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ENTERGY NEW ORLEANS, LLC - Annual Report: 2017 (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, 2017
 
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, INC.
(an Arkansas corporation)
425 West Capitol Avenue
Little Rock, Arkansas 72201
Telephone (501) 377-4000
71-0005900
 
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, INC.
(a Mississippi corporation)
308 East Pearl Street
Jackson, Mississippi 39201
Telephone (601) 368-5000
64-0205830
 
 
 

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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 – 180,770,383 shares outstanding at January 31, 2018
New York Stock Exchange, Inc.
Chicago Stock Exchange, Inc.
 
 
 
Entergy Arkansas, Inc.
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, Inc.
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 Arkansas, Inc.
Preferred Stock, Cumulative, $100 Par Value
 
 
Entergy Mississippi, Inc.
Preferred Stock, Cumulative, $100 Par Value
 
 
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, Inc.
 
 
ü
Entergy Louisiana, LLC
ü
 
 
Entergy Mississippi, Inc.
 
 
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, Inc.
 
 
ü
Entergy Louisiana, LLC
 
 
ü
Entergy Mississippi, Inc.
 
 
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 and posted on Entergy’s corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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.  [ü]


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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, Inc.
 
 
 
 
ü
 
 
 
 
Entergy Louisiana, LLC
 
 
 
 
ü
 
 
 
 
Entergy Mississippi, Inc.
 
 
 
 
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 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 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 2017 was $13.8 billion based on the reported last sale price of $76.77 per share for such stock on the New York Stock Exchange on June 30, 2017.  Entergy Corporation is the sole holder of the common stock of Entergy Arkansas, Inc., Entergy Mississippi, Inc., 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 Louisiana, 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 4, 2018, 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.
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, Inc. 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, 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.
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, Inc., Entergy Louisiana, LLC, Entergy Mississippi, Inc., 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 renewals or 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 the commitment of substantial human and capital resources required for the 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;
•
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;

iv
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FORWARD-LOOKING INFORMATION (Continued)

•
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, heat, and other regulated air and water emissions, requirements for waste management and disposal and for the remediation of contaminated sites, wetlands protection and permitting, and changes in costs of compliance with these 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, or energy policies;
•
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 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 Northeast 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, including the potential impact to credit ratings, which may affect Entergy’s ability to borrow funds or increase the cost of borrowing in the future;
•
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 with respect to new, developing, or alternative sources of generation such as distributed energy and energy storage, energy efficiency, demand side management and other measures that reduce load;
•
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;
•
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;


v
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FORWARD-LOOKING INFORMATION (Concluded)

•
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
ASLB
Atomic Safety and Licensing Board, the board within the NRC that conducts hearings and performs other regulatory functions that the NRC authorizes
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

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DEFINITIONS (Continued)

Abbreviation or Acronym
Term
 
 
GWh
Gigawatt-hour(s), which equals one million kilowatt-hours
Independence
Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi, and 7% by Entergy Power, LLC
Indian Point 2
Unit 2 of Indian Point Energy Center (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
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, Inc., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, LLC, Entergy Texas, Inc., and System Energy Resources, Inc.

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DEFINITIONS (Concluded)

Abbreviation or Acronym
Term
 
 
River Bend
River Bend Station (nuclear), owned by Entergy Louisiana
RTO
Regional transmission organization
SEC
Securities and Exchange Commission
System Agreement
Agreement, effective January 1, 1983, as modified, among the Utility operating companies relating to the sharing of generating capacity and other power resources. The agreement terminated effective August 2016.
System Energy
System Energy Resources, Inc.
TWh
Terawatt-hour(s), which equals one billion kilowatt-hours
Unit Power Sales Agreement
Agreement, dated as of June 10, 1982, as amended and approved by the FERC, among Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, relating to the sale of capacity and energy from System Energy’s share of Grand Gulf
Utility
Entergy’s business segment that generates, transmits, distributes, and sells electric power, with a small amount of natural gas distribution
Utility operating companies
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas
Vermont Yankee
Vermont Yankee Nuclear Power Station (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment, which ceased power production in December 2014
Waterford 3
Unit No. 3 (nuclear) of the Waterford Steam Electric Station, 100% owned or leased 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
2017
2016
2015
 
2017
2016
2015
Utility
85

83

82

 
92

89

86

Entergy Wholesale Commodities
15

17

18

 
12

15

18

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

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
108,187

 
13,922

 
4,869

 
126,978

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

Gain on sale of asset
—

 
16,270

 
—

 
16,270

Other income
64,815

 
132,734

 
1,962

 
199,511

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 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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Management’s Financial Discussion and Analysis

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.

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.


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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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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 and capacity revenue per MWh
$50.04
 
$47.31
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 $2,360 million for 2016 to $2,468 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.

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.

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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 increased from $915 million for 2016 to $929 million for 2017 primarily due to:

•
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 increase was partially offset by a decrease due to the absence of other operation and maintenance expenses 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.

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 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,

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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.

The gain on sale of assets resulted from the sale in March 2017 of the 838 MW FitzPatrick plant to Exelon. Entergy sold the FitzPatrick plant for approximately $110 million, which includes 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 a 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% 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.

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2016 Compared to 2015
 
Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2016 to 2015 showing how much the line item increased or (decreased) in comparison to the prior period.

 
Utility
 
Entergy Wholesale Commodities
 
Parent & Other
 
Entergy
 
(In Thousands)
2015 Consolidated Net Income (Loss)

$1,114,516

 

($1,065,657
)
 

($205,593
)
 

($156,734
)
 
 
 
 
 
 
 
 
Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits)
350,528

 
(123,791
)
 
(33
)
 
226,704

Other operation and maintenance
(83,265
)
 
15,269

 
9,726

 
(58,270
)
Asset write-offs, impairments, and related charges
(68,672
)
 
799,403

 
—

 
730,731

Taxes other than income taxes
(10,229
)
 
(16,259
)
 
(432
)
 
(26,920
)
Depreciation and amortization
49,600

 
(39,180
)
 
(509
)
 
9,911

Gain on sale of asset
—

 
(154,037
)
 
—

 
(154,037
)
Other income
15,153

 
8,666

 
4,281

 
28,100

Interest expense
14,414

 
(3,930
)
 
12,417

 
22,901

Other expenses
19,589

 
(15,074
)
 
—

 
4,515

Income taxes
407,627

 
(581,924
)
 
(35
)
 
(174,332
)
2016 Consolidated Net Income (Loss)

$1,151,133

 

($1,493,124
)
 

($222,512
)
 

($564,503
)

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 2016 include $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. See Note 14 to the financial statements for further discussion of the impairment and related charges. Results of operations for 2016 also include 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 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 3 to the financial statements for additional discussion of the income tax items. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

Results of operations for 2015 include $2,036 million ($1,317 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ FitzPatrick, Pilgrim, and Palisades plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of the impairment and related charges. As a result of the Entergy Louisiana and Entergy Gulf States Louisiana business combination, results of operations for 2015 also include two items that occurred in October 2015: 1) a deferred tax asset and resulting net increase in tax basis of approximately $334 million and 2) a regulatory liability of $107 million

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($66 million net-of-tax) as a result of customer credits to be realized by electric customers of Entergy Louisiana, consistent with the terms of the stipulated settlement in the business combination proceeding. See Note 2 to the financial statements for further discussion of the business combination and customer credits. Results of operations for 2015 also include the sale in December 2015 of the 583 MW Rhode Island State Energy Center for a realized gain of $154 million ($100 million net-of-tax) on the sale and the $77 million ($47 million net-of-tax) write-off and regulatory charges to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project is no longer probable of recovery. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale. See Note 2 to the financial statements for further discussion of the Waterford 3 replacement steam generator prudence review proceeding.

Net Revenue

Utility

Following is an analysis of the change in net revenue comparing 2016 to 2015.
  
Amount
  
(In Millions)
 
 
2015 net revenue

$5,829

Retail electric price
289

Louisiana business combination customer credits
107

Volume/weather
14

Louisiana Act 55 financing savings obligation
(17
)
Other
(43
)
2016 net revenue

$6,179


The retail electric price variance is primarily due to:

•
an increase in base rates at Entergy Arkansas, as approved by the APSC. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. The increase 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. A significant portion of the increase was related to the purchase of Power Block 2 of the Union Power Station;
•
an increase in the purchased power and capacity acquisition cost recovery rider for Entergy New Orleans, as approved by the City Council, effective with the first billing cycle of March 2016, primarily related to the purchase of Power Block 1 of the Union Power Station;
•
an increase in formula rate plan revenues for Entergy Louisiana, 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; and
•
an increase in revenues at Entergy Mississippi, as approved by the MPSC, effective with the first billing cycle of July 2016, and an increase in revenues collected through the storm damage rider.

See Note 2 to the financial statements for further discussion of the rate proceedings. See Note 14 to the financial statements for discussion of the Union Power Station purchase.

The Louisiana business combination customer credits variance is due to a regulatory liability of $107 million recorded by Entergy in October 2015 as a result of the Entergy Gulf States Louisiana and Entergy Louisiana business combination. Consistent with the terms of the stipulated settlement in the business combination proceeding, electric customers of Entergy Louisiana will realize customer credits associated with the business combination; accordingly, in October 2015, Entergy recorded a regulatory liability of $107 million ($66 million net-of-tax). These costs are being

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amortized over a nine-year period beginning December 2015. See Note 2 to the financial statements for further discussion of the business combination and customer credits.

The volume/weather variance is primarily due to the effect of more favorable weather during the unbilled period and an increase in industrial usage, partially offset by the effect of less favorable weather on residential sales. The increase in industrial usage is primarily due to expansion projects, primarily in the chemicals industry, and increased demand from new customers, primarily in the industrial gases industry.

The Louisiana Act 55 financing savings obligation variance results from a regulatory charge 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.

Included in Other is a provision of $23 million recorded in 2016 related to the settlement of the Waterford 3 replacement steam generator prudence review proceeding, offset by a provision of $32 million recorded in 2015 related to the uncertainty at that time associated with the resolution of the Waterford 3 replacement steam generator prudence review proceeding.  See Note 2 to the financial statements for a discussion of the Waterford 3 replacement steam generator prudence review proceeding.

Entergy Wholesale Commodities

Following is an analysis of the change in net revenue comparing 2016 to 2015.
  
Amount
  
(In Millions)
 
 
2015 net revenue

$1,666

Nuclear realized price changes
(149
)
Rhode Island State Energy Center
(44
)
Nuclear volume
(36
)
FitzPatrick reimbursement agreement
41

Nuclear fuel expenses
68

Other
(4
)
2016 net revenue

$1,542


As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by approximately $124 million in 2016 primarily due to:

•
lower realized wholesale energy prices and lower capacity prices, the amortization of the Palisades below-market PPA, and Vermont Yankee capacity revenue. The effect of the amortization of the Palisades below-market PPA and Vermont Yankee capacity revenue on the net revenue variance from 2015 to 2016 is minimal;
•
the sale of the Rhode Island State Energy Center in December 2015. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale; and
•
lower volume in the Entergy Wholesale Commodities nuclear fleet resulting from more refueling outage days in 2016 as compared to 2015 and larger exercise of resupply options in 2016 as compared to 2015. See “Nuclear Matters - Indian Point” below for discussion of the extended Indian Point 2 outage in the second quarter 2016.


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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. Revenues received from Exelon under the reimbursement agreement are offset in nuclear fuel expenses and other operation and maintenance expenses and have no material effect on net income. See “Entergy Wholesale Commodities Exit from the Merchant Power Business - Sale of FitzPatrick” below for further discussion of the reimbursement agreement; and
•
a decrease in nuclear fuel expenses primarily related to the impairments of the FitzPatrick, Pilgrim, and Palisades plants and related assets. See Note 14 to the financial statements for discussion of the impairments.

Following are key performance measures for Entergy Wholesale Commodities for 2016 and 2015.
 
2016
 
2015
Owned capacity (MW) (a)
4,800
 
4,880
GWh billed
35,881
 
39,745
 
 
 
 
Entergy Wholesale Commodities Nuclear Fleet
 
 
 
Capacity factor
87%
 
91%
GWh billed
33,551
 
35,859
Average energy and capacity revenue per MWh
$47.31
 
$50.29
Refueling Outage Days:
 
 
 
Indian Point 2
102
 
—
Indian Point 3
—
 
23
Palisades
—
 
32
Pilgrim
—
 
34

(a)
The reduction in owned capacity is due to Entergy’s sale of its 50% membership interest in Top Deer Wind Ventures, LLC in November 2016. See Note 14 to the financial statements for discussion of the sale.

Other Income Statement Items

Utility

Other operation and maintenance expenses decreased from $2,443 million for 2015 to $2,360 million for 2016 primarily due to:

•
a decrease of $78 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit 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 include 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;
•
the deferral in 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

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amortized over a ten-year period beginning March 2016. See Note 2 to the financial statements for further discussion of the rate case settlement; and
•
a decrease of $13 million in energy efficiency costs, including the effects of true-ups to energy efficiency filings for fixed costs to be collected from customers and incentives recognized as a result of participation in energy efficiency programs.

The decrease was partially offset by an increase of $61 million in nuclear generation expenses primarily due to higher nuclear labor costs, including contract labor, and an overall higher scope of work done during plant outages in 2016 as compared to prior year.

The asset write-offs, impairments, and related charges variance is due to the following activity:

•
the $45 million ($28 million net-of-tax) write-off in 2015 to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery; and
•
the $23.5 million ($15.3 million net-of-tax) write-off in 2015 of the regulatory asset associated with the Spindletop gas storage facility as a result of the approval of the System Agreement termination settlement agreement.

See Note 2 to the financial statements for further discussion of the asset write-offs.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Union Power Station purchased in March 2016, partially offset by the effects of recording the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $11 million in 2016 of spent nuclear fuel storage costs previously recorded as depreciation. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

Other expenses increased primarily due to an increase in nuclear refueling outage expenses as a result of amortization of higher costs associated with refueling outages and increases in decommissioning expenses in 2016 primarily due to revised decommissioning cost studies in 2015 for Grand Gulf and Waterford 3.

Entergy Wholesale Commodities

Other operation and maintenance expenses increased from $899 million for 2015 to $915 million for 2016 primarily due to:

•
an increase of $60 million in severance and retention costs related to the planned shutdown or sale of the Pilgrim and FitzPatrick plants. See “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;
•
$41 million associated with preparing to refuel FitzPatrick in January 2017. Exelon reimbursed Entergy for these costs in accordance with the reimbursement agreement discussed in “Entergy Wholesale Commodities Exit From the Merchant Power Business - Sale of FitzPatrick” below; and
•
an increase of $26 million in costs related to Pilgrim’s response to a planned NRC enhanced inspection as a result of the NRC placing Pilgrim in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix in September 2015. See Note 8 to the financial statements for further discussion of the NRC’s decision and Pilgrim’s response.

The increase was partially offset by:

•
the effects of recording the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $60 million in 2016 compared to the reimbursement of approximately $2 million in 2015 of spent nuclear fuel storage costs

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previously recorded as other operation and maintenance expenses. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;
•
a decrease of $32 million as a result of the sale of the Rhode Island State Energy Center in December 2015. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale; and
•
a decrease of $21 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.

The asset write-offs, impairments, and related charges variance is due to $2,836 million ($1,829 million net-of-tax) in 2016 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, partially offset by $2,036 million ($1,317 million net-of-tax) in 2015 of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ FitzPatrick, Pilgrim, and Palisades plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of these charges.

Depreciation and amortization expenses decreased primarily due to:

•
decreases in depreciable asset balances as a result of the impairments of the FitzPatrick, Pilgrim, and Palisades plants. See Note 14 to the financial statements for further discussion of the impairments;
•
the effects of recording the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $15 million in 2016 compared to the reimbursement of approximately $4 million in 2015 of spent nuclear fuel storage costs previously recorded as depreciation. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
•
a decrease in depreciable asset balances as a result of the sale of the Rhode Island State Energy Center in December 2015. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale.

The gain on sale of asset resulted from the sale in December 2015 of the 583 MW Rhode Island State Energy Center in Johnston, Rhode Island, a business wholly-owned by Entergy in the Entergy Wholesale Commodities segment. Entergy sold the Rhode Island State Energy Center for approximately $490 million and realized a pre-tax gain of $154 million on the sale. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale.

Other expenses decreased primarily due to the reduction in deferred refueling outage amortization costs related to the impairments of the FitzPatrick, Pilgrim, and Palisades plants and related assets, partially offset by increases in decommissioning expenses primarily as a result of a trust transfer agreement Entergy entered into with NYPA in August 2016 to transfer the decommissioning trusts and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy and a revision to the estimated decommissioning cost liability for the Entergy Wholesale Commodities’ Pilgrim plant as a result of a revised decommissioning cost study in 2015. See Note 14 to the financial statements for further discussion of the impairments and related charges and Note 9 to the financial statements for further discussion of nuclear decommissioning costs.

Income Taxes

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


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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.

The effective income tax rate for 2015 was 80.4%.  The difference in the effective income tax rate versus the statutory rate of 35% for 2015 was primarily due to the tax effects of the Louisiana business combination. See Note 3 to the financial statements for further discussion of the tax effects of the Louisiana business combination.

Income Tax Legislation

On December 22, 2017, President Trump signed into law H.R. 1, also known as 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 is effective January 1, 2018. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 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 proceedings commenced or other responses by Entergy’s regulators to the Act.

On a going forward basis, after going through the appropriate regulatory processes Entergy expects the Act to reduce its operating cash flows because the lower federal corporate income tax rate will result in lower income tax expense collected in revenues and as excess deferred income taxes are returned to customers. In general, 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 expects to finance its incremental cash requirements as a consequence of these changes through a combination of Registrant Subsidiary debt and Entergy Corporation debt and equity. Entergy Corporation expects the equity portion of this financing to be approximately $1 billion, and currently expects to issue all of this equity before the end of 2019. It is expected that certain credit metrics that incorporate operating cash flows or debt outstanding will be adversely affected by the effects of the Act.

The amount and timing of the earnings and cash effects of the Act and the financing of the incremental cash requirements will depend upon regulatory treatment of the effects of the Act. The Registrant Subsidiaries will work directly with their respective regulators to determine the appropriate path forward in each jurisdiction. Potential regulatory options that may be considered include:

•
determining the period over which certain income tax benefits are provided to customers;
•
accelerating depreciation or amortization for certain assets or asset classes; and
•
increasing or modifying capital investments.

Entergy Wholesale Commodities Exit from the Merchant Power Business

Entergy management has undertaken a strategy 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. Assumptions regarding the operating life of the plants and the decommissioning timeline and process continue to be evaluated.  Changes to current assumptions 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 could result in an increase in operating expense in the period of a revision. 

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Assumptions regarding the possibility that a plant may have an operating life shorter than previously assumed will likely 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 includes the ownership of the following nuclear reactors:

 
 
Location
 
Market
 
Capacity
 
Planned Transaction
Vermont Yankee
 
Vernon, VT
 
ISO-NE
 
605 MW
 
Plant in decommissioning phase, planned sale in 2018
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 the FitzPatrick nuclear power plant to Exelon in March 2017. 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. In addition, Entergy Wholesale Commodities 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 Planned 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 is the owner of the Vermont Yankee plant and is in the Entergy Wholesale Commodities segment. The sale of Entergy Nuclear Vermont Yankee to NorthStar will include the transfer of the nuclear decommissioning trust fund and the asset retirement obligation for the spent fuel management and decommissioning of the plant.

Entergy Nuclear Vermont Yankee has an outstanding credit facility with borrowing capacity of $145 million to pay for dry fuel storage costs. This credit facility is guaranteed by Entergy Corporation. At or before closing, a subsidiary of Entergy will assume the obligations under the existing credit facility or enter into a new credit facility, and Entergy will guarantee the credit facility. At the closing of the sale transaction, NorthStar will pay $1,000 for the membership interests in Entergy Nuclear Vermont Yankee, and NorthStar will cause Entergy Nuclear Vermont Yankee to issue a promissory note to an Entergy affiliate. The amount of the promissory note issued will be equal to the amount drawn under the credit facility or the amount drawn under the new credit facility, plus borrowing fees and costs incurred by Entergy in connection with such facility. The principal amount drawn under the outstanding credit facility was $104 million as of December 31, 2017, and the net book value of Entergy Nuclear Vermont Yankee, including unrealized gains on the decommissioning trust fund, as of December 31, 2017, was approximately $123 million.

Entergy plans to transfer all spent nuclear fuel to dry cask storage by the end of 2018 in advance of the planned transaction close. Under the sale agreement and related agreements to be entered into at the closing, NorthStar will commit to initiate decommissioning and site restoration by 2021 and complete those activities by 2030. The original planned completion date, as outlined in Entergy’s Post Shutdown Decommissioning Activities Report filed with the NRC, was 2075. Entergy Nuclear Vermont Yankee, under NorthStar ownership, will be required to repay the promissory note issued to Entergy with certain of the proceeds from the recovery of damages under its claims against the DOE related to spent nuclear fuel disposal, with any balance remaining due at partial site release, subject to extension not to exceed two years from partial site release.

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The transaction is subject to certain closing conditions, including approval by the NRC; approval by the State of Vermont Public Utility Commission, including approval of site restoration standards that have been proposed as part of the transaction; the transfer of all spent nuclear fuel to dry fuel storage on the independent spent fuel storage installation; and that the market value of the fund assets held in the decommissioning trust fund for the Vermont Yankee Nuclear Power Station, less the hypothetical income tax on the aggregate unrealized net gain of such fund assets at closing, is equal to or exceeds $451.95 million, subject to adjustments. Entergy has the option to contribute to the decommissioning trust fund if the value is less than $451.95 million, subject to adjustments. The transaction is planned to close by the end of 2018.

Sale of Rhode Island State Energy Center

In December 2015, Entergy sold the Rhode Island State Energy Center, a 583 MW natural gas-fired combined-cycle generating plant owned by Entergy in the Entergy Wholesale Commodities segment. Entergy sold the Rhode Island State Energy Center for approximately $490 million and realized a pre-tax gain of $154 million on the sale.

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. See Note 14 to the financial statements for discussion of the impairment charges associated with the decision to cease operations earlier than expected.

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 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 asset retirement obligations are accreted monthly through a charge to decommissioning expense. The decommissioning trust funds for the Indian Point 3 and FitzPatrick plants were transferred to Entergy by NYPA in January 2017. See Note 9 to the financial statements for further discussion of Indian Point 3 and FitzPatrick’s decommissioning liabilities and see Note 16 to the financial statements for further discussion of the receivables for the beneficial interests in Indian Point 3 and FitzPatrick’s decommissioning trust funds as of December 31, 2016.

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

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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. 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

Indian Point 2 and Indian Point 3 have been involved, and have faced opposition, in extensive licensing proceedings. 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. See further discussion of the licensing proceedings and the settlement reached with New York State in “Entergy Wholesale Commodities Authorizations to Operate Indian Point” below.

As discussed above, in August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust fund and decommissioning liability for the Indian Point 3 plant to Entergy. The decommissioning trust fund for the Indian Point 3 plant was transferred to Entergy by NYPA in January 2017.

See Note 14 to the financial statements for further discussion of the impairment charges associated with management’s evaluation of alternatives to the continued operation of 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 change in 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

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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 liability amortization associated with the PPA and discussion of the impairment charges associated with the decision to cease operations earlier than expected.

Costs Associated with Entergy Wholesale Commodities Strategic Transactions

Entergy incurred approximately $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 $165 million in 2018, and approximately $205 million from 2019 through mid-2022 associated with these strategic transactions. See Note 13 to the financial statements for further discussion of these costs.

In 2017, Entergy Wholesale Commodities incurred impairment charges related to nuclear fuel spending, nuclear refueling outage spending, and expenditures for capital assets of $0.5 billion. 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.

Entergy Wholesale Commodities Authorizations to Operate Indian Point

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. The original expiration dates of the NRC operating licenses for Indian Point 2 and Indian Point 3 were in September 2013 and December 2015, respectively. While the NRC staff reviews the license renewal applications, Indian Point 2 and Indian Point 3’s initial license terms have expired and the plants are operating under “timely renewal,” which is a federal statutory rule of general applicability providing for extension of a license for which a renewal application has been timely filed with the licensing agency.

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. See Note 14 to the financial statements for a discussion of the impairment and related charges associated with the settlement with New York State.

The Indian Point settlement required New York State agencies to issue environmental certifications needed for license renewal and a renewed water discharge permit based on current plant configuration. It also required the New York State Attorney General and Riverkeeper to withdraw their contentions pending before the Atomic Safety and Licensing Board (ASLB). In exchange, Entergy commits to cease commercial operation of Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021. These actions have been completed, all New York State approvals required for the NRC to issue renewed licenses have been granted, and the ASLB has terminated proceedings before it following the withdrawal of pending contentions. The NRC is not expected to issue renewed licenses earlier than third quarter 2018, as its staff must complete updates to the record on environmental and safety matters (a supplement to the final supplemental environmental impact statement and a supplement to the final safety evaluation report).

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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 accordance with the FERC-approved tariff of the New York Independent System Operator (NYISO), Entergy submitted to the NYISO a notice of generator deactivation based on the dates in the settlement (no later than April 30, 2020 for Indian Point Unit 2 and April 30, 2021 for Indian Point Unit 3). In December 2017, NYISO issued a report stating there will not be a system reliability need following the deactivation of Indian Point. The NYISO also has advised that it will perform an analysis of the potential competitive impacts of the proposed retirement under provisions of its tariff. The deadline for the NYISO to make a withholding determination is in dispute and is pending before the FERC.

In addition to contractually agreeing to cease commercial operations early, in February 2017 Entergy filed with the NRC an amendment to its license renewal application changing the term of the requested licenses to coincide with the latest possible extension by mutual agreement based on exigent reliability needs: April 30, 2024 for Indian Point 2 and April 30, 2025 for Indian Point 3. If Entergy reasonably determines that the NRC will treat the amendment other than as a routine amendment, Entergy may withdraw the amendment.

Other provisions of the settlement include termination of all then-existing investigations of Indian Point by the agencies signing the agreement, which include the New York State Department of Environmental Conservation, the New York State Department of State, the New York State Department of Public Service, the New York State Department of Health, and the New York State Attorney General. The settlement recognizes the right of New York State agencies to pursue new investigations and enforcement actions with respect to new circumstances or existing conditions that become materially exacerbated.

Another provision of the settlement obligates Entergy to establish a $15 million fund for environmental projects and community support. Apportionment and allocation of funds to beneficiaries are to be determined by mutual agreement of New York State and Entergy. The settlement recognizes New York State’s right to perform an annual inspection of Indian Point, with scope and timing to be determined by mutual agreement.

In May 2017 a plaintiff filed two parallel state court appeals challenging New York State’s actions in signing and implementing the Indian Point settlement with Entergy on the basis that the State failed to perform sufficient environmental analysis of its actions. All signatories to the settlement agreement, including the Entergy affiliates that hold NRC licenses for Indian Point, were named. The appeals were voluntarily dismissed in November 2017.

Liquidity and Capital Resources

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

Capital Structure

Entergy’s capitalization is balanced between equity and debt, as shown in the following table. The increase in the debt to capital ratio for Entergy as of December 31, 2017 is primarily due to an increase in commercial paper outstanding in 2017 as compared to 2016.
 
2017
 
2016
Debt to capital
67.1%
 
64.8%
Effect of excluding securitization bonds
(0.8%)
 
(1.0%)
Debt to capital, excluding securitization bonds (a)
66.3%

63.8%
Effect of subtracting cash
(1.1%)
 
(2.0%)
Net debt to net capital, excluding securitization bonds (a)
65.2%

61.8%

(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.

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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, 2017. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2017. 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
 
2018
 
2019
 
2020
 
2021-2022
 
after 2022
 
 
(In Millions)
Utility
 

$1,427

 

$1,430

 

$927

 

$2,234

 

$15,102

Entergy Wholesale Commodities
 
3

 
3

 
106

 
—

 
—

Parent and Other
 
76

 
76

 
520

 
953

 
832

Total
 

$1,506

 

$1,509

 

$1,553

 

$3,187

 

$15,934


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 August 2022. The facility permits 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, 2017 was 2.55% on the drawn portion of the facility.

As of December 31, 2017, amounts outstanding and capacity available under the $3.5 billion credit facility are:
Capacity
 
Borrowings
 
Letters of Credit
 
Capacity Available
(In Millions)
$3,500
 
$210
 
$6
 
$3,284

A covenant in Entergy Corporation’s credit facility requires Entergy to maintain a consolidated debt ratio, as defined, of 65% or less of its total capitalization.  The calculation of this debt ratio under Entergy Corporation’s credit facility is different than the calculation of the debt to capital ratio above. One such difference is that it excludes the effects, among other things, of certain impairments related to the Entergy Wholesale Commodities nuclear generation assets. Entergy is currently in compliance with the covenant and expects to remain in compliance with this covenant. If Entergy fails to meet this ratio, or if Entergy or one of the Utility operating companies (except Entergy New Orleans) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the Entergy Corporation credit facility’s maturity date may occur.


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Entergy Corporation has a commercial paper program with a Board-approved program limit of up to $2 billion.  As of December 31, 2017, Entergy Corporation had $1.467 billion of commercial paper outstanding.  The weighted-average interest rate for the year ended December 31, 2017 was 1.49%.

Capital lease obligations are a minimal part of Entergy’s overall capital structure. Following are Entergy’s payment obligations under those leases.
 
2018
 
2019
 
2020
 
2021-2022
 
after 2022
 
(In Millions)
Capital lease payments
$3
 
$3
 
$3
 
$6
 
$19

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, 2017 as follows:
Company
 
Expiration Date
 
Amount of Facility
 
Interest Rate (a)
 
Amount Drawn
 as of December 31, 2017
 
Letters of Credit Outstanding as of December 31, 2017
Entergy Arkansas
 
April 2018
 
$20 million (b)
 
2.82%
 
—
 
—
Entergy Arkansas
 
August 2022
 
$150 million (c)
 
2.82%
 
—
 
—
Entergy Louisiana
 
August 2022
 
$350 million (c)
 
2.82%
 
—
 
$9.1 million
Entergy Mississippi
 
May 2018
 
$10 million (d)
 
3.07%
 
—
 
—
Entergy Mississippi
 
May 2018
 
$20 million (d)
 
3.07%
 
—
 
—
Entergy Mississippi
 
May 2018
 
$35 million (d)
 
3.07%
 
—
 
—
Entergy Mississippi
 
May 2018
 
$37.5 million (d)
 
3.07%
 
—
 
—
Entergy New Orleans
 
November 2018
 
$25 million (c)
 
3.04%
 
—
 
$0.8 million
Entergy Texas
 
August 2022
 
$150 million (c)
 
3.07%
 
—
 
$25.6 million

(a)
The interest rate is the estimated interest rate as of December 31, 2017 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 permits 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, 2017:

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Company
 
 
Amount of Uncommitted Facility
 
Letter of Credit Fee
 
Letters of Credit Issued as of December 31, 2017 (a)
Entergy Arkansas
 
 
$25 million
 
0.70%
 
$1.0 million
Entergy Louisiana
 
 
$125 million
 
0.70%
 
$29.7 million
Entergy Mississippi
 
 
$40 million
 
0.70%
 
$15.3 million
Entergy New Orleans
 
 
$15 million
 
1.00%
 
$1.4 million
Entergy Texas
 
 
$50 million
 
0.70%
 
$22.8 million
(a)
As of December 31, 2017, letters of credit posted with MISO covered financial transmission right exposure of $0.2 million for Entergy Arkansas, $0.1 million for Entergy Mississippi, and $0.05 million for Entergy Texas. See Note 15 to the financial statements for discussion of financial transmission rights.

Entergy Nuclear Vermont Yankee has a credit facility guaranteed by Entergy Corporation with a borrowing capacity of $145 million that expires in November 2020. As of December 31, 2017, $104 million in cash borrowings were outstanding under the credit facility.  The weighted average interest rate for the year ended December 31, 2017 was 2.64% on the drawn portion of the facility.  Entergy Nuclear Vermont Yankee also had an uncommitted credit facility guaranteed by Entergy Corporation with a borrowing capacity of $85 million that expired in January 2018. As of December 31, 2017, there were no cash borrowings outstanding under the credit facility. See Note 4 to the financial statements for additional discussion of the Vermont Yankee credit facilities.
    
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, 2017 on non-cancelable operating leases with a term over one year:
 
2018
 
2019
 
2020
 
2021-2022
 
after 2022
 
(In Millions)
Operating lease payments
$80
 
$83
 
$67
 
$102
 
$97

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

Summary of Contractual Obligations of Consolidated Entities

Contractual Obligations
 
2018
 
2019-2020
 
2021-2022
 
after 2022
 
Total
 
 
(In Millions)
Long-term debt (a)
 

$1,506

 

$3,062

 

$3,187

 

$15,934

 

$23,689

Capital lease payments (b)
 

$3

 

$6

 

$6

 

$19

 

$34

Operating leases (b) (c)
 

$80

 

$150

 

$102

 

$97

 

$429

Purchase obligations (d)
 

$1,394

 

$2,485

 

$1,992

 

$4,728

 

$10,599


(a)
Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.
(b)
Lease obligations are discussed in Note 10 to the financial statements.
(c)
Does not include power purchase agreements that are accounted for as leases that are included in purchase obligations.
(d)
Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services.  Almost all of the total are fuel and purchased power obligations.


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In addition to the contractual obligations stated above, Entergy currently expects to contribute approximately $352.1 million to its pension plans and approximately $52.3 million to other postretirement plans in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018. 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 $916 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.

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 2018 through 2020.
Planned construction and capital investments
 
2018
 
2019
 
2020
 
 
(In Millions)
Utility:
 
 
 
 
 
 
Generation
 

$1,590

 

$1,410

 

$1,245

Transmission
 
990

 
865

 
735

Distribution
 
860

 
1,030

 
945

Utility Support
 
480

 
335

 
375

Total
 
3,920

 
3,640

 
3,300

Entergy Wholesale Commodities
 
245

 
75

 
35

Total
 

$4,165

 

$3,715

 

$3,335


Planned construction and capital investments refer to amounts Entergy plans to spend on routine capital projects that are necessary to support reliability of its service, equipment, or systems and to support normal customer growth, 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, New Orleans Power Station, and Montgomery County Power Station, each discussed below, and potential construction of additional generation.
•
Entergy Wholesale Commodities investments associated with specific investments such as component replacements, software and security, and dry cask storage.

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•
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 estimated 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.

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 application included an updated cost estimate of $232 million for the 226 MW advanced combustion turbine. 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 testimony filed subsequent to Entergy New Orleans’s supplemental and amending application, several intervenors oppose City Council approval of either alternative, while the City Council advisors and one intervenor support the smaller alternative. A contested hearing was held in December 2017 and post-hearing briefs were filed in January 2018. In February 2018 the City Council Utility Committee adopted a resolution approving construction of the 128 MW unit. The full City Council is expected

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to vote on the resolution in March 2018. The commercial operation date is dependent on the alternative selected by the City Council and the receipt of other permits and approvals.

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.

Washington Parish Energy Center

In April 2017, Entergy Louisiana signed a purchase and sale agreement with a subsidiary of Calpine Corporation for the acquisition 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 in 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. A procedural schedule has been established, with the deadlines recently extended and the hearing continued from March 2018 until June 2018 in order to allow the parties an opportunity to reach settlement.

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 2018 meeting, the Board declared a dividend of $0.89 per share. Entergy paid $629 million in 2017, $612 million in 2016, and $599 million in 2015 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.


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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, 2017, $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 ($781 million as of December 31, 2017);
•
securities issuances;
•
bank financing under new or existing facilities or commercial paper; and
•
sales of assets.

Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future.

Provisions within the articles of incorporation relating to preferred stock of certain of Entergy Corporation’s subsidiaries could restrict the payment of cash dividends or other distributions on their common and preferred stock. All debt and common and preferred equity issuances by the Registrant Subsidiaries require prior regulatory approval and their preferred equity and debt issuances are also subject to issuance tests set forth in corporate charters, 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, except securities with maturities longer than one year issued by Entergy Arkansas, which is subject to the jurisdiction of the APSC. The City Council has concurrent jurisdiction over Entergy New Orleans’s securities issuances with maturities longer than one year. No regulatory approvals are necessary for Entergy Corporation to issue securities. The current FERC-authorized short-term borrowing limits are effective through October 2019. Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through October 2019. Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2018. Entergy New Orleans also has obtained long-term financing authorization from the City Council that extends through June 2018. Entergy Arkansas, Entergy Louisiana, and System Energy each have obtained long-term financing authorizations from the FERC that extend through October 2019 for issuances by its respective nuclear fuel company variable interest entity. In addition to borrowings from commercial banks, the Registrant Subsidiaries may also borrow from the Entergy System money pool and from other internal short-term borrowing arrangements. The money pool 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.


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Cash Flow Activity

As shown in Entergy’s Consolidated Statements of Cash Flows, cash flows for the years ended December 31, 2017, 2016, and 2015 were as follows:
 
2017
 
2016
 
2015
 
(In Millions)
Cash and cash equivalents at beginning of period

$1,188

 

$1,351

 

$1,422

 


 
 
 
 
Net cash provided by (used in):
 

 
 

 
 

Operating activities
2,624

 
2,999

 
3,291

Investing activities
(3,841
)
 
(3,850
)
 
(2,609
)
Financing activities
810

 
688

 
(753
)
Net decrease in cash and cash equivalents
(407
)
 
(163
)
 
(71
)
 
 
 
 
 
 
Cash and cash equivalents at end of period

$781

 

$1,188

 

$1,351


Operating Activities

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, excluding the effect of 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;
•
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. See Note 3 to the financial statements for a discussion of the income tax audit;
•
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

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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.

2016 Compared to 2015

Net cash flow provided by operating activities decreased by $292 million in 2016 primarily due to:

•
a decrease due to the timing of recovery of fuel and purchased power costs in 2016 as compared to 2015. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;
•
lower Entergy Wholesale Commodities net revenue in 2016 as compared to 2015, as discussed previously; and
•
an increase of $83 million in interest paid in 2016 as compared to 2015 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 and an increase in interest expense primarily due to 2016 net debt issuances by various Utility operating companies, partially offset by a decrease in interest paid in 2016 on the Grand Gulf sale-leaseback obligation. 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 for details of the Grand Gulf lease obligation. See Note 5 to the financial statements for a discussion of long-term debt.

The decrease was partially offset by:

•
higher Utility net revenues in 2016 as compared to 2015, as discussed above;
•
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;
•
a decrease of $46 million in spending on nuclear refueling outages in 2016 as compared to 2015; and
•
a decrease of $19 million in spending related to the shutdown of Vermont Yankee, which ceased power production in December 2014.

Investing Activities

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;

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•
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.

2016 Compared to 2015

Net cash flow used in investing activities increased by $1,241 million in 2016 primarily due to:

•
the purchase of the Union Power Station for approximately $949 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;
•
proceeds of approximately $490 million from the sale in December 2015 of Rhode Island State Energy Center. See Note 14 to the financial statements for further discussion of the sale; and
•
an increase of $279 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 $114 million in transmission construction expenditures primarily due to an overall higher scope of work performed on transmission projects in 2016 as compared to 2015, an increase of $106 million in nuclear construction expenditures primarily due to a higher scope of work on various nuclear projects in 2016 as compared to 2015, an increase of $95 million in fossil-fueled generation construction expenditures primarily due to spending on the St. Charles Power Station project in 2016, an increase of $79 million in distribution construction expenditures primarily due to a higher scope of non-storm related work performed in 2016 as compared to the same period in 2015 and higher storm restoration spending in 2016, and an increase of $65 million in information technology construction expenditures due to various information technology projects and upgrades in 2016. The increase was partially offset by a decrease of $148 million in spending related to compliance with NRC post-Fukushima requirements in the Utility and Entergy Wholesale Commodities businesses.

The increase was partially offset by:

•
a decrease of $179 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;
•
an increase of $151 million in proceeds received from the DOE in 2016 as compared to the prior year resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;
•
a $71 million NYPA value sharing payment in 2015. See Note 14 to the financial statements for further discussion of Entergy’s NYPA value sharing agreements; and
•
the deposit of $64 million into Entergy New Orleans’s storm reserve escrow accounts in 2015.

Financing Activities

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%

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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;
•
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. Included in the long-term debt activity is $490 million in 2017 and $135 million in 2016 for the repayment of borrowings on the Entergy Corporation long-term credit facility.

2016 Compared to 2015

Entergy’s financing activities provided $688 million of cash for 2016 compared to using $753 million of cash for 2015 primarily due to the following activity:

•
long-term debt activity providing approximately $1,489 million of cash in 2016 compared to providing $41 million of cash in 2015.  Included in the long-term debt activity is net repayments of borrowings of $135 million in 2016 compared to net borrowings of $140 million in 2015 on the Entergy Corporation long-term credit facility;
•
the issuance of $110 million of preferred stock in 2015. See Note 6 to the financial statements for further discussion;
•
$100 million of common stock repurchased in 2015, as discussed above;
•
a net increase of $41 million in 2016 in short-term borrowings by the nuclear fuel company variable interest entities; and
•
a decrease of $21 million resulting from higher repurchase/redemptions of preferred stock. In September 2015, Entergy Louisiana redeemed its $100 million 6.95% Series preferred membership interests, of which $16 million was owned by Entergy Louisiana Holdings, an Entergy subsidiary, and Entergy Gulf States Louisiana repurchased its $10 million Series A 8.25% preferred membership interests as part of a multi-step process to effectuate the Entergy Louisiana and Entergy Gulf States Louisiana business combination.  See Note 2 to the financial statements for a discussion of the combination. 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.

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:

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Company
 
Authorized Return on Common Equity
 
 
 
Entergy Arkansas
 
9.25% - 10.25%
Entergy Louisiana
 
9.15% - 10.75% Electric; 9.45% - 10.45% Gas
Entergy Mississippi
 
9.47% - 11.49%
Entergy New Orleans
 
10.7% - 11.5% Electric; 10.25% - 11.25% Gas
Entergy Texas
 
9.8%

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 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 System Agreement proceedings, a complaint filed with the FERC challenging System Energy’s return on equity, and System Energy’s proposed amendments to the Unit Power Sales Agreement.

Market and Credit Risk Sensitive Instruments

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

•
The commodity price risk associated with the sale of electricity by the Entergy Wholesale Commodities business.
•
The interest rate and equity price risk associated with Entergy’s investments in pension and other postretirement benefit trust funds.  See Note 11 to the financial statements for details regarding Entergy’s pension and other postretirement benefit trust funds.
•
The interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds, particularly in the Entergy Wholesale Commodities business.  See Note 16 to the financial statements for details regarding Entergy’s decommissioning trust funds.
•
The interest rate risk associated with changes in interest rates as a result of Entergy’s outstanding indebtedness.  Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to total capitalization.  See Notes 4 and 5 to the financial statements for the details of Entergy’s debt outstanding.

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


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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 also uses a combination of financial contracts, including swaps, collars, and options, to manage forward commodity price risk.  Certain hedge volumes have price downside and upside relative to market price movement.  The contracted minimum, expected value, and sensitivities are provided in the table below to show potential variations.  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, 2017.


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Entergy Wholesale Commodities Nuclear Portfolio

 
 
2018
 
2019
 
2020
 
2021
 
2022
Energy
 
 
 
 
 
 
 
 
 
 
Percent of planned generation under contract (a):
 
 
 
 
 
 
 
 
 
 
Unit-contingent (b)
 
98%
 
91%
 
51%
 
74%
 
67%
Firm LD (c)
 
9%
 
—%
 
—%
 
—%
 
—%
Offsetting positions (d)
 
(9%)
 
—%
 
—%
 
—%
 
—%
Total
 
98%
 
91%
 
51%
 
74%
 
67%
Planned generation (TWh) (e) (f)
 
27.9
 
25.5
 
17.9
 
9.7
 
2.8
Average revenue per MWh on contracted volumes:
 
 
 
 
 
 
 
 
 
 
Expected based on market prices as of December 31, 2017
 
$39.1
 
$40.6
 
$50.5
 
$59.2
 
$58.8
 
 
 
 
 
 
 
 
 
 
 
Capacity
 
 
 
 
 
 
 
 
 
 
Percent of capacity sold forward (g):
 
 
 
 
 
 
 
 
 
 
Bundled capacity and energy contracts (h)
 
22%
 
25%
 
36%
 
69%
 
99%
Capacity contracts (i)
 
36%
 
13%
 
—%
 
—%
 
—%
Total
 
58%
 
38%
 
36%
 
69%
 
99%
Planned net MW in operation (average) (f)
 
3,568
 
3,167
 
2,195
 
1,158
 
338
Average revenue under contract per kW per month (applies to capacity contracts only)
 
$7.1
 
$9.1
 
$—
 
$—
 
$—
 
 
 
 
 
 
 
 
 
 
 
Total Energy and Capacity Revenues (j)
 
 
 
 
 
 
 
 
 
 
Expected sold and market total revenue per MWh
 
$47.0
 
$46.9
 
$48.9
 
$56.1
 
$47.8
Sensitivity: -/+ $10 per MWh market price change
 
$46.9 - $47.2
 
$46.0 - $47.8
 
$44.3 - $53.5
 
$53.5 - $58.7
 
$44.5 - $51.1

(a)
Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts, or options that mitigate price uncertainty that may require regulatory approval or approval of transmission rights. 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 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)
Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, defaulting party must compensate the other party as specified in the contract, a portion of which may be capped through the use of risk management products. This also includes option transactions that may expire without being exercised.
(d)
Transactions for the purchase of energy, generally to offset a Firm LD transaction.
(e)
Amount of output expected to be generated by Entergy Wholesale Commodities resources considering plant operating characteristics, outage schedules, and expected market conditions that affect dispatch.
(f)
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,

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2022. Assumes NRC license renewals for two units, as follows (with current license expirations in parentheses): Indian Point 2 (September 2013 and now operating under its period of extended operations while its application is pending) and Indian Point 3 (December 2015 and now operating under its period of extended operations while its application is pending). 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. For a discussion regarding the license renewals for Indian Point 2 and Indian Point 3, see “Entergy Wholesale Commodities Authorizations to Operate Indian Point” above.
(g)
Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions.
(h)
A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold.
(i)
A contract for the sale of an installed capacity product in a regional market.
(j)
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 conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax income of $3 million in 2018 and would have had a corresponding effect on pre-tax income of $37 million in 2017. 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 ($3) million in 2018 and would have had a corresponding effect on pre-tax income of ($31) million in 2017.

Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA.  In October 2007, Entergy subsidiaries and NYPA amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms.  Under the amended value sharing agreements, Entergy subsidiaries made annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014.  Entergy subsidiaries paid NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual cap of $24 million.  The annual payment for each year’s output was due by January 15 of the following year, and the final payment to NYPA was made in January 2015.  Entergy recorded the liability for payments to NYPA as power was generated and sold by Indian Point 3 and FitzPatrick.  An amount equal to the liability was recorded to the plant asset account as contingent purchase price consideration for the plants.

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 guaranty.  Cash and letters of credit are also acceptable forms of credit support.  At December 31, 2017, based on power prices at that time, Entergy had liquidity exposure of $167 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $8 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, 2017, Entergy would have been required to provide approximately $98 million of additional cash or letters of credit under some of the agreements. As of December 31, 2017, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $372 million for a $1 per MMBtu increase in gas prices in both the short- and long-term markets.  

As of December 31, 2017, 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.



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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.

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.

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.

Indian Point

During the scheduled refueling and maintenance outage at Indian Point 2 in the first quarter 2016, comprehensive inspections were done as part of the aging management program that calls for an in-depth inspection of the reactor vessel.  Inspections of more than 2,000 bolts in the reactor’s removable insert liner identified issues with roughly 11% of the bolts that required further analysis.  Entergy replaced bolts as appropriate, and the unit returned to service in June 2016. In 2016, Entergy evaluated the scope and duration of Indian Point 3’s scheduled refueling outage planned for 2017, which began in March 2017. Based on the results of the 2016 evaluation and analysis, Entergy extended Indian Point 3’s planned 2017 outage duration. Entergy performed the same in-depth inspection of the reactor vessel at Indian Point 3 during Indian Point 3’s spring 2017 refueling and maintenance outage that it performed for Indian Point 2. Based on inspection data, Entergy replaced approximately the same number of bolts at Indian Point 3 that it replaced at Indian Point 2 before returning the plant to service in May 2017.

Grand Gulf

Grand Gulf began a maintenance outage on September 8, 2016 to replace a residual heat removal pump. Although the pump had been replaced, on September 27, 2016 management decided to keep the plant in an outage for additional training and other steps to support management’s operational goals. Grand Gulf returned to service on January 31, 2017.

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. Entergy is implementing a plan to restore Grand Gulf to Column 1, including addressing the issues related to the three very low safety significance non-

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cited violations identified in the NRC’s report on the results of its October 2016 special inspection. Depending on the success of implementing that plan and the plant’s performance indicators, there is risk that the NRC could move Grand Gulf into the “degraded cornerstone column,” or Column 3, of the NRC’s Reactor Oversight Process Action Matrix.

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, as well as assumptions regarding the probability that the plant’s license will be renewed for those plants that have not yet received operating license renewal. Second, an assumption must be made whether all decommissioning activity will proceed immediately upon plant retirement, or whether the plant will be placed in SAFSTOR status. SAFSTOR is decommissioning a facility by placing it in a safe, stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation of operations. A change of assumption regarding either the probability of license renewal, the period of continued operation, or the use of a SAFSTOR period 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 3% 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.

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•
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 occur, 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 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.

Unbilled Revenue

As discussed in Note 1 to the financial statements, Entergy records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized

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during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.

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 a plant for a shorter period than previously expected; if there is a significant adverse change in the physical condition of a plant; if investment in a plant significantly exceeds previously-expected amounts; or, for Indian Point 2 and Indian Point 3, if their operating licenses are not renewed.

If an asset is considered held for use, and Entergy concludes that events and circumstances are present indicating that an impairment analysis should be performed under the accounting standards, the sum of the expected undiscounted future cash flows from the asset are compared to the asset’s carrying value.  The carrying value of the asset includes any capitalized asset retirement cost associated with the decommissioning liability; therefore, changes in assumptions that affect the decommissioning liability can increase or decrease the carrying value of the asset subject to impairment.  If the expected undiscounted future cash flows exceed the carrying value, no impairment is recorded. If the expected undiscounted future cash flows are less than the carrying value and the carrying value exceeds the fair value, Entergy is required to record an impairment charge to write the asset down to its fair value.  If an asset is considered held for sale, an impairment is required to be recognized if the fair value (less costs to sell) of the asset is less than its carrying value.

The expected future cash flows are based on a number of key assumptions, including:

•
Future power and fuel prices - Electricity and gas prices can be very volatile.  This volatility increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows.
•
Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets.  While market transactions provide evidence for this valuation, these transactions are relatively infrequent, the market for such assets is volatile, and the value of individual assets is affected by factors unique to those assets.
•
Future operating costs - Entergy assumes relatively minor annual increases in operating costs.  Technological or regulatory changes that have a significant effect on operations could cause a significant change in these assumptions.
•
Timing and the life of the asset - Entergy assumes an expected life of the asset.  A change in the timing assumption, whether due to management decisions regarding operation of the plant, the regulatory process, or operational or other factors, could have a significant effect on the expected future cash flows and result in a significant effect on operations.

See Note 14 to the financial statements for a discussion of the impairments of the Palisades, Indian Point, FitzPatrick, and Pilgrim plants.

Entergy evaluates investment 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

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present value of cash flows expected to be collected less the amortized cost basis (credit loss).  The assessment of whether an investment in an equity security has suffered an other than temporary impairment is based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time.  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.  As discussed in Note 1 to the financial statements, unrealized losses on equity securities that are considered other-than-temporarily impaired are recorded in earnings for Entergy Wholesale Commodities.  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 will be 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 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 falling 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. Before 2016 the discount rates used to estimate the service cost and interest cost components of benefit costs were the same as the weighted-average discount rate used to measure the benefit obligation at the beginning of the year. In 2016, Entergy refined its approach to estimating the service cost and interest cost components. Under the refined approach, instead of using the weighted-average benefit obligation discount rate at the beginning of the year, the 2016 service and interest costs’ expected cash flows were discounted by the applicable spot rates. The refinement had the effect of lowering 2016 qualified pension costs by $61 million and 2016 other postretirement health care and life insurance benefit costs by $15 million.

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.
Since 2003, Entergy has targeted an asset allocation for its qualified pension plan assets of roughly 65% equity securities and 35% fixed-income securities.  In 2017, Entergy confirmed the 2011 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, from its current allocation to an ultimate allocation. In 2017, Entergy adopted a new ultimate allocation for pension assets of 35% equity securities and 65% fixed income securities.  The ultimate asset allocation is expected to be attained when the plan is 105% funded.
In 2016, the target allocations for both Entergy’s non-taxable other postretirement assets and its taxable other postretirement assets were 65% equity securities and 35% fixed-income securities. During the first quarter of 2017, Entergy implemented a new asset allocation strategy, based on the funded status of each sub-account within each trust, which resulted in an overall shift to more fixed income in the non-taxable trusts and no material changes in asset allocation to the taxable 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. See Note 11 to the financial statements for discussion of the current asset allocations for Entergy’s other postretirement assets.


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Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis

Retirement and mortality rates

In October 2017 the Internal Revenue Service issued updated mortality regulations for single employer plans for determining cash contribution requirements. The regulations, based on the Society of Actuaries’ 2014 mortality table, are effective for plan years beginning on or after January 1, 2018.

Costs and Sensitivities

The estimated 2018 and actual 2017 qualified pension and other postretirement costs and related underlying assumptions and sensitivities are shown below:
Costs
 
Estimated 2018
 
2017
 
 
(In Millions)
Qualified pension cost
 
$254.8
 
$214.2
Other postretirement cost
 
$13.1
 
$25.6
 
 
 
 
 
Assumptions
 
2018
 
2017
Discount rates
 
 
 
 
Qualified pension
 
 
 
 
Service cost
 
3.89%
 
4.75%
Interest cost
 
3.44%
 
3.73%
Other postretirement
 
 
 
 
Service cost
 
3.88%
 
4.60%
Interest cost
 
3.33%
 
3.61%
 
 
 
 
 
Expected long-term rates of return
 
 
 
 
Qualified pension assets
 
7.50%
 
7.50%
Other postretirement - non-taxable assets
 
6.50% - 7.50%
 
6.50% - 6.90%
Other postretirement - taxable assets - after tax rate
 
5.50%
 
5.75%
 
 
 
 
 
Weighted-average rate of future compensation
 
3.98%
 
3.98%
 
 
 
 
 
Assumed health care cost trend rates
 
 
 
 
Pre-65 retirees
 
6.95%
 
6.55%
Post-65 retirees
 
7.25%
 
7.25%
Ultimate rate
 
4.75%
 
4.75%
Year ultimate rate is reached and beyond
 
2027
 
2026

Actual asset returns have an effect on Entergy’s qualified pension and other postretirement costs. In 2017, Entergy’s actual average annual return on qualified pension assets was approximately 16% and for other postretirement assets was approximately 14%, as compared with the 2017 expected long-term rates of return discussed above.


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Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis


The following chart reflects the sensitivity of qualified pension cost and qualified pension projected benefit obligation to changes in certain actuarial assumptions (dollars in millions):
Actuarial Assumption
 
Change in Assumption
 
Impact on 2018 Qualified Pension Cost
 
Impact on 2017 Qualified Projected Benefit Obligation
 
 
Increase/(Decrease)
Discount rate
 
(0.25%)
 
$23
 
$250
Rate of return on plan assets
 
(0.25%)
 
$15
 
$—
Rate of increase in compensation
 
0.25%
 
$7
 
$34

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 2018 Postretirement Benefit Cost
 
Impact on 2017 Accumulated Postretirement Benefit Obligation
 
 
Increase/(Decrease)
Discount rate
 
(0.25%)
 
$3
 
$50
Health care cost trend
 
0.25%
 
$5
 
$39

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 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 2017 was $410 million.  Entergy estimates pension contributions will be approximately $352.1 million in 2018; although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018.


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Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis

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 and the funding liability is based upon a weighted average 24-month corporate bond rate published by the U.S. Treasury; therefore, periodic changes in asset returns and interest rates can affect funding shortfalls and future cash contributions.

Moving Ahead for Progress in the 21st Century Act (MAP-21) became federal law in July 2012.  Under the law, the segment rates used to calculate funding liabilities must be within a corridor of the 25-year average of prior segment rates.  The interest rate corridor applies to the determination of minimum funding requirements and benefit restrictions.  These pension funding stabilization provisions provide for a near-term reduction in minimum funding requirements for single employer defined benefit plans in response to the historically low interest rates that existed when the law was enacted.  The law did not reduce contribution requirements over the long term. The interest rate stabilization periods of MAP-21 were extended by the Highway and Transportation Funding Act in 2014 and the Bipartisan Budget Act in 2015.

Entergy contributed $44.3 million to its postretirement plans in 2017 and plans to contribute $52.3 million in 2018.

Federal Healthcare Legislation

In 2010 the Patient Protection and Affordable Care Act (PPACA), as amended, imposed a 40% excise tax on per capita medical benefit costs that exceed certain thresholds. In January 2018 the effective date of the excise tax was delayed and is currently expected to take effect in 2022.  Entergy will continue to monitor developments to determine the possible effect on Entergy.

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 subject it to environmental, litigation, and other risks.  Entergy periodically evaluates its exposure for such risks and records a reserve 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 and 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.

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Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis


•
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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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, 2017.

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, 2017.  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, Inc., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, LLC, Entergy Texas, Inc., and System Energy Resources, Inc.
 
RICHARD C. RILEY
Chairman of the Board, President, and Chief Executive Officer of Entergy Arkansas, Inc.
 
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, Inc.
 
CHARLES L. RICE, JR.
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










 
2017

2016

2015

2014

2013
 
(In Thousands, Except Percentages and Per Share Amounts)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$11,074,481



$10,845,645

 

$11,513,251

 

$12,494,921



$11,390,947

Net income (loss)

$425,353



($564,503
)
 

($156,734
)
 

$960,257



$730,572

Earnings (loss) per share:
 

 
 
 
 
 


 

Basic

$2.29



($3.26
)
 

($0.99
)
 

$5.24



$3.99

Diluted

$2.28



($3.26
)
 

($0.99
)
 

$5.22



$3.99

Dividends declared per share

$3.50



$3.42

 

$3.34

 

$3.32



$3.32

Return on common equity
5.12
%

(6.73
%)
 
(1.83
)%
 
9.58
%

7.56
%
Book value per share, year-end

$44.28



$45.12

 

$51.89

 

$55.83



$54.00

Total assets

$46,707,149



$45,904,434

 

$44,647,681

 

$46,414,455



$43,290,290

Long-term obligations (a)

$14,535,077



$14,695,422

 

$13,456,742

 

$12,627,180



$12,265,971
















(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.










 
2017

2016

2015

2014

2013
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
Utility electric operating revenues:
 


 


 


 


 

Residential

$3,355



$3,288



$3,518



$3,555



$3,396

Commercial
2,480


2,362


2,516


2,553


2,415

Industrial
2,584


2,327


2,462


2,623


2,405

Governmental
231


217


223


227


218

Total retail
8,650


8,194


8,719


8,958


8,434

Sales for resale
253


236


249


330


210

Other
376


437


341


304


298

Total

$9,279



$8,867



$9,309



$9,592



$8,942

 
 
 
 
 
 
 
 
 
 
Utility billed electric energy sales (GWh):





 


 


 

Residential
33,834


35,112


36,068


35,932


35,169

Commercial
28,745


29,197


29,348


28,827


28,547

Industrial
47,769


45,739


44,382


43,723


41,653

Governmental
2,511


2,547


2,514


2,428


2,412

Total retail
112,859


112,595


112,312


110,910


107,781

Sales for resale
11,550


11,054


9,274


9,462


3,020

Total
124,409


123,649


121,586


120,372


110,801

 
 
 
 
 
 
 
 
 
 
Entergy Wholesale Commodities:
 


 


 


 


 

Operating revenues

$1,657

 

$1,850

 

$2,062

 

$2,719

 

$2,313

Billed electric energy sales (GWh)
30,501

 
35,881

 
39,745

 
44,424

 
45,127




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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, 2017 and 2016, 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, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2017, 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, 2018, 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, 2018


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,
 
 
2017
 
2016
 
2015
 
 
  (In Thousands, Except Share Data)
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$9,278,895

 

$8,866,659

 

$9,308,678

Natural gas
 
138,856

 
129,348

 
142,746

Competitive businesses
 
1,656,730

 
1,849,638

 
2,061,827

TOTAL
 
11,074,481

 
10,845,645

 
11,513,251

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
1,991,589

 
1,809,200

 
2,452,171

Purchased power
 
1,427,950

 
1,220,527

 
1,390,805

Nuclear refueling outage expenses
 
168,151

 
208,678

 
251,316

Other operation and maintenance
 
3,423,689

 
3,296,711

 
3,354,981

Asset write-offs, impairments, and related charges
 
538,372

 
2,835,637

 
2,104,906

Decommissioning
 
405,685

 
327,425

 
280,272

Taxes other than income taxes
 
617,556

 
592,502

 
619,422

Depreciation and amortization
 
1,389,978

 
1,347,187

 
1,337,276

Other regulatory charges (credits) - net
 
(131,901
)
 
94,243

 
175,304

TOTAL
 
9,831,069

 
11,732,110

 
11,966,453

 
 
 
 
 
 
 
Gain on sale of asset
 
16,270

 
—

 
154,037

 
 
 
 
 
 
 
OPERATING INCOME (LOSS)
 
1,259,682

 
(886,465
)
 
(299,165
)
 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
95,088

 
67,563

 
51,908

Interest and investment income
 
288,197

 
145,127

 
187,062

Miscellaneous - net
 
(12,701
)
 
(41,617
)
 
(95,997
)
TOTAL
 
370,584

 
171,073

 
142,973

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
707,212

 
700,545

 
670,096

Allowance for borrowed funds used during construction
 
(44,869
)
 
(34,175
)
 
(26,627
)
TOTAL
 
662,343

 
666,370

 
643,469

 
 
 
 
 
 
 
INCOME (LOSS) BEFORE INCOME TAXES
 
967,923

 
(1,381,762
)
 
(799,661
)
 
 
 
 
 
 
 
Income taxes
 
542,570

 
(817,259
)
 
(642,927
)
 
 
 
 
 
 
 
CONSOLIDATED NET INCOME (LOSS)
 
425,353

 
(564,503
)
 
(156,734
)
 
 
 
 
 
 
 
Preferred dividend requirements of subsidiaries
 
13,741

 
19,115

 
19,828

 
 
 
 
 
 
 
NET INCOME (LOSS) ATTRIBUTABLE TO ENTERGY CORPORATION
 

$411,612

 

($583,618
)
 

($176,562
)
 
 
 
 
 
 
 
Earnings (loss) per average common share:
 
 

 
 

 
 

Basic
 

$2.29

 

($3.26
)
 

($0.99
)
Diluted
 

$2.28

 

($3.26
)
 

($0.99
)
 
 
 
 
 
 
 
Basic average number of common shares outstanding
 
179,671,797

 
178,885,660

 
179,176,356

Diluted average number of common shares outstanding
 
180,535,893

 
178,885,660

 
179,176,356

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 


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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
 
 
 
For the Years Ended December 31,
 
2017
 
2016
 
2015
 
(In Thousands)
 
 
 
 
 
 
Net Income (Loss)

$425,353

 

($564,503
)
 

($156,734
)
 
 
 
 
 
 
Other comprehensive income (loss)
 

 
 

 
 

Cash flow hedges net unrealized gain (loss)
 

 
 

 
 

(net of tax expense (benefit) of ($22,570), ($55,298), and $3,752)
(41,470
)
 
(101,977
)
 
7,852

Pension and other postretirement liabilities
 

 
 

 
 

(net of tax expense (benefit) of ($4,057), ($3,952), and $61,576)
(61,653
)
 
(2,842
)
 
103,185

Net unrealized investment gains (losses)
 

 
 

 
 

(net of tax expense (benefit) of $80,069, $57,277, and ($45,904))
115,311

 
62,177

 
(59,138
)
Foreign currency translation
 

 
 

 
 

(net of tax benefit of $403, $689, and $345)
(748
)
 
(1,280
)
 
(641
)
Other comprehensive income (loss)
11,440

 
(43,922
)
 
51,258

 
 
 
 
 
 
Comprehensive Income (Loss)
436,793

 
(608,425
)
 
(105,476
)
Preferred dividend requirements of subsidiaries
13,741

 
19,115

 
19,828

Comprehensive Income (Loss) Attributable to Entergy Corporation

$423,052

 

($627,540
)
 

($125,304
)
 
 
 
 
 
 
See Notes to Financial Statements.
 

 
 

 
 



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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
 
 
 
For the Years Ended December 31,
 
 
2017
 
2016
 
2015
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING ACTIVITIES
 
 
 
 
 
 
Consolidated net income (loss)
 

$425,353

 

($564,503
)
 

($156,734
)
Adjustments to reconcile consolidated net income (loss) to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 
2,078,578

 
2,123,291

 
2,117,236

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
529,053

 
(836,257
)
 
(820,350
)
Asset write-offs, impairments, and related charges
 
357,251

 
2,835,637

 
2,104,906

Gain on sale of asset
 
(16,270
)
 
—

 
(154,037
)
Changes in working capital:
 
 

 
 

 
 

Receivables
 
(97,637
)
 
(96,975
)
 
38,152

Fuel inventory
 
(3,043
)
 
38,210

 
(12,376
)
Accounts payable
 
101,802

 
174,421

 
(135,211
)
Prepaid taxes and taxes accrued
 
33,853

 
(28,963
)
 
81,969

Interest accrued
 
742

 
(7,335
)
 
(11,445
)
Deferred fuel costs
 
56,290

 
(241,896
)
 
298,725

Other working capital accounts
 
(4,331
)
 
31,197

 
(113,701
)
Changes in provisions for estimated losses
 
(3,279
)
 
20,905

 
42,566

Changes in other regulatory assets
 
595,504

 
(48,469
)
 
262,317

Changes in other regulatory liabilities
 
2,915,795

 
158,031

 
61,241

Deferred tax rate change recognized as regulatory liability / asset
 
(3,665,498
)
 
—

 
—

Changes in pensions and other postretirement liabilities
 
(130,686
)
 
(136,919
)
 
(446,418
)
Other
 
(549,977
)
 
(421,676
)
 
134,344

Net cash flow provided by operating activities
 
2,623,500

 
2,998,699

 
3,291,184

 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 

 
 

 
 

Construction/capital expenditures
 
(3,607,532
)
 
(2,780,222
)
 
(2,500,860
)
Allowance for equity funds used during construction
 
96,000

 
68,345

 
53,635

Nuclear fuel purchases
 
(377,324
)
 
(314,706
)
 
(493,604
)
Payment for purchase of plant or assets
 
(16,762
)
 
(949,329
)
 
—

Proceeds from sale of assets
 
100,000

 
—

 
487,406

Insurance proceeds received for property damages
 
26,157

 
20,968

 
24,399

Changes in securitization account
 
1,323

 
4,007

 
(5,806
)
NYPA value sharing payment
 
—

 
—

 
(70,790
)
Payments to storm reserve escrow account
 
(2,878
)
 
(1,544
)
 
(69,163
)
Receipts from storm reserve escrow account
 
11,323

 
—

 
5,916

Decrease in other investments
 
1,078

 
9,055

 
571

Litigation proceeds for reimbursement of spent nuclear fuel storage costs
 
25,493

 
169,085

 
18,296

Proceeds from nuclear decommissioning trust fund sales
 
3,162,747

 
2,408,920

 
2,492,176

Investment in nuclear decommissioning trust funds
 
(3,260,674
)
 
(2,484,627
)
 
(2,550,958
)
Net cash flow used in investing activities
 
(3,841,049
)
 
(3,850,048
)
 
(2,608,782
)
 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 


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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
 
 
 
For the Years Ended December 31,
 
 
2017
 
2016
 
2015
 
 
(In Thousands)
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Proceeds from the issuance of:
 
 
 
 
 
 
Long-term debt
 
1,809,390

 
6,800,558

 
3,502,189

Preferred stock of subsidiary
 
14,399

 
—

 
107,426

Treasury stock
 
80,729

 
33,114

 
24,366

Retirement of long-term debt
 
(1,585,681
)
 
(5,311,324
)
 
(3,461,518
)
Repurchase of common stock
 
—

 
—

 
(99,807
)
Repurchase / redemptions of preferred stock
 
(20,599
)
 
(115,283
)
 
(94,285
)
Changes in credit borrowings and commercial paper - net
 
1,163,296

 
(79,337
)
 
(104,047
)
Other
 
(7,731
)
 
(6,872
)
 
(9,136
)
Dividends paid:
 
 

 
 

 
 

Common stock
 
(628,885
)
 
(611,835
)
 
(598,897
)
Preferred stock
 
(13,940
)
 
(20,789
)
 
(19,758
)
Net cash flow provided by (used in) financing activities
 
810,978

 
688,232

 
(753,467
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net decrease in cash and cash equivalents
 
(406,571
)
 
(163,117
)
 
(71,065
)
 
 
 
 
 
 
 
Cash and cash equivalents at beginning of period
 
1,187,844

 
1,350,961

 
1,422,026

 
 
 
 
 
 
 
Cash and cash equivalents at end of period
 

$781,273

 

$1,187,844

 

$1,350,961

 
 
 
 
 
 
 
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 

 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$678,371

 

$746,779

 

$663,630

Income taxes
 

($13,375
)
 

$95,317

 

$103,589

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$56,629

 

$129,579

Temporary cash investments
 
724,644

 
1,058,265

Total cash and cash equivalents
 
781,273

 
1,187,844

Accounts receivable:
 
 

 
 

Customer
 
673,347

 
654,995

Allowance for doubtful accounts
 
(13,587
)
 
(11,924
)
Other
 
169,377

 
158,419

Accrued unbilled revenues
 
383,813

 
368,677

Total accounts receivable
 
1,212,950

 
1,170,167

Deferred fuel costs
 
95,746

 
108,465

Fuel inventory - at average cost
 
182,643

 
179,600

Materials and supplies - at average cost
 
723,222

 
698,523

Deferred nuclear refueling outage costs
 
133,164

 
146,221

Prepayments and other
 
156,333

 
193,448

TOTAL
 
3,285,331

 
3,684,268

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Investment in affiliates - at equity
 
198

 
198

Decommissioning trust funds
 
7,211,993

 
5,723,897

Non-utility property - at cost (less accumulated depreciation)
 
260,980

 
233,641

Other
 
441,862

 
469,664

TOTAL
 
7,915,033

 
6,427,400

 
 
 
 
 
PROPERTY, PLANT, AND EQUIPMENT
 
 

 
 

Electric
 
47,287,370

 
45,191,216

Property under capital lease
 
620,544

 
619,527

Natural gas
 
453,162

 
413,224

Construction work in progress
 
1,980,508

 
1,378,180

Nuclear fuel
 
923,200

 
1,037,899

TOTAL PROPERTY, PLANT AND EQUIPMENT
 
51,264,784

 
48,640,046

Less - accumulated depreciation and amortization
 
21,600,424

 
20,718,639

PROPERTY, PLANT AND EQUIPMENT - NET
 
29,664,360

 
27,921,407

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Regulatory asset for income taxes - net
 
—

 
761,280

Other regulatory assets (includes securitization property of $485,031 as of December 31, 2017 and $600,996 as of December 31, 2016)
 
4,935,689

 
4,769,913

Deferred fuel costs
 
239,298

 
239,100

Goodwill
 
377,172

 
377,172

Accumulated deferred income taxes
 
178,204

 
117,885

Other
 
112,062

 
1,606,009

TOTAL
 
5,842,425

 
7,871,359

 
 
 
 
 
TOTAL ASSETS
 

$46,707,149

 

$45,904,434

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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Table of Contents

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Currently maturing long-term debt
 

$760,007

 

$364,900

Notes payable and commercial paper
 
1,578,308

 
415,011

Accounts payable
 
1,452,216

 
1,285,577

Customer deposits
 
401,330

 
403,311

Taxes accrued
 
214,967

 
181,114

Interest accrued
 
187,972

 
187,229

Deferred fuel costs
 
146,522

 
102,753

Obligations under capital leases
 
1,502

 
2,423

Pension and other postretirement liabilities
 
71,612

 
76,942

Other
 
221,771

 
180,836

TOTAL
 
5,036,207

 
3,200,096

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
4,466,503

 
7,495,290

Accumulated deferred investment tax credits
 
219,634

 
227,147

Obligations under capital leases
 
22,015

 
24,582

Regulatory liability for income taxes-net
 
2,900,204

 
—

Other regulatory liabilities
 
1,588,520

 
1,572,929

Decommissioning and asset retirement cost liabilities
 
6,185,814

 
5,992,476

Accumulated provisions
 
478,273

 
481,636

Pension and other postretirement liabilities
 
2,910,654

 
3,036,010

Long-term debt (includes securitization bonds of $544,921 as of December 31, 2017 and $661,175 as of December 31, 2016)
 
14,315,259

 
14,467,655

Other
 
393,748

 
1,121,619

TOTAL
 
33,480,624

 
34,419,344

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
Subsidiaries’ preferred stock without sinking fund
 
197,803

 
203,185

 
 
 
 
 
 COMMON EQUITY
 
 

 
 

Common stock, $.01 par value, authorized 500,000,000 shares; issued 254,752,788 shares in 2017 and in 2016
 
2,548

 
2,548

Paid-in capital
 
5,433,433

 
5,417,245

Retained earnings
 
7,977,702

 
8,195,571

Accumulated other comprehensive loss
 
(23,531
)
 
(34,971
)
Less - treasury stock, at cost (74,235,135 shares in 2017 and 75,623,363 shares in 2016)
 
5,397,637

 
5,498,584

TOTAL
 
7,992,515

 
8,081,809

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$46,707,149

 

$45,904,434

 
 
 
 
 
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, 2017, 2016, and 2015
 
 
 
 
 
 
 
 

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, 2014

$94,000

 

$2,548

 

($5,497,526
)
 

$5,375,353

 

$10,169,657

 

($42,307
)
 

$10,101,725

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Consolidated net income (loss) (a)
19,828

 
—

 
—

 
—

 
(176,562
)
 
—

 
(156,734
)
Other comprehensive income
—

 
—

 
—

 
—

 
—

 
51,258

 
51,258

Common stock repurchases
—

 
—

 
(99,807
)
 
—

 
—

 
—

 
(99,807
)
Preferred stock repurchases / redemptions
(94,000
)
 
—

 
—

 
—

 
(285
)
 
—

 
(94,285
)
Common stock issuances related to stock plans
—

 
—

 
44,954

 
28,405

 
—

 
—

 
73,359

Common stock dividends declared
—

 
—

 
—

 
—

 
(598,897
)
 
—

 
(598,897
)
Preferred dividend requirements of subsidiaries (a)
(19,828
)
 
—

 
—

 
—

 
—

 
—

 
(19,828
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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) (a)
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 (a)
(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 (a)
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 (a)
(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

 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 

 
 

 
 

 
 

(a) Consolidated net income and preferred dividend requirements of subsidiaries include $13.7 million for 2017, $19.1 million for 2016, and $14.9 million for 2015 of preferred dividends on subsidiaries’ preferred stock without sinking fund that is not presented as equity.

