit Program Payout
    
For the three-year performance period ending in 2018, Entergy Corporation’s total shareholder return was ninth out of the twenty companies in the Philadelphia Utility Index, resulting in a payout of 111% of target for the executive officers. Payouts were made in shares of Entergy Corporation stock which are required to be held by the executive officers until they satisfy the executive stock ownership guidelines.

What Entergy Corporation Pays and Why

How Entergy Corporation Sets Target Pay

The Personnel Committee annually reviews compensation data from two sources:

Use of Competitive Data

To develop marketplace compensation levels for Entergy Corporation’s executive officers, the Personnel Committee primarily uses the following types of data to compare the current compensation opportunities provided to each of the executive officers against the compensation opportunities provided to executives holding similar positions at companies with corporate revenues similar to Entergy Corporation’s:

•
Published and private compensation survey data compiled by Pay Governance;
•
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.

The Personnel Committee uses this survey data to develop compensation opportunities that are designed to deliver total target compensation 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 six other executive officers (including all of the Named Executive Officers) who constitute the Office of the Chief Executive 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 with strong performance who are viewed as critical to retain would be positioned at the higher end of the competitive range. Actual compensation received by an individual officer may be above or below the targeted range based on an individual officer’s skills, performance, experience and responsibilities, corporate performance and internal pay equity.
 
Proxy Analysis

Although the survey data described above are the primary data used in benchmarking compensation, the committee reviews data derived from the proxy statements of companies included in the Philadelphia Utility Index to evaluate the overall reasonableness of Entergy Corporation’s compensation programs. The Personnel Committee identified the Philadelphia Utility Index as the appropriate industry peer group because the companies included in this index, in the aggregate, are comparable to Entergy Corporation in terms of business and scale. Companies included in the Philadelphia Utility Index at the time the proxy data was compiled were as follows:


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Ÿ
AES Corporation
Ÿ
El Paso Electric Co.
Ÿ
Ameren Corporation
Ÿ
Eversource Energy
Ÿ
American Electric Power Co. Inc.
Ÿ
Exelon Corporation
Ÿ
American Water Works
Ÿ
FirstEnergy Corporation
Ÿ
CenterPoint Energy Inc.
Ÿ
NextEra Energy, Inc.
Ÿ
Consolidated Edison Inc.
Ÿ
PG&E Corporation
Ÿ
Dominion Energy
Ÿ
Public Service Enterprise Group, Inc.
Ÿ
DTE Energy Company
Ÿ
Southern Company
Ÿ
Duke Energy Corporation
Ÿ
Xcel Energy, Inc.
Ÿ
Edison International
 
 

Principal Executive Compensation Elements

The following table summarizes the elements of total direct compensation (TDC) granted or paid to the executive officers under the 2018 executive compensation programs. The programs use a mix of fixed and variable compensation elements and are designed to provide alignment with both short- and long-term business goals through annual and long-term incentives. An executive officer’s TDC is based primarily on corporate performance, market-based compensation levels and individual performance with each of these elements reviewed annually for each Named Executive Officer.
 
Compensation Component
Primary Purpose
Performance Measured
Key Characteristic
Cash/Equity
Performance Period
Base Salary
Provides a base level of competitive cash compensation for executive talent.
Role, experience, job scope, market data, and individual performance
Fixed
Cash
Ongoing
Annual Incentive
Motivates and rewards executives for performance on key financial measures during the year.
Consolidated operational earnings per share and operational operating cash flow
Variable
Cash
1 year
Long-Term
Performance
Unit
Program
Focuses executives on growing earnings and building long-term shareholder value and increases executives’ ownership of Entergy Corporation common stock.
Total shareholder return and utility earnings growth
Variable
Equity
3 years
Stock
Options
Align interests of executives with long-term shareholder value, provide competitive compensation, and increase the executives’ ownership in Entergy Corporation’s common stock.
Job scope, market data, individual and Entergy Corporation performance.
Variable
 Equity
3 years
Restricted Stock
Aligns interests of executives with long-term shareholder value, provides competitive compensation, retains executive talent and increases the executives’ ownership in Entergy Corporation’s common stock.

Job scope, market data, and individual performance

Variable
Equity
3 years

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Fixed Compensation

Base Salary

The Personnel Committee determines the base salaries for all of the Named Executive Officers who are members of the Office of the Chief Executive based on competitive compensation data, performance considerations, and advice provided by the committee’s independent compensation consultant. For the other Named Executive Officers, their salaries are established by their immediate supervisors using the same criteria. In addition, in determining base salary adjustments, the Personnel Committee considered internal pay equity, although the Personnel Committee has not established any predetermined formula by which an individual’s base salary is measured or evaluated in relation to other employees. In 2018, all of the Named Executive Officers received merit increases in their base salaries ranging from approximately 2.4% to 4.2% other than Mr. Ellis. The increases in base salary were based on the market data previously discussed in this CD&A under “What Entergy Corporation Pays and Why - How Entergy Corporation Sets Target Pay.”
 
The following table sets forth the 2017 and 2018 base salaries for the Named Executive Officers. Except as indicated below, changes in base salaries for 2018 were effective in April.

Named Executive Officer
 
2017 Base Salary
 
2018 Base Salary
A. Christopher Bakken, III
 
$620,125
 
$638,125
Marcus V. Brown
 
$630,000
 
$650,000
Leo P. Denault
 
$1,230,000
 
$1,260,000
David D. Ellis(1)
 
$—
 
$305,000
Haley R. Fisackerly
 
$355,300
 
$365,959
Laura R. Landreaux(2)
 
$186,339
 
$308,000
Andrew S. Marsh
 
$600,000
 
$622,000
Phillip R. May, Jr.
 
$366,150
 
$381,550
Sallie T. Rainer
 
$328,275
 
$338,123
Charles L. Rice, Jr.(3)
 
$286,424
 
$230,000
Richard C. Riley(4)
 
$344,200
 
$375,000
Roderick K. West
 
$675,598
 
$696,598
(1)
When Mr. Ellis joined Entergy in December 2018, his base salary was set at $305,000 based on competitive market data discussed above, as well as internal pay equity considerations.
(2)
In July 2018, Ms. Landreaux’s salary was increased when she became President and Chief Executive Officer, Entergy Arkansas and assumed the increased responsibilities of that role.
(3)
Mr. Rice’s salary was adjusted when he transitioned into Entergy Corporation’s legal department.
(4)
Mr. Riley’s salary was increased when he became Senior Vice President, Distribution Operations and Asset Management and assumed the increased responsibilities of that role.

Variable Compensation

Short-Term Incentive Compensation

Annual Incentive Plan

Entergy Corporation includes performance-based incentives in the Named Executive Officers’ compensation packages because it believes performance-based incentives encourage the Named Executive Officers to pursue objectives consistent with the overall goals and strategic direction that the Board has approved for Entergy Corporation. The EAM is the performance metric used to determine the maximum percentage of target annual plan opportunities that will be paid each year to each Named Executive Officer who is a member of the Office of the Chief Executive

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under the Annual Incentive Plan. Once the EAM has been determined, individual awards for the Office of the Chief Executive members may be adjusted downward, but not upward, from the EAM at the Personnel Committee’s discretion, based on individual performance and other factors deemed relevant by the Personnel Committee.

Target award opportunities are set based on an executive officer’s position and executive management level within the Entergy organization. Executive management levels at Entergy Corporation range from Level 1 through Level 5. At December 31, 2018, Mr. Denault held a Level 1 position, Messrs. Bakken, Brown, Marsh, and West held positions in Level 2, Mr. May and Mr. Riley held Level 3 positions, Mr. Ellis, Mr. Fisackerly, Ms. Landreaux and Ms. Rainer held Level 4 positions and Mr. Rice held a Level 5 position. Accordingly, their respective incentive award opportunities differ from one another based on their management level and the external market data developed by the Committee’s independent compensation consultant.

Setting Targets

Annual Review of Performance Measures to Determine EAM Pool:

In December 2017, the Personnel Committee decided to retain consolidated operational earnings per share and consolidated operational operating cash flow, with each measure weighted equally, as the performance measures for determining the EAM pool. Other measures were considered, but the Personnel Committee determined that consolidated operational earnings per share and operational operating cash flow continued to be the best metrics to use for this purpose because:

•
They represent objective measures that Entergy Corporation and its investors consider to be important in evaluating its financial performance;
•
They align with Entergy Corporation’s internal and external financial reporting; and
•
They provide both discipline and transparency.

Establishing Target Achievement Levels

The Personnel Committee annually engages in a rigorous process with a goal of establishing target achievement levels that are consistent with Entergy Corporation’s strategy and business objectives for the upcoming year, as reflected in its financial plan and sufficient to drive results that represent a high level of achievement. These targets are approved based on a comprehensive review by the full Board of Entergy Corporation’s financial plan, conducted in December of the preceding year and updated in January to reflect the most current information concerning changes in commodity market conditions and other key drivers of anticipated changes in performance from the preceding year. 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.

2018 Targets

In January 2018, the Personnel Committee followed the process described above in setting 2018 performance targets. Consistent with its authority and past practice, the Personnel Committee determined that the effect of the following would be excluded from the reported results:

•
Any major storms that may occur during the year;
•
Certain impacts that may occur as a result of the implementation of the Tax Cuts and Jobs Act enacted in December 2017;
•
Certain unresolved litigation initiated in the late 1990s and early 2000s relating to an agreement among the Utility operating company subsidiaries that has since been terminated; and

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•
Unrealized gains and losses on equity securities different than assumed in the plan.

The Personnel Committee viewed the exclusion of major storms as appropriate because although estimates for storm costs are included in Entergy Corporation’s financial plan, it does not include estimates for a major storm event, such as a hurricane. The adjustment for unanticipated impacts of the Tax Cuts and Jobs Act was limited to the impact of any deviations from regulatory assumptions incorporated into the plan relating to (a) the timing of the adjustment of retail electric rates due to the change in the federal tax rate, and (b) the timing and amount of deferred income taxes that may be refunded to customers. However, the impacts of tax reform were only to be excluded to the extent that they cumulatively impacted consolidated operational earnings per share by more than $0.10 per share in 2018. The Personnel Committee considered the exclusion of tax reform to be appropriate because of the substantial uncertainty around the outcomes of the applicable discussions and proceedings with regulators, which had not yet commenced, and because of the potential that there could be significant adverse impacts on 2018 results from such outcomes that would be in the long-term best interest of Entergy Corporation. The Personnel Committee approved the other exclusions from reported results, for the impact of the legacy system agreement litigation and 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.

In determining the targets to set for 2018, the Personnel Committee reviewed anticipated drivers for consolidated operational earnings per share and consolidated operational operating cash flow for 2018 as set forth in Entergy Corporation’s financial plan, as well as factors driving the strong financial performance achieved in 2017. The Personnel Committee noted that a substantial portion of 2017 operational earnings per share was attributable to a major restructuring tax benefit at the Entergy Wholesale Commodities business. The committee also noted that 2017 operational earnings per share had been adversely impacted by unusual weather. After adjusting to eliminate the impact on 2017 operational results of both the tax item and weather, the committee confirmed that the proposed plan target for operational earnings per share reflected substantial growth in core operational earnings.

The Personnel Committee also considered the potential impact of certain risks and opportunities, including differences from plan in wholesale energy prices and capacity factors at the Entergy Wholesale Commodities business, utility sales, operations and maintenance costs, interest expense and certain tax and regulatory outcomes. This evaluation indicated that there was significantly more downside risk than upside opportunity in the targets and, as a result, that there was a reasonable degree of challenge embedded in the targets.
 
2018 Performance Assessment

The following table shows the 2018 Incentive Plan targets established by the Personnel Committee and 2018 results:

Annual Incentive Plan Targets and Results
 
Performance Goals(1)
 
 
Minimum
Target
Maximum
2018 Results(2)
Consolidated Operational Earnings Per Share
$5.90
$6.55
$7.20
$8.58
Consolidated Operational Operating Cash Flow ($ billion)
$2.580
$3.000
$3.420
$2.820
EAM as % of Target
25%
100%
200%
134%
(1)
Payouts for performance between minimum and target achievement levels and between target and maximum levels are calculated using straight-line interpolation. There is no payout for performance below minimum.
(2) These results are adjusted to reflect the pre-determined exclusions approved by the Personnel Committee in January 2018 and described above.

In January 2019, 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 consolidated operational earnings per share and consolidated operational operating cash flow

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results for 2018, including primary factors explaining how those results compared to the 2018 business plan and Annual Incentive Plan targets set in January. Consolidated operational earnings per share, adjusted as determined by the committee when targets were set at the beginning of the year, exceeded Entergy Corporation’s consolidated operational earnings per share goal of $6.55 per share by $2.03, due in large part to a favorable tax item and a pre-determined adjustment made for the impact of below-plan market performance by the investment securities in Entergy Corporation’s nuclear decommissioning trusts, but management fell short of achieving its consolidated operational operating cash flow goal of $3.000 billion by approximately $180 million, on an adjusted basis, leading to a calculated EAM of 134%.

Operational results for 2018 excluded the impact of certain special items that were excluded from as-reported (GAAP) consolidated earnings per share and operating cash flow to determine operational earnings per share and operating cash flow, including items related to tax reform legislation, the shutdown and disposition of Entergy Wholesale Commodities business nuclear plants, the accelerated return of unprotected accumulated deferred income taxes as a result of tax reform, Entergy Wholesale Commodities business net revenue and nuclear decommissioning trust tax payments. These were not adjustments made by the committee in determining the EAM, but were all considered special items and therefore excluded from the operational results reported to investors and from the financial measures used in the plan targets.

     To determine individual executive officer awards under the Annual Incentive Plan for the Named Executive Officers who are members of the Office of the Chief Executive, the Personnel Committee considered not only each executive’s role in executing on Entergy Corporation’s strategies and delivering the strong financial performance achieved in 2018, but also the individual’s accountability for certain operational and regulatory challenges it experienced during the year. With these considerations in mind, the committee exercised negative discretion to determine individual awards that ranged from 115% to 122% of target for each of the Named Executive Officers who are members of the Office of the Chief Executive, with the extent of the negative discretion applied varying based on the executive’s specific accountabilities and accomplishments.  
 
After the EAM was established to determine overall funding for the Annual Incentive Plan, 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 Named Executive Officers who are not members of the Office of the Chief Executive by their immediate supervisor based on the individual officer’s key accountabilities, accomplishments, and performance.  This resulted in payouts that ranged from 0% of target to 118% of target for the Named Executive Officers who are not members of the Office of the Chief Executive.