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ENTERGY CORPORATION AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS

NOTE 1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
  
The accompanying consolidated financial statements include the accounts of Entergy Corporation and its subsidiaries.  As required by generally accepted accounting principles in the United States of America, all intercompany transactions have been eliminated in the consolidated financial statements.  Entergy’s Registrant Subsidiaries (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy) also include their separate financial statements in this Form 10-K.  The Registrant Subsidiaries and many other Entergy subsidiaries also maintain accounts in accordance with FERC and other regulatory guidelines.  

Use of Estimates in the Preparation of Financial Statements

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

Revenues and Fuel Costs

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, including Algiers. Prior to October 1, 2015, Entergy Louisiana was the electric power supplier for Algiers. 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.

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 filing. System Energy’s operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy

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Table of Contents
Entergy Corporation and Subsidiaries
Notes to Financial Statements


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.

Accounting for MISO transactions

Entergy is a member of 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 on an hourly basis. MISO settles these hourly offers and bids based on locational marginal prices, which is 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 the market participants’ energy offers and demand bids to economically and reliably dispatch the entire MISO system. Entergy nets purchases and sales within the MISO market on an hourly basis and reports in operating revenues when in a net selling position for an hour period and in operating expenses when in a net purchasing position for an hour period.  

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, 2017 and 2016, is shown below:
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



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Table of Contents
Entergy Corporation and Subsidiaries
Notes to Financial Statements


2016
 
Entergy
 
Utility
 
Entergy Wholesale Commodities
 
Parent & Other
 
 
(In Millions)
Production
 
 

 
 

 
 

 
 

Nuclear
 

$6,948

 

$6,524

 

$424

 

$—

Other
 
4,047

 
4,000

 
47

 
—

Transmission
 
5,226

 
5,223

 
3

 
—

Distribution
 
7,648

 
7,648

 
—

 
—

Other
 
1,636

 
1,521

 
111

 
4

Construction work in progress
 
1,378

 
1,334

 
44

 
—

Nuclear fuel
 
1,038

 
817

 
221

 
—

Property, plant, and equipment - net
 

$27,921

 

$27,067

 

$850

 

$4


Depreciation rates on average depreciable property for Entergy approximated 3.0% in 2017, 2.8% in 2016, and 2.9% in 2015.  Included in these rates are the depreciation rates on average depreciable Utility property of 2.6% in 2017, 2.6% in 2016, and 2.7% 2015, and the depreciation rates on average depreciable Entergy Wholesale Commodities property of 22.3% in 2017, 5.2% in 2016, and 5.4% in 2015. The higher 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.

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 $167 million and $169 million as of December 31, 2017 and 2016, respectively.

Construction expenditures included in accounts payable is $368 million and $253 million at December 31, 2017 and 2016, respectively.

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, 2017 and 2016, is shown below:
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


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Table of Contents
Entergy Corporation and Subsidiaries
Notes to Financial Statements


2016
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Millions)
Production
 
 
 
 
 
 
 
 
 
 
 
 
Nuclear
 

$1,201

 

$3,540

 

$—

 

$—

 

$—

 

$1,783

Other
 
801

 
1,966

 
537

 
213

 
483

 
—

Transmission
 
1,491

 
1,925

 
740

 
79

 
943

 
45

Distribution
 
2,144

 
2,632

 
1,242

 
414

 
1,216

 
—

Other
 
216

 
517

 
201

 
188

 
106

 
25

Construction work in progress
 
304

 
670

 
118

 
25

 
111

 
44

Nuclear fuel
 
307

 
250

 
—

 
—

 
—

 
260

Property, plant, and equipment - net
 

$6,464

 

$11,500

 

$2,838

 

$919

 

$2,859

 

$2,157


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
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%
2015
2.6%
 
2.3%
 
3.2%
 
3.0%
 
2.6%
 
2.8%

Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $152.3 million and $154.4 million as of December 31, 2017 and 2016, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Mississippi is reported net of accumulated depreciation of $0.5 million and $0.5 million as of December 31, 2017 and 2016, respectively.  Non-utility property - at cost (less accumulated depreciation) for Entergy Texas is reported net of accumulated depreciation of $4.9 million and $4.9 million as of December 31, 2017 and 2016, respectively.

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.  As of December 31, 2016, construction expenditures included in accounts payable are $40.9 million for Entergy Arkansas, $114.8 million for Entergy Louisiana, $11.5 million for Entergy Mississippi, $2.3 million for Entergy New Orleans, $9.3 million for Entergy Texas, and $6.2 million for System Energy.

Jointly-Owned Generating Stations

Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties. All parties are required to provide their own financing.  The investments, fuel expenses, and other operation and maintenance expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests.  As of December 31, 2017, the subsidiaries’ investment and accumulated depreciation in each of these generating stations were as follows:


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Generating Stations
 
Fuel Type
 
Total Megawatt Capability (a)
 
Ownership
 
Investment
 
Accumulated Depreciation
 
 
 
 
 
 
 
 
 
(In Millions)
Utility business:
 
 
 
 
 
 
 
 
 
 
 
Entergy Arkansas -
 
 
 
 
 
 
 
 
 
 
 
  Independence
Unit 1
 
Coal
 
836

 
31.50
%
 

$140

 

$103

  Independence
Common Facilities
 
Coal
 
 
 
15.75
%
 

$34

 

$27

  White Bluff
Units 1 and 2
 
Coal
 
1,636

 
57.00
%
 

$531

 

$364

  Ouachita (b)
Common Facilities
 
Gas
 


 
66.67
%
 

$172

 

$150

  Union (c)
Units 1 and 2 Common Facilities
 
Gas
 


 
50.00
%
 

$1

 

$—

  Union (c)
Common Facilities
 
Gas
 
 
 
25.00
%
 

$28

 

$3

Entergy Louisiana -
 
 
 
 
 
 
 

 
 
 
 
  Roy S. Nelson
Unit 6
 
Coal
 
550

 
40.25
%
 

$280

 

$194

  Roy S. Nelson
Unit 6 Common Facilities
 
Coal
 
 
 
25.79
%
 

$15

 

$6

  Big Cajun 2
Unit 3
 
Coal
 
574

 
24.15
%
 

$150

 

$117

  Big Cajun 2
Unit 3 Common Facilities
 
Coal
 
 
 
8.05
%
 

$5

 

$2

  Ouachita (b)
Common Facilities
 
Gas
 


 
33.33
%
 

$90

 

$75

  Acadia
Common Facilities
 
Gas
 


 
50.00
%
 

$20

 

$—

  Union (c)
Common Facilities
 
Gas
 
 
 
50.00
%
 

$55

 

$3

Entergy Mississippi -
 
 
 
 
 
 
 

 
 
 
 
  Independence
Units 1 and 2 and Common Facilities
 
Coal
 
1,678

 
25.00
%
 

$266

 

$156

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


 
50.00
%
 

$1

 

$—

  Union (c)
Common Facilities
 
Gas
 
 
 
25.00
%
 

$28

 

$3

Entergy Texas -
 
 
 
 
 
 
 

 
 
 
 
  Roy S. Nelson
Unit 6
 
Coal
 
550

 
29.75
%
 

$200

 

$114

  Roy S. Nelson
Unit 6 Common Facilities
 
Coal
 
 
 
14.16
%
 

$6

 

$3

  Big Cajun 2
Unit 3
 
Coal
 
574

 
17.85
%
 

$113

 

$76

  Big Cajun 2
Unit 3 Common Facilities
 
Coal
 
 
 
5.95
%
 

$3

 

$1

System Energy -
 
 
 
 
 
 
 

 
 
 
 
  Grand Gulf (d)
Unit 1
 
Nuclear
 
1,414

 
90.00
%
 

$4,916

 

$3,175

Entergy Wholesale Commodities:
 
 
 
 
 
 
 

 
 
 
 
  Independence
Unit 2
 
Coal
 
842

 
14.37
%
 

$73

 

$50

  Independence
Common Facilities
 
Coal
 
 
 
7.18
%
 

$17

 

$12

  Roy S. Nelson
Unit 6
 
Coal
 
550

 
10.90
%
 

$113

 

$62

  Roy S. Nelson
Unit 6 Common Facilities
 
Coal
 
 
 
5.19
%
 

$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 Louisiana, 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,
 
2017
 
2016
 
2015
 
(In Millions, Except Per Share Data)
 
 
 
$/share
 
 
 
$/share
 
 
 
$/share
Net income (loss) attributable to Entergy Corporation

$411.6

 
 

 

($583.6
)
 
 

 

($176.6
)
 
 

Basic earnings (loss) per average common share
179.7

 

$2.29

 
178.9

 

($3.26
)
 
179.2

 

($0.99
)
Average dilutive effect of:
 

 
 

 
 

 
 

 
 

 
 

Stock options
0.2

 
—

 
—

 
—

 
—

 
—

Other equity plans
0.6

 
(0.01
)
 
—

 
—

 
—

 
—

Diluted earnings (loss) per average common shares
180.5

 

$2.28

 
178.9

 

($3.26
)
 
179.2

 

($0.99
)

The calculation of diluted earnings (loss) per share excluded 2,927,512 options outstanding at December 31, 2017, 7,137,210 options outstanding at December 31, 2016, and 7,399,820 options outstanding at December 31, 2015 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.

Effective January 1, 2017, Entergy adopted ASU 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.” The ASU permits the election of an accounting policy change to the method of recognizing forfeitures of stock-based compensation. Previously, Entergy recorded an estimate of the number of forfeitures expected to occur each period. Entergy elected to change this policy to account for forfeitures when they occur. This accounting change was applied retrospectively, but did not result in an adjustment to retained earnings as of January 1, 2017. As a result of adoption of the ASU, Entergy now prospectively recognizes all income tax effects related to share-based payments through the income statement. In the first quarter 2017, stock option expirations, along with other stock compensation activity, resulted in the write-off of $11.5 million of deferred tax assets.

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

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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.

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.  Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment

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for decommissioning trust funds, for unrealized gains/(losses) on investment securities the Registrant Subsidiaries record an offsetting amount in other regulatory liabilities/assets.  For the 30% interest in River Bend formerly owned by Cajun, Entergy Louisiana records an offsetting amount in other deferred credits for the excess 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 recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of shareholders’ equity because these assets are classified as available for sale.  Unrealized losses (where cost exceeds fair market value) on the assets in these 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.  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).  The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment is based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time.  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 will be 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 Registrant Subsidiaries, an offsetting amount of unrealized gains/losses will continue to be recorded in other regulatory liabilities/assets. 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

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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. Changes in the fair value of derivative instruments that are not designated as cash flow hedges are recorded in current-period earnings on a mark-to-market basis.

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

Fair Values

The estimated fair values of Entergy’s financial instruments and derivatives are determined using historical prices, bid prices, market quotes, and financial modeling.  Considerable judgment is required in developing the estimates of fair value.  Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange.  Gains or losses realized on financial instruments 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.


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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.

Presentation of Preferred Stock without Sinking Fund

Accounting standards regarding non-controlling interests and the classification and measurement of redeemable securities require the classification of preferred securities between liabilities and shareholders’ equity on the balance sheet if the holders of those securities have protective rights that allow them to gain control of the board of directors in certain circumstances.  These rights would have the effect of giving the holders the ability to potentially redeem their securities, even if the likelihood of occurrence of these circumstances is considered remote.  The Entergy Arkansas, Entergy Mississippi, and, prior to December 1, 2017, Entergy New Orleans articles of incorporation provide, generally, that the holders of each company’s preferred securities may elect a majority of the respective company’s board of directors if dividends are not paid for a year, until such time as the dividends in arrears are paid.  Therefore, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans present their preferred securities outstanding between liabilities and shareholders’ equity on the balance sheet.  In November 2017, Entergy New Orleans 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 New Orleans’s internal restructuring.

The outstanding preferred securities of Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans, 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.

New Accounting Pronouncements

In May 2014 the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The ASU’s core principle is that “an entity should 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. With FASB issuance of ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” ASU 2014-09 is effective for Entergy for the first quarter 2018. Entergy has selected the modified retrospective transition method. Entergy’s evaluation of ASU 2014-09 has not identified any effects that it expects will affect materially its results of operations, financial position, or cash flows, other than changes in required financial statement disclosures. The adoption of the ASU did not result in an adjustment to retained earnings as of January 1, 2018.

In January 2016 the FASB issued ASU No. 2016-01 “Financial Instruments (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities.” 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. The ASU requires a qualitative assessment to identify impairments of investments in equity securities that do not have a readily determinable fair value. ASU 2016-01 is effective for Entergy for the first quarter 2018. Entergy expects that ASU 2016-01 will affect its results of operations by requiring unrealized gains and losses on investments in equity securities held by the nuclear decommissioning trust funds to be recorded in earnings rather than in other comprehensive income. In accordance with the regulatory treatment of the decommissioning trust funds of Entergy Arkansas, Entergy Louisiana, and System Energy, an offsetting amount of unrealized gains/losses will continue to be recorded in other regulatory liabilities/assets. Entergy recorded an adjustment to retained earnings of $633 million as of January 1, 2018 for the cumulative effect of the unrealized gains and losses

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on investments in equity securities held by the decommissioning trust funds that do not meet the criteria for regulatory accounting treatment.

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. ASU 2016-02 is effective for Entergy for the first quarter 2019, and Entergy does not expect to early adopt the standard.  Entergy expects that ASU 2016-02 will affect its financial position by increasing the assets and liabilities recorded relating to its operating leases.  Entergy is evaluating ASU 2016-02 for other effects on its results of operations, financial position, cash flows, and financial statement disclosures, as well as the potential to elect various practical expedients permitted by the standards.
    
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 October 2016 the FASB issued ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory.” The ASU requires entities to recognize the income tax consequences of intra-entity asset transfers, other than inventory, at the time the transfer occurs. ASU 2016-16 is effective for Entergy for the first quarter 2018 and will affect its statement of financial position by requiring recognition of deferred tax assets or liabilities arising from intra-entity asset transfers. Entergy recorded an adjustment to retained earnings of $56 million as of January 1, 2018 for the cumulative-effect of the recognition of the deferred tax assets arising from intra-entity asset transfers.

In March 2017 the FASB issued ASU No. 2017-07, “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” 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.  In addition, the ASU allows only the service cost component of net benefit cost to be eligible for capitalization.  ASU 2017-07 is effective for Entergy for the first quarter 2018.  Entergy does not expect ASU 2017-07 to affect materially its results of operations, financial position, or 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 is effective for Entergy for the first quarter 2019. Entergy does not expect to early adopt the standard.  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 is evaluating ASU 2017-12 for other effects on its results of operations, financial position, or cash flows.

In February 2018 the FASB issued ASU No. 2018-02, “Income Statement- Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.”  The ASU

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Notes to Financial Statements


allows 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 .  ASU 2018-02 is effective for Entergy for the first quarter 2019, but may be early adopted. Entergy plans to adopt the ASU in the first quarter 2018.  Entergy expects that upon the adoption of ASU 2018-02 it will record to the statement of financial position a net reclassification reducing retained earnings and increasing accumulated other comprehensive income by approximately $15 million.  Entergy does not expect that ASU 2018-02 will have any other material effect on its results of operations, financial position, or cash flows.


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

Regulatory assets represent probable future revenues associated with costs that Entergy expects to recover from customers through the regulatory ratemaking process under which the Utility business operates. Regulatory liabilities represent probable future reductions in revenues associated with amounts that Entergy expects to benefit customers through the regulatory ratemaking process under which the Utility business operates. In addition to the regulatory assets and liabilities that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” and “Other regulatory liabilities” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 2017 and 2016:
 
Other Regulatory Assets

Entergy
 
2017
 
2016
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)

$2,642.3

 

$2,635.5

Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)
746.0

 
677.2

Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 – Storm Cost Recovery Filings with Retail Regulators) (Note 5)
558.9

 
637.0

Removal costs - recovered through depreciation rates (Note 9) (a)
436.5

 
353.9

Opportunity Sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)
109.8

 
—

Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators
86.4

 
22.1

Unamortized loss on reacquired debt - recovered over term of debt
82.9

 
91.4

Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)
73.7

 
100.0

Transition to competition costs - recovered over a 15-year period through February 2021
37.7

 
47.9

New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) (b)
36.4

 
43.7

Other
125.1

 
161.2

Entergy Total

$4,935.7

 

$4,769.9



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Entergy Arkansas
 
2017
 
2016
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)

$757.0

 

$786.6

Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)
345.2

 
322.9

Removal costs - recovered through depreciation rates (Note 9) (a)
176.9

 
128.5

Opportunity sales - recovery will be determined after final order in proceeding (Note 2 - Entergy Arkansas Opportunity Sales Proceeding)
109.8

 
—

Storm damage costs - recovered either through securitization or retail rates (Note 5 - Entergy Arkansas Securitization Bonds)
76.2

 
88.9

Retail rate deferrals - recovered through rate riders as rates are redetermined annually
28.2

 
10.1

Unamortized loss on reacquired debt - recovered over term of debt
24.3

 
27.6

ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (Note 2 - Retail Rate Proceedings) (b)
14.4

 
16.1

Lake Catherine 4 reliability and sustainability cost deferral - recovery through retail rates (b)
8.9

 
9.8

Incremental ice storm costs - recovered through 2032
7.4

 
7.9

MISO costs - recovery through retail rates through 2018 (Note 2 - Retail Rate Proceedings) (b)
5.5

 
11.1

Human capital management costs - recovery through retail rates through August 2019 (Note 2 - Retail Rate Proceedings) (b)
4.4

 
7.0

Other
9.2

 
11.5

Entergy Arkansas Total

$1,567.4

 

$1,428.0



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Entergy Louisiana
 
2017
 
2016
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (a)

$724.6

 

$715.7

Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)
218.6

 
199.4

Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)
71.4

 
97.8

New nuclear generation development costs - recovery through formula rate plan beginning December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (b)
35.8

 
43.1

Unamortized loss on reacquired debt - recovered over term of debt
24.7

 
27.0

Storm damage costs - recovered through retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)
14.3

 
—

Business combination external costs deferral - recovery through formula rate plan beginning December 2015 through November 2025 (b)
14.1

 
15.2

River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC)
12.9

 
14.8

Other
29.4

 
55.1

Entergy Louisiana Total

$1,145.8

 

$1,168.1


Entergy Mississippi
 
2017
 
2016
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)

$218.7

 

$217.2

Removal costs - recovered through depreciation rates (Note 9) (a)
91.6

 
82.0

Retail rate deferrals - recovered through rate riders as rates are redetermined annually
49.4

 
9.3

Unamortized loss on reacquired debt - recovered over term of debt
17.6

 
18.9

Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)
7.6

 
7.2

Other
13.0

 
7.6

Entergy Mississippi Total

$397.9

 

$342.2



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Entergy New Orleans
 
2017
 
2016
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)

$102.8

 

$108.8

Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators)
82.3

 
93.6

Removal costs - recovered through depreciation rates (Note 9) (a)
44.8

 
40.1

Retail rate deferrals - recovered through rate riders as rates are redetermined monthly or annually
4.4

 
4.3

Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)
4.3

 
4.2

Unamortized loss on reacquired debt - recovered over term of debt
3.0

 
3.4

Rate case costs - recovered over a 6-year period through September 2021 (Note 2 - Retail Rate Proceedings)
2.6

 
3.0

Michoud plant maintenance – recovered over a 7-year period through September 2018
1.4

 
3.3

Other
5.8

 
7.4

Entergy New Orleans Total

$251.4

 

$268.1


Entergy Texas
 
2017
 
2016
 
(In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds)

$386.1

 

$442.4

Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)
169.2

 
201.7

Transition to competition costs - recovered over a 15-year period through February 2021
37.7

 
47.9

Removal costs - recovered through depreciation rates (Note 9) (a)
55.2

 
33.5

Unamortized loss on reacquired debt - recovered over term of debt
8.7

 
9.0

Other
4.5

 
5.7

Entergy Texas Total

$661.4

 

$740.2


System Energy
 
2017
 
2016
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (a)

$202.7

 

$193.5

Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a)
169.1

 
142.5

Removal costs - recovered through depreciation rates (Note 9) (a)
67.9

 
69.7

Unamortized loss on reacquired debt - recovered over term of debt
4.6

 
5.5

System Energy Total

$444.3

 

$411.2


(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
 
2017
 
2016
 
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)

$989.3

 

$735.5

Vidalia purchased power agreement (Note 8) (b)
151.6

 
202.4

Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)
124.8

 
165.5

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 beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)
65.8

 
83.5

Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and the FERC
44.4

 
44.4

Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
36.7

 
32.7

Removal costs - returned to customers through depreciation rates (Note 9) (a)
32.4

 
53.9

Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement
32.1

 
39.3

Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings)
—

 
68.0

Other
43.5

 
79.8

Entergy Total

$1,588.5

 

$1,572.9


Entergy Arkansas
 
2017
 
2016
 
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)

$354.0

 

$280.8

Other
9.6

 
25.1

Entergy Arkansas Total

$363.6

 

$305.9



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Entergy Louisiana
 
2017
 
2016
 
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)

$323.7

 

$235.4

Vidalia purchased power agreement (Note 8) (b)
151.6

 
202.4

Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (b)
124.8

 
165.5

Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)
65.8

 
83.5

Gas hedging costs - refunded through fuel rates (Note 15 - Derivatives)
—

 
10.9

Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)
36.7

 
32.7

Removal costs - returned to customers through depreciation rates (Note 9) (a)
32.4

 
53.9

Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings)
—

 
68.0

Other
26.1

 
28.7

Entergy Louisiana Total

$761.1

 

$881.0


Entergy Texas
 
2017
 
2016
 
(In Millions)
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically

$4.8

 

$6.2

Other
2.1

 
2.3

Entergy Texas Total

$6.9

 

$8.5


System Energy
 
2017
 
2016
 
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)

$311.6

 

$219.3

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
32.1

 
39.3

System Energy Total

$456.0

 

$370.9


(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.


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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 enactment of the Tax Cuts and Jobs Act, in December 2017, including its effects on Entergy’s and the Registrant Subsidiaries’ regulatory asset/liability for income taxes.

After enactment of the Tax Cuts and Jobs Act the APSC issued an order that applies to investor-owned utilities in Arkansas, including Entergy Arkansas. The order requests information regarding certain effects of the Tax Cuts and Jobs Act and requires the utilities to begin, effective January 1, 2018, to record regulatory liabilities to record the effects of the Act, subject to review by the APSC, although the order acknowledges that the exact amount of tax savings and rate reductions cannot be determined at this time. Entergy Arkansas requested clarification or, in the alternative, rehearing regarding the requirement to record a regulatory liability, and also responded to the request for information. In its request for clarification Entergy Arkansas sought clarification that the amount of any regulatory liability would be determined only after the utilities are heard and present evidence on the issue, as this otherwise would be arbitrary and could implicate single-issue and retroactive ratemaking. The APSC has not responded to the request for clarification. In its response to the APSC’s request for information Entergy Arkansas states that its formula rate plan rider already provides the means for customers to realize the benefits of the Act, except for the return of unprotected excess accumulated deferred income taxes. Entergy Arkansas’s next formula rate plan filing is scheduled for July 2018. Entergy Arkansas intends to return unprotected excess accumulated deferred income taxes as expeditiously as possible, subject to a subsequent request to be made by Entergy Arkansas and approval by the APSC.

After enactment of the Tax Cuts and Jobs Act the LPSC passed an agenda item requiring utilities, including Entergy Louisiana, to file reports regarding certain effects of the Act. Entergy Louisiana responded to the directive and stated in its response that it is working with the LPSC staff and other interested parties to extend its formula rate plan such that its next base rate change will occur effective September 2018, or it would file a base rate case. Entergy Louisiana went on to state that if the formula rate plan is extended Entergy Louisiana’s next adjustment of rates will reflect the new 21% federal corporate income tax rate. Entergy Louisiana stated that it is working with the LPSC staff and interested parties to determine when the tax rate reduction will be reflected in rates, along with when and how the excess accumulated deferred income taxes will be reflected in rates, and how certain tax sharing agreement customer credits will be adjusted. On February 21, 2018, the LPSC issued a special order requiring that all LPSC-jurisdictional utilities, beginning as of January 1, 2018, record as a regulatory liability (deferred liability) the amount required to reflect the reduction in the federal corporate income tax rate from 35% to 21% and the associated savings in excess accumulated deferred income taxes until such time as its rates are changed by the LPSC to reflect these federal tax savings. In the same special order, the LPSC also initiated a new rulemaking docket to consider these issues and the appropriate manner in which to flow through the benefits to Louisiana customers and to provide an opportunity for discovery and comments of jurisdictional utilities and other interested stakeholders. The rulemaking further requires the LPSC staff to report back to the LPSC as soon as practicable and preferably by the March 21, 2018, LPSC Business and Executive Session with recommendations as to how the federal tax-related benefits will be flowed through to Louisiana customers.

After enactment of the Tax Cuts and Jobs Act the MPSC ordered utilities, including Entergy Mississippi, that operate under a formula rate plan to file a description by February 26, 2018, of how the Act will be reflected in the formula rate plan under which the utility operates. In addition to the description that is due February 26, 2018, Entergy Mississippi’s formula rate plan 2018 test year filing is scheduled to be filed by March 15, 2018.

After enactment of the Tax Cuts and Jobs Act the City Council passed a resolution ordering Entergy New Orleans to, effective January 1, 2018, record deferred regulatory liabilities to account for the Act’s effect on Entergy New Orleans’s revenue requirement and to make a filing by mid-March 2018 regarding the Act’s effects on Entergy New Orleans’s operating income and rate base and potential mechanisms for customers to receive benefits of the Act. The 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 plans to make such filings with the FERC by the end of March 2018.

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After enactment of the Tax Cuts and Jobs 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. The order also directs the PUCT staff to investigate each investor-owned utility on a case-by-case basis to determine the appropriate mechanism to adjust its rates to reflect the changes under the Act. In both a memorandum issued prior to the open meeting when the order was discussed and during the discussions at the open meeting discussing the order, the PUCT indicated that it would consider utility earnings in determining the treatment of the liability and the effects of the Act. Entergy Texas had previously provided information to the PUCT Staff in the docket and stated that it expects 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 a subsequent order issued following the February 2018 open meeting, the PUCT clarified that carrying costs need not be recorded as part of the regulatory liability.

The Registrant Subsidiaries will continue to work with their respective regulators to determine the appropriate path forward in each jurisdiction regarding the effects of the Act.

Fuel and purchased power cost recovery

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas 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, 2017 and 2016 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.
 
2017
 
2016
 
(In Millions)
Entergy Arkansas (a)

$130.4

 

$163.6

Entergy Louisiana (b)

$96.7

 

$119.9

Entergy Mississippi

$32.4

 

$7.0

Entergy New Orleans (b)

($3.7
)
 

$8.9

Entergy Texas

($67.3
)
 

($54.5
)

(a)
Includes $67.1 million in 2017 and $66.9 million in 2016 of fuel and purchased power 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.
(b)
Includes $168.1 million in each year for Entergy Louisiana and $4.1 million in each year 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.  These costs cause an increase in Entergy

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Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects the costs from customers over twelve months.

In May 2014, Entergy Arkansas filed its annual redetermination of the production cost allocation rider to recover the $3 million unrecovered retail balance as of December 31, 2013 and the $67.8 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. In January 2015 the APSC issued an order approving Entergy Arkansas’s request for recovery of the $3 million under-recovered amount based on the true-up of the production cost allocation rider and the $67.8 million May 2014 System Agreement bandwidth remedy payment subject to refund with interest, with recovery of these payments concluding with the last billing cycle in December 2015. The APSC also found that Entergy Arkansas is entitled to carrying charges pursuant to the current terms of the production cost allocation rider. Entergy Arkansas made its compliance filing pursuant to the order in January 2015 and the APSC issued its approval order, also in January 2015. The redetermined rate went into effect with the first billing cycle of February 2015.

In May 2015, Entergy Arkansas filed its annual redetermination of the production cost allocation rider, which included a $38 million payment made by Entergy Arkansas as a result of the FERC’s February 2014 order related to the comprehensive bandwidth recalculation for calendar year 2006, 2007, and 2008 production costs. The redetermined rate for the 2015 production cost allocation rider update was added to the redetermined rate from the 2014 production cost allocation rider update and the combined rate was effective with the first billing cycle of July 2015. This combined rate was effective through December 2015. The collection of the remainder of the redetermined rate for the 2015 production cost allocation rider update continued through June 2016.

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 became effective with the first billing cycle of July 2016, and the rates were effective 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.

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 redetermination of its energy cost rate that was subsequently filed in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude $65.9 million of deferred fuel and purchased energy costs incurred in 2013 from the redetermination of its 2014 energy cost rate. The $65.9 million is an estimate of the incremental fuel and replacement

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energy costs that Entergy Arkansas incurred 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 is available regarding various claims associated with the ANO stator incident. The APSC approved Entergy Arkansas’s request in February 2014. In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that docket, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a docket 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.

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 April 2010 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings.  The audit included a review of the reasonableness of charges flowed through the fuel adjustment clause by Entergy Louisiana for the period from 2005 through 2009.  The LPSC staff issued its audit report in January 2013.  The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1 million from Entergy Louisiana’s fuel adjustment clause to base rates.  The recommended refund was made by Entergy Louisiana in May 2013 in the form of a credit to customers through its fuel adjustment clause filing. In October 2016 the LPSC staff filed testimony affirming the recommendation in its audit report on the lone remaining issue that nuclear dry fuel storage costs should be realigned to base rates. The parties agreed to remove that remaining issue to a separate docket because the same issue was outstanding in the Entergy Gulf States Louisiana audit for the same time period. In November 2016 the LPSC approved the resolution of this audit and the creation of a new docket for the resolution of the proper method of recovery for nuclear dry fuel storage costs. In December 2016 the LPSC opened a new docket in order to resolve the issue regarding the proper methodology for the recovery of nuclear dry fuel storage costs. In October 2017 the LPSC approved the continued recovery of the nuclear dry fuel storage costs through the fuel adjustment clause, resolving the open issue in the audit.

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 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.

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In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Gulf States Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery commenced in July 2015. No report of audit has been issued.

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. Discovery commenced in July 2015. No report of audit has been issued.

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.

Due to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs, Entergy Louisiana plans to cap the average fuel adjustment charge to be billed in March 2018 at $0.03060 per kWh and to defer billing of all fuel costs in excess of the capped amounts by including such costs in the over- or under-recovery account.

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.

Entergy Mississippi had a deferred fuel over-recovery balance of $58.3 million as of May 31, 2015, along with an under-recovery balance of $12.3 million under the power management rider. Pursuant to those tariffs, in July 2015, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider to flow through to customers the approximately $46 million net over-recovery over a six-month period. In August 2015, the MPSC approved the interim adjustments effective with September 2015 bills. 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

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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.

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.  The Mississippi attorney general moved to remand the matter to state court.  In August 2012 the District Court issued an opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.

The defendant Entergy companies answered the complaint and filed a counterclaim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act.  In May 2009 the defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdiction of the MPSC, and factual errors in the Attorney General’s complaint.  In September 2012 the District Court heard oral argument on Entergy’s motion for judgment on the pleadings.

In January 2014 the U.S. Supreme Court issued a decision in which it held that cases brought by attorneys general as the sole plaintiff to enforce state laws were not considered “mass actions” under the Class Action Fairness Act, so as to establish federal subject matter jurisdiction. One day later the Attorney General renewed his motion to remand the Entergy case back to state court, citing the U.S. Supreme Court’s decision. The defendant Entergy companies responded to that motion reiterating the additional grounds asserted for federal question jurisdiction, and the District Court held oral argument on the renewed motion to remand in February 2014. In April 2015 the District Court entered an order denying the renewed motion to remand, holding that the District Court has federal question subject matter jurisdiction. The Attorney General appealed to the U.S. Fifth Circuit Court of Appeals the denial of the motion to remand. In July 2015 the Fifth Circuit issued an order denying the appeal, and the Attorney General subsequently filed a petition for rehearing of the request for interlocutory appeal, which was also denied. In December 2015 the District Court ordered that the parties submit to the court undisputed and disputed facts that are material to the Entergy defendants’ motion for judgment on the pleadings, as well as supplemental briefs regarding the same. Those filings were made in January 2016.

In September 2016 the Attorney General filed a mandamus petition with the U.S. Fifth Circuit Court of Appeals in which the Attorney General asked the Fifth Circuit to order the chief judge to reassign this case to another judge. In September 2016 the District Court denied the Entergy companies’ motion for judgment on the pleadings. The Entergy companies filed a motion seeking to amend the District Court’s order denying the Entergy companies’ motion for judgment on the pleadings and allowing an interlocutory appeal. In October 2016 the Fifth Circuit granted the Attorney General’s motion for writ of mandamus and directed the chief judge to assign the case to a new judge. The case was reassigned in October 2016. In January 2017 the District Court denied the Entergy companies’ motion to amend the order denying the motion for judgment on the pleadings. In June 2017 the District Court issued a case management order setting a trial date in November 2018. Discovery is currently in progress.

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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.

Due to higher fuel costs associated in part with the extended Grand Gulf outage and the partially simultaneous Union Power Block 1 planned outage, for the December 2016, January 2017, and February 2017 billing months, the City Council authorized Entergy New Orleans to cap the fuel adjustment charge billed to customers at $0.035 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.

Due to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs associated in part with certain plant outages, Entergy New Orleans has proposed to cap the fuel adjustment charge to be billed in March 2018 to non-transmission Entergy New Orleans legacy customers and Entergy New Orleans Algiers customers at $0.035323 per kWh and $0.025446 per kWh, respectively. Entergy New Orleans has also proposed to cap the fuel adjustment charge to be billed in March 2018 for Entergy New Orleans legacy transmission customers at $0.034609 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.

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.
        
In August 2014, Entergy Texas filed an application seeking PUCT approval to implement an interim fuel refund of approximately $24.6 million for over-collected fuel costs incurred during the months of November 2012 through April 2014. This refund resulted from (i) applying $48.6 million in bandwidth remedy payments that Entergy Texas received in May 2014 related to the June - December 2005 period to Entergy Texas’s $8.7 million under-recovered fuel balance as of April 30, 2014 and (ii) netting that fuel balance against the $15.3 million bandwidth remedy payment that Entergy Texas made related to calendar year 2013 production costs. Also in August 2014, Entergy Texas filed an unopposed motion for interim rates to implement these refunds for most customers over a two-month period commencing with September 2014. The PUCT issued its order approving the interim relief in August 2014 and Entergy Texas completed the refunds in October 2014. Parties intervened in this matter, and all parties agreed that the proceeding should be bifurcated such that the proposed interim refund would become final in a separate proceeding, which refund was approved by the PUCT in March 2015.   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,

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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 to be 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 U.S. Court of Appeals for the Fifth Circuit in February 2018, and a decision is pending. The State District Court appeal of the PUCT’s January 2016 decision also remains pending.

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 Apri1 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 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 beginning January 2018 and will continue through March 2018. A final decision in this matter remains pending.
    
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 September 2015 the APSC staff and intervenors filed direct testimony, with the APSC staff recommending a revenue requirement of $217.9 million and a 9.65% return on common equity. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors

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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. A settlement hearing was held in January 2016. 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 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved the 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 docket 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 docket and

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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.
 
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. The restructuring is subject to regulatory review and approval by the APSC, the FERC, and the NRC. 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. If the APSC approves the restructuring by September 1, 2018, and the restructuring closes on or before December 1, 2018, Entergy Arkansas proposed in its application to credit retail customers $66 million over six years, beginning in 2019. In February 2018, Entergy Arkansas filed supplemental testimony reducing the proposed retail customer credits to $39.6 million over six years. If the APSC, the FERC, and the NRC approvals are obtained, Entergy Arkansas expects the restructuring will be consummated on or before December 1, 2018.
It is currently contemplated that Entergy Arkansas would undertake a multi-step restructuring, which would include the following:
•
Entergy Arkansas would redeem its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million, which includes call premiums, plus accumulated and unpaid dividends, if any.
•
Entergy Arkansas would convert from an Arkansas corporation to a Texas corporation.
•
Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas will allocate 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 will assume substantially all of the liabilities of Entergy Arkansas, in a transaction regarded as a merger under the TXBOC. Entergy Arkansas will remain in existence and hold the membership interests in Entergy Arkansas Power.
•
Entergy Arkansas will contribute 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 will be a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
•
Entergy Arkansas will change its name to Entergy Utility Property, Inc., and Entergy Arkansas Power will then change its name to Entergy Arkansas, LLC.

Upon the completion of the restructuring, Entergy Arkansas, LLC will hold substantially all of the assets, and will have assumed substantially all of the liabilities, of Entergy Arkansas. Entergy Arkansas may modify or supplement the steps to be taken to effectuate the restructuring.
Filings with the LPSC (Entergy Louisiana)

Retail Rates - Electric

2014 Formula Rate Plan Filing

In connection with the approval of the business combination of Entergy Gulf States Louisiana and Entergy Louisiana, the LPSC authorized the filing of a single, joint, formula rate plan evaluation report for Entergy Gulf States Louisiana’s and Entergy Louisiana’s 2014 calendar year operations. The joint evaluation report was filed in September 2015 and reflected an earned return on common equity of 9.09%. As such, no adjustment to base formula rate plan revenue was required. The following adjustments were required under the formula rate plan, however: a decrease in the additional capacity mechanism for Entergy Louisiana of $17.8 million; an increase in the additional capacity mechanism for Entergy Gulf States Louisiana of $4.3 million; and a reduction of $5.5 million to the MISO cost recovery

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mechanism to collect approximately $35.7 million on a combined-company basis. Under the order approving the business combination, following completion of the prescribed review period, rates were implemented with the first billing cycle of December 2015, subject to refund. See “Entergy Louisiana and Entergy Gulf States Louisiana Business Combination” below for further discussion of the business combination. In June 2017 the LPSC staff and Entergy Louisiana filed an unopposed joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of this proceeding with no changes to rates already implemented.

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.

Extension of MISO Cost Recovery Mechanism Rider

In November 2016, Entergy Louisiana filed with the LPSC a request to extend the MISO cost recovery mechanism rider provision of its formula rate plan. In March 2017 the LPSC staff submitted direct testimony generally supportive of a one-year extension of the MISO cost recovery mechanism and the intervenor in the proceeding did not oppose an extension for this period of time. In July 2017 an uncontested joint stipulation authorizing a one-year extension of the MISO cost recovery mechanism rider was approved.

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 the present level of $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.

Formula Rate Plan Extension Request

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

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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.  Entergy Louisiana requested that the LPSC consider its request on an expedited basis, in an effort to maintain Entergy Louisiana’s current cycle for implementing rate adjustments, i.e., September 2018, without the need for filing a full base rate case proceeding. Several parties have intervened in the proceeding and all parties have been participating in settlement discussions.

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. At the hearing the parties maintained the positions reflected in pre-filed testimony. 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.


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Ninemile 6

In July 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed an unopposed stipulation with the LPSC, which was subsequently approved, that estimated a first year revenue requirement associated with Ninemile 6 and provided a mechanism to update the revenue requirement as the in-service date approached. In late-December 2014, roughly contemporaneous with the unit's placement in service, a final updated estimated revenue requirement of $26.8 million for Entergy Gulf States Louisiana and $51.1 million for Entergy Louisiana was filed. The December 2014 estimate formed the basis of rates implemented effective with the first billing cycle of January 2015. In July 2015, Entergy Louisiana submitted to the LPSC a compliance filing including an estimate at completion, inclusive of interconnection costs and transmission upgrades, of approximately $648 million, or $76 million less than originally estimated, along with other project details and supporting evidence, to enable the LPSC to review the prudence of Entergy Louisiana’s management of the project. Testimony filed by the LPSC staff generally supported the prudence of the management of the project and recovery of the costs incurred to complete the project. The LPSC staff had questioned the warranty coverage for one element of the project. In October 2016 all parties agreed to a stipulation providing that 100% of Ninemile 6 construction costs was prudently incurred and is eligible for recovery from customers, but reserving the LPSC’s rights to review the prudence of Entergy Louisiana’s actions regarding one element of the project. This stipulation was approved by the LPSC in January 2017.

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 $474 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 have requested further proceedings on the prudence of the decision to deactivate Willow Glen 2 and 4.  No party contests the prudence of the decision to deactivate Willow Glen 2 and 4 or suggests reactivation of these units; however, issues have been 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. An evidentiary hearing was held in August 2017 and post-hearing briefs were submitted in October 2017. A decision is expected in 2018.

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

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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.

2014 Rate Stabilization Plan Filing

In January 2015, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2014.  The filing showed an earned return on common equity of 7.20%, which resulted in a $706 thousand rate increase.  In April 2015 the LPSC issued findings recommending two adjustments to Entergy Gulf States Louisiana’s as-filed results, and an additional recommendation that did not affect the results. The LPSC staff’s recommended adjustments increase the earned return on equity for the test year to 7.24%. Entergy Gulf States Louisiana accepted the LPSC staff’s recommendations and a revenue increase of $688 thousand was implemented with the first billing cycle of May 2015.

2015 Rate Stabilization Plan Filing

In January 2016, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2015. The filing showed an earned return on common equity of 10.22%, which is within the authorized bandwidth, therefore requiring no change in rates. In March 2016 the LPSC staff issued its report stating that the 2015 gas rate stabilization plan filing was in compliance with the exception of several issues that required additional information, explanation, or clarification for which the LPSC staff had reserved the right to further review. In July 2016 the parties to the proceeding filed an unopposed joint report and motion for entry of order accepting the report that indicated no outstanding issues remained in the filing.

In February 2016, Entergy Louisiana filed a motion requesting to extend the term of the gas rate stabilization plan in substantially similar form for an additional three-year term and included a request for sharing of non-jurisdictional compressed natural gas revenues. Following discovery and the filing of testimony by the LPSC staff, Entergy Louisiana and the LPSC submitted a joint motion for hearing an uncontested stipulated settlement resolving the proceeding. A hearing on the stipulation was held in November 2016. The ALJ issued a report of proceedings that was presented with the parties’ stipulation to the LPSC for consideration. The stipulation approving Entergy Louisiana’s requested extension of the rate stabilization plan was approved by the LPSC in December 2016.

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%. As part of the original filing, pursuant to the extraordinary cost provision of the rate stabilization plan, Entergy Louisiana sought to recover approximately $1.5 million in deferred operation and maintenance expenses incurred to restore service and repair damage resulting from flooding and widespread rainfall in southeast Louisiana that occurred in August 2016. Entergy Louisiana requested to recover the prudently incurred August 2016 storm restoration costs over ten years, outside of the rate stabilization plan sharing provisions. As a result, Entergy Louisiana’s filing sought an annual increase in revenue of $1.4 million. Following review of the filing, except for the proposed extraordinary cost recovery, the LPSC staff confirmed Entergy Louisiana’s filing was consistent with the principles and requirements of the rate stabilization plan. The extraordinary cost recovery request associated with the 2016 flood-related deferred operation and maintenance expenses incurred for gas operations was removed from the rate stabilization

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plan pending LPSC consideration in a separate docket. 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.

In connection with the joint report of proceedings accepted by the LPSC, in May 2017, Entergy Louisiana filed an application to initiate a separate proceeding to recover through the extraordinary cost provision of the gas rate stabilization plan the deferred operation and maintenance expenses of $1.4 million incurred to restore service and repair damage resulting from flooding and widespread rainfall in southeast Louisiana that occurred in August 2016. The LPSC staff submitted its direct testimony in the proceeding recommending recovery of $0.9 million. Entergy Louisiana filed rebuttal testimony responding to the LPSC staff’s recommendation. The procedural schedule was suspended to allow the parties to engage in settlement negotiations, and in February 2018 the LPSC staff and Entergy Louisiana filed an unopposed settlement. If approved by the LPSC, the settlement would provide for Entergy Louisiana to recover, over ten years, the approximately $1.4 million in deferred operation and maintenance expense and related carrying charges. The settlement further provides for recovery to commence in May 2018.

2017 Rate Stabilization Plan Filing

In January 2018, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for 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.  As a result, Entergy Louisiana will file a supplement to the January 2018 evaluation report to reflect, among other things, a 21% federal corporate income tax rate.  Any rate change resulting from the revised rate stabilization plan will become effective in rates in May 2018.

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 includes 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 includes $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.


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Filings with the City Council (Entergy New Orleans)

Retail Rates

See “Algiers Asset Transfer” below for discussion of the Algiers asset transfer. As a provision of the settlement agreement approved by the City Council in May 2015 providing for the Algiers asset transfer, 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 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

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costs during the period between when existing funds directed to Energy Smart programs are depleted (estimated to be June 2018) and when new rates from the anticipated 2018 combined rate case, which will include a cost recovery mechanism for Energy Smart funding, take effect (estimated to be August 2019). Entergy New Orleans requested that the City Council approve a cost recovery mechanism prior to June 2018. 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.

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. The restructuring was subject to regulatory review and approval by the City Council and the FERC. 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 anticipated 2018 base rate case. 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, pursuant to the agreement in principle, Entergy New Orleans undertook a multi-step restructuring, including the following:

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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.
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Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
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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

2011 Rate Case

In November 2011, Entergy Texas filed a rate case requesting a $112 million base rate increase reflecting a 10.6% return on common equity based on an adjusted June 2011 test year.  The rate case also proposed a purchased power recovery rider.  On January 12, 2012, the PUCT voted not to address the purchased power recovery rider in the rate case, but the PUCT voted to set a baseline in the rate case proceeding that would be applicable if a purchased

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power capacity rider is approved in a separate proceeding.  In April 2012 the PUCT Staff filed direct testimony recommending a base rate increase of $66 million and a 9.6% return on common equity.  The PUCT Staff, however, subsequently filed a statement of position in the proceeding indicating that it was still evaluating the position it would ultimately take in the case regarding Entergy Texas’s recovery of purchased power capacity costs and Entergy Texas’s proposal to defer its MISO transition expenses.  In April 2012, Entergy Texas filed rebuttal testimony indicating a revised request for a $105 million base rate increase.  A hearing was held in late-April through early-May 2012.

In September 2012 the PUCT issued an order approving a $28 million rate increase, effective July 2012.  The order included a finding that “a return on common equity (ROE) of 9.80 percent will allow [Entergy Texas] a reasonable opportunity to earn a reasonable return on invested capital.”  The order also provided for increases in depreciation rates and the annual storm reserve accrual.  The order also reduced Entergy Texas’s proposed purchased power capacity costs, stating that they are not known and measurable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6 million of MISO transition expense in base rates; and reduced Entergy’s Texas’s fuel reconciliation recovery by $4 million because the PUCT disagreed with the line-loss factor used in the calculation.  After considering the progress of the proceeding in light of the PUCT order, Entergy Texas recorded in the third quarter 2012 an approximate $24 million charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery.  Entergy Texas believed that it was entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012.  Several other parties also filed motions for rehearing of the PUCT’s order.  The PUCT subsequently denied rehearing of substantive issues.  Several parties, including Entergy Texas, appealed various aspects of the PUCT’s order to the Travis County District Court. A hearing was held in July 2014. In October 2014 the Travis County District Court issued an order upholding the PUCT’s decision except as to the line-loss factor issue referenced above, which was found in favor of Entergy Texas. In November 2014, Entergy Texas and other parties, including the PUCT, appealed the Travis County District Court decision to the Third Court of Appeals. Oral argument before the court panel was held in September 2015. In April 2016 the Third Court of Appeals issued its opinion affirming the District Court’s decision on all points. Entergy Texas petitioned the Texas Supreme Court to hear its appeal of the Third Court’s ruling. In September 2017 the Texas Supreme Court denied the petitions for review. Entergy Texas filed a motion for rehearing of the Texas Supreme Court’s denial of the petition for review. In January 2018 the Texas Supreme Court denied Entergy Texas’s motion for rehearing.

Distribution cost recovery factor (DCRF) rider

In September 2015, Entergy Texas filed to amend its DCRF rider. Entergy Texas requested an increase in recovery under the rider of $6.5 million, for a total collection of $10.1 million annually from retail customers. In October 2015 intervenors and PUCT staff filed testimony opposing, in part, Entergy Texas’s request. In November 2015, Entergy Texas and the parties filed an unopposed settlement agreement and supporting documents. The settlement established an annual revenue requirement of $8.65 million for the amended DCRF rider, with the resulting rates effective for usage on and after January 1, 2016. The PUCT approved the settlement agreement in February 2016.

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, 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, with the resulting rates effective for usage no later than October 1, 2017. 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.
    
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

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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. A hearing on the merits was held in December 2015. 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 is designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount includes the approximately $10.5 million annually that Entergy Texas is currently 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 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.

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 is expected to begin 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. Entergy Arkansas has begun discussions with the other parties to implement the items in the settlement agreement including pre-pay and time of use programs.


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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 is expected to begin in 2019. The communications network deployment is expected to begin by late-2018, after the necessary information technology infrastructure is in place. 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 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, with deployment of the communications network expected to begin 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.

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

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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 is expected to begin in 2019.  Deployment of the information technology infrastructure began in 2017 and deployment of the communications network is expected to begin 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.

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 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. Consistent with the approval, deployment of the communications network is expected to begin in 2018. 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.

Entergy Louisiana and Entergy Gulf States Louisiana Business Combination

Entergy Louisiana and Entergy Gulf States Louisiana filed an application with the LPSC in September 2014 seeking authorization to undertake transactions that would result in the combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility. An uncontested stipulated settlement (stipulated settlement) was filed with the LPSC in July 2015. Through the stipulated settlement, the parties agreed to terms upon which to recommend that the LPSC find that the business combination was in the public interest. The stipulated settlement, which was either joined, or unopposed, by all parties to the LPSC proceeding, represented a compromise of stakeholder positions and was the result of an extensive period of analysis, discovery, and negotiation. The stipulated settlement provided $107 million in guaranteed customer benefits during the first nine years following the transaction’s close. Additionally, the combined company would honor the 2013 Entergy Louisiana and Entergy Gulf States Louisiana rate case settlements, including the commitments that (1) there would be no rate increase for legacy Entergy Gulf States Louisiana customers for the 2014 test year, and (2) through the 2016 test year formula rate plan, Entergy Louisiana (as a combined entity)

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would not raise rates by more than $30 million, net of the $10 million rate increase included in the Entergy Louisiana legacy formula rate plan. The stipulated settlement also provided that Entergy Gulf States Louisiana and Entergy Louisiana would be permitted to defer certain external costs that were incurred to achieve the business combination’s customer benefits. In 2015 deferrals of $16 million for these external costs were recorded, and they are being amortized over a 10-year period. The LPSC approved the business combination in August 2015.

On October 1, 2015, the businesses formerly conducted by Entergy Louisiana and Entergy Gulf States Louisiana were combined into a single public utility. With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Entergy Louisiana and Entergy Gulf States Louisiana. The combination was accounted for as a transaction between entities under common control. See Note 3 to the financial statements for further discussion of the customer credits resulting from the business combination.

Algiers Asset Transfer (Entergy Louisiana and Entergy New Orleans)

In October 2014, Entergy Louisiana and Entergy New Orleans filed an application with the City Council seeking authorization to undertake a transaction that would result in 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. In April 2015 the FERC issued an order approving the Algiers assets transfer. In May 2015 the parties filed a settlement agreement authorizing the Algiers assets transfer and the settlement agreement was approved by a City Council resolution in May 2015. On September 1, 2015, Entergy Louisiana transferred its Algiers assets to Entergy New Orleans for a purchase price of approximately $85 million. Entergy New Orleans paid Entergy Louisiana $59.6 million, including final true-ups, from available cash and issued a note payable to Entergy Louisiana in the amount of $25.5 million.

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 equalizes 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 will 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 will not reflect the actual Vidalia price for the year but is 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 and the first reallocation payments were made in 2007.

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The FERC’s decision reallocated total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower 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 provides 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 shows the following payments/receipts among the Utility operating companies:


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

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 addressing 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 April and May 2014, Entergy filed with the FERC an updated compliance filing that provides the payments and receipts among the Utility operating companies pursuant to the FERC’s February 2014 orders.  The filing shows 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.


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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 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. The initial decision is pending before the FERC.

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.

The following rough production cost equalization rate proceedings are still ongoing.

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:

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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 refund calculation of the 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.

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.

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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. Briefs were filed in September 2016 and the proceeding 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. The ALJ further found that all of the Utility operating companies should share in those benefits pursuant to a methodology proposed by the MPSC. The Utility operating companies and other parties to the proceeding filed briefs on exceptions and/or briefs opposing exceptions with the FERC challenging various aspects of the December 2014 initial decision. 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. Oral argument before the D.C. Circuit was held on the APSC’s petition in January 2018 and a decision is pending.

In connection with the System Agreement termination settlement agreement, the purchase power agreements, referred to as the jurisdictional separation plan PPAs, between Entergy Texas and Entergy Gulf States Louisiana that were put in place for certain legacy gas units at the time of Entergy Gulf States’s separation into Entergy Texas and Entergy Gulf States Louisiana terminated effective with the System Agreement termination. Similarly, the purchase power agreement between Entergy Gulf States Louisiana and Entergy Texas for the Calcasieu unit also terminated. In

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March 2016, Entergy Services filed with the FERC the notices of termination. The jurisdictional separation plan PPAs were the means by which Entergy Texas received payment for its receivable associated with Entergy Louisiana’s Spindletop gas storage facility regulatory asset. As a result of the System Agreement termination settlement agreement, effective with the termination date, Entergy Texas no longer receives payments from Entergy Louisiana related to the Spindletop storage facility, which resulted in a write-off recorded in 2015 by Entergy Texas of $23.5 million ($15.3 million net-of-tax). Upon termination of the System Agreement, other purchase power agreements entered into under Service Schedule MSS-4 of the System Agreement were replaced with updated agreements under a FERC-jurisdictional tariff effective September 1, 2016.

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, and the Utility operating companies filed an answer to the protest in January 2008.  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.

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 has requested rehearing of the FERC’s June 2011 decision.  In July 2011 the refunds made in the fourth quarter 2009 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 September 2010 the FERC had issued an order setting the refund report filed in the proceeding in November 2007 for hearing and settlement judge procedures.  In May 2011, Entergy filed a settlement agreement that resolved all issues relating to the refund report set for hearing.  In June 2011 the settlement judge certified the settlement as uncontested.  The settlement agreement was approved by the FERC in September 2016.


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Prior to the FERC’s June 2011 order on rehearing, Entergy Arkansas filed an application in November 2010 with the APSC for recovery of the refund that it paid.  The APSC denied Entergy Arkansas’s application, and also denied Entergy Arkansas’s petition for rehearing.  If the FERC were to order Entergy Arkansas to pay refunds on rehearing in the interruptible load proceeding the APSC’s decision would trap FERC-approved costs at Entergy Arkansas with no regulatory-approved mechanism to recover them.  In August 2011, Entergy Arkansas filed a complaint in the United States District Court for the Eastern District of Arkansas asking for a declaratory judgment that the rejection of Entergy Arkansas’s application by the APSC is preempted by the Federal Power Act.  The APSC filed a motion to dismiss the complaint.  In April 2012 the United States district court dismissed Entergy Arkansas’s complaint without prejudice stating that Entergy Arkansas’s claim is not ripe for adjudication and that Entergy Arkansas did not have standing to bring suit at this time.

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 prior 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 a motion to establish a briefing schedule on remand and 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 has appealed the April and September 2016 orders to the U.S. Court of Appeals for the D.C. Circuit. Oral argument before the D.C. Circuit was held before the D.C. Circuit in February 2018 and a decision is pending.
 
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 requesting that the FERC dismiss the complaint on the merits without hearing because the LPSC has failed to meet its burden of showing any violation of the System Agreement and failed to produce any evidence of imprudent action by the Entergy System.  In their response,

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the Utility operating companies explained that the System Agreement clearly 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.

The LPSC filed direct testimony in the proceeding alleging, among other things, (1) that Entergy violated the System Agreement by permitting Entergy Arkansas to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other Utility operating companies’ customers; and (2) that over the period 2000 - 2009, these non-requirements sales caused harm to the Utility operating companies’ customers and these customers should be compensated for this harm by Entergy.  In subsequent testimony, the LPSC modified its original damages claim in favor of quantifying damages by re-running intra-system bills.  The Utility operating companies believe the LPSC’s allegations are without merit.  A hearing in the matter was held in August 2010.

In December 2010 the ALJ issued an initial decision.  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.  Quantifying the effect of the FERC’s decision requires re-running intra-system bills for a ten-year period, and the FERC in its decision established further hearing procedures to determine the calculation of the effects.  In July 2012, Entergy and the LPSC filed requests for rehearing of the FERC’s June 2012 decision. A hearing was held in May 2013 to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision.

In August 2013 the presiding judge issued an initial decision in the calculation proceeding. The initial decision concluded that the methodology proposed by the LPSC, rather than the methodologies proposed by Entergy or the FERC Staff, should be used to calculate the payments that Entergy Arkansas is to make to the other Utility operating companies. The initial decision also concluded that the other System Agreement service schedules should not be adjusted and that payments by Entergy Arkansas should not be reflected in the rough production cost equalization bandwidth calculations for the applicable years. The initial decision recognized that the LPSC’s methodology would result in an inequitable windfall to the other Utility operating companies and, therefore, concluded that any payments by Entergy Arkansas should be reduced by 20%. 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

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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 still pending with 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.

Pursuant to the procedural schedule established in the case, Entergy Services re-ran intra-system bills for the ten-year period 2000-2009 to quantify the effects of the FERC's ruling. In November 2016 the LPSC submitted testimony disputing certain aspects of the calculations. A hearing was held in May 2017. In July 2017, the ALJ issued an initial decision concluding that Entergy Arkansas should pay $86 million plus interest to the other Utility operating companies. 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. The case is pending before the FERC. No payments will be made or received by the Utility operating companies until the FERC issues an order reviewing the initial decision and Entergy submits a subsequent filing to comply with that order.

The effect of the FERC’s decisions thus far in the case would be that Entergy Arkansas will make payments to some or all of the other Utility operating companies. Because further proceedings will still occur in the case, the amount and recipients of payments by Entergy Arkansas are unknown at this time. 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 includes interest, for its estimated increased costs and payment to the other Utility operating companies. This estimate is subject to change depending on how the FERC resolves the issues that are still outstanding in the case, including its review of the July 2017 initial decision. Entergy Arkansas’s increased costs will be attributed to Entergy Arkansas’s retail and wholesale businesses, and it is not probable that Entergy Arkansas will recover the wholesale portion. Entergy Arkansas, therefore, recorded a deferred fuel regulatory asset in the first quarter 2016 of approximately $75 million, which represents its estimate of the retail portion of the costs. 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. Because management currently expects to recover the retail portion of the costs through a base rate proceeding or newly proposed rider, the regulatory asset is reflected as Other regulatory assets as of December 31, 2017.
    
Complaint Against System Energy

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,

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Entergy Mississippi, and Entergy New Orleans under separate agreements. The current return on equity under the Unit Power Sales Agreement is 10.94%. The 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. If the parties fail to come to an agreement during settlement proceedings, a prehearing conference will be held to establish a procedural schedule for hearing proceedings.

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 Complaint Against System Energy above, and directed the parties to engage in settlement proceedings before an ALJ. If the parties fail to come to an agreement during settlement proceedings, a prehearing conference will be held to establish a procedural schedule for hearing proceedings.

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.


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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 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.

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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.  The Louisiana Act 55 financing is expected to produce additional customer benefits as compared to traditional securitization.  Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and savings to customers via a storm cost offset rider.  In April 2008 the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financing, approved requests for the Act 55 financing.  Also in April 2008, Entergy Louisiana and the LPSC staff filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana’s proposal under the Act 55 financing, which included a commitment to pass on to customers a minimum of $40 million of customer benefits through a prospective annual rate reduction of $8 million for five years.  The LPSC subsequently approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financing.  In May 2008 the Louisiana State Bond Commission granted final approval of the Act 55 financing. The settlement agreement allowed for an adjustment to the credits if there was a change in the applicable federal or state income tax rate. As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21%, the Louisiana Act 55 financing savings obligation regulatory liability related to Hurricanes Katrina and Rita was reduced by $22.3 million, with a corresponding increase to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

In July 2008 the LPFA issued $687.7 million in bonds under the aforementioned Act 55.  From the $679 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $152 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $527 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $545 million, including $17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 10% annual distribution rate.  In August 2008, the LPFA issued $278.4 million in bonds under the aforementioned Act 55.  From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $187.7 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $189.4 million, including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC that carry a 10% annual distribution rate.  Distributions are payable quarterly commencing on September 15, 2008 and have a liquidation price of $100 per unit.  The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement.  The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.  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.

Entergy and Entergy Louisiana do not report the bonds issued by the LPFA on their balance sheets because the bonds are the obligation of the LPFA, 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.


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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 again 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.

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.

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, 2017, Entergy Louisiana has a regulatory asset of $35.8 million on its balance sheet related to these new nuclear generation development costs.

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

Income taxes for 2017, 2016, and 2015 for Entergy Corporation and Subsidiaries consist of the following:
 
2017
 
2016
 
2015
 
(In Thousands)
Current:
 
 
 
 
 
Federal

$29,595

 

$45,249

 

$77,166

Foreign
—

 
68

 
97

State
15,478

 
(14,960
)
 
157,829

Total
45,073

 
30,357

 
235,092

Deferred and non-current - net
505,010

 
(840,465
)
 
(864,799
)
Investment tax credit adjustments - net
(7,513
)
 
(7,151
)
 
(13,220
)
Income taxes

$542,570

 

($817,259
)
 

($642,927
)
    
Income taxes for 2017, 2016, and 2015 for Entergy’s Registrant Subsidiaries consist of the following:
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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2015
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Federal
 

$66,966

 

$101,382

 

$25,628

 

($9,346
)
 

$53,313

 

($63,302
)
State
 
6,265

 
35,406

 
6,832

 
1,784

 
2,450

 
26,755

Total
 
73,231

 
136,788

 
32,460

 
(7,562
)
 
55,763

 
(36,547
)
Deferred and non-current - net
 
(31,463
)
 
47,220

 
31,149

 
32,890

 
(17,599
)
 
93,491

Investment tax credit adjustments - net
 
(1,227
)
 
(5,337
)
 
(1,737
)
 
(138
)
 
(914
)
 
(3,867
)
Income taxes
 

$40,541

 

$178,671

 

$61,872

 

$25,190

 

$37,250

 

$53,077


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 2017, 2016, and 2015 are:
 
2017
 
2016
 
2015
 
(In Thousands)
Net income (loss) attributable to Entergy Corporation

$411,612

 

($583,618
)
 

($176,562
)
Preferred dividend requirements of subsidiaries
13,741

 
19,115

 
19,828

Consolidated net income (loss)
425,353

 
(564,503
)
 
(156,734
)
Income taxes
542,570

 
(817,259
)
 
(642,927
)
Income (loss) before income taxes

$967,923

 

($1,381,762
)
 

($799,661
)
Computed at statutory rate (35%)

$338,773

 

($483,617
)
 

($279,881
)
Increases (reductions) in tax resulting from:
 

 
 

 
 

State income taxes net of federal income tax effect
44,179

 
40,581

 
29,944

Regulatory differences - utility plant items
39,825

 
33,581

 
32,089

Equity component of AFUDC
(33,282
)
 
(23,647
)
 
(18,191
)
Amortization of investment tax credits
(10,204
)
 
(10,889
)
 
(11,136
)
Flow-through / permanent differences
8,727

 
(19,307
)
 
(7,872
)
Tax legislation enactment (a)
560,410

 
—

 
—

Louisiana business combination
—

 
—

 
(333,655
)
Entergy Wholesale Commodities restructuring (b)
(373,277
)
 
(237,760
)
 
—

Act 55 financing settlement (d)
—

 
(63,477
)
 
—

FitzPatrick disposition
(44,344
)
 
—

 
—

Provision for uncertain tax positions (c) (d)
8,756

 
(67,119
)
 
(56,683
)
Valuation allowance
—

 
11,411

 
—

Other - net
3,007

 
2,984

 
2,458

Total income taxes as reported

$542,570

 

($817,259
)
 

($642,927
)
Effective Income Tax Rate
56.1
%
 
59.1
%
 
80.4
%

(a)
See “Other Tax Matters - Tax Cuts and Jobs Act” below for discussion of the tax legislation enactment.
(b)
See “Other Tax Matters - Entergy Wholesale Commodities Restructuring” below for discussion of the Entergy Wholesale Commodities restructuring.
(c)
See “Income Tax Audits - 2008-2009 IRS Audit” below for discussion of the most significant items for 2015.
(d)
See “Income Tax Audits - 2010-2011 IRS Audit” below for discussion of the most significant items for 2016.


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Entergy Corporation and Subsidiaries
Notes to Financial Statements


Total income taxes for the Registrant Subsidiaries differ from the amounts computed by applying the statutory income tax rate to income before taxes.  The reasons for the differences for the years 2017, 2016, and 2015 are:
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 (a)
 
(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 (b)
 
—

 
(61,620
)
 
—

 
—

 
(454
)
 
—

Non-taxable dividend income
 
—

 
(44,658
)
 
—

 
—

 
—

 
—

Provision for uncertain tax positions (b)
 
(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
%


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Table of Contents
Entergy Corporation and Subsidiaries
Notes to Financial Statements


2015
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Net income
 

$74,272

 

$446,639

 

$92,708

 

$44,925

 

$69,625

 

$111,318

Income taxes
 
40,541

 
178,671

 
61,872

 
25,190

 
37,250

 
53,077

Pretax income
 

$114,813

 

$625,310

 

$154,580

 

$70,115

 

$106,875

 

$164,395

Computed at statutory rate (35%)
 

$40,185

 

$218,859

 

$54,103

 

$24,540

 

$37,406

 

$57,538

Increases (reductions) in tax resulting from:
 
 

 
 

 
 

 
 

 
 

 
 

State income taxes net of federal income tax effect
 
6,643

 
23,650

 
5,219

 
2,887

 
1,621

 
6,403

Regulatory differences - utility plant items
 
7,299

 
3,013

 
2,383

 
2,201

 
3,703

 
12,167

Equity component of AFUDC
 
(4,979
)
 
(5,420
)
 
(1,083
)
 
(451
)
 
(1,987
)
 
(2,973
)
Amortization of investment tax credits
 
(1,201
)
 
(5,252
)
 
(160
)
 
(111
)
 
(900
)
 
(3,476
)
Flow-through / permanent differences
 
(4,062
)
 
2,460

 
431

 
(4,539
)
 
530

 
618

Non-taxable dividend income
 
—

 
(44,658
)
 
—

 
—

 
—

 
—

Provision for uncertain tax positions (c)
 
(3,978
)
 
(15,377
)
 
756

 
525

 
(3,365
)
 
(17,313
)
Other - net
 
634

 
1,396

 
223

 
138

 
242

 
113

Total income taxes as reported
 

$40,541

 

$178,671

 

$61,872

 

$25,190

 

$37,250

 

$53,077

Effective Income Tax Rate
 
35.3
%
 
28.6
%
 
40.0
%
 
35.9
%
 
34.9
%
 
32.3
%

(a)
See “Other Tax Matters - Tax Cuts and Jobs Act” below for discussion of the tax legislation enactment.
(b)
See “Income Tax Audits - 2010-2011 IRS Audit” below for discussion of the most significant items for Entergy Louisiana.
(c)
See “Income Tax Audits - 2008-2009 IRS Audit” below for discussion of the most significant items for Entergy Louisiana and System Energy.



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Entergy Corporation and Subsidiaries
Notes to Financial Statements


Significant components of accumulated deferred income taxes and taxes accrued for Entergy Corporation and Subsidiaries as of December 31, 2017 and 2016 are as follows:
 
 
2017
 
2016
 
(In Thousands)
Deferred tax liabilities:
 
 
 
Plant basis differences - net

($3,963,798
)
 

($6,362,905
)
Regulatory assets
—

 
(584,572
)
Nuclear decommissioning trusts/receivables
(1,657,808
)
 
(1,739,977
)
Pension, net funding
(350,743
)
 
(429,896
)
Combined unitary state taxes
(24,645
)
 
(33,063
)
Power purchase agreements
(19,621
)
 
(993
)
Other
(249,327
)
 
(251,719
)
Total
(6,265,942
)
 
(9,403,125
)
Deferred tax assets:
 

 
 

Nuclear decommissioning liabilities
964,945

 
1,399,468

Regulatory liabilities
841,370

 
255,272

Pension and other post-employment benefits
343,817

 
539,456

Sale and leaseback
122,397

 
135,866

Compensation
75,217

 
99,300

Accumulated deferred investment tax credit
59,285

 
92,375

Provision for allowances and contingencies
126,391

 
188,390

Net operating loss carryforwards
467,255

 
334,025

Capital losses and miscellaneous tax credits
16,738

 
18,470

Valuation allowance
(137,283
)
 
(104,277
)
Other
54,058

 
59,079

Total
2,934,190

 
3,017,424

Non-current accrued taxes (including unrecognized tax benefits)
(956,547
)
 
(991,704
)
Accumulated deferred income taxes and taxes accrued

($4,288,299
)
 

($7,377,405
)

Entergy’s estimated tax attributes carryovers and their expiration dates as of December 31, 2017 are as follows:
Carryover Description
 
Carryover Amount
 
Year(s) of expiration
 
 
 
 
 
Federal net operating losses
 
$10.7 billion
 
2023-2037
State net operating losses
 
$9.6 billion
 
2018-2037
Miscellaneous federal and state credits
 
$96.6 million
 
2018-2036

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 $106 million as of December 31, 2017 and $62 million as of December 31, 2016 have been provided on the deferred tax assets relating to these state net operating loss and credit carryovers. Additionally, valuation allowances totaling $31 million as of December 31, 2017 and $42.3 million as of December 31, 2016 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.

112
Table of Contents
Entergy Corporation and Subsidiaries
Notes to Financial Statements


Significant components of accumulated deferred income taxes and taxes accrued for the Registrant Subsidiaries as of December 31, 2017 and 2016 are as follows:
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
)

113
Table of Contents
Entergy Corporation and Subsidiaries
Notes to Financial Statements


2016
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Deferred tax liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
Plant basis differences - net
 

($1,857,554
)
 

($2,357,599
)
 

($820,971
)
 

($177,242
)
 

($835,671
)
 

($651,394
)
Regulatory assets
 
(109,241
)
 
(219,750
)
 
(25,309
)
 
(36,301
)
 
(153,914
)
 
(39,879
)
Nuclear decommissioning trusts
 
(144,250
)
 
(119,544
)
 
—

 
—

 
—

 
(83,891
)
Pension, net funding
 
(123,889
)
 
(122,465
)
 
(34,284
)
 
(16,307
)
 
(28,371
)
 
(29,357
)
Deferred fuel
 
(14,774
)
 
(1,778
)
 
(12,770
)
 
(5,229
)
 
(2,808
)
 
(1,137
)
Power purchase agreements
 
—

 
—

 
—

 
—

 
—

 
—

Other
 
(47,785
)
 
(22,136
)
 
(12,474
)
 
(18,536
)
 
(8,812
)
 
(2,051
)
Total
 
(2,297,493
)
 
(2,843,272
)
 
(905,808
)
 
(253,615
)
 
(1,029,576
)
 
(807,709
)
Deferred tax assets:
 
 

 
 

 
 

 
 

 
 

 
 

Regulatory liabilities
 
5,768

 
175,973

 
18,833

 
25,240

 
15,814

 
13,644

Nuclear decommissioning liabilities
 
124,206

 
55,408

 
—

 
—

 
—

 
53,113

Pension and other post-employment benefits
 
(24,467
)
 
145,401

 
(8,042
)
 
(12,070
)
 
(19,096
)
 
(1,182
)
Sale and leaseback
 
—

 
33,383

 
—

 
—

 
—

 
102,483

Accumulated deferred investment tax credit
 
13,848

 
54,509

 
3,315

 
239

 
4,527

 
15,936

Provision for allowances and contingencies
 
(1,497
)
 
124,309

 
21,817

 
36,466

 
5,904

 
—

Power purchase agreements
 
(3,094
)
 
29,827

 
1,905

 
—

 
140

 
—

Unbilled/deferred revenues
 
6,799

 
(35,006
)
 
5,085

 
3,751

 
11,902

 
—

Compensation
 
2,787

 
5,309

 
1,492

 
685

 
1,587

 
360

Net operating loss carryforwards
 
69,524

 
17,125

 
—

 
—

 
—

 
—

Capital losses and miscellaneous tax credits
 
2,074

 
—

 
4,487

 
—

 
—

 
—

Other
 
174

 
17,110

 
1,152

 
496

 
2,955

 
—

Total
 
196,122

 
623,348

 
50,044

 
54,807

 
23,733

 
184,354

Non-current accrued taxes (including unrecognized tax benefits)
 
(85,252
)
 
(471,194
)
 
(5,567
)
 
(136,145
)
 
(21,804
)
 
(489,510
)
Accumulated deferred income taxes and taxes accrued
 

($2,186,623
)
 

($2,691,118
)
 

($861,331
)
 

($334,953
)
 

($1,027,647
)
 

($1,112,865
)


114
Table of Contents
Entergy Corporation and Subsidiaries
Notes to Financial Statements


The Registrant Subsidiaries’ estimated tax attributes carryovers and their expiration dates as of December 31, 2017 are as follows:
 
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
 
 
 
 
 
 
 
 
 
 
 
Federal net operating losses
 
$77 million
 
$4.3 billion
 
$86.6 million
 
$1.1 billion
 
—
 
—
Year(s) of expiration
 
2030-2037
 
2035-2037
 
2030-2037
 
2037
 
N/A
 
N/A
 
 
 
 
 
 
 
 
 
 
 
 
 
State net operating losses
 
—
 
$5 billion
 
—
 
$1.2 billion
 
—
 
—
Year(s) of expiration
 
N/A
 
2029-2037
 
N/A
 
2037
 
N/A
 
N/A
 
 
 
 
 
 
 
 
 
 
 
 
 
Misc. federal credits
 
$2.7 million
 
$1.7 million
 
$2.7 million
 
$2.1 million
 
$0.6 million
 
$2.5 million
Year(s) of expiration
 
2029-2036
 
2029-2036
 
2029-2036
 
2029-2036
 
2029-2036
 
2029-2036
 
 
 
 
 
 
 
 
 
 
 
 
 
State credits
 
—
 
—
 
$4.9 million
 
—
 
$3.2 million
 
$10 million
Year(s) of expiration
 
N/A
 
N/A
 
2018-2021
 
N/A
 
2026
 
2018-2021

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:
 
2017
 
2016
 
2015
 
(In Thousands)
Gross balance at January 1

$3,909,855

 

$2,611,585

 

$4,736,785

Additions based on tax positions related to the current year
1,120,687

 
1,532,782

 
1,850,705

Additions for tax positions of prior years
283,683

 
368,404

 
59,815

Reductions for tax positions of prior years (a)
(442,379
)
 
(265,653
)
 
(3,966,535
)
Settlements
—

 
(337,263
)
 
(68,227
)
Lapse of statute of limitations
—

 
—

 
(958
)
Gross balance at December 31
4,871,846

 
3,909,855

 
2,611,585

Offsets to gross unrecognized tax benefits:
 

 
 

 
 

Carryovers and refund claims
(3,945,524
)
 
(2,922,085
)
 
(1,264,483
)
Cash paid to taxing authorities
(10,000
)
 
(10,000
)
 
—

Unrecognized tax benefits net of unused tax attributes, refund claims and payments (b)

$916,322

 

$977,770

 

$1,347,102


(a)
The primary reduction for 2015 is related to the nuclear decommissioning costs treatment discussed in “Income Tax Audits - 2008-2009 IRS Audit” below.
(b)
Potential tax liability above what is payable on tax returns


115
Table of Contents
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Notes to Financial Statements


The balances of unrecognized tax benefits include $1,462 million, $1,240 million, and $955 million as of December 31, 2017, 2016, and 2015, respectively, which, if recognized, would lower the effective income tax rates.  Because of the effect of deferred tax accounting, the remaining balances of unrecognized tax benefits of $3,410 million, $2,670 million, and $1,657 million as of December 31, 2017, 2016, and 2015, 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, 2017, 2016, and 2015 accrued balance for the possible payment of interest is approximately $38 million, $30 million, and $27 million, respectively.

A reconciliation of the Registrant Subsidiaries’ beginning and ending amount of unrecognized tax benefits for 2017, 2016, and 2015 is as follows:
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


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



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2015
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Gross balance at January 1, 2015
 

$362,912

 

$1,205,929

 

$20,144

 

$53,763

 

$17,264

 

$258,242

Additions based on tax positions related to the current year (b)
 
2,196

 
1,367,058

 
566

 
472

 
657

 
472,304

Additions for tax positions of prior years
 
1,057

 
7,992

 
8,140

 
48

 
2,914

 
913

Reductions for tax positions of prior years
 
(340,720
)
 
(859,430
)
 
—

 
(386
)
 
(3,981
)
 
(253,141
)
Settlements
 
—

 
(30,888
)
 
(9,368
)
 
—

 
(3,392
)
 
—

Gross balance at December 31, 2015
 
25,445

 
1,690,661

 
19,482

 
53,897

 
13,462

 
478,318

Offsets to gross unrecognized tax benefits:
 
 

 
 

 
 

 
 

 
 

 
 

Loss carryovers
 
(3,613
)
 
(893,764
)
 
(1,016
)
 
(506
)
 
(276
)
 
(133,611
)
Unrecognized tax benefits net of unused tax attributes and payments
 

$21,832

 

$796,897

 

$18,466

 

$53,391

 

$13,186

 

$344,707


(a)
The primary additions for Entergy Louisiana in 2016 and for Entergy New Orleans in 2017 are related to the mark-to-market treatment discussed in “Other Tax Matters - Tax Accounting Methods” below.
(b)
The primary addition for Entergy Louisiana and System Energy is related to the nuclear decommissioning costs 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,
 
2017
 
2016
 
2015
 
(In Millions)
Entergy Arkansas

$2.6

 

$3.6

 

$4.5

Entergy Louisiana

$575.8

 

$473.3

 

$692.7

Entergy Mississippi

$—

 

$—

 

$8.1

Entergy New Orleans

$31.7

 

$33.6

 

$50.7

Entergy Texas

$4.4

 

$7.0

 

$5.2

System Energy

$—

 

$—

 

$0.7


The Registrant Subsidiaries accrue interest and penalties related to unrecognized tax benefits in income tax expense.  Penalties have not been accrued.  Accrued balances for the possible payment of interest are as follows:
 
December 31,
 
2017
 
2016
 
2015
 
(In Millions)
Entergy Arkansas

$1.6

 

$1.4

 

$1.3

Entergy Louisiana

$14.1

 

$8.4

 

$9.3

Entergy Mississippi

$1.0

 

$0.8

 

$0.4

Entergy New Orleans

$2.1

 

$1.5

 

$1.8

Entergy Texas

$0.4

 

$1.2

 

$1.2

System Energy

$8.5

 

$3.7

 

$0.7



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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 2012. All state taxing authorities’ examinations are complete for years before 2010. 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.

2006-2007 IRS Audit

In the first quarter 2015, the IRS finalized tax and interest computations from the 2006-2007 audit that resulted in a reversal of Entergy’s provision for uncertain tax positions related to accrued interest of approximately $20 million, including decreases of approximately $4 million for Entergy Arkansas, $11 million for Entergy Louisiana, and $1 million for System Energy.

2008-2009 IRS Audit

In the fourth quarter 2009, Entergy filed Applications for Change in Accounting Method (the “2009 CAM”) for tax purposes with the IRS for certain costs under Section 263A of the Internal Revenue Code.  In the Applications, Entergy proposed to treat the nuclear decommissioning liability associated with the operation of its nuclear power plants as a production cost properly includable in cost of goods sold.  The effect of the 2009 CAM was a $5.7 billion reduction in 2009 taxable income.  The 2009 CAM was adjusted to $9.3 billion in 2012.

In the fourth quarter 2012, the IRS disallowed the reduction to 2009 taxable income related to the 2009 CAM.  In the third quarter 2013, the Internal Revenue Service issued its Revenue Agent Report (RAR) for the tax years 2008-2009. As a result of the issuance of this RAR, Entergy and the IRS resolved all of the 2008-2009 issues described above except for the 2009 CAM. Entergy disagreed with the IRS’s disallowance of the 2009 CAM and filed a protest with the IRS Appeals Division in October 2013.

In August 2015, Entergy and the IRS agreed on the treatment of the 2009 position regarding nuclear decommissioning liabilities from the 2008-2009 audit. The agreement provides that Entergy is entitled to deduct approximately $118 million of the $9.3 billion claimed in 2009. The agreement effectively settled all matters pertaining to the 2009 tax year and increased Entergy’s 2009 federal income tax liability by $2.4 million.

2010-2011 IRS Audit

The IRS completed its examination of the 2010 and 2011 tax years and issued its 2010-2011 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. Entergy Louisiana also accrued a regulatory liability of $16.1 million ($9.9 million net-of-tax) in accordance with the terms of Entergy Louisiana’s previous settlement agreement approved by the LPSC regarding 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.

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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 H.R. 1, also known as 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. Accordingly, the potential interest expense disallowance is not expected to have a material effect on Entergy’s or the Registrant Subsidiaries’ interest deductions.
The Act extends and modifies the additional first-year depreciation deduction (bonus depreciation). The Act excludes from bonus-eligible qualified property, however, 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.
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 provides for the indefinite carryforward of NOLs arising in tax years ending after December 31, 2017, as opposed to the current 20-year carryforward. 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 believe it is probable that a significant portion of the decrease in the net accumulated deferred income tax liability, which is often referred to as “excess ADIT,” will be returned to customers. Accordingly, it is appropriate for Entergy and the Registrant Subsidiaries to establish a regulatory liability for the probable reduction in future revenue. Entergy’s December 31, 2017 balance sheet reflects a regulatory liability of $2.9 billion due to a re-measurement of deferred tax assets and liabilities resulting from the income tax rate change. 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

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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, 2017 balance sheets reflect net regulatory liabilities for income taxes as follows: Entergy Arkansas, $986 million; Entergy Louisiana, $725 million; Entergy Mississippi, $411 million; Entergy New Orleans, $119 million; Entergy Texas, $413 million; and System Energy, $246 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 return the protected portion of the excess ADIT in conformity with the normalization requirements. The Registrant Subsidiaries’ net regulatory liability for income taxes 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.
The return period of the unprotected excess ADIT is subject to the regulatory process in each jurisdiction and has yet to be determined. Further, a portion of the unprotected excess ADIT amount is associated with amounts previously securitized and may be treated differently than other unprotected excess ADIT consistent with applicable agreements and/or not be subject to the same schedule for the return to customers as the remaining unprotected excess ADIT. The Registrant Subsidiaries’ net regulatory liability for income taxes 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 is 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’s accounting for the effects of the Act is complete using the best estimates and information available to it at this time. Entergy anticipates that the Act, including the federal corporate income tax rate change, however, will 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) the filing of all applicable federal and state income tax returns that include any tax elections that may change estimates accrued in the year-end recording process; 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 adjustments

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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 will potentially affect the regulatory liability for income taxes.
Louisiana Business Combination

In October 2015 two of Entergy’s Louisiana utilities, Entergy Gulf States Louisiana and Entergy Louisiana, combined their businesses into a legal entity which is identified as Entergy Louisiana herein. The structure of the business combination generated both a permanent difference and a temporary difference under FASB ASC Topic 740. The permanent difference resulted from recognition of the Waterford 3 and River Bend decommissioning liabilities as part of the business combination. Recognition of such decommissioning liabilities required Entergy to also recognize a taxable gain. The taxable gain resulted in a temporary difference because the gain provided for an increase in tax basis. Entergy Louisiana maintained a carryover tax basis in the assets received; and, to the extent that the increase in tax basis will provide additional tax depreciation, Entergy recorded a deferred tax asset. Entergy Louisiana obtained the corresponding deferred tax asset in the business combination. The permanent tax benefit net of ancillary tax charges was approximately $334 million. Consistent with the terms of the stipulated settlement in the business combination proceeding, electric customers of Entergy Louisiana will realize customer credits associated with the business combination. Accordingly, in October 2015, Entergy recorded a regulatory liability of $107 million ($66 million net-of-tax) which partially offsets the effect of the aforementioned deferred tax asset. The deferred tax asset and the regulatory liability, net-of-tax, increased Entergy Louisiana’s member’s equity by $268 million. See Note 2 to the financial statements for further discussion of the business combination.

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.

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 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

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billion deductible temporary difference. In 2017, Entergy New Orleans also elected mark-to-market income tax treatment with respect to the Unit Power Sales Agreement resulting in a $1.1 billion deductible temporary difference.

Accounting Pronouncements

In the first quarter 2017, Entergy implemented ASU No. 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.” Entergy will now prospectively recognize all income tax effects related to share-based payments through the income statement. In the first quarter 2017, stock option expirations, along with other stock compensation activity, resulted in the write-off of $11.5 million of deferred tax assets. Entergy’s stock-based compensation plans are discussed in Note 12 to the financial statements.


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 August 2022.  The facility permits 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, 2017 was 2.55% 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, 2017.
Capacity
 
Borrowings
 
Letters of Credit
 
Capacity Available
(In Millions)
$3,500
 
$210
 
$6
 
$3,284

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, 2017, Entergy Corporation had $1.467 billion of commercial paper outstanding.  The weighted-average interest rate for the year ended December 31, 2017 was 1.49%.


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Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2017 as follows:
Company
 
Expiration Date
 
Amount of Facility
 
Interest Rate (a)
 
 Amount Drawn as of December 31, 2017
 
Letters of Credit Outstanding as of December 31, 2017
Entergy Arkansas
 
April 2018
 
$20 million (b)
 
2.82%
 
—
 
—
Entergy Arkansas
 
August 2022
 
$150 million (c)
 
2.82%
 
—
 
—
Entergy Louisiana
 
August 2022
 
$350 million (c)
 
2.82%
 
—
 
$9.1 million
Entergy Mississippi
 
May 2018
 
$10 million (d)
 
3.07%
 
—
 
—
Entergy Mississippi
 
May 2018
 
$20 million (d)
 
3.07%
 
—
 
—
Entergy Mississippi
 
May 2018
 
$35 million (d)
 
3.07%
 
—
 
—
Entergy Mississippi
 
May 2018
 
$37.5 million (d)
 
3.07%
 
—
 
—
Entergy New Orleans
 
November 2018
 
$25 million (c)
 
3.04%
 
—
 
$0.8 million
Entergy Texas
 
August 2022
 
$150 million (c)
 
3.07%
 
—
 
$25.6 million

(a)
The interest rate is the estimated interest rate as of December 31, 2017 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 permits the issuance of letters of credit against a portion of the borrowing capacity of the facility as follows: $5 million for Entergy Arkansas; $15 million for Entergy Louisiana; $10 million for Entergy New Orleans; and $30 million for Entergy Texas.  
(d)
Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option. 

The commitment fees on the credit facilities range from 0.075% to 0.275% of the undrawn commitment amount. Each of the credit facilities requires the Registrant Subsidiary borrower to maintain a debt ratio, as defined, of 65% or less of its total capitalization. Each Registrant Subsidiary is in compliance with this covenant.

In addition, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each entered into one or more uncommitted standby letter of credit facilities as a means to post collateral to support its obligations to MISO. Following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2017:
Company
 
Amount of Uncommitted Facility
 
Letter of Credit Fee
 
Letters of Credit Issued as of December 31, 2017 (a)
Entergy Arkansas
 
$25 million
 
0.70%
 
$1.0 million
Entergy Louisiana
 
$125 million
 
0.70%
 
$29.7 million
Entergy Mississippi
 
$40 million
 
0.70%
 
$15.3 million
Entergy New Orleans
 
$15 million
 
1.00%
 
$1.4 million
Entergy Texas
 
$50 million
 
0.70%
 
$22.8 million

(a)
As of December 31, 2017, letters of credit posted with MISO covered financial transmission right exposure of $0.2 million for Entergy Arkansas, $0.1 million for Entergy Mississippi, and $0.05 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 are effective through October 31, 2019. In addition to borrowings from commercial

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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, 2017 (aggregating both internal and external short-term borrowings) for the Registrant Subsidiaries:

 
Authorized
 
Borrowings
 
(In Millions)
Entergy Arkansas
$250
 
$166
Entergy Louisiana
$450
 
—
Entergy Mississippi
$175
 
—
Entergy New Orleans
$150
 
—
Entergy Texas
$200
 
—
System Energy
$200
 
—

Entergy Nuclear Vermont Yankee Credit Facilities

Entergy Nuclear Vermont Yankee has a credit facility guaranteed by Entergy Corporation with a borrowing capacity of $145 million that expires in November 2020. Entergy Nuclear Vermont Yankee does not have the ability to issue letters of credit against the credit facility. This facility provides working capital to Entergy Nuclear Vermont Yankee for general business purposes including, without limitation, the decommissioning of Vermont Yankee. The commitment fee is currently 0.20% of the undrawn commitment amount.  As of December 31, 2017, $104 million in cash borrowings were outstanding under the credit facility.  The weighted average interest rate for the year ended December 31, 2017 was 2.64% on the drawn portion of the facility. 

Entergy Nuclear Vermont Yankee also had an uncommitted credit facility guaranteed by Entergy Corporation
with a borrowing capacity of $85 million that expired in January 2018.  As of December 31, 2017, there were no cash borrowings outstanding under the credit facility. The estimated interest rate for the year ended December 31, 2017 would have been 3.07% on the drawn portion of the facility.

Variable Interest Entities (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)

See Note 17 to the financial statements for a discussion of the consolidation of the nuclear fuel company variable interest entities (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, 2017:
Company
 
Expiration Date
 
Amount of Facility
 
Weighted Average Interest Rate on Borrowings (a)
 
Amount Outstanding as of December 31, 2017
 
 
(Dollars in Millions)
Entergy Arkansas VIE
 
May 2019
 
$80
 
2.87%
 

$74.9
 (b)
Entergy Louisiana River Bend VIE
 
May 2019
 
$105
 
2.38%
 

$65.7

Entergy Louisiana Waterford VIE
 
May 2019
 
$85
 
2.64%
 

$79.9
 (c)
System Energy VIE
 
May 2019
 
$120
 
2.52%
 

$67.8
 (d)

(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

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company variable interest entity for Entergy Louisiana River Bend does not issue commercial paper, but borrows directly on its bank credit facility.
(b)
Includes borrowings on the credit facility and commercial paper. Commercial paper is classified as a current liability and the amount outstanding for Entergy Arkansas VIE as of December 31, 2017 was $50 million.
(c)
Includes borrowings on the credit facility and commercial paper. Commercial paper is classified as a current liability and the amount outstanding for Entergy Louisiana Waterford VIE as of December 31, 2017 was $43.5 million.
(d)
Includes borrowings on the credit facility and commercial paper. Commercial paper is classified as a current liability and the amount outstanding for System Energy VIE as of December 31, 2017 was $17.8 million.

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, 2017 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
 
3.78% Series I due October 2018
 
$85 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 long-term financing authorizations from the FERC that extend through October 2019 for issuances by its nuclear fuel company variable interest entities.



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

Long-term debt for Entergy Corporation and subsidiaries as of December 31, 2017 and 2016 consisted of:
Type of Debt and Maturity
 
Weighted Average Interest Rate December 31, 2017
 
Interest Rate Ranges at December 31,
 
Outstanding at December 31,
2017
 
2016
 
2017
 
2016
 
 
 
 
 
 
 
 
(In Thousands)
Mortgage Bonds
 
 
 
 
 
 
 
 
 
 
2018-2022
 
4.39%
 
2.55%-7.125%
 
2.55%-7.125%
 

$2,550,000

 

$2,550,000

2023-2027
 
3.72%
 
2.40%-5.59%
 
2.40%-5.59%
 
4,735,000

 
3,765,000

2028-2031
 
3.06%
 
2.85%-3.25%
 
2.85%-3.25%
 
1,125,000

 
1,125,000

2044-2066
 
5.00%
 
4.70%-5.625%
 
4.70%-5.625%
 
2,960,000

 
2,960,000

Governmental Bonds (a)
 
 
 
 
 
 
 
 
 
 
2017-2022
 
5.20%
 
2.375%-5.875%
 
1.55%-5.875%
 
179,000

 
233,700

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

 
198,680

Securitization Bonds
 
 
 
 
 
 
 
 
 
 
2018-2027
 
3.79%
 
2.04%-5.93%
 
2.04%-5.93%
 
551,499

 
669,310

Variable Interest Entities Notes Payable (Note 4)
 
 
 
 
 
 
 
 
 
 
2017-2023
 
3.48%
 
3.17%-3.92%
 
2.62%-4.02%
 
345,000

 
555,000

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
 
2.55%
 
2.23%
 
210,000

 
700,000

Vermont Yankee Credit Facility (Note 4)
 
n/a
 
2.64%
 
2.17%
 
103,500

 
44,500

Entergy Arkansas VIE Credit Facility (Note 4)
 
n/a
 
2.87%
 
—
 
24,900

 
—

Entergy Louisiana River Bend VIE Credit Facility (Note 4)
 
n/a
 
2.38%
 
—
 
65,650

 
—

Entergy Louisiana Waterford VIE Credit Facility (Note 4)
 
n/a
 
2.64%
 
—
 
36,360

 
—

System Energy VIE Credit Facility (Note 4)
 
n/a
 
2.52%
 
—
 
50,000

 
—

Long-term DOE Obligation (b)
 
—
 
—
 
—
 
183,435

 
181,853

Waterford 3 Lease Obligation (c)
 
n/a
 
—
 
8.09%
 
—

 
57,492

Waterford Series Collateral Trust Mortgage Notes due 2017 (c)
 
n/a
 
—
 
(d)
 
—

 
42,703

Grand Gulf Lease Obligation (c)
 
n/a
 
5.13%
 
5.13%
 
34,356

 
34,359

Unamortized Premium and Discount - Net
 
 
 
 
 
 
 
(13,911
)
 
(19,397
)
Unamortized Debt Issuance Costs
 
 
 
 
 
 
 
(126,033
)
 
(128,849
)
Other
 
 
 
 
 
 
 
12,830

 
13,204

Total Long-Term Debt
 
 
 
 
 
 
 
15,075,266

 
14,832,555

Less Amount Due Within One Year
 
 
 
 
 
 
 
760,007

 
364,900

Long-Term Debt Excluding Amount Due Within One Year
 
 
 
 
 
 
 

$14,315,259

 

$14,467,655

Fair Value of Long-Term Debt (e)
 
 
 
 
 
 
 

$15,367,453

 

$14,815,535



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(a)
Consists of pollution control revenue bonds and environmental revenue bonds, some of which are secured by collateral mortgage bonds.
(b)
Pursuant to the Nuclear Waste Policy Act of 1982, Entergy’s nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service.  The contracts include a one-time fee for generation prior to April 7, 1983.  Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt.
(c)
See Note 10 to the financial statements for further discussion of the Waterford 3 lease obligation and Entergy Louisiana’s acquisition of the equity participant’s beneficial interest in the Waterford 3 leased assets and for further discussion of the Grand Gulf lease obligation.
(d)
This note did not have a stated interest rate, but had an implicit interest rate of 7.458%.
(e)
The fair value excludes lease obligations of $34 million at System Energy and long-term DOE obligations of $183 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.

The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2017, for the next five years are as follows:
 
Amount
 
(In Thousands)
2018

$760,000

2019

$857,679

2020

$898,500

2021

$960,764

2022

$1,304,431


In November 2000, Entergy’s non-utility nuclear business purchased the FitzPatrick and Indian Point 3 power plants in a seller-financed transaction. As part of the purchase agreement with NYPA, Entergy recorded a liability representing the net present value of the payments Entergy would be liable to NYPA for each year that the FitzPatrick and Indian Point 3 power plants would run beyond their respective original NRC license expiration date. In October 2015, Entergy announced a planned shutdown of FitzPatrick at the end of its fuel cycle. As a result of the announcement, Entergy reduced this liability by $26.4 million pursuant to the terms of the purchase agreement. 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. As part of the trust transfer agreement, the original decommissioning agreements were amended, and the Entergy subsidiaries’ obligation to make additional license extension payments to NYPA was eliminated. In the third quarter 2016, Entergy removed the note payable of $35.1 million from the consolidated balance sheet.

Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through October 2019.  Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2018. Entergy New Orleans has also obtained long-term financing authorization from the City Council that extends through June 2018, as the City Council has concurrent jurisdiction with the FERC over such issuances.

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);

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•
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.

Long-term debt for the Registrant Subsidiaries as of December 31, 2017 and 2016 consisted of:
 
 
2017
 
2016
 
 
(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

 
380,000

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
 
2,560,000

 
2,340,000

Governmental Bonds (a):
 
 
 
 
1.55% Series due 2017, Jefferson County (d)
 
—

 
54,700

2.375% Series due 2021, Independence County (d)
 
45,000

 
45,000

Total governmental bonds
 
45,000

 
99,700

Variable Interest Entity Notes Payable and Credit Facility (Note 4):
 
 
 
 
2.62% Series K due December 2017
 
—

 
60,000

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 May 2019, weighted avg rate 2.87%
 
24,900

 
—

Total variable interest entity notes payable and credit facility
 
154,900

 
190,000

Securitization Bonds:
 
 
 
 
2.30% Series Senior Secured due August 2021
 
35,764

 
49,548

Total securitization bonds
 
35,764

 
49,548

Other:
 
 
 
 
Long-term DOE Obligation (b)
 
183,435

 
181,853

Unamortized Premium and Discount – Net
 
5,307

 
984

Unamortized Debt Issuance Costs
 
(34,049
)
 
(34,357
)
Other
 
2,042

 
2,057

Total Long-Term Debt
 
2,952,399

 
2,829,785

Less Amount Due Within One Year
 
—

 
114,700

Long-Term Debt Excluding Amount Due Within One Year
 

$2,952,399

 

$2,715,085

Fair Value of Long-Term Debt (c)
 

$2,865,844

 

$2,623,910



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2017
 
2016
 
 
(In Thousands)
Entergy Louisiana
 
 
 
 
Mortgage Bonds:
 
 
 
 
6.0% Series due May 2018
 

$375,000

 

$375,000

6.50% Series due September 2018
 
300,000

 
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

 
—

3.25% Series due April 2028
 
425,000

 
425,000

3.05% Series due June 2031
 
325,000

 
325,000

5.0% Series due July 2044
 
170,000

 
170,000

4.95% Series due January 2045
 
450,000

 
450,000

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
 
5,690,000

 
5,240,000

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):
 
 
 
 
3.25% Series G due July 2017
 
—

 
25,000

3.25% Series Q due July 2017
 
—

 
75,000

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 May 2019, weighted avg rate 2.38%
 
65,650

 
—

Credit Facility due May 2019, weighted avg rate 2.64%
 
36,360

 
—

Total variable interest entity notes payable and credit facilities
 
232,010

 
230,000

Securitization Bonds:
 
 
 
 
2.04% Series Senior Secured due September 2023
 
79,228

 
100,972

Total securitization bonds
 
79,228

 
100,972

Other:
 
 
 
 
Waterford 3 Lease Obligation (Note 10) (e)
 
—

 
57,492

Waterford Series Collateral Trust Mortgage Notes due 2017 (Note 10) (f)
 
—

 
42,703

Unamortized Premium and Discount - Net
 
(13,877
)
 
(14,917
)
Unamortized Debt Issuance Costs
 
(48,540
)
 
(48,972
)
Other
 
6,570

 
6,833

Total Long-Term Debt
 
6,144,071

 
5,812,791

Less Amount Due Within One Year
 
675,002

 
200,198

Long-Term Debt Excluding Amount Due Within One Year
 

$5,469,069

 

$5,612,593

Fair Value of Long-Term Debt (c)
 

$6,389,774

 

$5,929,488



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2017
 
2016
 
 
(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

 
—

2.85% Series due June 2028
 
375,000

 
375,000

4.90% Series due October 2066
 
260,000

 
260,000

Total mortgage bonds
 
1,285,000

 
1,135,000

Other:
 
 
 
 
Unamortized Premium and Discount – Net
 
(1,155
)
 
(766
)
Unamortized Debt Issuance Costs
 
(13,723
)
 
(13,318
)
Total Long-Term Debt
 
1,270,122

 
1,120,916

Less Amount Due Within One Year
 
—

 
—

Long-Term Debt Excluding Amount Due Within One Year
 

$1,270,122

 

$1,120,916

Fair Value of Long-Term Debt (c)
 

$1,285,741

 

$1,086,203


 
 
2017
 
2016
 
 
(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

5.0% Series due December 2052
 
30,000

 
30,000

5.50% Series due April 2066
 
110,000

 
110,000

Total mortgage bonds
 
350,000

 
350,000

Securitization Bonds:
 
 
 
 
       2.67% Series Senior Secured due June 2027
 
76,707

 
87,307

Total securitization bonds
 
76,707


87,307

Other:
 
 
 
 
Payable to Entergy Louisiana due November 2035
 
18,423

 
20,527

Unamortized Premium and Discount – Net
 
(206
)
 
(245
)
Unamortized Debt Issuance Costs
 
(8,054
)
 
(8,595
)
Total Long-Term Debt
 
436,870

 
448,994

Less Amount Due Within One Year
 
2,077

 
2,104

Long-Term Debt Excluding Amount Due Within One Year
 

$434,793

 

$446,890

Fair Value of Long-Term Debt (c)
 

$455,968

 

$455,459


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2017
 
2016
 
 
(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

 
—

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

 
1,085,000

Securitization Bonds:
 
 
 
 
5.79% Series Senior Secured, Series A due October 2018
 
—

 
23,584

3.65% Series Senior Secured, Series A due August 2019
 
30,769

 
74,899

5.93% Series Senior Secured, Series A due June 2022
 
110,431

 
114,400

4.38% Series Senior Secured, Series A due November 2023
 
218,600

 
218,600

Total securitization bonds
 
359,800

 
431,483

Other:
 
 
 
 
Unamortized Premium and Discount - Net
 
(1,498
)
 
(1,579
)
Unamortized Debt Issuance Costs
 
(10,366
)
 
(10,809
)
Other
 
4,214

 
4,312

Total Long-Term Debt
 
1,587,150

 
1,508,407

Less Amount Due Within One Year
 
—

 
—

Long-Term Debt Excluding Amount Due Within One Year
 

$1,587,150

 

$1,508,407

Fair Value of Long-Term Debt (c)
 

$1,661,902

 

$1,600,156



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2017
 
2016
 
 
(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):
 
 
 
 
4.02% Series H due February 2017
 
—

 
50,000

3.78% Series I due October 2018
 
85,000

 
85,000

Credit Facility due May 2019, weighted avg rate 2.52%
 
50,000

 
—

Total variable interest entity notes payable and credit facility
 
135,000

 
135,000

Other:
 
 
 
 
Grand Gulf Lease Obligation 5.13% (Note 10)
 
34,356

 
34,359

Unamortized Premium and Discount – Net
 
(415
)
 
(503
)
Unamortized Debt Issuance Costs
 
(1,455
)
 
(1,727
)
Other
 
2

 
3

Total Long-Term Debt
 
551,488

 
551,132

Less Amount Due Within One Year
 
85,004

 
50,003

Long-Term Debt Excluding Amount Due Within One Year
 

$466,484

 

$501,129

Fair Value of Long-Term Debt (c)
 

$529,119

 

$529,520


(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 $183 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)
The interest rate as of December 31, 2016 was 8.09%. See Note 10 to the financial statements for further discussion of Entergy Louisiana’s acquisition of the equity participant’s beneficial interest in the Waterford 3 leased assets in March 2016.
(f)
This note did not have a stated interest rate, but had an implicit interest rate of 7.458%.

The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2017, for the next five years are as follows:
 
Entergy
Arkansas
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
Entergy
Texas
 
System
Energy
 
(In Thousands)
2018

$—

 

$675,000

 

$—

 

$2,077

 

$—

 

$85,000

2019

$24,900

 

$102,010

 

$150,000

 

$1,979

 

$530,769

 

$50,000

2020

$—

 

$320,000

 

$—

 

$26,838

 

$—

 

$—

2021

$520,764

 

$240,000

 

$—

 

$1,618

 

$200,000

 

$—

2022

$—

 

$200,000

 

$—

 

$1,326

 

$110,431

 

$134,000


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Notes to Financial Statements


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 three years in the amount of $14.1 million for 2018, $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 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 four years in the amounts of $22.3 million for 2018, $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 million for 2018, $11.2 million for 2019, $11.6 million for 2020, $11.9 million for 2021, and $12.2 million for 2022. 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

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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, 2017 the remaining amount outstanding on Tranche A-3 was $110.4 million.

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 four years in the amounts of $29.2 million for 2018, $30.9 million for 2019, $32.8 million for 2020, and $17.5 million for 2021. All of the scheduled principal payments for 2018-2021 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 (a)
144,800

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

Total senior secured transition bonds

$545,900


(a)     As of December 31, 2017 the remaining amount outstanding on Tranche A-2 was $30.8 million.

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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 five years in the amount of $45.8 million for 2018, $47.6 million for 2019, $49.8 million for 2020, $52 million for 2021, and $54.3 million for 2022. Of the scheduled principal payments for 2018, $30.8 million are for Tranche A-2 and $15 million are for Tranche A-3. All of the scheduled principle payments for 2019-2022 are for Tranche A-3. Tranche A-1 has 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.


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

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, 2017 and 2016 are presented below.  All series of the Utility preferred stock are redeemable at the option of the related company.
 
 
Shares/Units
Authorized
 
Shares/Units
Outstanding
 
 
 
 
 
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
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

 
313,500

 
313,500

 

$31,350

 

$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

 
—

 
14,398

 
—

Entergy Mississippi, 4.36%-4.92% Series
 
203,807

 
203,807

 
203,807

 
203,807

 
20,381

 
20,381

Entergy New Orleans, 4.36%-5.56% Series
 
—

 
197,798

 
—

 
197,798

 
—

 
19,780

Total Utility Preferred Stock or Preferred Membership Interests without sinking fund
 
642,307

 
825,105

 
642,307

 
825,105

 
173,554

 
178,936

Entergy Wholesale Commodities:
 
 
 
 
 
 
 
 
 
 
 
 
Preferred Stock without sinking fund:
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Finance Holding, Inc. 8.75% (c)
 
250,000

 
250,000

 
250,000

 
250,000

 
24,249

 
24,249

Total Subsidiaries’ Preferred Stock without sinking fund
 
892,307

 
1,075,105

 
892,307

 
1,075,105

 

$197,803

 

$203,185


(a)
Dollar amount outstanding is net of $2,575 thousand of preferred stock issuance costs.
(b)
Dollar amount outstanding is net of $602 thousand of preferred stock issuance costs.
(c)
Dollar amount outstanding is net of $751 thousand of preferred stock issuance costs.

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In November 2017, Entergy Utility Holding Company, LLC issued 15,000 shares of $1,000 par value 6.25% Series B Preferred Membership Interests, all of which are outstanding as of December 31, 2017. 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 share.

In October 2015, Entergy Utility Holding Company, LLC issued 110,000 shares of $1,000 par value 7.5% Series A Preferred Membership Interests, all of which are outstanding as of December 31, 2017. 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 share.

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 Holding, Inc.’s option, at the fixed redemption price of $100 per share.
 
The number of shares and units authorized and outstanding and dollar value of preferred stock for Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans as of December 31, 2017 and 2016 are presented below.  All series of the Utility operating companies’ preferred stock are redeemable at the respective company’s option at the call prices presented.  Dividends and distributions paid on all of Entergy’s preferred stock and membership interests series are eligible for the dividends received deduction.  
 
 
Shares
Authorized
and Outstanding
 
 
 
Call Price per
Share as of
December 31,
 
 
2017
 
2016
 
2017
 
2016
 
2017
Entergy Arkansas Preferred Stock
 
 
 
 
 
(Dollars in Thousands)
 
 
Without sinking fund:
 
 
 
 
 
 
 
 
 
 
Cumulative, $100 par value:
 
 
 
 
 
 
 
 
 
 
4.32% Series
 
70,000

 
70,000

 

$7,000

 

$7,000

 

$103.65

4.72% Series
 
93,500

 
93,500

 
9,350

 
9,350

 

$107.00

4.56% Series
 
75,000

 
75,000

 
7,500

 
7,500

 

$102.83

4.56% 1965 Series
 
75,000

 
75,000

 
7,500

 
7,500

 

$102.50

Total without sinking fund
 
313,500

 
313,500

 

$31,350

 

$31,350

 
 

 
 
Shares
Authorized
and Outstanding
 
 
 
Call Price per
Share as of
December 31,
 
 
2017
 
2016
 
2017
 
2016
 
2017
Entergy Mississippi Preferred Stock
 
 
 
 
 
(Dollars in Thousands)
 
 
Without sinking fund:
 
 
 
 
 
 
 
 
 
 
Cumulative, $100 par value:
 
 
 
 
 
 
 
 
 
 
4.36% Series
 
59,920

 
59,920

 

$5,992

 

$5,992

 

$103.86

4.56% Series
 
43,887

 
43,887

 
4,389

 
4,389

 

$107.00

4.92% Series
 
100,000

 
100,000

 
10,000

 
10,000

 

$102.88

Total without sinking fund
 
203,807

 
203,807

 

$20,381

 

$20,381

 
 


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Shares
Authorized
and Outstanding
 
 
 
 
 
Call Price per
Share as of
December 31,
 
 
2017
 
2016
 
2017
 
2016
 
2017
Entergy New Orleans Preferred Stock
 
 
 
 
(Dollars in Thousands)
 
 
Without sinking fund:
 
 
 
 
 
 
 
 
 
 
Cumulative, $100 par value:
 
 
 
 
 
 
 
 
 
 
4.36% Series (a)
 
—

 
60,000

 

$—

 

$6,000

 

$—

4.75% Series (a)
 
—

 
77,798

 
—

 
7,780

 

$—

5.56% Series (a)
 
—

 
60,000

 
—

 
6,000

 

$—

Total without sinking fund
 
—

 
197,798

 

$—

 

$19,780

 
 

(a)
In November 2017, Entergy New Orleans redeemed its $6 million of 4.36% Series, $7.8 million of 4.75% Series, and $6 million of 5.56% Series of preferred membership interests as part of a multi-step internal restructuring.


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 2017, 2016, and 2015 is as follows:
 
2017
 
2016
 
2015
 
Common
Shares
Issued
 

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

 
75,623,363

 
254,752,788

 
76,363,763

 
254,752,788

 
75,512,079

Repurchases
—

 
—

 
—

 
—

 
—

 
1,468,984

Issuances:
 

 
 

 
 

 
 

 
 

 
 

Employee Stock-Based Compensation Plans
—

 
(1,377,363
)
 
—

 
(729,073
)
 
—

 
(610,409
)
Directors’ Plan
—

 
(10,865
)
 
—

 
(11,327
)
 
—

 
(6,891
)
Ending Balance, December 31
254,752,788

 
74,235,135

 
254,752,788

 
75,623,363

 
254,752,788

 
76,363,763


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, 2017, $350 million of authority remains under the $500 million share repurchase program.

Dividends declared per common share were $3.50 in 2017, $3.42 in 2016, and $3.34 in 2015.

System Energy paid its parent, Entergy Corporation, distributions out of its common stock of $21 million in 2017 and $40 million in 2016.

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Retained Earnings and Dividend Restrictions

Provisions within the articles of incorporation relating to preferred stock of each of Entergy Arkansas and Entergy Mississippi could restrict the payment of cash dividends or other distributions on their common and preferred equity if such payment were to occur when, or result in, a ratio of common stock equity to total capitalization of 25% or less.  Entergy Corporation received dividend payments and distributions from subsidiaries totaling $201 million in 2017, $165 million in 2016, and $615 million in 2015.

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, 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 for the year ended December 31, 2016 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, 2016

$105,970



($466,604
)


$367,557



$2,028

 

$8,951

Other comprehensive income (loss) before reclassifications
87,740

 
(26,997
)
 
68,465

 
(1,280
)
 
127,928

Amounts reclassified from
accumulated other comprehensive income (loss)
(189,717
)
 
24,155

 
(6,288
)
 
—

 
(171,850
)
Net other comprehensive income (loss) for the period
(101,977
)
 
(2,842
)
 
62,177

 
(1,280
)
 
(43,922
)
Ending balance, December 31, 2016

$3,993

 

($469,446
)
 

$429,734

 

$748

 

($34,971
)


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Notes to Financial Statements


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
)

The following table presents changes in accumulated other comprehensive income (loss) for Entergy Louisiana for the year ended December 31, 2016:

 
Pension and Other
Postretirement Liabilities

 
(In Thousands)
 
 
 
Beginning balance, January 1, 2016
 

($56,412
)
Other comprehensive income (loss) before reclassifications
 
8,926

Amounts reclassified from accumulated other comprehensive income (loss)
 
(956
)
Net other comprehensive income (loss) for the period
 
7,970

Ending balance, December 31, 2016
 

($48,442
)


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Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy for the years ended December 31, 2017 and 2016 are as follows:
 
 
Amounts reclassified from AOCI
 
Income Statement Location
 
 
2017
 
2016
 
 
 
 
(In Thousands)
 
 
Cash flow hedges net unrealized gain (loss)
 
 
 
 
 
 
Power contracts
 

$108,606

 

$293,268

 
Competitive business operating revenues
Interest rate swaps
 
(803
)
 
(1,395
)
 
Miscellaneous - net
Total realized gain (loss) on cash flow hedges
 
107,803

 
291,873

 
 
 
 
(37,731
)
 
(102,156
)
 
Income taxes
Total realized gain (loss) on cash flow hedges (net of tax)
 

$70,072

 

$189,717

 
 
 
 
 
 

 
 
Pension and other postretirement liabilities
 
 

 
 

 
 
Amortization of prior-service costs
 

$26,251

 

$29,414

 
(a)
Acceleration of prior-service cost due to curtailment
 
—

 
(1,045
)
 
(a)
Amortization of loss
 
(86,002
)
 
(60,693
)
 
(a)
Settlement loss
 
(7,544
)
 
(2,007
)
 
(a)
Total amortization
 
(67,295
)
 
(34,331
)
 
 
 
 
24,919

 
10,176

 
Income taxes
Total amortization (net of tax)
 

($42,376
)
 

($24,155
)
 
 
 
 
 
 

 
 
Net unrealized investment gain (loss)
 
 
 

 
 
Realized gain (loss)
 

$109,388

 

$12,329

 
Interest and investment income
 
 
(53,600
)
 
(6,041
)
 
Income taxes
Total realized investment gain (loss) (net of tax)
 

$55,788

 

$6,288

 
 
 
 
 
 

 
 
Total reclassifications for the period (net of tax)
 

$83,484

 

$171,850

 
 

(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, 2017 and 2016 are as follows:
 
 
Amounts reclassified from AOCI
 
Income Statement Location
 
 
2017
 
2016
 
 
 
 
(In Thousands)
 
 
 
 
 
 
 
 
 
Pension and other postretirement liabilities
 
 
 
 
 
 
Amortization of prior-service costs
 

$7,734

 

$7,786

 
(a)
Amortization of loss
 
(5,327
)
 
(6,281
)
 
(a)
Total amortization
 
2,407

 
1,505

 
 
 
 
(987
)
 
(549
)
 
Income taxes
Total amortization (net of tax)
 
1,420

 
956

 
 
 
 
 
 

 
 
Total reclassifications for the period (net of tax)
 

$1,420

 

$956

 
 
(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 the outcome of such proceedings, management does not believe that the ultimate resolution of these matters will have a material 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 $122.9 million in 2017, $158.7 million in 2016, and $146 million in 2015.  If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $129 million in 2018, and a total of $1.68 billion for the years 2019 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 is pursuing its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. During 2014, Entergy Arkansas collected $50 million from Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the members’ nuclear generating plants. Litigation remains pending.

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 approved Entergy Arkansas’s request to exclude from the calculation of its revised energy cost rate $65.9 million of deferred fuel and purchased energy costs incurred in 2013 as a result of the ANO stator incident. 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 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 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.

Shortly after the stator incident, the NRC deployed an augmented inspection team to review the plant’s response.  In July 2013 a second team of NRC inspectors visited ANO to evaluate certain items that were identified as requiring follow-up inspection to determine whether performance deficiencies existed. In March 2014 the NRC issued an inspection report on the follow-up inspection that discussed two preliminary findings, one that was preliminarily determined to be “red with high safety significance” for Unit 1 and one that was preliminarily determined to be “yellow with substantial safety significance” for Unit 2, with the NRC indicating further that these preliminary findings may warrant additional regulatory oversight. This report also noted that one additional item related to flood barrier effectiveness was still under review. In June 2014 the NRC classified both findings as “yellow with substantial safety significance.”

In March 2015, after several NRC inspections and regulatory conferences, the NRC issued a letter notifying Entergy of its decision to move ANO into the “multiple/repetitive degraded cornerstone column,” or Column 4, of the NRC’s Reactor Oversight Process Action Matrix. Placement into Column 4 requires significant additional NRC inspection activities at the ANO site, including a review of the site’s root cause evaluation associated with flood barrier effectiveness and stator issues, an assessment of the effectiveness of the site’s corrective action program, an additional design basis inspection, a safety culture assessment, and possibly other inspection activities consistent with the NRC’s Inspection Procedure. Entergy Arkansas incurred incremental costs of approximately $53 million in 2015 to prepare for the NRC inspection that began in early 2016. Excluding remediation and response costs that may result from the additional NRC inspection activities, Entergy Arkansas also incurred approximately $44 million in 2016 in support of NRC inspection activities and to implement Entergy Arkansas’s performance improvement initiatives developed in 2015. A lesser amount of incremental expense is expected to be ongoing annually after 2016, until ANO transitions out of Column 4.

The NRC completed the supplemental inspection required for ANO’s Column 4 designation in February 2016, and published its inspection report in June 2016. In its inspection report, the NRC concluded that the ANO site is being operated safely and that Entergy understands the depth and breadth of performance concerns associated with ANO’s performance decline. Also in June 2016, the NRC issued a confirmatory action letter to confirm the actions Entergy Arkansas has taken and will continue to take to improve performance at ANO. The NRC will verify the

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completion of those actions through quarterly follow-up inspections, the results of which will determine when ANO should transition out of Column 4. There have been no significant issues arising from the follow-up inspections.
 
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. The preliminary estimate of direct costs of Pilgrim’s response to a planned NRC enhanced inspection ranges from $45 million to $60 million, of which $50 million has been incurred through the end of 2017 in operation and maintenance expense. The estimate does not include potential capital expenditures, which will be charged directly to expense when incurred, or other costs to address issues that may arise in the inspection.

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 intends 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.

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


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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 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 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.


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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. 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.

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,

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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 $127.3 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.146 billion).  This retrospective premium is payable at a rate currently set at approximately $19 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 $13 billion in coverage.  The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to $100 billion in coverage in excess of existing coverage for a terrorist event. Under current law, the Terrorism Risk Insurance Act extends through 2020.

Currently, 102 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 $13 billion in secondary layer insurance coverage to compensate the public in the event of a nuclear power reactor accident.  The Price-Anderson Act provides that all potential liability for a nuclear accident is limited to the amounts of insurance coverage available under the primary and secondary layers.

Entergy Arkansas and Entergy Louisiana each have two licensed reactors. System Energy has one licensed reactor (10% of Grand Gulf is owned by a non-affiliated company (Cooperative Energy) that would share on a pro-rata basis in any retrospective premium assessment to System Energy under the Price-Anderson Act).  The Entergy Wholesale Commodities segment includes the ownership, operation, and decommissioning of 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 premature decommissioning expense, 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 is included in the first $500 million for Waterford 3 and River Bend. 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, 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

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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 and Palisades 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 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, 2017, the maximum amounts of such possible assessments per occurrence were as follows:
 
Assessments
 
(In Millions)
Utility:
 
Entergy Arkansas
$40.3
Entergy Louisiana
$49.4
Entergy Mississippi
$0.11
Entergy New Orleans
$0.11
Entergy Texas
N/A
System Energy
$22.3
 
 
Entergy Wholesale Commodities
$—

Potential assessments for the Entergy Wholesale Commodities plants are covered by insurance obtained through NEIL’s reinsurers.

NRC regulations provide that the proceeds of this insurance must be used, first, to render the reactor safe and stable, and second, to complete decontamination operations.  Only after proceeds are dedicated for such use and regulatory approval is secured would any remaining proceeds be made available for the benefit of plant owners or their creditors.

In the event that one or more acts of terrorism causes property damage under one or more or all nuclear insurance policies issued by NEIL (including, but not limited to, those described above) within 12 months from the date the first property damage occurs, the maximum recovery under all such nuclear insurance policies shall be an aggregate not exceeding $3.24 billion plus the additional amounts recovered for such losses from reinsurance, indemnity, and any other sources applicable to such losses.  

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Non-Nuclear Property Insurance

Entergy’s non-nuclear property insurance program provides coverage on a system-wide basis for Entergy’s non-nuclear assets. The insurance program provides coverage up to $400 million per occurrence, “each and every loss” basis in excess of a $20 million self-insured retention with the exception of the following: earthquake shock, flood, and named windstorm, including associated storm surge. For earthquake shock and flood, the insurance program provides coverage up to $400 million on an annual aggregate basis in excess of a $40 million self-insured retention. For named windstorm and associated storm surge, the insurance program provides coverage up to $125 million on an annual aggregate basis in excess of a $40 million self-insured retention.  The coverage provided by the insurance program for the Entergy New Orleans gas distribution system is limited to $50 million per occurrence and is subject to the same annual aggregate limits and retentions listed above for earthquake shock, flood, and named windstorm, including associated storm surge.

Covered property generally includes power plants, substations, facilities, inventories, and gas distribution-related properties.  Excluded property generally includes transmission and distribution lines, poles, and towers. For substations valued at $5 million or less, coverage for named windstorm and associated storm surge is excluded.  This coverage is in place for Entergy Corporation, the Registrant Subsidiaries, and certain other Entergy subsidiaries, including the owners of the nuclear power plants in 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.

Prior to June 1, 2017, Entergy purchased additional coverage for some of its non-regulated, non-generation assets in addition to the insurance procured via the conventional property insurance program. The policy served to buy-down the conventional property insurance policy’s $20 million deductible and was placed on a scheduled location basis.  Due to Entergy’s gradual exit from the merchant/wholesale power business, effective June 1, 2017, Entergy no longer purchases this additional coverage ($20 million per occurrence) for some of its non-regulated, non-generation assets.

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 third parties not selected for open positions or providing services directly or indirectly to one or more of the Registrant Subsidiaries and other Entergy subsidiaries.  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

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approximately 500 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.

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 2017 under the agreement are approximately $19.5 million for Entergy Arkansas, $7.8 million for Entergy Louisiana, $17 million for Entergy Mississippi, and $9.4 million for Entergy New Orleans. See Note 2 to the financial statements for discussion of the complaint 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.


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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.


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 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,
 
2017
 
2016
 
(In Millions)
Entergy Arkansas
$176.9
 
$128.5
Entergy Louisiana
($32.4)
 
($53.9)
Entergy Mississippi
$91.6
 
$82.0
Entergy New Orleans
$44.8
 
$40.1
Entergy Texas
$55.2
 
$33.5
System Energy
$67.9
 
$69.7


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The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2017 and 2016 by Entergy were as follows:
 
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

(a)
13.9

 
—

 
(0.9
)
 
(727.3
)
(b)
—

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 (c)
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






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Liabilities as
of December 31,
2015
 
Liabilities Incurred
 
 
 
Accretion
 
Change in
Cash Flow
Estimate
 
 
 
Spending
 
Liabilities as
of December 31,
2016
 
 
(In Millions)
 
Utility:
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Arkansas

$872.3

 

$—

 

$53.6

 

$—

 

($1.5
)
 

$924.4

 
Entergy Louisiana
1,027.9

 
—

 
54.8

 
—

 
—

 
1,082.7

 
Entergy Mississippi
8.3

 
—

 
0.4

 
—

 
—

 
8.7

 
Entergy New Orleans
2.7

 
—

 
0.2

 
—

 
—

 
2.9

 
Entergy Texas
6.1

 
—

 
0.4

 
—

 
—

 
6.5

 
System Energy
803.4

 
—

 
50.8

 
—

 
—

 
854.2

 
Total
2,720.7

 
—

 
160.2

 
—

 
(1.5
)
 
2,879.4

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Wholesale Commodities:
 


 


 


 


 
Big Rock Point
28.0

 
—

 
2.2

 
10.1

 
(2.4
)
 
37.9

 
FitzPatrick
—

(d)
696.2

 
18.1

 
—

 
—

 
714.3

(a)
Indian Point 1
197.9

 
—

 
17.1

 
(0.3
)
 
(7.1
)
 
207.6

 
Indian Point 2
390.1

 
—

 
33.0

 
230.0

 
—

 
653.1

 
Indian Point 3
—

(d)
466.3

 
12.1

 
162.7

 
—

 
641.1

 
Palisades
342.0

 
—

 
29.5

 
128.8

 
—

 
500.3

 
Pilgrim
551.2

 
—

 
48.4

 
3.2

 
(0.5
)
 
602.3

 
Vermont Yankee
560.0

 
—

 
39.3

 
—

 
(128.8
)
 
470.5

 
Other (c)
0.3

 
—

 
—

 
—

 
—

 
0.3

 
Total
2,069.5

 
1,162.5

 
199.7

 
534.5

 
(138.8
)
 
3,827.4

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Total

$4,790.2

 

$1,162.5

 

$359.9

 

$534.5

 

($140.3
)
 

$6,706.8

 

(a)
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.
(b)
See Note 14 to the financial statements for discussion of the sale of the FitzPatrick plant to Exelon in March 2017.
(c)
See “Coal Combustion Residuals” below for additional discussion regarding the asset retirement obligations related to coal combustion residuals management.
(d)
See “Entergy Wholesale Commodities” in “Nuclear Plant Decommissioning” below for additional discussion regarding the decommissioning agreements with NYPA and the associated asset retirement obligations.

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

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

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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.    

Entergy Wholesale Commodities

In August 2013 the Board approved a plan to close and decommission Vermont Yankee at the end of 2014. Vermont Yankee submitted notification of permanent cessation of operations and permanent removal of fuel from the reactor in January 2015 after final shutdown in December 2014. Vermont Yankee’s future certifications to satisfy the NRC’s financial assurance requirements will now be based on the site specific cost estimate, including the estimated cost of managing spent fuel, rather than the NRC minimum formula for estimating decommissioning costs. Filings with the NRC for planned shutdown activities will determine whether any other financial assurance may be required and will specifically address funding for spent fuel management, which will be required until the federal government takes possession of the fuel and removes it from the site, per its current obligation.

Entergy expects that amounts available in Vermont Yankee’s decommissioning trust fund, including expected earnings, together with borrowings under its credit facility that are expected to be repaid with recoveries from DOE litigation related to spent fuel storage, and the site restoration trust, will be sufficient to cover Vermont Yankee’s expected costs of decommissioning, spent fuel management costs, and site restoration. See Note 4 to the financial statements for discussion of the credit facility and Note 16 to the financial statements for discussion of the decommissioning trust fund.  In June 2015 the NRC staff issued an exemption from its regulations to allow Vermont Yankee to use its decommissioning trust fund to pay for approximately $225 million of estimated future spent fuel management costs that will not be paid for using funds from its credit facility.  In August 2015, Vermont and two Vermont utilities filed a petition in the U.S. Court of Appeals for the D.C. Circuit challenging the NRC’s issuance of that exemption.  In February 2016 the court dismissed the petition as premature because Vermont and the utilities had requested the NRC to reconsider a number of issues related to Vermont Yankee's use of the decommissioning trust fund including its use to pay for spent fuel management expenses pursuant to the exemption granted in June 2015. In October 2016 the NRC denied Vermont's and the utilities' request for a hearing and other relief but directed the NRC staff to conduct an assessment of any environmental impacts associated with the exemption. In December 2017 the NRC issued its final environmental assessment, concluding that the exemption did not, and will not, have a significant effect on the environment.
    
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.

For the Indian Point 3 and FitzPatrick plants purchased 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

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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.

In the third quarter 2015, Entergy Wholesale Commodities recorded a revision to the contract asset for the FitzPatrick plant. Due to a change in expectation regarding the timing of decommissioning cash flows, the result was a write down of the contract asset from $335 million to $131 million, for a charge of $204 million.

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. 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 transaction was contingent upon receiving approval from the NRC, which was received in January 2017.  The decommissioning trust funds for the Indian Point 3 and FitzPatrick plants were transferred to Entergy by NYPA 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. See Note 14 to the financial statements for discussion of the sale of FitzPatrick.

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.

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.


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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, 2017 and 2016 are as follows:
 
2017
 
2016
 
Decommissioning
Trust Fair Values
 
Regulatory
Asset (Liability)
 
Decommissioning
Trust Fair Values
 
Regulatory
Asset (Liability)
 
(In Millions)
 
(In Millions)
Utility:
 
 
 
 
 
 
 
ANO 1 and ANO 2

$944.9

 
$337.9
 

$834.7

 

$316.3

River Bend

$818.2

 
($30.6)
 

$712.8

 

($28.4
)
Waterford 3

$493.9

 
$188.9
 

$427.9

 

$172.8

Grand Gulf

$905.7

 
$169.1
 

$780.5

 

$142.5

Entergy Wholesale Commodities

$4,049.3

 
$—
 

$2,968.0

 

$—


As a result of the agreement with NYPA discussed above, in the third quarter 2016, Entergy removed the contract asset from its balance sheet, and recorded receivables of $1.5 billion for the beneficial interests in the decommissioning trust funds for Indian Point 3 and FitzPatrick. At December 31, 2016, the fair values of the decommissioning trust funds held by NYPA were $719 million for the Indian Point 3 plant and $785 million for the FitzPatrick plant. See Note 16 to the financial statements for further discussion of the transfer of the decommissioning trust funds held by NYPA to Entergy.

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 CCR rule in light of the WIIN Act. The EPA has not yet initiated a new round of rulemaking and has not extended the existing mid-October 2017 groundwater monitoring deadline. Entergy met the existing monitoring deadline, is monitoring state agency actions, and will participate in the regulatory development process.



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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, 2017, 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)
2018
 

$80,368

 

$3,018

2019
 
82,516

 
2,887

2020
 
67,385

 
2,887

2021
 
58,507

 
2,887

2022
 
43,760

 
2,887

Years thereafter
 
96,550

 
19,004

Minimum lease payments
 
429,086

 
33,570

Less:  Amount representing interest
 
—

 
10,051

Present value of net minimum lease payments
 

$429,086

 

$23,519


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 $53.1 million in 2017, $44.4 million in 2016, and $63.9 million in 2015.

As of December 31, 2017 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)
2018
 

$17,009

 

$21,814

 

$11,771

 

$1,646

 

$3,469

2019
 
17,665

 
22,875

 
10,611

 
1,579

 
2,893

2020
 
11,483

 
17,790

 
8,969

 
1,382

 
1,934

2021
 
9,363

 
13,762

 
7,059

 
1,033

 
1,299

2022
 
6,834

 
10,067

 
5,007

 
662

 
862

Years thereafter
 
23,598

 
19,443

 
5,817

 
1,797

 
2,173

Minimum lease payments
 

$85,952

 

$105,751

 

$49,234

 

$8,099

 

$12,630



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

2015
 

$13.6

 

$21.8

 

$5.4

 

$1.6

 

$4.0

 

$2.9


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 $4.0 million in 2017, $3.4 million in 2016, and $4.7 million in 2015 for Entergy Arkansas and $0.3 million in 2017, $0.3 million in 2016, and $1.1 million in 2015 for Entergy Louisiana.  Oil tank facilities lease payments for Entergy Mississippi were $1.6 million in 2017, $1.6 million in 2016, and $1.6 million in 2015.

Power Purchase Agreements

As of December 31, 2017, 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)
2018
 

$30,458

 

$30,458

2019
 
31,159

 
31,159

2020
 
31,876

 
31,876

2021
 
32,609

 
32,609

2022
 
10,180

 
10,180

Years thereafter
 
—

 
—

Minimum lease payments
 

$136,282

 

$136,282


(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 $34.1 million in 2017, $26.1 million in 2016, and $29.9 million in 2015.

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.

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

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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 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, 2017 and 2016.


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As of December 31, 2017, System Energy, in connection with the Grand Gulf sale and leaseback transactions, had future minimum lease payments (reflecting an implicit rate of 5.13%) that are recorded as long-term debt, as follows:
 
Amount
 
(In Thousands)
 
 
2018

$17,188

2019
17,188

2020
17,188

2021
17,188

2022
17,188

Years thereafter
240,625

Total
326,565

Less: Amount representing interest
292,209

Present value of net minimum lease payments

$34,356



NOTE 11.  RETIREMENT, OTHER POSTRETIREMENT BENEFITS, AND DEFINED CONTRIBUTION PLANS  (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Qualified Pension Plans

Entergy has eight 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 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

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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.

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 2017, 2016, and 2015 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:
 
2017
 
2016
 
2015
 
(In Thousands)
Net periodic pension cost:
 

 
 

 
 

Service cost - benefits earned during the period

$133,641

 

$143,244

 

$175,046

Interest cost on projected benefit obligation
260,824

 
261,613

 
302,777

Expected return on assets
(408,225
)
 
(389,465
)
 
(394,618
)
Amortization of prior service cost
261

 
1,079

 
1,561

Recognized net loss
227,720

 
195,298

 
235,922

Curtailment loss
—

 
3,084

 
374

Special termination benefit
—

 
—

 
76

Net periodic pension costs

$214,221

 

$214,853

 

$321,138

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

$368,067

 

$203,229

 

$50,762

Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
 
 
 
 
 
Amortization of prior service cost
(261
)
 
(1,079
)
 
(1,561
)
Acceleration of prior service cost to curtailment
—

 
(1,045
)
 
(374
)
Amortization of net loss
(227,720
)
 
(195,298
)
 
(235,922
)
Total

$140,086

 

$5,807

 

($187,095
)
Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)

$354,307

 

$220,660

 

$134,043

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

$398

 

$261

 

$1,079

Net loss

$274,104

 

$227,720

 

$195,321


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Notes to Financial Statements


The Registrant Subsidiaries’ total 2017, 2016, and 2015 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:
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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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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2015
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Net periodic pension cost:
 
 
 
 
 
 
 
 
 
 
 
 
Service cost - benefits earned during the period
 

$26,646

 

$34,396

 

$7,929

 

$3,395

 

$6,582

 

$7,827

Interest cost on projected benefit obligation
 
61,885

 
69,465

 
18,007

 
8,432

 
17,414

 
13,970

Expected return on assets
 
(80,102
)
 
(90,803
)
 
(24,420
)
 
(10,899
)
 
(24,887
)
 
(18,271
)
Recognized net loss
 
54,254

 
59,802

 
14,896

 
8,053

 
12,950

 
13,055

Net pension cost
 

$62,683

 

$72,860

 

$16,412

 

$8,981

 

$12,059

 

$16,581

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

$16,687

 

$16,618

 

$6,329

 

$1,853

 

($4,488
)
 

$101

Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
 
 
 
 
 
 
 
 
 
 
 
 
Amortization of net loss
 
(54,254
)
 
(59,802
)
 
(14,896
)
 
(8,053
)
 
(12,950
)
 
(13,055
)
Total
 

($37,567
)
 

($43,184
)
 

($8,567
)
 

($6,200
)
 

($17,438
)
 

($12,954
)
Total recognized as net periodic pension (income)/cost, regulatory asset, and/or AOCI (before tax)
 

$25,116

 

$29,676

 

$7,845

 

$2,781

 

($5,379
)
 

$3,627

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

$43,747

 

$47,809

 

$11,938

 

$6,460

 

$9,358

 

$10,414



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Qualified Pension Obligations, Plan Assets, Funded Status, Amounts Recognized in the Balance Sheet

Qualified pension obligations, plan assets, funded status, amounts recognized in the Consolidated Balance Sheets for Entergy Corporation and its Subsidiaries as of December 31, 2017 and 2016 are as follows:
 
2017
 
2016
 
(In Thousands)
Change in Projected Benefit Obligation (PBO)
 

 
 

Balance at January 1

$7,142,567

 

$6,848,238

Service cost
133,641

 
143,244

Interest cost
260,824

 
261,613

Curtailment
—

 
2,039

Actuarial loss
767,849

 
209,360

Employee contributions
40

 
23

Benefits paid
(317,834
)
 
(321,950
)
Balance at December 31

$7,987,087

 

$7,142,567

Change in Plan Assets
 

 
 

Fair value of assets at January 1

$5,171,202

 

$4,707,433

Actual return on plan assets
808,007

 
395,596

Employer contributions
409,901

 
390,100

Employee contributions
40

 
23

Benefits paid
(317,834
)
 
(321,950
)
Fair value of assets at December 31

$6,071,316

 

$5,171,202

Funded status

($1,915,771
)
 

($1,971,365
)
Amount recognized in the balance sheet
 
 
 
Non-current liabilities

($1,915,771
)
 

($1,971,365
)
Amount recognized as a regulatory asset
 
 
 
Net loss

$2,418,206

 

$2,326,349

Amount recognized as AOCI (before tax)
 
 
 
Prior service cost

$398

 

$659

Net loss
667,766

 
619,276

 

$668,164

 

$619,935



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Qualified pension obligations, plan assets, funded status, amounts recognized in the Balance Sheets for the Registrant Subsidiaries as of December 31, 2017 and 2016 are as follows:
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

 

$—

 

$—

 

$—

 

$—



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Notes to Financial Statements


2016
 
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
 

$1,400,511

 

$1,564,710

 

$408,604

 

$191,064

 

$383,627

 

$311,542

Service cost
 
20,724

 
28,194

 
6,250

 
2,625

 
5,664

 
6,263

Interest cost
 
52,219

 
59,478

 
15,245

 
7,256

 
14,228

 
11,966

Actuarial loss
 
62,187

 
48,357

 
11,343

 
5,573

 
4,274

 
20,661

Benefits paid
 
(81,331
)
 
(76,506
)
 
(22,241
)
 
(9,054
)
 
(21,427
)
 
(15,051
)
Balance at December 31
 

$1,454,310

 

$1,624,233

 

$419,201

 

$197,464

 

$386,366

 

$335,381

Change in Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair value of assets at January 1
 

$959,618

 

$1,071,234

 

$292,297

 

$129,975

 

$298,378

 

$212,006

Actual return on plan assets
 
80,306

 
89,998

 
24,325

 
10,858

 
24,705

 
17,692

Employer contributions
 
82,999

 
84,421

 
19,968

 
10,709

 
15,920

 
20,497

Benefits paid
 
(81,331
)
 
(76,506
)
 
(22,241
)
 
(9,054
)
 
(21,427
)
 
(15,051
)
Fair value of assets at December 31
 

$1,041,592

 

$1,169,147

 

$314,349

 

$142,488

 

$317,576

 

$235,144

Funded status
 

($412,718
)
 

($455,086
)
 

($104,852
)
 

($54,976
)
 

($68,790
)
 

($100,237
)
Amounts recognized in the balance sheet (funded status)
 
 
 
 
 
 
 
 
 
 
 
 
Non-current liabilities
 

($412,718
)
 

($455,086
)
 

($104,852
)
 

($54,976
)
 

($68,790
)
 

($100,237
)
Amounts recognized as regulatory asset
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
 

$701,774

 

$686,337

 

$189,409

 

$94,944

 

$153,544

 

$169,897

Amounts recognized as AOCI  (before tax)
 
 

 
 
 
 
 
 
 
 
 
 
Net loss
 

$—

 

$51,660

 

$—

 

$—

 

$—

 

$—


Accumulated Pension Benefit Obligation

The accumulated benefit obligation for Entergy’s qualified pension plans was $7.4 billion and $6.7 billion at December 31, 2017 and 2016, respectively.

The qualified pension accumulated benefit obligation for each of the Registrant Subsidiaries for their employees as of December 31, 2017 and 2016 was as follows:
 
December 31,
 
2017
 
2016
 
(In Thousands)
Entergy Arkansas

$1,492,876

 

$1,379,265

Entergy Louisiana

$1,652,939

 

$1,513,884

Entergy Mississippi

$430,268

 

$396,081

Entergy New Orleans

$205,316

 

$186,247

Entergy Texas

$387,083

 

$365,251

System Energy

$359,258

 

$315,131



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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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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 2017, 2016, and 2015 other postretirement benefit costs, including amounts capitalized and amounts recognized as a regulatory asset and/or other comprehensive income, included the following components:
 
2017
 
2016
 
2015
 
(In Thousands)
Other postretirement costs:
 
 
 
 
 
Service cost - benefits earned during the period

$26,915

 

$32,291

 

$45,305

Interest cost on accumulated postretirement benefit obligation (APBO)
55,838

 
56,331

 
71,934

Expected return on assets
(37,630
)
 
(41,820
)
 
(45,375
)
Amortization of prior service credit
(41,425
)
 
(45,490
)
 
(37,280
)
Recognized net loss
21,905

 
18,214

 
31,573

Net other postretirement benefit cost

$25,603

 

$19,526

 

$66,157

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
)
 

($48,192
)
Net (gain)/loss
(66,922
)
 
49,805

 
(154,339
)
Amounts reclassified from regulatory asset and /or AOCI to net periodic benefit cost in the current year:
 
 
 
 
 
Amortization of prior service credit
41,425

 
45,490

 
37,280

Amortization of net loss
(21,905
)
 
(18,214
)
 
(31,573
)
Total

($49,966
)
 

$56,728

 

($196,824
)
Total recognized as net periodic benefit income/(cost), regulatory asset, and/or AOCI (before tax)

($24,363
)
 

$76,254

 

($130,667
)
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic benefit cost in the following year
 
 
 
 
 
Prior service credit

($37,002
)
 

($41,425
)
 

($45,485
)
Net loss

$13,729

 

$21,905

 

$18,214



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Entergy Corporation and Subsidiaries
Notes to Financial Statements


Total 2017, 2016, and 2015 other postretirement benefit costs of the Registrant Subsidiaries, including amounts capitalized and deferred, for their employees included the following components:
2017
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
 
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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Entergy Corporation and Subsidiaries
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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Entergy Corporation and Subsidiaries
Notes to Financial Statements


2015
 
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
 

$6,957

 

$9,893

 

$2,028

 

$818

 

$2,000

 

$1,881

Interest cost on APBO
 
12,518

 
16,311

 
3,436

 
2,608

 
5,366

 
2,511

Expected return on assets
 
(19,190
)
 
—

 
(6,166
)
 
(4,804
)
 
(10,351
)
 
(3,644
)
Amortization of prior service credit
 
(2,441
)
 
(7,467
)
 
(916
)
 
(709
)
 
(2,723
)
 
(1,465
)
Recognized net loss
 
5,356

 
7,118

 
860

 
470

 
2,740

 
1,198

Net other postretirement benefit (income)/cost
 

$3,200

 

$25,855

 

($758
)
 

($1,617
)
 

($2,968
)
 

$481

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
 

($18,035
)
 

($1,361
)
 

$—

 

$—

 

$—

 

($644
)
Net (gain)/loss
 
(11,978
)
 
(47,043
)
 
774

 
(5,810
)
 
(4,907
)
 
305

Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
 
 
 
 
 
 
 
 
 
 
 
 
Amortization of prior service credit
 
2,441

 
7,467

 
916

 
709

 
2,723

 
1,465

Amortization of net loss
 
(5,356
)
 
(7,118
)
 
(860
)
 
(470
)
 
(2,740
)
 
(1,198
)
Total
 

($32,928
)
 

($48,055
)
 

$830

 

($5,571
)
 

($4,924
)
 

($72
)
Total recognized as net periodic other postretirement income/(cost), regulatory asset, and/or AOCI (before tax)
 

($29,728
)
 

($22,200
)
 

$72

 

($7,188
)
 

($7,892
)
 

$409

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

($5,472
)
 

($7,783
)
 

($933
)
 

($745
)
 

($2,722
)
 

($1,570
)
Net loss
 

$4,256

 

$2,926

 

$893

 

$146

 

$2,148

 

$1,149



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Entergy Corporation and Subsidiaries
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, 2017 and 2016 are as follows:
 
2017
 
2016
 
(In Thousands)
Change in APBO
 

 
 

Balance at January 1

$1,568,963

 

$1,530,829

Service cost
26,915

 
32,291

Interest cost
55,838

 
56,331

Plan amendments
(2,564
)
 
(20,353
)
Plan participant contributions
35,080

 
27,686

Actuarial (gain)/loss
(23,409
)
 
46,201

Benefits paid
(97,829
)
 
(104,477
)
Medicare Part D subsidy received
493

 
455

Balance at December 31

$1,563,487

 

$1,568,963

Change in Plan Assets
 

 
 

Fair value of assets at January 1

$596,660

 

$579,069

Actual return on plan assets
81,143

 
38,216

Employer contributions
44,273

 
56,166

Plan participant contributions
35,080

 
27,686

Benefits paid
(97,829
)
 
(104,477
)
Fair value of assets at December 31

$659,327

 

$596,660

Funded status

($904,160
)
 

($972,303
)
Amounts recognized in the balance sheet
 
 
 
Current liabilities

($45,237
)
 

($45,255
)
Non-current liabilities
(858,923
)
 
(927,048
)
Total funded status

($904,160
)
 

($972,303
)
Amounts recognized as a regulatory asset
 
 
 
Prior service credit

($40,461
)
 

($54,896
)
Net loss
144,966

 
222,540

 

$104,505

 

$167,644

Amounts recognized as AOCI (before tax)
 
 
 
Prior service credit

($65,047
)
 

($89,474
)
Net loss
161,322

 
172,575

 

$96,275

 

$83,101



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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, 2017 and 2016 are as follows:
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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Entergy Corporation and Subsidiaries
Notes to Financial Statements


2016
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Change in APBO
 
 
 
 
 
 
 
 
 
 
 
 
Balance at January 1
 

$258,900

 

$356,253

 

$77,382

 

$51,951

 

$114,582

 

$57,645

Service cost
 
3,913

 
7,476

 
1,543

 
622

 
1,590

 
1,337

Interest cost
 
9,297

 
13,041

 
2,835

 
1,791

 
4,154

 
2,117

Plan amendments
 
(1,007
)
 
(4,647
)
 
(6,219
)
 
—

 
—

 
—

Plan participant contributions
 
6,330

 
6,273

 
1,721

 
1,213

 
1,927

 
1,390

Actuarial (gain)/loss
 
2,453

 
(13,117
)
 
8,230

 
4,774

 
12,389

 
4,806

Benefits paid
 
(21,178
)
 
(22,893
)
 
(7,031
)
 
(4,852
)
 
(6,977
)
 
(4,818
)
Medicare Part D subsidy received
 
79

 
114

 
24

 
16

 
35

 
21

Balance at December 31
 

$258,787

 

$342,500

 

$78,485

 

$55,515

 

$127,700

 

$62,498

Change in Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair value of assets at January 1
 

$243,206

 

$—

 

$75,538

 

$69,881

 

$130,374

 

$44,917

Actual return on plan assets
 
16,977

 
—

 
5,032

 
3,674

 
8,586

 
3,066

Employer contributions
 
5,591

 
16,620

 
685

 
4,320

 
3,159

 
330

Plan participant contributions
 
6,330

 
6,273

 
1,721

 
1,213

 
1,927

 
1,390

Benefits paid
 
(21,178
)
 
(22,893
)
 
(7,031
)
 
(4,852
)
 
(6,977
)
 
(4,818
)
Fair value of assets at December 31
 

$250,926

 

$—

 

$75,945

 

$74,236

 

$137,069

 

$44,885

Funded status
 

($7,861
)
 

($342,500
)
 

($2,540
)
 

$18,721

 

$9,369

 

($17,613
)
Amounts recognized in the balance sheet
 
 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 

$—

 

($19,209
)
 

$—

 

$—

 

$—

 

$—

Non-current liabilities
 
(7,861
)
 
(323,291
)
 
(2,540
)
 
18,721

 
9,369

 
(17,613
)
Total funded status
 

($7,861
)
 

($342,500
)
 

($2,540
)
 

$18,721

 

$9,369

 

($17,613
)
Amounts recognized in regulatory asset
 
 
 
 
 
 
 
 
 
 
 
 
Prior service credit
 

($21,684
)
 

$—

 

($8,511
)
 

($2,172
)
 

($8,296
)
 

($5,332
)
Net loss
 
76,388

 
—

 
26,416

 
12,029

 
50,036

 
23,405

 
 

$54,704

 

$—

 

$17,905

 

$9,857

 

$41,740

 

$18,073

Amounts recognized in AOCI (before tax)
 
 
 
 
 
 
 
 
 
 
 
 
Prior service credit
 

$—

 

($27,735
)
 

$—

 

$—

 

$—

 

$—

Net loss
 
—

 
54,700

 
—

 
—

 
—

 
—

 
 

$—

 

$26,965

 

$—

 

$—

 

$—

 

$—



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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 $37.6 million in 2017, $24.9 million in 2016, and $22.8 million in 2015.  In 2017, 2016, and 2015 Entergy recognized $20.3 million, $8.1 million, and $5.1 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 $162.3 million and $169.3 million as of December 31, 2017 and 2016, respectively.  The accumulated benefit obligation was $144.7 million and $151.0 million as of December 31, 2017 and 2016, respectively.