Based on the foregoing evaluation of management performance, the Named Executive Officers received the following Annual Incentive Plan payouts for 2018:

Named Executive Officer
Base Salary (1)
Target as Percentage of Base Salary
Payout as Percentage of Target(2)
2018 Annual
Incentive Award
A. Christopher Bakken, III
$638,125
70%
122%
$544,959
Marcus V. Brown
$650,000
70%
120%
$546,000
Leo P. Denault
$1,260,000
135%
120%
$2,041,200
David D. Ellis(3)
$—
—%
—%
$—
Haley R. Fisackerly
$365,959
40%
117%
$172,000
Laura R. Landreaux
$308,000
40%
101%
$124,000
Andrew S. Marsh
$622,000
70%
122%
$531,188
Phillip R. May, Jr.
$381,550
60%
118%
$270,000
Sallie T. Rainer
$338,123
40%
118%
$159,000
Charles L. Rice, Jr.
$230,000
30%
—%
$—
Richard C. Riley
$375,000
60%
100%
$225,000
Roderick K. West
$696,598
70%
115%
$560,762

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(1)
The target opportunities, as a percentage of salary, were determined based on the individual’s position and salary at the end of 2018. Such target opportunities for the Named Executive Officers did not change from the levels set in 2017, except for Ms. Landreaux’s and Mr. Riley’s, whose target opportunities increased due to their promotions during the year, and Mr. Rice’s whose target opportunities decreased, as he was no longer serving in an officer position at year-end.
(2)
The Named Executive Officers, who are members of the Office of the Chief Executive, may earn a maximum payout ranging from 0% to 200% of their target opportunity, not to exceed the EAM.
(3)
As a new hire, Mr. Ellis was not eligible to participate in the Annual Incentive Plan for 2018.

 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. Mr. Bakken’s participation in the plan commenced in May 2016, and in accordance with the terms and conditions of the plan, in May 2017 and 2018, Mr. Bakken received, and in May 2019, subject to his continued employment, Mr. Bakken will receive a cash bonus equal to $181,500 or 30% of his May 1, 2016 base salary. This plan does not provide for accelerated or prorated payout upon termination of any kind.

Long-Term Incentive Compensation

Entergy Corporation’s goal for its long-term incentive compensation is to focus the executive officers on building shareholder value and to increase the executive officers’ ownership of Entergy Corporation’s common stock in order to more closely align their interest with those of Entergy Corporation’s shareholders. 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. Awards for individual Named Executive Officers may vary from this target as a result of individual performance, promotions, and internal pay equity.

All of the outstanding performance units and all of the shares of restricted stock and stock options granted to the Named Executive Officers in 2018 were granted pursuant to the 2015 Equity Ownership Plan or 2015 Equity Plan. The 2015 Equity Plan requires both a change in control and an involuntary job loss or substantial diminution of duties (a “double trigger”) for the acceleration of these awards upon a change in control.

Performance Unit Program

The Named Executive Officers are issued performance unit awards under the Long-Term Performance Unit Program.

•
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, with payouts only occurring if the performance goals are met.
•
Payouts under this program are not made if minimum performance goals are not achieved.
•
All shares paid out under the Long-Term Performance Unit Program are required to be retained by Entergy Corporation’s officers until applicable executive stock ownership requirements are met.

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 by each participant. For the

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2016-2018 and 2017-2019 performance periods, performance will be measured by assessing Entergy Corporation’s total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index. The Personnel Committee identified the Philadelphia Utility Index as the appropriate industry peer group for this purpose because the companies included in this index, in the aggregate, are comparable to Entergy Corporation in terms of business and scale. The Personnel Committee chose relative total shareholder return as a performance measure because it reflects Entergy Corporation’s creation of shareholder value relative to other electric utilities over the performance period. It also takes into account dividends paid by the companies in this index and normalizes certain 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 total shareholder return against the total shareholder return of the companies in the Philadelphia Utility Index.

For the 2018-2020 performance period, performance will be measured using two performance measures - total shareholder return and cumulative adjusted Utility, Parent & Other earnings per share (UP&O Adjusted EPS), with each performance measure weighted equally. UP&O Adjusted EPS, which adjusts Entergy Corporation’s operational Utility, Parent & Other results to eliminate the impact of tax items and weather, was added as a performance measure since delivering steady, predictable growth at the Utility is an integral component of executing Entergy Corporation’s strategy, and it aligns with externally communicated Utility guidance. Similar to the way targets are established for the Annual Incentive Plan, targets for the UP&O Adjusted EPS performance measure were established by the Personnel Committee after the Board’s review of Entergy Corporation’s financial plan. These targets also incorporate exclusions similar to those used with the Annual Incentive Plan. Given the economic and market conditions at the time the targets were set, the target payout levels for the UP&O Adjusted EPS goal were designed to be challenging but achievable, while payouts at the maximum levels were designed to be stretch goals. Payout is based on achieving the performance goals established for each performance measure by the committee at the beginning of the performance period.

Performance Unit Program Grants. At any given time, a participant in the Long-Term Performance Unit Program may be participating in up to three performance periods. During 2018, eligible participants were participating in the 2016-2018, 2017-2019 and 2018-2020 performance periods. Subject to achievement of the applicable performance levels as described below, the Personnel Committee established the following target performance unit payout opportunities for each of the 2016-2018, 2017-2019 and 2018-2020 performance periods.

Named Executive Officer
2016-2018
Target
2017-2019
 Target
2018-2020 Target
A. Christopher Bakken, III (1)
7,289
8,300
7,900
Marcus V. Brown
8,200
8,300
7,900
Leo P. Denault
41,700
48,700
42,700
David D. Ellis(2)
—
—
—
Haley R. Fisackerly
1,800
1,850
1,650
Laura R. Landreaux(3)
—
925
1,375
Andrew S. Marsh
8,200
8,300
7,900
Phillip R. May, Jr.
2,700
3,150
2,550
Sallie T. Rainer
1,800
1,850
1,650
Charles L. Rice, Jr.(4)
1,500
976
321
Richard C. Riley(4)
1,950
2,500
2,400
Roderick K. West
8,200
8,300
7,900
(1)
As a new hire in 2016, Mr. Bakken received a pro-rated target award opportunity for the 2016-2018 performance period.
(2)
As of December 31, 2018, Mr. Ellis was not a participant in the Long-Term Performance Unit Program.
(3)
When Ms. Landreaux became President, Entergy Arkansas, she received pro-rated target award opportunities for the 2017-2019 and 2018-2020 performance periods. As a new officer in 2018, Ms. Landreaux was not eligible to participate in the 2016-2018 performance period.

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(4)
Mr. Rice and Mr. Riley’s target opportunities were modified in connection with their change in positions in 2018.

The range of potential payouts for the 2016-2018 and 2017-2019 performance periods under the program is shown below.

Performance Level(1)
Zero
Minimum
Target
Maximum
Total Shareholder Return
Fourth Quartile
Bottom of Third Quartile
Median percentile
Top Quartile
Payout
No Payout
Minimum Payout of 25% of target
100% of target
200% of Target
(1)
Payouts for performance between achievement levels are calculated using straight-line interpolation, with no payouts for performance below the minimum achievement level.
    
As noted above, for the 2018-2020 performance period, performance will be measured using two performance measures - total shareholder return and UP&O Adjusted EPS with each performance measure weighted equally. Under the 2018-2020 performance period, the performance goals and the payout opportunities associated with the relative total shareholder return metric are consistent with the 2016-2018 and 2017-2019 performance periods, as described above. Based on performance, the performance units allocated to the UP&O Adjusted EPS goal could range from 25% to 200% of the target opportunity, with no payment for performance below the minimum performance goal. The Personnel Committee established the performance goals and range of potential payouts for the 2018-2020 performance period to encourage strong, focused performance.

Payout for the 2016-2018 Performance Period. In January 2019, the Personnel Committee reviewed Entergy Corporation’s total shareholder return for the 2016-2018 performance period in order to determine the payout to participants. The committee compared Entergy Corporation’s total shareholder return against the total shareholder return of the companies that comprise the Philadelphia Utility Index, with the performance measures and range of potential payouts for the 2016-2018 performance period as discussed above. As recommended by the Finance Committee, the Personnel Committee concluded that Entergy Corporation’s relative total shareholder return for the 2016-2018 performance period fell in the second quartile, yielding a payout of 111% of target for the Named Executive Officers.

Named Executive Officer
2016-2018
Target
Number of Shares Issued
Value of Shares Actually Issued(1)
Grant Date Fair Value
A. Christopher Bakken, III(2)
7,289
8,998
$774,098
$616,066
Marcus V. Brown
8,200
10,212
$878,538
$693,064
Leo P. Denault
41,700
51,933
$4,467,796
$3,524,484
David D. Ellis(3)
—
—
$—
$—
Haley R. Fisackerly
1,800
2,241
$192,793
$152,136
Laura R. Landreaux(4)
—
—
$—
$—
Andrew S. Marsh
8,200
10,212
$878,538
$693,064
Phillip R. May, Jr.
2,700
3,362
$289,233
$228,204
Sallie T. Rainer
1,800
2,241
$192,793
$152,136
Charles L. Rice, Jr.(5)
1,500
1,894
$162,941
$126,780
Richard C. Riley(5)
1,950
2,411
$207,418
$164,814
Roderick K. West
8,200
10,212
$878,538
$693,064

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(1)
Value determined based on the closing price of Entergy Corporation’s common stock on January 17, 2019 ($86.03), the date the Personnel Committee certified the 2016-2018 performance period results.
(2)
As a new hire in 2016, Mr. Bakken received a pro-rated target award opportunity for the 2016-2018 performance period.
(3)
As a new hire in 2018, Mr. Ellis was not eligible to participate in 2016-2018 performance period.
(4)
As a new officer in 2018, Ms. Landreaux was not a participant in the 2016-2018 performance period.
(5)
Mr. Rice and Mr. Riley experienced a change in officer status in 2018, and accordingly, each received a pro-rated award opportunity for the 2016-2018 performance period.

Stock Options and Restricted Stock
Factors used by the Personnel Committee to determine the number of stock options and shares of restricted stock it will grant to Entergy Corporation’s Named Executive Officers include Entergy Corporation and individual performance, internal pay equity, prevailing market practice, with the committee’s assessment of individual performance of each Named Executive Officer other than Entergy Corporation’s Chief Executive Officer being the most important factor in determining the number of shares of restricted stock and stock options awarded and comparative market data being the most important factor in determining Entergy Corporation’s Chief Executive Officer’s award levels. The Personnel Committee, in consultation with Entergy Corporation’s Chief Executive Officer, reviews each other Named Executive Officer’s performance, role and responsibilities, strengths and developmental opportunities. Stock option and restricted stock awards for Entergy Corporation’s Chief Executive Officer are determined solely by the Personnel Committee on the basis of the same considerations.
 
The following table sets forth the number of stock options and shares of restricted stock granted to each Named Executive Officer in 2018. The exercise price for each option was $78.08, which was the closing price of Entergy Corporation’s common stock on the date of grant.

Named Executive Officer
Stock Options
Shares of Restricted Stock
A. Christopher Bakken, III
40,500
5,000
Marcus V. Brown
40,500
5,000
Leo P. Denault
167,100
15,700
David D. Ellis(1)
—
—
Haley R. Fisackerly
6,600
800
Laura R. Landreaux(2)
—
1,200
Andrew S. Marsh
49,000
5,200
Phillip R. May, Jr.
9,900
1,000
Sallie T. Rainer
6,600
800
Charles L. Rice, Jr.
400
600
Richard C. Riley
9,900
1,100
Roderick K. West
42,500
5,200
(1)
As a new hire, Mr. Ellis was not eligible to receive stock options or restricted stock in 2018.
(2)
Stock options are awarded only to individuals who are officers at the time of grant. Ms. Landreaux was not eligible to receive stock options in 2018 because she was not an officer when the grants were made in 2018.

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Benefits and Perquisites

Entergy Corporation’s Named Executive Officers 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.
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.

See the 2018 Pension Benefits Table for additional information regarding the operation of the plans described above.
Savings Plan
Entergy Corporation-sponsored 401(k) Savings Plan that covers a broad group of employees.
Health & Welfare Benefits
Medical, dental, and vision coverage, 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 Named Executive Officers as for the broad employee population.
2018 Perquisites
Corporate aircraft usage, annual mandatory physical exams, relocation assistance, and event tickets. The Named Executive Offices who are members of the Office of the Chief Executive do not receive tax gross ups on any benefits, except for relocation assistance.

Named Executive Officers who are not members of the Office of the Chief Executive also were provided in 2018 with club dues and tax gross up payments on some perquisites.

For additional information regarding perquisites, see the “All Other Compensation” column in the 2018 Summary Compensation Table.
Deferred Compensation
The Named Executive Officers are eligible to defer up to 100% of their base salary and Annual Incentive Plan 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 Named Executive Officers as part of providing 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 Other Compensation 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 Named Executive Officers, 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 executive officers, defined as ML level 1 through 4 officers (ML 1-4 Officers), are entitled to receive “change in control” payments and benefits if such officer’s employment is involuntarily terminated in connection with a change in control of Entergy Corporation and its subsidiaries. Severance payments under the System Executive Continuity Plan generally are based on a multiple of the sum of an executive officer’s annual base salary plus his or her average Annual Incentive Plan award for the two calendar years immediately preceding the calendar year in which the termination of employment occurs. Under the policy, under no circumstances can this multiple exceed 2.99 times the sum of the executive officer’s annual base salary and his or her annual incentive, calculated in accordance with this policy. 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 Named Executive Officers, 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 “2018 Potential Payments Upon Termination or Change in Control.”

In certain cases, the Personnel Committee may approve the execution of a retention agreement with an individual executive officer. These decisions are made on a case by case basis to reflect specific retention needs or other factors, including market practice. If a retention agreement is entered into with an individual officer, the committee considers the economic value associated with that agreement in making overall compensation decisions for that officer. Entergy Corporation has voluntarily adopted a policy that any employment or severance agreements providing severance benefits in excess of 2.99 times the sum of an officer’s annual base salary and annual incentive award (other than the value of the vesting or payment of an outstanding equity-based award or the pro rata vesting or payment of an outstanding long-term incentive award) must be approved by Entergy Corporation’s shareholders.

Mr. Denault

Entergy Corporation currently has a retention agreement with Mr. Denault. In general, Mr. Denault’s retention agreement provides for certain payments and benefits in the event of his termination of employment by his Entergy employer other than for cause, by Mr. Denault for good reason or on account of his death or disability. See “2018 Potential Payments Upon Termination or Change in Control - Mr. Denault’s 2006 Retention Agreement.” Because Mr. Denault has reached age 55, certain severance payment provisions in his retention agreement no longer apply. Mr. Denault is not entitled to receive tax gross up payments on any payments or benefits he may receive under his agreement. Mr. Denault’s retention agreement was entered into in 2006 when he was Entergy Corporation’s Chief Financial Officer and was designed to reflect the competition for chief financial officer talent in the marketplace at that time and the Personnel Committee’s assessment of the critical role this position played in executing Entergy Corporation’s long-term financial and other strategic objectives. Based on the market data provided by its former independent compensation consultant, the committee, at the time the agreement was entered into, believed the benefits and payment levels under Mr. Denault’s retention agreement were consistent with market practices.