Entergy’s non-qualified, non-current pension liability at December 31, 2017 and 2016 was $136 million and $137.6 million, respectively; and its current liability was $26.4 million and $31.7 million, respectively.  The unamortized prior service cost and net loss are recognized in regulatory assets ($55.2 million at December 31, 2017 and $59.8 million at December 31, 2016) and accumulated other comprehensive income before taxes ($35.9 million at December 31, 2017 and $31.6 million at December 31, 2016).

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 2017, 2016, and 2015, was as follows:
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
(In Thousands)
2017

$679

 

$185

 

$251

 

$73

 

$499

2016

$1,819

 

$231

 

$236

 

$65

 

$504

2015

$446

 

$377

 

$235

 

$64

 

$595


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. Included in the 2015 net periodic pension cost above are settlement charges of $108 thousand and $2 thousand for Entergy Louisiana 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, 2017 and 2016 was as follows:
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
(In Thousands)
2017

$4,221

 

$2,061

 

$2,737

 

$583

 

$8,913

2016

$3,897

 

$2,134

 

$2,296

 

$514

 

$8,665



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Notes to Financial Statements


The accumulated benefit obligation for their employees for the non-qualified plans as of December 31, 2017 and 2016 was as follows:
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
(In Thousands)
2017

$3,825

 

$2,061

 

$2,250

 

$519

 

$8,602

2016

$3,439

 

$2,134

 

$1,961

 

$452

 

$8,333


The following amounts were recorded on the balance sheet as of December 31, 2017 and 2016:
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

 

$—

 

$—

 

$—


2016
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
 
(In Thousands)
Current liabilities
 

($242
)
 

($233
)
 

($137
)
 

($20
)
 

($773
)
Non-current liabilities
 
(3,655
)
 
(1,901
)
 
(2,159
)
 
(495
)
 
(7,892
)
Total funded status
 

($3,897
)
 

($2,134
)
 

($2,296
)
 

($515
)
 

($8,665
)
Regulatory asset/(liability)
 

$2,914

 

$175

 

$876

 

($148
)
 

($316
)
Accumulated other comprehensive income (before taxes)
 

$—

 

$13

 

$—

 

$—

 

$—



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Reclassification out of Accumulated Other Comprehensive Income (Loss)

Entergy and Entergy Louisiana reclassified the following costs out of accumulated other comprehensive income (loss) (before taxes and including amounts capitalized) as of December 31, 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


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, 2016:
 
Qualified Pension Costs
 
Other Postretirement Costs
 
Non-Qualified Pension Costs
 
Total
 
(In Thousands)
Entergy
 
 
 
 
 
 
 
Amortization of prior service cost

($1,079
)


$30,949

 

($456
)
 

$29,414

Acceleration of prior service cost due to curtailment
(1,045
)
 
—

 
—

 
(1,045
)
Amortization of loss
(49,930
)
 
(8,248
)
 
(2,515
)
 
(60,693
)
Settlement loss
—

 
—

 
(2,007
)
 
(2,007
)
 

($52,054
)
 

$22,701

 

($4,978
)
 

($34,331
)
Entergy Louisiana
 
 
 
 
 
 
 
Amortization of prior service cost

$—



$7,787

 

($1
)
 

$7,786

Amortization of loss
(3,345
)
 
(2,926
)
 
(10
)
 
(6,281
)
 

($3,345
)
 

$4,861

 

($11
)
 

$1,505


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

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require that changes in the funded status be recorded as other comprehensive income and/or a regulatory asset in the period in which the changes occur.

With regard to pension and other postretirement costs, Entergy calculates the expected return on pension and other postretirement benefit plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets.  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, 2017 and 2016 and the target asset allocation and ranges for 2017 are as follows:
Pension Asset Allocation
 
Target
 
Range
 
Actual 2017
 
Actual 2016
Domestic Equity Securities
 
45%
 
37%
to
53%
 
45%
 
46%
International Equity Securities
 
20%
 
16%
to
24%
 
20%
 
20%
Fixed Income Securities
 
35%
 
32%
to
38%
 
34%
 
33%
Other
 
0%
 
0%
to
10%
 
1%
 
1%

Postretirement Asset Allocation
 
Non-Taxable and Taxable
 
 
Target
 
Range
 
Actual 2017
 
Actual 2016
Domestic Equity Securities
 
27%
 
22%
to
32%
 
30%
 
40%
International Equity Securities
 
18%
 
13%
to
23%
 
20%
 
27%
Fixed Income Securities
 
55%
 
50%
to
60%
 
50%
 
33%
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, 2017, 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, 2017, and December 31, 2016, 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
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



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Notes to Financial Statements


2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Thousands)
Short-term investments
 

$—

 

$3,610

(a)

$—

 

$3,610

Equity securities:
 
 
 
 
 
 
 
 
Corporate stocks:
 
 
 
 
 
 
 
 
Preferred
 
6,423

(b)
—

 
—

 
6,423

Common
 
745,715

(b)
39

(b)
—

 
745,754

Common collective trusts (c)
 


 


 


 
2,072,743

103-12 investment entities (h)
 

 

 

 
335,818

Registered investment companies
 
258,879

(d)
—

 
—

 
258,879

Fixed income securities:
 
 
 
 
 
 
 
 
U.S. Government securities
 
136

(b)
370,545

(a)
—

 
370,681

Corporate debt instruments
 
—

 
630,726

(a)
—

 
630,726

Registered investment companies (e)
 
35,216

(d)
2,695

(d)
—

 
640,836

Other
 
34

(f)
105,613

(f)
—

 
105,647

Other:
 
 
 
 
 
 
 
 
Insurance company general account (unallocated contracts)
 
—

 
37,111

(g)
—

 
37,111

Total investments
 

$1,046,403

 

$1,150,339

 

$—

 

$5,208,228

Cash
 
 
 
 
 
 
 
929

Other pending transactions
 
 
 
 
 
 
 
8,869

Less: Other postretirement assets included in total investments
 
 
 
 
 
 
 
(46,824
)
Total fair value of qualified pension assets
 
 
 
 
 
 
 

$5,171,202


Other Postretirement Trusts
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



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2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Thousands)
Equity securities:
 
 
 
 
 
 
 
 
Common collective trust (c)
 
 
 
 
 
 
 

$368,704

Fixed income securities:
 
 
 
 
 
 
 
 

U.S. Government securities
 
30,632

(b)
43,097

(a)
—

 
73,729

Corporate debt instruments
 
—

 
58,787

(a)
—

 
58,787

Registered investment companies
 
3,123

(d)
—

 
—

 
3,123

Other
 
—

 
45,389

(f)
—

 
45,389

Total investments
 

$33,755

 

$147,273

 

$—

 

$549,732

Other pending transactions
 
 
 
 
 
 
 
104

Plus:  Other postretirement assets included in the investments of the qualified pension trust
 
 
 
 
 
 
 
46,824

Total fair value of other postretirement assets
 
 
 
 
 
 
 

$596,660


(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.
(h)
103-12 investment entities hold investments in accordance with stated objectives. The investment strategy of the investment entities is to capture the growth potential of international equity markets by replicating the performance of a specified index. 103-12 investment entities estimate fair value using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table.


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Notes to Financial Statements


Estimated Future Benefit Payments

Based upon the assumptions used to measure Entergy’s qualified pension and other postretirement benefit obligations at December 31, 2017, 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 Subsidy Receipts
 
(In Thousands)
Year(s)
 
 
 
 
 
 
 
2018

$412,057

 

$26,375

 

$82,087

 

$745

2019

$435,880

 

$10,108

 

$86,685

 

$842

2020

$447,224

 

$13,364

 

$89,508

 

$956

2021

$462,624

 

$10,765

 

$92,087

 

$1,071

2022

$470,846

 

$17,425

 

$94,427

 

$1,195

2023 - 2027

$2,478,959

 

$72,181

 

$475,991

 

$8,109


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)
 
 
 
 
 
 
 
 
 
 
 
 
2018
 

$87,295

 

$93,155

 

$25,833

 

$11,484

 

$25,333

 

$17,780

2019
 

$87,832

 

$96,060

 

$25,977

 

$12,202

 

$25,656

 

$18,566

2020
 

$88,905

 

$100,179

 

$27,198

 

$12,463

 

$26,399

 

$19,398

2021
 

$90,278

 

$103,810

 

$27,508

 

$13,087

 

$26,756

 

$20,279

2022
 

$92,061

 

$107,609

 

$27,389

 

$13,207

 

$26,310

 

$21,714

2023 - 2027
 

$479,160

 

$571,926

 

$141,912

 

$69,595

 

$130,905

 

$117,835

Estimated Future Non-Qualified Pension Benefits Payments
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
 
(In Thousands)
Year(s)
 
 
 
 
 
 
 
 
 
 
2018
 

$376

 

$231

 

$135

 

$21

 

$788

2019
 

$300

 

$219

 

$137

 

$55

 

$764

2020
 

$355

 

$208

 

$290

 

$36

 

$895

2021
 

$310

 

$196

 

$192

 

$39

 

$723

2022
 

$506

 

$186

 

$201

 

$41

 

$662

2023 - 2027
 

$2,196

 

$749

 

$1,462

 

$459

 

$3,762



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Notes to Financial Statements


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)
 
 
 
 
 
 
 
 
 
 
 
 
2018
 

$15,282

 

$18,962

 

$4,677

 

$3,954

 

$6,485

 

$3,246

2019
 

$15,398

 

$19,767

 

$4,818

 

$4,000

 

$6,842

 

$3,363

2020
 

$15,349

 

$20,287

 

$5,043

 

$3,952

 

$7,101

 

$3,381

2021
 

$15,483

 

$20,756

 

$5,218

 

$3,899

 

$7,369

 

$3,537

2022
 

$15,419

 

$21,250

 

$5,331

 

$3,800

 

$7,519

 

$3,595

2023 - 2027
 

$75,293

 

$108,290

 

$26,723

 

$17,698

 

$36,897

 

$17,677


Estimated Future Medicare Part D Subsidy
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
 
(In Thousands)
Year(s)
 
 
 
 
 
 
 
 
 
 
 
 
2018
 

$164

 

$168

 

$58

 

$38

 

$64

 

$23

2019
 

$185

 

$187

 

$65

 

$39

 

$69

 

$27

2020
 

$209

 

$210

 

$70

 

$41

 

$75

 

$33

2021
 

$230

 

$234

 

$76

 

$43

 

$81

 

$38

2022
 

$254

 

$257

 

$82

 

$46

 

$88

 

$46

2023 - 2027
 

$1,646

 

$1,720

 

$514

 

$259

 

$552

 

$346


Contributions

Entergy currently expects to contribute approximately $352.1 million to its qualified pension plans and approximately $52.3 million to other postretirement plans in 2018.  The expected 2018 pension and other postretirement plan contributions of the Registrant Subsidiaries for their employees are shown below.  The 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018.

The Registrant Subsidiaries expect to contribute approximately the following to the qualified pension and other postretirement plans for their employees in 2018:
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
(In Thousands)
Pension Contributions

$64,062

 

$71,917

 

$14,933

 

$7,250

 

$10,883

 

$13,786

Other Postretirement Contributions

$472

 

$18,962

 

$110

 

$3,669

 

$3,231

 

$16



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Notes to Financial Statements


Actuarial Assumptions

The significant actuarial assumptions used in determining the pension PBO and the other postretirement benefit APBO as of December 31, 2017 and 2016 were as follows:
 
2017
 
2016
Weighted-average discount rate:
 
 
 
Qualified pension
3.70% - 3.82% Blended 3.78%
 
4.30% - 4.49% Blended 4.39%
Other postretirement
3.72%
 
4.30%
Non-qualified pension
3.34%
 
3.63%
Weighted-average rate of increase in future compensation levels
3.98%
 
3.98%
Assumed health care trend rate:
 
 
 
Pre-65
6.95%
 
6.55%
Post-65
7.25%
 
7.25%
Ultimate rate
4.75%
 
4.75%
Year ultimate rate is reached and beyond:

 
 
    Pre-65
2027
 
2026
    Post-65
2027
 
2026

The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2017, 2016, and 2015 were as follows:
 
2017
 
2016
 
2015
Weighted-average discount rate:
 
 
 
 
 
Qualified pension:
 
 
 
 
 
    Service cost
4.75%
 
5.00%
 
4.27%
    Interest cost
3.73%
 
3.90%
 
4.27%
Other postretirement:
 
 
 
 
 
    Service cost
4.60%
 
4.92%
 
4.23%
    Interest cost
3.61%
 
3.78%
 
4.23%
Non-qualified pension:
 
 
 
 
 
    Service cost
3.65%
 
3.65%
 
3.61%
    Interest cost
3.10%
 
3.10%
 
3.61%
Weighted-average rate of increase in future compensation levels
3.98%
 
4.23%
 
4.23%
Expected long-term rate of return on plan assets:
 
 
 
 
 
Pension assets
7.50%
 
7.75%
 
8.25%
Other postretirement non-taxable assets
6.50% - 7.50%
 
7.75%
 
8.05%
Other postretirement taxable assets
5.75%
 
6.00%
 
6.25%
Assumed health care trend rate:
 
 
 
 
 
Pre-65
6.55%
 
6.75%
 
7.10%
Post-65
7.25%
 
7.55%
 
7.70%
Ultimate rate
4.75%
 
4.75%
 
4.75%
Year ultimate rate is reached and beyond:

 

 

    Pre-65
2026
 
2024
 
2023
    Post-65
2026
 
2024
 
2023
    

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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-2017 projection scale, in determining its December 31, 2017 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-2016 projection scale, in determining its December 31, 2016 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 2017 would have the following effects:
 
 
1 Percentage Point Increase
 
1 Percentage Point Decrease
2017
 
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
 

$166,814

 

$10,221

 

($139,648
)
 

($8,385
)

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 2017 would have the following effects for the Registrant Subsidiaries for their employees:
 
 
1 Percentage Point Increase
 
1 Percentage Point Decrease
2017
 
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
 

$23,612

 

$1,369

 

($19,810
)
 

($1,133
)
Entergy Louisiana
 

$37,240

 

$2,333

 

($31,063
)
 

($1,909
)
Entergy Mississippi
 

$8,666

 

$448

 

($7,276
)
 

($370
)
Entergy New Orleans
 

$4,585

 

$251

 

($3,895
)
 

($208
)
Entergy Texas
 

$12,444

 

$751

 

($10,452
)
 

($618
)
System Energy
 

$7,334

 

$475

 

($6,074
)
 

($387
)

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 IV (established in March 2002), the Savings Plan of Entergy Corporation and Subsidiaries VI (established in April 2007), and the Savings Plan of Entergy Corporation and Subsidiaries VII (established in April 2007) to which matching contributions are also made.  The plans are defined contribution plans that cover eligible employees, as defined by each plan, of Entergy and certain of its subsidiaries.  

Entergy’s subsidiaries’ contributions to defined contribution plans collectively were $49.1 million in 2017, $47 million in 2016, and $44.4 million in 2015.  The majority of the contributions were to the System Savings Plan.

The Registrant Subsidiaries’ 2017, 2016, and 2015 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)
2017
 

$3,741

 

$5,079

 

$2,133

 

$731

 

$1,865

2016
 

$3,528

 

$4,746

 

$1,997

 

$708

 

$1,778

2015
 

$3,242

 

$4,324

 

$1,920

 

$721

 

$1,620



NOTE 12.    STOCK-BASED COMPENSATION (Entergy Corporation)

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.  Effective May 8, 2015, Entergy’s shareholders approved the 2015 Equity Ownership and Long-Term Cash Incentive 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 only applies to awards granted on or after May 8, 2015 and awards will expire ten years from the date of grant. As of December 31, 2017, there were 3,498,788 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:
 
2017
 
2016
 
2015
 
(In Millions)
Compensation expense included in Entergy’s consolidated net income
$4.4
 
$4.4
 
$4.3
Tax benefit recognized in Entergy’s consolidated net income
$1.7
 
$1.7
 
$1.6
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:
 
2017
 
2016
 
2015
Stock price volatility
18.39%
 
20.38%
 
23.62%
Expected term in years
7.35
 
7.25
 
7.06
Risk-free interest rate
2.31%
 
1.77%
 
1.59%
Dividend yield
4.75%
 
4.50%
 
4.50%
Dividend payment per share
$3.50
 
$3.42
 
$3.34

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, 2017 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, 2017
7,137,210

 
$84.91
 
 
 
 
Options granted
791,900

 
$70.53
 
 
 
 
Options exercised
(1,109,306
)
 
$72.74
 
 
 
 
Options forfeited/expired
(1,654,950
)
 
$91.36
 
 
 
 
Options outstanding as of December 31, 2017
5,164,854

 
$83.26
 
$—
 
4.18 years
Options exercisable as of December 31, 2017
4,027,902

 
$86.37
 
$—
 
2.94 years
Weighted-average grant-date fair value of options granted during 2017
$6.54
 
 
 
 
 
 

The weighted-average grant-date fair value of options granted during the year was $7.40 for 2016 and $11.41 for 2015.  The total intrinsic value of stock options exercised was $11 million during 2017, $5 million during 2016, and $5 million during 2015.  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, 2017.  Because Entergy’s year-end common stock price was less than the weighted average exercise price, the aggregate intrinsic value of stock options outstanding as of December 31, 2017 was zero. The intrinsic value of “in the money” stock options is $32 million as of December 31, 2017. Entergy recognizes compensation cost over the vesting period of the options based on their grant-date fair value.  The total fair value of options that vested was approximately $6 million during 2017, $5 million during 2016, and $4 million during 2015. Cash received from option exercises was $81 million for the year ended December 31, 2017. The tax benefits realized from options exercised was $4 million for the year ended December 31, 2017.


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The following table summarizes information about stock options outstanding as of December 31, 2017:
 
 
 
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
 
12/31/2017
 
 
 
12/31/2017
 

$51
 -
$64.99
 
502,709

 
5.73
 
$63.68
 
502,709

 
$63.68

$65
 -
$78.99
 
2,790,045

 
5.56
 
$72.94
 
1,751,402

 
$74.36

$79
 -
$91.99
 
441,000

 
7.08
 
$89.90
 
342,691

 
$89.90

$92
 -
$108.20
 
1,431,100

 
0.06
 
$108.20
 
1,431,100

 
$108.20

$51
 -
$108.20
 
5,164,854

 
4.18
 
$83.26
 
4,027,902

 
$86.37

Stock-based compensation cost related to non-vested stock options outstanding as of December 31, 2017 not yet recognized is approximately $6 million and is expected to be recognized over a weighted-average period of 1.70 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 2017 the Board approved and Entergy granted 379,850 restricted stock awards under the 2015 Equity Ownership and Long-term Cash Incentive Plan.  The restricted stock awards were made effective as of January 26, 2017 and were valued at $70.53 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, 2017:
 
Shares
 
Weighted-Average Grant Date Fair Value Per Share
Outstanding shares at January 1, 2017
683,474

 
$74.80
Granted
410,787

 
$70.71
Vested
(330,816
)
 
$73.61
Forfeited
(53,834
)
 
$75.63
Outstanding shares at December 31, 2017
709,611

 
$72.92

The following table includes financial information for restricted stock for each of the years presented:
 
2017
 
2016
 
2015
 
(In Millions)
Compensation expense included in Entergy’s consolidated net income
$19.7
 
$19.8
 
$19.5
Tax benefit recognized in Entergy’s consolidated net income
$7.6
 
$7.6
 
$7.5
Compensation cost capitalized as part of fixed assets and inventory
$5.2
 
$4.5
 
$3.9

The total fair value of the restricted stock awards granted was $29 million for each of the years ended December 31, 2017, 2016, and 2015.


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The total fair value of the restricted stock awards vested was $24 million, $23 million, and $29 million for the years ended December 31, 2017, 2016, and 2015, 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. There is no payout for performance that falls within the lowest quartile of performance of the peer companies.  For top quartile performance, a maximum payout of 200% of target is earned.

The costs of incentive awards are charged to income over the 3-year period.  In January 2017 the Board approved and Entergy granted 220,450 performance units under the 2015 Equity Ownership and Long-Term Cash Incentive Plan.  The performance units were made effective as of January 26, 2017, and were valued at $71.40 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, 2017:
 
Shares
 
Weighted-Average Grant Date Fair Value Per Share
Outstanding shares at January 1, 2017
571,551

 
$82.02
Granted
258,808

 
$72.28
Vested
(86,964
)
 
$67.16
Forfeited
(209,244
)
 
$72.12
Outstanding shares at December 31, 2017
534,151

 
$83.60

The following table includes financial information for the long-term performance units for each of the years presented:
 
2017
 
2016
 
2015
 
(In Millions)
Compensation expense included in Entergy’s consolidated net income
$10.8
 

$12.3

 

$11.8

Tax benefit recognized in Entergy’s consolidated net income
$4.2
 

$4.8

 

$4.5

Compensation cost capitalized as part of fixed assets and inventory
$3.0
 

$2.9

 

$2.3

    
The total fair value of the long-term performance units granted was $19 million, $21 million, and $16 million for the years ended December 31, 2017, 2016, and 2015, respectively.

In January 2017, Entergy issued 86,964 shares of Entergy Corporation common stock at a share price of $71.89 for awards earned 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. In January 2015, Entergy issued 105,503 shares of Entergy Corporation common stock at a share price of $88.67 for awards earned and dividends accrued under the 2012-2014 Long-Term Performance Unit Program.

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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 41 months.  As of December 31, 2017, there were 201,570 unvested restricted stock units that are expected to vest over an average period of 24 months.

The following table includes information about the restricted stock unit awards outstanding as of December 31, 2017:
 
Shares
 
Weighted-Average Grant Date Fair Value Per Share
Outstanding shares at January 1, 2017
181,650

 
$74.94
Granted
40,170

 
$79.10
Vested
(5,800
)
 
$73.22
Forfeited
(14,450
)
 
$79.69
Outstanding shares at December 31, 2017
201,570

 
$75.48

The following table includes financial information for restricted stock unit awards for each of the years presented:
 
2017
 
2016
 
2015
 
(In Millions)
Compensation expense included in Entergy’s consolidated net income
$2.5
 
$2.2
 
$0.9
Tax benefit recognized in Entergy’s consolidated net income
$1.0
 
$0.8
 
$0.4
Compensation cost capitalized as part of fixed assets and inventory
$0.6
 
$0.4
 
$0.3

The total fair value of the restricted stock unit awards granted was $3 million, $5 million, and $4 million for the years ended December 31, 2017, 2016, and 2015, respectively.

The total fair value of the restricted stock unit awards vested was $0.4 million, $2 million, and $1 million for the years ended December 31, 2017, 2016, and 2015, 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, 2017 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:
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


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



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2015
 
 
 
Utility
 
Entergy Wholesale Commodities*
 
 
 
All Other
 
 
 
Eliminations
 
 
 
Consolidated
 
 
(In Thousands)
Operating revenues
 

$9,451,486

 

$2,061,827

 

$—

 

($62
)
 

$11,513,251

Asset write-offs, impairments, and related charges
 

$68,672

 

$2,036,234

 

$—

 

$—

 

$2,104,906

Depreciation, amortization, & decommissioning
 

$1,238,832

 

$376,560

 

$2,156

 

$—

 

$1,617,548

Interest and investment income
 

$191,546

 

$148,654

 

$34,303

 

($187,441
)
 

$187,062

Interest expense
 

$543,132

 

$26,788

 

$129,750

 

($56,201
)
 

$643,469

Income taxes
 

$16,761

 

($610,339
)
 

($49,349
)
 

$—

 

($642,927
)
Consolidated net income (loss)
 

$1,114,516

 

($1,065,657
)
 

($74,353
)
 

($131,240
)
 

($156,734
)
Total assets
 

$38,356,906

 

$8,210,183

 

($461,505
)
 

($1,457,903
)
 

$44,647,681

Investment in affiliates - at equity
 

$199

 

$4,142

 

$—

 

$—

 

$4,341

Cash paid for long-lived asset additions
 

$2,495,194

 

$569,824

 

$236

 

$—

 

$3,065,254


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 shutdown 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.

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 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 2017 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 January 1, 2017
 

$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


Total restructuring charges in 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 January 1, 2016
 

$—

 

$—

 

$—

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


In addition, Entergy Wholesale Commodities incurred $0.5 billion in 2017 and $2.8 billion in 2016 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 $165 million in 2018 and approximately $205 million from 2019 through mid-2022 associated with these strategic transactions.

Geographic Areas

For the years ended December 31, 2017, 2016, and 2015, the amount of revenue Entergy derived from outside of the United States was insignificant.  As of December 31, 2017 and 2016, 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.  For the PPA, which was at below-market prices at the time of the acquisition, Entergy will amortize a liability to revenue over the life of the agreement.  The amount that will be 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 $28 million in 2017, $13 million in 2016, and $15 million in 2015.  

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. Entergy updated the liability amortization calculation to reflect the expected early termination of the PPA.

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. Based on that decision, the amounts to be amortized to revenue for the next five years will be approximately $6 million in 2018, $10 million in 2019, $11 million in 2020, $12 million in 2021, and $5 million in 2022.

NYPA Value Sharing Agreements

Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA.  In October 2007, Entergy subsidiaries and NYPA amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms.  Under the amended value sharing agreements, Entergy subsidiaries made annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014.  Entergy subsidiaries paid NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual

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cap of $24 million.  The annual payment for each year’s output was due by January 15 of the following year, and the final payment to NYPA was made in January 2015.  Entergy recorded the liability for payments to NYPA as power was generated and sold by Indian Point 3 and FitzPatrick.  An amount equal to the liability was recorded to the plant asset account as contingent purchase price consideration for the plants.

Dispositions

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 is the owner of the Vermont Yankee plant and is in the Entergy Wholesale Commodities segment. The sale of Entergy Nuclear Vermont Yankee to NorthStar will include the transfer of the nuclear decommissioning trust fund and the asset retirement obligation for the spent fuel management and decommissioning of the plant.

Entergy Nuclear Vermont Yankee has an outstanding credit facility with borrowing capacity of $145 million to pay for dry fuel storage costs. This credit facility is guaranteed by Entergy Corporation. At or before closing, a subsidiary of Entergy will assume the obligations under the existing credit facility or enter into a new credit facility and Entergy will guarantee the credit facility. At the closing of the sale transaction, NorthStar will pay $1,000 for the membership interests in Entergy Nuclear Vermont Yankee, and NorthStar will cause Entergy Nuclear Vermont Yankee to issue a promissory note to an Entergy subsidiary. The amount of the promissory note issued will be equal to the amount drawn under the credit facility or the amount drawn under the new credit facility, plus borrowing fees and costs incurred by Entergy in connection with such facility. The principal amount drawn under the outstanding credit facility was $104 million as of December 31, 2017, and the net book value of Entergy Nuclear Vermont Yankee, including unrealized gains on the decommissioning trust fund, as of December 31, 2017, was approximately $123 million.

Entergy plans to transfer all spent nuclear fuel to dry cask storage by the end of 2018 in advance of the planned transaction close. Under the sale agreement and related agreements to be entered into at the closing, NorthStar will commit to initiate decommissioning and site restoration by 2021 and complete those activities by 2030. The original planned completion date, as outlined in Entergy’s Post Shutdown Decommissioning Activities Report filed with the NRC, was 2075. Entergy Nuclear Vermont Yankee, under NorthStar ownership, will be required to repay the promissory note issued to Entergy with certain of the proceeds from the recovery of damages under its claims against the DOE related to spent nuclear fuel disposal, with any balance remaining due at partial site release, subject to extension not to exceed two years from partial site release.

The transaction is subject to certain closing conditions, including approval by the NRC; approval by the State of Vermont Public Utility Commission, including approval of revised site restoration standards that have been proposed as part of the transaction; the transfer of all spent nuclear fuel to dry fuel storage on the independent spent fuel storage installation; and that the market value of the fund assets held in the decommissioning trust fund for the Vermont Yankee Nuclear Power Station, less the hypothetical income tax on the aggregate unrealized net gain of such fund assets at closing, is equal to or exceeds $451.95 million, subject to adjustments. Entergy has the option to contribute to the decommissioning trust fund if the value is less than $451.95 million, subject to adjustments. The transaction is planned to close by the end of 2018.

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. As a result of the sales agreement and the status of the necessary regulatory approvals, the assets and liabilities associated with the sale of FitzPatrick to Exelon were classified as held for sale on Entergy Corporation and Subsidiaries’ Consolidated Balance Sheet as of December 31, 2016. At December 31, 2016, the receivable for the beneficial interest in the decommissioning trust fund was $785 million, classified within other deferred debits, and the asset retirement obligation was $714 million, classified within

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other non-current liabilities. See Note 9 to the financial statements for further discussion of FitzPatrick’s decommissioning liability and see Note 16 to the financial statements for further discussion of the receivables for the beneficial interest in FitzPatrick’s decommissioning trust fund.

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.

Rhode Island State Energy Center

In December 2015, Entergy sold the Rhode Island State Energy Center, a 583 MW natural gas-fired combined-cycle generating plant owned by Entergy in the Entergy Wholesale Commodities segment. Entergy sold the Rhode Island State Energy Center for approximately $490 million and realized a pre-tax gain of $154 million on the sale.

Impairment of Long-lived Assets

2015 Impairment Conclusions

Entergy determined in October 2015 that it would close FitzPatrick at the end of its fuel cycle, which was planned for January 27, 2017, 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. This decision came after management’s extensive analysis of whether it was advisable economically to refuel the plant, as scheduled, in the fall of 2016. Entergy also had discussions with the State of New York regarding the future of FitzPatrick. Because of the uncertainty regarding the refueling decision and its implications to the plant’s expected operating life, Entergy tested the recoverability of the plant and related assets as of September 30, 2015. See above in the Dispositions section for further information on the subsequent decision to sell the FitzPatrick plant.

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 in September 2015

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to place the plant in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix. Because of the uncertainty regarding the plant’s operating life created by the NRC’s decision and management’s analysis of the plant, Entergy tested the recoverability of the plant and related assets as of September 30, 2015.

Due to the announced plant closures in October 2015, as well as the continued challenging market price trend, the high level of investment required to continue to operate the Entergy Wholesale Commodities plants, and the inadequate compensation provided to nuclear generators for their capacity benefits under the current market design, in the fourth quarter 2015, Entergy tested the recoverability of the plant and related assets of the two remaining operating nuclear power generating facilities in the Entergy Wholesale Commodities business, Palisades and Indian Point. For purposes of that evaluation, Entergy considered a number of factors associated with the facilities’ continued operation, including the status of the associated NRC licenses, the status of state regulatory issues, existing power purchase agreements, and the supply region in which the nuclear facilities sell energy and capacity.

Under generally accepted accounting principles the determination of an asset’s recoverability is based on the probability-weighted undiscounted net cash flows expected to be generated by the plant and related assets. Projected net cash flows primarily depend on the status of the operations of the plant and pending legal and state regulatory matters, as well as projections of future revenues and costs over the estimated remaining life of the plant.

The tests for FitzPatrick and Pilgrim indicated that the probability-weighted undiscounted net cash flows did not exceed the carrying values of the plants and related assets as of September 30, 2015.

The test for Palisades indicated that the probability-weighted undiscounted net cash flows did not exceed the carrying value of the plant and related assets as of December 31, 2015.

The test for Indian Point indicated that the probability-weighted undiscounted net cash flows exceeded the carrying value of the plant and related assets as of December 31, 2015. As such, the carrying value of Indian Point was not impaired as of December 31, 2015.

As of September 30, 2015, the estimated fair value of the FitzPatrick plant and related long-lived assets was $29 million, while the carrying value was $742 million, resulting in an impairment charge of $713 million. Materials and supplies were evaluated and written down by $48 million. In addition, FitzPatrick had a contract asset recorded for an agreement between Entergy subsidiaries and NYPA entered when Entergy subsidiaries purchased FitzPatrick from NYPA in 2000 and NYPA retained the decommissioning trusts and the decommissioning liabilities. The agreement gave NYPA the right to require the Entergy subsidiaries to assume the decommissioning liability provided that it assigns the decommissioning trust, up to a specified level, to Entergy. If NYPA retained the decommissioning liabilities, the Entergy subsidiaries would perform the decommissioning of the plant at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. The contract asset represented an estimate of the present value of the difference between the Entergy subsidiaries’ stipulated contract amount for decommissioning the plants less the decommissioning costs estimated in independent decommissioning cost studies. See Note 9 for further discussion of the contract asset. Due to a change in expectation regarding the timing of decommissioning cash flows, the result was a write down of the contract asset from $335 million to $131 million, for a charge of $204 million. In summary, as of September 30, 2015, the impairment and related charges for FitzPatrick was $965 million ($624 million net-of-tax).

As of September 30, 2015, the estimated fair value of the Pilgrim plant and related long-lived assets is $65 million, while the carrying value was $718 million, resulting in an impairment charge of $653 million. Materials and supplies were evaluated and written down by $24 million. In summary, as of September 30, 2015, the total impairment loss and related charges for Pilgrim was $677 million ($438 million net-of-tax). The pre-impairment carrying value of $718 million includes the effect of a $134 million increase in Pilgrim’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.

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As of December 31, 2015, the estimated fair value of the Palisades plant and related long-lived assets was $463 million, while the carrying value was $859 million, resulting in an impairment charge of $396 million ($256 million net-of-tax). The pre-impairment carrying value of $859 million includes the effect of a $42 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 assessment of the estimated decommissioning cash flows that occurred in conjunction with the impairment analysis.

2016 Impairment Conclusions

As discussed in more detail above in the Acquisitions section, in December 2016, Entergy reached an agreement with Consumers Energy to amend the existing PPA to terminate early, on May 31, 2018. 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 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 have 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-

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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.

2017 Impairment Conclusions

In 2017 Entergy management continued to execute the strategy to reduce the size of Entergy Wholesale Commodities’ merchant fleet, with the planned shutdowns of Pilgrim by May 31, 2019, Indian Point 2 by April 30, 2020, Indian Point 3 by April 30, 2021, and, as discussed in further detail above in the Acquisitions section, Palisades on May 31, 2022. The FitzPatrick plant was classified as held-for-sale at December 31, 2016, and subsequently sold to Exelon in March 2017.

In 2017 Entergy Wholesale Commodities incurred $538 million of impairment charges related to nuclear fuel spending, nuclear refueling outage spending, and expenditures for capital assets. These costs were charged to expense as incurred as a result of the impaired fair value of the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining estimated operating lives associated with management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet.

As discussed above in the Acquisitions section, as a result of the Michigan Public Service Commission only granting Consumers Energy partial recovery of the requested early termination payment, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement in September 2017. 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.

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 FitzPatrick, Pilgrim, and Palisades in 2015, and 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 the FitzPatrick, Pilgrim, 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.


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The following table sets forth a description of significant unobservable inputs used in the valuation of the FitzPatrick, Pilgrim, Palisades, and Indian Point plants and related assets:
Significant Unobservable Inputs
 
Amount
 
Weighted-Average
2015
 
 
 
 
Weighted-average cost of capital
 
 
 
 
FitzPatrick
 
7.5%
 
7.5%
Pilgrim (a)
 
7.5%-8.0%
 
7.9%
Palisades
 
7.5%
 
7.5%
 
 
 
 
 
Long-term pre-tax operating margin (cash basis)
 
 
 
 
FitzPatrick
 
10.2%
 
10.2%
Pilgrim (a)
 
2.4%-10.6%
 
8.1%
Palisades (b)
 
30.8%
 
30.8%
 
 
 
 
 
2016
 
 
 
 
Weighted-average cost of capital
 
 
 
 
Indian Point (c)
 
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) (d)
 
17.8%-38.8%

 
34.6%

(a)
The fair value of Pilgrim was based on the probability weighting of two potential scenarios.
(b)
Most of the Palisades output is sold under a 15-year power purchase agreement, entered at the plant’s acquisition in 2007, that is scheduled to expire in 2022. The power purchase agreement prices currently exceed market prices and escalate each year, up to $61.50/MWh in 2022.
(c)
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.
(d)
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 group, which reports to the Chief Accounting Officer, was primarily responsible for determining the valuation of the FitzPatrick, Pilgrim, 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.


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

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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, 2017 is approximately 3.25 years.  Planned generation currently under contract from Entergy Wholesale Commodities nuclear power plants is 98% for 2018, of which approximately 79% is sold under financial derivatives and the remainder under normal purchase/normal sale contracts.  Total planned generation for 2018 is 27.9 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 guaranty, as determined in accordance with Entergy’s credit policy.

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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, 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. As of December 31, 2016, derivative contracts with three counterparties were in a liability position (approximately $8 million total). In addition to the corporate guarantee, $2 million in cash collateral was required to be posted by the Entergy subsidiary to its counterparties. 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 short-term natural gas swaps that financially settle against NYMEX futures. These swaps 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 for electric generation at Entergy Louisiana and Entergy Mississippi and projected winter purchases for gas distribution at Entergy Louisiana and Entergy New Orleans. The total volume of natural gas swaps outstanding as of December 31, 2017 is 38,540,750 MMBtu for Entergy, including 31,361,500 MMBtu for Entergy Louisiana, 6,714,250 MMBtu for Entergy Mississippi, and 465,000 MMBtu for Entergy New Orleans.  Credit support for these natural gas swaps is covered by master agreements that do not require collateral based on mark-to-market value, but do carry adequate assurance language that may lead to requests for collateral.

During the second quarter 2017, Entergy participated in the annual financial transmission rights auction process for the MISO planning year of June 1, 2017 through May 31, 2018. 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, 2017 is 46,474 GWh for Entergy, including 10,479 GWh for Entergy Arkansas, 20,590 GWh for Entergy Louisiana, 6,391 GWh for Entergy Mississippi, 2,366 GWh for Entergy New Orleans, and 6,322 GWh for Entergy Texas. Credit support for financial transmission rights held by the Utility operating companies is covered by cash and/or letters of credit issued by each Utility operating company as required by MISO. Credit support for financial transmission rights held by Entergy Wholesale Commodities is covered by cash. No cash or letters of credit were required to be posted for financial transmission rights exposure for Entergy Wholesale Commodities as of December 31, 2017 and December 31, 2016. Letters of credit posted with MISO covered the financial transmission rights exposure for Entergy Arkansas, Entergy Mississippi, and Entergy Texas as of December 31 2017 and for Entergy Arkansas and Entergy Mississippi as of December 31, 2016.


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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


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The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 2016 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)
 
$25
 
($14)
 
$11
 
Entergy Wholesale Commodities
Electricity swaps and options
 
Other deferred debits and other assets (non-current portion)
 
$6
 
($6)
 
$—
 
Entergy Wholesale Commodities
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Other current liabilities (current portion)
 
$11
 
($10)
 
$1
 
Entergy Wholesale Commodities
Electricity swaps and options
 
Other non-current liabilities (non-current portion)
 
$16
 
($7)
 
$9
 
Entergy Wholesale Commodities
Derivatives not designated as hedging instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Prepayments and other (current portion)
 
$18
 
($13)
 
$5
 
Entergy Wholesale Commodities
Electricity swaps and options
 
Other deferred debits and other assets (non-current portion)
 
$5
 
($5)
 
$—
 
Entergy Wholesale Commodities
Natural gas swaps
 
Prepayments and other
 
$13
 
$—
 
$13
 
Utility
Financial transmission rights
 
Prepayments and other
 
$22
 
($1)
 
$21
 
Utility and Entergy Wholesale Commodities
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Other current liabilities (current portion)
 
$18
 
($17)
 
$1
 
Entergy Wholesale Commodities
Electricity swaps and options
 
Other non-current liabilities (non-current portion)
 
$4
 
($4)
 
$—
 
Entergy Wholesale Commodities

(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 $1 million posted and $4 million held as of December 31, 2017 and $2 million posted as of December 31, 2016. Also excludes $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, 2017, 2016, and 2015 are as follows:
Instrument
 
Amount of gain 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)
2017
 
 
 
 
 
 
Electricity swaps and options
 
$44
 
Competitive business operating revenues
 
$109
 
 
 
 
 
 
 
2016
 
 
 
 
 
 
Electricity swaps and options
 
$135
 
Competitive business operating revenues
 
$293
 
 
 
 
 
 
 
2015
 
 
 
 
 
 
Electricity swaps and options
 
$254
 
Competitive business operating revenues
 
($244)

(a)
Before taxes of $38 million, $103 million, and ($85) million, for the years ended December 31, 2017, 2016, and 2015, 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 ($3) million, ($356) thousand, and $150 thousand for the years ended December 31, 2017, 2016, and 2015, respectively.
   
Based on market prices as of December 31, 2017, unrealized gains recorded in accumulated other comprehensive income on cash flow hedges relating to power sales totaled $55 million of net unrealized losses.  Approximately ($59) 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, 2017, 2016, and 2015 are as follows:
Instrument
 
Amount of gain recognized in accumulated other comprehensive income
 
Income Statement location
 
Amount of gain (loss) recorded in the income statement
 
 
(In Millions)
 
 
 
(In Millions)
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)
 
 
 
 
 
 
 
2015
 
 
 
 
 
 
Natural gas swaps
 
$—
 
Fuel, fuel-related expenses, and gas purchased for resale
(a)
($41)
Financial transmission rights
 
$—
 
Purchased power expense
(b)
$166
Electricity swaps and options
 
$12
(c)
Competitive business operating revenues
 
($19)

(a)
Due to regulatory treatment, the natural gas swaps 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 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 (loss) 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, 2017 and 2016 are as follows:
Instrument
 
Balance Sheet Location
 
Fair Value (a)
 
Registrant
 
 
 
 
(In Millions)
 
 
2017
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
Financial transmission rights
 
Prepayments and other
 
$3.0
 
Entergy Arkansas
Financial transmission rights
 
Prepayments and other
 
$10.2
 
Entergy Louisiana
Financial transmission rights
 
Prepayments and other
 
$2.1
 
Entergy Mississippi
Financial transmission rights
 
Prepayments and other
 
$2.2
 
Entergy New Orleans
Financial transmission rights
 
Prepayments and other
 
$3.4
 
Entergy Texas
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Natural gas swaps
 
Other current liabilities
 
$5.0
 
Entergy Louisiana
Natural gas swaps
 
Other current liabilities
 
$1.2
 
Entergy Mississippi
Natural gas swaps
 
Other current liabilities
 
$0.2
 
Entergy New Orleans
 
 
 
 
 
 
 
2016
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
Natural gas swaps
 
Prepayments and other
 
$10.9
 
Entergy Louisiana
Natural gas swaps
 
Prepayments and other
 
$2.3
 
Entergy Mississippi
Natural gas swaps
 
Prepayments and other
 
$0.2
 
Entergy New Orleans
 
 
 
 
 
 
 
Financial transmission rights
 
Prepayments and other
 
$5.4
 
Entergy Arkansas
Financial transmission rights
 
Prepayments and other
 
$8.5
 
Entergy Louisiana
Financial transmission rights
 
Prepayments and other
 
$3.2
 
Entergy Mississippi
Financial transmission rights
 
Prepayments and other
 
$1.1
 
Entergy New Orleans
Financial transmission rights
 
Prepayments and other
 
$3.1
 
Entergy Texas

(a)
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. As of December 31, 2016, letters of credit posted with MISO covered financial transmission rights exposure of $0.3 million for Entergy Arkansas and $0.1 million for Entergy Mississippi.





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The effects of the Registrant Subsidiaries’ derivative instruments not designated as hedging instruments on their income statements for the years ended December 31, 2017, 2016, and 2015 are as follows:
Instrument
 
Income Statement Location
 
Amount of gain (loss) recorded in the income statement
 
Registrant
 
 
 
 
(In Millions)
 
 
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
 
 
 
 
 
 
 
2015
 
 
 
 
 
 
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
($33.2)
(a)
Entergy Louisiana
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
($6.1)
(a)
Entergy Mississippi
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
($1.4)
(a)
Entergy New Orleans
 
 
 
 
 
 
 
Financial transmission rights
 
Purchased power
 
$68.7
(b)
Entergy Arkansas
Financial transmission rights
 
Purchased power
 
$55.4
(b)
Entergy Louisiana
Financial transmission rights
 
Purchased power
 
$16.5
(b)
Entergy Mississippi
Financial transmission rights
 
Purchased power
 
$8.5
(b)
Entergy New Orleans
Financial transmission rights
 
Purchased power
 
$16.8
(b)
Entergy Texas

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(a)
Due to regulatory treatment, the natural gas swaps 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 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 hedge contracts.  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.

•
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 communicated to senior management within Entergy and within Entergy Wholesale Commodities.  Finally, for all

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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 group reviews these valuations for reasonableness, with the assistance of others within the organization with knowledge of the various inputs and assumptions used in the valuation. The Business Unit Risk Control groups report to the Vice President and Treasurer.  The Accounting Policy and Entergy Wholesale Commodities Accounting group reports to the Chief Accounting Officer.

The following tables set forth, by level within the fair value hierarchy, Entergy’s assets and liabilities that are accounted for at fair value on a recurring basis as of December 31, 2017 and December 31, 2016.  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.

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






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2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$1,058

 

$—

 

$—

 

$1,058

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
480

 
—

 
—

 
480

Debt securities
 
985

 
1,228

 
—

 
2,213

Common trusts (b)
 
 
 
 
 
 
 
3,031

Power contracts
 
—

 
—

 
16

 
16

Securitization recovery trust account
 
46

 
—

 
—

 
46

Escrow accounts
 
433

 
—

 
—

 
433

Gas hedge contracts
 
13

 
—

 
—

 
13

Financial transmission rights
 
—

 
—

 
21

 
21

 
 

$3,015

 

$1,228

 

$37

 

$7,311

Liabilities:
 
 
 
 
 
 
 
 
Power contracts
 

$—

 

$—

 

$11

 

$11


(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, 2017, 2016, and 2015:
 
2017
 
2016
 
2015
 
Power Contracts
Financial transmission rights
 
Power Contracts
Financial transmission rights
 
Power Contracts
Financial transmission rights
 
(In Millions)
Balance as of January 1,

$5


$21

 

$189


$23

 

$215


$47

Total gains (losses) for the period (a)
 
 
 
 
 
 
 
 
Included in earnings
(3
)
1

 
(10
)
—

 
(20
)
(1
)
Included in other comprehensive income
44

—

 
135

—

 
254

—

Included as a regulatory liability/asset
—

76

 
—

68

 
—

63

Issuances of financial transmission rights
—

62

 
—

55

 
—

80

Purchases
—

—

 
—

—

 
15

—

Settlements
(111
)
(139
)
 
(309
)
(125
)
 
(275
)
(166
)
Balance as of December 31,

($65
)

$21

 

$5


$21

 

$189


$23


(a)
Change in unrealized gains or losses for the period included in earnings for derivatives held at the end of the reporting period is $0.9 million, $0.2 million, and $3 million for the years ended December 31, 2017, 2016, and 2015, 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, 2017:
Transaction Type
 
Fair Value as of December 31, 2017
 
Significant Unobservable Inputs
 
Range from Average %
 
Effect on Fair Value
 
 
(In Millions)
 
 
 
 
 
(In Millions)
Power contracts - electricity swaps
 
($65)
 
Unit contingent discount
 
+/- 4% - 4.75%
 
$6 - $7
 
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, 2017 and December 31, 2016.  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

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


2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 

$3.6

 

$—

 

$—

 

$3.6

Debt securities
 
112.5

 
196.8

 
—

 
309.3

Common trusts (b)
 
 
 
 
 
 
 
521.8

Securitization recovery trust account
 
4.1

 
—

 
—

 
4.1

Escrow accounts
 
7.1

 
—

 
—

 
7.1

Financial transmission rights
 
—

 
—

 
5.4

 
5.4

 
 

$127.3

 

$196.8

 

$5.4

 

$851.3


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Entergy Louisiana

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


2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$163.9

 

$—

 

$—

 

$163.9

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
13.9

 
—

 
—

 
13.9

Debt securities
 
132.3

 
292.5

 
—

 
424.8

Common trusts (b)
 
 
 
 
 
 
 
702.0

Escrow accounts
 
305.7

 
—

 
—

 
305.7

Securitization recovery trust account
 
2.8

 
—

 
—

 
2.8

Gas hedge contracts
 
10.9

 
—

 
—

 
10.9

Financial transmission rights
 
—

 
—

 
8.5

 
8.5

 
 

$629.5

 

$292.5

 

$8.5

 

$1,632.5


Entergy Mississippi
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



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2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$76.8

 

$—

 

$—

 

$76.8

Escrow accounts
 
31.8

 
—

 
—

 
31.8

Gas hedge contracts
 
2.3

 
—

 
—

 
2.3

Financial transmission rights
 
—

 
—

 
3.2

 
3.2

 
 

$110.9

 

$—

 

$3.2

 

$114.1


Entergy New Orleans

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


2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$103.0

 

$—

 

$—

 

$103.0

Securitization recovery trust account
 
1.7

 
—

 
—

 
1.7

Escrow accounts
 
88.6

 
—

 
—

 
88.6

Gas hedge contracts
 
0.2

 
—

 
—

 
0.2

Financial transmission rights
 
—

 
—

 
1.1

 
1.1

 
 

$193.5

 

$—

 

$1.1

 

$194.6


Entergy Texas

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



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2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$5.0

 

$—

 

$—

 

$5.0

Securitization recovery trust account
 
37.5

 
—

 
—

 
37.5

Financial transmission rights
 
—

 
—

 
3.1

 
3.1

 
 

$42.5

 

$—

 

$3.1

 

$45.6


System Energy

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


2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$245.1

 

$—

 

$—

 

$245.1

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
0.3

 
—

 
—

 
0.3

Debt securities
 
248.3

 
58.3

 
—

 
306.6

Common trusts (b)
 
 
 
 
 
 
 
473.6

 
 

$493.7

 

$58.3

 

$—

 

$1,025.6


(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, 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 (losses) 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


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, 2016.
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
(In Millions)
 
 
 
 
 
 
 
 
 
 
Balance as of January 1,

$7.9

 

$8.5

 

$2.4

 

$1.5

 

$2.2

Issuances of financial transmission rights
18.8

 
18.1

 
5.9

 
2.8

 
9.3

Gains included as a regulatory liability/asset
1.9

 
51.6

 
11.5

 
0.9

 
1.8

Settlements
(23.2
)
 
(69.7
)
 
(16.6
)
 
(4.1
)
 
(10.2
)
Balance as of December 31,

$5.4

 

$8.5

 

$3.2

 

$1.1

 

$3.1



NOTE 16.    DECOMMISSIONING TRUST FUNDS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)

Entergy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts.  The NRC requires Entergy subsidiaries to maintain 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.  The funds are invested primarily in equity securities, fixed-rate debt securities, and cash and cash equivalents.

For the Indian Point 3 and FitzPatrick plants purchased 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. 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.

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. The transaction

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was contingent upon receiving approval from the NRC, which was received in January 2017.  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 recorded asset retirement obligations for the decommissioning liabilities. At December 31, 2016, the fair values of the decommissioning trust funds held by NYPA were $719 million for the Indian Point 3 plant and $785 million for the FitzPatrick plant. The fair values were based on the trust statements received from NYPA and were valued by the fund administrator using net asset value as a practical expedient. Accordingly, these funds were not assigned a level in the fair value hierarchy. For Indian Point 3, the receivable for the beneficial interest in the decommissioning trust fund was recorded in other deferred debits on the consolidated balance sheet as of December 31, 2016. For FitzPatrick, the receivable for the beneficial interest in the decommissioning trust fund was classified as held for sale within other deferred debits on the consolidated balance sheet as of December 31, 2016. In January 2017, NYPA transferred to Entergy the Indian Point 3 decommissioning trust funds with a fair value of $726 million and the FitzPatrick decommissioning trust fund with a fair value of $793 million. In March 2017, Entergy closed on the sale of the FitzPatrick plant to Exelon. As part of the transaction, Entergy transferred the FitzPatrick decommissioning trust fund to Exelon. The FitzPatrick decommissioning trust fund had a disposition-date fair value of $805 million. See Note 9 to the financial statements for further discussion of the decommissioning agreements with NYPA and see Note 14 to the financial statements for further discussion of the sale of FitzPatrick.

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 excess 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 recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of shareholders’ equity because these assets are classified as available for sale.  Unrealized losses (where cost exceeds fair market value) on the assets in these 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.  Generally, Entergy records realized gains and losses on its debt and equity securities using the specific identification method to determine the cost basis of its securities.

The securities held as of December 31, 2017 and 2016 are summarized as follows:
 
 
2017
 
2016
 
 
Fair Value
 
Total Unrealized Gains
 
Total Unrealized Losses
 
Fair Value
 
Total Unrealized Gains
 
Total Unrealized Losses
 
 
(In Millions)
Equity Securities
 

$4,662

 

$2,131

 

$1

 

$3,511

 

$1,673

 

$1

Debt Securities
 
2,550

 
44

 
16

 
2,213

 
34

 
27

Total
 

$7,212

 

$2,175

 

$17

 

$5,724

 

$1,707

 

$28


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 million for Palisades, $1,068 million for Pilgrim, and $613 million for Vermont Yankee. The fair values of the decommissioning trust funds related to the Entergy Wholesale Commodities nuclear plants as of December 31, 2016 are $443 million for Indian Point 1, $564 million for Indian Point 2, $412 million for Palisades, $960 million for Pilgrim, and $584 million for Vermont Yankee. The fair values of the decommissioning trust funds for the Registrant Subsidiaries’ nuclear plants are detailed below.
    

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Deferred taxes on unrealized gains/(losses) are recorded in other comprehensive income (loss) for the decommissioning trusts which do not meet the criteria for regulatory accounting treatment as described above. Unrealized gains/(losses) above are reported before deferred taxes of $479 million and $399 million as of December 31, 2017 and 2016, respectively.  The amortized cost of debt securities was $2,539 million as of December 31, 2017 and $2,212 million as of December 31, 2016.  As of December 31, 2017, the debt securities have an average coupon rate of approximately 3.24%, an average duration of approximately 6.33 years, and an average maturity of approximately 9.99 years.  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 fair value and gross unrealized losses of available-for-sale equity and debt 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 and 2016:
 
2017
 
2016
 
Equity Securities
 
Debt Securities
 
Equity Securities
 
Debt Securities
 
Fair Value
 
Gross Unrealized Losses
 
Fair Value
 
Gross Unrealized Losses
 
Fair Value
 
Gross Unrealized Losses
 
Fair Value
 
Gross Unrealized Losses
 
(In Millions)
Less than 12 months

$8

 

$1

 

$1,099

 

$7

 

$23

 

$1

 

$1,169

 

$26

More than 12 months
—

 
—

 
265

 
9

 
1

 
—

 
20

 
1

Total

$8

 

$1

 

$1,364

 

$16

 

$24

 

$1

 

$1,189

 

$27


The fair value of debt securities, summarized by contractual maturities, as of December 31, 2017 and 2016 are as follows:
 
2017
 
2016
 
(In Millions)
less than 1 year

$74

 

$125

1 year - 5 years
902

 
763

5 years - 10 years
812

 
719

10 years - 15 years
147

 
109

15 years - 20 years
100

 
73

20 years+
515

 
424

Total

$2,550

 

$2,213


During the years ended December 31, 2017, 2016, and 2015, proceeds from the dispositions of securities amounted to $3,163 million, $2,409 million, and $2,492 million, respectively.  During the years ended December 31, 2017, 2016, and 2015, gross gains of $149 million, $32 million, and $72 million, respectively, and gross losses of $13 million, $13 million, and $13 million, respectively, were reclassified out of other comprehensive income into earnings.


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Entergy Arkansas

Entergy Arkansas holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts.  The securities held as of December 31, 2017 and 2016 are summarized as follows:
 
 
2017
 
2016
 
 
Fair Value
 
Total Unrealized Gains
 
Total Unrealized Losses
 
Fair Value
 
Total Unrealized Gains
 
Total Unrealized Losses
 
 
(In Millions)
Equity Securities
 

$596.7

 

$354.9

 

$—

 

$525.4

 

$281.5

 

$—

Debt Securities
 
348.2

 
2.1

 
3.0

 
309.3

 
3.4

 
4.2

Total
 

$944.9

 

$357.0

 

$3.0

 

$834.7

 

$284.9

 

$4.2


The amortized cost of debt securities was $349.1 million as of December 31, 2017 and $310.1 million as of December 31, 2016.  As of December 31, 2017, the debt securities have an average coupon rate of approximately 2.64%, an average duration of approximately 5.61 years, and an average maturity of approximately 7.00 years.  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 equity and debt 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 and 2016:
 
2017
 
2016
 
Equity Securities
 
Debt Securities
 
Equity Securities
 
Debt Securities
 
Fair Value
 
Gross Unrealized Losses
 
Fair Value
 
Gross Unrealized Losses
 
Fair Value
 
Gross Unrealized Losses
 
Fair Value
 
Gross Unrealized Losses
 
(In Millions)
Less than 12 months

$—

 

$—

 

$168.0

 

$1.2

 

$—

 

$—

 

$146.7

 

$4.2

More than 12 months
—

 
—

 
41.4

 
1.8

 
—

 
—

 
—

 
—

Total

$—

 

$—

 

$209.4

 

$3.0

 

$—

 

$—

 

$146.7

 

$4.2


The fair value of debt securities, summarized by contractual maturities, as of December 31, 2017 and 2016 are as follows:
 
2017
 
2016
 
(In Millions)
less than 1 year

$13.0

 

$16.7

1 year - 5 years
123.4

 
106.2

5 years - 10 years
180.6

 
161.2

10 years - 15 years
4.8

 
7.7

15 years - 20 years
3.4

 
1.0

20 years+
23.0

 
16.5

Total

$348.2

 

$309.3


During the years ended December 31, 2017, 2016, and 2015, proceeds from the dispositions of securities amounted to $339.4 million, $197.4 million, and $213 million, respectively.  During the years ended December 31,

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2017, 2016, and 2015, gross gains of $17.7 million, $1.8 million, and $5.9 million, respectively, and gross losses of $0.6 million, $0.8 million, and $0.3 million, respectively, were recorded in earnings.

Entergy Louisiana

Entergy Louisiana holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts.  The securities held as of December 31, 2017 and 2016 are summarized as follows:
 
 
2017
 
2016
 
 
Fair Value
 
Total Unrealized Gains
 
Total Unrealized Losses
 
Fair Value
 
Total Unrealized Gains
 
Total Unrealized Losses
 
 
(In Millions)
Equity Securities
 

$818.3

 

$461.2

 

$—

 

$715.9

 

$346.6

 

$—

Debt Securities
 
493.8

 
10.9

 
3.6

 
424.8

 
8.0

 
5.0

Total
 

$1,312.1

 

$472.1

 

$3.6

 

$1,140.7

 

$354.6

 

$5.0


The amortized cost of debt securities was $490 million as of December 31, 2017 and $421.9 million as of December 31, 2016.  As of December 31, 2017, the debt securities have an average coupon rate of approximately 3.88%, an average duration of approximately 6.17 years, and an average maturity of approximately 12.06 years.  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 equity and debt 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 and 2016:
 
2017
 
2016
 
Equity Securities
 
Debt Securities
 
Equity Securities
 
Debt Securities
 
Fair Value
 
Gross Unrealized Losses
 
Fair Value
 
Gross Unrealized Losses
 
Fair Value
 
Gross Unrealized Losses
 
Fair Value
 
Gross Unrealized Losses
 
(In Millions)
Less than 12 months

$—

 

$—

 

$135.3

 

$1.1

 

$—

 

$—

 

$198.8

 

$4.8

More than 12 months
—

 
—

 
84.4

 
2.5

 
—

 
—

 
4.8

 
0.2

Total

$—

 

$—

 

$219.7

 

$3.6

 

$—

 

$—

 

$203.6

 

$5.0


The fair value of debt securities, summarized by contractual maturities, as of December 31, 2017 and 2016 are as follows:
 
2017
 
2016
 
(In Millions)
less than 1 year

$23.2

 

$31.4

1 year - 5 years
122.8

 
99.1

5 years - 10 years
109.3

 
122.8

10 years - 15 years
52.7

 
41.4

15 years - 20 years
50.7

 
30.9

20 years+
135.1

 
99.2

Total

$493.8

 

$424.8



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During the years ended December 31, 2017, 2016, and 2015, proceeds from the dispositions of securities amounted to $231.3 million, $219.2 million, and $123.5 million, respectively.  During the years ended December 31, 2017, 2016, and 2015, gross gains of $12 million, $3.9 million, and $1.9 million, respectively, and gross losses of $0.4 million, $0.4 million, and $0.3 million, respectively, were recorded in earnings.

System Energy    

System Energy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts.  The securities held as of December 31, 2017 and 2016 are summarized as follows:
 
 
2017
 
2016
 
 
Fair Value
 
Total Unrealized Gains
 
Total Unrealized Losses
 
Fair Value
 
Total Unrealized Gains
 
Total Unrealized Losses
 
 
(In Millions)
Equity Securities
 

$575.2

 

$308.6

 

$—

 

$473.9

 

$221.9

 

$0.1

Debt Securities
 
330.5

 
4.2

 
1.2

 
306.6

 
2.0

 
4.5

Total
 

$905.7

 

$312.8

 

$1.2

 

$780.5

 

$223.9

 

$4.6


The amortized cost of debt securities was $327.5 million as of December 31, 2017 and $309.1 million as of December 31, 2016.  As of December 31, 2017, the debt securities have an average coupon rate of approximately 2.67%, an average duration of approximately 6.48 years, and an average maturity of approximately 9.22 years.  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 equity and debt 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 and 2016:
 
2017
 
2016
 
Equity Securities
 
Debt Securities
 
Equity Securities
 
Debt Securities
 
Fair Value
 
Gross Unrealized Losses
 
Fair Value
 
Gross Unrealized Losses
 
Fair Value
 
Gross Unrealized Losses
 
Fair Value
 
Gross Unrealized Losses
 
(In Millions)
Less than 12 months

$—

 

$—

 

$196.9

 

$1.0

 

$—

 

$—

 

$220.9

 

$4.4

More than 12 months
—

 
—

 
10.4

 
0.2

 
—

 
0.1

 
0.8

 
0.1

Total

$—

 

$—

 

$207.3

 

$1.2

 

$—

 

$0.1

 

$221.7

 

$4.5



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The fair value of debt securities, summarized by contractual maturities, as of December 31, 2017 and 2016 are as follows:
 
2017
 
2016
 
(In Millions)
less than 1 year

$4.1

 

$6.6

1 year - 5 years
173.0

 
188.2

5 years - 10 years
78.5

 
78.5

10 years - 15 years
1.0

 
1.3

15 years - 20 years
6.9

 
7.8

20 years+
67.0

 
24.2

Total

$330.5

 

$306.6


During the years ended December 31, 2017, 2016, and 2015, proceeds from the dispositions of securities amounted to $565.4 million, $499.3 million, and $390.4 million, respectively.  During the years ended December 31, 2017, 2016, and 2015, gross gains of $1.4 million, $3.5 million, and $3.3 million, respectively, and gross losses of $3.3 million, $1.7 million, and $0.5 million, respectively, were recorded in earnings.

Other-than-temporary impairments and unrealized gains and losses

Entergy evaluates investment 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, 2017, 2016, and 2015.  The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment is based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time.  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.  Entergy did not record material charges to other income in 2017, 2016, or 2015 resulting from the recognition of the other-than-temporary impairment of equity securities held in its decommissioning trust funds.


NOTE 17.  VARIABLE INTEREST ENTITIES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Under applicable authoritative accounting guidance, a variable interest entity (VIE) is an entity that conducts a business or holds property that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity holders do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations, and is required to consolidate a VIE if it is the VIE’s primary beneficiary. The primary beneficiary of a VIE is the entity that has the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance, and has the obligation to absorb losses or has the right to residual returns that would potentially be significant to the entity.


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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 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,

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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 and $28.8 million in 2015.  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 2017, $17.2 million in 2016, and $52.3 million in 2015.  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 Entergy 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 Entergy accounts for this leasing arrangement as a capital financing, however, Entergy 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.  Entergy believes, however, that the obligations recorded on the balance sheet materially represent the company’s potential exposure to loss.

Entergy has also reviewed various lease arrangements, power purchase agreements, including agreements for renewable power, and other agreements that represent variable interests in other legal entities which have been determined to be variable interest entities.  In these cases, Entergy has determined that it is not the primary beneficiary of the related VIE because it does not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance, or it does not have the obligation to absorb losses or the right to residual returns that would potentially be significant to the entity, or both.
 

NOTE 18.   TRANSACTIONS WITH AFFILIATES (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Each Registrant Subsidiary purchases electricity from or sells electricity to the other Registrant Subsidiaries, or both, under rate schedules filed with the FERC.  The Registrant Subsidiaries receive management, technical, advisory, operating, and administrative services from Entergy Services; and receive management, technical, and operating services from Entergy Operations.  These transactions are on an “at cost” basis.

As described in Note 1 to the financial statements, all of System Energy’s operating revenues consist of billings to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.


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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)
2017

$127.8

 

$282.4

 

$1.7

 

$—

 

$57.9

 

$633.5

2016

$49.4

 

$376.6

 

$2.9

 

$30.3

 

$180.2

 

$548.3

2015

$127.9

 

$420.2

 

$86.0

 

$66.1

 

$259.1

 

$632.4


Intercompany Operating Expenses
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
(In Millions)
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

2015

$508.5

 

$929.4

 

$331.8

 

$278.4

 

$413.7

 

$155.1


Intercompany Interest and Investment Income
 
 
Entergy Louisiana
 
Entergy
Mississippi
 
Entergy
New
Orleans
 
System
Energy
 
 
(In Millions)
 
 
 
 
 
 
 
 
 
2017
 

$128.0

 

$—

 

$0.2

 

$0.9

2016
 

$127.7

 

$0.1

 

$—

 

$0.1

2015
 

$133.6

 

$—

 

$—

 

$—


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 $24.6 million in 2017, $24.7 million in 2016, and $24.5 million in 2015.

Entergy’s operating transactions with its other equity method investees were not significant in 2017, 2016, or 2015.

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NOTE 19.  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 2017 and 2016 for Entergy Corporation and subsidiaries were:
 
Operating Revenues
 
Operating Income (Loss)
 
Consolidated Net Income (Loss)
 
Net Income (Loss) Attributable to Entergy Corporation
 
(In Thousands)
2017:
 
 
 
First Quarter

$2,588,458

 

$174,803

 

$86,051

 

$82,605

Second Quarter

$2,618,550

 

$143,509

 

$413,368

 

$409,922

Third Quarter

$3,243,628

 

$729,469

 

$401,644

 

$398,198

Fourth Quarter

$2,623,845

 

$211,901

 

($475,710
)
 

($479,113
)
2016:
 
 
 
First Quarter

$2,609,852

 

$498,218

 

$235,242

 

$229,966

Second Quarter

$2,462,562

 

$442,258

 

$572,590

 

$567,314

Third Quarter

$3,124,703

 

$772,060

 

$393,204

 

$388,170

Fourth Quarter

$2,648,528

 

($2,599,001
)
 

($1,765,539
)
 

($1,769,068
)

Earnings (loss) per average common share
 
2017
 
2016
 
Basic
 
Diluted
 
Basic
 
Diluted
First Quarter

$0.46

 

$0.46

 

$1.29

 

$1.28

Second Quarter

$2.28

 

$2.27

 

$3.17

 

$3.16

Third Quarter

$2.22

 

$2.21

 

$2.17

 

$2.16

Fourth Quarter

($2.67
)
 

($2.66
)
 

($9.89
)
 

($9.86
)

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 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 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.

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

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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.

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 2017 and 2016 were:

Operating Revenues
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
(In Thousands)
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

2016:
 
 
 
 
 
 
 
 
 
 
 
First Quarter

$465,373

 

$955,145

 

$263,046

 

$149,340

 

$378,304

 

$137,693

Second Quarter

$504,252

 

$999,034

 

$248,138

 

$164,920

 

$412,922

 

$151,323

Third Quarter

$654,599

 

$1,249,452

 

$309,739

 

$201,336

 

$442,085

 

$114,039

Fourth Quarter

$462,384

 

$973,417

 

$273,726

 

$149,867

 

$382,308

 

$145,236


Operating Income
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
(In Thousands)
2017:
 
 
 
 
 
 
 
 
 
 
 
First Quarter

$39,847

 

$152,648

 

$39,608

 

$21,762

 

$38,842

 

$41,544

Second Quarter

$68,994

 

$193,779

 

$55,262

 

$27,606

 

$47,787

 

$40,717

Third Quarter

$169,755

 

$290,089

 

$84,035

 

$33,415

 

$78,950

 

$37,459

Fourth Quarter

$14,507

 

$210,325

 

$42,169

 

$12,333

 

$33,800

 

$41,073

2016:
 
 
 
 
 
 
 
 
 
 
 
First Quarter

$54,378

 

$181,618

 

$41,573

 

$21,880

 

$41,269

 

$47,466

Second Quarter

$73,447

 

$193,752

 

$61,890

 

$26,913

 

$58,039

 

$45,020

Third Quarter

$188,660

 

$312,951

 

$88,312

 

$42,279

 

$107,964

 

$43,886

Fourth Quarter

$29,843

 

$111,066

 

$32,464

 

$8,807

 

$38,338

 

$44,781





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Net Income (Loss)
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
(In Thousands)
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

2016:
 
 
 
 
 
 
 
 
 
 
 
First Quarter

$19,294

 

$111,606

 

$17,118

 

$11,167

 

$14,562

 

$25,958

Second Quarter

$33,891

 

$253,325

 

$32,194

 

$11,843

 

$24,058

 

$25,090

Third Quarter

$110,148

 

$189,506

 

$46,612

 

$23,701

 

$56,133

 

$22,370

Fourth Quarter

$3,879

 

$67,610

 

$13,260

 

$2,138

 

$12,785

 

$23,326


Earnings (Loss) Applicable to Common Equity
 
Entergy Arkansas
 
Entergy Mississippi
 
Entergy New Orleans
 
(In Thousands)
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

2016:
 
 
 
 
 
First Quarter

$17,576

 

$16,411

 

$10,926

Second Quarter

$32,173

 

$31,487

 

$11,602

Third Quarter

$108,672

 

$45,905

 

$23,460

Fourth Quarter

$3,521

 

$12,938

 

$1,896




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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 $11.1 billion in 2017 and had more than 13,000 employees as of December 31, 2017.

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 mission is to operate a world-class energy business that creates sustainable value for its owners, customers, employees, and communities.  Entergy aspires to achieve top quartile total shareholder returns in a socially and environmentally responsible fashion by leveraging the scale and expertise inherent in its operations.  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 through periodic buy, build, hold, or disposal decisions.  To accomplish this, Entergy has established strategic imperatives for each business segment.  For the Utility, the strategic imperative is to modernize its operations, maintain reliability, and better serve its customers while growing the business. For Entergy Wholesale Commodities, the strategic imperative is to continue to manage the risk of its operating portfolio as Entergy completes its exit from the merchant power business.

Utility
 
The Utility business segment includes five 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, 2017, 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
 
709

 
25
%
 
 
 
 
Entergy Louisiana
Portions of Louisiana
 
1,078

 
37
%
 
93

 
47
%
Entergy Mississippi
Portions of Mississippi
 
449

 
16
%
 
 
 
 
Entergy New Orleans
City of New Orleans
 
200

 
7
%
 
106

 
53
%
Entergy Texas
Portions of Texas
 
448

 
15
%
 
 
 
 
Total customers
 
 
2,884

 
100
%
 
199

 
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, 2017, Entergy reached a 2017 peak demand of 21,671 MWh, compared to the 2016 peak of 21,387 MWh recorded on July 21, 2016.  Selected electric energy sales data is shown in the table below:

Selected 2017 Electric Energy Sales Data
 
Entergy Arkansas
 
Entergy Louisiana
 
Entergy Mississippi
 
Entergy New Orleans
 
Entergy Texas
 
System Energy
 
Entergy (a)
 
(In GWh)
Sales to retail customers
20,888

 
55,243

 
13,048

 
5,622

 
18,058

 
—

 
112,859

Sales for resale:
 
 
 
 
 
 
 
 
 
 
 
 
 
Affiliates
1,782

 
4,793

 
—

 
—

 
1,534

 
6,675

 
—

Others
6,549

 
1,711

 
857

 
1,703

 
729

 
—

 
11,550

Total
29,219

 
61,747

 
13,905

 
7,325

 
20,321

 
6,675

 
124,409

Average use per residential customer (kWh)
12,349

 
14,377

 
14,142

 
11,986

 
14,597

 
—

 
13,716


(a)
Includes the effect of intercompany eliminations.

The following table illustrates the Utility operating companies’ 2017 combined electric sales volume as a percentage of total electric sales volume, and 2017 combined electric revenues as a percentage of total 2017 electric revenue, each by customer class.
Customer Class
 
% of Sales Volume
 
% of Revenue
Residential
 
27.2
 
36.2
Commercial
 
23.1
 
26.7
Industrial (a)
 
38.4
 
27.8
Governmental
 
2.0
 
2.5
Wholesale/Other
 
9.3
 
6.8

(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 2013-2017.

Selected 2017 Natural Gas Sales Data

Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers.  Entergy New Orleans and Entergy Louisiana sold 9,745,874 and 6,017,174 Mcf, respectively, of natural gas to retail customers in 2017.  In 2017, 99% of Entergy Louisiana’s operating revenue was derived from the electric utility business, and only 1% from the natural gas distribution business.  For Entergy New Orleans, 88% of operating revenue was derived from the electric utility business and 12% from the natural gas distribution business in 2017.  

Following is data concerning Entergy New Orleans’s 2017 retail operating revenue sources.
Customer Class
 
Electric Operating Revenue
 
Natural Gas Operating Revenue
Residential
 
42%
 
46%
Commercial
 
39%
 
28%
Industrial
 
6%
 
7%
Governmental/Municipal
 
13%
 
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
 
$7.095 (a)
 
9.25% -10.25%
 
4.67%
 
31.69%
 
- forward test year formula rate plan

- riders: MISO, capacity, Grand
Gulf, energy efficiency, fuel and
purchased power
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Louisiana (electric)
 
$8.303 (b)
 
9.15% - 10.75%
 
7.35%
 
49.64%
 
- formula rate plan through 2016 test
year

- riders/specific recovery: MISO,
capacity, fuel
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Louisiana (gas)
 
$0.059 (c)
 
9.45% - 10.45%
 
7.54%
 
51.63%
 
- gas rate stabilization plan

- rider: gas infrastructure
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Mississippi
 
$2.131 (d)
 
9.47% - 11.49%
 
7.35%
 
49.37%
 
- 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
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy New Orleans (electric)
 
$0.299 (e)
 
10.7% - 11.5%
 
8.58%
 
50.08%
 
- rate case

- riders/specific recovery: fuel,
   capacity
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy New Orleans (gas)
 
$0.089 (f)
 
10.25% - 11.25%
 
8.40%
 
50.08%
 
- rate case

- rider: purchased gas
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Texas
 
$1.634 (g)
 
9.8%
 
8.22%
 
48.6%
 
- rate case

- riders: fuel, distribution and
   transmission, RPCE payments
   and rate case expenses, among
   others
 
 
 
 
 
 
 
 
 
 
 
 
 
System Energy
 
$1.201 (h)
 
10.94%
 
8.90%
 
65%
 
- monthly cost of service
 


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(a)
Based on 2018 forward test year.
(b)
Based on December 31, 2016 test year.
(c)
Based on September 30, 2016 test year.
(d)
Based on 2017 forward test year.
(e)
Based on December 31, 2011 test year and excludes approximately $228 million first-year average rate base for Union.
(f)
Based on December 31, 2011 test year.
(g)
Based on March 31, 2013 adjusted test year and excludes approximately $331 million for rate base being recovered through the distribution cost recovery rider and the transmission cost recovery rider
(h)
Based on calculation as of December 31, 2017.

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. A decision is expected in 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.

To help stabilize retail gas costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility for its gas purchased for resale through the use of financial instruments.  Entergy Louisiana hedges approximately one-half of the projected natural gas volumes used to serve its natural gas customers for November through March.  The hedge quantity is reviewed on an annual basis.


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Due to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs, Entergy Louisiana plans to cap the average fuel adjustment charge to be billed in March 2018 at $0.03060 per kWh and to defer billing of all fuel costs in excess of the capped amounts by including such costs in the over- or under-recovery account.

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 recently-approved 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.

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 docket. 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

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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.

Due to higher fuel costs associated in part with the extended Grand Gulf outage and the partially simultaneous Union Power Block 1 planned outage, for the December 2016, January 2017, and February 2017 billing months, the City Council authorized Entergy New Orleans to cap the fuel adjustment charge billed to customers at $0.035 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.

Due to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs associated in part with certain plant outages, Entergy New Orleans has proposed to cap the fuel adjustment charge to be billed in March 2018 to non-transmission Entergy New Orleans legacy customers and Entergy New Orleans Algiers customers at $0.035323 per kWh and $0.025446 per kWh, respectively. Entergy New Orleans has also proposed to cap the fuel adjustment charge to be billed in March 2018 for Entergy New Orleans legacy transmission customers at $0.034609 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.

Storm Cost Recovery

See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.


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Entergy Texas

Fuel Recovery

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included in base rates.  Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix.  The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT.  The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.

At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. Entergy Texas has not exercised the option to recover its capacity costs under the new rider mechanism, but will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.
    
Electric Industry Restructuring

In June 2009, a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition.  The law allows Entergy Texas to remain a part of the SERC 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

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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.

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 2018-2058.

The business of System Energy is limited to wholesale power sales.  It has no distribution franchises.


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Property and Other Generation Resources

Owned Generating Stations

The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2017, is indicated below:
 
 
Owned and Leased Capability MW(a)
Company
 
Total
 
Gas/Oil
 
Nuclear
 
Coal
 
Hydro
 
Solar
Entergy Arkansas
 
5,217

 
2,136

 
1,821

 
1,189

 
71

 
—

Entergy Louisiana
 
9,099

 
6,603

 
2,136

 
360

 
—

 
—

Entergy Mississippi
 
3,359

 
2,944

 
—

 
414

 
—

 
1

Entergy New Orleans
 
492

 
491

 
—

 
—

 
—

 
1

Entergy Texas
 
2,331

 
2,065

 
—

 
266

 
—

 
—

System Energy
 
1,271

 
—

 
1,271

 
—

 
—

 
—

Total
 
21,769

 
14,239

 
5,228

 
2,229

 
71

 
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 21,533 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 6,800 MW of new long-term resources and the deactivation of over 5,200 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;

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•
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;
•
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; and
•
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.

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;
•
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 has approved the project, and the expected commercial operation date is in June 2019;

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•
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 has 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 has received regulatory approval and will begin in June 2018; and
•
In June 2017, Entergy Arkansas and Chicot Solar, LLC executed 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. Entergy Arkansas filed for regulatory approval in October 2017.

In June 2016, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for long-term renewable generation resources. The RFP was seeking up to 200 MW of renewable resources that could provide energy, fuel diversity, and other benefits to customers. Two proposals were placed in the primary selection list and the transactions are currently in negotiations.

In July 2016, Entergy Services, on behalf of Entergy New Orleans, issued an RFP for long-term renewable generation resources. The RFP was seeking up to 20 MW of renewable resources that could provide increased depth and diversity to Entergy New Orleans’s generation resource portfolio. In May 2017, Entergy New Orleans selected three proposals, including a 5 MW self-build option for an aggregated solar photovoltaic resource located within Orleans Parish, Louisiana. In October 2017, Entergy New Orleans filed an application seeking City Council approval for the self-build option, which is pending before the City Council. Following unsuccessful negotiations related to the other proposals selected in May 2017, Entergy New Orleans suspended negotiations in November 2017 and invited bidders to re-submit proposals with current information. From these submissions, in January 2018, Entergy New Orleans selected three proposals with an anticipated total capacity of 90 MW. The updated proposals selected are in addition to the self-build option.

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. This simple-cycle power plant is proposed to be developed pursuant to an agreement with Entergy Louisiana, which will purchase the plant upon completion in 2021 for a fixed payment to reimburse construction costs plus an associated premium. In May 2017, Entergy Louisiana filed an application with the LPSC seeking certification of the plant. The application is pending.

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 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

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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, 2017, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,500 miles of gas pipeline.  As of December 31, 2017, 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 2015-2017 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
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

2015
 
35
 
2.65

 
31
 
0.85

 
7
 
2.85

 
11
 
3.63

 
16
 
3.24



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Actual 2017 and projected 2018 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)
 
2017
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
 
2018
Entergy Arkansas (a)
28
%
 
33
%
 
49
%
 
51
%
 
18
%
 
15
%
 
—
%
 
1
%
 
5
%
 
—
Entergy Louisiana
38
%
 
49
%
 
26
%
 
33
%
 
3
%
 
4
%
 
9
%
 
14
%
 
24
%
 
—
Entergy Mississippi (b)
47
%
 
55
%
 
18
%
 
30
%
 
13
%
 
15
%
 
—
%
 
—

 
22
%
 
—
Entergy New Orleans (b)
53
%
 
57
%
 
33
%
 
41
%
 
2
%
 
1
%
 
—
%
 
1
%
 
12
%
 
—
Entergy Texas
30
%
 
33
%
 
10
%
 
17
%
 
7
%
 
9
%
 
28
%
 
41
%
 
25
%
 
—
System Energy (c)
—

 
—

 
100
%
 
100
%
 
—

 
—

 
—

 
—

 
—

 
—
Utility (a) (b)
38
%
 
44
%
 
26
%
 
36
%
 
8
%
 
9
%
 
8
%
 
11
%
 
20
%
 
—

(a)
Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2017 and is expected to provide about less than1% of its generation in 2018.
(b)
Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2017 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2018.
(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. MISO purchases cannot be projected for 2018.

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 2018, 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 will use alternate fuels, such as oil, 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 2018.  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 2018.  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 2018.

Entergy Louisiana has committed to five one- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2018.  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 2018.  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 2018.

For the year 2017, coal transportation delivery to Entergy Arkansas-and Entergy Louisiana-operated coal-fired units was adequate for the majority of the year but experienced some delays in the fourth quarter of 2017. It is expected that delivery times will improve in 2018. 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 2018.  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 2018 or 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 shutdowns of the

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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 2017 under a firm contract from Sequent Energy Management L.P.  The gas is delivered through a combination of intrastate and interstate pipelines.

As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements.  Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.

Federal Regulation of the Utility

State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies.  The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.

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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

On December 19, 2013, the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO does 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 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

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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 a complaint filed with the FERC in January 2017 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 under the Availability Agreement would remain in effect and would govern payments made under such agreement in

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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 Agreement relating to the specific indebtedness being secured, Entergy Corporation has agreed to make cash capital

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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 corporation 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 substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States

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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.

Earnings Ratios of Registrant Subsidiaries

The Registrant Subsidiaries’ ratios of earnings to fixed charges and ratios of earnings to combined fixed charges and preferred dividends or distributions pursuant to Item 503 of SEC Regulation S-K are as follows:
 
Ratios of Earnings to Fixed Charges
Years Ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
Entergy Arkansas
2.87
 
3.32
 
2.04
 
3.08
 
3.62
Entergy Louisiana
3.85
 
3.57
 
3.36
 
3.44
 
3.30
Entergy Mississippi
4.49
 
3.96
 
3.59
 
3.23
 
3.19
Entergy New Orleans
4.50
 
4.61
 
4.90
 
3.55
 
1.85
Entergy Texas
2.41
 
2.92
 
2.22
 
2.39
 
1.94
System Energy
4.91
 
5.39
 
4.53
 
4.04
 
5.66


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Ratios of Earnings to Combined Fixed
Charges and Preferred Dividends or Distributions
Years Ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
Entergy Arkansas
2.81
 
3.09
 
1.85
 
2.76
 
3.25
Entergy Louisiana
3.85
 
3.57
 
3.24
 
3.28
 
3.14
Entergy Mississippi
4.36
 
3.71
 
3.34
 
3.00
 
2.97
Entergy New Orleans
4.24
 
4.30
 
4.50
 
3.26
 
1.70

The Registrant Subsidiaries accrue interest expense related to unrecognized tax benefits in income tax expense and do not include it in fixed charges.

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.

On December 29, 2014, Entergy Wholesale Commodities’ Vermont Yankee plant was removed from the grid, after 42 years of operations. The decision to close and decommission Vermont Yankee, which was announced in August 2013, was due to numerous issues including sustained low natural gas and wholesale energy prices, the high cost structure of the plant, and lack of a market structure that adequately compensates merchant nuclear plants for their environmental and fuel diversity benefits in the Northeast region. In November 2016, Entergy entered into an agreement to sell 100% of its membership interest in Entergy Nuclear Vermont Yankee, LLC to a subsidiary of NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant.  The sale of Entergy Nuclear Vermont Yankee to NorthStar will include the transfer of Entergy Nuclear Vermont Yankee’s nuclear decommissioning trust fund and the asset retirement obligation for spent fuel management and decommissioning of the plant. Entergy plans to transfer all spent nuclear fuel to dry cask storage by the end of 2018 in advance of the planned transaction close. Under the sale and related agreements to be entered into at the closing, NorthStar will commit to initiate decommissioning and site restoration by 2021 and complete those activities, along with partial restoration of the Vermont Yankee site, with the exception of the independent spent fuel storage installation and switchyard, by 2030. The original completion date, as outlined in Entergy’s Post Shutdown Decommissioning Activities Report filed with the NRC, was 2075. The transaction is contingent upon certain closing conditions, including approval by the NRC; approval by the State of Vermont Public Utility Commission, including approval of site restoration standards that will be proposed as part of the transaction; the transfer of all spent nuclear fuel to dry fuel storage on the independent spent fuel storage installation; and that the market value of the assets held in the decommissioning trust fund for the Vermont Yankee Nuclear Power Station, less the hypothetical income tax on the aggregate unrealized net gain of such assets at closing, is equal to or exceeds $451.95 million, subject to adjustments.

In October 2015, Entergy determined that it would close the FitzPatrick plant at the end of its fuel cycle in January 2017. In August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon. The transaction was contingent upon, among other things, the expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, the receipt of necessary regulatory approvals from the FERC, the NRC, and the Public Service Commission of the State of New York (NYPSC), and the receipt of a private letter ruling from the IRS. Because certain specified conditions were satisfied in November 2016, including the continued effectiveness of the Clean Energy Standards/Zero Emissions Credit program (CES/ZEC), the establishment of certain long-term agreements on acceptable terms with the Energy Research and Development Authority of the State of New York in connection with the CES/ZEC program, and NYPSC approval of the transaction on acceptable terms, Entergy

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refueled the FitzPatrick plant in January and February 2017. The sale closed in March 2017 after obtaining all the necessary approvals.

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. The Pilgrim plant is expected to cease operations on May 31, 2019, after refueling in the spring of 2017 and operating through the end of that fuel cycle.

In December 2015, Entergy Wholesale Commodities closed on the sale of its 583 MW Rhode Island State Energy Center, in Johnston, Rhode Island. The base sales price, excluding adjustments, was approximately $490 million. Entergy Wholesale Commodities purchased the Rhode Island State Energy Center for $346 million in December 2011.

In December 2016, Entergy announced that it had reached an agreement with Consumers Energy to terminate the existing PPA for the Palisades plant on May 31, 2018. Pursuant to the agreement, 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 granting Consumers Energy recovery of only $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.

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. See Note 14 to the financial statements for a discussion of the impairment and related charges associated with the settlement with New York State.

The Indian Point settlement required New York State agencies to issue environmental certifications needed for license renewal and a renewed water discharge permit based on current plant configuration. It also required the New York State Attorney General and Riverkeeper to withdraw their contentions pending before the Atomic Safety and Licensing Board (ASLB). In exchange, Entergy commits to cease commercial operation of Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021. These actions have been completed, all New York State approvals required for the NRC to issue renewed licenses have been granted, and the ASLB has terminated proceedings before it following the withdrawal of pending contentions. The NRC is not expected to issue renewed licenses earlier than third quarter 2018, as its staff must complete updates to the record on environmental and safety matters (a supplement to the final supplemental environmental impact statement and a supplement to the final safety evaluation report).

With the settlement concerning Indian Point, Entergy has announced plans for the disposition of all of the Entergy Wholesale Commodities nuclear power plants, including the sales of Vermont Yankee and FitzPatrick, and the earlier than previously expected shutdowns of Pilgrim, Palisades, Indian Point 2, and Indian Point 3. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” for further discussion.


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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
 
2015 (b)
Indian Point 2 (b)
 
NYISO
 
1974
 
Sept. 2001
 
Buchanan, NY
 
1,028 MW - Pressurized Water
 
2013 (b)
Vermont Yankee (c)
 
IS0-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)
In October 2015, Entergy determined that it would close the Pilgrim plant no later than June 1, 2019, as discussed above.
(b)
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. See below for discussion of Indian Point 2 and Indian Point 3 entering their “period of extended operation” after expiration of the plants’ initial license terms under “timely renewal.”
(c)
On December 29, 2014, the Vermont Yankee plant ceased power production. In November 2016, Entergy entered into an agreement to sell 100% of the membership interest in Entergy Nuclear Vermont Yankee, to NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant.
(d)
In December 2016, Entergy announced that it had reached an agreement with Consumers Energy to terminate the existing PPA for the Palisades plant in 2018. Separately, and assuming regulatory approvals are obtained for the PPA termination agreement, 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, as a result of the Michigan Public Service Commission’s order, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022.

In October 2015, Entergy determined that it would close the FitzPatrick plant at the end of the fuel cycle, in January 2017, but in August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon, and the sale closed in March 2017.

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.

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. The original expiration dates of the NRC operating licenses for Indian Point 2 and Indian Point 3 were September 28, 2013 and December 12, 2015, respectively. Authorization to operate Indian Point 2 and Indian Point 3 rests on Entergy’s having timely filed a license renewal application that remains pending before the NRC. Indian Point 2 and Indian Point 3 have now entered their “period of extended operation” after expiration of the plants’ initial license term under “timely renewal,” which is a federal statutory rule of general applicability providing for extension of a license for which a renewal application has been timely filed with the licensing agency until the license renewal process has been completed. The license renewal application for Indian Point 2 and Indian Point 3 qualifies for timely renewal protection because it met NRC regulatory standards for timely filing. The NRC is not expected to issue renewed licenses earlier than third quarter 2018. For additional discussion of the license renewal applications and the settlement with New York State, see “Entergy Wholesale Commodities

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Authorizations to Operate Indian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

Non-nuclear Generating Stations

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

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.

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

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credit, “green” credit, etc.) or otherwise to have a market value. In December 2016, Entergy announced that it reached an agreement with Consumers Energy to terminate the existing PPA for the Palisades plant in 2018. 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, as a result of the Michigan Public Service Commission’s order, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022. See discussion above for additional details regarding the agreement.

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 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.


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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.

In September 2003, Entergy agreed to provide plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska.  The original contract was to expire in 2014 corresponding to the original operating license life of the plant.  In 2006 an Entergy subsidiary signed an agreement to provide license renewal services for the Cooper Nuclear Station.  The Cooper Nuclear Station received its license renewal from the NRC in November 2010.  In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029. In 2017 the contract was amended so that it could not be terminated prior to December 21, 2022.

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.


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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 some of the rates charged by Entergy Arkansas and Entergy Louisiana.  The FERC also regulates the provisions of the System Agreement, including the rates, and the provision of transmission service to wholesale market participants. The FERC also 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, which includes the authority to:

•
oversee utility service;
•
set retail rates;
•
determine reasonable and adequate service;
•
control leasing;
•
control the acquisition or sale of any public utility plant or property constituting an operating unit or system;
•
set rates of depreciation;
•
issue certificates of convenience and necessity and certificates of environmental compatibility and public need; and
•
regulate the issuance and sale of certain securities.

Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to recent 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.

Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to:

•
utility service;
•
retail rates and charges;
•
certification of generating facilities and certain transmission projects;
•
certification of power or capacity purchase contracts;
•
audit of the fuel adjustment charge, environmental adjustment charge, and avoided cost payment to Qualifying Facilities;
•
integrated resource planning;
•
utility mergers and acquisitions and other changes of control; and
•
depreciation and other matters.


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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;
•
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:

•
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.

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 fines 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, Vermont Yankee, 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.


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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, 2017 of $183.3 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.

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 2017, Entergy’s subsidiaries won and collected on judgments against the government totaling over $500 million.

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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 May 2015 the U.S. Court of Federal Claims issued a final partial summary judgment on a portion, $21 million, of the claims in the Palisades case. The DOE did not appeal that decision, and Entergy received the payment from the U.S. Treasury in October 2015.

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 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. Supreme 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.


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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 for future decommissioning costs.  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.  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.

In November 2016, Entergy entered into an agreement to sell 100% of the membership interest in Entergy Nuclear Vermont Yankee to a subsidiary of NorthStar. Upon closing of the sale, NorthStar will assume ownership of Vermont Yankee and its decommissioning and site restoration trusts, together with complete responsibility for the facility’s decommissioning and site restoration. The sale is subject to certain closing conditions, including approval from the NRC and the State of Vermont Public Utility Commission. 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.


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In March 2017 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 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 $127.3 million per reactor (with 102 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. Waterford 3, River Bend, Indian Point 2, Indian Point 3, and Palisades are in Column 1. Grand Gulf is in Column 2. ANO 1 and 2 are in Column 4, and are subject to an extensive set of required NRC inspections. Pilgrim is also in Column 4 and is subject to an extensive, but limited, set of required NRC inspections. See Note 8 to the financial statements for further discussion of the placement of ANO 1 and 2, and 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.


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Clean Air Act and Subsequent Amendments

The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other  facilities.  Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements.  These programs include:

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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);
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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;
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Operating permit programs and enforcement of these and other Clean Air Act programs;
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Regional Haze programs; and
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New and existing source standards for greenhouse gas 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.  In recent years, however, the EPA has begun 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 a subsequent request for similar information was received for the White Bluff facility. Entergy responded to all requests. None of these EPA requests for information alleged that the facilities were in violation of law.

In January 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. Entergy is reviewing these claims and will respond accordingly.
 

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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 Count Power Station) in a geographic area that is not in attainment with the currently-enforced 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 indicates 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 non-attainment new source review requirements associated with the revoked 1997 NAAQS.

In March 2008 the EPA revised the 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 non-attainment 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 reclassifies the Houston-Galveston-Brazoria area from marginal to “moderate.”

In October 2015 the EPA issued a final rule lowering the primary and secondary NAAQS for ozone to a level of 70 parts per billion. States were required to assess their attainment status and recommend designations to the EPA. In January 2018 the EPA proposed that the following counties and parishes in Entergy’s service territory be listed as in non-attainment: in Louisiana, Ascension Parish, East Baton Rouge Parish, West Baton Rouge Parish, Iberville Parish, and Livingston Parish; in Texas, Montgomery County. In addition to Lewis Creek in Montgomery County, Texas, Entergy owns or operates fossil-fueled generating units in East Baton Rouge Parish (Louisiana Station) and in Iberville Parish (Willow Glen), Louisiana. The EPA’s final designations are pending. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and non-attainment with the new standard and, where necessary, in planning for compliance. Following designations by the EPA, states will be required to develop plans intended to return non-attainment areas to a condition of attainment. The timing for that action depends largely on the severity of non-attainment in a given area.

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 non-attainment for the SO2

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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 2015 the EPA issued a final data requirement rule for the SO2 1-hour standard. This rule will guide the process to be followed by the states and the EPA to determine the appropriate designation for the remaining unclassified areas in the country. 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 non-attainment areas. Evangeline Parish, Louisiana, was designated non-attainment. 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 non-attainment of the standard or designated as contributing to non-attainment areas.

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.

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.

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 will require 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

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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 continues to review its prior grant of the government’s motion to hold the appeal litigation in abeyance 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. Arkansas has proposed a Part II SIP which is still under consideration at the state level. The public comment period on Part II ended on February 2, 2018.

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 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

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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. 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:

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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 mandatory federal carbon dioxide emission 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 power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants in the United States were approximately 53.2 million tons in 2000 and 35.6 million tons in 2005.  In 2006, Entergy changed its method of calculating emissions to include 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 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 46.1 million tons in 2011, 45.5 million tons in 2012, 46.2 million tons in 2013, 42.4 million tons in 2014, 39.5 million tons in 2015, 42.5 million tons in 2016, and 39.9 million tons in 2017. The decrease

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in this number from 2014 to 2015 was largely attributable to the impact on the calculation methodology of the Utility operating companies’ transition into the MISO system. Participation in this system resulted in fewer power purchases being classified as “controllable” and thus included in the calculation of the emissions total.
    
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 CO2 emissions audit 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 2017 was listed on the North American Index.

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.  

For thirteen years, Entergy participated in an administrative permitting process with the New York State Department of Environmental Conservation (NYSDEC) for renewal of the Indian Point 2 and Indian Point 3 discharge permit.  That proceeding recently was settled along with other ongoing proceedings. For a discussion of the recent Indian Point settlement, see “Entergy Wholesale Commodities Authorization to Operate Indian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

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 developing 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. A decision is expected in 2018.

Coastal Zone Management Act

Before a federal licensing agency (such as the NRC) may issue a major license or permit for an activity within the federally designated coastal zone, the agency must be satisfied that the requirements of the Coastal Zone Management Act (CZMA), as applicable, have been met. In many cases, CZMA requirements are satisfied by the state’s written concurrence with a “consistency determination” filed by the federal license applicant explaining why the activity proposed to be federally licensed is consistent with the state’s coastal management program. For a discussion of the recent Indian Point settlement, including the CZMA proceedings related to Indian Point license renewal, see “Entergy

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Wholesale Commodities Authorizations to Operate Indian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

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. Army Corps of Engineers’ jurisdiction, which in turn could pose additional permitting and pollutant management burdens on Entergy’s operations. The final rule has been challenged in various federal courts by several parties, including most states. In August 2015 the District Court for North Dakota issued a preliminary injunction staying the new rule in 13 states, including Arkansas. In October 2015 the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the rule. 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. In June 2017 the EPA and the U.S. Army Corps of Engineers released a proposed rule that rescinds the June 2015 rule and recodifies the definition of “waters of the U.S.” that was in effect prior to the 2015 rule. The administration is expected to propose a definition of “waters of the U.S.” at a later date. In January 2018 the Supreme Court determined that the Sixth Circuit lacked jurisdiction over the petition to review the 2015 rule and that the challenges should be heard in the federal district court. The matter has been remanded to the Sixth Circuit, which is expected to lift the nationwide stay. After the Supreme Court decision, the EPA and the U.S. Army Corps of Engineers finalized a rule delaying the applicability date of the 2015 rule to early 2020. In February 2018 the states of Louisiana, Mississippi, and Texas filed suit in Texas federal district court seeking a preliminary injunction of the 2015 rule. Entergy will continue to monitor this rulemaking and litigation.

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, Vermont Yankee, 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 has determined that the source is 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

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exchanger operated in support of the Indian Point 2 outage. Oversight by 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 has completed all required corrective actions and expects the NRC to close the notice of violation by March 2018.

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.  In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation.  Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities.  Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs.  The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities.  Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental Matters” section below.

Coal Combustion Residuals

In June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contained two primary regulatory options: (1) regulating CCRs destined for disposal in landfills or received (including stored) in surface impoundments as so-called “special wastes” under the hazardous waste program of 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, 2017, Entergy’s has recorded asset retirement obligations related to CCR management of $8.6 million, including $3.9 million at Entergy Arkansas, $1.8 million at Entergy Louisiana, $1.1 million at Entergy Mississippi, and $1.3 million at Entergy Texas.

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 programs. In September 2017 the EPA agreed to reconsider certain provisions of the CCR rule in light of the WIIN Act. The EPA has not yet initiated a new round of rulemaking and did not extend the existing mid-October 2017 groundwater monitoring deadline. Entergy met the existing monitoring deadline, is monitoring state agency actions, and will participate in the regulatory development process.

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. Entergy is taking action to address the operational and regulatory management of these facilities. Entergy also has monitored levels of constituents in the groundwater monitoring system surrounding its coal combustion residual landfills at these locations that require reporting and additional monitoring. Reporting has occurred as required, and monitoring will continue. Any potential

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requirements for corrective action or operational changes under the new EPA rule are currently being assessed. Moreover, the rule is currently under review at the EPA for potential changes, and the nature and cost of any 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 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 and continue to cooperate in this investigation.  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, while Entergy Arkansas likely will pay a de minimis amount.  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 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,

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Entergy entered into the Voluntary Cleanup Program with TCEQ. Additional direction is expected from TCEQ regarding final remediation requirements for the site.

Entergy

In May 2015 a transformer at the Indian Point facility failed, resulting in a fire and the release of non-PCB oil to the ground surface. The fire was extinguished by the facility’s fire deluge system. No injuries occurred due to the transformer failure or company response. An estimated 3,000 gallons of oil were released into the facility’s discharge canal and the environment surrounding the transformer and discharge canal, including the Hudson River, as a result of the failure, fire, and fire suppression. Once the fire was extinguished, Indian Point personnel and contractors began recovering free-product from the damaged transformer, the transformer containment moat, and the area surrounding the transformer. The United States Coast Guard designated Entergy as the responsible party under the Oil Pollution Act of 1990 and assessed a $1,000 civil penalty for the discharge of oil into navigable waters. As required, Entergy established a claims process including a voluntary hotline. Entergy received no reports to the voluntary hotline or claims under the established claims process. In September 2016, Indian Point personnel identified an oil sheen in the discharge canal. Further investigation revealed that an estimated 600 gallons of lubricating oil had leaked from the Indian Point 3 turbine system. The leaking component has been taken out of service and no oil has been discovered in the Hudson River. In October 2016 the New York Department of Environmental Conservation issued two notices of violation, one for each of these events, and a proposed order on consent for the 2015 event. In January 2017, Entergy and the New York Department of Environmental Conservation resolved this matter with an order on consent. Pursuant to the order, Entergy paid approximately $600 thousand in civil penalties, natural resource damages, and oversight costs. Additionally, Entergy repaired a section of the discharge canal wall and will conduct daily visual inspections of the discharge canal wall to help identify additional material erosion or material structural deficiencies. Entergy has completed all compliance obligations under the consent order and the Department of Environmental Conservation closed the matter in December 2017.

Litigation

Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but certain states in which Entergy operates have proven to be unusually litigious environments.  Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases.  The litigation environment in these states poses a significant business risk to Entergy.

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.

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Employees

Employees are an integral part of Entergy’s commitment to serving customers.  As of December 31, 2017, Entergy subsidiaries employed 13,504 people.

Utility:
 

Entergy Arkansas
1,278

Entergy Louisiana
1,713

Entergy Mississippi
737

Entergy New Orleans
274

Entergy Texas
616

System Energy
—

Entergy Operations
3,361

Entergy Services
3,264

Entergy Nuclear Operations
2,211

Other subsidiaries
50

Total Entergy
13,504


Approximately 4,600 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, 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 public may read and copy any materials that Entergy files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549.  The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  The SEC also 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.

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 was approved for continued use through the test year 2016 filing and included a cap in cost of service increases at a cumulative total of $30 million through the formula rate plan cycle, which cap was not reached. The LPSC also approved in the business combination Entergy Louisiana’s continuation of a mechanism to recover non-fuel MISO-related costs, which are calculated separately from the formula rate plan requirements, but embedded in the formula rate plan factor applied on customer bills. This recovery mechanism expired following the 2015 test year, but was renewed for the 2016 test year. MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause. The formula rate plan includes exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities, as well as purchase power agreements approved by the LPSC, among other items. In August 2017, Entergy Louisiana filed to extend the formula rate plan for an additional three years and to reset rates to the authorized mid-point return on equity of 9.95%. The filing also seeks certain modifications to the formula rate plan, including a narrower, 80 basis points earnings sharing bandwidth and implementation of a rider to recover certain transmission-related investments, when those investments begin delivering benefits to customers. 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 from a base rate case that must be filed for its electric and gas operations in 2018. The limited exceptions include implementation of the final year of a four-year phased-in rate increase for its Algiers operations in the Fifteenth Ward of the City of New Orleans and certain exceptional cost increases or decreases in its base revenue requirement.

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 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.


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The Utility operating companies’ cash flows can be negatively affected by the time delays between when gas, power, or other commodities are purchased and the ultimate recovery from customers of the costs in rates.  On occasion, when the level of incurred costs for fuel and purchased power rises very dramatically, some of the Utility operating companies may agree to defer recovery of a portion of that period’s fuel and purchased power costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies.  For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power costs recovery, see Note 2 to the financial statements.
 
There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.

The Utility operating companies historically have 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

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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 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, capped through the use of risk management products.

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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.

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.  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 most of 2018.  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 two to five 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.  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, not renew, 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, not renew, 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

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nuclear facilities. The license renewal process in some cases may be the subject of significant public debate and legislative review and scrutiny at the federal and, in some cases, state level, though the decision whether to renew is subject to the exclusive jurisdiction of the NRC. Interested parties may also intervene which could result in prolonged proceedings. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy (through Entergy Wholesale Commodities), its Utility operating companies, or System Energy.  A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the change in classification. For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business, see “Regulation of Entergy’s Business - Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1 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.  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.  In addition, certain major parts have long lead-times to manufacture

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if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for Entergy.

The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities nuclear power plants, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.

Certain of the Utility operating companies, System Energy and the owners of the Entergy Wholesale Commodities nuclear plants incur costs for the on-site storage of spent nuclear fuel.  The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel.  For example, while the DOE is required by law to proceed with the licensing of Yucca Mountain and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are prolonging the time before spent fuel is removed from Entergy’s plant sites.  Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts, and Entergy has sued the DOE for such breach.  Furthermore, Entergy is uncertain as to when the DOE will commence acceptance of spent fuel from its facilities for storage or disposal.  As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase.  The costs of on-site storage are also affected by regulatory requirements for such storage.  In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning.  For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.

Certain of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.

Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere.  The Price-Anderson Act limits each reactor owner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool of up to approximately $127.3 million per reactor.   With 102 reactors currently participating, this translates to a total public liability cap of approximately $13 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 as of January 1, 2018).  Claims for any nuclear incident exceeding that amount are covered under the retrospective premiums paid into the secondary insurance pool.  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 $127.3 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.146 billion).  The retrospective premium payment is currently limited to approximately $19 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $127.3 million cap.


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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 surplus (reserve) be significantly depleted due to insured losses.  As of December 31, 2017, the maximum annual assessment amounts total $112.2 million for the Utility plants.  Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments and the Entergy Wholesale Commodities plants currently maintain the retrospective premium insurance to cover those potential assessments.

As an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event.  Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, System Energy, or the Entergy Wholesale Commodities subsidiaries.

The decommissioning trust fund assets for the nuclear power plants owned by the Utility operating companies, System Energy and the Entergy Wholesale Commodities nuclear plant owners may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.
 
Owners of nuclear generating plants have an obligation to decommission those plants.  Certain of the Utility operating companies, System Energy, and owners of the Entergy Wholesale Commodities nuclear power plants maintain decommissioning trust funds for this purpose.  Certain of the Utility operating companies collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies.  Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs.  Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds.

In connection with the acquisition of certain nuclear plants, the Entergy Wholesale Commodities plant owners acquired decommissioning trust funds that are funded in accordance with NRC regulations.  Under NRC regulations, Entergy Wholesale Commodities’ nuclear subsidiaries 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 of the Entergy Wholesale Commodities nuclear power plant’s decommissioning trusts combined with 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, for each of these nuclear power plants.  As a result, if the projected amount of individual plants’ 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 the applicable Entergy subsidiaries would be required to incur 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 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,

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or accelerate the timing for funding of, the obligations related to the decommissioning of 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 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 and the impairment charges that resulted from such decision, 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 northeastern 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 are expected to 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 could lead to the shutdown of nuclear units, denial of license renewal applications, 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)

A failure to obtain renewed licenses or other approvals required for the continued operation of the Entergy Wholesale Commodities’ Indian Point nuclear power plants could have a material effect on Entergy’s results of operations, financial condition, and liquidity and could lead to an acceleration of the timing for the funding of decommissioning obligations.

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The license renewal and related processes for the Entergy Wholesale Commodities’ Indian Point nuclear power plants have been and may continue to be the subject of significant public debate and regulatory and legislative review and scrutiny at the federal and, in certain cases, state level.  The original expiration date of the operating license for Indian Point 2 was September 2013 and the original expiration date of the operating license for Indian Point 3 was December 2015.  Because these plants filed timely license renewal applications, the NRC’s rules provide that these plants may continue to operate under their existing operating licenses until their renewal applications have been finally determined.

In January 2017, Entergy announced that it plans to shut down Indian Point 2 in 2020 and Indian Point 3 in 2021. The early and orderly shutdown is part of a settlement under which New York State has agreed to drop legal challenges and support renewal of the operating licenses for Indian Point. For additional discussion of the settlement agreement with New York State, see the “Entergy Wholesale Commodities Authorizations to Operate Indian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

If the NRC were to deny the applications for the renewal of operating licenses for the Indian Point nuclear power plants, or if Indian Point fails to obtain other approvals, Entergy’s results of operations, financial condition, and liquidity could be materially affected by loss of revenue and cash flow associated with the plant or plants until the proposed shutdown date, potential impairments of the carrying value of the plants, increased depreciation rates, and an accelerated need for decommissioning funds, which could require additional funding. In addition, Entergy may incur increased operating costs depending on any conditions that may be imposed in connection with license renewal.  For further discussion regarding the license renewal processes for the Indian Point nuclear power plants, see the “Entergy Wholesale Commodities Authorizations to Operate Indian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

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, 2017, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 98% in 2018, 91% in 2019, 51% in 2020, 74% in 2021, and 67% 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.

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.


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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;
•
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;

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•
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 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

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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 the plants discussed below. 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 (including if the operating licenses for the Indian Point power plants are not renewed by the NRC), or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.

On August 27, 2013, Entergy announced its plan to close and decommission Vermont Yankee.  Vermont Yankee ceased power production in the fourth quarter 2014 at the end of a fuel cycle.  This decision was approved by the Board in August 2013, and resulted in the recognition of impairment charges in 2013 and 2014. In October 2015, Entergy determined that it will close the Pilgrim and FitzPatrick plants. The Pilgrim plant will cease operations no later than June 1, 2019. FitzPatrick was expected to shut down at the end of its current fuel cycle, planned for January 27, 2017, but in March 2017, Entergy sold the FitzPatrick plant to Exelon Generation Company, LLC which continues to operate the plant. During the third quarter 2015, Entergy recorded impairment and other related charges to write down the carrying values of the FitzPatrick and Pilgrim plants and related assets to their fair values. In addition, in the fourth quarter 2015, Entergy recorded impairment and other related charges to write down the carrying value of the Palisades plant and related assets to their fair value. In December 2016, Entergy reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant and to shut down the plant in 2018, but the agreement was terminated in September 2017 after the Michigan Public Service Commission decided that Consumers Power could not recover costs incurred under the agreement. Entergy intends to shut down the Palisades plant permanently on May 31, 2022. In January 2017, Entergy announced that it reached a settlement with New York State and plans to close the Indian Point 2 plant in 2020 and the Indian Point 3 plant in 2021. As a result, in the fourth quarter of 2016, Entergy recorded impairment and other related charges to write down the carrying values of the Palisades and Indian Point 2 and Indian Point 3 plants and related assets to their fair value. In addition to the impairments and other related charges, Entergy has incurred severance and employee retention costs and expects to incur additional charges through 2022 relating to the decisions to shut down Vermont Yankee, Palisades, Pilgrim, Indian Point 2 and Indian Point 3, and the sale of FitzPatrick.

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, 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, 2017, based on power prices at that time, Entergy had liquidity exposure of $167 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $8 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, 2017, Entergy would have been required to provide approximately $98 million of additional cash or letters of credit under some of the agreements. In the event of a decrease in the credit ratings of Entergy’s Utility operating companies to below investment grade, those companies collectively could be required to provide up to $50 million of additional cash or letters of credit to MISO. As of December 31, 2017, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously received collateral from counterparties, would increase by $372 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, cash flows, and credit ratings.

The recently enacted H.R. 1, also known as the Tax Cuts and Jobs Act of 2017, will significantly change 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 is unclear in certain respects and will require 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. In addition, the regulatory treatment of the impacts of this legislation, particularly on companies like Entergy and the Registrant Subsidiaries, will be subject to the discretion of federal, state, and local public utility regulators.

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. Depending on the outcome of the ratemaking process, IRS examinations, or tax positions and elections that Entergy may elect, Entergy and the Registrant Subsidiaries may be required to record additional charges or credits to income tax expense. Further, the amount and timing of the return of the deferred taxes to customers is dependent upon the regulatory treatment received, and, if the Registrant Subsidiaries are unsuccessful in receiving balanced regulatory treatment, Entergy’s or the Utility operating companies’ cash flow could be materially adversely affected. Further, there may be other material effects resulting from the legislation that have not been identified. While Entergy plans to finance its cash needs that result from the Act through a combination of Registrant Subsidiary debt and Entergy Corporation debt and equity, there can be no assurance that Entergy or the Registrant Subsidiaries will obtain debt or equity financing on terms that are satisfactory or consistent with their current expectations.

In addition, while Moody’s changed the ratings outlooks for Entergy Corporation to negative from stable in reaction to the legislation, it is unclear when or how capital markets, other credit rating agencies, the FERC or state or local regulators may respond to this legislation. Entergy expects that certain financial metrics used by credit rating agencies will be negatively affected as a result of the return of excess deferred taxes to customers, increased debt, and the decrease in the Registrant Subsidiaries’ revenue requirements, and related decrease in operating cash flows, expected as a consequence of the lower federal corporate income tax rate while, at the same time, the loss of the bonus depreciation tax deduction will increase taxable income in the future. Also, the timing of the return of excess deferred income taxes

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to customers will not exactly match the lower taxes that Entergy will be paying which will result in cash outflows to customers. It is also uncertain how other credit rating agencies will treat the impacts of this legislation on their credit ratings and metrics, and whether additional avenues will evolve for companies to manage the adverse aspects of this legislation. These avenues, to the extent available and if successfully applied, could lessen the impacts on certain credit metrics, although there can be no assurance in this regard.

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, and could result in additional credit rating agency actions. Any such actions by credit rating agencies may make it more difficult and costly for Entergy to issue debt securities and certain other types of financing and could increase borrowing costs under its credit facilities.

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 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 proceedings commenced or other responses by Entergy’s regulators to 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.

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, in November 2016, Entergy announced that it had entered into a purchase and sale agreement with NorthStar for the sale of 100% of the membership interests in Entergy Nuclear Vermont Yankee, which owns the Vermont Yankee plant. 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. 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:


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•
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 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 of additional generation supply sources within the Utility operating companies’ service territory, and as to the Entergy Wholesale Commodities business, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.

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The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs to fulfill their obligations related to environmental and other matters.

The businesses in which the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business operate are subject to extensive environmental regulation by local, state, and federal authorities.  These laws and regulations affect the manner in which the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business conduct their operations and make capital expenditures.  These laws and regulations also affect how the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, certain migratory birds and eagles, hazardous materials transportation, and similar matters.  Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies.  Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures.  Violations of these requirements can subject the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards.  In addition, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business potentially are subject to liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies, System Energy, and Entergy Wholesale Commodities and of property contaminated by hazardous substances they generate.  The Utility operating companies 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, 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.  The changes to the

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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.

(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

The effects of weather and economic conditions, and the related impact on electricity and gas usage, may 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 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 experience lower usage per customer in the residential and commercial classes, and further advances have the potential to limit sales growth in the future.  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 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, 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 are focusing 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 late 2017, the EPA proposed to repeal the regulations and issued an Advanced Notice of Proposed Rulemaking for replacing certain aspects of the standards for existing sources. 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

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developed in California. The impact that recent changes in the federal government 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 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 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 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, 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 wetland and barrier island erosion, 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, 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.  Three of Entergy’s Utility operating companies 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.


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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.

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

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support may not always be adequate to cover the related obligations.  In such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties.  In addition, the credit commitments of Entergy’s lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially affect the adequacy of its liquidity sources.

Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.

The performance of the capital markets affects the values of the assets held in trust under Entergy’s pension and postretirement 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, including cyber attacks, and failures or breaches of Entergy’s and its subsidiaries’ technology systems may adversely affect Entergy’s results of operations.

As power generators and distributors, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism, including physical and cyber attacks, either as a direct act against one of Entergy’s generation facilities, transmission operations centers, or distribution infrastructure used to manage and transport power to customers. 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 recently discovered on our corporate network and remediated on a timely basis, it did not affect the company’s operational systems, nuclear plants or transmission network, nor did it have a material effect on our operations. Additionally, within Entergy’s industry, there have been attacks on energy infrastructure, but with minimal impact to operations, and there may be more attacks in the future. 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 the company’s 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 standards. Despite the implementation of multiple layers of security by Entergy and its subsidiaries,

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technology systems remain vulnerable to potential threats that could lead to unauthorized access or loss of availability to 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). 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.

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

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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, INC. AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net 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.

2016 Compared to 2015

Net income increased $92.9 million primarily due to higher net revenue and lower other operation and maintenance expenses, partially offset by a higher effective income tax rate and higher depreciation and amortization expenses.

Net Revenue

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

$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.


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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.

2016 Compared to 2015

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 2016 to 2015.
 
Amount
 
(In Millions)
 
 
2015 net revenue

$1,362.2

Retail electric price
161.5

Other
(3.2
)
2016 net revenue

$1,520.5


The retail electric price variance is primarily due to an increase in base rates, as approved by the APSC. The new base rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. The increase includes 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. A significant portion of the increase was related to the purchase of Power Block 2 of the Union Power Station in March 2016. See Note 2 to the financial statements for further discussion of the rate case. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.

Other Income Statement Variances

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 the prior year; 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

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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 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 rebalancing for the ANO 1 and ANO 2 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; 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.

2016 Compared to 2015

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 decreased primarily due to:

•
a decrease of $21.6 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;

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•
the deferral 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; and
•
a decrease of $7.2 million in energy efficiency costs, including the effects of true-ups to the energy efficiency filings for fixed costs to be collected from customers and incentives recognized as a result of participation in energy efficiency programs.

The decrease was partially offset by an increase of $24.1 million in nuclear generation expenses primarily due to an overall higher scope of work performed during plant outages and higher nuclear labor costs compared to prior year and an increase of $8.2 million in fossil-fueled generation expenses primarily due to the purchase of Power Block 2 of the Union Power Station in March 2016. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.

Taxes other than income taxes decreased primarily due to a decrease in local franchise taxes resulting from lower residential and commercial revenues compared to the prior year and a decrease in payroll taxes.
    
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.
        
Interest expense increased primarily due to:

•
$5.1 million in estimated interest expense recorded in connection with the FERC orders issued in April 2016 in the opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding; and
•
the net issuance of $230 million of first mortgage bonds in 2016. See Note 5 to the financial statements for further discussion of long-term debt.

Income Taxes

The effective income tax rates for 2017, 2016, and 2015 were 40.1%, 39.2%, and 35.3%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% 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 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 proceedings commenced or other responses by Entergy’s regulators to the Act.



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Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2017, 2016, and 2015 were as follows:
 
2017
 
2016
 
2015
 
(In Thousands)
Cash and cash equivalents at beginning of period

$20,509

 

$9,135

 

$218,505

 
 
 
 
 
 
Net cash provided by (used in):
 
 
 

 
 

Operating activities
555,556

 
676,511

 
474,890

Investing activities
(829,312
)
 
(947,995
)
 
(685,274
)
Financing activities
259,463

 
282,858

 
1,014

Net increase (decrease) in cash and cash equivalents
(14,293
)
 
11,374

 
(209,370
)
 
 
 
 
 
 
Cash and cash equivalents at end of period

$6,216

 

$20,509

 

$9,135


Operating Activities

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.

Net cash flow provided by operating activities increased $201.6 million in 2016 primarily due to:

•
income tax refunds of $135.7 million in 2016 compared to income tax payments of $103.3 million in 2015. Entergy Arkansas had income tax refunds in 2016 and income tax payments in 2015 in accordance with an intercompany income tax allocation agreement. The 2016 income tax refunds resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit whereas the income tax payments in 2015 resulted primarily from final settlement of amounts outstanding associated with the 2006-2007 IRS audit as well as adjustments associated with the settlement of the 2008-2009 IRS audit. See Note 3 to the financial statements for further discussion of the income tax audits;
•
the timing of payments to vendors; and
•
an increase in net revenue.

The increase was partially offset by a decrease due to the timing of recovery of fuel and purchased power costs.

Investing Activities

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. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.


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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;
•
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; and
•
an increase of $11.2 million due to increased spending on advanced metering infrastructure.

Net cash flow used in investing activities increased $262.7 million in 2016 primarily due to the purchase of Power Block 2 of the Union Power Station in March 2016 for approximately $237 million. See Note 14 to the financial statements for further discussion of the Union Power Station purchase. The increase was partially offset by 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.

Financing Activities

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 resulting from Entergy Arkansas’s routine evaluation of its ability to pay dividends. 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. 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 increased $281.8 million in 2016 primarily due to:

•
the net issuance of $189.1 million of long-term debt in 2016 compared to the net retirement of $13.2 million of long-term debt in 2015;
•
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; and
•
net repayments of $11.7 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2016 compared to net repayments of $36.3 million in 2015.

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The increase was partially offset by the redemptions of $75 million of 6.45% Series preferred stock and $10 million of 6.08% Series preferred stock in 2016 and money pool activity.

Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased by $1.5 million in 2016 compared to increasing by $52.7 million in 2015.

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

Capital Structure

Entergy Arkansas’s capitalization is balanced between equity and debt, as shown in the following table.
 
December 31,
2017
 
December 31,
2016
Debt to capital
55.5%
 
55.3%
Effect of excluding the securitization bonds
(0.3%)
 
(0.4%)
Debt to capital, excluding securitization bonds (a)
55.2%
 
54.9%
Effect of subtracting cash
—%
 
(0.2%)
Net debt to net capital, excluding securitization bonds (a)
55.2%
 
54.7%

(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 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 Arkansas may issue incremental debt or reduce dividends, 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 dividends, 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 and preferred stock 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 Arkansas’s planned construction and other capital investments.
 
2018
 
2019
 
2020
 
(In Millions)
Planned construction and capital investment:
 
 
 

 
 

Generation

$190

 

$240

 

$225

Transmission
170

 
165

 
175

Distribution
225

 
245

 
225

Utility Support
110

 
85

 
85

Total

$695

 

$735

 

$710


Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2018
 
2019-2020
 
2021-2022
 
after 2022
 
Total
 
(In Millions)
Long-term debt (a)

$125

 

$266

 

$672

 

$4,208

 

$5,271

Operating leases

$17

 

$29

 

$16

 

$24

 

$86

Purchase obligations (b)

$595

 

$1,050

 

$863

 

$5,369

 

$7,877


(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 $64.1 million to its qualified pension plans and approximately $472 thousand to its other postretirement health care and life insurance plans in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018.  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 ($117.7) 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 investment to support advanced metering; resource planning, including potential generation projects; system improvements; investments in ANO 1 and 2; 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 discussed above in “Capital Structure,” Entergy Arkansas routinely evaluates its ability to pay dividends to Entergy Corporation from its earnings. Provisions in Entergy Arkansas’s articles of incorporation relating to preferred

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stock restrict the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock.  

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 is expected to begin 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. Entergy Arkansas has begun discussions with the other parties to implement the items in the settlement agreement including pre-pay and time of use programs.

Sources of Capital

Entergy Arkansas’s sources to meet its capital requirements include:

•
internally generated funds;
•
cash on hand;
•
debt or preferred stock issuances; and
•
bank financing under new or existing facilities.

Entergy Arkansas may refinance, redeem, or otherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common and preferred stock issuances by Entergy Arkansas require prior regulatory approval.  Preferred stock and debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s corporate charters, bond indentures, and other agreements.  Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.


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Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
2017
 
2016
 
2015
 
2014
(In Thousands)
($166,137)
 
($51,232)
 
($52,742)
 
$2,218

See Note 4 to the financial statements for a description of the money pool.

Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in August 2022. Entergy Arkansas also has a $20 million credit facility scheduled to expire in April 2018.  The $150 million credit facility permits the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2017, 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, 2017, 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 May 2019.  As of December 31, 2017, $50 million in letters of credit to support a like amount of commercial paper issued and $24.9 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 authorizations from the FERC through October 2019 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 APSC, and the current authorization extends through December 2018.

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 September 2015 the APSC staff and intervenors filed direct testimony, with the APSC staff recommending a revenue requirement of $217.9 million and a 9.65% 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. A settlement hearing was held in January 2016. 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

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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 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved the 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 docket 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 docket 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.

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. The restructuring is subject to regulatory review and approval by the APSC, the FERC, and the NRC. Entergy Arkansas also filed a notice with the Missouri Public Service Commission in December 2017 out of an abundance of caution, although

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Entergy Arkansas does not serve any retail customers in Missouri. If the APSC approves the restructuring by September 1, 2018, and the restructuring closes on or before December 1, 2018, Entergy Arkansas proposed in its application to credit retail customers $66 million over six years, beginning in 2019. In February 2018, Entergy Arkansas filed supplemental testimony reducing the proposed retail customer credits to $39.6 million over six years. If the APSC, the FERC, and the NRC approvals are obtained, Entergy Arkansas expects the restructuring will be consummated on or before December 1, 2018.
It is currently contemplated that Entergy Arkansas would undertake a multi-step restructuring, which would include the following:
•
Entergy Arkansas would redeem its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million, which includes call premiums, plus accumulated and unpaid dividends, if any.
•
Entergy Arkansas would convert from an Arkansas corporation to a Texas corporation.
•
Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas will allocate 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 will assume substantially all of the liabilities of Entergy Arkansas, in a transaction regarded as a merger under the TXBOC. Entergy Arkansas will remain in existence and hold the membership interests in Entergy Arkansas Power.
•
Entergy Arkansas will contribute 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 will be a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
•
Entergy Arkansas will change its name to Entergy Utility Property, Inc., and Entergy Arkansas Power will then change its name to Entergy Arkansas, LLC.

Upon the completion of the restructuring, Entergy Arkansas, LLC will hold substantially all of the assets, and will have assumed substantially all of the liabilities, of Entergy Arkansas. Entergy Arkansas may modify or supplement the steps to be taken to effectuate the restructuring.
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.  These costs cause an increase in Entergy Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects the costs from customers over twelve months.

In May 2014, Entergy Arkansas filed its annual redetermination of the production cost allocation rider to recover the $3 million unrecovered retail balance as of December 31, 2013 and the $67.8 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. In January 2015 the APSC issued an order approving Entergy Arkansas’s request for recovery of the $3 million under-recovered amount based on the true-up of the production cost allocation rider and the $67.8 million May 2014 System Agreement bandwidth remedy payment subject to refund with interest, with recovery of these payments concluding with the last billing cycle in December 2015. The APSC also found that Entergy Arkansas is entitled to carrying charges pursuant to the current terms of the production cost allocation rider. Entergy Arkansas made its compliance filing pursuant to the order in January 2015 and the APSC issued its approval order, also in January 2015. The redetermined rate went into effect with the first billing cycle of February 2015.

In May 2015, Entergy Arkansas filed its annual redetermination of the production cost allocation rider, which included a $38 million payment made by Entergy Arkansas as a result of the FERC’s February 2014 order related to the comprehensive bandwidth recalculation for calendar year 2006, 2007, and 2008 production costs. The redetermined rate for the 2015 production cost allocation rider update was added to the redetermined rate from the 2014 production

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cost allocation rider update and the combined rate was effective with the first billing cycle of July 2015. This combined rate was effective through December 2015. The collection of the remainder of the redetermined rate for the 2015 production cost allocation rider update continued through June 2016.

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 became effective with the first billing cycle of July 2016, and the rates were effective 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.

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 redetermination of its energy cost rate that was subsequently filed in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude $65.9 million of deferred fuel and purchased energy costs incurred in 2013 from the redetermination of its 2014 energy cost rate. The $65.9 million is an estimate of the incremental fuel and replacement energy costs that Entergy Arkansas incurred 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 is available regarding various claims associated with the ANO stator incident. The APSC approved Entergy Arkansas’s request in February 2014. 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 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.


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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 requests refunds.  In July 2009 the Utility operating companies filed a response to the complaint requesting that the FERC dismiss the complaint on the merits without hearing because the LPSC has failed to meet its burden of showing any violation of the System Agreement and failed to produce any evidence of imprudent action by the Entergy System.  In their response, the Utility operating companies explained that the System Agreement clearly 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.

The LPSC filed direct testimony in the proceeding alleging, among other things, (1) that Entergy violated the System Agreement by permitting Entergy Arkansas to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other Utility operating companies’ customers; and (2) that over the period 2000 - 2009, these non-requirements sales caused harm to the Utility operating companies’ customers and these customers should be compensated for this harm by Entergy.  In subsequent testimony, the LPSC modified its original damages claim in favor of quantifying damages by re-running intra-system bills.  The Utility operating companies believe the LPSC’s allegations are without merit.  A hearing in the matter was held in August 2010.

In December 2010 the ALJ issued an initial decision.  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.  Quantifying the effect of the FERC’s decision requires re-running intra-system bills for a ten-year period, and the FERC in its decision established further hearing procedures to determine the calculation of the effects.  In July 2012, Entergy and the LPSC filed requests for rehearing of the FERC’s June 2012 decision. A hearing was held in May 2013 to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision.
    
In August 2013 the presiding judge issued an initial decision in the calculation proceeding. The initial decision concluded that the methodology proposed by the LPSC, rather than the methodologies proposed by Entergy or the FERC Staff, should be used to calculate the payments that Entergy Arkansas is to make to the other Utility operating companies. The initial decision also concluded that the other System Agreement service schedules should not be adjusted and that payments by Entergy Arkansas should not be reflected in the rough production cost equalization bandwidth calculations for the applicable years. The initial decision recognized that the LPSC’s methodology would result in an inequitable windfall to the other Utility operating companies and, therefore, concluded that any payments by Entergy Arkansas should be reduced by 20%. The LPSC, APSC, 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.


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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 still pending with 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.

Pursuant to the procedural schedule established in the case, Entergy Services re-ran intra-system bills for the ten-year period 2000-2009 to quantify the effects of the FERC's ruling. In November 2016 the LPSC submitted testimony disputing certain aspects of the calculations. A hearing was held in May 2017. In July 2017, the ALJ issued an initial decision concluding that Entergy Arkansas should pay $86 million plus interest to the other Utility operating companies. 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. The case is pending before the FERC. No payments will be made or received by the Utility operating companies until the FERC issues an order reviewing the initial decision and Entergy submits a subsequent filing to comply with that order.

The effect of the FERC’s decisions thus far in the case would be that Entergy Arkansas will make payments to some or all of the other Utility operating companies. Because further proceedings will still occur in the case, the amount and recipients of payments by Entergy Arkansas are unknown at this time. 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 includes interest, for its estimated increased costs and payment to the other Utility operating companies. This estimate is subject to change depending on how the FERC resolves the issues that are still outstanding in the case, including its review of the July 2017 initial decision. Entergy Arkansas’s increased costs will be attributed to Entergy Arkansas’s retail and wholesale businesses, and it is not probable that Entergy Arkansas will recover the wholesale portion. Entergy Arkansas, therefore, recorded a deferred fuel regulatory asset in the first quarter 2016 of approximately $75 million, which represents its estimate of the retail portion of the costs. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in November 2017

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Management’s Financial Discussion and Analysis


described above, in the fourth quarter 2017, Entergy Arkansas recorded an additional liability of $35 million and a regulatory asset of $31 million. Because management currently expects to recover the retail portion of the costs through a base rate proceeding or newly proposed rider, the regulatory asset is reflected as Other regulatory assets as of December 31, 2017.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.

Nuclear Matters

Entergy Arkansas owns and, through an affiliate, operates the ANO 1 and ANO 2 nuclear power plants.  Entergy Arkansas is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, to position Entergy’s nuclear fleet to meet its operational goals, 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.

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.

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.


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Management’s Financial Discussion and Analysis


Nuclear Decommissioning Costs

See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.

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.

Unbilled Revenue

See “Unbilled Revenue” 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 unbilled revenue amounts.

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 2018 Qualified Pension Cost
 
Impact on 2017 Qualified Projected Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$3,107
 
$47,040
Rate of return on plan assets
 
(0.25%)
 
$2,914
 
$-
Rate of increase in compensation
 
0.25%
 
$1,353
 
$6,446


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Management’s Financial Discussion and Analysis


The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption
 
Change in Assumption
 
Impact on 2018 Postretirement Benefit Cost
 
Impact on 2017 Accumulated Postretirement Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$506
 

$7,552

Health care cost trend
 
0.25%
 
$782
 

$5,513


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 2017 was $37 million.  Entergy Arkansas anticipates 2018 qualified pension cost to be $43 million. In 2016, Entergy Arkansas refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $13.3 million. Entergy Arkansas contributed $79.6 million to its qualified pension plan in 2017 and estimates pension contributions will be approximately $64.1 million in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018.

Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 2017 was $4 million.  Entergy Arkansas expects 2018 postretirement health care and life insurance benefit income of approximately $10.2 million.  In 2016, Entergy Arkansas refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $2.5 million. Entergy Arkansas contributed $695 thousand to its other postretirement plans in 2017 and estimates 2018 contributions will be approximately $472 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 shareholders and Board of Directors of
Entergy Arkansas, Inc. and Subsidiaries

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Entergy Arkansas, Inc. and Subsidiaries (the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of income, cash flows and changes in common equity (pages 319 through 324 and applicable items in pages 55 through 230), for each of the three years in the period ended December 31, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2018


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


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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS
 
 
 
 
 
For the Years Ended December 31,
 
 
2017
 
2016
 
2015
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$2,139,919

 

$2,086,608

 

$2,253,564

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
402,777

 
325,036

 
535,919

Purchased power
 
230,652

 
233,350

 
380,081

Nuclear refueling outage expenses
 
83,968

 
56,650

 
51,411

Other operation and maintenance
 
707,825

 
706,573

 
734,118

Decommissioning
 
56,860

 
53,610

 
50,414

Taxes other than income taxes
 
103,662

 
93,109

 
99,926

Depreciation and amortization
 
277,146

 
264,215

 
246,897

Other regulatory charges (credits) - net
 
(16,074
)
 
7,737

 
(24,608
)
TOTAL
 
1,846,816

 
1,740,280

 
2,074,158

 
 
 
 
 
 
 
OPERATING INCOME
 
293,103

 
346,328

 
179,406

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
18,452

 
17,099

 
14,227

Interest and investment income
 
35,882

 
19,087

 
22,382

Miscellaneous - net
 
(299
)
 
(1,446
)
 
(3,385
)
TOTAL
 
54,035

 
34,740

 
33,224

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
122,075

 
115,311

 
105,622

Allowance for borrowed funds used during construction
 
(8,585
)
 
(9,228
)
 
(7,805
)
TOTAL
 
113,490

 
106,083

 
97,817

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
233,648

 
274,985

 
114,813

 
 
 
 
 
 
 
Income taxes
 
93,804

 
107,773

 
40,541

 
 
 
 
 
 
 
NET INCOME
 
139,844

 
167,212

 
74,272

 
 
 
 
 
 
 
Preferred dividend requirements
 
1,428

 
5,270

 
6,873

 
 
 
 
 
 
 
EARNINGS APPLICABLE TO COMMON STOCK
 

$138,416

 

$161,942

 

$67,399

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 


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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS



 

For the Years Ended December 31,
 

2017

2016

2015
 

(In Thousands)
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$139,844

 

$167,212

 

$74,272

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 
427,394

 
414,933

 
400,156

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
67,711

 
201,219

 
(4,330
)
Changes in assets and liabilities:
 
 

 
 

 
 

Receivables
 
(23,397
)
 
(39,118
)
 
20,813

Fuel inventory
 
3,402

 
29,929

 
(11,791
)
Accounts payable
 
16,011

 
143,645

 
(2,528
)
Prepaid taxes and taxes accrued
 
40,127

 
37,485

 
(54,531
)
Interest accrued
 
1,635

 
(3,303
)
 
(367
)
Deferred fuel costs
 
33,190

 
(105,741
)
 
151,332

Other working capital accounts
 
15,087

 
(46,490
)
 
(44,784
)
Provisions for estimated losses
 
16,047

 
13,130

 
(137
)
Other regulatory assets
 
(76,762
)
 
(95,464
)
 
60,279

Other regulatory liabilities
 
1,043,507

 
62,994

 
(11,123
)
Deferred tax rate change recognized as regulatory liability/asset
 
(1,047,837
)
 
—

 
—

Pension and other postretirement liabilities
 
(70,826
)
 
(36,805
)
 
(110,936
)
Other assets and liabilities
 
(29,577
)
 
(67,115
)
 
8,565

Net cash flow provided by operating activities
 
555,556

 
676,511

 
474,890

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(735,816
)
 
(666,289
)
 
(624,546
)
Allowance for equity funds used during construction
 
19,211

 
17,754

 
15,882

Nuclear fuel purchases
 
(151,424
)
 
(102,050
)
 
(132,252
)
Proceeds from sale of nuclear fuel
 
51,029

 
39,313

 
52,281

Proceeds from nuclear decommissioning trust fund sales
 
339,434

 
197,390

 
212,954

Investment in nuclear decommissioning trust funds
 
(352,138
)
 
(213,093
)
 
(223,357
)
Payment for purchase of plant
 
—

 
(237,323
)
 
—

Changes in money pool receivable - net
 
—

 
—

 
2,218

Insurance proceeds
 
—

 
10,404

 
11,654

Other
 
392

 
5,899

 
(108
)
Net cash flow used in investing activities
 
(829,312
)

(947,995
)

(685,274
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
294,656

 
817,563

 
—

Retirement of long-term debt
 
(175,560
)
 
(628,433
)
 
(13,234
)
Capital contribution from parent
 
—

 
200,000

 
—

Redemption of preferred stock
 
—

 
(85,283
)
 
—

Change in money pool payable - net
 
114,905

 
(1,510
)
 
52,742

Changes in short-term borrowings - net
 
49,974

 
(11,690
)
 
(36,278
)
Dividends paid:
 
 

 
 

 
 

Common stock
 
(15,000
)
 
—

 
—

Preferred stock
 
(1,428
)
 
(6,631
)
 
(6,873
)
Other
 
(8,084
)
 
(1,158
)
 
4,657

Net cash flow provided by financing activities
 
259,463

 
282,858

 
1,014

Net increase (decrease) in cash and cash equivalents
 
(14,293
)
 
11,374

 
(209,370
)
Cash and cash equivalents at beginning of period
 
20,509

 
9,135

 
218,505

Cash and cash equivalents at end of period
 

$6,216

 

$20,509

 

$9,135

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 
 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$115,162

 

$112,912

 

$100,435

Income taxes
 

($8,141
)
 

($135,709
)
 

$103,296

See Notes to Financial Statements.

 


 


 


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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$6,184

 

$20,174

Temporary cash investments
 
32

 
335

Total cash and cash equivalents
 
6,216

 
20,509

Securitization recovery trust account
 
3,748

 
4,140

Accounts receivable:
 
 

 
 

Customer
 
110,016

 
102,229

Allowance for doubtful accounts
 
(1,063
)
 
(1,211
)
Associated companies
 
38,765

 
35,286

Other
 
65,209

 
58,153

Accrued unbilled revenues
 
105,120

 
100,193

Total accounts receivable
 
318,047

 
294,650

Deferred fuel costs
 
63,302

 
96,690

Fuel inventory - at average cost
 
29,358

 
32,760

Materials and supplies - at average cost
 
192,853

 
182,600

Deferred nuclear refueling outage costs
 
56,485

 
81,313

Prepayments and other
 
12,108

 
14,293

TOTAL
 
682,117

 
726,955

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Decommissioning trust funds
 
944,890

 
834,735

Other
 
3,160

 
7,912

TOTAL
 
948,050

 
842,647

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
11,059,538

 
10,488,060

Property under capital lease
 
—

 
716

Construction work in progress
 
280,888

 
304,073

Nuclear fuel
 
277,345

 
307,352

TOTAL UTILITY PLANT
 
11,617,771

 
11,100,201

Less - accumulated depreciation and amortization
 
4,762,352

 
4,635,885

UTILITY PLANT - NET
 
6,855,419

 
6,464,316

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Regulatory asset for income taxes - net
 
—

 
62,646

Other regulatory assets (includes securitization property of $28,583 as of December 31, 2017 and $41,164 as of December 31, 2016)
 
1,567,437

 
1,428,029

Deferred fuel costs
 
67,096

 
66,898

Other
 
13,910

 
14,626

TOTAL
 
1,648,443

 
1,572,199

 
 
 
 
 
TOTAL ASSETS
 

$10,134,029

 

$9,606,117

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Currently maturing long-term debt
 

$—

 

$114,700

Short-term borrowings
 
49,974

 
—

Accounts payable:
 
 

 
 

Associated companies
 
365,915

 
239,711

Other
 
215,942

 
185,153

Customer deposits
 
97,687

 
97,512

Taxes accrued
 
47,321

 
7,194

Interest accrued
 
18,215

 
16,580

Other
 
29,922

 
36,557

TOTAL
 
824,976

 
697,407

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
1,190,669

 
2,186,623

Accumulated deferred investment tax credits
 
34,104

 
35,305

Regulatory liability for income taxes - net
 
985,823

 
—

Other regulatory liabilities
 
363,591

 
305,907

Decommissioning
 
981,213

 
924,353

Accumulated provisions
 
34,729

 
18,682

Pension and other postretirement liabilities
 
353,274

 
424,234

Long-term debt (includes securitization bonds of $34,662 as of December 31, 2017 and $48,139 as of December 31, 2016)
 
2,952,399

 
2,715,085

Other
 
5,147

 
13,854

TOTAL
 
6,900,949

 
6,624,043

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
Preferred stock without sinking fund
 
31,350

 
31,350

 
 
 
 
 
COMMON EQUITY
 
 

 
 

Common stock, $0.01 par value, authorized 325,000,000 shares; issued and outstanding 46,980,196 shares in 2017 and 2016
 
470

 
470

Paid-in capital
 
790,264

 
790,243

Retained earnings
 
1,586,020

 
1,462,604

TOTAL
 
2,376,754

 
2,253,317

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$10,134,029

 

$9,606,117

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 



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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY
For the Years Ended December 31, 2017, 2016, and 2015
 
 
 
 
 
 
 
Common Equity
 
 
 
 
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Total
 
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2014
 

$470

 

$588,471

 

$1,235,296

 

$1,824,237

Net income
 
—

 
—

 
74,272

 
74,272

Preferred stock dividends
 
—

 
—

 
(6,873
)
 
(6,873
)
Other
 
—

 
22

 
—

 
22

Balance at December 31, 2015
 

$470

 

$588,493

 

$1,302,695

 

$1,891,658

Net income
 
—

 
—

 
167,212

 
167,212

Capital contributions from parent
 
—

 
200,000

 
—

 
200,000

Capital stock redemption
 
—

 
1,750

 
(2,033
)
 
(283
)
Preferred stock dividends
 
—

 
—

 
(5,270
)
 
(5,270
)
Balance at December 31, 2016
 

$470

 

$790,243

 

$1,462,604

 

$2,253,317

Net income
 
—

 
—

 
139,844

 
139,844

Common stock dividends
 
—

 
—

 
(15,000
)
 
(15,000
)
Preferred stock dividends
 
—

 
—

 
(1,428
)
 
(1,428
)
Other
 
—

 
21

 
—

 
21

Balance at December 31, 2017
 

$470

 

$790,264

 

$1,586,020

 

$2,376,754

 
 
 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 

 
 



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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 

$2,139,919

 

$2,086,608

 

$2,253,564

 

$2,172,391

 

$2,190,159

Net income
 

$139,844

 

$167,212

 

$74,272

 

$121,392

 

$161,948

Total assets
 

$10,134,029

 

$9,606,117

 

$8,747,774

 

$8,777,655

 

$8,007,707

Long-term obligations (a)
 

$2,983,749

 

$2,746,435

 

$2,691,189

 

$2,757,423

 

$2,424,969

 
 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund.
 