Mr. Bakken

In connection with the commencement of his employment, Entergy Corporation provided Mr. Bakken relocation assistance to facilitate his move to Jackson, Mississippi where Entergy Corporation’s nuclear fleet corporate headquarters is located. As part of that relocation assistance, Entergy Corporation agreed to provide Mr. Bakken with certain relocation benefits, including the purchase of Mr. Bakken’s house at a fixed price which the Personnel Committee

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determined was necessary to facilitate Mr. Bakken’s transition to Entergy Corporation and to mitigate the expenses associated with his relocation. The terms of Mr. Bakken’s employment, including the relocation assistance, were reviewed by the Personnel Committee, were determined based on competitive market data, and were designed to reflect the competition for chief nuclear officer talent in the marketplace and the committee’s assessment of the critical role this position plays in transforming the nuclear fleet and to encourage retention of his leadership in light of his marketability as a chief nuclear officer.

Mr. Ellis

In connection with the commencement of his employment as President, Entergy New Orleans, Mr. Ellis is eligible for certain relocation benefits pursuant to our Relocation Assistance Policy including assistance with moving expenses, transportation of household goods and assistance with the sale of his home. Mr. Ellis also received a sign-on bonus of $200,000 when he assumed this role. Mr. Ellis’s sign-on bonus and certain of his relocation benefits are subject to forfeiture under certain circumstances if Mr. Ellis’ employment is terminated within two years of the commencement of his employment.

Mr. Ellis is eligible to participate in our annual and long-term incentive plans at the same level as the other Chief Executive Officers of the Utility operating companies, except Mr. May. Mr. Ellis was not eligible to participate in the 2016-2018 performance period, but received pro-rated target award opportunities for the 2017- 2019 and 2018-2020 performance periods in January 2019, in accordance with the terms of the program. Mr. Ellis also participates in our Cash Balance Plan and our Cash Balance Equalization Plan, retirement plans that are available to all eligible executive officers hired on or after July 1, 2014. For more information about the Cash Balance Plan and our Cash Balance Equalization Plan, see “2018 Pension Benefits.” Beginning in 2019, Mr. Ellis also is eligible to participate in our annual stock option and restricted stock programs.

Mr. Riley

When Mr. Riley assumed the position of Senior Vice President, Distribution Operations and Asset Management, Entergy Services, LLC, he was required to relocate from Arkansas to Entergy Corporation’s corporate office in New Orleans. To facilitate the transition to this new role, Entergy Corporation provided Mr. Riley relocation assistance pursuant to our Relocation Assistance Policy, including assistance with moving expenses, transportation of household goods and assistance with the sale of his home.

Compensation Policies and 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 the members of the Office of the Chief Executive, and the other Named Executive Officers. Under the policy, which goes beyond the requirements of Sarbanes-Oxley Act of 2002 (Sarbanes-Oxley), the Personnel Committee will require reimbursement of incentives paid to these executive officers 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
•
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.

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The amount the Personnel Committee requires 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. Further, following a material restatement of Entergy Corporation’s financial statements, Entergy Corporation will seek to recover any compensation received by Entergy Corporation’s Chief Executive Officer and Chief Financial Officer that is required to be reimbursed under Sarbanes-Oxley.

Stock Ownership Guidelines and Share Retention Requirements

For many years, Entergy Corporation has had stock ownership guidelines for executives, including the Named Executive Officers. 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.

The ownership guidelines are as follows:

Role
Value of Common Stock to be Owned
Chief Executive Officer
6 times base salary
Executive Vice Presidents
3 times base salary
Senior Vice Presidents
2 times base salary
Vice Presidents
1 time 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 Long-Term Performance Unit Program;
•
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 and Anti-Pledging and Anti-Hedging Policies

Executive officers, including the Named Executive Officers, are required to receive the permission of Entergy Corporation’s General Counsel 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 immediately following the release of earnings. Employees, who are subject to trading restrictions, including the Named Executive Officers, 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. The Named Executive Officer bears full responsibility if he or she violates Entergy Corporation’s policy by permitting shares to be bought or sold without pre-approval or when trading is restricted.

Entergy Corporation also prohibits directors and executive officers, including the Named Executive Officers, 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. The Board adopted this policy to require officers, directors, and employees to continue to own Entergy Corporation stock with the full risks and rewards of ownership, thereby ensuring continued alignment of their objectives with those of Entergy Corporation’s other shareholders.


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How Entergy Corporation Makes Compensation Decisions

Role of the Personnel Committee
The Personnel Committee is responsible for overseeing the development and administration of the compensation and benefits policies and programs. The committee, which consists of three independent directors, is responsible for the review and approval of all aspects of the executive compensation programs. Among its duties, the Personnel Committee is responsible for formulating the compensation recommendations for Entergy Corporation’s Chief Executive Officer and approving all compensation recommendations for all members of the Office of Chief Executive, 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 Entergy Corporation’s officers’ total compensation package, 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 Board on succession planning.

The Personnel Committee is supported in its work by its independent compensation consultant and executive management to ensure that the compensation policies and practices are consistent with Entergy Corporation’s values and support the successful recruitment, development and retention of executive talent so that Entergy Corporation can achieve its business objectives and optimize its long-term financial returns.

Role of the Chief Executive Officer

Within the framework of the compensation programs approved by the Personnel Committee and competitive data, each year Entergy Corporation’s Chief Executive Officer makes recommendations with respect to compensation decisions for the members of the Office of the Chief Executive. Entergy Corporation’s Chief Executive Officer provides the Personnel Committee with an assessment of the performance of each of the other Named Executive Officers and recommends compensation levels to be awarded to each of them. In addition, the committee may request that the Chief Executive Officer provide management feedback and recommendations on changes in the design of the executive compensation programs, such as special retention plans or changes in incentive program structure. However, Entergy Corporation’s Chief Executive Officer does not play any role with respect to any matter affecting his own compensation, and is not present when the committee discusses and formulates his compensation. The Personnel Committee also relies on the recommendations of the most senior Human Resources’ officer with respect to compensation decisions, policies and practices.

Entergy Corporation’s Chief Executive Officer may attend meetings of the Personnel Committee only at the invitation of the chair of the Personnel Committee and cannot call a meeting of the committee. Since he is not a member of the committee, he has no vote on matters submitted to the committee. During 2018, Mr. Denault attended 6 meetings of the Personnel Committee.

Role of the Compensation Consultant

The Personnel Committee conducts an annual review of the compensation consultant, and in 2018, it retained Pay Governance LLC as its independent compensation consultant to assist it in, among other things, evaluating different compensation practices and programs and developing market data to assess Entergy Corporation’s compensation programs. Also in 2018, the Corporate Governance Committee retained Pay Governance to review and perform a competitive analysis of non-employee director compensation.


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During 2018, Pay Governance assisted the Personnel Committee with its responsibilities related to Entergy Corporation’s compensation programs for its executives. The committee directed Pay Governance to: (i) regularly attend meetings of the committee; (ii) conduct studies of competitive compensation practices; (iii) identify Entergy Corporation’s market surveys and proxy peer group; (iv) review base salary, annual incentives, and long-term incentive compensation opportunities relative to competitive practices; and (v) develop conclusions and recommendations related to the executive compensation programs for consideration by the committee. A senior consultant from Pay Governance attended all Personnel Committee meetings to which he was invited in 2018.

The Personnel Committee has the sole authority to hire the compensation consultant, approve its compensation, determine the nature and scope of its services evaluate its performance and terminate its engagement.

Compensation Consultant Independence

To maintain the independence of the Personnel Committee’s compensation consultant, the Board has adopted a policy that any consultant (including its affiliates) retained by the Board of Directors or any committee of the Board of Directors to provide advice or recommendations on the amount or form of executive or director compensation should not be retained by Entergy Corporation or any of its affiliates to provide other services in an aggregate amount that exceeds $120,000 in any year. Pay Governance did not provide any services to management in 2018.

Annually, the Personnel Committee reviews the relationship with its compensation consultant, including services provided, quality of those services, and fees associated with services in its evaluation of the compensation consultant’s independence. The committee also assesses Pay Governance’s independence under NYSE rules and has concluded that no conflicts of interest exist that would prevent Pay Governance from independently advising the Personnel Committee

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 Subsidiaries has a compensation committee or other board committee performing equivalent functions. The board of directors of each of the Subsidiaries is comprised of individuals who are officers or employees of Entergy Corporation or one of the Subsidiaries. These boards do not make determinations regarding the compensation paid to executive officers of the Subsidiaries.


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EXECUTIVE COMPENSATION TABLES

2018 Summary Compensation Tables

The following table summarizes the total compensation paid or earned by each of the Named Executive Officers for the fiscal year ended December 31, 2018, and to the extent required by SEC executive compensation disclosure rules, the fiscal years ended December 31, 2017 and 2016.  For information on the principal positions held by each of the Named Executive Officers, see Item 10, “Directors and Executive Officers 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)
 
 
 
 
 
 
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
Compens-ation 
 (8)
 
 
 
 
 
 
 
Total
 
A. Christopher Bakken, III
 
2018
 

$632,967

 

$181,500

 

$1,041,479

 

$283,095

 

$544,959

 

$108,700

 

$452,012

 

$3,244,712

Executive Vice President and
 
2017
 

$615,791

 

$181,500

 

$959,376

 

$245,904

 

$559,973

 

$33,000

 

$114,494

 

$2,710,038

Chief Nuclear Officer of Entergy Corp.
 
2016
 

$426,990

 

$650,000

 

$3,292,700

 

$—

 

$529,375

 

$27,900

 

$140,601

 

$5,067,566

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Marcus V. Brown
 
2018
 

$644,231

 

$—

 

$1,041,479

 

$283,095

 

$546,000

 

$371,800

 

$61,885

 

$2,948,490

Executive Vice President and
 
2017
 

$622,788

 

$—

 

$1,022,853

 

$287,760

 

$568,890

 

$1,217,200

 

$43,269

 

$3,762,760

General Counsel of Entergy Corp.

 
2016
 

$563,208

 

$—

 

$1,144,648

 

$333,000

 

$550,550

 

$934,600

 

$34,381

 

$3,560,387

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Leo P. Denault
 
2018
 

$1,251,346

 

$—

 

$4,744,977

 

$1,168,029

 

$2,041,200

 

$982,800

 

$138,104

 

$10,326,456

Chairman of the
 
2017
 

$1,221,346

 

$—

 

$4,676,190

 

$1,173,276

 

$2,142,045

 

$3,819,500

 

$125,863

 

$13,158,220

Board and CEO -
 
2016
 

$1,191,462

 

$—

 

$4,632,276

 

$1,235,800

 

$2,154,600

 

$4,166,800

 

$97,786

 

$13,478,724

Entergy Corp.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
David D. Ellis
 
2018
 

$7,258

 

$200,000

 

$—

 

$—

 

$—

 

$600

 

$35,308

 

$243,166

CEO - Entergy
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
New Orleans
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Haley R. Fisackerly
 
2018
 

$363,089

 

$—

 

$198,449

 

$46,134

 

$172,000

 

$—

 

$35,982

 

$815,654

CEO - Entergy
 
2017
 

$354,451

 

$—

 

$192,041

 

$49,704

 

$169,123

 

$406,300

 

$35,724

 

$1,207,343

Mississippi
 
2016
 

$320,067

 

$—

 

$229,752

 

$49,580

 

$168,000

 

$268,600

 

$34,243

 

$1,070,242

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


Laura R. Landreaux
 
2018
 

$246,136

 

$—

 

$273,062

 

$—

 

$124,000

 

$21,500

 

$10,741

 

$675,439

CEO - Entergy
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Arkansas
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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Table of Contents

(a)
 
(b)
 
(c)
 
(d)
 
(e)
 
(f)
 
(g)
 
(h)
 
(i)
 
(j)
 
 
 
 
 
 
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
Compens-ation 
 (8)
 
 
 
 
 
 
 
Total
 
Andrew S. Marsh
 
2018
 

$615,654

 

$—

 

$1,057,095

 

$342,510

 

$531,188

 

$—

 

$57,638

 

$2,604,085

Executive Vice
 
2017
 

$588,291

 

$—

 

$1,022,853

 

$287,760

 

$541,800

 

$801,900

 

$51,647

 

$3,294,251

President and CFO -
 
2016
 

$553,284

 

$—

 

$1,144,648

 

$333,000

 

$509,061

 

$593,700

 

$47,484

 

$3,181,177

Entergy Corp.,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Arkansas,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Louisiana,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Mississippi,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy New
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Orleans, Entergy
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Texas
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Phillip R. May, Jr.
 
2018
 

$377,108

 

$—

 

$288,238

 

$69,201

 

$270,000

 

$—

 

$26,874

 

$1,031,421

CEO - Entergy
 
2017
 

$363,410

 

$—

 

$302,493

 

$68,670

 

$300,000

 

$503,400

 

$26,981

 

$1,564,954

Louisiana
 
2016
 

$353,690

 

$—

 

$326,988

 

$71,040

 

$224,690

 

$600,000

 

$26,018

 

$1,602,426

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sallie T. Rainer
 
2018
 

$335,263

 

$—

 

$198,449

 

$46,134

 

$159,000

 

$—

 

$35,379

 

$774,225

CEO - Entergy
 
2017
 

$325,737

 

$—

 

$195,567

 

$51,012

 

$156,259

 

$435,900

 

$35,785

 

$1,200,260

Texas
 
2016
 

$316,003

 

$—

 

$229,752

 

$49,580

 

$153,348

 

$346,300

 

$53,797

 

$1,148,780

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Charles L. Rice, Jr.
 