 
 
 
 
 
 
 
 
 
 
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
 
Electric Operating Revenues:
 
 

 
 

 
 

 
 

 
 

Residential
 

$768

 

$789

 

$824

 

$755

 

$772

Commercial
 
495

 
495

 
515

 
461

 
469

Industrial
 
472

 
446

 
477

 
424

 
433

Governmental
 
19

 
18

 
20

 
18

 
19

Total retail
 
1,754

 
1,748

 
1,836

 
1,658

 
1,693

Sales for resale:
 
 

 
 

 
 

 
 

 
 

Associated companies
 
128

 
49

 
128

 
131

 
346

Non-associated companies
 
121

 
118

 
195

 
282

 
83

Other
 
137

 
172

 
95

 
101

 
68

Total
 

$2,140

 

$2,087

 

$2,254

 

$2,172

 

$2,190

 
 
 
 
 
 
 
 
 
 
 
Billed Electric Energy Sales (GWh):
 
 
 
 

 
 

 
 

 
 

Residential
 
7,298

 
7,618

 
8,016

 
8,070

 
7,921

Commercial
 
5,825

 
5,988

 
6,020

 
5,934

 
5,929

Industrial
 
7,528

 
6,795

 
6,889

 
6,808

 
6,769

Governmental
 
237

 
237

 
235

 
238

 
241

Total retail
 
20,888

 
20,638

 
21,160

 
21,050

 
20,860

Sales for resale:
 
 

 
 

 
 

 
 

 
 

Associated companies
 
1,782

 
1,609

 
2,239

 
2,299

 
7,918

Non-associated companies
 
6,549

 
7,115

 
7,980

 
8,003

 
1,011

Total
 
29,219

 
29,362

 
31,379

 
31,352

 
29,789



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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

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.

2016 Compared to 2015

Net income increased $175.4 million primarily due to 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 increase were lower other operation and maintenance expenses, higher net revenue, and higher other income. The increase was partially offset by higher depreciation and amortization expenses, higher interest expense, and higher nuclear refueling outage expenses. See Note 3 to the financial statements for discussion of the IRS audit.

Net Revenue

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.


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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.

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.

2016 Compared to 2015

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 2016 to 2015.
 
Amount
 
(In Millions)
 
 
2015 net revenue

$2,408.8

Retail electric price
62.5

Volume/weather
(6.7
)
Louisiana Act 55 financing savings obligation
(17.2
)
Other
(9.0
)
2016 net revenue

$2,438.4


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. See Note 2 to the financial statements for further discussion.

The volume/weather variance is primarily due to the effect of less favorable weather on residential sales, partially offset by an increase in industrial usage and an increase in volume during the unbilled period. The increase in industrial usage is primarily due to increased demand from new customers and expansion projects, primarily in the chemicals industry.

The Louisiana Act 55 financing savings obligation variance results from a regulatory charge 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.

Included in Other is a provision of $23 million recorded in 2016 related to the settlement of the Waterford 3 replacement steam generator prudence review proceeding, offset by a provision of $32 million recorded in 2015 related to the uncertainty at that time associated with the resolution of the Waterford 3 replacement steam generator prudence

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review proceeding.  See Note 2 to the financial statements for a discussion of the Waterford 3 replacement steam generator prudence review proceeding.

Other Income Statement Variances

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;
•
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 for 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.

2016 Compared to 2015

Nuclear refueling outage expenses increased primarily due to the amortization of higher expenses associated with the refueling outages at Waterford 3.
    
Other operation and maintenance expenses decreased primarily due to:

•
the $45 million write-off recorded in 2015 to recognize the portion of the assets associated with the Waterford 3 replacement steam generator project no longer probable of recovery. See Note 2 to the financial statements for further discussion of the prudence review proceeding; and

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•
a decrease of $35 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement costs as a result of higher discount rates used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.

The decrease was partially offset by an increase of $19.9 million in nuclear generation expenses primarily due to higher nuclear labor costs, including contract labor.

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.

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 2016, which included the St. Charles Power Station project, and increased distribution and transmission spending. The increase was also due to higher income in 2016 on the River Bend and Waterford 3 decommissioning trust fund investments.

Interest expense increased primarily due to:

•
the issuance in March 2016 of $425 million of 3.25% Series collateral trust mortgage bonds;
•
the issuance in March 2016 of $200 million of 4.95% Series first mortgage bonds; and
•
the issuance in October 2016 of $400 million of 2.40% Series collateral trust mortgage bonds.

The increase was partially offset by the refinancing at lower interest rates of certain first mortgage bonds. See Note 5 to the financial statements for details of long-term debt.

Income Taxes

The effective income tax rates for 2017, 2016, and 2015 were 60.5%, 12.6%, and 28.6%, respectively. The difference in the effective income tax rate of 60.5% for 2017 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 further discussion of the effects of the Tax Cuts and Jobs Act. The difference in the effective income tax rate of 12.6% for 2016 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 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 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 proceedings commenced or other responses by Entergy’s regulators to the Act.


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Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2017, 2016, and 2015 were as follows:
 
2017
 
2016
 
2015
 
(In Thousands)
Cash and cash equivalents at beginning of period

$213,850

 

$35,102

 

$320,516

 
 
 
 
 
 
Net cash provided by (used in):
 
 
 

 
 

Operating activities
1,337,545

 
1,037,912

 
1,155,516

Investing activities
(1,787,409
)
 
(1,474,065
)
 
(994,208
)
Financing activities
271,921

 
614,901

 
(446,722
)
Net increase (decrease) in cash and cash equivalents
(177,943
)
 
178,748

 
(285,414
)
 
 
 
 
 
 
Cash and cash equivalents at end of period

$35,907

 

$213,850

 

$35,102


Operating Activities

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 audits;
•
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.

Net cash flow provided by operating activities decreased $117.6 million in 2016 primarily due to:

•
an increase of $67.5 million in income tax payments in 2016. Entergy Louisiana had income tax payments in 2016 and 2015 in accordance with intercompany income tax allocation agreements. 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. The 2015 income tax payments resulted primarily from adjustments

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associated with the settlement of the 2008-2009 IRS audit. See Note 3 to the financial statements for a discussion of the income tax audits;
•
an increase of $80.7 million in interest paid resulting from an increase in interest expense, including a 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 the purchase of a beneficial interest in the Waterford 3 leased assets;
•
the timing of collections from customers and payments to vendors; and
•
a decrease due to the timing of recovery of fuel and purchased power costs in 2016.

The decrease was partially offset by proceeds of $37.8 million received in 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed and a decrease of $30.5 million in spending on nuclear refueling outages in 2016. 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 $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;
•
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. 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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Net cash flow used in investing activities increased $479.9 million in 2016 primarily due to:

•
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;
•
an increase of $130.7 million in fossil-fueled generation construction expenditures primarily due to spending on the St. Charles Power Station project in 2016;
•
cash proceeds of $59.6 million received in 2015 from the transfer of Algiers assets to Entergy New Orleans in September 2015. See “State and Local Rate Regulation and Fuel-Cost Recovery - Retail Rates - Electric - Filings with the City Council” below for further discussion of the transfer;
•
an increase of $52 million in transmission construction expenditures due to a higher scope of work performed in 2016; and
•
an increase of $20.5 million due to various information technology projects and upgrades in 2016.

The increase was partially offset by:

•
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;
•
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; and
•
a decrease of $16.9 million in nuclear construction expenditures primarily due to decreased spending on compliance with NRC post-Fukushima requirements.

Financing Activities

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:

•
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.

Entergy Louisiana’s financing activities provided $614.9 million of cash in 2016 compared to using $446.7 million in 2015 primarily due to the following activity:

•
the net issuance of $961.2 million of long-term debt in 2016 compared to the net retirement of $103.4 million of long-term debt in 2015;
•
the redemption in September 2015 of $100 million of 6.95% Series and $10 million of 8.25% Series preferred membership interests in connection with the Entergy Louisiana and Entergy Gulf States Louisiana business combination;
•
net repayments of borrowings of $56.6 million on the nuclear fuel company variable interest entity’s credit facility in 2016 compared to net borrowings of $14.3 million in 2015; and
•
an increase of $59.5 million in common equity distributions in 2016. Equity distributions were lower in 2015 in anticipation of the purchase of Power Blocks 3 and 4 of the Union Power Station.
            
See Note 5 to the financial statements for details of long-term debt.


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Capital Structure

Entergy Louisiana’s capitalization is balanced between equity and debt, as shown in the following table.
 
December 31,
2017
 
December 31,
2016
Debt to capital
53.8
%
 
53.4
%
Effect of excluding securitization bonds
(0.3
%)
 
(0.5
%)
Debt to capital, excluding securitization bonds (a)
53.5
%
 
52.9
%
Effect of subtracting cash
(0.1
%)
 
(0.9
%)
Net debt to net capital, excluding securitization bonds (a)
53.4
%
 
52.0
%

(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 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 Louisiana may issue incremental debt or reduce dividends, 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 dividends, 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.
 
2018
 
2019
 
2020
 
(In Millions)
Planned construction and capital investment:
 
 
 
 
 
Generation

$875

 

$530

 

$330

Transmission
465

 
350

 
285

Distribution
325

 
395

 
365

Utility Support
165

 
110

 
135

Total

$1,830

 

$1,385

 

$1,115


Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2018
 
2019-2020
 
2021-2022
 
After 2022
 
Total
 
(In Millions)
Long-term debt (a)

$940

 

$903

 

$843

 

$6,785

 

$9,471

Operating leases

$22

 

$41

 

$24

 

$19

 

$106

Purchase obligations (b)

$633

 

$1,420

 

$1,366

 

$7,125

 

$10,544


(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 $71.9 million to its qualified pension plans and approximately $19 million to its other postretirement health care and life insurance plans in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018. 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 $926.6 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 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; 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 effects of regulatory constraints and requirements,

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environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.

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 estimated 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 a purchase and sale agreement with a subsidiary of Calpine Corporation for the acquisition 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 in 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. A procedural schedule has been established, with the deadlines recently extended and the hearing continued from March 2018 until June 2018 in order to allow the parties an opportunity to reach settlement.

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 meters, the three-year deployment of which is expected to begin in 2019. The communications network deployment

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is expected to begin by late-2018, after the necessary information technology infrastructure is in place. 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; 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. Preferred membership interest and 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.
2017
 
2016
 
2015
 
2014
(In Thousands)
$11,173
 
$22,503
 
$6,154
 
$2,815

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 August 2022. The credit facility allows Entergy Louisiana to issue letters of credit against $15 million of the borrowing capacity of the facility. As of December 31, 2017, there were no cash borrowings and a $9.1 million letter 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, 2017, a $29.7 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, one in the amount of $105 million and one in the amount of $85 million, both scheduled to expire in May 2019. As of December 31, 2017, $65.7 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, 2017, $43.5 million in letters of credit to support a like amount of commercial paper issued and $36.4 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 October 2019 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
•
long-term 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

2014 Formula Rate Plan Filing

In connection with the approval of the business combination of Entergy Gulf States Louisiana and Entergy Louisiana, the LPSC authorized the filing of a single, joint, formula rate plan evaluation report for Entergy Gulf States Louisiana’s and Entergy Louisiana’s 2014 calendar year operations. The joint evaluation report was filed in September 2015 and reflected an earned return on common equity of 9.09%. As such, no adjustment to base formula rate plan revenue was required. The following adjustments were required under the formula rate plan, however: a decrease in the additional capacity mechanism for Entergy Louisiana of $17.8 million; an increase in the additional capacity mechanism for Entergy Gulf States Louisiana of $4.3 million; and a reduction of $5.5 million to the MISO cost recovery mechanism to collect approximately $35.7 million on a combined-company basis. Under the order approving the business combination, following completion of the prescribed review period, rates were implemented with the first billing cycle of December 2015, subject to refund. In June 2017 the LPSC staff and Entergy Louisiana filed an unopposed joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of this proceeding with no changes to rates already implemented.

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.

Extension of MISO Cost Recovery Mechanism Rider

In November 2016, Entergy Louisiana filed with the LPSC a request to extend the MISO cost recovery mechanism rider provision of its formula rate plan. In March 2017 the LPSC staff submitted direct testimony generally supportive of a one-year extension of the MISO cost recovery mechanism and the intervenor in the proceeding did not

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oppose an extension for this period of time. In July 2017 an uncontested joint stipulation authorizing a one-year extension of the MISO cost recovery mechanism rider was approved.

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 the present level of $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.

Formula Rate Plan Extension Request

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.  Entergy Louisiana requested that the LPSC consider its request on an expedited basis, in an effort to maintain Entergy Louisiana’s current cycle for implementing rate adjustments, i.e., September 2018, without the need for filing a full base rate case proceeding. Several parties have intervened in the proceeding and all parties have been participating in settlement discussions.

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. At the hearing the parties maintained the positions reflected in pre-filed testimony. 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

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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.

Ninemile 6

In July 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed an unopposed stipulation with the LPSC, which was subsequently approved, that estimated a first year revenue requirement associated with Ninemile 6 and provided a mechanism to update the revenue requirement as the in-service date approached. In late-December 2014, roughly contemporaneous with the unit's placement in service, a final updated estimated revenue requirement of $26.8 million for Entergy Gulf States Louisiana and $51.1 million for Entergy Louisiana was filed. The December 2014 estimate formed the basis of rates implemented effective with the first billing cycle of January 2015. In July 2015, Entergy Louisiana submitted to the LPSC a compliance filing including an estimate at completion, inclusive of interconnection costs and transmission upgrades, of approximately $648 million, or $76 million less than originally estimated, along with other project details and supporting evidence, to enable the LPSC to review the prudence of Entergy Louisiana’s management of the project. Testimony filed by the LPSC staff generally supported the prudence of the management of the project and recovery of the costs incurred to complete the project. The LPSC staff had questioned the warranty coverage for one element of the project. In October 2016 all parties agreed to a stipulation providing that 100% of Ninemile 6 construction costs was prudently incurred and is eligible for recovery from customers, but reserving the LPSC’s rights to review the prudence of Entergy Louisiana’s actions regarding one element of the project. This stipulation was approved by the LPSC in January 2017.

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 $474 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.


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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 have requested further proceedings on the prudence of the decision to deactivate Willow Glen 2 and 4.  No party contests the prudence of the decision to deactivate Willow Glen 2 and 4 or suggests reactivation of these units; however, issues have been 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. An evidentiary hearing was held in August 2017 and post-hearing briefs were submitted in October 2017. A decision is expected in 2018.

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.

2014 Rate Stabilization Plan Filing

In January 2015, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2014.  The filing showed an earned return on common equity of 7.20%, which resulted in a $706 thousand rate increase.  In April 2015 the LPSC issued findings recommending two adjustments to Entergy Gulf States Louisiana’s as-filed results, and an additional recommendation that did not affect the results. The LPSC staff’s recommended adjustments increase the earned return on equity for the test year to 7.24%. Entergy Gulf States Louisiana accepted the LPSC staff’s recommendations and a revenue increase of $688 thousand was implemented with the first billing cycle of May 2015.

2015 Rate Stabilization Plan Filing

In January 2016, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2015. The filing showed an earned return on common equity of 10.22%, which is within the authorized bandwidth, therefore requiring no change in rates. In March 2016 the LPSC staff issued its report stating that the 2015 gas rate stabilization plan filing was in compliance with the exception of several issues that required additional information, explanation, or clarification for which the LPSC staff had reserved the right to further review. In July 2016 the parties to the proceeding filed an unopposed joint report and motion for entry of order accepting the report that indicated no outstanding issues remained in the filing.


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In February 2016, Entergy Louisiana filed a motion requesting to extend the term of the gas rate stabilization plan in substantially similar form for an additional three-year term and included a request for sharing of non-jurisdictional compressed natural gas revenues. Following discovery and the filing of testimony by the LPSC staff, Entergy Louisiana and the LPSC submitted a joint motion for hearing an uncontested stipulated settlement resolving the proceeding. A hearing on the stipulation was held in November 2016. The ALJ issued a report of proceedings that was presented with the parties’ stipulation to the LPSC for consideration. The stipulation approving Entergy Louisiana’s requested extension of the rate stabilization plan was approved by the LPSC in December 2016.

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%. As part of the original filing, pursuant to the extraordinary cost provision of the rate stabilization plan, Entergy Louisiana sought to recover approximately $1.5 million in deferred operation and maintenance expenses incurred to restore service and repair damage resulting from flooding and widespread rainfall in southeast Louisiana that occurred in August 2016. Entergy Louisiana requested to recover the prudently incurred August 2016 storm restoration costs over ten years, outside of the rate stabilization plan sharing provisions. As a result, Entergy Louisiana’s filing sought an annual increase in revenue of $1.4 million. Following review of the filing, except for the proposed extraordinary cost recovery, the LPSC staff confirmed Entergy Louisiana’s filing was consistent with the principles and requirements of the rate stabilization plan. The extraordinary cost recovery request associated with the 2016 flood-related deferred operation and maintenance expenses incurred for gas operations was removed from the rate stabilization plan pending LPSC consideration in a separate docket. 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.

In connection with the joint report of proceedings accepted by the LPSC, in May 2017, Entergy Louisiana filed an application to initiate a separate proceeding to recover through the extraordinary cost provision of the gas rate stabilization plan the deferred operation and maintenance expenses of $1.4 million incurred to restore service and repair damage resulting from flooding and widespread rainfall in southeast Louisiana that occurred in August 2016. The LPSC staff submitted its direct testimony in the proceeding recommending recovery of $0.9 million. Entergy Louisiana filed rebuttal testimony responding to the LPSC staff’s recommendation. The procedural schedule was suspended to allow the parties to engage in settlement negotiations, and in February 2018 the LPSC staff and Entergy Louisiana filed an unopposed settlement. If approved by the LPSC, the settlement would provide for Entergy Louisiana to recover, over ten years, the approximately $1.4 million in deferred operation and maintenance expense and related carrying charges. The settlement further provides for recovery to commence in May 2018.

2017 Rate Stabilization Plan Filing

In January 2018, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for 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.  As a result, Entergy Louisiana will file a supplement to the January 2018 evaluation report to reflect, among other things, a 21% federal corporate income tax rate.  Any rate change resulting from the revised rate stabilization plan will become effective in rates in May 2018.

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

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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 April 2010 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings.  The audit included a review of the reasonableness of charges flowed through the fuel adjustment clause by Entergy Louisiana for the period from 2005 through 2009.  The LPSC staff issued its audit report in January 2013.  The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1 million from Entergy Louisiana’s fuel adjustment clause to base rates.  The recommended refund was made by Entergy Louisiana in May 2013 in the form of a credit to customers through its fuel adjustment clause filing. In October 2016 the LPSC staff filed testimony affirming the recommendation in its audit report on the lone remaining issue that nuclear dry fuel storage costs should be realigned to base rates. The parties agreed to remove that remaining issue to a separate docket because the same issue was outstanding in the Entergy Gulf States Louisiana audit for the same time period. In November 2016 the LPSC approved the resolution of this audit and the creation of a new docket for the resolution of the proper method of recovery for nuclear dry fuel storage costs. In December 2016 the LPSC opened a new docket in order to resolve the issue regarding the proper methodology for the recovery of nuclear dry fuel storage costs. In October 2017 the LPSC approved the continued recovery of the nuclear dry fuel storage costs through the fuel adjustment clause, resolving the open issue in the audit.

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 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 Entergy Gulf States Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery commenced in July 2015. No report of audit has been issued.

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. Discovery commenced in July 2015. No report of audit has been issued.

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.

Due to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs, Entergy Louisiana plans to cap the

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average fuel adjustment charge to be billed in March 2018 at $0.03060 per kWh and to defer billing of all fuel costs in excess of the capped amounts by including such costs in the over- or under-recovery account.

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.
        
Waterford 3’s operating license is currently due to expire in December 2024.  In March 2016, Entergy Louisiana filed an application with the NRC for an extension of Waterford 3’s operating license to 2044. River Bend’s operating license is currently due to expire in August 2025. In May 2017, Entergy Louisiana filed an application with the NRC for an extension of River Bend’s operating license to 2045. In October 2017 an intervenor filed with the NRC a petition to intervene and request for a hearing on the River Bend license renewal application. As provided by NRC procedure, a panel of the Atomic Safety and Licensing Board has been designated to determine whether the intervenor’s three proposed contentions, or allegations of errors or omissions in the license renewal application, are admissible and, if so, to rule on any admitted contentions. In January 2018 the Atomic Safety and Licensing Board denied the petition to intervene and the request for hearing.
  
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

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Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis


“Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

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

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.

Unbilled Revenue

See “Unbilled Revenue” 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 unbilled revenue amounts.

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.
 

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Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis


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 2018 Qualified Pension Cost
 
Impact on 2017 Projected Qualified Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$3,737
 
$54,506
Rate of return on plan assets
 
(0.25%)
 
$3,309
 
$—
Rate of increase in compensation
 
0.25%
 
$1,726
 
$8,824

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 2018 Postretirement Benefit Cost
 
Impact on 2017 Accumulated postretirement Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$753
 
$10,727
Health care cost trend
 
0.25%
 
$1,219
 
$8,675

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 2017 was $44.3 million.  Entergy Louisiana anticipates 2018 qualified pension cost to be $52.1 million.   In 2016, Entergy Louisiana refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $14.2 million.  Entergy Louisiana contributed $87.5 million to its pension plans in 2017 and estimates pension contributions will be approximately $71.9 million in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018.

Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 2017 were $12.6 million.  Entergy Louisiana expects 2018 postretirement health care and life insurance benefit costs of approximately $11.2 million.  In 2016, Entergy Louisiana refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $3.5 million. Entergy Louisiana contributed $14.4 million to its other postretirement plans in 2017 and estimates that 2018 contributions will be approximately $19 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.


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Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis


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, 2017 and 2016, the related consolidated statements of income, comprehensive income, cash flows, and changes in equity (pages 349 through 354 and applicable items in pages 55 through 230), for each of the three years in the period ended December 31, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2018


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

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Table of Contents

ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS
 
 
 
 
 
For the Years Ended December 31,
 
 
2017
 
2016
 
2015
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$4,246,020

 

$4,126,343

 

$4,361,524

Natural gas
 
54,530

 
50,705

 
55,622

TOTAL
 
4,300,550

 
4,177,048

 
4,417,146

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
912,060

 
804,433

 
850,869

Purchased power
 
980,070

 
890,058

 
1,129,910

Nuclear refueling outage expenses
 
52,074

 
51,361

 
44,480

Other operation and maintenance
 
969,400

 
923,779

 
997,546

Decommissioning
 
49,457

 
46,944

 
43,445

Taxes other than income taxes
 
175,359

 
165,665

 
167,966

Depreciation and amortization
 
467,369

 
451,290

 
437,036

Other regulatory charges (credits) - net
 
(152,080
)
 
44,131

 
27,562

TOTAL
 
3,453,709

 
3,377,661

 
3,698,814

 
 
 
 
 
 
 
OPERATING INCOME
 
846,841

 
799,387

 
718,332

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
51,485

 
27,925

 
19,192

Interest and investment income
 
164,550

 
154,778

 
150,168

Miscellaneous - net
 
(11,960
)
 
(11,597
)
 
(13,190
)
TOTAL
 
204,075

 
171,106

 
156,170

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
275,185

 
273,283

 
259,894

Allowance for borrowed funds used during construction
 
(25,914
)
 
(14,571
)
 
(10,702
)
TOTAL
 
249,271

 
258,712

 
249,192

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
801,645

 
711,781

 
625,310

 
 
 
 
 
 
 
Income taxes
 
485,298

 
89,734

 
178,671

 
 
 
 
 
 
 
NET INCOME
 
316,347

 
622,047

 
446,639

 
 
 
 
 
 
 
Preferred distribution requirements and other
 
—

 
—

 
5,737

 
 
 
 
 
 
 
EARNINGS APPLICABLE TO COMMON EQUITY
 

$316,347

 

$622,047

 

$440,902

 
 
 
 
 
 
 
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,
 
 
2017
 
2016
 
2015
 
 
(In Thousands)
 
 
 
 
 
 
 
Net Income
 

$316,347

 

$622,047

 

$446,639

 
 
 
 
 
 
 
Other comprehensive income
 
 

 
 

 
 

Pension and other postretirement liabilities
 
 

 
 

 
 

(net of tax expense of $234, $5,034, and $14,316)
 
2,042

 
7,970

 
22,811

Other comprehensive income
 
2,042

 
7,970

 
22,811

 
 
 
 
 
 
 
Comprehensive Income
 

$318,389

 

$630,017

 

$469,450

 
 
 
 
 
 
 
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,
 
 
2017
 
2016
 
2015
 
 
(In Thousands)
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$316,347

 

$622,047

 

$446,639

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 
621,018

 
620,211

 
593,635

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
575,804

 
178,549

 
97,461

Changes in working capital:
 
 

 
 

 
 

Receivables
 
(53,829
)
 
(102,200
)
 
(12,795
)
Fuel inventory
 
11,010

 
(2,693
)
 
(887
)
Accounts payable
 
58,880

 
(36,720
)
 
23,641

Prepaid taxes and taxes accrued
 
128,261

 
(235,246
)
 
105,687

Interest accrued
 
(70
)
 
1,218

 
2,933

Deferred fuel costs
 
23,236

 
(17,023
)
 
4,222

Other working capital accounts
 
(30,911
)
 
6,462

 
(41,890
)
Changes in provisions for estimated losses
 
(8,324
)
 
490

 
(8,946
)
Changes in other regulatory assets
 
492,696

 
57,579

 
130,762

Changes in other regulatory liabilities
 
605,453

 
62,351

 
96,234

Deferred tax rate change recognized as regulatory liability/asset
 
(1,207,808
)
 
—

 
—

Changes in pension and other postretirement liabilities
 
(32,309
)
 
(52,559
)
 
(98,695
)
Other
 
(161,909
)
 
(64,554
)
 
(182,485
)
Net cash flow provided by operating activities
 
1,337,545

 
1,037,912

 
1,155,516

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(1,662,835
)
 
(1,030,416
)
 
(845,227
)
Allowance for equity funds used during construction
 
51,485

 
27,925

 
19,192

Insurance proceeds
 
5,305

 
10,564

 
—

Nuclear fuel purchases
 
(197,829
)
 
(73,618
)
 
(244,040
)
Proceeds from the sale of nuclear fuel
 
42,634

 
63,304

 
54,595

Payment for purchase of plant
 
—

 
(474,670
)
 
—

Payments to storm reserve escrow account
 
(2,110
)
 
(1,063
)
 
(308
)
Receipts from storm reserve escrow account
 
8,835

 
—

 
—

Changes in securitization account
 
880

 
351

 
(137
)
Proceeds from nuclear decommissioning trust fund sales
 
231,293

 
219,182

 
123,474

Investment in nuclear decommissioning trust funds
 
(266,592
)
 
(257,209
)
 
(158,028
)
Changes in money pool receivable - net
 
11,330

 
(16,349
)
 
(3,339
)
Proceeds from sale of assets
 
—

 
—

 
59,610

Payment for purchase of assets
 
(9,805
)
 
—

 
—

Litigation proceeds for reimbursement of spent nuclear fuel storage costs
 
—

 
57,934

 
—

Net cash flow used in investing activities
 
(1,787,409
)
 
(1,474,065
)
 
(994,208
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
733,344

 
2,450,063

 
77,172

Retirement of long-term debt
 
(407,736
)
 
(1,488,870
)
 
(180,595
)
Redemption of preferred membership interests
 
—

 
—

 
(110,286
)
Changes in credit borrowings - net
 
39,746

 
(56,562
)
 
14,322

Distributions paid:
 
 

 
 

 
 

Common equity
 
(91,250
)
 
(285,500
)
 
(226,000
)
Preferred membership interests
 
—

 
—

 
(6,082
)
Other
 
(2,183
)
 
(4,230
)
 
(15,253
)
Net cash flow provided by (used in) financing activities
 
271,921

 
614,901

 
(446,722
)
Net increase (decrease) in cash and cash equivalents
 
(177,943
)
 
178,748

 
(285,414
)
Cash and cash equivalents at beginning of period
 
213,850

 
35,102

 
320,516

Cash and cash equivalents at end of period
 

$35,907

 

$213,850

 

$35,102

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 

 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$266,871

 

$324,456

 

$243,745

Income taxes
 

($234,199
)
 

$156,605

 

$89,124

Non-cash financing activities:
 
 
 
 
 
 
Capital contribution from parent
 

$—

 

$—

 

($267,826
)
See Notes to Financial Statements.
 
 

 
 

 
 


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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$5,836

 

$49,972

Temporary cash investments
 
30,071

 
163,878

Total cash and cash equivalents
 
35,907

 
213,850

Accounts receivable:
 
 

 
 

Customer
 
254,308

 
213,517

Allowance for doubtful accounts
 
(8,430
)
 
(6,277
)
Associated companies
 
143,524

 
155,794

Other
 
60,893

 
54,186

Accrued unbilled revenues
 
153,118

 
159,176

Total accounts receivable
 
603,413

 
576,396

Fuel inventory
 
39,728

 
50,738

Materials and supplies - at average cost
 
299,881

 
294,421

Deferred nuclear refueling outage costs
 
65,711

 
22,535

Prepaid taxes
 
—

 
110,104

Prepayments and other
 
34,035

 
41,687

TOTAL
 
1,078,675

 
1,309,731

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Investment in affiliate preferred membership interests
 
1,390,587

 
1,390,587

Decommissioning trust funds
 
1,312,073

 
1,140,707

Storm reserve escrow account
 
284,759

 
291,485

Non-utility property - at cost (less accumulated depreciation)
 
245,255

 
217,494

Other
 
18,999

 
28,844

TOTAL
 
3,251,673

 
3,069,117

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
19,678,536

 
18,827,532

Natural gas
 
191,899

 
172,816

Construction work in progress
 
1,281,452

 
670,201

Nuclear fuel
 
337,402

 
249,807

TOTAL UTILITY PLANT
 
21,489,289

 
19,920,356

Less - accumulated depreciation and amortization
 
8,703,047

 
8,420,596

UTILITY PLANT - NET
 
12,786,242

 
11,499,760

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Regulatory asset for income taxes - net
 
—

 
470,480

Other regulatory assets (includes securitization property of $71,367 as of December 31, 2017 and $92,951 as of December 31, 2016)
 
1,145,842

 
1,168,058

Deferred fuel costs
 
168,122

 
168,122

Other
 
18,310

 
16,003

TOTAL
 
1,332,274

 
1,822,663

 
 
 
 
 
TOTAL ASSETS
 

$18,448,864

 

$17,701,271

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Currently maturing long-term debt
 

$675,002

 

$200,198

Short-term borrowings
 
43,540

 
3,794

Accounts payable:
 
 

 
 

Associated companies
 
126,685

 
82,106

Other
 
404,374

 
358,741

Customer deposits
 
150,623

 
148,601

Taxes accrued
 
18,157

 
—

Interest accrued
 
75,528

 
75,598

Deferred fuel costs
 
71,447

 
48,211

Other
 
79,037

 
80,013

TOTAL
 
1,644,393

 
997,262

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
2,050,371

 
2,691,118

Accumulated deferred investment tax credits
 
121,870

 
126,741

Regulatory liability for income taxes - net
 
725,368

 
—

Other regulatory liabilities
 
761,059

 
880,974

Decommissioning
 
1,140,461

 
1,082,685

Accumulated provisions
 
302,448

 
310,772

Pension and other postretirement liabilities
 
748,384

 
780,278

Long-term debt (includes securitization bonds of $77,736 as of December 31, 2017 and $99,217 as of December 31, 2016)
 
5,469,069

 
5,612,593

Other
 
176,637

 
137,039

TOTAL
 
11,495,667

 
11,622,200

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
EQUITY
 
 

 
 

Member’s equity
 
5,355,204

 
5,130,251

Accumulated other comprehensive loss
 
(46,400
)
 
(48,442
)
TOTAL
 
5,308,804

 
5,081,809

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$18,448,864

 

$17,701,271

 
 
 
 
 
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, 2017, 2016, and 2015
 
 
 
 
 
 
 
 
 
Common Equity
 
 
 
Preferred Membership Interests
 
Member’s Equity
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
(In Thousands)
 
 
 
 
 
 
 
 
Balance at December 31, 2014

$110,000

 

$4,316,210

 

($79,223
)
 

$4,346,987

Net income
—

 
446,639

 
—

 
446,639

Other comprehensive income
—

 
—

 
22,811

 
22,811

Preferred stock redemption
(110,000
)
 
—

 
—

 
(110,000
)
Non-cash contribution from parent
—

 
267,826

 
—

 
267,826

Distributions to parent
—

 
(226,000
)
 
—

 
(226,000
)
Distributions declared on preferred membership interests
—

 
(5,737
)
 
—

 
(5,737
)
Other
—

 
(5,214
)
 
—

 
(5,214
)
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

 
 
 
 
 
 
 
 
See Notes to Financial Statements.
 

 
 

 
 

 
 



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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$4,300,550

 

$4,177,048

 

$4,417,146

 

$4,740,504

 

$4,399,511

Net income

$316,347

 

$622,047

 

$446,639

 

$446,022

 

$414,126

Total assets

$18,448,864

 

$17,701,271

 

$16,387,447

 

$16,423,825

 

$15,275,863

Long-term obligations (a)

$5,469,069

 

$5,612,593

 

$4,806,790

 

$4,882,813

 

$4,383,273

 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (excluding currently maturing debt).
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
Electric Operating Revenues:
 

 
 

 
 

 
 

 
 

Residential

$1,198

 

$1,196

 

$1,292

 

$1,358

 

$1,304

Commercial
956

 
930

 
989

 
1,044

 
1,003

Industrial
1,534

 
1,350

 
1,420

 
1,569

 
1,457

Governmental
69

 
67

 
67

 
70

 
68

Total retail
3,757

 
3,543

 
3,768

 
4,041

 
3,832

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
278

 
368

 
406

 
427

 
320

Non-associated companies
64

 
50

 
36

 
80

 
48

Other
147

 
165

 
152

 
121

 
140

Total

$4,246

 

$4,126

 

$4,362

 

$4,669

 

$4,340

 
 
 
 
 
 
 
 
 
 
Billed Electric Energy Sales (GWh):
 

 
 

 
 

 
 

 
 

Residential
13,357

 
13,810

 
14,399

 
14,415

 
14,026

Commercial
11,342

 
11,478

 
11,700

 
11,555

 
11,402

Industrial
29,754

 
28,517

 
27,713

 
27,025

 
25,734

Governmental
790

 
794

 
756

 
732

 
723

Total retail
55,243

 
54,599

 
54,568

 
53,727

 
51,885

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
4,793

 
7,345

 
7,500

 
6,240

 
5,168

Non-associated companies
1,711

 
1,690

 
770

 
1,051

 
979

Total
61,747

 
63,634

 
62,838

 
61,018

 
58,032

 
 
 
 
 
 
 
 
 
 


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ENTERGY MISSISSIPPI, INC.

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

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.

2016 Compared to 2015

Net income increased $16.5 million primarily due to lower other operation and maintenance expenses, higher net revenues, and a lower effective income tax rate, partially offset by higher depreciation and amortization expenses.

Net Revenue

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.
 
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 more discussion of the formula rate plan and the storm damage rider.


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2016 Compared to 2015

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 2016 to 2015.
 
Amount
 
(In Millions)
 
 
2015 net revenue

$696.3

Retail electric price
12.9

Volume/weather
4.7

Net wholesale revenue
(2.4
)
Reserve equalization
(2.8
)
Other
(3.3
)
2016 net revenue

$705.4


The retail electric price variance is primarily due to a $19.4 million net annual increase in revenues, as approved by the MPSC, effective with the first billing cycle of July 2016, and an increase in revenues collected through the storm damage rider.  See Note 2 to the financial statements for more discussion of the formula rate plan and the storm damage rider.

The volume/weather variance is primarily due to an increase of 153 GWh, or 1%, in billed electricity usage, including an increase in industrial usage, partially offset by the effect of less favorable weather on residential and commercial sales. The increase in industrial usage is primarily due to expansion projects in the pulp and paper industry, increased demand for existing customers, primarily in the metals industry, and new customers in the wood products industry.

The net wholesale revenue variance is primarily due to Entergy Mississippi’s exit from the System Agreement in November 2015.

The reserve equalization revenue variance is primarily due to the absence of reserve equalization revenue as compared to the same period in 2015 resulting from Entergy Mississippi’s exit from the System Agreement in November 2015.

Other Income Statement Variances

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 on 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.


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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.

2016 Compared to 2015

Other operation and maintenance expenses decreased primarily due to:

•
a decrease of $9.4 million in fossil-fueled generation expenses primarily due to a lower scope of work done during plant outages in 2016 as compared to the same period in 2015;
•
a decrease of $6.1 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;
•
a decrease of $2 million due to lower write-offs of uncollectible customer accounts in 2016;
•
a decrease of $2 million in energy efficiency costs; and
•
several individually insignificant items.

The decrease was partially offset by an increase of $7.1 million in storm damage provisions and an increase of $6 million in distribution expenses primarily due to higher vegetation maintenance. See Note 2 to the financial statements for a discussion of storm cost recovery.

Depreciation and amortization expenses increased primarily due to additions to plant in service.

Income Taxes

The effective income tax rates for 2017, 2016, and 2015 were 40.2%, 36.9%, and 40.0%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% 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 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 proceedings commenced or other responses by Entergy’s regulators to the Act.


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Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2017, 2016, and 2015 were as follows:
 
2017
 
2016
 
2015
 
(In Thousands)
Cash and cash equivalents at beginning of period

$76,834

 

$145,605

 

$61,633

 
 
 
 
 
 
Net cash provided by (used in):
 

 
 

 
 

Operating activities
226,585

 
212,280

 
372,279

Investing activities
(417,226
)
 
(289,444
)
 
(245,127
)
Financing activities
119,903

 
8,393

 
(43,180
)
Net increase (decrease) in cash and cash equivalents
(70,738
)
 
(68,771
)
 
83,972

 
 
 
 
 
 
Cash and cash equivalents at end of period

$6,096

 

$76,834

 

$145,605


Operating Activities

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.

Net cash flow provided by operating activities decreased $160 million in 2016 primarily due to the timing of recovery of fuel and purchased power costs in 2016 as compared to the same period in 2015 and $15.3 million in insurance proceeds received in 2015 related to the unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant in September 2013. The decrease was partially offset by income tax refunds of $12.5 million in 2016 compared to income tax payments of $61.3 million in 2015. Entergy Mississippi had income tax refunds in 2016 and income tax payments in 2015 in accordance with an intercompany income tax allocation agreement. The 2016 income tax refunds resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit whereas the income tax payments in 2015 were primarily due to the results of operations and the reversal of taxable temporary differences as well as final settlement of amounts outstanding associated with the 2006-2007 IRS audit. See Note 3 to the financial statements for a discussion of the income tax audits.

Investing Activities

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.


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Net cash flow used in investing activities increased $44.3 million in 2016 primarily due to:

•
an increase of $72.4 million in transmission construction expenditures primarily due to a higher scope of work performed in 2016 as compared to 2015;
•
insurance proceeds of $12.9 million received in 2015 related to the unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant in September 2013;
•
an increase of $11.4 million in distribution construction expenditures primarily due to a higher scope of non-storm related work performed in 2016 as compared to 2015; and     
•
an increase of $10.1 million due to various information technology projects and upgrades.

The increase was partially offset by a decrease of $20.1 million in fossil-fueled generation construction expenditures primarily due to a decreased scope of work performed during plant outages in 2016 as compared to 2015 and money pool activity.

Decreases in Entergy Mississippi’s receivable from the money pool are a source of cash flow, and Entergy Mississippi’s receivable from the money pool decreased by $15.3 million in 2016 compared to increasing by $25.3 million in 2015. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.

Financing Activities

Net cash flow provided by financing activities increased $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 6.25% Series preferred stock in 2016, partially offset by the net issuance of $61.4 million of long-term debt in 2016.

Entergy Mississippi’s financing activities provided $8.4 million of cash in 2016 compared to using $43.2 million in 2015 primarily due to the net issuance of $61.4 million of long-term debt in 2016 and a decrease of $16 million in common stock dividends paid in 2016, partially offset by the redemption of $30 million of 6.25% Series preferred stock. The decrease in dividends paid was primarily because of lower operating cash flows and higher capital expenditures, each discussed above.

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

Capital Structure

Entergy Mississippi’s capitalization is balanced between equity and debt, as shown in the following table. The increase in the debt to capital ratio for Entergy Mississippi is primarily due to the issuance of long-term debt in 2017.
  
 
December 31,
2017
 
December 31,
2016
Debt to capital
51.5
%
 
50.2
%
Effect of subtracting cash
(0.2
%)
 
(1.8
%)
Net debt to net capital
51.3
%
 
48.4
%

Net debt consists of debt less cash and cash equivalents.  Debt consists of short-term borrowings, capital lease obligations, 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

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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 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 Mississippi may issue incremental debt or reduce dividends, 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 dividends, 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 and preferred stock maturities or retirements;
•
working capital purposes, including the financing of fuel and purchased power costs; and
•
dividend and interest payments.
    
Following are the amounts of Entergy Mississippi’s planned construction and other capital investments.
 
2018
 
2019
 
2020
 
(In Millions)
Planned construction and capital investment:
 
 
 
 
 
Generation

$55

 

$45

 

$260

Transmission
145

 
100

 
105

Distribution
125

 
140

 
130

Utility Support
70

 
50

 
35

Total

$395

 

$335

 

$530


Following are the amounts of Entergy Mississippi’s existing debt obligations and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2018
 
2019-2020
 
2021-2022
 
After 2022
 
Total
 
(In Millions)
Long-term debt (a)

$50

 

$234

 

$80

 

$1,784

 

$2,148

Operating leases

$12

 

$19

 

$12

 

$6

 

$49

Purchase obligations (b)

$280

 

$519

 

$490

 

$5,304

 

$6,593


(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 $14.9 million to its qualified pension plans and approximately $110 thousand to other postretirement health care and life insurance plans in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018  See “Critical Accounting Estimates

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– Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
 
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Mississippi includes amounts associated with 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 investment to support advanced metering; resource planning, including potential generation projects; system improvements; 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, Entergy Mississippi dividends its earnings to Entergy Corporation at a percentage determined monthly.  Provisions in Entergy Mississippi’s articles of incorporation relating to preferred stock restrict the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock.

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, with deployment of the communications network expected to begin 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.

Sources of Capital

Entergy Mississippi’s sources to meet its capital requirements include:

•
internally generated funds;
•
cash on hand;
•
debt or preferred stock issuances; and
•
bank financing under new or existing facilities.


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Entergy Mississippi may refinance, redeem, or otherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common and preferred stock issuances by Entergy Mississippi require prior regulatory approval.  Preferred stock and debt issuances are also subject to issuance tests set forth in its corporate charter, 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.
2017
 
2016
 
2015
 
2014
(In Thousands)
$1,633
 
$10,595
 
$25,930
 
$644

See Note 4 to the financial statements for a description of the money pool.

Entergy Mississippi has four separate credit facilities in the aggregate amount of $102.5 million scheduled to expire May 2018. No borrowings were outstanding under the credit facilities as of December 31, 2017.  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, 2017, a $15.3 million letter of credit was 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 authorizations from the FERC through October 2019 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

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 includes 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 includes $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

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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.

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.

Entergy Mississippi had a deferred fuel over-recovery balance of $58.3 million as of May 31, 2015, along with an under-recovery balance of $12.3 million under the power management rider. Pursuant to those tariffs, in July 2015, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider to flow through to customers the approximately $46 million net over-recovery over a six-month period. In August 2015, the MPSC approved the interim adjustments effective with September 2015 bills. 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.

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.  The Mississippi attorney general moved to remand the matter to state court.  In August 2012 the District

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Court issued an opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.

The defendant Entergy companies answered the complaint and filed a counterclaim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act.  In May 2009 the defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdiction of the MPSC, and factual errors in the Attorney General’s complaint.  In September 2012 the District Court heard oral argument on Entergy’s motion for judgment on the pleadings.

In January 2014 the U.S. Supreme Court issued a decision in which it held that cases brought by attorneys general as the sole plaintiff to enforce state laws were not considered “mass actions” under the Class Action Fairness Act, so as to establish federal subject matter jurisdiction. One day later the Attorney General renewed his motion to remand the Entergy case back to state court, citing the U.S. Supreme Court’s decision. The defendant Entergy companies responded to that motion reiterating the additional grounds asserted for federal question jurisdiction, and the District Court held oral argument on the renewed motion to remand in February 2014. In April 2015 the District Court entered an order denying the renewed motion to remand, holding that the District Court has federal question subject matter jurisdiction. The Attorney General appealed to the U.S. Fifth Circuit Court of Appeals the denial of the motion to remand. In July 2015 the Fifth Circuit issued an order denying the appeal, and the Attorney General subsequently filed a petition for rehearing of the request for interlocutory appeal, which was also denied. In December 2015 the District Court ordered that the parties submit to the court undisputed and disputed facts that are material to the Entergy defendants’ motion for judgment on the pleadings, as well as supplemental briefs regarding the same. Those filings were made in January 2016.

In September 2016 the Attorney General filed a mandamus petition with the U.S. Fifth Circuit Court of Appeals in which the Attorney General asked the Fifth Circuit to order the chief judge to reassign this case to another judge. In September 2016 the District Court denied the Entergy companies’ motion for judgment on the pleadings. The Entergy companies filed a motion seeking to amend the District Court’s order denying the Entergy companies’ motion for judgment on the pleadings and allowing an interlocutory appeal. In October 2016 the Fifth Circuit granted the Attorney General’s motion for writ of mandamus and directed the chief judge to assign the case to a new judge. The case was reassigned in October 2016. In January 2017 the District Court denied the Entergy companies’ motion to amend the order denying the motion for judgment on the pleadings. In June 2017 the District Court issued a case management order setting a trial date in November 2018. Discovery is currently in progress.

Storm Damage Provision

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 again 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.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.



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Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis


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.

Unbilled Revenue

See “Unbilled Revenue” 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 unbilled revenue amounts.

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 Mississippi’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms.   See the “Qualified

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Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis

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 2018 Qualified Pension Cost
 
Impact on 2017 Projected Qualified Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$874
 

$13,479

Rate of return on plan assets
 
(0.25%)
 
$867
 

$—

Rate of increase in compensation
 
0.25%
 
$381
 

$1,848


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 2018 Postretirement Benefit Cost
 
Impact on 2017 Accumulated Postretirement Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$184
 
$2,561
Health care cost trend
 
0.25%
 
$296
 
$2,024

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 2017 was $8.5 million. Entergy Mississippi anticipates 2018 qualified pension cost to be $10.8 million. In 2016, Entergy Mississippi refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $3.8 million.  Entergy Mississippi contributed $19.1 million to its qualified pension plans in 2017 and estimates 2018 pension contributions will be approximately $14.9 million, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018.

Total postretirement health care and life insurance benefit income for Entergy Mississippi in 2017 was $1 million. Entergy Mississippi expects 2018 postretirement health care and life insurance benefit income of approximately $1.5 million. In 2016, Entergy Mississippi refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $770 thousand. In 2017, Entergy Mississippi’s contributions (that is, contributions to the external trusts plus claims payments) were offset by trust claims reimbursements, resulting in a net reimbursement of $2 thousand. Entergy Mississippi estimates that 2018 contributions will be approximately $110 thousand.


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Management’s Financial Discussion and Analysis


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 shareholders and Board of Directors of
Entergy Mississippi, Inc.

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Entergy Mississippi, Inc. (the “Company”) as of December 31, 2017 and 2016, the related statements of income, cash flows and changes in common equity (pages 370 through 374 and applicable items in pages 55 through 230), for each of the three years in the period ended December 31, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2018


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


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ENTERGY MISSISSIPPI, INC.
INCOME STATEMENTS
 
 
 
 
 
For the Years Ended December 31,
 
 
2017
 
2016
 
2015
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$1,198,229

 

$1,094,649

 

$1,396,985

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
185,816

 
95,090

 
291,666

Purchased power
 
328,463

 
297,902

 
389,950

Other operation and maintenance
 
243,480

 
250,443

 
261,255

Taxes other than income taxes
 
95,051

 
94,482

 
94,152

Depreciation and amortization
 
143,479

 
136,214

 
129,029

Other regulatory charges (credits) - net
 
(19,134
)
 
(3,721
)
 
19,027

TOTAL
 
977,155

 
870,410

 
1,185,079

 
 
 
 
 
 
 
OPERATING INCOME
 
221,074

 
224,239

 
211,906

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
9,667

 
5,801

 
3,095

Interest and investment income
 
85

 
656

 
195

Miscellaneous - net
 
510

 
(3,531
)
 
(4,418
)
TOTAL
 
10,262

 
2,926

 
(1,128
)
 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
51,260

 
57,114

 
57,842

Allowance for borrowed funds used during construction
 
(3,875
)
 
(2,987
)
 
(1,644
)
TOTAL
 
47,385

 
54,127

 
56,198

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
183,951

 
173,038

 
154,580

 
 
 
 
 
 
 
Income taxes
 
73,919

 
63,854

 
61,872

 
 
 
 
 
 
 
NET INCOME
 
110,032

 
109,184

 
92,708

 
 
 
 


 
 
Preferred dividend requirements and other
 
953

 
2,443

 
2,828

 
 
 
 
 
 
 
EARNINGS APPLICABLE TO COMMON STOCK
 

$109,079

 

$106,741

 

$89,880

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY MISSISSIPPI, INC.
STATEMENTS OF CASH FLOWS
 
 
 
 
 
For the Years Ended December 31,
 
 
2017
 
2016
 
2015
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$110,032

 

$109,184

 

$92,708

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation and amortization
 
143,479

 
136,214

 
129,029

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
84,816

 
60,986

 
18,673

Changes in assets and liabilities:
 
 

 
 

 
 

Receivables
 
(29,528
)
 
(28,819
)
 
50,199

Fuel inventory
 
5,266

 
401

 
(8,537
)
Accounts payable
 
3,595

 
33,733

 
(26,682
)
Taxes accrued
 
18,803

 
20,579

 
(10,104
)
Interest accrued
 
1,248

 
822

 
(2,341
)
Deferred fuel costs
 
(25,487
)
 
(114,711
)
 
105,560

Other working capital accounts
 
5,115

 
(5,222
)
 
(663
)
Provisions for estimated losses
 
(9,676
)
 
6,378

 
(2,080
)
Other regulatory assets
 
(17,412
)
 
(3,626
)
 
39,582

Other regulatory liabilities
 
405,395

 
(2,986
)
 
9,172

     Deferred tax rate change recognized as regulatory liability/asset
 
(452,429
)
 
—

 
—

Pension and other postretirement liabilities
 
(8,055
)
 
(10,648
)
 
(14,939
)
Other assets and liabilities
 
(8,577
)
 
9,995

 
(7,298
)
Net cash flow provided by operating activities
 
226,585

 
212,280

 
372,279

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(427,616
)
 
(310,356
)
 
(235,894
)
Allowance for equity funds used during construction
 
9,667

 
5,801

 
3,095

Insurance proceeds
 
—

 
—

 
12,932

Changes in money pool receivable - net
 
8,962

 
15,335

 
(25,286
)
Payment for purchase of assets
 
(6,958
)
 
—

 
—

Other
 
(1,281
)
 
(224
)
 
26

Net cash flow used in investing activities
 
(417,226
)
 
(289,444
)
 
(245,127
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
148,185

 
623,812

 
—

Retirement of long-term debt
 
—

 
(562,400
)
 
—

Redemption of preferred stock
 
—

 
(30,000
)
 
—

Dividends paid:
 
 

 
 

 
 

Common stock
 
(26,000
)
 
(24,000
)
 
(40,000
)
Preferred stock
 
(953
)
 
(2,755
)
 
(2,828
)
Other
 
(1,329
)
 
3,736

 
(352
)
Net cash flow provided by (used in) financing activities
 
119,903

 
8,393

 
(43,180
)
Net increase (decrease) in cash and cash equivalents
 
(70,738
)
 
(68,771
)
 
83,972

Cash and cash equivalents at beginning of period
 
76,834

 
145,605

 
61,633

Cash and cash equivalents at end of period
 

$6,096

 

$76,834

 

$145,605

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 
 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$47,631

 

$53,693

 

$57,576

Income taxes
 

($25,043
)
 

($12,487
)
 

$61,333

See Notes to Financial Statements.
 
 

 
 

 
 


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ENTERGY MISSISSIPPI, INC.
BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$1,607

 

$16

Temporary cash investments
 
4,489

 
76,818

Total cash and cash equivalents
 
6,096

 
76,834

Accounts receivable:
 
 

 
 

Customer
 
72,039

 
51,218

Allowance for doubtful accounts
 
(574
)
 
(549
)
Associated companies
 
45,081

 
45,973

Other
 
9,738

 
12,006

Accrued unbilled revenues
 
54,256

 
51,327

Total accounts receivable
 
180,540

 
159,975

Deferred fuel costs
 
32,444

 
6,957

Fuel inventory - at average cost
 
45,606

 
50,872

Materials and supplies - at average cost
 
42,571

 
41,146

Prepayments and other
 
7,041

 
8,873

TOTAL
 
314,298

 
344,657

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Non-utility property - at cost (less accumulated depreciation)
 
4,592

 
4,608

Escrow accounts
 
31,969

 
31,783

TOTAL
 
36,561

 
36,391

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
4,660,297

 
4,321,214

Property under capital lease
 
125

 
1,590

Construction work in progress
 
149,367

 
118,182

TOTAL UTILITY PLANT
 
4,809,789

 
4,440,986

Less - accumulated depreciation and amortization
 
1,681,306

 
1,602,711

UTILITY PLANT - NET
 
3,128,483

 
2,838,275

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Regulatory asset for income taxes - net
 
—

 
38,284

Other regulatory assets
 
397,909

 
342,213

Other
 
2,124

 
2,320

TOTAL
 
400,033

 
382,817

 
 
 
 
 
TOTAL ASSETS
 

$3,879,375

 

$3,602,140

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY MISSISSIPPI, INC.
BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Accounts payable:
 
 

 
 

Associated companies
 

$55,689

 

$43,647

Other
 
77,326

 
80,227

Customer deposits
 
83,654

 
84,112

Taxes accrued
 
82,843

 
64,040

Interest accrued
 
22,901

 
21,653

Other
 
12,785

 
9,554

TOTAL
 
335,198

 
303,233

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
488,806

 
861,331

Accumulated deferred investment tax credits
 
8,867

 
8,667

Regulatory liability for income taxes - net
 
411,011

 
—

Asset retirement cost liabilities
 
9,219

 
8,722

Accumulated provisions
 
44,764

 
54,440

Pension and other postretirement liabilities
 
101,498

 
109,551

Long-term debt
 
1,270,122

 
1,120,916

Other
 
11,639

 
20,108

TOTAL
 
2,345,926

 
2,183,735

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
Preferred stock without sinking fund
 
20,381

 
20,381

 
 
 
 
 
COMMON EQUITY
 
 

 
 

Common stock, no par value, authorized 12,000,000 shares; issued and outstanding 8,666,357 shares in 2017 and 2016
 
199,326

 
199,326

Capital stock expense and other
 
167

 
167

Retained earnings
 
978,377

 
895,298

TOTAL
 
1,177,870

 
1,094,791

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$3,879,375

 

$3,602,140

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 



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ENTERGY MISSISSIPPI, INC.
STATEMENTS OF CHANGES IN COMMON EQUITY
For the Years Ended December 31, 2017, 2016, and 2015
 
 
 
 
 
Common Equity
 
 
 
Common Stock
 
Capital Stock Expense and Other
 
Retained Earnings
 
Total
 
(In Thousands)
 
 
 
 
 
 
 
 
Balance at December 31, 2014

$199,326

 

($690
)
 

$763,534

 

$962,170

Net income
—

 
—

 
92,708

 
92,708

Common stock dividends
—

 
—

 
(40,000
)
 
(40,000
)
Preferred stock dividends
—

 
—

 
(2,828
)
 
(2,828
)
Balance at December 31, 2015

$199,326

 

($690
)
 

$813,414

 

$1,012,050

Net income
—

 
—

 
109,184

 
109,184

Common stock dividends
—

 
—

 
(24,000
)
 
(24,000
)
Preferred stock dividends
—

 
—

 
(2,443
)
 
(2,443
)
Preferred stock redemption
—

 
857

 
(857
)
 
—

Balance at December 31, 2016

$199,326

 

$167

 

$895,298

 

$1,094,791

Net income
—

 
—

 
110,032

 
110,032

Common stock dividends
—

 
—

 
(26,000
)
 
(26,000
)
Preferred stock dividends
—

 
—

 
(953
)
 
(953
)
Balance at December 31, 2017

$199,326

 

$167

 

$978,377

 

$1,177,870

 
 
 
 
 
 
 
 
See Notes to Financial Statements.
 

 
 

 
 

 
 



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ENTERGY MISSISSIPPI, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$1,198,229

 

$1,094,649

 

$1,396,985

 

$1,524,193

 

$1,334,540

Net income

$110,032

 

$109,184

 

$92,708

 

$74,821

 

$82,159

Total assets

$3,879,375

 

$3,602,140

 

$3,477,407

 

$3,358,625

 

$3,234,875

Long-term obligations (a)

$1,290,503

 

$1,141,924

 

$972,058

 

$1,097,182

 

$1,092,786

 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and preferred stock without sinking fund.
 
 
 
 
 
 
 
 
 
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
Electric Operating Revenues:
 

 
 

 
 

 
 

 
 

Residential

$502

 

$459

 

$565

 

$585

 

$527

Commercial
423

 
374

 
465

 
481

 
432

Industrial
159

 
134

 
164

 
175

 
156

Governmental
41

 
38

 
47

 
47

 
42

Total retail
1,125

 
1,005

 
1,241

 
1,288

 
1,157

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
—

 
1

 
75

 
153

 
92

Non-associated companies
18

 
30

 
10

 
14

 
24

Other
55

 
59

 
71

 
69

 
62

Total

$1,198

 

$1,095

 

$1,397

 

$1,524

 

$1,335

 
 
 
 
 
 
 
 
 
 
Billed Electric Energy Sales (GWh):
 
 
 

 
 

 
 

 
 

Residential
5,308

 
5,617

 
5,661

 
5,672

 
5,629

Commercial
4,783

 
4,894

 
4,913

 
4,821

 
4,815

Industrial
2,536

 
2,493

 
2,283

 
2,297

 
2,265

Governmental
421

 
439

 
433

 
414

 
409

Total retail
13,048

 
13,443

 
13,290

 
13,204

 
13,118

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
—

 
—

 
1,419

 
2,657

 
1,543

Non-associated companies
857

 
1,021

 
261

 
193

 
304

Total
13,905

 
14,464

 
14,970

 
16,054

 
14,965



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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

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. The restructuring was subject to regulatory review and approval by the City Council and the FERC. 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 anticipated 2018 base rate case. 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, pursuant to the agreement in principle, 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.

Results of Operations

Net Income

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.

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2016 Compared to 2015

Net income increased $3.9 million primarily due to higher net revenue, partially offset by higher depreciation and amortization expenses, higher interest expense, and lower other income.

Net Revenue

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 an increase 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.

2016 Compared to 2015

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 2016 to 2015.
 
Amount
 
(In Millions)
 
 
2015 net revenue

$293.9

Retail electric price
39.0

Net gas revenue
(2.5
)
Volume/weather
(5.1
)
Other
(8.1
)
2016 net revenue

$317.2


The retail electric price variance is primarily due to an increase in the purchased power and capacity acquisition cost recovery rider, as approved by the City Council, effective with the first billing cycle of March 2016, primarily

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related to the purchase of Power Block 1 of the Union Power Station. See Note 14 to the financial statements for discussion of the Union Power Station purchase.

The net gas revenue variance is primarily due to the effect of less favorable weather on residential and commercial sales.

The volume/weather variance is primarily due to a decrease of 112 GWh, or 2%, in billed electricity usage, partially offset by the effect of favorable weather on commercial sales and a 2% increase in the average number of electric customers.
    
Other Income Statement Variances

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.

2016 Compared to 2015

Other operation and maintenance expenses decreased primarily due to:

•
a decrease of $6.1 million due to lower transmission equalization expenses, as allocated under the System Agreement as compared to the same period in 2015 primarily due to the termination of the System Agreement. See Note 2 to the financial statements for further discussion on the System Agreement termination;
•
a decrease of $4.4 million due to the cessation of storm damage provisions in August 2015. See Note 2 to the financial statements for further discussion of storm cost recovery; and
•
a decrease of $3.1 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.

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The decrease was partially offset by:

•
an increase of $5.7 million in fossil-fueled generation expenses primarily due to an increase as a result of the purchase of Power Block 1 of the Union Power Station in March 2016, partially offset by a decrease as a result of the deactivation of Michoud Units 2 and 3 effective May 2016.  See Note 14 to the financial statements for discussion of the Union Power Station purchase;
•
an increase of $3.1 million in loss provisions; and
•
an increase of $2.8 million due to higher write-offs of uncollectible customer accounts in 2016 as compared to 2015.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including the purchase of Power Block 1 of the Union Power Station in March 2016, partially offset by the retirement of Michoud Units 2 and 3 effective May 2016.
    
Interest expense increased primarily due to the issuance of $110 million of 5.50% Series first mortgage bonds in March 2016 and the issuance of $98.7 million of storm cost recovery bonds in July 2015. See Note 5 to the financial statements for details on long-term debt.

Other income decreased primarily due to an increase in charitable contributions made in 2016 as compared to 2015.
    
Income Taxes

The effective income tax rates for 2017, 2016, and 2015 were 42.8%, 37.0% and 35.9%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% 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 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 proceedings commenced or other responses by Entergy’s regulators to the Act.


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Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2017, 2016, and 2015 were as follows:
 
2017
 
2016
 
2015
 
(In Thousands)
Cash and cash equivalents at beginning of period

$103,068

 

$88,876

 

$42,389

 
 
 
 
 
 
Net cash provided by (used in):
 

 
 

 
 

Operating activities
127,797

 
205,211

 
105,068

Investing activities
(109,500
)
 
(322,681
)
 
(173,460
)
Financing activities
(88,624
)
 
131,662

 
114,879

Net increase (decrease) in cash and cash equivalents
(70,327
)

14,192


46,487

 
 
 
 
 
 
Cash and cash equivalents at end of period

$32,741



$103,068



$88,876


Operating Activities

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 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.

Net cash flow provided by operating activities increased $100.1 million in 2016 primarily due to income tax refunds of $86 million in 2016 as compared to income tax payments of $8.1 million in 2015. Entergy New Orleans had income tax refunds in 2016 and income tax payments in 2015 in accordance with an intercompany income tax allocation agreement. The 2016 income tax refunds resulted primarily from deductible temporary differences.

Investing Activities
    
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.

Net cash flow used in investing activities increased $149.2 million in 2016 primarily due to the purchase of Power Block 1 of the Union Power Station for approximately $237 million in March 2016. The increase was partially offset by a deposit of $63.9 million into the storm reserve escrow account in July 2015 and money pool activity. See Note 14 to the financial statements for discussion of the Union Power Station purchase. See Note 5 to the financial statements for a discussion of the issuance in July 2015 of securitization bonds to recover storm costs.

Decreases in Entergy New Orleans’s receivable from the money pool are a source of cash flow, and Entergy New Orleans’s receivable from the money pool decreased $1.6 million in 2016 compared to increasing $15.4 million in 2015.  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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Financing Activities

Entergy New Orleans’s financing activities used $88.6 million of cash in 2017 compared to providing $131.7 million 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 above.

See Note 14 to the financial statements for discussion of the Union Power Station purchase.

Net cash flow provided by financing activities increased $16.8 million in 2016 primarily due to:

•
the purchase of Entergy Louisiana’s Algiers assets in September 2015. The cash portion of the purchase is reflected as a repayment of a long-term payable due to Entergy Louisiana in the cash flow statement. See Note 2 to the financial statements and “Algiers Asset Transfer” below for further discussion of the Algiers asset transfer and accounting for the transaction;
•
the issuance of $110 million of 5.50% Series first mortgage bonds in March 2016; and
•
the issuance of $85 million of 4% Series first mortgage bonds in May 2016. Entergy New Orleans used the proceeds to pay, prior to maturity, its $33.271 million of 5.6% Series first mortgage bonds due September 2024 and to pay, prior to maturity, its $37.772 million of 5.65% Series first mortgage bonds due September 2029.

The increase was offset by:

•
the issuance of $98.7 million of storm costs recovery bonds in July 2015;
•
a $47.8 million capital contribution received from Entergy Corporation in 2016 as compared to an $87.5 million capital contribution received from Entergy Corporation in 2015, both in anticipation of Entergy New Orleans’s purchase of Power Block 1 of the Union Power Station; and
•
an increase of $11.5 million in common equity distributions in 2016. Common equity distributions were lower in 2015 in anticipation of the purchase of Power Block 1 of the Union Power Station.
        
See Note 5 to the financial statements for more details on long-term debt.


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Capital Structure

Entergy New Orleans’s capitalization 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 redemptions of preferred stock in 2017. 
 
December 31, 2017
 
December 31, 2016
Debt to capital
51.3
%
 
50.1
%
Effect of excluding securitization bonds
(4.7
%)
 
(5.2
%)
Debt to capital, excluding securitization bonds (a)
46.6
%
 
44.9
%
Effect of subtracting cash
(2.4
%)
 
(8.0
%)
Net debt to net capital, excluding securitization bonds (a)
44.2
%
 
36.9
%

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

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, long-term debt, including the currently maturing portion, and the long-term payable to Entergy Louisiana. Capital consists of debt, preferred stock without sinking fund, 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 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 New Orleans may issue incremental debt or reduce dividends, 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 dividends, 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.


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Following are the amounts of Entergy New Orleans’s planned construction and other capital investments.
 
2018
 
2019
 
2020
 
(In Millions)
Planned construction and capital investment:
 
 
 
 
 
Generation

$115

 

$80

 

$15

Transmission
15

 
10

 
5

Distribution
80

 
85

 
80

Utility Support
20

 
15

 
15

Total

$230

 

$190

 

$115


Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2018
 
2019-2020
 
2021-2022
 
After 2022
 
Total
 
(In Millions)
Long-term debt (a)

$31

 

$87

 

$59

 

$674

 

$851

Operating leases

$2

 

$3

 

$1

 

$2

 

$8

Purchase obligations (b)

$245

 

$480

 

$463

 

$3,669

 

$4,857


(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 $7.3 million to its qualified pension plan and approximately $3.7 million to other postretirement health care and life insurance plans in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018. 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 $238.2 million of unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy 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 investment to support advanced metering; system improvements; 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.


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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 application included an updated cost estimate of $232 million for the 226 MW advanced combustion turbine. 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 testimony filed subsequent to Entergy New Orleans’s supplemental and amending application, several intervenors oppose City Council approval of either alternative, while the City Council advisors and one intervenor support the smaller alternative. A contested hearing was held in December 2017 and post-hearing briefs were filed in January 2018. In February 2018 the City Council Utility Committee adopted a resolution approving construction of the 128 MW unit. The full City Council is expected to vote on the resolution in March 2018. The commercial operation date is dependent on the alternative selected by the City Council and the receipt of other permits and approvals.

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 of 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, which is anticipated to be filed in 2018.  The City Council has authorized Entergy New Orleans to proceed with its replacement plans at the requested pace until such time that rates resulting from the anticipated 2018 rate case are implemented (approximately 13 months after filing).  As a result of the anticipated 2018 rate case, the City Council may establish new overall gas base rates to allow Entergy New Orleans to continue to recover these replacement costs.  The City Council has established a schedule for proceedings in advance of the rate case intended to provide an opportunity for evaluation of the gas infrastructure replacement plan that would best serve the public interest and the effect on customers of the approval of any such plan.

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 is expected to begin in 2019.  Deployment of the information technology infrastructure began in 2017 and deployment of the communications network is expected to begin 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

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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.

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; 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.

Entergy New Orleans’s receivables from the money pool were as follows as of December 31 for each of the following years.
2017
 
2016
 
2015
 
2014
(In Thousands)
$12,723
 
$14,215
 
$15,794
 
$442

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 2018. The credit facility allows Entergy New Orleans to issue letters of credit against $10 million of the borrowing capacity of the facility. As of December 31, 2017, 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, 2017, a $1.4 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 June 2018.

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

See “Algiers Asset Transfer” below for discussion of the Algiers asset transfer. As a provision of the settlement agreement approved by the City Council in May 2015 providing for the Algiers asset transfer, 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

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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 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 (estimated to be June 2018) and when new rates from the anticipated 2018 combined rate case, which will include a cost recovery mechanism for Energy Smart funding, take effect (estimated to be August 2019). Entergy New Orleans requested that the City Council approve a cost recovery mechanism prior to June 2018. 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.


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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.

Due to higher fuel costs associated in part with the extended Grand Gulf outage and the partially simultaneous Union Power Block 1 planned outage, for the December 2016, January 2017, and February 2017 billing months, the City Council authorized Entergy New Orleans to cap the fuel adjustment charge billed to customers at $0.035 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.

Due to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs associated in part with certain plant outages, Entergy New Orleans has proposed to cap the fuel adjustment charge to be billed in March 2018 to non-transmission Entergy New Orleans legacy customers and Entergy New Orleans Algiers customers at $0.035323 per kWh and $0.025446 per kWh, respectively. Entergy New Orleans has also proposed to cap the fuel adjustment charge to be billed in March 2018 for Entergy New Orleans legacy transmission customers at $0.034609 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.

Algiers Asset Transfer

In October 2014, Entergy Louisiana and Entergy New Orleans filed an application with the City Council seeking authorization to undertake a transaction that would result in 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. In April 2015 the FERC issued an order approving the Algiers assets transfer. In May 2015 the parties filed a settlement agreement authorizing the Algiers assets transfer and the settlement agreement was approved by a City Council resolution in May 2015. On September 1, 2015, Entergy Louisiana transferred its Algiers assets to Entergy New Orleans for a purchase price of approximately $85 million. Entergy New Orleans paid Entergy Louisiana $59.6 million, including final true-ups, from available cash and issued a note payable to Entergy Louisiana in the amount of $25.5 million.

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.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation. 

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Nuclear Matters

See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.

Environmental Risks

Entergy New Orleans’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous solid wastes, and other environmental matters.  Management believes that Entergy New Orleans is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1.  Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

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

Utility Regulatory Accounting

See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.

Unbilled Revenue

See “Unbilled Revenue” 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 unbilled revenue amounts.

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

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Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.  Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption
 
Change in Assumption
 
Impact on 2018 Qualified Pension Cost
 
Impact on 2017 Projected Qualified Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$348
 

$6,153

Rate of return on plan assets
 
(0.25%)
 
$399
 

$—

Rate of increase in compensation
 
0.25%
 
$159
 

$729


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 2018 Postretirement Benefit Cost
 
Impact on 2017 Accumulated Postretirement Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 

($12
)
 
$1,406
Health care cost trend
 
0.25%
 

$54

 
$1,074

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 2017 was $5.1 million. Entergy New Orleans anticipates 2018 qualified pension cost to be $5.8 million.  In 2016, Entergy New Orleans refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $1.7 million.  Entergy New Orleans contributed $9.9 million to its pension plans in 2017 and estimates 2018 pension contributions will be approximately $7.3 million, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018.

Total postretirement health care and life insurance benefit income for Entergy New Orleans in 2017 was $2.5 million.  Entergy New Orleans expects 2018 postretirement health care and life insurance benefit income of approximately $3.7 million.  In 2016, Entergy New Orleans refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $548 thousand. Entergy New Orleans contributed $3.7 million to its other postretirement plans in 2017 and estimates 2018 contributions will be approximately $3.7 million.