2018
 

$272,519

 

$—

 

$182,833

 

$2,796

 

$—

 

$12,700

 

$28,886

 

$499,734

Former CEO -
 
2017
 

$284,681

 

$—

 

$170,882

 

$25,506

 

$91,000

 

$221,200

 

$30,842

 

$824,111

Entergy New Orleans
 
2016
 

$276,998

 

$—

 

$229,752

 

$49,580

 

$67,302

 

$177,600

 

$33,807

 

$835,039

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Richard C. Riley
 
2018
 

$355,187

 

$—

 

$342,772

 

$69,201

 

$225,000

 

$150,400

 

$163,463

 

$1,306,023

Former CEO -
 
2017
 

$341,723

 

$—

 

$202,620

 

$52,320

 

$280,661

 

$437,700

 

$38,695

 

$1,353,719

Entergy Arkansas
 
2016
 

$325,020

 

$—

 

$226,224

 

$34,780

 

$167,500

 

$277,900

 

$102,112

 

$1,133,536

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Roderick K. West
 
2018
 

$690,581

 

$—

 

$1,057,095

 

$297,075

 

$560,762

 

$—

 

$67,234

 

$2,672,747

Group President
 
2017
 

$670,876

 

$—

 

$818,316

 

$190,968

 

$610,065

 

$867,200

 

$52,220

 

$3,209,645

Utility Operations of
 
2016
 

$654,514

 

$—

 

$1,116,424

 

$303,400

 

$461,384

 

$601,000

 

$73,706

 

$3,210,428

Entergy Corp.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

(1)
Mr. Bakken was named Executive Vice President and Chief Nuclear Officer in April 2016. 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 Named Executive Officers in the applicable year.  Except as otherwise provided, the 2018 changes in base salaries noted in the Compensation Discussion and Analysis were effective in April 2018.
(3)
The amount in column (d) in 2018 and 2017 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 2016 for Mr. Bakken represents a cash sign-on bonus paid to Mr. Bakken in connection with his commencement of employment with Entergy Corporation. 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, performance units, and restricted stock units granted under the 2015 Equity Plan, each calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures.  The grant date fair value of the restricted stock and

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restricted stock units 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 will be received if the highest achievement level is attained with respect to both the total shareholder return and UP&O Adjusted EPS, for performance units granted in 2018 are as follows:  Mr. Bakken, $1,233,664; Mr. Brown, $1,233,664; Mr. Denault, $6,668,032; Mr. Fisackerly, $257,664; Ms. Landreaux $365,366; Mr. Marsh, $1,233,664; Mr. May, $398,208; Ms. Rainer, $257,664; Mr. Rice, $257,664; Mr. Riley, $505,072; and Mr. West, $1,233,664. The amount in 2016 for Mr. Bakken includes restricted stock units granted to him in connection with his commencement of employment as Chief Nuclear Officer.
(5)
The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the 2015 Equity Plan 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 cash payments made under the Annual Incentive Plan.
(7)
For all Named Executive Officers, the amounts in column (h) include the annual actuarial increase in the present value of these Named Executive Officers’ 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 Named Executive Officers may not currently be entitled to receive because such amounts are not vested (see “2018 Pension Benefits”).  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. None of the increases for any of the Named Executive Officers is attributable to above-market or preferential earnings on non-qualified deferred compensation (see “2018 Non-qualified Deferred Compensation”).
(8)
The amounts in column (i) for 2018 include (a) matching contributions by Entergy Corporation under the Savings Plan to each of the Named Executive Officers; (b) dividends paid on restricted stock when vested; (c) life insurance premiums; (d) tax gross up payments on club dues and relocation expenses; 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

$16,500


$6,028


$11,919


$1,235


$416,330


$452,012

Marcus V. Brown

$11,550


$41,159


$7,482


$—


$1,694


$61,885

Leo P. Denault

$11,550


$102,475


$7,482


$—


$16,597


$138,104

David D. Ellis

$—


$—


$—


$8,078


$27,230


$35,308

Haley R. Fisackerly

$11,550


$6,857


$2,370


$4,145


$11,060


$35,982

Laura R. Landreaux

$—


$6,947


$359


$1,073


$2,362


$10,741

Andrew S. Marsh

$11,550


$41,159


$4,929


$—


$—


$57,638

Phillip R. May, Jr.

$11,550


$7,860


$5,596


$—


$1,868


$26,874

Sallie T. Rainer

$11,550


$6,550


$6,677


$2,753


$7,849


$35,379

Charles L. Rice, Jr.

$11,446


$6,158


$4,447


$1,714


$5,121


$28,886

Richard C. Riley

$11,550


$7,859


$5,364


$16,885


$121,805


$163,463

Roderick K. West

$11,550


$35,795


$4,002


$—


$15,887


$67,234





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Perquisites and Other Compensation

The amounts set forth in column (i) also include perquisites and other personal benefits that Entergy Corporation provides to its Named Executive Officers as part of providing a competitive executive compensation programs and for employee retention. The following perquisites were provided to the Named Executive Officers in 2018.
Named Executive Officer
Relocation
Personal Use of Corporate Aircraft
Club Dues
Executive Physical Exams
Event Tickets
A. Christopher Bakken, III
X
X
 
X
 
Marcus V. Brown
 
 
 
X
 
Leo P. Denault
 
X
 
X
X
David D. Ellis
X
 
 
 
 
Haley R. Fisackerly
 
 
X
X
 
Laura R. Landreaux
 
 
X
 
 
Andrew S. Marsh
 
 
 
X
 
Phillip R. May, Jr.
 
 
 
 
X
Sallie T. Rainer
 
 
X
 
 
Charles L. Rice, Jr.
 
 
X
X
 
Richard C. Riley
X
 
X
 
 
Roderick K. West
 
X
 
X
 

For security and business reasons, Entergy Corporation’s Chief Executive Officer is permitted to use its corporate aircraft for personal use at the expense of Entergy Corporation.  The other Named Executive Officers 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. In addition, Entergy Corporation offers its executives comprehensive annual physical exams at Entergy Corporation’s expense. Tickets to cultural and sporting events are purchased for business purposes, and if not utilized for business purposes, the tickets are made available to the employees, including the Named Executive Officers, for personal use.

Entergy Corporation also provides relocation benefits to a broad base of employees which include assistance with moving expenses, transportation of household goods and in certain circumstances, assistance with the sale of the employee’s home. In connection with employment, and in accordance with its relocation policies, Entergy Corporation paid $27,230 and $114,928 in relocation expense for Messrs. Ellis and Riley, respectively, in 2018. The relocation assistance amounts reported above represent the amount paid to Entergy’s relocation service provider or Messrs. Ellis or Riley, as applicable. Certain of Mr. Ellis’s relocation benefits are subject to forfeiture if Mr. Ellis terminates his service prior to the two year anniversary of his date of hire. In connection with his employment and as an inducement for Mr. Bakken to join Entergy Corporation and relocate to Jackson, Mississippi, and in accordance with its relocation policies and pursuant to certain additional relocation benefits, Entergy Corporation agreed to purchase Mr. Bakken’s home at a fixed price. In 2018, Entergy Corporation sold the purchased property. The amount reported in this column above includes $400,074 from the loss on the sale of Mr. Bakken’s home, which was calculated based on the agreed upon price Entergy Corporation paid for the home as compared to the price Entergy Corporation received upon disposition.

None of the other perquisites referenced above exceeded $25,000 for any of the other Named Executive Officers.
 

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Table of Contents

2018 Grants of Plan-Based Awards

The following table summarizes award grants during 2018 to the Named Executive Officers.
 
 
 
 
Estimated Future 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
 
1/25/18
 
$-
$446,688
$893,376
 
 
 
 
 
 
 
 
 
 
 
 
Bakken, III
 
1/25/18
 
 
 
 
 
1,975

7,900

15,800

 
 
 
 
 
 
 
$651,079
 
 
1/25/18
 
 
 
 
 


 


 
5,000

 
 
 
 
 
$390,400
 
 
1/25/18
 
 
 
 
 
 
 
 
 
 
 
40,500

 
$78.08
 
$283,095
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Marcus V.
 
1/25/18
 
$-
$455,000
$910,000
 
 
 
 
 
 
 
 
 
 
 
 
Brown
 
1/25/18
 
 
 
 
 
1,975

7,900

15,800

 
 
 
 
 
 
 
$651,079
 
 
1/25/18
 
 
 
 
 
 
 
 
 
5,000

 
 
 
 
 
$390,400
 
 
1/25/18
 
 
 
 
 
 
 
 
 
 
 
40,500

 
$78.08
 
$283,095
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Leo P.
 
1/25/18
 
$-
$1,701,000
$3,402,000
 
 
 
 
 
 
 
 
 
 
 
 
Denault
 
1/25/18
 
 
 
 
 
10,675

42,700

85,400

 
 
 
 
 
 
 
$3,519,121
 
 
1/25/18
 
 
 
 
 
 
 
 
 
15,700

 
 
 
 
 
$1,225,856
 
 
1/25/18
 
 
 
 
 
 
 
 
 
 
 
167,100

 
$78.08
 
$1,168,029
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Haley R.
 
1/25/18
 
$-
$146,384
$292,768
 
 
 
 
 
 
 
 

 
 
 
 
Fisackerly
 
1/25/18
 
 
 
 
 
413

1,650

3,300

 
 
 
 
 
 
 
$135,985
 
 
1/25/18
 
 
 
 
 
 
 
 
 
800

 
 
 
 
 
$62,464
 
 
1/25/18
 
 
 
 
 
 
 
 
 
 
 
6,600

 
$78.08
 
$46,134
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Laura R.
 
1/25/18
 
$-
$123,200
$246,400
 

 
 
 
 
 
 
 
 
 
 
Landreaux (6)
 
7/1/18
 
 
 
 
 
344

1,375

2,750

 
 
 
 
 
 
 
$113,321
 
 
7/1/18
 
 
 
 
 
231

925

1,850

 
 
 
 
 
 
 
$66,045
 
 
1/25/18
 
 
 
 
 
 
 
 
 
1,200

 
 
 

 
$93,696
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Andrew S.
 
1/25/18
 
$-
$435,400
$870,800
 
 
 
 
 
 
 
 
 
 
 
 
Marsh
 
1/25/18
 
 
 
 
 
1,975

7,900

15,800

 
 
 
 
 
 
 
$651,079
 
 
1/25/18
 
 
 
 
 
 
 
 
 
5,200

 
 
 
 
 
$406,016
 
 
1/25/18
 
 
 
 
 
 
 
 
 
 
 
49,000

 
$78.08
 
$342,510
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Phillip R.
 
1/25/18
 
$-
$228,930
$457,860
 
 
 
 
 
 
 
 
 
 
 
 
May, Jr.
 
1/25/18
 
 
 
 
 
638

2,550

5,100

 
 
 
 
 
 
 
$210,158
 
 
1/25/18
 
 
 
 
 
 
 
 
 
1,000

 
 
 
 
 
$78,080
 
 
1/25/18
 
 
 
 
 
 
 
 
 
 
 
9,900

 
$78.08
 
$69,201

 

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Estimated Future 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)
Sallie T.
 
1/25/18
 
$-
$135,249
$270,498
 
 
 
 
 
 

 
 

 
 
 
 
Rainer
 
1/25/18
 
 
 
 
 
413

1,650

3,300

 
 
 
 
 
 
 
$135,985
 
 
1/25/18
 
 
 
 
 
 
 
 
 
800

 
 
 
 
 
$62,464
 
 
1/25/18
 
 
 
 
 
 
 
 
 
 
 
6,600

 
$78.08
 
$46,134
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Charles L.
 
1/25/18
 
$-
$69,000
$138,000
 
 
 
 
 
 
 
 
 
 
 
 
Rice, Jr.(6)
 
1/25/18
 
 
 
 
 
413

1,650

3,300

 
 
 
 
 
 
 
$135,985
 
 
1/25/18
 
 
 
 
 
 
 
 
 
600

 
 
 
 
 
$46,848
 
 
1/25/18
 
 
 
 
 
 
 
 
 
 
 
400

 
$78.08
 
$2,796
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Richard C.
 
1/25/18
 
$-
$225,000
$450,000
 
 
 
 
 
 
 
 
 
 
 
 
Riley(6)
 
1/25/18
 
 
 
 
 
600

2,400

4,800

 
 
 
 
 
 
 
$197,796
 
 
7/1/18
 
 
 
 
 
163

650

1,300

 
 
 
 
 
 
 
$46,410
 
 
7/1/18
 
 
 
 
 
38

150

300

 
 
 
 
 
 
 
$12,678
 
 
1/25/18
 
 
 
 
 
 
 
 
 
1,100

 
 
 
 
 
$85,888
 
 
1/25/18
 
 
 
 
 
 
 
 
 
 
 
9,900

 
$78.08
 
$69,201
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Roderick K.
 
1/25/18
 
$-
$487,619
$975,238
 
 
 
 
 
 
 
 
 
 
 
 
West
 
1/25/18
 
 
 
 
 
1,975

7,900

15,800

 
 
 
 
 
 
 
$651,079
 
 
1/25/18
 
 
 
 
 
 
 
 
 
5,200

 
 
 
 
 
$406,016
 
 
1/25/18
 
 
 
 
 
 
 
 
 
 
 
42,500

 
$78.08
 
$297,075

(1)
The amounts in columns (c), (d), and (e) represent minimum, target, and maximum payment levels under the Annual Incentive Plan.  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 Long-Term Performance Unit Program.  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 UP&O Adjusted EPS with each performance measure weighted equally. 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 UP&O 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, 2020.)  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 2015 Equity Plan.  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 2015 Equity Plan.

480
Table of Contents

(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 2018 Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value.
(6)
Ms. Landreaux’s and Messrs. Rice’s and Riley’s awards were modified in connection with their changes in position.

2018 Outstanding Equity Awards at Fiscal Year-End

The following table summarizes, for each Named Executive Officer, unexercised options, restricted stock that has not vested, and equity incentive plan awards outstanding as of December 31, 2018.

 
 
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
 
—

 
40,500(1)

 
 
 
$78.08
 
1/25/2028
 
 
 
 
 
 
 
 
 
 
12,533

 
25,067(2)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15,800(4)
 
$1,359,906
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
16,600(5)
 
$1,428,762
 
 
 
 
 
 
 
 
 
 
 
 
5,000(6)
 
$430,350
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,467(9)
 
$298,405
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
30,000(10)
 
$2,582,100
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Marcus V. Brown
 
—

 
40,500(1)

 
 
 
$78.08
 
1/25/2028
 
 
 
 
 
 
 
 
 
 
14,666

 
29,334(2)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
20,000

 
15,000(3)

 
 
 
$70.56
 
1/28/2026
 
 
 
 
 
 
 
 
 
 
24,000

 
—

 
 
 
$89.90
 
1/29/2025
 
 
 
 
 
 
 
 
 
 
20,500

 
—

 
 
 
$63.17
 
1/30/2024
 
 
 
 
 
 
 
 
 
 
10,800

 
—

 
 
 
$64.60
 
1/31/2023
 
 
 
 
 
 
 
 
 
 
4,600

 
—

 
 
 
$71.30
 
1/26/2022
 
 
 
 
 
 
 
 
 
 
2,800

 
—

 
 
 
$72.79
 
1/27/2021
 
 
 
 
 
 
 
 
 
 
4,500

 
—

 
 
 
$77.10
 
1/28/2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15,800(4)
 
$1,359,906
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
16,600(5)
 
$1,428,762
 
 
 
 
 
 
 
 
 
 
 
 
5,000(6)
 
$430,350
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,067(7)
 
$350,047
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,134(8)
 
$183,673
 
 
 
 

481
Table of Contents

 
 
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
 
—

 
167,710(1)

 
 
 
$78.08
 
1/25/2028
 
 
 
 
 
 
 
 
 
 
59,800

 
119,600(2)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
111,333

 
55,667(3)

 
 
 
$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
 
 
 
 
 
 
 
 
 
 
30,000

 
—

 
 
 
$71.30
 
1/26/2022
 
 
 
 
 
 
 
 
 
 
25,000

 
—

 
 
 
$72.79
 
1/27/2021
 
 
 
 
 
 
 
 
 
 
50,000

 
—

 
 
 
$77.10
 
1/28/2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
85,400(4)
 
$7,350,378
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
97,400(5)
 
$8,383,218
 
 
 
 
 
 
 
 
 
 
 
 
15,700(6)
 
$1,351,299
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
11,334(7)
 
$975,517
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5,234(8)
 
$450,490
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Haley R. Fisackerly
 
—

 
6,600(1)

 
 
 
$78.08
 
1/25/2028
 
 
 
 
 
 
 
 
 
 
—

 
5,067(2)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
2,233

 
2,234(3)

 
 
 
$70.56
 
1/28/2026
 
 
 
 
 
 
 
 
 
 
4,500

 
—

 
 
 
$89.90
 
1/29/2025
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,300(4)
 
$284,031
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,700(5)
 
$318,459
 
 
 
 
 
 
 
 
 
 
 
 
800(6)
 
$68,856
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
567(7)
 
$48,802
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
367(8)
 
$31,588
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Laura R. Landreaux
 
 
 
 
 
 
 
 
 
 
 
1,200(6)
 
$103,284
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,000(7)
 
$86,070
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
467(8)
 
$40,195
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,750(4)
 
$236,693
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,850(5)
 
$159,230






482
Table of Contents

 
 
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
 
 
(#)
 
(#)
 
(#)
 
($)
 
 
 
(#)
 
($)
 
(#)
 
($)
Andrew S. Marsh
 
—

 
49,000(1)

 
 
 
$78.08
 
1/25/2028
 
 
 
 
 
 
 
 
 
 
14,666

 
29,334(2)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
30,000

 
15,000(3)

 
 
 
$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
 
 
 
 
 
 
 
 
 
 
9,100

 
—

 
 
 
$77.10
 
1/28/2020
 
 
 
 
 
 
 
 
 
 
8,000

 
—

 
 
 
$77.53
 
1/29/2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15,800(4)
 
$1,359,906
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
16,600(5)
 
$1,428,762
 
 
 
 
 
 
 
 
 
 
 
 
5,200(6)
 
$447,564
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,067(7)
 
$350,047
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,134(8)
 
$183,673
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
21,100(9)
 
$1,816,077
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Phillip R. May, Jr.
 