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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 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, 2017 and 2016, the related consolidated statements of income, cash flows, and changes in common equity (pages 392 through 396 and applicable items in pages 55 through 230), for each of the three years in the period ended December 31, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2018


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,
 
 
2017
 
2016
 
2015
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$631,744

 

$586,820

 

$584,322

Natural gas
 
84,326

 
78,643

 
87,124

TOTAL
 
716,070

 
665,463

 
671,446

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
111,082

 
40,489

 
96,307

Purchased power
 
282,178

 
299,551

 
277,851

Other operation and maintenance
 
109,270

 
117,471

 
119,087

Taxes other than income taxes
 
54,590

 
48,078

 
46,660

Depreciation and amortization
 
52,945

 
51,737

 
43,205

Other regulatory charges - net
 
10,889

 
8,258

 
3,366

TOTAL
 
620,954

 
565,584

 
586,476

 
 
 
 
 
 
 
OPERATING INCOME
 
95,116

 
99,879

 
84,970

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
2,418

 
1,178

 
1,404

Interest and investment income
 
707

 
256

 
73

Miscellaneous - net
 
24

 
(3,144
)
 
339

TOTAL
 
3,149

 
(1,710
)
 
1,816

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
21,281

 
21,061

 
17,312

Allowance for borrowed funds used during construction
 
(847
)
 
(446
)
 
(641
)
TOTAL
 
20,434

 
20,615

 
16,671

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
77,831

 
77,554

 
70,115

 
 
 
 
 
 
 
Income taxes
 
33,278

 
28,705

 
25,190

 
 
 
 
 
 
 
NET INCOME
 
44,553

 
48,849

 
44,925

 
 
 
 
 
 
 
Preferred dividend requirements and other
 
841

 
965

 
965

 
 
 
 
 
 
 
EARNINGS APPLICABLE TO COMMON EQUITY
 

$43,712

 

$47,884

 

$43,960

 
 
 
 
 
 
 
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,
 
 
2017
 
2016
 
2015
 
 
(In Thousands)
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$44,553

 

$48,849

 

$44,925

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation and amortization
 
52,945

 
51,737

 
43,205

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
64,036

 
140,283

 
22,180

Changes in assets and liabilities:
 
 

 
 

 
 

Receivables
 
(18,058
)
 
(3,888
)
 
7,878

Fuel inventory
 
(49
)
 
71

 
1,104

Accounts payable
 
1,874

 
15,434

 
2,738

Prepaid taxes and taxes accrued
 
(22,100
)
 
(1,685
)
 
(1,050
)
Interest accrued
 
44

 
534

 
1,270

Deferred fuel costs
 
12,592

 
(33,839
)
 
(182
)
Other working capital accounts
 
(2,711
)
 
4,165

 
(1,945
)
Provisions for estimated losses
 
(3,430
)
 
4,326

 
58,310

Other regulatory assets
 
16,673

 
(2,784
)
 
(70,471
)
Other regulatory liabilities
 
110,147

 
(3,997
)
 
(7,359
)
Deferred tax rate change recognized as regulatory liability/asset
 
(111,170
)
 
—

 
—

Pension and other postretirement liabilities
 
(15,994
)
 
(6,859
)
 
(18,831
)
Other assets and liabilities
 
(1,555
)
 
(7,136
)
 
23,296

Net cash flow provided by operating activities
 
127,797

 
205,211

 
105,068

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(115,584
)
 
(90,512
)
 
(91,928
)
Allowance for equity funds used during construction
 
2,418

 
1,178

 
1,404

Payment for purchase of plant
 
—

 
(237,335
)
 
—

Investments in affiliates
 
—

 
(38
)
 
—

Changes in money pool receivable - net
 
1,492

 
1,579

 
(15,352
)
Payments to storm reserve escrow account
 
(597
)
 
(438
)
 
(68,886
)
Receipts from storm reserve escrow account
 
2,488

 
3

 
5,922

Changes in securitization account
 
283

 
2,882

 
(4,620
)
Net cash flow used in investing activities
 
(109,500
)
 
(322,681
)
 
(173,460
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
—

 
240,604

 
95,367

Retirement of long-term debt
 
(10,600
)
 
(132,526
)
 
—

Repayment of long-term payable due to Entergy Louisiana
 
(2,104
)
 
(4,973
)
 
(59,610
)
Redemption of preferred stock
 
(20,599
)
 
—

 
—

Capital contributions from parent
 
20,000

 
47,750

 
87,500

Distributions/dividends paid:
 
 

 
 

 
 

Common equity
 
(74,250
)
 
(18,720
)
 
(7,250
)
Preferred stock
 
(1,083
)
 
(965
)
 
(965
)
Other
 
12

 
492

 
(163
)
Net cash flow provided by (used in) financing activities
 
(88,624
)
 
131,662

 
114,879

Net increase (decrease) in cash and cash equivalents
 
(70,327
)
 
14,192

 
46,487

Cash and cash equivalents at beginning of period
 
103,068

 
88,876

 
42,389

Cash and cash equivalents at end of period
 

$32,741

 

$103,068

 

$88,876

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 

 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$20,180

 

$19,317

 

$14,951

Income taxes
 

($8,660
)
 

($85,962
)
 

$8,110

See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents
 
 
 
 
Cash
 

$30

 

$28

Temporary cash investments
 
32,711

 
103,040

Total cash and cash equivalents
 
32,741

 
103,068

Securitization recovery trust account
 
1,455

 
1,738

Accounts receivable:
 
 

 
 

Customer
 
51,006

 
43,536

Allowance for doubtful accounts
 
(3,057
)
 
(3,059
)
Associated companies
 
22,976

 
16,811

Other
 
6,471

 
5,926

Accrued unbilled revenues
 
20,638

 
18,254

Total accounts receivable
 
98,034

 
81,468

Deferred fuel costs
 
—

 
4,818

Fuel inventory - at average cost
 
1,890

 
1,841

Materials and supplies - at average cost
 
10,381

 
8,416

Prepaid taxes
 
26,479

 
4,379

Prepayments and other
 
8,030

 
6,587

TOTAL
 
179,010


212,315

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Non-utility property at cost (less accumulated depreciation)
 
1,016

 
1,016

Storm reserve escrow account
 
79,546

 
81,437

Other
 
2,373

 
7,160

TOTAL
 
82,935

 
89,613

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
1,302,235

 
1,258,934

Natural gas
 
261,263

 
240,408

Construction work in progress
 
46,993

 
24,975

TOTAL UTILITY PLANT
 
1,610,491

 
1,524,317

Less - accumulated depreciation and amortization
 
631,178

 
604,825

UTILITY PLANT - NET
 
979,313

 
919,492

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Deferred fuel costs
 
4,080

 
4,080

Other regulatory assets (includes securitization property of $72,095 as of December 31, 2017 and $82,272 as of December 31, 2016)
 
251,433

 
268,106

Other
 
1,065

 
963

TOTAL
 
256,578

 
273,149

 
 
 
 
 
TOTAL ASSETS
 

$1,497,836

 

$1,494,569

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
December 31,
 
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Payable due to Entergy Louisiana
 

$2,077

 

$2,104

Accounts payable:
 
 

 
 

Associated companies
 
47,472

 
39,260

Other
 
29,777

 
35,920

Customer deposits
 
28,442

 
28,667

Interest accrued
 
5,487

 
5,443

Deferred fuel costs
 
7,774

 
—

Other
 
7,351

 
11,415

TOTAL CURRENT LIABILITIES
 
128,380

 
122,809

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
283,302

 
334,953

Accumulated deferred investment tax credits
 
2,323

 
622

Regulatory liability for income taxes - net
 
119,259

 
9,074

Asset retirement cost liabilities
 
3,076

 
2,875

Accumulated provisions
 
85,083

 
88,513

Pension and other postretirement liabilities
 
20,755

 
36,750

Long-term debt (includes securitization bonds of $74,419 as of December 31, 2017 and $84,776 as of December 31, 2016)
 
418,447

 
428,467

Long-term payable due to Entergy Louisiana
 
16,346

 
18,423

Other
 
5,317

 
5,357

TOTAL NON-CURRENT LIABILITIES
 
953,908

 
925,034

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
Preferred stock without sinking fund
 
—

 
19,780

 
 
 
 
 
EQUITY
 
 

 
 

Member's equity
 
415,548

 
426,946

TOTAL
 
415,548

 
426,946

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$1,497,836

 

$1,494,569

 
 
 
 
 
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, 2017, 2016, and 2015
 
 
 
 
 
 
 
 
Member’s Equity
 
 
(In Thousands)
 
 
 
Balance at December 31, 2014
 

$228,025

Net income
 
44,925

Net income attributable to Entergy Louisiana
 
(2,203
)
Capital contributions from parent
 
87,500

Common equity distributions
 
(7,250
)
Preferred stock dividends
 
(965
)
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

 
 
 
See Notes to Financial Statements.
 
 



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ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$716,070

 

$665,463

 

$671,446

 

$735,192

 

$659,746

Net income

$44,553

 

$48,849

 

$44,925

 

$31,030

 

$12,608

Total assets

$1,497,836

 

$1,494,569

 

$1,215,144

 

$1,014,916

 

$964,482

Long-term obligations (a)

$434,793

 

$466,670

 

$357,687

 

$323,280

 

$318,034

 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (including the long-term payable to Entergy Louisiana and excluding currently maturing debt) and preferred stock without sinking fund.
 
 
 
 
 
 
 
 
 
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
Electric Operating Revenues:
 

 
 

 
 

 
 

 
 

Residential

$250

 

$231

 

$220

 

$230

 

$221

Commercial
228

 
206

 
186

 
196

 
194

Industrial
36

 
33

 
30

 
33

 
35

Governmental
77

 
69

 
64

 
67

 
69

Total retail
591

 
539

 
500

 
526

 
519

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
—

 
30

 
66

 
78

 
27

Non-associated companies
29

 
3

 
—

 
4

 
—

Other
12

 
15

 
18

 
17

 
19

Total

$632

 

$587

 

$584

 

$625

 

$565

 
 
 
 
 
 
 
 
 
 
Billed Electric Energy Sales (GWh):
 
 
 

 
 

 
 

 
 

Residential
2,155

 
2,231

 
2,301

 
2,262

 
2,152

Commercial
2,248

 
2,268

 
2,257

 
2,181

 
2,130

Industrial
429

 
441

 
463

 
455

 
484

Governmental
790

 
794

 
825

 
783

 
778

Total retail
5,622

 
5,734

 
5,846

 
5,681

 
5,544

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
—

 
1,071

 
1,644

 
1,379

 
517

Non-associated companies
1,703

 
141

 
11

 
18

 
14

Total
7,325

 
6,946

 
7,501

 
7,078

 
6,075

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



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ENTERGY TEXAS, INC. AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

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.

2016 Compared to 2015

Net income increased $37.9 million primarily due to lower other operation and maintenance expenses, the asset write-off of its receivable associated with the Spindletop gas storage facility in 2015, and higher net revenue.

Net Revenue

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.


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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.

2016 Compared to 2015

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 2016 to 2015.
 
Amount
 
(In Millions)
 
 

2015 net revenue

$637.2

Reserve equalization
14.3

Purchased power capacity
12.4

Transmission revenue
7.0

Retail electric price
5.4

Net wholesale revenue
(27.8
)
Other
(4.3
)
2016 net revenue

$644.2


The reserve equalization variance is primarily due to a reduction in reserve equalization expense primarily due to changes in the Entergy System generation mix compared to the same period in 2015 as a result of the execution of a new purchased power agreement and Entergy Mississippi’s exit from the System Agreement, each in November 2015, and 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 purchased power capacity variance is primarily due to decreased expenses due to the termination of the purchased power agreements between Entergy Louisiana and Entergy Texas in August 2016, as well as capacity cost changes for ongoing purchased power capacity contracts.

The transmission revenue variance is primarily due to an increase in Attachment O rates charged by MISO to transmission customers and a settlement of Attachment O rates previously billed to transmission customers by MISO.

The retail electric price variance is primarily due to the implementation of the transmission cost recovery factor rider, as approved by the PUCT and implemented in September 2016, and the increase in the distribution cost recovery rider, as approved by the PUCT and implemented in January 2016. This increase was partially offset by a decrease in energy efficiency revenues. See Note 2 to the financial statements for further discussion of the transmission cost recovery factor rider and distribution cost recovery factor rider filings.

The net wholesale revenue variance is primarily due to lower capacity revenues resulting from the termination of the purchased power agreements between Entergy Louisiana and Entergy Texas in August 2016.


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Other Income Statement Variances

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.

2016 Compared to 2015

Other operation and maintenance expenses decreased primarily due to:

•
a decrease of $11.2 million in fossil-fueled generation expenses primarily due to an overall lower scope of work performed in 2016 as compared to 2015;
•
a decrease of $7 million in transmission expenses primarily due to lower transmission equalization expenses, as allocated under the System Agreement, as compared to the same period in 2015 as a result of Entergy Mississippi’s exit from the System Agreement in November 2015 and Entergy Texas’s exit from the System Agreement in August 2016;
•
a decrease of $5.7 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;
•
the write-off in the third quarter 2015 of $4.3 million of rate case expenses and acquisition costs related to the proposed Union Power Station acquisition upon Entergy Texas’s withdrawal of its 2015 rate case and dismissal of its certificate of convenience and necessity filing; and
•
a decrease of $4.2 million in energy efficiency costs.

The asset write-off variance is due to the $23.5 million ($15.3 million net-of-tax) write-off recorded in 2015 of the receivable associated with the Spindletop gas storage facility. See Note 2 to the financial statements for discussion of the write-off.

Income Taxes

The effective income tax rates for 2017, 2016, and 2015 were 38.9%, 37.0%, and 34.9%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.

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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 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 proceedings commenced or other responses by Entergy’s regulators to the Act.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2017, 2016, and 2015 were as follows:
 
2017
 
2016
 
2015
 
(In Thousands)
Cash and cash equivalents at beginning of period

$6,181

 

$2,182

 

$30,441

 
 
 
 
 
 
Net cash provided by (used in):
 

 
 

 
 

Operating activities
301,396

 
306,601

 
284,268

Investing activities
(383,176
)
 
(330,191
)
 
(315,293
)
Financing activities
191,112

 
27,589

 
2,766

Net increase (decrease) in cash and cash equivalents
109,332

 
3,999

 
(28,259
)
 
 
 
 
 
 
Cash and cash equivalents at end of period

$115,513

 

$6,181

 

$2,182


Operating Activities

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.
    
Net cash flow provided by operating activities increased $22.3 million in 2016 primarily due to increased net income and a decrease of $31.8 million in income tax payments in 2016. Entergy Texas had income tax payments in 2016 and 2015 in accordance with an intercompany income tax allocation agreement.  The income tax payments in 2016 resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit. The income tax payments in 2015 resulted primarily from the results of operations and the reversal of taxable temporary differences. See Note 3 to the financial statements for a discussion of the income tax audit. The increase was partially offset by an increase of $5.2 million in interest paid in 2016 due to the issuance of $125 million of 2.55% Series first mortgage bonds in March 2016 and the timing of collections from customers.


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Investing Activities

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. 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 $14.9 million in 2016 primarily due to increases of $27.7 million in transmission construction expenditures and $11.7 million in distribution construction expenditures primarily due to a greater scope of projects in 2016 as compared to the same period in 2015. The increase was partially offset by a $21.4 million decrease in fossil-fueled generation construction expenditures primarily due to a decreased scope of work performed during plant outages in 2016 as compared to the same period in 2015.

Financing Activities

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 2.55% Series first mortgage bonds in December 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.

Net cash flow provided by financing activities increased $24.8 million in 2016 primarily due to the retirement of $200 million of 3.6% Series first mortgage bonds in June 2015 and the issuance of $125 million of 2.55% Series first mortgage bonds in March 2016, partially offset by the issuance of $250 million of 5.15% Series first mortgage bonds in May 2015 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 compared to increasing by $22.1 million in 2015.


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Capital Structure

Entergy Texas’s capitalization 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 capital contribution received from Entergy Corporation and an increase in retained earnings.
 
 
December 31,
2017
 
December 31,
2016
Debt to capital
55.7
%
 
58.5
%
Effect of excluding the securitization bonds
(6.3
%)
 
(8.3
%)
Debt to capital, excluding securitization bonds (a)
49.4
%
 
50.2
%
Effect of subtracting cash
(2.5
%)
 
(0.1
%)
Net debt to net capital, excluding securitization bonds (a)
46.9
%
 
50.1
%
(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.
 
2018
 
2019
 
2020
 
(In Millions)
Planned construction and capital investment:
 
 
 
 
 
Generation

$175

 

$385

 

$265

Transmission
195

 
240

 
165

Distribution
105

 
165

 
145

Utility Support
55

 
30

 
30

Total

$530

 

$820

 

$605


Following are the amounts of Entergy Texas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2018
 
2019-2020
 
2021-2022
 
After 2022
 
Total
 
(In Millions)
Long-term debt (a)

$159

 

$749

 

$385

 

$1,168

 

$2,461

Operating leases (b)

$4

 

$5

 

$2

 

$2

 

$13

Purchase obligations (c)

$279

 

$555

 

$527

 

$1,188

 

$2,549


(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 $10.9 million to its qualified pension plans and approximately $3.2 million to other postretirement health care and life insurance plans in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018. 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 $15.8 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, 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; system improvements; 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 discussed above in “Capital Structure,” Entergy Texas routinely evaluates its ability to pay dividends to Entergy Corporation from its earnings.
    

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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. Consistent with the approval, deployment of the communications network is expected to begin in 2018. 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; and
•
bank financing under new or existing facilities.

Entergy Texas may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest and dividend rates are favorable.


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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.
2017
 
2016
 
2015
 
2014
(In Thousands)
$44,903
 
$681
 
($22,068)
 
$306

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 August 2022. The credit facility allows Entergy Texas to issue letters of credit against $30 million of the borrowing capacity of the facility. As of December 31, 2017, there were no cash borrowings and $25.6 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, 2017, a $22.8 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 October 2019 for short-term borrowings, not to exceed an aggregate amount of $200 million at any time outstanding, and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Texas’s short-term borrowing limits.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Texas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Texas is regulated and the rates charged to its customers are determined in regulatory proceedings. The PUCT, a governmental agency, is primarily responsible for approval of the rates charged to customers.

Filings with the PUCT

2011 Rate Case

In November 2011, Entergy Texas filed a rate case requesting a $112 million base rate increase reflecting a 10.6% return on common equity based on an adjusted June 2011 test year.  The rate case also proposed a purchased power recovery rider.  On January 12, 2012, the PUCT voted not to address the purchased power recovery rider in the rate case, but the PUCT voted to set a baseline in the rate case proceeding that would be applicable if a purchased power capacity rider is approved in a separate proceeding.  In April 2012 the PUCT Staff filed direct testimony recommending a base rate increase of $66 million and a 9.6% return on common equity.  The PUCT Staff, however, subsequently filed a statement of position in the proceeding indicating that it was still evaluating the position it would ultimately take in the case regarding Entergy Texas’s recovery of purchased power capacity costs and Entergy Texas’s proposal to defer its MISO transition expenses.  In April 2012, Entergy Texas filed rebuttal testimony indicating a revised request for a $105 million base rate increase.  A hearing was held in late-April through early-May 2012.

In September 2012 the PUCT issued an order approving a $28 million rate increase, effective July 2012.  The order included a finding that “a return on common equity (ROE) of 9.80 percent will allow [Entergy Texas] a reasonable opportunity to earn a reasonable return on invested capital.”  The order also provided for increases in depreciation rates and the annual storm reserve accrual.  The order also reduced Entergy Texas’s proposed purchased power capacity costs, stating that they are not known and measurable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6 million of MISO transition expense in base rates; and reduced Entergy’s Texas’s fuel reconciliation recovery by $4

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million because the PUCT disagreed with the line-loss factor used in the calculation.  After considering the progress of the proceeding in light of the PUCT order, Entergy Texas recorded in the third quarter 2012 an approximate $24 million charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery.  Entergy Texas believed that it was entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012.  Several other parties also filed motions for rehearing of the PUCT’s order.  The PUCT subsequently denied rehearing of substantive issues.  Several parties, including Entergy Texas, appealed various aspects of the PUCT’s order to the Travis County District Court. A hearing was held in July 2014. In October 2014 the Travis County District Court issued an order upholding the PUCT’s decision except as to the line-loss factor issue referenced above, which was found in favor of Entergy Texas. In November 2014, Entergy Texas and other parties, including the PUCT, appealed the Travis County District Court decision to the Third Court of Appeals. Oral argument before the court panel was held in September 2015. In April 2016 the Third Court of Appeals issued its opinion affirming the District Court’s decision on all points. Entergy Texas petitioned the Texas Supreme Court to hear its appeal of the Third Court’s ruling. In September 2017 the Texas Supreme Court denied the petitions for review. Entergy Texas filed a motion for rehearing of the Texas Supreme Court’s denial of the petition for review. In January 2018 the Texas Supreme Court denied Entergy Texas’s motion for rehearing.

Distribution cost recovery factor (DCRF) rider

In September 2015, Entergy Texas filed to amend its DCRF rider. Entergy Texas requested an increase in recovery under the rider of $6.5 million, for a total collection of $10.1 million annually from retail customers. In October 2015 intervenors and PUCT staff filed testimony opposing, in part, Entergy Texas’s request. In November 2015, Entergy Texas and the parties filed an unopposed settlement agreement and supporting documents. The settlement established an annual revenue requirement of $8.65 million for the amended DCRF rider, with the resulting rates effective for usage on and after January 1, 2016. The PUCT approved the settlement agreement in February 2016.

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, 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, with the resulting rates effective for usage no later than October 1, 2017. 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.
    
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. A hearing on the merits was held in December 2015. 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.


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In September 2016, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed amended TCRF rider is designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount includes the approximately $10.5 million annually that Entergy Texas is currently 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 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.

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 August 2014, Entergy Texas filed an application seeking PUCT approval to implement an interim fuel refund of approximately $24.6 million for over-collected fuel costs incurred during the months of November 2012 through April 2014. This refund resulted from (i) applying $48.6 million in bandwidth remedy payments that Entergy Texas received in May 2014 related to the June - December 2005 period to Entergy Texas’s $8.7 million under-recovered fuel balance as of April 30, 2014 and (ii) netting that fuel balance against the $15.3 million bandwidth remedy payment that Entergy Texas made related to calendar year 2013 production costs. Also in August 2014, Entergy Texas filed an unopposed motion for interim rates to implement these refunds for most customers over a two-month period commencing with September 2014. The PUCT issued its order approving the interim relief in August 2014 and Entergy Texas completed the refunds in October 2014. Parties intervened in this matter, and all parties agreed that the proceeding should be bifurcated such that the proposed interim refund would become final in a separate proceeding, which refund was approved by the PUCT in March 2015.   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 to be 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 U.S. Court of Appeals for the Fifth Circuit in February 2018, and a decision is pending. The State District Court appeal of the PUCT’s January 2016 decision also remains pending.

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

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Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis

approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning Apri1 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.

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 beginning January 2018 and will continue through March 2018. A final decision in this matter remains pending.

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.



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Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis


Critical Accounting Estimates

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

Utility Regulatory Accounting

See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.

Unbilled Revenue

See “Unbilled Revenue” 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 unbilled revenue amounts.

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.


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Management’s Financial Discussion and Analysis

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 2018 Qualified Pension Cost
 
Impact on 2017 Qualified Projected Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$701
 

$11,425

Rate of return on plan assets
 
(0.25%)
 
$868
 

$—

Rate of increase in compensation
 
0.25%
 
$301
 

$1,488

    
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 2018 Postretirement Benefit Cost
 
Impact on 2017 Accumulated Postretirement Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$231
 
$3,481
Health care cost trend
 
0.25%
 
$413
 
$2,907

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

Costs and Funding

Total qualified pension cost for Entergy Texas in 2017 was $3.5 million. Entergy Texas anticipates 2018 qualified pension income to be $4.2 million. In 2016, Entergy Texas refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $3.6 million. Entergy Texas contributed $17 million to its qualified pension plans in 2017 and estimates 2018 pension contributions will be approximately $10.9 million, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018.

Total postretirement health care and life insurance benefit income for Entergy Texas in 2017 was $1.8 million. Entergy Texas expects 2018 postretirement health care and life insurance benefit income to approximate $6.2 million. In 2016, Entergy Texas refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $1.1 million. Entergy Texas contributed $3.1 million to its other postretirement plans in 2017 and estimates 2018 contributions will be approximately $3.2 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.

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New Accounting Pronouncements

See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the 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, 2017 and 2016, the related consolidated statements of income, cash flows, and changes in common equity (pages 414 through 418 and applicable items in pages 55 through 230), for each of the three years in the period ended December 31, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2018


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,
 
 
2017
 
2016
 
2015
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$1,544,893

 

$1,615,619

 

$1,707,203

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
225,517

 
271,968

 
277,810

Purchased power
 
610,279

 
616,597

 
709,947

Other operation and maintenance
 
230,616

 
220,566

 
254,731

Asset write-off
 
—

 
—

 
23,472

Taxes other than income taxes
 
79,254

 
70,973

 
72,945

Depreciation and amortization
 
117,520

 
107,026

 
102,410

Other regulatory charges - net
 
82,328

 
82,879

 
82,243

TOTAL
 
1,345,514

 
1,370,009

 
1,523,558

 
 
 
 
 
 
 
OPERATING INCOME
 
199,379

 
245,610

 
183,645

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
6,722

 
7,617

 
5,678

Interest and investment income
 
981

 
987

 
684

Miscellaneous - net
 
193

 
(746
)
 
(798
)
TOTAL
 
7,896

 
7,858

 
5,564

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
86,719

 
87,776

 
86,024

Allowance for borrowed funds used during construction
 
(4,098
)
 
(4,943
)
 
(3,690
)
TOTAL
 
82,621

 
82,833

 
82,334

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
124,654

 
170,635

 
106,875

 
 
 
 
 
 
 
Income taxes
 
48,481

 
63,097

 
37,250

 
 
 
 
 
 
 
NET INCOME
 

$76,173

 

$107,538

 

$69,625

 
 
 
 
 
 
 
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,
 
 
2017
 
2016
 
2015
 
 
(In Thousands)
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$76,173

 

$107,538

 

$69,625

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation and amortization
 
117,520

 
107,026

 
102,410

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
42,119

 
20,794

 
(23,292
)
Changes in assets and liabilities:
 
 

 
 

 
 

Receivables
 
(15,934
)
 
(9,300
)
 
21,443

Fuel inventory
 
(25,054
)
 
9,765

 
2,960

Accounts payable
 
32,842

 
(22,462
)
 
(16,913
)
Prepaid taxes and taxes accrued
 
30,308

 
10,018

 
3,484

Interest accrued
 
(421
)
 
(3,229
)
 
(551
)
Deferred fuel costs
 
12,758

 
29,419

 
36,985

Other working capital accounts
 
(7,852
)
 
(3,354
)
 
2,468

Provisions for estimated losses
 
2,531

 
(1,735
)
 
(2,899
)
Other regulatory assets
 
184,574

 
74,389

 
125,133

Other regulatory liabilities
 
410,968

 
2,106

 
1,271

Deferred tax rate change recognized as regulatory liability/asset
 
(520,547
)
 
—

 
—

Pension and other postretirement liabilities
 
(49,445
)
 
(10,204
)
 
(33,474
)
Other assets and liabilities
 
10,856

 
(4,170
)
 
(4,382
)
Net cash flow provided by operating activities
 
301,396

 
306,601

 
284,268

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(348,027
)
 
(337,963
)
 
(320,408
)
Allowance for equity funds used during construction
 
6,874

 
7,743

 
5,751

Insurance proceeds
 
2,431

 
—

 
—

Changes in money pool receivable - net
 
(44,222
)
 
(681
)
 
306

Changes in securitization account
 
(232
)
 
710

 
(942
)
Net cash flow used in investing activities
 
(383,176
)
 
(330,191
)
 
(315,293
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
148,277

 
123,502

 
246,607

Retirement of long-term debt
 
(71,683
)

(68,593
)

(265,734
)
Capital contributions from parent
 
115,000

 
—

 
—

Change in money pool payable - net
 
—

 
(22,068
)
 
22,068

Other
 
(482
)
 
(5,252
)
 
(175
)
Net cash flow provided by financing activities
 
191,112

 
27,589

 
2,766

Net increase (decrease) in cash and cash equivalents
 
109,332

 
3,999

 
(28,259
)
Cash and cash equivalents at beginning of period
 
6,181

 
2,182

 
30,441

Cash and cash equivalents at end of period
 

$115,513

 

$6,181

 

$2,182

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 

 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$84,556

 

$88,489

 

$83,290

Income taxes
 

($21,107
)
 

$28,523

 

$60,359

See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$32

 

$1,216

Temporary cash investments
 
115,481

 
4,965

Total cash and cash equivalents
 
115,513

 
6,181

Securitization recovery trust account
 
37,683

 
37,451

Accounts receivable:
 
 

 
 

Customer
 
74,382

 
71,803

Allowance for doubtful accounts
 
(463
)
 
(828
)
Associated companies
 
90,629

 
39,447

Other
 
9,831

 
14,756

Accrued unbilled revenues
 
50,682

 
39,727

Total accounts receivable
 
225,061

 
164,905

Fuel inventory - at average cost
 
42,731

 
37,177

Materials and supplies - at average cost
 
38,605

 
36,631

Prepayments and other
 
19,710

 
18,599

TOTAL
 
479,303

 
300,944

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Investments in affiliates - at equity
 
457

 
600

Non-utility property - at cost (less accumulated depreciation)
 
376

 
376

Other
 
19,235

 
18,801

TOTAL
 
20,068

 
19,777

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
4,569,295

 
4,274,069

Construction work in progress
 
102,088

 
111,227

TOTAL UTILITY PLANT
 
4,671,383

 
4,385,296

Less - accumulated depreciation and amortization
 
1,579,387

 
1,526,057

UTILITY PLANT - NET
 
3,091,996

 
2,859,239

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Regulatory asset for income taxes - net
 
—

 
105,816

  Other regulatory assets (includes securitization property of $313,123 as of December 31, 2017 and $384,609 as of December 31, 2016)
 
661,398

 
740,156

Other
 
26,973

 
7,149

TOTAL
 
688,371

 
853,121

 
 
 
 
 
TOTAL ASSETS
 

$4,279,738

 

$4,033,081

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2017
 
2016
 
 
(In Thousands)
CURRENT LIABILITIES
 
 
 
 
Accounts payable:
 
 
 
 
Associated companies
 

$59,347

 

$47,867

Other
 
126,095

 
77,342

Customer deposits
 
40,925

 
44,419

Taxes accrued
 
45,659

 
15,351

Interest accrued
 
25,556

 
25,977

Deferred fuel costs
 
67,301

 
54,543

Other
 
8,132

 
9,388

TOTAL
 
373,015

 
274,887

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
544,642

 
1,027,647

Accumulated deferred investment tax credits
 
11,983

 
12,934

Regulatory liability for income taxes - net
 
412,620

 
—

Other regulatory liabilities
 
6,850

 
8,502

Asset retirement cost liabilities
 
6,835

 
6,470

Accumulated provisions
 
10,115

 
7,584

Pension and other postretirement liabilities
 
17,853

 
67,313

Long-term debt (includes securitization bonds of $358,104 as of December 31, 2017 and $429,043 as of December 31, 2016)
 
1,587,150

 
1,508,407

Other
 
48,508

 
50,343

TOTAL
 
2,646,556

 
2,689,200

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
COMMON EQUITY
 
 

 
 

Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2017 and 2016
 
49,452

 
49,452

Paid-in capital
 
596,994

 
481,994

Retained earnings
 
613,721

 
537,548

TOTAL
 
1,260,167

 
1,068,994

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$4,279,738

 

$4,033,081

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 



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ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY
For the Years Ended December 31, 2017, 2016, and 2015
 
 
 
 
 
Common Equity
 
 
 
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Total
 
(In Thousands)
 
 
 
 
 
 
 
 
Balance at December 31, 2014

$49,452

 

$481,994

 

$360,385

 

$891,831

Net income
—

 
—

 
69,625

 
69,625

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

 
 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY TEXAS, INC. AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$1,544,893

 

$1,615,619

 

$1,707,203

 

$1,851,982

 

$1,728,799

Net income

$76,173

 

$107,538

 

$69,625

 

$74,804

 

$57,881

Total assets

$4,279,738

 

$4,033,081

 

$3,898,582

 

$3,897,989

 

$3,909,470

Long-term obligations (a)

$1,587,150

 

$1,508,407

 

$1,451,967

 

$1,268,835

 

$1,544,549

 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (excluding currently maturing debt).
 
 
 
 
 
 
 
 
 
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
Electric Operating Revenues:
 

 
 

 
 

 
 

 
 

Residential

$636

 

$613

 

$633

 

$654

 

$596

Commercial
378

 
356

 
369

 
384

 
327

Industrial
384

 
365

 
372

 
422

 
325

Governmental
25

 
24

 
25

 
26

 
24

Total retail
1,423

 
1,358

 
1,399

 
1,486

 
1,272

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
58

 
178

 
259

 
316

 
369

Non-associated companies
22

 
40

 
14

 
23

 
47

Other
42

 
40

 
35

 
27

 
41

Total

$1,545

 

$1,616

 

$1,707

 

$1,852

 

$1,729

 
 
 
 
 
 
 
 
 
 
Billed Electric Energy Sales (GWh):
 
 
 

 
 

 
 

 
 

Residential
5,716

 
5,836

 
5,889

 
5,810

 
5,726

Commercial
4,548

 
4,570

 
4,548

 
4,471

 
4,402

Industrial
7,521

 
7,493

 
7,036

 
7,140

 
6,404

Governmental
273

 
283

 
276

 
277

 
282

Total retail
18,058

 
18,182

 
17,749

 
17,698

 
16,814

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
1,534

 
4,625

 
5,853

 
4,763

 
6,287

Non-associated companies
729

 
1,086

 
254

 
200

 
712

Total
20,321

 
23,893

 
23,856

 
22,661

 
23,813



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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

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 - Complaint Against System Energy” below for further discussion of the complaint against System Energy.

2016 Compared to 2015

Net income decreased $14.6 million primarily due to a higher effective income tax rate in 2016.

Income Taxes

The effective income tax rates for 2017, 2016, and 2015 were 47.1%, 42.3%, and 32.3%, respectively. The difference in the effective income tax rate of 47.1% for 2017 versus the 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 rate of 35% 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 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 proceedings commenced or other responses by Entergy’s regulators to the Act.


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Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2017, 2016, and 2015 were as follows:
 
2017
 
2016
 
2015
 
(In Thousands)
Cash and cash equivalents at beginning of period

$245,863

 

$230,661

 

$223,179

 
 
 
 
 
 
Net cash provided by (used in):
 
 
 

 
 

Operating activities
371,278

 
341,939

 
502,536

Investing activities
(174,250
)
 
(232,602
)
 
(137,562
)
Financing activities
(155,704
)
 
(94,135
)
 
(357,492
)
Net increase in cash and cash equivalents
41,324

 
15,202

 
7,482

 
 
 
 
 
 
Cash and cash equivalents at end of period

$287,187

 

$245,863

 

$230,661


Operating Activities

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.

Net cash flow provided by operating activities decreased $160.6 million in 2016 primarily due to:

•
a decrease of $90.5 million in income tax refunds in 2016. System Energy received income tax refunds in 2016 and 2015 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2016 and 2015 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; and
•
an increase in spending of $35.1 million on nuclear refueling outages in 2016 as compared to 2015.

The decrease 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.

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Investing Activities

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.  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 $95 million in 2016 primarily due to:

•
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 in nuclear construction expenditures primarily as a result of a higher scope of work performed in 2016 on Grand Gulf outage projects, partially offset by decreased spending in 2016 on compliance with NRC post-Fukushima requirements.

The increase 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.

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 $6.1 million in 2016 compared to increasing by $37.6 million in 2015.

Financing Activities

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.


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Net cash flow used in financing activities decreased $263.4 million in 2016 primarily due to:

•
net borrowings of $66.9 million on the nuclear fuel company variable interest entity’s credit facility in 2016 compared to net repayments of $20.4 million on the nuclear fuel company variable interest entity’s credit facility in 2015;
•
a decrease of $61.8 million in common stock dividends and distributions as a result of lower operating cash flows and higher nuclear fuel purchases in 2016 as compared to the prior year;
•
the redemption in April 2015, at maturity, of $60 million of System Energy nuclear fuel company variable interest entity’s 5.33% Series G notes; and
•
redemption in May 2015 of $35 million and in November 2015 of $25 million of System Energy’s 5.875% Series governmental bonds due 2022.

The decrease was partially offset by 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 capitalization is balanced between equity and debt, as shown in the following table. The decrease in the debt to capital ratio for System Energy is primarily due to 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.
 
December 31,
2017
 
December 31,
2016
Debt to capital
44.5
%
 
45.5
%
Effect of subtracting cash
(16.0
%)
 
(12.0
%)
Net debt to net capital
28.5
%
 
33.5
%

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.

Uses of Capital

System Energy requires capital resources for:

•
construction and other capital investments;
•
debt maturities or retirements;

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•
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.
 
2018
 
2019
 
2020
 
(In Millions)
Planned construction and capital investment:
 
 
 
 
 
Generation

$180

 

$130

 

$150

Utility Support
15

 
15

 
10

Total

$195

 

$145

 

$160


Following are the amounts of System Energy’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2018
 
2019-2020
 
2021-2022
 
After 2022
 
Total
 
(In Millions)
Long-term debt (a)

$124

 

$121

 

$199

 

$493

 

$937

Purchase obligations (b)

$38

 

$39

 

$34

 

$—

 

$111


(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 $13.8 million to its qualified pension plans and approximately $16 thousand to other postretirement health care and life insurance plans in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018. 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 $433 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.  

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.


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System Energy may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common stock issuances by System Energy require prior regulatory approval.  Debt issuances are also subject to issuance tests set forth in its bond indentures 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.
2017
 
2016
 
2015
 
2014
(In Thousands)
$111,667
 
$33,809
 
$39,926
 
$2,373

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 May 2019. As of December 31, 2017, $17.8 million in letters of credit to support a like amount of commercial paper issued and $50 million in loans were outstanding under the System Energy nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the variable interest entity credit facility.

System Energy obtained authorizations from the FERC through October 2019 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
•
long-term 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.

Complaint Against System Energy

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%. The 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

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proceedings before an ALJ. If the parties fail to come to an agreement during settlement proceedings, a prehearing conference will be held to establish a procedural schedule for hearing proceedings.

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 Complaint Against System Energy above, and directed the parties to engage in settlement proceedings before an ALJ. If the parties fail to come to an agreement during settlement proceedings, a prehearing conference will be held to establish a procedural schedule for hearing proceedings.

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 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.  In December 2016, the NRC granted the extension of Grand Gulf’s operating license to 2044.
 
Grand Gulf Outage and NRC review

Grand Gulf began a maintenance outage on September 8, 2016 to replace a residual heat removal pump. Although the pump had been replaced, on September 27, 2016 management decided to keep the plant in an outage for additional training and other steps to support management’s operational goals. Grand Gulf returned to service on January 31, 2017.


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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. Entergy is implementing a plan to restore Grand Gulf to Column 1, including addressing the issues related to the three very low safety significance non-cited violations identified in the NRC’s report on the results of its October 2016 special inspection. Depending on the success of implementing that plan and the plant’s performance indicators, there is risk that the NRC could move Grand Gulf into the “degraded cornerstone column,” or Column 3, of the NRC’s Reactor Oversight Process Action Matrix.

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.

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.

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 2018 Qualified Pension Cost
 
Impact on 2017 Projected Qualified Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$820
 

$11,922

Rate of return on plan assets
 
(0.25%)
 
$664
 

$—

Rate of increase in compensation
 
0.25%
 
$329
 

$1,473


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 2018 Postretirement Benefit Cost
 
Impact on 2017 Accumulated Postretirement Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$154
 
$2,042
Health care cost trend
 
0.25%
 
$239
 
$1,704

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 2017 was $11.7 million.  System Energy anticipates 2018 qualified pension cost to be $14.9 million.  In 2016, System Energy refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $2.8 million. System Energy contributed $18.2 million to its pension plans in 2017 and estimates 2018 pension contributions will approximate $13.8 million, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018.

Total postretirement health care and life insurance benefit cost for System Energy in 2017 was $692 thousand. System Energy expects 2018 postretirement health care and life insurance benefit income to approximate $490 thousand.

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In 2016, System Energy refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $555 thousand. System Energy contributed $570 thousand to its other postretirement plans in 2017 and expects 2018 contributions to approximate $16 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, 2017 and 2016, the related statements of income, cash flows, and changes in common equity (pages 431 through 436 and applicable items in pages 55 through 230), for each of the three years in the period ended December 31, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2018


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,
 
 
2017
 
2016
 
2015
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$633,458

 

$548,291

 

$632,405

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
71,700

 
27,416

 
89,598

Nuclear refueling outage expenses
 
17,968

 
19,512

 
21,654

Other operation and maintenance
 
213,534

 
153,064

 
156,552

Decommissioning
 
43,347

 
50,797

 
47,993

Taxes other than income taxes
 
26,180

 
25,195

 
27,281

Depreciation and amortization
 
137,767

 
136,195

 
143,133

Other regulatory credits - net
 
(37,831
)
 
(45,041
)
 
(39,434
)
TOTAL
 
472,665

 
367,138

 
446,777

 
 
 
 
 
 
 
OPERATING INCOME
 
160,793

 
181,153

 
185,628

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
6,345

 
7,944

 
8,494

Interest and investment income
 
17,538

 
14,793

 
14,437

Miscellaneous - net
 
(521
)
 
(556
)
 
(876
)
TOTAL
 
23,362

 
22,181

 
22,055

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
37,141

 
37,529

 
45,532

Allowance for borrowed funds used during construction
 
(1,551
)
 
(2,000
)
 
(2,244
)
TOTAL
 
35,590

 
35,529

 
43,288

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
148,565

 
167,805

 
164,395

 
 
 
 
 
 
 
Income taxes
 
69,969

 
71,061

 
53,077

 
 
 
 
 
 
 
NET INCOME
 

$78,596

 

$96,744

 

$111,318

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 


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SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF CASH FLOWS
 
 
 
 
 
For the Years Ended December 31,
 
 
2017
 
2016
 
2015
 
 
(In Thousands)
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$78,596

 

$96,744

 

$111,318

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 
240,962

 
224,879

 
270,514

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
7,827

 
99,531

 
200,797

Changes in assets and liabilities:
 
 

 
 

 
 

Receivables
 
9,210

 
(15,846
)
 
5,879

Accounts payable
 
15,969

 
2,720

 
(352
)
Prepaid taxes and taxes accrued
 
62,466

 
(6,555
)
 
(32,594
)
Interest accrued
 
(660
)
 
(134
)
 
(19,013
)
Other working capital accounts
 
12,083

 
(15,470
)
 
13,576

Other regulatory assets
 
60,012

 
(58,279
)
 
(4,565
)
Other regulatory liabilities
 
331,251

 
33,438

 
(33,686
)
Deferred tax rate change recognized as regulatory liability/asset
 
(325,707
)
 
—

 
—

Pension and other postretirement liabilities
 
4,024

 
5,586

 
(16,888
)
Other assets and liabilities
 
(124,755
)
 
(24,675
)
 
7,550

Net cash flow provided by operating activities
 
371,278

 
341,939

 
502,536

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(91,705
)
 
(88,037
)
 
(70,358
)
Allowance for equity funds used during construction
 
6,345

 
7,944

 
8,494

Nuclear fuel purchases
 
(49,728
)
 
(151,068
)
 
(64,977
)
Proceeds from the sale of nuclear fuel
 
69,516

 
11,467

 
57,681

Proceeds from nuclear decommissioning trust fund sales
 
565,416

 
499,252

 
390,371

Investment in nuclear decommissioning trust funds
 
(596,236
)
 
(534,083
)
 
(421,220
)
Changes in money pool receivable - net
 
(77,858
)
 
6,117

 
(37,553
)
Litigation proceeds for reimbursement of spent nuclear fuel storage costs
 
—

 
15,806

 
—

Net cash flow used in investing activities
 
(174,250
)
 
(232,602
)
 
(137,562
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
150,100

 
—

 
—

Retirement of long-term debt
 
(150,103
)
 
(22,002
)
 
(136,310
)
Changes in credit borrowings - net
 
(49,063
)
 
66,893

 
(20,404
)
Common stock dividends and distributions
 
(106,610
)
 
(139,000
)
 
(200,750
)
Other
 
(28
)
 
(26
)
 
(28
)
Net cash flow used in financing activities
 
(155,704
)
 
(94,135
)
 
(357,492
)
Net increase in cash and cash equivalents
 
41,324

 
15,202

 
7,482

Cash and cash equivalents at beginning of period
 
245,863

 
230,661

 
223,179

Cash and cash equivalents at end of period
 

$287,187

 

$245,863

 

$230,661

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 

 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$26,251

 

$36,152

 

$47,864

Income taxes
 

($2,227
)
 

($23,565
)
 

($114,092
)
See Notes to Financial Statements.
 
 

 
 

 
 


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SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$78

 

$786

Temporary cash investments
 
287,109

 
245,077

Total cash and cash equivalents
 
287,187

 
245,863

Accounts receivable:
 
 

 
 

Associated companies
 
170,149

 
104,390

Other
 
6,526

 
3,637

Total accounts receivable
 
176,675

 
108,027

Materials and supplies - at average cost
 
88,424

 
82,469

Deferred nuclear refueling outage costs
 
7,908

 
24,729

Prepayments and other
 
2,489

 
20,111

TOTAL
 
562,683

 
481,199

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Decommissioning trust funds
 
905,686

 
780,496

TOTAL
 
905,686

 
780,496

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
4,327,849

 
4,331,668

Property under capital lease
 
588,281

 
585,084

Construction work in progress
 
69,937

 
43,888

Nuclear fuel
 
207,513

 
259,635

TOTAL UTILITY PLANT
 
5,193,580

 
5,220,275

Less - accumulated depreciation and amortization
 
3,175,018

 
3,063,249

UTILITY PLANT - NET
 
2,018,562

 
2,157,026

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Regulatory asset for income taxes - net
 
—

 
93,127

Other regulatory assets
 
444,327

 
411,212

Other
 
7,629

 
4,652

TOTAL
 
451,956

 
508,991

 
 
 
 
 
TOTAL ASSETS
 

$3,938,887

 

$3,927,712

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2017
 
2016
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Currently maturing long-term debt
 

$85,004

 

$50,003

Short-term borrowings
 
17,830

 
66,893

Accounts payable:
 
 

 
 

Associated companies
 
16,878

 
5,843

Other
 
62,868

 
50,558

Taxes accrued
 
46,584

 
—

Interest accrued
 
13,389

 
14,049

Other
 
2,434

 
2,957

TOTAL
 
244,987

 
190,303

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
776,420

 
1,112,865

Accumulated deferred investment tax credits
 
39,406

 
41,663

Regulatory liability for income taxes - net
 
246,122

 
—

Other regulatory liabilities
 
455,991

 
370,862

Decommissioning
 
861,664

 
854,202

Pension and other postretirement liabilities
 
121,874

 
117,850

Long-term debt
 
466,484

 
501,129

Other
 
15,130

 
15

TOTAL
 
2,983,091

 
2,998,586

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
COMMON EQUITY
 
 

 
 

Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2017 and 2016
 
658,350

 
679,350

Retained earnings
 
52,459

 
59,473

TOTAL
 
710,809

 
738,823

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$3,938,887

 

$3,927,712

 
 
 
 
 
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, 2017, 2016, and 2015
 
 
 
 
 
Common Equity
 
 
 
Common Stock
 
Retained Earnings
 
Total
 
(In Thousands)
 
 
 
 
 
 
Balance at December 31, 2014

$789,350

 

$81,161

 

$870,511

Net income
—

 
111,318

 
111,318

Common stock dividends and distributions
(70,000
)
 
(130,750
)
 
(200,750
)
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

 
 
 
 
 
 
See Notes to Financial Statements.
 

 
 

 
 



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SYSTEM ENERGY RESOURCES, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
(Dollars In Thousands)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$633,458

 

$548,291

 

$632,405

 

$664,364

 

$735,089

Net income

$78,596

 

$96,744

 

$111,318

 

$96,334

 

$113,664

Total assets

$3,938,887

 

$3,927,712

 

$3,728,875

 

$3,826,193

 

$3,537,414

Long-term obligations (a)

$466,484

 

$501,129

 

$572,665

 

$630,603

 

$702,273

Electric energy sales (GWh)
6,675

 
5,384

 
10,547

 
9,219

 
9,794

 
 
 
 
 
 
 
 
 
 
(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 2017 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)
 
58
 
Chairman of the Board and Chief Executive Officer of Entergy Corporation
 
2013-Present
 
 
 
 
Executive Vice President and Chief Financial Officer of Entergy Corporation
 
2004-2013
 
 
 
 
Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and System Energy
 
2004-2013
 
 
 
 
Director of Entergy Texas
 
2007-2013
 
 
 
 
Director of Entergy New Orleans
 
2011-2013
 
 
 
 
 
 
 
A. Christopher Bakken, III (a)
 
56
 
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)
 
56
 
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
 
 
 
 
Senior Vice President and General Counsel of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
 
2012-2013
 
 
 
 
Vice President and Deputy General Counsel of Entergy Services, Inc.
 
2009-2012
 
 
 
 
Associate General Counsel of Entergy Services, Inc.
 
2007-2009

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Name
 
Age
 
Position
 
Period
Andrew S. Marsh (a)
 
46
 
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
 
 
 
 
Vice President, System Planning of Entergy Services, Inc.
 
2010-2013
 
 
 
 
Vice President, Planning and Financial Communications of Entergy Services, Inc.
 
2007-2010
 
 
 
 
 
 
 
Roderick K. West (a)
 
49
 
Group President Utility Operations of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
 
2017-Present
 
 
 
 
President, Chief Executive Officer, and Director of System Energy
 
2017-Present
 
 
 
 
Executive Vice President of Entergy Corporation
 
2010-2017
 
 
 
 
Chief Administrative Officer of Entergy Corporation
 
2010-2016
 
 
 
 
President and Chief Executive Officer of Entergy New Orleans
 
2007-2010
 
 
 
 
Director of Entergy New Orleans
 
2005-2011
 
 
 
 
 
 
 
Paul D. Hinnenkamp (a)
 
56
 
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
 
 
 
 
Vice President of Fossil Generation Development and Support of Entergy Services, Inc.
 
2010-2013
 
 
 
 
 
 
 
Alyson M. Mount (a)
 
47
 
Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
 
2012-Present
 
 
 
 
Vice President Corporate Controller of Entergy Services, Inc.
 
2010-2012
 
 
 
 
Director, Corporate Reporting and Accounting Policy of Entergy Services, Inc.
 
2002-2010
 
 
 
 
 
 
 
Andrea Coughlin Rowley (a)
 
52
 
Senior Vice President, Human Resources of Entergy Corporation
 
2016-Present
 
 
 
 
President and Chief Executive Officer of Advance/Evolve LLC
 
2013-2016
 
 
 
 
Vice President, Human Resources of Dover Corporation
 
2012-2013

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Name
 
Age
 
Position
 
Period
Donald W. Vinci (a)
 
59
 
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
 
 
 
 
Vice President, Human Capital Management of Entergy Services, Inc.
 
2013
 
 
 
 
Vice President, Gas Distribution Business of Entergy Services, Inc.
 
2010-2013
 
 
 
 
Vice President, Business Development of Entergy Services, Inc.
 
2008-2010

(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, 2017.

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.

The high and low prices of Entergy Corporation’s common stock for each quarterly period in 2017 and 2016 were as follows:
 
2017
 
2016
 
High
 
Low
 
High
 
Low
 
(In Dollars)
First
77.51
 
69.63
 
79.72
 
65.38
Second
80.61
 
74.88
 
81.36
 
72.67
Third
80.49
 
74.83
 
82.09
 
75.99
Fourth
87.95
 
75.01
 
76.56
 
66.71

Consecutive quarterly cash dividends on common stock were paid to stockholders of Entergy Corporation in 2017 and 2016.  Quarterly dividends of $0.85 per share were paid through third quarter 2016. In fourth quarter 2016 and through third quarter 2017, dividends of $0.87 per share were paid. In fourth quarter 2017, dividends of $0.89 per share were paid.
 
As of January 31, 2018, there were 26,213 stockholders of record of Entergy Corporation.


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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)
 
 
 
 
 
 
 
 
 
 
10/01/2017
-10/31/2017
 
—

 

$—

 
—

 

$350,052,918

11/01/2017
-11/30/2017
 
—

 

$—

 
—

 

$350,052,918

12/01/2017
-12/31/2017
 
—

 

$—

 
—

 

$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 2017, Entergy withheld 1,054 shares of its common stock at $70.58 per share, 122,148 shares of its common stock at $70.61 per share, and 31,243 shares of its common stock at $71.89 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.  Cash dividends and distributions on common equity paid by the Registrant Subsidiaries during 2017 and 2016, were as follows:

 
2017
 
2016
 
(In Millions)
Entergy Arkansas

$15.0

 

$—

Entergy Louisiana

$91.3

 

$285.5

Entergy Mississippi

$26.0

 

$24.0

Entergy New Orleans

$74.3

 

$18.7

Entergy Texas

$—

 

$—

System Energy

$106.6

 

$139.0


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, INC. AND SUBSIDIARIES, ENTERGY LOUISIANA, LLC AND SUBSIDIARIES, ENTERGY MISSISSIPPI, INC., 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, INC. AND SUBSIDIARIES, ENTERGY LOUISIANA, LLC AND SUBSIDIARIES, ENTERGY MISSISSIPPI, INC., 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, Entergy Arkansas, Inc., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, LLC, Entergy Texas, Inc., 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, 2017, 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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Table of Contents

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, 2017.  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, 2017.

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, 2017 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, 2017, 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, 2017, 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, 2017 of the Corporation and our report dated February 26, 2018 expressed an unqualified opinion of 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, 2018

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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 4, 2018, 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, INC.
 
 
 
 
 
 
 
Directors
 
 
 
 
 
 
Richard C. Riley
 
55
 
President and Chief Executive Officer of Entergy Arkansas
 
2016-Present
 
 
 
 
Director of Entergy Arkansas
 
2016-Present
 
 
 
 
Group Vice President, Customer Service and Operations of Entergy Arkansas
 
2015-2016
 
 
 
 
Vice President, Transmission of Entergy Services, Inc.
 
2010-2015
 
 
 
 
 
 
 
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.
 
 
Alyson M. Mount
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Richard C. Riley
 
 
 
See information under the Entergy Arkansas Directors Section above.
 
 
Andrea Coughlin Rowley
 
 
 
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.
 
55
 
President and Chief Executive Officer of Entergy Louisiana
 
2013-Present
 
 
 
 
Director of Entergy Louisiana
 
2013-Present
 
 
 
 
Vice President, Regulatory Services of Entergy Services, Inc.
 
2002-2013
 
 
 
 
 
 
 
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.
 
 
Andrea Coughlin Rowley
 
 
 
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, INC.
Directors
 
 
 
 
 
 
Haley R. Fisackerly
 
52
 
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.
 
 
Andrea Coughlin Rowley
 
 
 
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
 
 
 
 
 
 
Charles L. Rice, Jr.
 
53
 
President and Chief Executive Officer of Entergy New Orleans
 
2010-Present
 
 
 
 
Director of Entergy New Orleans
 
2010-Present
 
 
 
 
Director, Utility Strategy of Entergy Services, Inc.
 
2009-2010
 
 
 
 
Partner, Barrasso, Usdin, Kupperman, Freeman & Sarver, LLC
 
2005-2009
 
 
 
 
 
 
 
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.
 
 
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.
 
 
Charles L. Rice, Jr.
 
 
 
See information under the Entergy New Orleans Directors Section above.
 
 
Andrea Coughlin Rowley
 
 
 
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
 
56
 
President and Chief Executive Officer of Entergy Texas
 
2012-Present
 
 
 
 
Director of Entergy Texas
 
2012-Present
 
 
 
 
Vice President, Federal Policy of Entergy Services, Inc.
 
2011-2012
 
 
 
 
Director, Regulatory Affairs and Energy Settlements of Entergy Services, Inc.
 
2006-2011
 
 
 
 
 
 
 
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.
 
 
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.
 
 
Andrea Coughlin Rowley
 
 
 
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.
 
 

Each director and officer of the applicable Entergy company is elected yearly to serve by the unanimous consent of the sole common stockholder with the exception of the directors and officers of Entergy Louisiana, LLC and Entergy New Orleans, LLC, who are elected yearly to serve by the unanimous consent of the sole common membership owner, Entergy Utility Holding Company, LLC. Entergy Corporation’s directors are elected annually at the annual meeting of shareholders.  Entergy Corporation’s officers are elected at the annual organizational meeting of the Board of Directors.

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 full 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)
Maureen S. Bateman
Philip L. Frederickson
Blanche L. Lincoln
Karen A. Puckett

All Audit Committee members are independent.  In addition to the general independence requirements, 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 and accounting or related financial management expertise required by the NYSE rules.  The Board has determined that each of Patrick J. Condon and Philip L. Frederickson is an “audit committee financial expert” as such term is defined by the rules of the SEC.


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Code of Ethics

The Board of Directors has adopted a Code of Business Conduct and Ethics for Members of the Board of Directors.  The code is available through Entergy’s website (www.entergy.com) or upon written request.  The Board has also adopted a Code of Business Conduct and Ethics for Employees that includes Special Provisions Relating to Principal Executive Officer and Senior Financial Officers.  The Code of Business Conduct and Ethics for Employees 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 for Employees, 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.

Source of Nominations to the 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;
•
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 “Corporate Governance at Entergy - Our Board Structure - Identifying Director Candidates” and
•
the candidate’s signed consent to be named in the Proxy Statement and to serve as a director 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 4, 2018, 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,” “Nominees for the Board of Directors,” and “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 by the following Named Executive Officers in 2017 is discussed. Each officer’s title is provided as of December 31, 2017.
Name(1)
Title
A. Christopher Bakken, III
Executive Vice President and Chief Nuclear Officer
Marcus V. Brown
Executive Vice President and General Counsel
Leo P. Denault
Chairman of the Board and Chief Executive Officer
Haley R. Fisackerly
President and Chief Executive Officer, Entergy Mississippi
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.
President and Chief Executive Officer, Entergy New Orleans
Richard C. Riley
President and Chief Executive Officer, Entergy Arkansas
Roderick K. West
Group President Utility Operations

(1)
Messrs. Bakken, Brown, Denault, Marsh, and West hold the positions referenced above as executive officers
of Entergy Corporation and are members of Entergy Corporation’s Office of the Chief Executive. No additional compensation was paid in 2017 to any of these officers for their service as Named Executive Officers of the Utility operating companies.



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CD&A Highlights
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.

Sound Program Design

Entergy Corporation’s executive compensation programs are designed to:

•
Pay for performance
•
Attract, retain, and motivate key executive officers who drive Entergy Corporation’s success and industry leadership
•
Provide market compensation payout opportunities
•
Align with the interests of Entergy Corporation’s long-term shareholders
•
Reflect best practices in the market

 Executive Compensation Best Practices:

Changes Since 2017 Annual Meeting
*
To align with compensation best practices, and in response to investor feedback, beginning with the 2018-2020 performance period, added a cumulative utility earnings performance measure to the Long-Term Performance Incentive Program supplementing the relative total shareholder return measure historically used in this program
What Entergy Corporation Does
*
Double trigger for severance payments or equity acceleration in the event of a change in control
*
Clawback policy that goes beyond Sarbanes-Oxley requirements
*
Maximum payout capped at 200% of target under the Long-Term Performance Unit Program and under the Annual Incentive Plan 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
*
New officers are excluded from participation in the System Executive Retirement Plan
*
No grants of supplemental service credit to newly-hired officers under any of Entergy Corporation’s non-qualified retirement plans

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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 its ability to drive strong financial and operational results and to attract and retain a highly experienced and successful management team. The Annual Incentive Plan incentivizes and rewards the achievement of financial metrics that are deemed by the Personnel Committee to be consistent with the overall goals and strategic direction that the Entergy Corporation Board has approved for Entergy Corporation. The long-term incentive programs further align the interests of Entergy Corporation’s executives and its shareholders by directly tying the value of the equity awards granted to executives under these programs to Entergy Corporation’s stock price performance and total shareholder return. By incentivizing officers to achieve important financial and operational objectives and create long-term shareholder value, these programs play a key role in creating sustainable value for the benefit of all of Entergy Corporation’s stakeholders, including owners, customers, employees, and communities.

Incentive Programs and 2017 Incentive Pay Outcomes
    
Entergy Corporation believes that the 2017 incentive pay outcomes for the Named Executive Officers demonstrated the application of its 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 2017 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.

•
2017 Annual Incentive Plan Payout. For 2017, the Personnel Committee, based on a recommendation of the Finance Committee, determined that management exceeded its consolidated operational earnings per share goal of $5.05 per share by $2.17, but fell short of its consolidated operational operating cash flow goal of $3.000 billion by approximately $227 million. Based on the targets and ranges previously established by the Committee, these results resulted in a calculated EAM of 129%. This determined the maximum funding level for the plan and the maximum award, as a percentage of target, that could be received by any of the executive officers, subject to downward adjustment based on individual performance. After considering individual performance, including 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 in 2017, the Personnel Committee approved payouts of 129% 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 79% of target to 204% 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 to incentivize long-term value creation - performance units, stock options, and restricted stock. Performance under the Long-Term Performance Unit Program is measured over

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a three-year period by assessing Entergy Corporation’s total shareholder return in relation to the total shareholder return of the companies included in the Philadelphia Utility Index. Payouts, if any, are based on Entergy Corporation’s total shareholder return performance in relation to its peers and are not subject to adjustment by the Personnel Committee. Beginning with the 2018-2020 performance period, Entergy Corporation will be using a cumulative utility earnings measure, as well as relative total shareholder return to assess performance under the Long-Term Performance Unit Program. Entergy Corporation also uses stock options, which reward increases in the market value of its common stock, and restricted stock, which is an effective retention mechanism.

•
Long-Term Performance Unit Program Payout. For the three-year performance period ending in 2017, Entergy Corporation’s total shareholder return was in the third quartile, resulting in a payout of 31% of target for its executive officers. Payouts were made in shares of Entergy Corporation common stock which are required to be held by executive officers until they satisfy the executive stock ownership guidelines.

What Entergy Corporation Pays and Why

How Entergy Corporation Sets Target Pay

To develop a competitive compensation program, the Personnel Committee annually reviews compensation data from two sources:

Use of Competitive Data

The Personnel Committee uses published and private compensation survey data to develop marketplace compensation levels for Entergy Corporation’s executive officers. The data compiled by the Committee’s independent compensation consultant, Pay Governance LLC, 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. The Committee reviews:

•
For non-industry specific positions, general industry data for total cash compensation (base salary and annual incentive) since the market for talent is broader than the utility sector.
•
For management positions that are industry-specific, such as Group President, Utility Operations, data from utility companies for total cash compensation.
•
For all positions, utility market data for long-term incentives.

The survey data reviewed by the Committee cover hundreds of companies across a broad range of industries and approximately 60 investor-owned utility companies. In evaluating compensation levels against the survey data, the Committee considers only the aggregated survey data. The identities of the companies participating in the compensation survey data are not disclosed to, or considered by, the Committee in its decision-making process and, thus, are not considered material by the Committee.

The Committee uses this survey data to develop compensation opportunities that are designed to deliver total target compensation at approximately the 50th percentile of the surveyed companies in the aggregate. The survey data are the primary data used for purposes of assessing target compensation. As a result, Mr. Denault, Entergy Corporation’s Chief Executive Officer, is compensated at a higher level than the other Named Executive Officers, reflecting market practices that compensate chief executive officers at greater potential compensation levels with more pay “at risk” than other Named Executive Officers, due to the greater responsibilities and accountability required of a Chief Executive Officer. In most cases, the Committee considers its objectives to have been met if Entergy Corporation’s Chief Executive Officer and the 7 other executive officers who constitute what is referred to as the Office of the Chief Executive each has a target compensation opportunity that falls within the range of 85% - 115% of the 50th percentile of the survey data. Promoted officers or officers who are new to their roles may be transitioned into the targeted market range over time. 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, Entergy Corporation performance, and internal pay equity.

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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 as an additional point of comparison. 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. The proxy data are used to compare the compensation levels of the Named Executive Officers with the compensation levels of the corresponding top five highest paid executive officers of the companies included in the Philadelphia Utility Index, as reported in their proxy statements. The Personnel Committee uses this analysis to evaluate the overall reasonableness of Entergy Corporation’s compensation programs. The following companies were included in the Philadelphia Utility Index at the time the proxy data from the 2016 filings were compiled:
Ÿ
AES Corporation
Ÿ
El Paso Electric
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
Ÿ
Consolidated Edison Inc.
Ÿ
PG&E Corporation
Ÿ
Dominion Resources Inc.
Ÿ
Public Service Enterprise Group, Inc.
Ÿ
DTE Energy Company
Ÿ
Southern Company
Ÿ
Duke Energy Corporation
Ÿ
Xcel Energy
Ÿ
Edison International
 
 

Executive Compensation Elements

The following table summarizes the elements of total direct compensation (TDC) granted or paid to the executive officers under Entergy Corporation’s 2017 executive compensation program. The program uses a mix of fixed and variable compensation elements and provides alignment with both short- and long-term business goals through annual and long-term incentives. The Personnel Committee establishes the performance measures and ranges of performance for the variable compensation elements. An individual’s award is based primarily on corporate performance, market-based compensation levels, and individual performance.  

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Element
Key Characteristics
Why This Element Is Paid
How This Amount Is Determined
2017 Decisions
Base Salary
Fixed compensation component payable in cash. Reviewed annually and adjusted when appropriate.
Provides a base level of competitive cash compensation for executive talent.
Experience, job scope, market data, individual performance, and internal pay equity.
All of the Named Executive Officers received increases in their base salaries ranging from 1.5% to 7.3%.
Annual Incentive Awards
Variable compensation component payable in cash based on performance against goals established annually.
Motivate and reward executives for performance on key financial and operational measures during the year.
Target opportunity is determined based on job scope, market data, and internal pay equity.
 
For 2017, awards were determined based on success in meeting consolidated operational earnings per share and consolidated operational operating cash flow targets, subject to downward adjustment at the Personnel Committee’s discretion for members of the Office of the Chief Executive.
Mr. Denault's target annual incentive award for 2017 was 135% of base salary, and target awards were in the range of 40% to 70% of base salary for the other Named Executive Officers.

Strong operational and financial performance and a review of individual performance resulted in an award at 129% of target for Entergy Corporation’s Chief Executive Officer, and awards that ranged from 79% to 204% of target for the other Named Executive Officers.
Long-Term
Performance
Unit
Program
Each performance unit equals one share of Entergy Corporation’s common stock. Performance is measured at the end of a three-year performance period. Each unit also earns the equivalent of the dividends paid during the performance period. Performance units granted under the Long-Term Performance Unit Program along with accrued dividend equivalents are settled in shares of Entergy Corporation common stock.
Focuses executive officers on building long-term shareholder value and increases executive officers’ ownership of Entergy Corporation common stock.
Formulaic. payout based on Entergy Corporation’s total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index.

Beginning with the 2018-2020 performance period, payouts will be based on a cumulative utility earnings metric, as well as total shareholder return.
Performance unit grants for the 2017-2019 performance period represented approximately 39% of target TDC for Entergy Corporation’s Chief Executive Officer and approximately 21% to 31% of target for the other Named Executive Officers.

Unfavorable relative total shareholder return in 2015 and 2016, partially offset by strong relative total shareholder return in 2017, resulted in performance in the third quartile with a 6.7% TSR for the 2015-2017 performance period, yielding a payout of 31% of target for the Named Executive Officers.
Stock
Options
Non-qualified stock options are granted at fair market value, have a ten-year term, and vest over 3 years - 33 1/3% on each anniversary of the grant date.
Reward executives for absolute value creation and coupled with restricted stock provide competitive compensation, retain executive talent, and increase the executive officers’ ownership in Entergy Corporation’s common stock.
Job scope, market data, individual performance, and Entergy Corporation performance.
Stock options in 2017 represented approximately 13% of target TDC for Entergy Corporation’s Chief Executive Officer and approximately 7% to 10% for the other Named Executive Officers.

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Restricted
Stock
Awards
Restricted stock awards vest over 3 years - 33 1/3% on each anniversary of the grant date, have voting rights, and accrue dividends during the vesting period.
Coupled with stock options, align interests of executives with long-term shareholder value, provide competitive compensation, retain executive talent, and increase the executive officers’ ownership of Entergy Corporation common stock.
Job scope, market data, individual performance, and Entergy Corporation performance.
Restricted stock in 2017 represented approximately 13% of target TDC for Entergy Corporation’s Chief Executive Officer and approximately 7% - 10% for the other Named Executive Officers.

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. The Committee also considers internal pay equity; however, the Committee has not established any predetermined formula against which the base salary of one Named Executive Officer is measured against another officer or employee.

In 2017, all of the Named Executive Officers received merit increases in their base salaries ranging from approximately 1.5% to 7.3%. 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,” as well as an internal pay equity comparison.

The following table sets forth the 2016 and 2017 base salaries for the Named Executive Officers. Changes in base salaries for 2017 were effective in April 2017.
Named Executive Officer
 
2016 Base Salary
 
2017 Base Salary
A. Christopher Bakken, III
 
$605,000
 
$620,125
Marcus V. Brown
 
$605,000
 
$630,000
Leo P. Denault
 
$1,200,000
 
$1,230,000
Haley R. Fisackerly
 
$350,000
 
$355,300
Andrew S. Marsh
 
$559,408
 
$600,000
Phillip R. May, Jr.
 
$356,650
 
$366,150
Sallie T. Rainer
 
$319,475
 
$328,275
Charles L. Rice, Jr.
 
$280,424
 
$286,424
Richard C. Riley
 
$335,000
 
$344,200
Roderick K. West
 
$659,120
 
$675,598

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 are members of the Office of the Chief Executive under the Annual Incentive Plan. Once the EAM has been determined, individual awards for the Office of the Chief

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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. For 2017, the target Annual Incentive Plan opportunities for each of the Named Executive Officers, expressed as a percentage of the officer’s base salary, were:

•
135% for Mr. Denault;
•
70% for Mr. Bakken, Mr. Brown, Mr. Marsh, and Mr. West;
•
60% for Mr. May; and
•
40% for Mr. Fisackerly, Ms. Rainer, Mr. Rice, and Mr. Riley.

The target opportunities established for these officers were comparable to the target opportunities historically set for these positions and levels of responsibility. Target opportunities for the Named Executive Officers who are members of the Office of the Chief Executive are established by the Personnel Committee, and these Named Executive Officers may earn a maximum payout ranging from 0% to 200% of their target opportunity, calculated as described in the table below.

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 4. At December 31, 2017, Mr. Denault held a Level 1 position, Messrs. Bakken, Brown, Marsh, and West held positions in Level 2, Mr. May held a Level 3 position, and the remaining Named Executive Officers held positions in Level 4. 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.

Each year the Personnel Committee reviews the performance measures used to determine the EAM pool. In December 2016, the Personnel Committee decided to retain consolidated operational earnings per share and consolidated operational operating cash flow, each measure weighted equally, as the performance measures for determining the EAM pool. The Committee considered a variety of other potential measures, but determined that consolidated operational earnings per share and consolidated operational operating cash flow continued to be the best metrics to use because, among other things, they are objective measures that Entergy Corporation’s investors consider to be important in evaluating its financial performance and because Entergy Corporation’s goals in that regard are broadly communicated both internally and externally. This provides both discipline and transparency that the Committee believes are important objectives of any well designed incentive compensation plan.

The Personnel Committee also engages in a rigorous process each year to establish the target achievement levels for each of the EAM performance measures 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, taking into consideration the applicable business environment and specific challenges facing it. 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 Committee also reviews the effects on plan results of various risks and opportunities that are recognized at the time the plan is set, to assure that targets that are determined based on the plan reflect an appropriate balance of risks and opportunities. The Committee further confirms that the earnings target it approves is aligned with the earnings guidance that will be communicated to the financial markets, thus ensuring that the internal earnings target set for purposes of Entergy Corporation’s incentive compensation plans is aligned with the external expectations set and communicated to Entergy Corporation’s shareholders.

In January 2017, after full Board review of management’s 2017 financial plan for Entergy Corporation and engaging in the process discussed above, the Committee determined the Annual Incentive Plan targets to be used for purposes of determining Annual Incentive Plan awards for 2017. In keeping with its past practice, the Committee also determined that for purposes of measuring performance against such targets, the Committee would exclude the effect on reported results of any major storms that may occur during the year. This exclusion was viewed by the Committee

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as appropriate because although Entergy Corporation includes estimates for storm costs in its financial plan, it does not include estimates for a major storm event, such as a hurricane. The Committee also approved exclusions from reported results, for purposes of calculating achievement levels, for the impact of certain longstanding unresolved litigation relating to the System Agreement among the Utility operating companies, and for the potential effects of changes in tax laws, given the possibility that significant unanticipated changes in tax laws might be enacted during the year that could impact reported results. The Committee believed that each of these adjustments was appropriate because of the significant uncertainty around each such item and management’s inability to influence any of the related outcomes.
 
In determining the targets to set for 2017, the Committee reviewed anticipated drivers for consolidated operational earnings per share and consolidated operational operating cash flow for 2017 as set forth in Entergy Corporation’s financial plan and as reflected in its published earnings guidance. Under the plan, consolidated operational earnings per share were expected to decline from 2016 results due primarily to the significant impact on 2016 operational results of certain tax benefits and, to a lesser extent, favorable weather, which were not anticipated to recur in 2017. Together, these factors accounted for $2.06 of consolidated operational earnings per share for 2016. Under the plan, consolidated operational operating cash flow was expected to increase slightly in 2017 from 2016 results.

In evaluating the proposed targets, the Committee considered the potential impact on consolidated operational earnings per share and consolidated operational operating cash flow of certain risks and opportunities, including differences in wholesale energy prices and capacity factors at Entergy Wholesale Commodities, utility sales, operations and maintenance costs, interest expense, and certain tax and regulatory risks. 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.

After adjusting to eliminate the impact of weather and tax benefits, the 2017 plan targets required management to achieve (i) slight growth in utility operational earnings despite higher nuclear and pension costs and the absence of certain favorable items from 2016 and (ii) modest growth in Entergy Wholesale Commodities operational earnings, despite an expectation for further declines in wholesale energy and capacity revenues due in part to the sale of FitzPatrick in the first quarter of 2017. While the resulting earnings target represented a decline from 2016 operational results, the Committee recognized that in addition to the favorable weather and tax items that were not expected to recur in 2017, management would be challenged in 2017 by significantly higher nuclear costs as they executed on its nuclear strategic plan. Thus, the Committee concluded, based on a careful review of the overall plan, that the targets derived from the plan challenged management appropriately to deliver growth in Entergy Corporation’s core business while continuing to manage the significant risks at Entergy Wholesale Commodities and represented an appropriate balancing of Entergy Corporation’s business risks and opportunities for 2017.

The following table shows the resulting Annual Incentive Plan targets established by the Personnel Committee in January 2017, and 2017 results:
Annual Incentive Plan Targets and Results
 
Performance Goals(1)
 
 
Minimum
Target
Maximum
2017 Results
Consolidated Operational Earnings Per Share
$4.55
$5.05
$5.55
$7.22
Consolidated Operational Operating Cash Flow ($ billion)
$2.600
$3.000
$3.400
$2.773
EAM as % of Target
25%
100%
200%
129%

(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.


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In January 2018, 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 the consolidated operational earnings per share and consolidated operational operating cash flow results for 2017, including primary factors explaining how those results compared to the 2017 business plan and Annual Incentive Plan targets. Consolidated operational earnings per share exceeded the operational earnings per share goal of $5.05 per share set at the beginning of the year by $2.17, due in large part to a non-cash restructuring tax benefit, but management fell short of achieving its consolidated operational operating cash flow goal of $3.000 billion by approximately $227 million, leading to a calculated EAM of 129%. Operational results excluded the impact of certain special items that were excluded from as-reported (GAAP) earnings per share and operating cash flow to determine consolidated operational earnings per share and consolidated operational operating cash flow, including asset impairments and related write-offs at Entergy Wholesale Commodities related to Entergy Corporation’s 2016 decision to close two nuclear generating plants, and certain costs associated with nuclear plant closings, and charges recorded at the end of 2017 relating to the impact of recently enacted federal income tax law changes. Consistent with determinations made by the Personnel Committee when the targets were set, adjustments were made to the reported results to exclude the impact of Hurricane Harvey and the resolution of certain longstanding System Agreement litigation, but these adjustments had only a negligible impact on the calculated EAM.