—

 
9,900(1)

 
 
 
$78.08
 
1/25/2028
 
 
 
 
 
 
 
 
 
 
500

 
7,000(2)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
3,400

 
3,200(3)

 
 
 
$70.56
 
1/28/2026
 
 
 
 
 
 
 
 
 
 
5,000

 
—

 
 
 
$89.90
 
1/29/2025
 
 
 
 
 
 
 
 
 
 
2,000

 
—

 
 
 
$63.17
 
1/30/2024
 
 
 
 
 
 
 
 
 
 
2,000

 
—

 
 
 
$64.60
 
1/31/2023
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5,100(4)
 
$438,957
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6,300(5)
 
$542,241
 
 
 
 
 
 
 
 
 
 
 
 
1,000(6)
 
$86,070
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
734(7)
 
$63,175
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
467(8)
 
$40,195
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sallie T. Rainer
 
—

 
6,600(1)

 
 
 
$78.08
 
1/25/2028
 
 
 
 
 
 
 
 
 
 
2,600

 
5,200(2)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
2,233

 
2,234(3)

 
 
 
$70.56
 
1/28/2026
 
 
 
 
 
 
 
 
 
 
3,800

 
—

 
 
 
$89.90
 
1/29/2025
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,300(4)
 
$284,031
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,700(5)
 
$318,459

483
Table of Contents

 
 
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
 
 
(#)
 
(#)
 
(#)
 
($)
 
 
 
(#)
 
($)
 
(#)
 
($)
 
 
 
 
 
 
 
 
 
 
 
 
800(6)
 
$68,856
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
600(7)
 
$51,642
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
367(8)
 
$31,588
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Charles L. Rice, Jr.
 
—

 
400(1)

 
 
 
$78.08
 
1/25/2028
 
 
 
 
 
 
 
 
 
 
—

 
2,600(2)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
—

 
2,234(3)

 
 
 
$70.56
 
1/28/2026
 
 
 
 
 
 
 
 
 
 
4,500

 
—

 
 
 
$89.90
 
1/29/2025
 
 
 
 
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
642(4)
 
$55,257
 
 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
1,952(5)
 
$168,009
 
 
 

 
 

 
 
 
 
 
 
 
600(6)
 
$51,642
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
367(7)
 
$31,588
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
367(8)
 
$31,588
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Richard C. Riley
 
—

 
9,900(1)

 
 
 
$78.08
 
1/25/2028
 
 
 
 
 
 
 
 
 
 
2,666

 
5,334(2)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
1,633

 
1,567(3)

 
 
 
$70.56
 
1/28/2026
 
 
 
 
 
 
 
 
 
 
4,500

 
—

 
 
 
$89.90
 
1/29/2025
 
 
 
 
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
4,800(4)
 
$413,136
 
 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
5,000(5)
 
$430,350
 
 
 

 
 

 
 
 
 
 
 
 
1,100(6)
 
$94,677
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
667(7)
 
$57,409
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
350(8)
 
$30,125
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Roderick K. West
 
—

 
42,500(1)

 
 
 
$78.08
 
1/25/2028
 
 
 
 
 
 
 
 
 
 
—

 
19,467(2)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
—

 
13,666(3)

 
 
 
$70.56
 
1/28/2026
 
 
 
 
 
 
 
 
 
 
23,000

 
—

 
 
 
$89.90
 
1/29/2025
 
 
 
 
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
15,800(4)
 
$1,359,906
 
 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
16,600(5)
 
$1,428,762
 
 
 

 
 

 
 
 
 
 
 
 
5,200(6)
 
$447,564
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
2,134(7)
 
$183,673
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
2,000(8)
 
$172,140
 
 
 
 


484
Table of Contents

(1)
Consists of options granted under the 2015 Equity Plan that vested or will vest as follows: 1/3 of the options granted vest on each of January 25, 2019, January 25, 2020 and January 25, 2021.
(2)
Consists of options granted under the 2015 Equity Plan that vested or will vest as follows: 1/2 of the remaining unexercisable options vest on each of January 26, 2019 and January 26, 2020.
(3)
Consists of options granted under the 2015 Equity Plan that vested on January 28, 2019.
(4)
Consists of performance units granted under the 2015 Equity Plan that will vest on December 31, 2020 based on two performance measures: 1) Entergy Corporation’s total shareholder return performance over the 2018-2020 performance period and 2) UP&O Adjusted EPS with each performance measure weighted equally, as described under “What Entergy Corporation Pays and Why - Executive Compensation Elements - Variable Compensation - Long-Term Incentive Compensation - Performance Unit Program” in the Compensation Discussion and Analysis.
(5)
Consists of performance units granted under the 2015 Equity Plan that will vest on December 31, 2019 based on Entergy Corporation’s total shareholder return performance over the 2017-2019 performance period.
(6)
Consists of shares of restricted stock granted under the 2015 Equity Plan that vested or will vest as follows:  1/3 of the shares of restricted stock granted vest on each of January 25, 2019, January 25, 2020, and January 25, 2021.
(7)
Consists of shares of restricted stock granted under the 2015 Equity Plan that vested or will vest as follows:  1/2 of the shares of restricted stock granted vest on each of January 26, 2019 and January 26, 2020.
(8)
Consists of shares of restricted stock granted under the 2015 Equity Plan that vested on January 28, 2019.
(9)
Consists of restricted stock units granted under the 2015 Equity Plan which will vest on August 3, 2020.
(10)
Consists of restricted stock units granted under the 2015 Equity Plan which will vest one third on April 6, 2019, April 6, 2022, and April 6, 2025.

2018 Option Exercises and Stock Vested

The following table provides information concerning each exercise of stock options and each vesting of stock during 2018 for the Named Executive Officers.
 
 
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
 
—

 

$—

 
10,808

 

$915,803

 
 
 
 
 
 
 
 
 
Marcus V. Brown
 
28,200

 

$633,480

 
16,579

 

$1,370,815

 
 
 
 
 
 
 
 
 
Leo P. Denault
 
45,000

 

$402,179

 
68,161

 

$5,723,234

 
 
 
 
 
 
 
 
 
Haley R. Fisackerly
 
15,200

 

$214,488

 
3,264

 

$271,822

 
 
 
 
 
 
 
 
 
Laura R. Landreaux
 
—

 

$—

 
1,224

 

$94,802

 
 
 
 
 
 
 
 
 
Andrew S. Marsh
 
—

 

$—

 
16,579

 

$1,370,815

 
 
 
 
 
 
 
 
 
Phillip R. May, Jr.
 
34,200

 

$500,989

 
4,581

 

$383,446

 
 
 
 
 
 
 
 
 
Sallie T. Rainer
 
6,233

 

$135,404

 
3,242

 

$270,157

 
 
 
 
 
 
 
 
 
Charles L. Rice, Jr.
 
5,766

 

$70,011

 
2,773

 

$230,753

 
 
 
 
 
 
 
 
 
Richard C. Riley
 
8,168

 

$169,477

 
3,563

 

$296,435

 
 
 
 
 
 
 
 
 
Roderick K. West
 
91,066

 

$1,379,491

 
36,310

 
$2,977,673(2)


(1)
Represents the value of performance units for the 2016-2018 performance period (payable solely in shares based on the closing stock price of Entergy Corporation on the date of vesting) under the Performance Unit Program and the vesting of shares of restricted stock in 2018.

485
Table of Contents

(2)
Includes the May 1, 2018 cash settlement of 21,000 restricted stock units granted under the 2011 Equity Ownership Plan.

2018 Pension Benefits

The following table shows the present value as of December 31, 2018, of accumulated benefits payable to each of the Named Executive Officers, including the number of years of service credited to each Named Executive Officer, 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 2018
A. Christopher Bakken, III
 
Cash Balance Equalization Plan
 
2.74

 

$121,600

 

$—

 
 
Cash Balance Plan
 
2.74

 

$48,000

 

$—

 
 
 
 
 
 
 
 
 
Marcus V. Brown(1)
 
System Executive Retirement Plan
 
23.74

 

$5,189,800

 

$—

 
 
Entergy Retirement Plan
 
23.74

 

$883,300

 

$—

 
 
 
 
 
 
 
 
 
Leo P. Denault (1)(2)
 
System Executive Retirement Plan
 
34.83

 

$23,059,200

 

$—

 
 
Entergy Retirement Plan
 
19.83

 

$797,900

 

$—

 
 
 
 
 
 
 
 
 
David D. Ellis
 
Cash Balance Equalization Plan
 
0.06

 

$—

 

$—

 
 
Cash Balance Plan
 
0.06

 

$600

 

$—

 
 
 
 
 
 
 
 
 
Haley R. Fisackerly
 
System Executive Retirement Plan
 
23.08

 

$1,355,000

 

$—

 
 
Entergy Retirement Plan
 
23.08

 

$752,200

 

$—

 
 
 
 
 
 
 
 
 
Laura R. Landreaux
 
Pension Equalization Plan
 
11.48

 

$23,200

 

$—

 
 
Entergy Retirement Plan
 
11.48

 

$253,100

 

$—

 
 
 
 
 
 
 
 
 
Andrew S. Marsh
 
System Executive Retirement Plan
 
20.37

 

$3,376,500

 

$—

 
 
Entergy Retirement Plan
 
20.37

 

$502,600

 

$—

 
 
 
 
 
 
 
 
 
Phillip R. May, Jr. (1)
 
System Executive Retirement Plan
 
32.56

 

$2,450,400

 

$—

 
 
Entergy Retirement Plan
 
32.56

 

$1,175,100

 

$—

 
 
 
 
 
 
 
 
 
Sallie T. Rainer (1)(3)
 
System Executive Retirement Plan
 
34.38

 

$1,301,300

 

$—

 
 
Entergy Retirement Plan
 
34.00

 

$1,359,200

 

$—

 
 
 
 
 
 
 
 
 
Charles L. Rice, Jr.(5)
 
System Executive Retirement Plan
 
9.10

 

$614,600

 

$—

 
 
Entergy Retirement Plan
 
9.47

 

$315,000

 

$—

 
 
 
 
 
 
 
 
 
Richard C. Riley (1)(4)
 
System Executive Retirement Plan
 
29.01

 

$1,867,500

 

$—

 
 
Entergy Retirement Plan
 
23.55

 

$837,100

 

$—

 
 
 
 
 
 
 
 
 
Roderick K. West
 
System Executive Retirement Plan
 
19.75

 

$4,523,600

 

$—

 
 
Entergy Retirement Plan
 
19.75

 

$557,400

 

$—


(1)
As of December 31, 2018, Mr. Brown, Mr. Denault, Mr. May, Ms. Rainer, and Mr. Riley were retirement eligible.
(2)
In 2006, Mr. Denault entered into a retention agreement granting him an additional 15 years of service and permission to retire under the non-qualified System Executive Retirement Plan 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 the additional

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15 years of service under the non-qualified System Executive Retirement Plan only if his Entergy employer grants him permission to retire. The additional 15 years of service increases the present value of his benefit by $3,742,900.
(3)
Service under the non-qualified System Executive Retirement Plan is granted from the date of hire. Qualified plan benefit service is granted from the later of the date of hire or the plan participation date.
(4)
Mr. Riley separated from Entergy Corporation and was subsequently rehired in June 1995. The Entergy Retirement Plan does not include any credit service prior to his rehire date; however, the System Executive Retirement Plan reflects a net credited service date of December 28, 1989.
(5)
Mr. Rice’s benefit accruals in the System Executive Retirement Plan ceased with his change in position. He continues to accrue benefits under the Entergy Retirement Plan and the Pension Equalization Plan.
The tables below contain summaries of the pension benefit plans sponsored by Entergy Corporation that the Named Executive Officers participated in during 2018. Benefits for the Named Executive Officers 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
Charles L. Rice, Jr.
Richard C. Riley
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
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.

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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%.
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 Named Executive Officers are eligible to participate in certain non-qualified retirement benefit plans that provide retirement income, including the Pension Equalization Plan, the Cash Balance Equalization Plan, and the System Executive Retirement Plan. 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 Pension Equalization Plan and the System Executive Retirement Plan 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.

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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
Charles L. Rice, Jr.
Richard C. Riley
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
Charles L. Rice, Jr.
Richard C. Riley
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
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 Internal Revenue Code limitations on pension benefits and earnings that may be considered in calculating tax-qualified pension benefits, and (2) the amount actually payable 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 Internal Revenue 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 Code Section 409A.
Payable upon separation from service subject to 6 month delay required under 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.

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(2)
Benefits accrued under the System Executive Retirement Plan, Pension Equalization Plan, 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 System Executive Retirement Plan was closed to new executive officers effective July 1, 2014.

2018 Non-qualified Deferred Compensation

As of December 31, 2018, Mr. May had a deferred account balance under a frozen Defined Contribution Restoration Plan.  The amount is deemed invested, as chosen by the participant, 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 2018
 
Registrant Contributions in 2018
 
Aggregate Earnings in 2018(1)
 
Aggregate Withdrawals/Distributions
 
Aggregate Balance at December 31, 2018
(a)
 
(b)
 
(c)
 
(d)
 
(e)
 
(f)
 
 
 
 
 
 
 
 
 
 
 
Phillip R. May, Jr.
 

$—

 

$—

 

$69

 

$—

 

$2,182


(1)
Amounts in this column are not included in the Summary Compensation Table.

2018 Potential Payments Upon Termination or Change in Control

Entergy Corporation has plans and other arrangements that provide compensation to a Named Executive Officer 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 Named Executive Officers solely upon a change in control.

In the event of a Qualifying Termination, executive officers, including the Named Executive Officers, 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 Plan for the two calendar years immediately preceding the calendar year in which termination occurs.
Performance Units
Participants will forfeit outstanding performance units, and in lieu of any payment for any outstanding performance period, will 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.
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 Equity Ownership Plan.
Retirement Benefits
Benefits already accrued under the System Executive Retirement Plan, Pension Equalization Plan 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 Plan or his or her annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan 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) 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)

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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) an Entergy employer purports to terminate his employment 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 Named Executive Officers, 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 vest on the retirement date 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 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
*
If an officer resigns after the completion of an Annual Incentive Plan, he or she may receive, at the Company’s discretion, an annual incentive payment.
**
If an officer resigns after the completion of a Long-Term Performance Unit Program performance period, he or she may receive a payout under the Long-Term Performance Unit Program based on the outcome of the performance period.


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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 Named Executive Officers would have received if his or her employment had been terminated as of December 31, 2018 under the various scenarios described above. For purposes of these tables, a stock price of $86.07 was used, which was the closing market price on December 31, 2018, the last trading day of the year.


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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
—

—

—

—

—

—


$3,254,438

Performance Units(3)
—

—

—

—


$702,847


$702,847


$1,127,518

Stock Options
—

—

—

—


$713,136


$713,136


$713,136

Restricted Stock
—

—

—

—


$775,045


$775,045


$775,045

Welfare Benefits(5)
—

—

—

—

—

—


$22,248

Unvested Restricted Stock Units(7)
—

—


$860,700

—


$860,700


$860,700


$2,582,100

 
 
 
 
 
 
 
 
Marcus V. Brown(2)
 
 
 
 
 
 
 
Severance Payment
—

—

—

—

—

—


$3,315,000

Performance Units(3)
—

—

—


$702,847


$702,847


$702,847


$1,127,518

Stock Options
—

—

—


$1,012,080


$1,012,080


$1,012,080


$1,012,080

Restricted Stock
—

—

—

—


$1,041,237


$1,041,237


$1,041,237

Welfare Benefits(6)
—

—

—

—

—

—

—

 
 
 
 
 
 
 
 
Leo P. Denault(2)
 
 
 
 
 
 
 
Severance Payment
—

—

—

—

—

—


$10,172,115

Performance Units(3)(4)
—

—


$3,145,859


$4,019,469


$4,019,469


$4,019,469


$5,697,834

Stock Options
—

—


$4,057,108


$4,057,108


$4,057,108


$4,057,108


$4,057,108

Restricted Stock
—

—


$2,990,370

—


$2,990,370


$2,990,370


$2,990,370

Welfare Benefits(6)
—

—

—

—

—

—

—

 
 
 
 
 
 
 
 
David D. Ellis(1)
 
 
 
 
 
 
 
Severance Payment
—

—

—

—

—

—


$305,000

Performance Units(3)
—

—

—

—

—

—

—

Stock Options
—

—

—

—

—

—

—

Restricted Stock
—

—

—

—

—

—

—

Welfare Benefits(5)
—

—

—

—

—

—


$19,908

 
 
 
 
 
 
 
 
Haley R. Fisackerly(1)
 
 
 
 
 
 
 
Severance Payment
—

—

—

—

—

—


$512,343

Performance Units(3)
—

—

—

—


$153,463


$153,463


$249,604

Stock Options
—

—

—

—


$166,109


$166,109


$166,109

Restricted Stock
—

—

—

—


$161,250


$161,250


$161,250

Welfare Benefits(5)
—

—

—

—

—

—


$19,908

 
 
 
 
 
 
 
 
Laura R. Landreaux(1)
 
 
 
 
 
 
 
Severance Payment
—

—

—

—

—

—


$392,700

Performance Units(3)(4)
—

—

—

—


$92,525


$92,525


$249,604

Stock Options
—

—

—

—

—

—

—

Restricted Stock
—

—

—

—


$247,702


$247,702


$247,702

Welfare Benefits(5)
—

—

—

—

—

—


$19,908


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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
—

—

—

—

—

—


$3,172,200

Performance Units(3)
—

—

—

—


$702,847


$702,847


$1,127,518

Stock Options
—

—

—

—


$1,079,995


$1,079,995


$1,079,995

Restricted Stock
—

—

—

—


$1,059,217


$1,059,217


$1,059,217

Welfare Benefits(5)
—

—

—

—

—

—


$29,862

Unvested Restricted Stock Units(8)
—

—

—

—


$1,816,077


$1,816,077


$1,816,077

 
 
 
 
 
 
 
 
Phillip R. May, Jr.(2)
 
 
 
 
 
 
 
Severance Payment
—

—

—

—

—

—


$1,220,960

Performance Units(3)
—

—

—


$253,907


$253,907


$253,907


$352,888

Stock Options
—

—

—


$237,513


$237,513


$237,513


$237,513

Restricted Stock
—

—

—

—


$204,746


$204,746


$204,746

Welfare Benefits(6)
—

—

—

—

—

—

—

 
 
 
 
 
 
 
 
Sallie T. Rainer(2)
 
 
 
 
 
 
 
Severance Payment
—

—

—

—

—

—


$473,373

Performance Units(3)
—

—

—


$153,463


$153,463


$153,463


$249,604

Stock Options
—

—

—


$168,176


$168,176


$168,176


$168,176

Restricted Stock
—

—

—

—


$164,349


$164,349


$164,349

Welfare Benefits(6)
—

—

—

—

—

—

—

 
 
 
 
 
 
 
 
Charles R. Rice, Jr(1)
 
 
 
 
 
 
 
Severance Payment
—

—

—

—

—

—

—

Performance Units(3)
—

—

—

—


$65,241


$65,241

—

Stock Options
—

—

—

—


$78,234


$78,234

—

Restricted Stock
—

—

—

—


$124,490


$124,490

—

Welfare Benefits(5)
—

—

—

—

—

—

—

 
 
 
 
 
 
 
 
Richard C. Riley(2)
 
 
 
 
 
 
 
Severance Payment
—

—

—

—

—

—


$1,050,000

Performance Units(3)
—

—

—


$212,335


$212,335


$212,335


$352,888

Stock Options
—

—

—


$186,280


$186,280


$186,280


$186,280

Restricted Stock
—

—

—

—


$195,937


$195,937


$195,937

Welfare Benefits(6)
—

—

—

—

—

—

—

 
 
 
 
 
 
 
 
Roderick K. West(1)
 
 
 
 
 
 
 
Severance Payment
—

—

—

—

—

—


$3,552,650

Performance Units(3)
—

—

—

—


$702,847


$702,847


$1,127,518

Stock Options
—

—

—

—


$854,067


$854,067


$854,067

Restricted Stock
—

—

—

—


$864,531


$864,531


$864,531

Welfare Benefits(5)
—

—

—

—

—

—


$29,862


1)
See “2018 Pension Benefits” for a description of the pension benefits Mr. Bakken, Mr. Ellis, Mr. Fisackerly, Ms. Landreaux, Mr. Marsh, Mr. Rice, and Mr. West may receive upon the occurrence of certain termination events.
 

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2)
As of December 31, 2018, Mr. Brown, Mr. Denault, Mr. May, Mr. Riley, 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. Riley, 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 “2018 Pension Benefits.”

3)
For purposes of the table, the value of Mr. Denault’s payments was calculated by multiplying the target performance units for the 2015-2017 Performance Unit Program (33,100) by the closing price of Entergy stock on December 31, 2018 ($86.07), which would equal a payment of $2,848,917 for the forfeited performance units for each performance period. The value of Mr. Bakken’s, Mr. Brown’s, Mr. Marsh’s, and Mr. West’s payments was calculated by multiplying the target performance units for the 2015-2017 Performance Unit Program (6,550) by the closing price of Entergy stock on December 31, 2018 ($86.07), which would equal a payment of $563,759 for the forfeited performance units for each performance period. The value of Mr. May’s and Mr. Riley’s payment was calculated by multiplying the target performance units for the 2015-2017 Performance Unit Program (2,050) by the closing price of Entergy stock on December 31, 2018 ($86.07), which would equal a payment of $176,444 for the forfeited performance units for each performance period. The value of the payments for the other Named Executives Officers, other than Mr. Ellis and Mr. Rice, was calculated by multiplying the target performance units for the 2015-2017 Performance Unit Program (1,450) by the closing price of Entergy stock on December 31, 2018 ($86.07), which would equal a payment of $124,802 for the forfeited performance units for each performance period. At December 31, 2018, Mr. Ellis was not eligible to participate in the long-term performance unit program, and Mr. Rice was not a participant in the System Executive Continuity Plan.
For purposes of the table, the values of the awards payable in the event of retirement in the case of Mr. Brown, Mr. Denault, Mr. May, Ms. Rainer, or Mr. Riley or upon death or disability, other than Mr. Denault, for each Named Executive Officer were calculated as follows:
Mr. Denault’s:
2017-2019 Plan: 32,467 (24/36 × 48,700) performance units at target, assuming a stock price of $86.07
2018-2020 Plan: 14,233 (12/36 × 42,700) performance units at target, assuming a stock price of $86.07
 
Messrs. Bakken’s, Brown’s, Marsh’s, and West’s:
2017-2019 Plan: 5,533 (24/36 × 8,300) performance units at target, assuming a stock price of $86.07
2018-2020 Plan: 2,633 (12/36 × 7,900) performance units at target, assuming a stock price of $86.07
Mr. May’s:
2017-2019 Plan: 2,100 (24/36 × 3,150) performance units at target, assuming a stock price of $86.07
2018-2020 Plan: 850 (12/36 × 2,550) performance units at target, assuming a stock price of $86.07
Mr. Riley’s:
2017-2019 Plan: 1,667 (24/36 × 2,500) performance units at target, assuming a stock price of $86.07
2018-2020 Plan: 800 (12/36 × 2,400) performance units at target, assuming a stock price of $86.07
Mr. Fisackerly’s and Ms. Rainer’s:
2017-2019 Plan: 1,233 (24/36 × 1,850) performance units at target, assuming a stock price of $86.07
2018-2020 Plan: 545 (12/36 × 1,650) performance units at target, assuming a stock price of $86.07
Ms. Landreaux’s:
2017-2019 Plan: 617 (24/36 × 925) performance units at target, assuming a stock price of $86.07
2018-2020 Plan: 458 (12/36 × 1,375) performance units at target, assuming a stock price of $86.07
Mr. Rice’s:

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2017-2019 Plan: 651 (24/36 × 976) performance units at target, assuming a stock price of $86.07
2018-2020 Plan: 107 (12/36 × 321) performance units at target, assuming a stock price of $86.07

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 2014-2016 Performance Unit Program (40,000) and from the 2015-2017 Performance Unit Program (33,100). This average number of units (36,550) multiplied by the closing price of Entergy stock on December 31, 2018 ($86.07) would equal a payment of $3,145,859.

5)
Pursuant to the System Executive Continuity Plan, 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, Mr. Fisackerly, and Ms. Landreaux would be eligible to receive Entergy-subsidized COBRA benefits for 12 months.

6)
Upon retirement, Mr. Brown, Mr. Denault, Mr. May, Mr. Riley, and Ms. Rainer would be eligible for retiree medical and dental benefits, the same as all other retirees.

7)
Mr. Bakken’s 30,000 restricted stock units vest 1/3rd on each of April 6, 2019, April 6, 2022, and April 6, 2025. Pursuant to his restricted stock unit agreement, if Mr. Bakken’s employment terminates due to total disability or death or, prior to April 6, 2019, Mr. Bakken’s employment is terminated by his Entergy employer other than for cause, he will vest in and be paid the 10,000 restricted stock units that otherwise would have vested had he satisfied the vesting conditions of the restricted stock unit agreement through the next vesting date to occur following his date of total disability, death or termination other than for cause prior to April 6, 2019 subject, in the case of a termination without cause, to Mr. Bakken timely executing and not revoking a release of claims against Entergy and its affiliates. 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.

8)
Mr. Marsh’s 21,100 restricted stock units vest 100% in 2020. Pursuant to his restricted stock unit agreement, any unvested restricted stock units will vest immediately in the event of his termination of employment due to Mr. Marsh’s total disability or death or a Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. Marsh is subject to certain restrictions on his ability to compete with Entergy and its affiliates during and for 12 months after his employment with Entergy, or to solicit its employees or customers during and for 24 months after his employment with Entergy. In addition, the restricted stock unit agreement limits Mr. Marsh’s ability to disparage Entergy and its affiliates. In the event of a breach of these restrictions, Mr. Marsh 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.



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Identification of Median Employee

For each of the Utility operating companies, October 5, 2018 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 it is representative of the compensation received by the employees of each respective Utility operating company and is readily available. The calculation of annual total compensation of the median employee for each Utility operating company is the same calculation used to determine total compensation for purposes of the 2018 Summary Compensation Table with respect to each of the Named Executive Officers.

Entergy Arkansas Ratio

For purposes of this disclosure and to reflect the Chief Executive Officer transition discussed earlier in the CD&A, the compensation amounts paid to each of Mr. Riley and Ms. Landreaux for the time he and she respectively served as Entergy Arkansas’ Chief Executive Officer during 2018 have been pro-rated and combined.

For 2018,
•
The median of the annual total compensation of all of Entergy Arkansas’ employees, other than Entergy Arkansas’ Chief Executive Officer, was $113,820.
•
The combined annual total compensation of Entergy Arkansas’ previous Chief Executive Officer, Mr. Riley, and its current Chief Executive Officer, Ms. Landreaux, as reported in the Total column of the 2018 Summary Compensation Table (pro-rated for the time each served as Entergy Arkansas’ Chief Executive Officer in 2018) was $990,731.
•
Based on this information, the ratio of the annual total compensation of Entergy Arkansas’ Chief Executive Officer to the median of the annual total compensation of all employees is estimated to be 9:1.

Entergy Louisiana Ratio

For 2018,
•
The median of the annual total compensation of all of Entergy Louisiana’s employees, other than Mr. May, was $108,115.
•
Mr. May’s annual total compensation, as reported in the Total column of the 2018 Summary Compensation Table, was $1,031,421.
•
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 10:1.

Entergy Mississippi Ratio

For 2018,
•
The median of the annual total compensation of all of Entergy Mississippi’s employees, other than Mr. Fisackerly, was $113,046.
•
Mr. Fisackerly’s annual total compensation, as reported in the Total column of the 2018 Summary Compensation Table, was $815,654.
•
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 7:1.


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Entergy New Orleans Ratio

For purposes of this disclosure and to reflect the Chief Executive Officer transition discussed earlier in the CD&A, the compensation amounts we paid to each of Mr. Ellis, Mr. Rice and Mr. West for the time they served as Entergy New Orleans’ Chief Executive Officer during 2018 have been pro-rated and combined.

For 2018,
•
The median of the annual total compensation of all of Entergy New Orleans’ employees, other than Entergy New Orleans’ Chief Executive Officer, was $93,562.
•
The combined annual total compensation of Entergy New Orleans’ previous Chief Executive Officers, Mr. Rice and Mr. West, and its current Chief Executive Officer, Mr. Ellis, as reported in the Total column of the 2018 Summary Compensation Table (pro-rated for the time each served as Entergy New Orleans’ Chief Executive Officer in 2018) was $1,382,688.
•
Based on this information, the ratio of the annual total compensation of Entergy New Orleans’ Chief Executive Officer to the median of the annual total compensation of all employees is estimated to be 15:1.

Entergy Texas Ratio

For 2018,
•
The median of the annual total compensation of all of Entergy Texas’ employees, other than Ms. Rainer, was $104,839.
•
Ms. Rainer’s annual total compensation, as reported in the Total column of the 2018 Summary Compensation Table, was $774,225.
•
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 7:1.



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Item 12.  Security Ownership of Certain Beneficial Owners and Management

Entergy Corporation owns 100% of the outstanding common stock of registrants Entergy Texas and indirectly 100% of the outstanding common membership interests of registrant 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” in the 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, 2019 for all directors and Named Executive Officers.  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**
 
19,880

 
38,566

 
—

Marcus V. Brown**
 
32,692

 
145,033

 
—

John R. Burbank*
 
874

 
—

 
—

Patrick J. Condon*
 
6,291

 
—

 
—

Leo P. Denault***
 
179,581

 
691,300

 
—

Kirkland H. Donald*
 
6,851

 
—

 
2,231

Philip L. Frederickson*
 
4,664

 
—

 
805

Alexis M. Herman*
 
13,352

 
—

 
—

Stuart L. Levenick*
 
19,878

 
—

 
—

Blanche L. Lincoln*
 
13,093

 
—

 
—

Andrew S. Marsh**
 
70,899

 
204,766

 
—

Karen A. Puckett*
 
6,291

 
—

 
—

Roderick K. West**
 
51,949

 
60,566

 
—

All directors and executive officers as a group (17 persons)
 
511,522

 
1,266,295

 
3,036

 
 
 
 
 
 
 
Entergy Arkansas
 
 

 
 

 
 

A. Christopher Bakken, III**
 
19,880

 
38,566

 
—

Marcus V. Brown**
 
32,692

 
145,033

 
—

Leo P. Denault**
 
179,581

 
691,300

 
—

Andrew S. Marsh***
 
70,899

 
204,766

 
—

Laura R. Landreaux***
 
4,132

 
—

 
—

Richard C. Riley****
 
11,599

 
16,333

 
—

Roderick K. West***
 
51,949

 
60,566

 
—

All directors and executive officers as a group (10 persons)
 
446,759

 
1,264,729

 
—

 
 
 
 
 
 
 
Entergy Louisiana
 
 
 
 
 
 
A. Christopher Bakken, III**
 
19,880

 
38,566

 
—

Marcus V. Brown**
 
32,692

 
145,033

 
—

Leo P. Denault**
 
179,581

 
691,300

 
—

Andrew S. Marsh***
 
70,899

 
204,766

 
—

Phillip R. May, Jr.***
 
21,546

 
22,900

 
12

Roderick K. West***
 
51,949

 
60,566

 
—

All directors and executive officers as a group (9 persons)
 
452,574

 
1,271,296

 
12



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Name
 
Shares (1)(2)
 
Options Exercisable Within 60 Days
 
Stock Units (3)
Entergy Mississippi
 
 
 
 
 
 
Marcus V. Brown**
 
32,692

 
145,033

 
—

Leo P. Denault**
 
179,581

 
691,300

 
—

Haley R. Fisackerly***
 
7,843

 
13,700

 
—

Andrew S. Marsh***
 
70,899

 
204,766

 
—

Roderick K. West***
 
51,949

 
60,566

 
—

All directors and executive officers as a group (8 persons)
 
418,991

 
1,223,530

 
—

 
 
 
 
 
 
 
Entergy New Orleans
 
 
 
 
 
 
Marcus V. Brown**
 
32,692

 
145,033

 
—

Leo P. Denault**
 
179,581

 
691,300

 
—

David D. Ellis***
 
500

 
—

 
—

Andrew S. Marsh***
 
70,899

 
204,766

 
—

Charles L. Rice, Jr.****
 
7,631

 
8,167

 
—

Roderick K. West***
 
51,949

 
60,566

 
—

All directors and executive officers as a group (9 persons)
 
419,279

 
1,217,997

 
—

 
 
 
 
 
 
 
Entergy Texas
 
 
 
 
 
 
Marcus V. Brown**
 
32,692

 
145,033

 
—

Leo P. Denault**
 
179,581

 
691,300

 
—

Andrew S. Marsh***
 
70,899

 
204,766

 
—

Sallie T. Rainer***
 
8,370

 
15,667

 
—

Roderick K. West***
 
51,949

 
60,566

 
—

All directors and executive officers as a group (8 persons)
 
419,518

 
1,225,497

 
—

*
Director of the respective Company
**
Named Executive Officer of the respective Company
***
Director and Named Executive Officer of the respective Company
****
Former Director 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, 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 executive holds under the defined contribution restoration plan and the deferral provisions of the Equity Ownership Plan.  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, 2018. 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)
 
2,993,333

 
$75.14
 
2,006,268

Equity compensation plans not approved by security holders
 
—

 
—

 
—

Total
 
2,993,333

 
$75.14
 
2,006,268


(1)
Includes the 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, and the 2015 Equity 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 6,900,000 shares of Entergy Corporation common stock can be issued from the 2015 Equity Plan, with no more than 1,500,000 shares available for incentive stock option grants.  The 2015 Equity Plan applies to awards granted on or after May 8, 2015. The 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, and the 2015 Equity 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 and any corporation 80% or more of whose stock (based on voting power) or value is owned, directly or indirectly, by 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 the 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 Proxy Statement under the headings “Corporate Governance at Entergy - Director Independence” and “Corporate Governance at Entergy - Governance Policies - Our Transactions with Related Party Persons Policy.”

Entergy Corporation’s Board of Directors has adopted written policies and procedures for the review, approval or ratification of any transaction involving an amount in excess of $120,000 in which any director or executive officer of Entergy Corporation, any nominee for director, or any immediate family member of the foregoing has or will have a material interest as contemplated by Item 404(a) of Regulation S-K (“Related Person Transactions”). Under these policies and procedures, Entergy Corporation’s Corporate Governance Committee or a subcommittee of its Board of Directors consisting entirely of independent directors reviews the transaction and either approves or rejects the transaction after taking into account the following factors:

•
Whether the proposed transaction is on terms that are at least as favorable to Entergy Corporation as those achievable with an unaffiliated third party;
•
Size of the transaction and amount of consideration;
•
Nature of the interest;
•
Whether the transaction involves a conflict of interest;
•
Whether the transaction involves services available from unaffiliated third parties; and
•
Any other factors that the Corporate Governance Committee or subcommittee deems relevant.

The policy does not apply to (a) compensation and related person transactions involving a director or an executive officer solely resulting from that person’s service as a director or employment with Entergy Corporation so long as the compens tion is approved by the Board of Directors (or an appropriate committee), (b) transactions involving public utility services at rates or charges fixed in conformity with law or governmental authority, or (c) any other categories of transactions currently or in the future excluded from the reporting requirements of Item 404(a) of Regulation S-K.

Related Party Transactions
 
Since January 1, 2018, neither Entergy Corporation nor any of its affiliates has participated in any Related Person 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, 2018 and 2017 by Deloitte & Touche LLP were as follows:

 
2018
 
2017
Entergy Corporation (consolidated)
 
 
 
Audit Fees

$8,801,895

 

$8,401,895

Audit-Related Fees (a)
1,067,119

 
875,000

Total audit and audit-related fees
9,869,014

 
9,276,895

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (b)

$9,869,014

 

$9,276,895

Entergy Arkansas
 
 
 
Audit Fees

$1,030,758

 

$1,018,860

Audit-Related Fees (a)
—

 
—

Total audit and audit-related fees
1,030,758

 
1,018,860

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (b)

$1,030,758

 

$1,018,860

Entergy Louisiana
 
 
 
Audit Fees

$1,916,517

 

$1,887,719

Audit-Related Fees (a)
500,000

 
500,000

Total audit and audit-related fees
2,416,517

 
2,387,719

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (b)

$2,416,517

 

$2,387,719

Entergy Mississippi
 
 
 
Audit Fees

$910,758

 

$933,860

Audit-Related Fees (a)
—

 
—

Total audit and audit-related fees
910,758

 
933,860

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (b)

$910,758

 

$933,860


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2018
 
2017
Entergy New Orleans
 
 
 
Audit Fees

$965,758

 

$953,860

Audit-Related Fees (a)
—

 
—

Total audit and audit-related fees
965,758

 
953,860

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (b)

$965,758

 

$953,860

Entergy Texas
 
 
 
Audit Fees

$1,200,758

 

$1,093,860

Audit-Related Fees (a)
—

 
—

Total audit and audit-related fees
1,200,758

 
1,093,860

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (b)

$1,200,758

 

$1,093,860

System Energy
 
 
 
Audit Fees

$850,758

 

$868,860

Audit-Related Fees (a)
—

 
—

Total audit and audit-related fees
850,758

 
868,860

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (b)

$850,758

 

$868,860


(a)
Includes fees for employee benefit plan audits, consultation on financial accounting and reporting, and other attestation services.
(b)
100% of fees paid in 2018 and 2017 were pre-approved by the Entergy Corporation Audit Committee.

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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:
•
Aggregate non-audit service fees are targeted at fifty percent or less of the approved audit service fee.
•
All other services should only be provided by the independent auditor if it is a highly qualified provider of that service or if the Audit Committee pre-approves the independent audit firm to provide the service.
3.
The Audit Committee will be informed quarterly as to the status of pre-approved services actually provided by the independent auditor.
4.
To ensure prompt handling of unexpected matters, the Audit Committee delegates to the Audit Committee Chair or its designee the authority to approve permissible services and fees.  The Audit Committee Chair or designee will report action taken to the Audit Committee at the next scheduled Audit Committee meeting.
5.
The Vice President and General Auditor will be responsible for tracking all independent auditor fees and will report quarterly to the Audit Committee.


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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
 
 
 
Report of Independent Registered Public Accounting Firm (see page 530)
 
 
 
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 509 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.


508
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EXHIBIT INDEX

The following exhibits indicated by an asterisk preceding the exhibit number are filed herewith.  The balance of the exhibits have heretofore 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
(a) 1 --

Entergy Louisiana
(b) 1 --
 
 
(b) 2 --
 
 
(b) 3 --

Entergy Mississippi
(c) 1 --

Entergy New Orleans
(d) 1 --

(3) Articles of Incorporation and By-laws

Entergy Corporation
(a) 1 --
 
 
(a) 2 --

509
Table of Contents


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
(g) 1 --
 
 
(g) 2 --

(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.
 
 

510
Table of Contents


(a) 2 --
 
 
(a) 3 --
 
 
(a) 4 --
 
 
(a) 5 --
 
 
(a) 6 --

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 --

Entergy Arkansas
(c) 1 --
Mortgage and Deed of Trust, dated as of October 1, 1944, as amended by the following Supplemental Indentures: (7(d) in 2-5463 (Mortgage); 7(b) in 2-7121 (First); 4(a)-7 in 2-10261 (Seventh); 2(b)-10 in 2-15767 (Tenth); 2(c) in 2-28869 (Sixteenth); 2(c) in 2-35107 (Eighteenth); 2(d) in 2-36646 (Nineteenth); 2(c) in 2-39253 (Twentieth); 4(c)1 to Form 10-K for the year ended December 31, 2017 in 1-10764 (Thirtieth); 4(c)1 to Form 10-K for the year ended December 31, 2017 in 1-10764 (Thirty-first); 4(c)1 to Form 10-K for the year ended December 31, 2017 in 1-10764 (Thirty-ninth); 4(c)1 to Form 10-K for the year ended December 31, 2017 in 1-10764 (Forty-first); 4(d)(2) in 33-54298 (Forty-sixth); C-2 to Form U5S for the year ended December 31,1995 (Fifty-third); 4.06 to Form 8-K filed October 8, 2010 in 1-10764 (Sixty-ninth); 4.06 to Form 8-K filed November 12, 2010 in 1-10764 (Seventieth); 4.06 to Form 8-K filed December 13, 2012 in 1-10764 (Seventy-first); 4(e) to Form 8-K filed January 9, 2013 in 1-10764 (Seventy-second); 4.06 to Form 8-K filed May 30, 2013 in 1-10764 (Seventy-third); 4.06 to Form 8-K filed June 4, 2013 in 1-10764 (Seventy-fourth); 4.05 to Form 8-K filed March 14, 2014 in 1-10764 (Seventy-sixth); 4.05 to Form 8-K filed December 9, 2014 in 1-10764 (Seventy-seventh); 4.05 to Form 8-K filed January 8, 2016 in 1-10764 (Seventy-eighth); 4.05 to Form 8-K filed August 16, 2016 in 1-10764 (Seventy-ninth); 4(a) to Form 10-Q for the quarter ended September 30, 2018 (Eightieth); and 4.1 to Form 8-K12B filed December 3, 2018 in 1-10764 (Eighty-first)).
 
 
(c) 2 --
 
 


511
Table of Contents

(c) 3 --
 
 
(c) 4 --
 
 
(c) 5 --

Entergy Louisiana

(d) 1 --
Mortgage and Deed of Trust, dated as of April 1, 1944, as amended by the following Supplemental Indentures: (7(d) in 2-5317 (Mortgage); 7(b) in 2-7408 (First); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Sixth); 2(c) in 2-34659 (Twelfth); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Thirteenth); 2(b)-2 in 2-38378 (Fourteenth); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Twenty-first); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Twenty-fifth); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Twenty-ninth); 4(d)1 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Forty-second); A-2(a) to Rule 24 Certificate filed April 4, 1996 in 70-8487 (Fifty-first); B-4(i) to Rule 24 Certificate filed January 10, 2006 in 70-10324 (Sixty-third); B-4(ii) to Rule 24 Certificate filed January 10, 2006 in 70-10324 (Sixty-fourth); 4(a) to Form 10-Q for the quarter ended September 30, 2008 in 1-32718 (Sixty-fifth); 4(e)1 to Form 10-K for the year ended December 31, 2009 in 1-132718 (Sixty-sixth); 4.08 to Form 8-K filed September 24, 2010 in 1-32718 (Sixty-eighth); 4.08 to Form 8-K filed March 24, 2011 in 1-32718 (Seventy-first); 4(a) to Form 10-Q for the quarter ended June 30, 2011 in 1-32718 (Seventy-second); 4.08 to Form 8-K filed July 3, 2012 in 1-32718 (Seventy-fifth); 4.08 to Form 8-K filed December 4, 2012 in 1-32718 (Seventy-sixth); 4.08 to Form 8-K filed May 21, 2013 in 1-32718 (Seventy-seventh); 4.08 to Form 8-K filed August 23, 2013 in 1-32718 (Seventy-eighth); 4.08 to Form 8-K filed June 24, 2014 in 1-32718 (Seventy-ninth); 4.08 to Form 8-K filed July 1, 2014 in 1-32718 (Eightieth); 4.08 to Form 8-K filed November 21, 2014 (Eighty-first); 4.1 to Form 8-K12B filed October 1, 2015 (Eighty-second); 4(g) to Form 8-K filed March 18, 2016 in 1-32718 (Eighty-third); 4.33 to Form 8-K filed March 24, 2016 in 1-32718 (Eighty-fourth); 4.33 to Form 8-K filed August 17, 2016 in 1-32718 (Eighty-sixth); 4.43 to Form 8-K filed October 4, 2016 in 1-32718 (Eighty-seventh); 4.43 to Form 8-K filed May 23, 2017 in 1-32718 (Eighty-eighth); 4.43 to Form 8‑K filed March 23, 2018 in 1-32718 (Eighty-ninth); and 4.43 to Form 8-K filed August 14, 2018 in 1-32718 (Ninetieth)).
 
 
(d) 2 --
 
 
(d) 3 --
 
 
(d) 4 --
 
 
(d) 5 --
 
 


512
Table of Contents

(d) 6 --
 
 
(d) 7 --
 
 
(d) 8 --
Indenture of Mortgage, dated September 1, 1926, as amended by the following Supplemental Indentures: (7-A-9 in Registration No. 2-6893 (Seventh); 4(d)15 to Form 10-K for the year ended December 31, 2017 in 1-32718 (Eighteenth); 2-A-8 in Registration No. 2-66612 (Thirty-eighth); 4(b) to Form 10-Q for the quarter ended March 31,1999 in 1-27031 (Fifty-eighth); 4(a) to Form 10-Q for the quarter ended September 30, 2009 in 0-20371 (Seventy-seventh); 4.07 to Form 8-K filed October 1, 2010 in 0-20371 (Seventy-eighth); 4.07 to Form 8-K filed July 1, 2014 in 0-20371 (Eighty-first); 4.2 to Form 8-K12B filed October 1, 2015 in 1-32718 (Eighty-second); 4.3 to Form 8-K12B filed October 1, 2015 in 1-32718 (Eighty-third); 4.42 to Form 8-K filed March 24, 2016 in 1-32718 (Eighty-fourth); 4.42 to Form 8-K filed May 19, 2016 in 1-32718 (Eighty-fifth); 4.42 to Form 8-K filed August 17, 2016 in 1-32718 (Eighty-sixth); 4.42 to Form 8-K filed October 4, 2016 in 1-32718 (Eighty-seventh); 4.42 to Form 8-K filed May 23, 2017 in 1-32718 (Eighty-eighth); 4.42 to Form 8-K filed March 23, 2018 in 1-32718 (Eighty-ninth); and 4.42 to Form 8-K filed August 14, 2018 in 1-32718 (Ninetieth)).
 
 
(d) 9 --
 
 
(d) 10 --
 
 
(d) 11 --
 
 
(d) 12 --
 
 
(d) 13 --
 
 
(d) 14 --
 
 
(d) 15 --
 
 
(d) 16 --
 
 
(d) 17 --
 
 
(d) 18 --


513
Table of Contents

Entergy Mississippi
(e) 1 --
Mortgage and Deed of Trust, dated as of February 1, 1988, as amended by the following Supplemental Indentures: 4(e)1 to Form 10-K for the year ended December 31, 2017 in 1-31508 (Mortgage); 4(e)1 to Form 10-K for the year ended December 31, 2017 in 1-31508 (Sixth); A-2(c) to Rule 24 Certificate filed May 14, 1999 in 70-8719 (Thirteenth); 4(b) to Form 10-Q for the quarter ended June 30, 2009 in 1-31508 (Twenty-sixth); 4.38 to Form 8-K filed December 11, 2012 in 1-31508 (Thirtieth); 4.05 to Form 8-K filed March 21, 2014 in 1-31508 (Thirty-first); 4.05 to Form 8-K filed May 13, 2016 in 1-31508 (Thirty-second); 4.16 to Form 8-K filed September 15, 2016 in 1-31508 (Thirty-third); 4.16 to Form 8-K filed November 14, 2017 in 1-31508 (Thirty-fourth); 4.1 to Form 8-K filed November 21, 2018 in 1-31508 (Thirty-fifth); 4.1 to Form 8-K12B filed December 3, 2018 in 1-31508 (Thirty-sixth); and 4(a) to Form 8-K filed December 12, 2018 in 1-31508 (Thirty-seventh)).

Entergy New Orleans
(f) 1 --
Mortgage and Deed of Trust, dated as of May 1, 1987, as amended by the following Supplemental Indentures: 4(f)1 to Form 10-K for the year ended December 31, 2017 in 1-35747 (Mortgage); 4(f)1 to Form 10-K for the year ended December 31, 2017 in 1-35747 (Third); 4(b) to Form 10-Q for the quarter ended June 30, 1998 in 0-5807 (Seventh); 4.02 to Form 8-K filed November 23, 2010 in 0-5807 (Fifteenth); 4.02 to Form 8-K filed November 29, 2012 in 1-35747 (Sixteenth); 4.02 to Form 8-K filed June 21, 2013 in 1-35747 (Seventeenth); 4(m) to Form 10-Q for the quarter ended March 31, 2016 in 1-35747 (Eighteenth); 4.02 to Form 8-K filed March 22, 2016 in 1-35747 (Nineteenth); 4.02 to Form 8-K filed May 24, 2016 in 1-35747 (Twentieth); 4.1 to Form 8-K12B filed December 1, 2017 in 1-35747 (Twenty-first); and 4(a) to Form 8-K filed September 27, 2018 in 1-35747 (Twenty-second)).
 
 
*(f) 2 --

Entergy Texas
(g) 1 --
 
 
(g) 2 --
 
 
(g) 3 --
 
 
(g) 4 --
 
 
(g) 5 --
 
 
(g) 6 --
 
 
(g) 7 --


514
Table of Contents

(g) 8 --
 
 
(g) 9 --

(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 --

515
Table of Contents

 
 
+(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 --
 
 
+(a) 31 --
 
 

516
Table of Contents

+(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 --
 
 
+(a) 47 --
 
 
+(a) 48 --
 
 
+(a) 49 --
 
 

517
Table of Contents

+(a) 50 --
 
 
+(a) 51 --
 
 
+(a) 52 --
 
 
+(a) 53 --
 
 
+(a) 54 --
 
 
+(a) 55 --
 
 
+(a) 56 --
 
 
(a) 57 --
 
 
(a) 58 --
 
 
(a) 59 --
 
 
(a) 60 --
 
 
(a) 61 --
 
 
(a) 62 --

System Energy
(b) 1 --
 
 
(b) 2 --
 
 
(b) 3 --
 
 

518
Table of Contents

(b) 4 --
 
 
(b) 5 --
 
 
(b) 6 --
 
 
(b) 7 --
 
 
(b) 8 --
 
 
(b) 9 --
 
 
(b) 10 --
 
 
(b) 11 --
 
 
(b) 12 --
 
 
(b) 13 --
 
 
(b) 14 --
 
 
(b) 15 --
 
 
*(b) 16 --

Entergy Louisiana
(c) 1 --

(14) Code of Ethics

Entergy Corporation
(a)

519
Table of Contents


*(21)  Subsidiaries of the Registrants

(23)  Consents of Experts and Counsel
*(a)

*(24)  Powers of Attorney

(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)

520
Table of Contents


*(h)
 
 
*(i)
 
 
*(j)
 
 
*(k)
 
 
*(l)
 
 
*(m)
 
 
*(n)


(101)  XBRL Documents

Entergy Corporation
*INS -
XBRL Instance Document.
 
 
*SCH -
XBRL Taxonomy Extension Schema Document.
 
 
*CAL -
XBRL Taxonomy Extension Calculation Linkbase Document.
 
 
*DEF -
XBRL Taxonomy Extension Definition Linkbase Document.
 
 
*LAB -
XBRL Taxonomy Extension Label Linkbase Document.
 
 
*PRE -
XBRL Taxonomy Extension Presentation Linkbase Document.
_________________
 
*
Filed herewith.
 
+ 
Management contracts or compensatory plans or arrangements.


521
Table of Contents

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/ Alyson M. Mount
 
Alyson M. Mount
 
Senior Vice President and Chief Accounting Officer
 
 
 
Date: February 26, 2019

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/ Alyson M. Mount 
Alyson M. Mount
Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
February 26, 2019

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, Philip L. Frederickson, Alexis M. Herman, Stuart L. Levenick, Blanche L. Lincoln, and Karen A. Puckett (Directors).

By: /s/ Alyson M. Mount
February 26, 2019
(Alyson M. Mount, Attorney-in-fact)
 


522
Table of Contents

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/ Alyson M. Mount
 
Alyson M. Mount
 
Senior Vice President and Chief Accounting Officer
 
 
 
Date: February 26, 2019

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/ Alyson M. Mount 
Alyson M. Mount
Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
February 26, 2019

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/ Alyson M. Mount
February 26, 2019
(Alyson M. Mount, Attorney-in-fact)
 


523
Table of Contents

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/ Alyson M. Mount
 
Alyson M. Mount
 
Senior Vice President and Chief Accounting Officer
 
 
 
Date: February 26, 2019

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/ Alyson M. Mount 
Alyson M. Mount
Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
February 26, 2019

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/ Alyson M. Mount
February 26, 2019
(Alyson M. Mount, Attorney-in-fact)
 

524
Table of Contents

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/ Alyson M. Mount
 
Alyson M. Mount
 
Senior Vice President and Chief Accounting Officer
 
 
 
Date: February 26, 2019

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/ Alyson M. Mount 
Alyson M. Mount
Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
February 26, 2019

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/ Alyson M. Mount
February 26, 2019
(Alyson M. Mount, Attorney-in-fact)
 

525
Table of Contents

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/ Alyson M. Mount
 
Alyson M. Mount
 
Senior Vice President and Chief Accounting Officer
 
 
 
Date: February 26, 2019

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/ Alyson M. Mount 
Alyson M. Mount
Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
February 26, 2019

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/ Alyson M. Mount
February 26, 2019
(Alyson M. Mount, Attorney-in-fact)
 

526
Table of Contents

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/ Alyson M. Mount
 
Alyson M. Mount
 
Senior Vice President and Chief Accounting Officer
 
 
 
Date: February 26, 2019

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/ Alyson M. Mount 
Alyson M. Mount
Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
February 26, 2019

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/ Alyson M. Mount
February 26, 2019
(Alyson M. Mount, Attorney-in-fact)
 

527
Table of Contents

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/ Alyson M. Mount
 
Alyson M. Mount
 
Senior Vice President and Chief Accounting Officer
 
 
 
Date: February 26, 2019

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/ Alyson M. Mount 
Alyson M. Mount
Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
February 26, 2019

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/ Alyson M. Mount
February 26, 2019
(Alyson M. Mount, Attorney-in-fact)
 


528
Table of Contents

EXHIBIT 23(a)

CONSENTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


We consent to the incorporation by reference in Registration Statement No. 333-213335 on Form S-3 and in Registration Statements Nos. 333-140183, 333-174148, 333-204546, 333-206556, and 333-227150 on Form S-8 of our reports dated February 26, 2019, relating to the consolidated 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, 2018.

We consent to the incorporation by reference in Registration Statement No. 333-213335-06 on Form S-3 of our reports dated February 26, 2019, relating to the consolidated 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, 2018.

We consent to the incorporation by reference in Registration Statement No. 333-213335-03 on Form S-3 of our reports dated February 26, 2019, relating to the consolidated 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, 2018.

We consent to the incorporation by reference in Registration Statement No. 333-213335-02 on Form S-3 of our reports dated February 26, 2019, 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, 2018.

We consent to the incorporation by reference in Registration Statement No. 333-213335-05 on Form S-3 of our reports dated February 26, 2019, relating to the consolidated 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, 2018.

We consent to the incorporation by reference in Registration Statement No. 333-213335-04 on Form S-3 of our report dated February 26, 2019, 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, 2018.


/s/ DELOITTE & TOUCHE LLP


New Orleans, Louisiana
February 26, 2019

529
Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the shareholders and Board of Directors of
Entergy Corporation and Subsidiaries


Opinion on the Financial Statement Schedule


We have audited the consolidated financial statements of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2018 and 2017, and for each of the three years in the period ended December 31, 2018, and the Corporation’s internal control over financial reporting as of December 31, 2018, and have issued our reports thereon dated February 26, 2019. 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, 2019



530
Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the shareholder and Board of Directors of
Entergy Texas, Inc. and Subsidiaries

To the members 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, 2018 and 2017, and for each of the three years in the period ended December 31, 2018, and have issued our reports thereon dated February 26, 2019. 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, 2019


531
Table of Contents

INDEX TO FINANCIAL STATEMENT SCHEDULES



Schedule
 
Page
 
 
 
II
Valuation and Qualifying Accounts 2018, 2017, and 2016:
 
 
 
 
 
 
 

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
Table of Contents

ENTERGY CORPORATION AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2018, 2017, and 2016
(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
 
Deductions (1)
 
at End of Period
Allowance for doubtful accounts
 
 
 
 
 
 
 
 
2018
 

$13,587

 

$3,936

 

$10,201

 

$7,322

2017
 

$11,924

 

$4,211

 

$2,548

 

$13,587

2016
 

$39,895

 

$7,505

 

$35,476

 

$11,924

Notes:
 
 

 
 

 
 

 
 

(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.


S-2
Table of Contents

ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2018, 2017, and 2016
(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
 
Deductions (1)
 
at End of Period
Allowance for doubtful accounts
 
 
 
 
 
 
 
 
2018
 

$1,063

 

$810

 

$609

 

$1,264

2017
 

$1,211

 

$503

 

$651

 

$1,063

2016
 

$34,226

 

$902

 

$33,917

 

$1,211

Notes:
 
 

 
 

 
 

 
 

(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.


S-3
Table of Contents

ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2018, 2017, and 2016
(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
 
Deductions (1)
 
at End of Period
Allowance for doubtful accounts
 
 
 
 
 
 
 
 
2018
 

$8,430

 

$2,395

 

$9,012

 

$1,813

2017
 

$6,277

 

$3,108

 

$955

 

$8,430

2016
 

$4,209

 

$2,942

 

$874

 

$6,277

Notes:
 
 

 
 

 
 

 
 

(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.


S-4
Table of Contents

ENTERGY MISSISSIPPI, LLC
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2018, 2017, and 2016
(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
 
Deductions (1)
 
at End of Period
Allowance for doubtful accounts
 
 
 
 
 
 
 
 
2018
 

$574

 

$265

 

$276

 

$563

2017
 

$549

 

$255

 

$230

 

$574

2016
 

$718

 

$259

 

$428

 

$549

Notes:
 
 

 
 

 
 

 
 

(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.


S-5
Table of Contents

ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2018, 2017, and 2016
(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
 
Deductions (1)
 
at End of Period
Allowance for doubtful accounts
 
 
 
 
 
 
 
 
2018
 

$3,057

 

$187

 

$22

 

$3,222

2017
 

$3,059

 

$152

 

$154

 

$3,057

2016
 

$268

 

$2,872

 

$81

 

$3,059

Notes:
 
 

 
 

 
 

 
 

(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.


S-6
Table of Contents

ENTERGY TEXAS, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2018, 2017, and 2016
(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
 
Deductions (1)
 
at End of Period
Allowance for doubtful accounts
 
 
 
 
 
 
 
 
2018
 

$463

 

$279

 

$281

 

$461

2017
 

$828

 

$192

 

$557

 

$463

2016
 

$474

 

$531

 

$177

 

$828

Notes:
 
 

 
 

 
 

 
 

(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.



S-7