     The Committee reviewed certain sensitivities as part of its review of the calculation of the EAM and noted that Entergy Corporation far exceeded its consolidated operational earnings per share goal in 2017, as noted, due in large part to a restructuring tax benefit, partially offset by unfavorable weather at the utility, and that unfavorable weather at the utility also accounted for approximately $128 million of the $227 million shortfall in consolidated operational operating cash flow. Had the EAM been calculated to exclude both the impact of the restructuring tax benefit and unfavorable weather, the calculated EAM would have been 140%. This indicated that the underlying performance of the core business, without regard to the impact of tax items and weather, was significantly stronger than implied by the calculated EAM. However, consistent with the plan design, the Personnel Committee did not make any adjustments for these factors to the consolidated operational earnings per share and consolidated operational operating cash flow results to determine the EAM for 2017. The Committee also noted that its utility, parent, and other adjusted earnings of $4.57 per share for 2017 were slightly above the high end of the guidance range Entergy Corporation had provided to investors at the beginning of the year for this extremely important measure of its core utility earnings.

In determining individual executive officer awards under the Annual Incentive Plan, for Entergy Corporation’s Chief Executive Officers and the Named Executive Officers, who are members of the Office of the Chief Executive, the Committee considered individual performance and, in particular, whether there were additional factors beyond those captured by the EAM measures that should be taken into account in determining whether to exercise negative discretion to reduce awards below the levels determined by the EAM. In determining the extent of negative discretion, if any, that it would exercise with respect to each executive officer, the Committee considered the executive’s key accountabilities and accomplishments, and individual performance executing on Entergy Corporation’s strategies in 2017. Based on these considerations, the Committee decided to award a payout equal to the EAM, or 129% of target, for Entergy Corporation’s Chief Executive Officer and the other 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 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 79% of target to 204% of target for the Named Executive Officers who are not members of the Office of the Chief Executive.


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Based on the foregoing evaluation of management performance, the Personnel Committee approved the following Annual Incentive Plan payouts to each Named Executive Officer for 2017:
Named Executive Officer
Base Salary
Target as Percentage of Base Salary
Payout as Percentage of Target
2017 Annual
Incentive Award
A. Christopher Bakken, III
$620,125
70%
129%
$559,973
Marcus V. Brown
$630,000
70%
129%
$568,890
Leo P. Denault
$1,230,000
135%
129%
$2,142,045
Haley R. Fisackerly
$355,300
40%
119%
$169,123
Andrew S. Marsh
$600,000
70%
129%
$541,800
Phillip R. May, Jr.
$366,150
60%
137%
$300,000
Sallie T. Rainer
$328,275
40%
119%
$156,259
Charles L. Rice, Jr.
$286,424
40%
79%
$91,000
Richard C. Riley
$344,200
40%
204%
$280,661
Roderick K. West
$675,598
70%
129%
$610,065

 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 employment 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, 2018, and 2019, subject to his continued employment, Mr. Bakken will receive a cash bonus equal to 30% of his base salary as of May 1, 2016. This plan does not allow for accelerated or prorated payout upon termination of any kind. The three-year coverage period and percentage of base salary payable under the plan are consistent with the terms of participation of other senior nuclear officers who participate in this plan. In May 2017, Mr. Bakken received a cash bonus of $181,500 which equaled 30% of his May 1, 2016, base salary of $605,000.

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 its long-term incentive compensation programs, Entergy Corporation uses a mix of performance units, restricted stock, and stock options. Performance units are used to deliver more than a majority of the total target long-term incentive awards. For periods through the end of 2017, performance units reward the Named Executive Officers on the basis of total shareholder return, which is a measure of stock price appreciation and dividend payments, in relation to the companies in the Philadelphia Utility Index. Beginning with the 2018-2020 performance period, a cumulative utility earnings metric has been 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. Restricted stock ties the executive officers’ long-term financial interest to the long-term financial interests of Entergy Corporation’s shareholders. Stock options provide a direct incentive to increase the value of Entergy Corporation’s common stock. 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.

The performance units for the 2015-2017 performance period were awarded under the 2011 Equity Ownership Plan and Long-Term Cash Incentive Plan (the “2011 Equity Ownership Plan”) and the performance units for the

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2016-2018 and 2017-2019 performance periods and all of the shares of restricted stock and stock options granted to the Named Executive Officers in 2017 were granted pursuant to the 2015 Equity Ownership Plan (the “2015 Equity Ownership Plan,” and together with the 2011 Equity Ownership Plan (the “Equity Ownership Plans”). The Equity Ownership Plans require 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

Entergy Corporation issues performance unit awards to the Named Executive Officers under its Long-Term Performance Unit Program. Each performance unit 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 Personnel Committee sets payout opportunities for the program at the outset of each performance period, and the program is structured to reward Named Executive Officers only if performance goals approved by the Personnel Committee are met. The Personnel Committee has no discretion to make awards if minimum performance goals are not achieved.

The performance units granted under the Long-Term Performance Unit Program and accrued dividends on any shares earned during the performance period are settled in shares of Entergy Corporation common stock rather than cash. No shares are issued, including shares attributable to accrued dividends, unless performance goals are achieved. All shares paid out under the Long-Term Performance Unit Program are required to be retained by the 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. Entergy Corporation measures performance by assessing Entergy Corporation’s total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index, which Entergy Corporation refers to as it peer companies. 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 measure of performance 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.

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 2017, eligible participants were participating in the 2015-2017, 2016-2018, and 2017-2019 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 2015-2017, 2016-2018, and 2017-2019 performance periods.

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Named Executive Officer
2015-2017
Target
2016-2018
Target
2017-2019
 Target
A. Christopher Bakken, III (1)
3,639
7,289
8,300
Marcus V. Brown
6,550
8,200
8,300
Leo P. Denault
33,100
41,700
48,700
Haley R. Fisackerly
1,450
1,800
1,850
Andrew S. Marsh
6,550
8,200
8,300
Phillip R. May, Jr.
2,050
2,700
3,150
Sallie T. Rainer
1,450
1,800
1,850
Charles L. Rice, Jr.
1,450
1,800
1,850
Richard C. Riley
1,450
1,800
1,850
Roderick K. West
6,550
8,200
8,300

(1)
As a new hire in 2016, Mr. Bakken received pro-rated target award opportunities for the 2015-2017 and 2016-2018 performance periods.

The range of potential payouts for the 2015-2017, 2016-2018, and 2017-2019 performance periods under the program is shown below.
Performance Level
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
    
For all performance periods, there is no payout for performance that falls within the lowest quartile of performance of the peer companies, and for top quartile performance a maximum payout of 200% of target is earned. Payouts between minimum and target and between target and maximum are calculated by interpolating between the performance of the company at the top of the fourth quartile of performance of the peer companies and the median or between the median and the performance of the company at the bottom position of the top quartile of performance of the peer companies, respectively.

Payout for the 2015-2017 Performance Period. In January 2018, the Committee reviewed Entergy Corporation’s total shareholder return for the 2015-2017 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 2015-2017 performance period similar to that discussed above. As recommended by the Finance Committee, the Personnel Committee concluded that Entergy Corporation’s relative total shareholder return for the 2015-2017 performance period fell in the bottom of the third quartile, yielding a payout of 31% of target for the Named Executive Officers.


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Named Executive Officer
2015-2017
Target
Number of Shares Issued
Value of Shares Actually Issued(1)
Grant Date Fair Value
A. Christopher Bakken, III(2)
3,639
1,212
$95,154
$360,334
Marcus V. Brown
6,550
2,287
$179,552
$648,581
Leo P. Denault
33,100
11,554
$907,105
$3,277,562
Haley R. Fisackerly
1,450
506
$39,726
$143,579
Andrew S. Marsh
6,550
2,287
$179,552
$648,581
Phillip R. May, Jr.
2,050
716
$56,213
$202,991
Sallie T. Rainer
1,450
506
$39,726
$143,579
Charles L. Rice, Jr.
1,450
506
$39,726
$143,579
Richard C. Riley
1,450
506
$39,726
$143,579
Roderick K. West
6,550
2,287
$179,552
$648,581

(1)
Value determined based on the closing price of Entergy Corporation’s common stock on January 17, 2018 ($78.51), the date the Personnel Committee certified the 2015-2017 performance period results.
(2)
As a new hire in 2016, Mr. Bakken received pro-rated target award opportunities for the 2015-2017 performance period.

Stock Options and Restricted Stock

Entergy Corporation grants stock options and restricted stock as a long-term incentive to its executive officers. As previously discussed, the Personnel Committee considers several factors in determining the number of stock options and shares of restricted stock it will grant to the Named Executive Officers, including Entergy Corporation and individual performance, internal pay equity, prevailing market practice, targeted long-term value created by the use of stock options and restricted stock, and the potential dilutive effect of stock option and restricted stock grants. Of these factors, the Committee’s assessment of individual performance of each Named Executive Officer is the most important factor in determining the number of shares of restricted stock and stock options awarded, except with respect to the Chief Executive Officer for whom comparative market data is the most important factor. The Committee, in consultation with Entergy Corporation’s Chief Executive Officer, reviews each of the 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 2017. The exercise price for each option was $70.53, 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
37,600
5,200
Marcus V. Brown
44,000
6,100
Leo P. Denault
179,400
17,000
Haley R. Fisackerly
7,600
850
Andrew S. Marsh
44,000
6,100
Phillip R. May, Jr.
10,500
1,100
Sallie T. Rainer
7,800
900
Charles L. Rice, Jr.
3,900
550
Richard C. Riley
8,000
1,000
Roderick K. West
29,200
3,200

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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 2017 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.
2017 Perquisites
Corporate aircraft usage, annual physical exams, relocation assistance, and event tickets. The Office of the Chief Executive members 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 2017 with club dues and tax gross up payments on some perquisites.

For additional information regarding perquisites, see the “All Other Compensation” column in the 2017 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 an 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 its 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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Compensation Arrangements

The Personnel Committee believes that retention and transitional compensation arrangements are an important part of overall compensation. The Committee believes that these arrangements 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 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 each of the Named Executive Officers is 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 Entergy Corporation’s 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, will not receive any tax gross up payments on any severance benefits received under this plan. For more information regarding the System Executive Continuity Plan, see “2017 Potential Payments Upon Termination or Change in Control-System Executive Continuity Plan.”

In certain cases, the 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.

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 “2017 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 will not 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 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.


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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 Securities Exchange Act of 1934 (the Exchange Act), including the members of the Office of the Chief Executive. Under the policy, which goes beyond the requirements of Sarbanes-Oxley Act of 2002 (Sarbanes-Oxley), the 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.

The amount the 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, it will seek to recover any compensation received by its Chief Executive Officer and Chief Financial Officer that is required to be reimbursed under Sarbanes-Oxley.

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 those of shareholders. Annually, the Personnel Committee monitors the executive officers’ compliance with these guidelines.

Entergy Corporation’s 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 ensure 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 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, except for stock options granted before January 1, 2014, as to which the executive officer must retain at least 75% of the after-tax net shares until the earlier of achievement of the stock ownership guidelines or five years from the date of exercise.

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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 the policy by permitting shares to be bought or sold without pre-approval or when trading is restricted.

Entergy Corporation also prohibits its directors and executive officers, including the Named Executive Officers, from pledging any Entergy Corporation securities or entering into margin accounts involving Entergy Corporation securities. These transactions are prohibited 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 has also adopted an anti-hedging policy that prohibits officers, directors, and employees from entering into hedging or monetization transactions involving Entergy Corporation 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 common stock or transactions involving “short-sales” of Entergy Corporation’s common stock. The Board adopted this policy to require officers, directors, and employees to continue to own Entergy Corporation’s common stock with the full risks and rewards of ownership, thereby ensuring continued alignment of their objectives with those of Entergy Corporation’s other shareholders.

How Entergy Corporation Makes Compensation Decisions

Role of the Personnel Committee

The Personnel Committee has overall responsibility for approving the compensation program for the Named Executive Officers and makes all final compensation decisions regarding Entergy Corporation’s Named Executive Officers. The Committee works with Entergy Corporation’s executive management to ensure that the compensation policies and practices are consistent with its 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. Annually, management presents the Personnel Committee with the proposed compensation model for the following year, including the compensation elements, mix of elements, and measures for each element, and consults with Entergy Corporation’s Chief Executive Officer on recommended compensation for senior executives. The Committee evaluates executive pay each year to ensure that Entergy Corporation’s compensation policies and practices are consistent with its philosophy. The Personnel Committee is responsible for, among its other duties, the following actions related to the Named Executive Officers:

•
developing and implementing compensation policies and programs for hiring, evaluating, and setting compensation for executive officers, including any employment agreement with an executive officer;
•
evaluating the performance of Entergy Corporation’s Chairman and Chief Executive Officer; and
•
reporting, at least annually, to the Board on succession planning, including succession planning for the Chief Executive Officer.

Role of the Chief Executive Officer

The Personnel Committee solicits recommendations from Entergy Corporation’s Chief Executive Officer with respect to compensation decisions for the other Named Executive Officers who are members of Entergy Corporation’s Office of the Chief Executive. Entergy Corporation’s Chief Executive Officer provides the Personnel Committee with an assessment of the performance of each of these Named Executive Officers and recommends compensation levels to be awarded to each of them. In addition, the Committee may request that the Chief Executive

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Officer provide management feedback and recommendations on changes in the design of compensation programs, such as special retention plans or changes in incentive program structure. However, the Chief Executive Officer does not play any role with respect to any matter affecting his own compensation, nor does he have any role determining or recommending the amount or form of director compensation. The Personnel Committee also relies on the recommendations of Entergy Corporation’s Senior Vice President, Human Resources with respect to compensation decisions, policies, and practices.

The 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 2017, Mr. Denault attended 9 meetings of the Personnel Committee.

Role of the Compensation Consultant

Entergy Corporation’s Personnel Committee has the sole authority for the appointment, compensation, and oversight of its outside compensation consultant. The Committee conducts an annual review of the compensation consultant, and in 2017, it retained Pay Governance LLC as its independent compensation consultant to assist it in, among other things, evaluating different compensation programs and developing market data to assess Entergy Corporation’s compensation programs. Also in 2017, the Corporate Governance Committee retained Pay Governance to review and perform a competitive analysis of non-employee director compensation.

During 2017, Pay Governance assisted the 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 2017.

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. In 2017, the Personnel Committee’s independent compensation consultant, Pay Governance, did not provide any services to Entergy Corporation other than its services to the Personnel Committee and the Corporate Governance Committee in connection with Entergy Corporation’s non-employee director compensation program. Annually, the 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 executive compensation consultant’s independence. The Committee also assesses Pay Governance’s independence under NYSE rules and has concluded that no conflict of interests exists that would prevent Pay Governance from independently advising the Personnel Committee.

Tax and Accounting Considerations

Section 162(m) of the Internal Revenue Code (the Code) limits the tax deductibility by a publicly-held corporation of compensation in excess of $1 million paid to the Chief Executive Officer and any of its other Section 162(m) covered employees. Historically, an exception was provided for compensation that was “performance-based compensation” within the meaning of Section 162(m).  Effective as of January 1, 2018, this exception no longer applies, other than with respect to certain grandfathered arrangements. In structuring the compensation packages that are provided to the Named Executive Officers, the Personnel Committee takes into account the tax effects of Section 162(m) and considers the financial accounting consequences. However, the Personnel Committee and the Board believe that it is in the best interest of Entergy Corporation that the Personnel Committee retains the discretion

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to make compensation awards, whether or not deductible. This flexibility is necessary to foster achievement of performance goals established by the Personnel Committee, as well as other corporate goals that the Committee deems important to Entergy Corporation’s success, such as encouraging employee retention and rewarding achievement of key corporate goals.


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

2017 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, 2017, and to the extent required by SEC executive compensation disclosure rules, the fiscal years ended December 31, 2016 and 2015.  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
 
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
 
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
 
2017
 

$1,221,346

 

$—

 

$4,676,190

 

$1,173,276

 

$2,142,045

 

$3,819,500

 

$125,863

 

$13,158,220

Chairman of the
 
2016
 

$1,191,462

 

$—

 

$4,632,276

 

$1,235,800

 

$2,154,600

 

$4,166,800

 

$97,786

 

$13,478,724

Board and CEO -
 
2015
 

$1,153,385

 

$—

 

$4,356,362

 

$1,004,080

 

$1,681,875

 

$4,802,400

 

$88,795

 

$13,086,897

Entergy Corp.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Haley R. Fisackerly
 
2017
 

$354,451

 

$—

 

$192,041

 

$49,704

 

$169,123

 

$406,300

 

$35,724

 

$1,207,343

CEO - Entergy
 
2016
 

$320,067

 

$—

 

$229,752

 

$49,580

 

$168,000

 

$268,600

 

$34,243

 

$1,070,242

Mississippi
 
2015
 

$320,131

 

$—

 

$219,994

 

$51,345

 

$190,000

 

$102,300

 

$43,987

 

$927,757

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


Andrew S. Marsh
 
2017
 

$588,291

 

$—

 

$1,022,853

 

$287,760

 

$541,800

 

$801,900

 

$51,647

 

$3,294,251

Executive Vice
 
2016
 

$553,284

 

$—

 

$1,144,648

 

$333,000

 

$509,061

 

$593,700

 

$47,484

 

$3,181,177

President and CFO -
 
2015
 

$532,245

 

$—

 

$2,600,401

 

$273,840

 

$508,308

 

$670,200

 

$39,131

 

$4,624,125

Entergy Corp.,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Arkansas,
 

























Entergy Louisiana,
 

























Entergy Mississippi,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy New
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Orleans, Entergy
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


Texas
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Phillip R. May, Jr.
 
2017
 

$363,410

 

$—

 

$302,493

 

$68,670

 

$300,000

 

$503,400

 

$26,981

 

$1,564,954

CEO - Entergy
 
2016
 

$353,690

 

$—

 

$326,988

 

$71,040

 

$224,690

 

$600,000

 

$26,018

 

$1,602,426

Louisiana
 
2015
 

$344,035

 

$—

 

$279,406

 

$57,050

 

$315,000

 

$288,100

 

$25,970

 

$1,309,561


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(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
 
Sallie T. Rainer
 
2017
 

$325,737

 

$—

 

$195,567

 

$51,012

 

$156,259

 

$435,900

 

$35,785

 

$1,200,260

CEO - Entergy
 
2016
 

$316,003

 

$—

 

$229,752

 

$49,580

 

$153,348

 

$346,300

 

$53,797

 

$1,148,780

Texas
 
2015
 

$304,783

 

$—

 

$211,004

 

$43,358

 

$190,000

 

$189,100

 

$41,565

 

$979,810

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Charles L. Rice, Jr.
 
2017
 

$284,681

 

$—

 

$170,882

 

$25,506

 

$91,000

 

$221,200

 

$30,842

 

$824,111

CEO - Entergy New
 
2016
 

$276,998

 

$—

 

$229,752

 

$49,580

 

$67,302

 

$177,600

 

$33,807

 

$835,039

Orleans
 
2015
 

$266,752

 

$—

 

$211,004

 

$51,345

 

$173,000

 

$104,500

 

$33,416

 

$840,017

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Richard C. Riley
 
2017
 

$341,723

 

$—

 

$202,620

 

$52,320

 

$280,661

 

$437,700

 

$38,695

 

$1,353,719

CEO - Entergy
 
2016
 

$325,020

 

$—

 

$226,224

 

$34,780

 

$167,500

 

$277,900

 

$102,112

 

$1,133,536

Arkansas
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Roderick K. West
 
2017
 

$670,876

 

$—

 

$818,316

 

$190,968

 

$610,065

 

$867,200

 

$52,220

 

$3,209,645

Group President
 
2016
 

$654,514

 

$—

 

$1,116,424

 

$303,400

 

$461,384

 

$601,000

 

$73,706

 

$3,210,428

Utility Operations of
 
2015
 

$638,876

 

$—

 

$1,071,111

 

$262,430

 

$607,677

 

$543,900

 

$71,790

 

$3,195,784

Entergy Corp.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

(1)
Mr. Bakken was named Executive Vice President and Chief Nuclear Officer in April 2016. Mr. Brown was not a Named Executive Officer in 2015. Mr. Riley was named Chief Executive Officer, Entergy Arkansas in May 2016.
(2)
The amounts in column (c) represent the actual base salary paid to the Named Executive Officers.  The 2017 changes in base salaries noted in the Compensation Discussion and Analysis were effective in April 2017.
(3)
The amount in column (d) in 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 represents a cash sign-on bonus paid to Mr. Bakken in connection with his commencement of employment with Entergy Corporation.
(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 Equity Ownership Plans, each calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures.  The grant date fair value of the restricted stock and 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 performance units is based on the probable outcome of the applicable performance conditions, 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.  If the highest achievement level is attained, the maximum amounts that will be received with respect to the performance units granted in 2017 are as follows:  Mr. Bakken, $1,170,798; Mr. Brown, $1,170,798; Mr. Denault, $6,869,622; Mr. Fisackerly, $260,961; Mr. Marsh, $1,170,798; Mr. May, $444,339; Ms. Rainer, $260,961; Mr. Rice, $260,961; Mr. Riley, $260,961; and Mr. West, $1,170,798. 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 Equity Ownership Plans calculated in accordance with FASB ASC Topic 718.  For a discussion of the relevant assumptions used in valuing these awards, see Note 12 to the financial statements.
(6)
The amounts in column (g) represent cash payments made under the Annual Incentive Plan.

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(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 “2017 Pension Benefits”).  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 “2017 Non-qualified Deferred Compensation”).
(8)
The amounts in column (i) for 2017 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.  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

$16,200


$—


$11,887


$1,299


$85,108


$114,494

Marcus V. Brown

$—


$35,517


$7,482


$—


$270


$43,269

Leo P. Denault

$11,340


$93,206


$7,482


$—


$13,835


$125,863

Haley R. Fisackerly

$11,340


$7,907


$2,306


$4,082


$10,089


$35,724

Andrew S. Marsh

$11,139


$35,517


$4,991


$—


$—


$51,647

Phillip R. May, Jr.

$11,340


$9,673


$5,279


$—


$689


$26,981

Sallie T. Rainer

$11,340


$7,696


$6,477


$2,952


$7,320


$35,785

Charles L. Rice, Jr.

$11,340


$6,849


$4,874


$2,637


$5,142


$30,842

Richard C. Riley

$11,340


$8,756


$5,040


$4,832


$8,727


$38,695

Roderick K. West

$11,340


$38,270


$2,610


$—


$—


$52,220


Perquisites and Other Compensation

The amounts set forth in column (i) include perquisites and other personal benefits that Entergy Corporation provides to its Named Executive Officers as part of providing a competitive executive compensation program and for employee retention. The following perquisites were provided to the Named Executive Officers in 2017.
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
X
Leo P. Denault
 
X
 
X
 
Haley R. Fisackerly
 
 
X
X
 
Andrew S. Marsh
 
 
 
X
 
Phillip R. May, Jr.
 
 
 
 
X
Sallie T. Rainer
 
 
X
 
 
Charles L. Rice, Jr.
 
 
X
 
 
Richard C. Riley
 
 
X
 
 
Roderick K. West
 
 
 
X
 

For security and business reasons, Entergy Corporation permits its Chief Executive Officer 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

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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, purchase and sale of homes, and transportation of household goods. In connection with his employment, and in accordance with its relocation policies and pursuant to certain additional relocation benefits including the purchase of his home, Entergy Corporation paid $77,897 in relocation expenses for Mr. Bakken in 2017. The relocation assistance amounts reported above represent the amounts paid to Entergy Corporation’s relocation service provider or Mr. Bakken, as applicable.

None of the other perquisites referenced above exceeded $25,000 for any of the other Named Executive Officers.
 
2017 Grants of Plan-Based Awards

The following table summarizes award grants during 2017 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
 
1/26/17
 
$-
$434,088
$868,175
 
 
 
 
 
 
 
 
 
 
 
 
Bakken, III
 
1/26/17
 
 
 
 
 
2,075

8,300

16,600

 
 
 
 
 
 
 
$592,620
 
 
1/26/17
 
 
 
 
 


 


 
5,200

 
 
 
 
 
$366,756
 
 
1/26/17
 
 
 
 
 
 
 
 
 
 
 
37,600

 
$70.53
 
$245,904
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Marcus V.
 
1/26/17
 
$-
$441,000
$882,000
 
 
 
 
 
 
 
 
 
 
 
 
Brown
 
1/26/17
 
 
 
 
 
2,075

8,300

16,600

 
 
 
 
 
 
 
$592,620
 
 
1/26/17
 
 
 
 
 
 
 
 
 
6,100

 
 
 
 
 
$430,233
 
 
1/26/17
 
 
 
 
 
 
 
 
 
 
 
44,000

 
$70.53
 
$287,760
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Leo P.
 
1/26/17
 
$-
$1,660,500
$3,321,000
 
 
 
 
 
 
 
 
 
 
 
 
Denault
 
1/26/17
 
 
 
 
 
12,175

48,700

97,400

 
 
 
 
 
 
 
$3,477,180
 
 
1/26/17
 
 
 
 
 
 
 
 
 
17,000

 
 
 
 
 
$1,199,010
 
 
1/26/17
 
 
 
 
 
 
 
 
 
 
 
179,400

 
$70.53
 
$1,173,276



474
Table of Contents

 
 
 
 
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)
Haley R.
 
1/26/17
 
$-
$142,120
$284,240
 
 
 
 
 
 
 
 

 
 
 
 
Fisackerly
 
1/26/17
 
 
 
 
 
463

1,850

3,700

 
 
 
 
 
 
 
$132,090
 
 
1/26/17
 
 
 
 
 
 
 
 
 
850

 
 
 
 
 
$59,951
 
 
1/26/17
 
 
 
 
 
 
 
 
 
 
 
7,600

 
$70.53
 
$49,704
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Andrew S.
 
1/26/17
 
$-
$420,000
$840,000









 
 
 
 
 
 
Marsh
 
1/26/17
 




2,075

8,300

16,600




 
 
 
 
 
$592,620
 
 
1/26/17
 
 
 
 
 
 
 
 
 
6,100

 
 
 
 
 
$430,233
 
 
1/26/17
 
 
 
 
 
 
 
 
 
 
 
44,000

 
$70.53
 
$287,760
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Phillip R.
 
1/26/17
 
$-
$219,690
$439,380
 
 
 
 
 
 
 
 
 
 
 
 
May, Jr.
 
1/26/17
 
 
 
 
 
788

3,150

6,300

 
 
 
 
 
 
 
$224,910
 
 
1/26/17
 
 
 
 
 
 
 
 
 
1,100

 
 
 
 
 
$77,583
 
 
1/26/17
 
 
 
 
 
 
 
 
 
 
 
10,500

 
$70.53
 
$68,670
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sallie T.
 
1/26/17
 
$-
$131,310
$262,620
 
 
 
 
 
 

 
 

 
 
 
 
Rainer
 
1/26/17
 
 
 
 
 
463

1,850

3,700

 
 
 
 
 
 
 
$132,090
 
 
1/26/17
 
 
 
 
 
 
 
 
 
900

 
 
 
 
 
$63,477
 
 
1/26/17
 
 
 
 
 
 
 
 
 
 
 
7,800

 
$70.53
 
$51,012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Charles L.
 
1/26/17
 
$-
$114,570
$229,140
 
 
 
 
 
 
 
 
 
 
 
 
Rice, Jr.
 
1/26/17
 
 
 
 
 
463

1,850

3,700

 
 
 
 
 
 
 
$132,090
 
 
1/26/17
 
 
 
 
 
 
 
 
 
550

 
 
 
 
 
$38,792
 
 
1/26/17
 
 
 
 
 
 
 
 
 
 
 
3,900

 
$70.53
 
$25,506
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Richard C.
 
1/26/17
 
$-
$137,680
$275,360
 
 
 
 
 
 
 
 
 
 
 
 
Riley
 
1/26/17
 
 
 
 
 
463

1,850

3,700

 
 
 
 
 
 
 
$132,090
 
 
1/26/17
 
 
 
 
 
 
 
 
 
1,000

 
 
 
 
 
$70,530
 
 
1/26/17
 
 
 
 
 
 
 
 
 
 
 
8,000

 
$70.53
 
$52,320
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Roderick K.
 
1/26/17
 
$-
$472,919
$945,837
 
 
 
 
 
 
 
 
 
 
 
 
West
 
1/26/17
 
 
 
 
 
2,075

8,300

16,600

 
 
 
 
 
 
 
$592,620
 
 
1/26/17
 
 
 
 
 
 
 
 
 
3,200

 
 
 
 
 
$225,696
 
 
1/26/17
 
 
 
 
 
 
 
 
 
 
 
29,200

 
$70.53
 
$190,968

(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.

475
Table of Contents

(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.  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.  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, 2019.)  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 Ownership 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 Ownership Plan.
(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 2017 Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value.

2017 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, 2017.
 
 
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
 
—

 
37,600(1)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8,300(4)
 
$675,537
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7,289(5)
 
$593,252
 
 
 
 
 
 
 
 
 
 
 
 
5,200(6)
 
$423,228
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
30,000(9)
 
$2,441,700
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Marcus V. Brown
 
—

 
44,000(1)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
15,000

 
30,000(2)

 
 
 
$70.56
 
1/28/2026
 
 
 
 
 
 
 
 
 
 
16,000

 
8,000(3)

 
 
 
$89.90
 
1/29/2025
 
 
 
 
 
 
 
 
 
 
30,500

 
—

 
 
 
$63.17
 
1/30/2024
 
 
 
 
 
 
 
 
 
 
16,000

 
—

 
 
 
$64.60
 
1/31/2023
 
 
 
 
 
 
 
 
 
 
4,600

 
—

 
 
 
$71.30
 
1/26/2022
 
 
 
 
 
 
 
 


476
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
 
 
(#)
 
(#)
 
(#)
 
($)
 
 
 
(#)
 
($)
 
(#)
 
($)
 
 
2,800

 
—

 
 
 
$72.79
 
1/27/2021
 
 
 
 
 
 
 
 
 
 
7,500

 
—

 
 
 
$77.10
 
1/28/2020
 
 
 
 
 
 
 
 
 
 
4,300

 
—

 
 
 
$108.20
 
1/24/2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8,300(4)
 
$675,537
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8,200(5)
 
$667,398
 
 
 
 
 
 
 
 
 
 
 
 
6,100(6)
 
$496,479
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,267(7)
 
$347,291
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,667(8)
 
$135,677
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Leo P. Denault
 
—

 
179,400(1)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
55,666

 
111,334(2)

 
 
 
$70.56
 
1/28/2026
 
 
 
 
 
 
 
 
 
 
58,666

 
29,334(3)

 
 
 
$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
 
 
 
 
 
 
 
 
 
 
45,000

 
—

 
 
 
$77.53
 
1/29/2019
 
 
 
 
 
 
 
 
 
 
50,000

 
—

 
 
 
$108.20
 
1/24/2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
48,700(4)
 
$3,963,693
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
41,700(5)
 
$3,393,963
 
 
 
 
 
 
 
 
 
 
 
 
17,000(6)
 
$1,383,630
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10,467(7)
 
$851,909
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,000(8)
 
$325,560
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Haley R. Fisackerly
 
—

 
7,600(1)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
2,233

 
4,467(2)

 
 
 
$70.56
 
1/28/2026
 
 
 
 
 
 
 
 
 
 
3,000

 
1,500(3)

 
 
 
$89.90
 
1/29/2025
 
 
 
 
 
 
 
 
 
 
1,534

 
—

 
 
 
$71.30
 
1/26/2022
 
 
 
 
 
 
 
 
 
 
2,900

 
—

 
 
 
$72.79
 
1/27/2021
 
 
 
 
 
 
 
 
 
 
6,000

 
—

 
 
 
$77.10
 
1/28/2020
 
 
 
 
 
 
 
 
 
 
5,000

 
—

 
 
 
$108.20
 
1/24/2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,850(4)
 
$150,572
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,800(5)
 
$146,502

477
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
 
 
(#)
 
(#)
 
(#)
 
($)
 
 
 
(#)
 
($)
 
(#)
 
($)
 
 
 
 
 
 
 
 
 
 
 
 
850(6)
 
$69,182
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
734(7)
 
$59,740
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
284(8)
 
$23,115
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Andrew S. Marsh
 
—

 
44,000(1)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
15,000

 
30,000(2)

 
 
 
$70.56
 
1/28/2026
 
 
 
 
 
 
 
 
 
 
16,000

 
8,000(3)

 
 
 
$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
 
 
 
 
 
 
 
 
 
 
10,000

 
—

 
 
 
$108.20
 
1/24/2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8,300(4)
 
$675,537
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8,200(5)
 
$667,398
 
 
 
 
 
 
 
 
 
 
 
 
6,100(6)
 
$496,479
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,267(7)
 
$347,291
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,667(8)
 
$135,677
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
21,100(10)
 
$1,717,329
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Phillip R. May, Jr.
 
—

 
10,500(1)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
3,200

 
6,400(2)

 
 
 
$70.56
 
1/28/2026
 
 
 
 
 
 
 
 
 
 
3,333

 
1,667(3)

 
 
 
$89.90
 
1/29/2025
 
 
 
 
 
 
 
 
 
 
8,000

 
—

 
 
 
$63.17
 
1/30/2024
 
 
 
 
 
 
 
 
 
 
6,000

 
—

 
 
 
$64.60
 
1/31/2023
 
 
 
 
 
 
 
 
 
 
4,600

 
—

 
 
 
$71.30
 
1/26/2022
 
 
 
 
 
 
 
 
 
 
2,900

 
—

 
 
 
$72.79
 
1/27/2021
 
 
 
 
 
 
 
 
 
 
6,000

 
—

 
 
 
$77.10
 
1/28/2020
 
 
 
 
 
 
 
 
 
 
4,700

 
—

 
 
 
$77.53
 
1/29/2019
 
 
 
 
 
 
 
 
 
 
6,500

 
—

 
 
 
$108.20
 
1/24/2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,150(4)
 
$256,379
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,700(5)
 
$219,753
 
 
 
 
 
 
 
 
 
 
 
 
1,100(6)
 
$89,529
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
934(7)
 
$76,018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
284(8)
 
$23,115
 
 
 
 

478
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
 
 
(#)
 
(#)
 
(#)
 
($)
 
 
 
(#)
 
($)
 
(#)
 
($)
Sallie T. Rainer
 
—

 
7,800(1)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
2,233

 
4,467(2)

 
 
 
$70.56
 
1/28/2026
 
 
 
 
 
 
 
 
 
 
2,533

 
1,267(3)

 
 
 
$89.90
 
1/29/2025
 
 
 
 
 
 
 
 
 
 
2,000

 
—

 
 
 
$63.17
 
1/30/2024
 
 
 
 
 
 
 
 
 
 
2,000

 
—

 
 
 
$64.60
 
1/31/2023
 
 
 
 
 
 
 
 
 
 
2,300

 
—

 
 
 
$108.20
 
1/24/2018
 
 
 
 
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
1,850(4)
 
$150,572
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,800(5)
 
$146,502
 
 
 
 
 
 
 
 
 
 
 
 
900(6)
 
$73,251
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
734(7)
 
$59,740
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
250(8)
 
$20,348
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Charles L. Rice, Jr.
 
—

 
3,900(1)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
2,233

 
4,467(2)

 
 
 
$70.56
 
1/28/2026
 
 
 
 
 
 
 
 
 
 
3,000

 
1,500(3)

 
 
 
$89.90
 
1/29/2025
 
 
 
 
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
1,850(4)
 
$150,572
 
 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
1,800(5)
 
$146,502
 
 
 

 
 

 
 
 
 
 
 
 
550(6)
 
$44,765
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
734(7)
 
$59,740
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
250(8)
 
$20,348
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Richard C. Riley
 
—

 
8,000(1)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
1,566

 
3,134(2)

 
 
 
$70.56
 
1/28/2026
 
 
 
 
 
 
 
 
 
 
3,000

 
1,500(3)

 
 
 
$89.90
 
1/29/2025
 
 
 
 
 
 
 
 
 
 
5,334

 
—

 
 
 
$63.17
 
1/30/2024
 
 
 
 
 
 
 
 
 
 
1,334

 
—

 
 
 
$64.60
 
1/31/2023
 
 
 
 
 
 
 
 
 
 
4,000

 
—

 
 
 
$108.20
 
1/24/2018
 
 
 
 
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
1,850(4)
 
$150,572
 
 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
1,800(5)
 
$146,502
 
 
 

 
 

 
 
 
 
 
 
 
1,000(6)
 
$81,390
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
700(7)
 
$56,973
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
367(8)
 
$29,870
 
 
 
 

479
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
 
 
(#)
 
(#)
 
(#)
 
($)
 
 
 
(#)
 
($)
 
(#)
 
($)
Roderick K. West
 
—

 
29,200(1)

 
 
 
$70.53
 
1/26/2027
 
 
 
 
 
 
 
 
 
 
13,666

 
27,334(2)

 
 
 
$70.56
 
1/28/2026
 
 
 
 
 
 
 
 
 
 
15,333

 
7,667(3)

 
 
 
$89.90
 
1/29/2025
 
 
 
 
 
 
 
 
 
 
12,000

 
—

 
 
 
$63.17
 
1/30/2024
 
 
 
 
 
 
 
 
 
 
30,000

 
—

 
 
 
$71.30
 
1/26/2022
 
 
 
 
 
 
 
 
 
 
7,000

 
—

 
 
 
$77.10
 
1/28/2020
 
 
 
 
 
 
 
 
 
 
5,000

 
—

 
 
 
$77.53
 
1/29/2019
 
 
 
 
 
 
 
 
 
 
8,000

 
—

 
 
 
$108.20
 
1/24/2018
 
 
 
 
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
8,300(4)
 
$675,537
 
 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
8,200(5)
 
$667,398
 
 
 

 
 

 
 
 
 
 
 
 
3,200(6)
 
$260,448
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
4,000(7)
 
$325,560
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
1,567(8)
 
$127,538
 
 
 
 
 
 
 

 
 

 
 
 
 
 
 
 
21,000(11)
 
$1,709,190
 
 
 
 

(1)
Consists of options that vested or will vest as follows: 1/3 of the remaining unexercisable options vest on each of January 26, 2018, January 26, 2019, and January 26, 2020.
(2)
Consists of options that vested or will vest as follows: 1/2 of the remaining unexercisable options vest on each of January 28, 2018 and January 28, 2019.
(3)
The remaining unexercisable options vested on January 29, 2018.
(4)
Consists of performance units that will vest on December 31, 2019 based on Entergy Corporation’s total shareholder return performance over the 2017-2019 performance period, as described under “What Entergy Corporation Pays and Why- Executive Compensation Elements - Variable - Long-Term Incentive Compensation - Performance Unit Program” in Compensation Discussion and Analysis.
(5)
Consists of performance units that will vest on December 31, 2018 based on Entergy Corporation’s total shareholder return performance over the 2016-2018 performance period.
(6)
Consists of shares of restricted stock that vested or will vest as follows:  1/3 of the shares of restricted stock granted vest on each of January 26, 2018, January 26, 2019, and January 26, 2020.
(7)
Consists of shares of restricted stock that vested or will vest as follows:  1/2 of the shares of restricted stock granted vest on each of January 28, 2018 and January 28, 2019.
(8)
Consists of shares of restricted stock that vested on January 29, 2018.
(9)
Consists of restricted stock units granted under the 2015 Equity Ownership Plan which will vest one third on April 6, 2019, April 6, 2022, and April 6, 2025.
(10)
Consists of restricted stock units granted under the 2015 Equity Ownership Plan which will vest on August 3, 2020.
(11)
Consists of restricted stock units granted under the 2011 Equity Ownership Plan which will vest on May 1, 2018.


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2017 Option Exercises and Stock Vested

The following table provides information concerning each exercise of stock options and each vesting of stock during 2017 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
 
—

 

$—

 
1,212

 

$95,154

 
 
 
 
 
 
 
 
 
Marcus V. Brown
 
5,000

 

$35,850

 
8,224

 

$598,764

 
 
 
 
 
 
 
 
 
Leo P. Denault
 
—

 

$—

 
26,741

 

$1,979,459

 
 
 
 
 
 
 
 
 
Haley R. Fisackerly
 
10,734

 

$134,837

 
1,734

 

$126,435

 
 
 
 
 
 
 
 
 
Andrew S. Marsh
 
—

 

$—

 
8,224

 

$598,764

 
 
 
 
 
 
 
 
 
Phillip R. May, Jr.
 
—

 

$—

 
2,202

 

$161,139

 
 
 
 
 
 
 
 
 
Sallie T. Rainer
 
11,300

 

$169,289

 
1,698

 

$123,893

 
 
 
 
 
 
 
 
 
Charles L. Rice, Jr.
 
9,234

 

$147,762

 
1,603

 

$117,185

 
 
 
 
 
 
 
 
 
Richard C. Riley
 
4,500

 

$67,559

 
1,847

 

$134,414

 
 
 
 
 
 
 
 
 
Roderick K. West
 
—

 

$—

 
8,396

 

$610,908


(1)
Represents the value of performance units for the 2015-2017 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 2017.


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2017 Pension Benefits

The following table shows the present value as of December 31, 2017, 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 2017
A. Christopher Bakken, III
 
Cash Balance Equalization Plan
 
1.74

 

$30,600

 

$—

 
 
Cash Balance Plan
 
1.74

 

$30,300

 

$—

 
 
 
 
 
 
 
 
 
Marcus V. Brown(1)
 
System Executive Retirement Plan
 
22.74

 

$4,793,900

 

$—

 
 
Entergy Retirement Plan
 
22.74

 

$907,400

 

$—

 
 
 
 
 
 
 
 
 
Leo P. Denault (1)(2)
 
System Executive Retirement Plan
 
33.83

 

$22,072,300

 

$—

 
 
Entergy Retirement Plan
 
18.83

 

$802,000

 

$—

 
 
 
 
 
 
 
 
 
Haley R. Fisackerly
 
System Executive Retirement Plan
 
22.08

 

$1,370,100

 

$—

 
 
Entergy Retirement Plan
 
22.08

 

$789,100

 

$—

 
 
 
 
 
 
 
 
 
Andrew S. Marsh
 
System Executive Retirement Plan
 
19.37

 

$3,493,700

 

$—

 
 
Entergy Retirement Plan
 
19.37

 

$548,400

 

$—

 
 
 
 
 
 
 
 
 
Phillip R. May, Jr. (1)
 
System Executive Retirement Plan
 
31.56

 

$2,398,400

 

$—

 
 
Entergy Retirement Plan
 
31.56

 

$1,227,800

 

$—

 
 
 
 
 
 
 
 
 
Sallie T. Rainer (1)(3)
 
System Executive Retirement Plan
 
33.38

 

$1,356,000

 

$—

 
 
Entergy Retirement Plan
 
33.00

 

$1,415,200

 

$—

 
 
 
 
 
 
 
 
 
Charles L. Rice, Jr.
 
System Executive Retirement Plan
 
8.47

 

$609,100

 

$—

 
 
Entergy Retirement Plan
 
8.47

 

$307,800

 

$—

 
 
 
 
 
 
 
 
 
Richard C. Riley (1)(4)
 
System Executive Retirement Plan
 
28.01

 

$1,688,200

 

$—

 
 
Entergy Retirement Plan
 
22.55

 

$866,000

 

$—

 
 
 
 
 
 
 
 
 
Roderick K. West
 
System Executive Retirement Plan
 
18.75

 

$4,636,200

 

$—

 
 
Entergy Retirement Plan
 
18.75

 

$594,100

 

$—


(1)
As of December 31, 2017, 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 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 $3,967,700.
(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.

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(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.
The tables below contain summaries of the pension benefit plans sponsored by Entergy Corporation that the Named Executive Officers participated in during 2017. 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
Phillip R. May, Jr.
Sallie T. Rainer
Charles L. Rice, Jr.
Richard C. Riley
Roderick K. West

A. Christopher Bakken, III
Eligibility
Non-bargaining employees hired on or 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.
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 Code limitations and exclude all other bonuses. Executive Annual Incentive Awards are eligible for inclusion in Earnings under this plan.

Interest credits are calculated based upon the annual rate of interest on 30-year U.S. Treasury securities, as specified by the Internal Revenue Service, for the month of August preceding the first day of the applicable calendar year subject to a minimum rate of 2.6% and a maximum rate of 9%.


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Benefit Timing
Normal retirement age under the plan is 65.

A reduced 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 is typically enrolled 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.
 
Pension Equalization Plan
Cash Balance Equalization Plan
System Executive Retirement Plan
Eligible Named Executive Officers
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

A. Christopher Bakken, III
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 as an annuity under the Entergy Retirement 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
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

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Pension Equalization Plan
Cash Balance Equalization Plan
System Executive Retirement Plan
 
Executive Annual Incentive Awards are taken into account as eligible earnings under this plan.
payable as a lump sum under the Cash Balance Plan.
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 Code Section 409A.

Additional Information

(1)
Effective July 1, 2014, (a) no new grants of supplemental service may be provided to participants in the Pension Equalization Plan; (b) supplemental credited service granted prior to July 1, 2014 was grandfathered; and (c) participants in Entergy Corporation’s Cash Balance Plan are not eligible to participate in the Pension Equalization Plan and instead may be eligible to participate in the Cash Balance Equalization Plan.
(2)
Benefits already 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 Code Section 409A.
(3)
The System Executive Retirement Plan was closed to new executive officers effective July 1, 2014.


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2017 Non-qualified Deferred Compensation

As of December 31, 2017, 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 Code.

Defined Contribution Restoration Plan
Name
 
Executive Contributions in 2017
 
Registrant Contributions in 2017
 
Aggregate Earnings in 2017(1)
 
Aggregate Withdrawals/Distributions
 
Aggregate Balance at December 31, 2017
(a)
 
(b)
 
(c)
 
(d)
 
(e)
 
(f)
 
 
 
 
 
 
 
 
 
 
 
Phillip R. May, Jr.
 

$—

 

$—

 

$362

 

$—

 

$2,113


(1)
Amounts in this column are not included in the Summary Compensation Table.


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2017 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. The tables below reflect the amount of compensation each of the Named Executive Officers would have received if his or her employment with an Entergy employer had been terminated under various scenarios as of December 31, 2017. For purposes of these tables, a stock price of $81.39 was used, which was the closing market price on December 29, 2017, the last trading day of the year.

Benefits and Payments Upon Termination
Voluntary Resignation
For Cause
Termination for Good Reason or Not for Cause
Retirement
Disability
Death
Termination Related to a Change in Control
A. Christopher Bakken, III(1)
 
 
 
 
 
 
 
Severance Payment(5)
—

—

—

—

—

—


$2,511,506

Performance Units(7)
—

—

—

—


$620,680


$620,680


$1,530,132

Stock Options(8)
—

—

—

—


$408,336


$408,336


$408,336

Restricted Stock(9)
—

—

—

—


$442,029


$442,029


$442,029

Welfare Benefits(10)
—

—

—

—

—

—


$20,358

Unvested Restricted Stock Units(12)
—

—


$813,900

—


$813,900


$813,900


$2,441,700

 
 
 
 
 
 
 
 
Marcus V. Brown(2)
 
 
 
 
 
 
 
Severance Payment(5)
—

—

—

—

—

—


$3,213,000

Performance Units(7)
—

—

—

$670,165


$670,165


$670,165


$1,530,132

Stock Options(8)
—

—

—


$802,740


$802,740


$802,740


$802,740

Restricted Stock(9)
—

—

—

—


$1,041,711


$1,041,711


$1,054,082

Welfare Benefits(11)
—

—

—

—

—

—

—

 
 
 
 
 
 
 
 
Leo P. Denault(3)
 
 
 
 
 
 
 
Severance Payment(5)
—

—

—

—

—

—


$10,119,954

Performance Units(6)(7)
—

—


$3,174,210

$3,583,846


$3,583,846


$3,583,846


$6,511,200

Stock Options(8)
—

—


$3,154,024


$3,154,024


$3,154,024


$3,154,024


$3,154,024

Restricted Stock(9)
—

—


$2,750,413

—


$2,750,413


$2,750,413


$2,750,413

Welfare Benefits(11)
—

—

—

—

—

—

—

 
 
 
 
 
 
 
 
Haley R. Fisackerly(4)
 
 
 
 
 
 
 
Severance Payment(5)
—

—

—

—

—

—


$497,420

Performance Units(7)
—

—

—

—


$147,886


$147,886


$358,116

Stock Options(8)
—

—

—

—


$130,910


$130,910


$130,910

Restricted Stock(9)
—

—

—

—


$161,966


$161,966


$164,163

Welfare Benefits(10)
—

—

—

—

—

—


$18,252

 
 
 
 
 
 
 
 
Andrew S. Marsh(4)
 
 
 
 
 
 
 
Severance Payment(5)
—

—

—

—

—

—


$3,060,000

Performance Units(7)
—

—

—

—


$670,165


$670,165


$1,530,132

Stock Options(8)
—

—

—

—


$802,740


$802,740


$802,740

Restricted Stock(9)
—

—

—

—


$1,041,711


$1,041,711


$1,054,082

Welfare Benefits(10)
—

—

—

—

—

—


$27,378

Unvested Restricted Stock Units(13)
—

—

—

—


$1,717,329


$1,717,329


$1,717,329

 
 
 
 
 
 
 
 

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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
Phillip R. May, Jr.(2)
 
 
 
 
 
 
 
Severance Payment(5)
—

—

—

—

—

—


$1,171,680

Performance Units(7)
—

—

—


$231,962


$231,962


$231,962


$504,618

Stock Options(8)
—

—

—


$183,342


$183,342


$183,342


$183,342

Restricted Stock(9)
—

—

—

—


$201,034


$201,034


$203,231

Welfare Benefits(11)
—

—

—

—

—

—

—

 
 
 
 
 
 
 
 
Sallie T. Rainer(2)
 
 
 
 
 
 
 
Severance Payment(5)
—

—

—

—

—

—


$459,585

Performance Units(7)
—

—

—


$147,886


$147,886


$147,886


$358,116

Stock Options(8)
—

—

—


$133,082


$133,082


$133,082


$133,082

Restricted Stock(9)
—

—

—

—


$163,269


$163,269


$165,222

Welfare Benefits(11)
—

—

—

—

—

—

—

 
 
 
 
 
 
 
 
Charles R. Rice, Jr(4)
 
 
 
 
 
 
 
Severance Payment(5)
—

—

—

—

—

—


$400,993

Performance Units(7)
—

—

—

—


$147,886


$147,886


$358,116

Stock Options(8)
—

—

—

—


$90,728


$90,728


$90,728

Restricted Stock(9)
—

—

—

—


$133,480


$133,480


$135,433

Welfare Benefits(10)
—

—

—

—

—

—


$18,252

 
 
 
 
 
 
 
 
Richard C. Riley(2)
 
 
 
 
 
 
 
Severance Payment(5)
—

—

—

—

—

—


$481,880

Performance Units(7)
—

—

—


$147,886


$147,886


$147,886


$358,116

Stock Options(8)
—

—

—


$120,814


$120,814


$120,814


$120,814

Restricted Stock(9)
—

—

—

—


$178,896


$178,896


$181,663

Welfare Benefits(11)
—

—

—

—

—

—

—

 
 
 
 
 
 
 
 
Roderick K. West(4)
 
 
 
 
 
 
 
Severance Payment(5)
—

—

—

—

—

—


$3,434,065

Performance Units(7)
—

—

—

—


$670,165


$670,165


$1,530,132

Stock Options(8)
—

—

—

—


$613,132


$613,132


$613,132

Restricted Stock(9)
—

—

—

—


$762,624


$762,624


$774,344

Welfare Benefits(10)
—

—

—

—

—

—


$27,378

Unvested Restricted Stock Units(14)
—

—


$1,709,190

—

—

—


$1,709,190


Pension Benefits

1)
In addition to the payments and benefits in the table, if Mr. Bakken’s employment were terminated under certain conditions relating to a change in control, on the first day of the month following the Qualifying Event (as defined in the Cash Balance Equalization Plan) he would have become vested in and would have been entitled to receive his vested pension benefits accumulated in the Cash Balance Equalization Plan as of the date of the Qualifying Event so long as a forfeiture event does not occur as described in the plan. For a description of the pension benefits under the Cash Balance Equalization Plan, see “2017 Pension Benefits.”

2)
As of December 31, 2017, Messrs. Brown, May, and 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, each also would be entitled to receive his or her vested pension benefits under the Entergy Retirement Plan. For a description of the pension

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benefits available, see “2017 Pension Benefits.” In the event their termination by their Entergy employer without cause or by Mr. Brown, Mr. May, Ms. Rainer, or Mr. Riley for good reason in connection with a change in control, each would be eligible for subsidized early retirement benefits under the System Executive Retirement Plan even if they do not have company permission to separate from employment. If Mr. Brown’s, Mr. May’s, Ms. Rainer’s, or Mr. Riley’s employment were terminated for cause in connection with a change in control, they would not be entitled to receive a benefit under the System Executive Retirement Plan. If their employment were terminated for any reason not in connection with a change in control, or they were to retire from their Entergy employer before age 65 without the permission of their Entergy employer, they would not be entitled to receive a benefit under the System Executive Retirement Plan.

3)
As of December 31, 2017, Mr. Denault is retirement eligible and would retire rather than voluntarily resign, and in addition to the payments and benefits in the table, Mr. Denault also would be entitled to receive his vested pension benefits under the Entergy Retirement Plan. For a description of the pension benefits available, see “2017 Pension Benefits.” If Mr. Denault’s employment was terminated by his Entergy employer other than for cause, by Mr. Denault for good reason or on account of his death or disability, he would also be eligible for certain additional retirement benefits. For a description of these benefits, see “2017 Pension Benefits.” Otherwise, if Mr. Denault’s employment was terminated for cause or he was to retire from his Entergy employer before age 65 without the permission of his Entergy employer, he would not receive a benefit under the System Executive Retirement Plan.

4)
In addition to the payments and benefits in the table, if Mr. Fisackerly’s, Mr. Marsh’s, Mr. Rice’s, or Mr. West’s employment were terminated under certain conditions relating to a change in control, each also would have been entitled to receive his vested pension benefits upon attainment of age 55 under the Entergy Retirement Plan and would have been eligible for early retirement benefits under the System Executive Retirement Plan calculated using early retirement reduction factors. For a description of the pension benefits, see “2017 Pension Benefits.” Mr. Fisackerly’s, Mr. Marsh’s, Mr. Rice’s, or Mr. West’s employment were terminated for cause in connection with a change in control, he would not be entitled to receive a benefit under the System Executive Retirement Plan. If his employment were terminated for any reason not in connection with a change in control, or each were to resign from his Entergy employer before age 65 without the permission of his Entergy employer, each would not be entitled to receive a benefit under the System Executive Retirement Plan.

Severance Payments:

5)
In the event of a termination by the executive for good reason or by his or her Entergy system employer not for cause during the period beginning upon the occurrence of a “potential change in control” (as defined in the System Executive Continuity Plan) and ending on the 2nd anniversary of a change in control, each Named Executive Officer would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to a multiple of the sum of (1) his or her 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 (2) his or her annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for 2015 and 2016 (the two calendar years immediately preceding the calendar year in which termination occurs), but in no event shall the severance payment exceed the product of 2.99 times the sum of (a) his or her annual base salary as in effect at any time within one year prior to the commencement of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) the higher of his or her actual annual incentive payment under the Annual Incentive Plan for the 2016 performance year or his or her annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for 2015 and 2016 (the two calendar years immediately preceding the calendar year in which termination occurs). For purposes of this table, the following target opportunity and base salary were assumed:

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Named Executive Officer
Target Opportunity
Base Salary
A. Christopher Bakken III
35%
$620,125
Marcus V. Brown
70%
$630,000
Leo P. Denault
130%
$1,230,000
Haley R. Fisackerly
40%
$355,300
Andrew S. Marsh
70%
$600,000
Phillip R. May Jr,
60%
$366,150
Sallie T. Rainer
40%
$328,275
Charles L. Rice, Jr.
40%
$286,424
Richard C. Riley
40%
$344,200
Roderick K. West
70%
$675,598

Performance Units:

6)
With respect to Mr. Denault, in the event of a Termination Event (as defined in Mr. Denault’s 2006 retention agreement), he is entitled to a Target LTIP Award, as defined in his 2006 retention agreement, 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. 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 2013-2015 Performance Unit Program (38,000) and from the 2014-2016 Performance Unit Program (40,000). This average number of units (39,000) multiplied by the closing price of Entergy Corporation’s common stock on December 29, 2017 ($81.39) would equal a payment of $3,174,210. In the event of death or disability, Mr. Denault receives the greater of the Target LTIP Award calculated as described above or the sum of the amount that would be payable under the provisions of each open Performance Unit Program as described in Note 7 below.

7)
In the event of a qualifying termination related to a change in control, each Named Executive Officer would have forfeited his or her performance units for the 2016-2018 and 2017-2019 performance periods and would have been entitled to receive, pursuant to the 2015 Equity Ownership Plan, a single-lump sum payment in lieu of any payment for each performance award that would not be based on any outstanding performance period. The payments for the 2016-2018 and the 2017-2019 performance periods would have been calculated using the most recent performance period preceding (but not including) the calendar year in which his or her termination occurs. For purposes of the table, the value of Mr. Denault’s payments was calculated by multiplying the target performance units for the 2014-2016 Performance Unit Program (40,000) by the closing price of Entergy Corporation’s common stock on December 29, 2017 ($81.39), which would equal a payment of $3,255,600 for the forfeited performance units for each performance period. The value of the payments for the other Named Executive Officers was calculated by multiplying the target performance units for the 2014-2016 Performance Unit Program (9,400) by the closing price of Entergy Corporation’s common stock on December 29, 2017 ($81.39), which would equal a payment of $765,066 for the forfeited performance units for each performance period. In the event his death or disability, Mr. Denault would receive the greater of the target Long-Term Performance Incentive award as described in note 6 above or a 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.

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, each Named Executive Officer would not have forfeited his or her performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on his or her number of months of participation in each open Performance Unit Program performance period, in accordance with his grant agreement under the Performance Unit Program. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period. For purposes of the table, the values of the awards were calculated as follows:

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Mr. Denault’s:
2016 - 2018 Plan - 27,800 (24/36*41,700) performance units at target, assuming a stock price of $81.39
2017 - 2019 Plan - 16,233 (12/36*48,700) performance units at target, assuming a stock price of $81.39
Mr. Bakken’s:
2016 - 2018 Plan - 4,859 (24/36*7,289) performance units at target, assuming a stock price of $81.39
2017 - 2019 Plan - 2,767 (12/36*8,300) performance units at target, assuming a stock price of $81.39
Messrs. Brown’s, Marsh’s, and West’s:
2016 - 2018 Plan - 5,467 (24/36*8,200) performance units at target, assuming a stock price of $81.39
2017 - 2019 Plan - 2,767 (12/36*8,300) performance units at target, assuming a stock price of $81.39

Mr. May’s:
2016 - 2018 Plan - 1,800 (24/36*2,700) performance units at target, assuming a stock price of $81.39
2017 - 2019 Plan - 1,050 (12/36*3,150) performance units at target, assuming a stock price of $81.39

Messrs. Fisackerly’s, Rice’s, Riley’s, and Ms. Rainer’s:

2016 - 2018 Plan - 1,200 (24/36*1,800) performance units at target, assuming a stock price of $81.39
2017 - 2019 Plan - 617 (12/36*1,850) performance units at target, assuming a stock price of $81.39

Stock Options:

8)
In the event of death or disability or qualifying termination related to a change in control, or retirement in the case of Mr. Brown, Mr. Denault, Mr. May, Ms. Rainer, or Mr. Riley, all of the unvested stock options of each Named Executive Officer would immediately vest pursuant to the Equity Ownership Plans. In addition, with respect to grants under the 2011 Equity Ownership Plan, each Named Executive Officer would be entitled to exercise his or her stock options for the remainder of the ten-year period extending from the grant date of the options, and with respect to grants under the 2015 Equity Ownership Plan, within the lesser of five years or the remaining term of the option grant. For purposes of this table, it is assumed that the Named Executive Officers exercised their options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 29, 2017, and the applicable exercise price of each option share.

In the event of a Termination Event as defined in his 2006 retention agreement, Mr. Denault will immediately vest in all unvested stock options.

Restricted Stock:

9)
In the event of death or disability pursuant to the 2011 Equity Ownership Plan, each Named Executive Officer would immediately vest in a pro-rated portion of his or her unvested restricted stock that was otherwise scheduled to become vested on the immediately following 12-month grant date anniversary date, as well as dividends declared on the pro-rated portion of such restricted stock pursuant to the 2011 Equity Ownership Plan. The pro-rated vested portion would be determined based on the number of days between the most recent preceding 12-month grant date anniversary date and the date of his or her death or disability. In the event of his or her qualifying termination related to a change in control, a Named Executive Officer would immediately vest in all of their unvested restricted stock, as well as dividends declared on such restricted stock granted pursuant the 2011 Equity Ownership Plan. In the event of death, disability, or qualifying termination related to a change in control, each Named Executive Officer would vest in all of their unvested restricted stock as well as dividends declared pursuant to the 2015 Equity Ownership Plan.


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In the event of a Termination Event as defined in his 2006 retention agreement, Mr. Denault will immediately vest in all unvested restricted stock.

Welfare Benefits:

10)
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-sponsored COBRA benefits for 18 months and Mr. Fisackerly and Mr. Rice would be eligible to receive Entergy-sponsored COBRA benefits for 12 months.

11)
Upon retirement, Mr. Brown, Mr. Denault, Mr. May, Ms. Rainer, and Mr. Riley would be eligible for retiree medical and dental benefits, the same as all other retirees.

Unvested Restricted Stock Units:

12)
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, then 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 Corporation and its affiliates. In the event of a change in control, the unvested restricted stock units will fully vest upon Mr. Bakken’s termination of employment by his Entergy employer without cause or by Mr. Bakken with good reason during a change in control period (as defined in the 2015 Equity Ownership Plan). Otherwise, if Mr. Bakken voluntarily resigns or is terminated, he would forfeit these units. Pursuant to his restricted stock unit agreement, Mr. Bakken is subject to certain restrictions on his ability to compete with Entergy Corporation 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 Corporation 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 Corporation any shares of Entergy Corporation’s common 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.

13)
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. In the event of a change in control, the units will vest upon termination of Mr. Marsh’s employment by his Entergy employer without cause or by Mr. Marsh with good reason during a change in control period (as defined in the 2015 Equity Ownership Plan). Otherwise, if Mr. Marsh voluntarily resigns or is terminated, he would forfeit these units. Pursuant to his restricted stock unit agreement, Mr. Marsh is subject to certain restrictions on his ability to compete with Entergy Corporation and its affiliates during and for 12 months after his employment with Entergy Corporation, or to solicit its employees or customers during and for 24 months after his employment with it. In addition, the restricted stock unit agreement limits Mr. Marsh’s ability to disparage Entergy Corporation 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 Corporation any shares of Entergy Corporation’s common 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.

14)
Mr. West’s 21,000 restricted stock units vest 100% in 2018. Pursuant to his restricted stock unit agreement, any unvested restricted stock units will vest immediately in the event of a termination other than for cause. In the event of a change in control, the units will vest upon termination of Mr. West’s employment by his Entergy employer without cause or by Mr. West with good reason during a change in control period (as defined in the 2011 Equity Ownership Plan). Otherwise, if Mr. West voluntarily resigns, is terminated for cause, dies, or becomes disabled, he would forfeit these units.

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Mr. Denault’s 2006 Retention Agreement
Under the terms of his 2006 retention agreement, Mr. Denault’s employment may be terminated for cause upon Mr. Denault’s:

•
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;
•
willfully engaging in conduct that is demonstrably and materially injurious to Entergy Corporation;
•
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 Corporation’s reputation;
•
material violation of any agreement that he has entered into with Entergy Corporation; or
•
unauthorized disclosure of Entergy Corporation’s confidential information.

Mr. Denault may terminate his employment for good reason upon:

•
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;
•
a reduction of 5% or more in his base salary as in effect on the date of the retention agreement;
•
the relocation of his principal place of employment to a location other than the corporate headquarters;
•
the failure to continue to allow him to participate in programs or plans providing opportunities for equity awards, stock options, restricted stock, stock appreciation rights, incentive compensation, bonus 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);
•
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 Entergy Corporation’s 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
•
any purported termination of his employment not taken in accordance with his retention agreement.

System Executive Continuity Plan

Termination Related to a Change in Control

Entergy Corporation’s Named Executive Officers will be entitled to the benefits described in the tables above under the System Executive Continuity Plan in the event of a termination related to a change in control if a change in control occurs and their employment is terminated by their Entergy employer other than for cause or if they terminate their employment for good reason, in each case within a period beginning on the occurrence of a potential change in control and ending 24 months following the effective date of a change in control.

A change in control includes the following events:

•
the purchase of 30% or more of either Entergy Corporation’s common stock or the combined voting power of Entergy Corporation’s voting securities;
•
the merger or consolidation of Entergy Corporation (unless its Board members constitute at least a majority of the board members of the surviving entity);
•
the liquidation, dissolution, or sale of all or substantially all of Entergy Corporation’s assets; or
•
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.


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A potential change in control includes the following events:

•
Entergy Corporation or an affiliate enters into an agreement the consummation of which would constitute a change in control;
•
the Entergy Corporation Board adopts resolutions determining that, for purposes of the System Executive Continuity Plan, a potential change in control has occurred;
•
a System Company or other person or entity publicly announces an intention to take actions that would constitute a change in control; or
•
any person or entity becomes the beneficial owner (directly or indirectly) of outstanding shares of Entergy Corporation’s common stock constituting 20% or more of the voting power or value of Entergy Corporation’s outstanding common stock.

A Named Executive Officer’s employment may be terminated for cause under the System Executive Continuity Plan if he or she:

•
willfully and continuously fails to substantially perform his or her duties after receiving a 30-day written demand for performance from Entergy Corporation’s Board;
•
engages in conduct that is materially injurious to Entergy Corporation or any of its subsidiaries;
•
is convicted or pleads guilty or nolo contendere to a felony or other crime that materially and adversely affects his or her ability to perform his or her duties or Entergy Corporation’s reputation;
•
materially violates any agreement with Entergy Corporation or any of its subsidiaries; or
•
discloses any of Entergy Corporation’s confidential information without authorization.

A Named Executive Officer may terminate his or her employment with his or her Entergy employer for good reason under the System Executive Continuity Plan if, without his or her consent:

•
the nature or status of his or her duties and responsibilities is substantially altered or reduced compared to the period prior to the change in control;
•
his or her salary is reduced by 5% or more;
•
he or she is required to be based outside of the continental United States at somewhere other than his or her primary work location prior to the change in control;
•
any of his or her compensation plans are discontinued without an equitable replacement;
•
his or her benefits or number of vacation days are substantially reduced; or
•
his or her Entergy employer purports to terminate his or her employment other than in accordance with the System Executive Continuity Plan.

In addition to participation in the System Executive Continuity Plan, benefits already accrued under the System Executive Retirement Plan, Pension Equalization Plan, and Cash Balance Equalization Plan, if any, will become fully vested if the executive is involuntarily terminated without cause or the executive terminates his or her employment for good reason within two years after the occurrence of a change in control. Any awards granted under the Equity Ownership Plans will become fully vested if the executive is involuntarily terminated without cause or terminates employment for good reason within two years after the occurrence of a change in control.

Under certain circumstances described below, the payments and benefits received by a Named Executive Officer pursuant to the System Executive Continuity Plan may be forfeited and, in certain cases, subject to repayment. Benefits are no longer payable under the System Executive Continuity Plan, and unvested performance units under the Performance Unit Program are subject to forfeiture, if the executive:

•
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;
•
discloses non-public data or information concerning 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.

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Furthermore, if the 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 System Executive Continuity Plan.

Voluntary Resignation

If a Named Executive Officer voluntarily resigns from his or her Entergy employer:

•
all unvested stock options, shares of restricted stock and restricted stock units as well as any perquisites to which he or she is entitled as an officer are forfeited;
•
incentive payments under any outstanding performance periods under the Long-Term Performance Unit Program or the Annual Incentive Plan are forfeited; provided however, if an officer resigns after the completion of an Annual Incentive Plan or Long-Term Performance Unit Program performance period, he or she could receive a payout under the Long-Term Performance Unit Program based on the outcome of the performance period and could, at Entergy Corporation’s discretion, receive an annual incentive payment under the Annual Incentive Plan;
•
any vested stock options held by the officer as of the separation date will expire the earlier of ten years from date of grant or 90 days from the last day of active employment; and
•
he or she is entitled to all vested accrued benefits and compensation as of the separation date, including qualified pension benefits (if any) and other post-employment benefits on terms consistent with those generally available to other salaried employees.

Termination for Cause

If a Named Executive Officer’s employment is terminated for “cause” (as defined in the System Executive Continuity Plan and described above under “Termination Related to a Change in Control”), he or she is generally entitled to the same compensation and separation benefits described above under “Voluntary Resignation,” except that all options are no longer exercisable.

Retirement

Upon a Named Executive Officer’s retirement:

•
the annual incentive payment under the Annual Incentive Plan is generally pro-rated based on the actual number of days employed during the performance year in which the retirement date occurs, subject to negative discretion that may be applied to reduce or disallow the payment; payments are delivered at the conclusion of the annual period, consistent with the timing of payments to active participants in the Annual Incentive Plan;
•
payments under the Long-Term Performance Unit Program for those retiring with a minimum of 12 months of participation are pro-rated based on the actual full months of participation in each outstanding performance period in which the retirement date occurs, and payments are delivered at the conclusion of each performance period, consistent with the timing of payments to active participants in the Long-Term Performance Unit Program;
•
unvested stock options issued under the 2011 Equity Ownership Plan vest on the retirement date and expire ten years from the grant date of the options;
•
unvested stock options issued under the 2015 Equity Ownership Plan vest on the retirement date and expire the earlier of five years from the grant date of the options or the original term of ten years;
•
any unvested restricted stock and restricted stock units held by the executive upon his retirement are forfeited; and
•
he or she is generally entitled to all vested accrued benefits and compensation as of the separation date, including qualified pension benefits and other post-employment benefits consistent with those generally available to salaried employees.

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Disability

If a Named Executive Officer’s employment is terminated due to disability, he or she generally is entitled to the same compensation and separation benefits described above under “Retirement,” except that unvested restricted stock and restricted stock units may be subject to specific disability benefits as noted, where applicable, in the tables above.

Death

If a Named Executive Officer dies while actively employed by an Entergy employer, he or she generally is entitled to the same compensation and separation benefits described above under “Retirement,” except that unvested restricted stock and restricted stock units may be subject to specific death benefits as noted, where applicable, in the tables above. 

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.

Identification of Median Employee

For each of the Utility operating companies, October 6, 2017 was selected as the date on which to determine the median employee. 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 2017 Summary Compensation Table with respect to each of the Named Executive Officers.

Entergy Arkansas Ratio

For 2017,
•
Mr. Riley’s annual total compensation, as reported in the Total column of the 2017 Summary Compensation Table, was $1,353,719.
•
The annual total compensation of the median employee was $127,560.
•
Based on this information, the ratio of the annual total compensation of Mr. Riley to the median employee is estimated to be 11:1.

Entergy Louisiana Ratio

For 2017,
•
Mr. May’s annual total compensation, as reported in the Total column of the 2017 Summary Compensation Table, was $1,564,954.
•
The annual total compensation of the median employee was $144,954.
•
Based on this information, the ratio of the annual total compensation of Mr. May to the median employee is estimated to be 11:1.
 

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Entergy Mississippi Ratio

For 2017,
•
Mr. Fisackerly’s annual total compensation, as reported in the Total column of the 2017 Summary Compensation Table, was $1,207,343.
•
The annual total compensation of the median employee was $112,110.
•
Based on this information, the ratio of the annual total compensation of Mr. Fisackerly to the median employee is estimated to be 11:1.
 
Entergy New Orleans Ratio

For 2017,
•
Mr. Rice’s annual total compensation, as reported in the Total column of the 2017 Summary Compensation Table, was $824,111.
•
The annual total compensation of the median employee was $91,346.
•
Based on this information, the ratio of the annual total compensation of Mr. Rice to the median employee is estimated to be 9:1.
 
Entergy Texas Ratio

For 2017,
•
Ms. Rainer’s annual total compensation, as reported in the Total column of the 2017 Summary Compensation Table, was $1,200,260.
•
The annual total compensation of the median employee was $129,877.
•
Based on this information, the ratio of the annual total compensation of Ms. Rainer to the median employee is estimated to be 9:1.


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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 Arkansas, Entergy Mississippi, Entergy Texas, and indirectly 100% of the outstanding common membership interests of registrant Entergy Louisiana 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, 2018 for all non-employee 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**
 
10,710

 
12,533

 
—

Maureen S. Bateman*
 
22,716

 
—

 
—

Marcus V. Brown**
 
27,803

 
130,066

 
—

Patrick J. Condon*
 
4,460

 
—

 
—

Leo P. Denault***
 
133,457

 
565,133

 
—

Kirkland H. Donald*
 
5,736

 
—

 
1,389

Philip L. Frederickson*
 
2,775

 
—

 
805

Alexis M. Herman*
 
12,581

 
—

 
—

Donald C. Hintz*
 
15,096

 
—

 
3,942

Stuart L. Levenick*
 
18,047

 
—

 
—

Blanche L. Lincoln*
 
11,004

 
—

 
—

Andrew S. Marsh**
 
60,425

 
166,766

 
—

Karen A. Puckett*
 
4,460

 
—

 
—

W. J. Tauzin*
 
17,809

 
—

 
—

Roderick K. West**
 
42,475

 
114,066

 
—

All directors and executive officers as a group (19 persons)
 
444,591

 
1,112,495

 
6,136

 
 
 
 
 
 
 
Entergy Arkansas
 
 

 
 

 
 

A. Christopher Bakken, III**
 
10,710

 
12,533

 
—

Marcus V. Brown**
 
27,803

 
130,066

 
—

Leo P. Denault**
 
133,457

 
565,133

 
—

Andrew S. Marsh***
 
60,425

 
166,766

 
—

Richard C. Riley***
 
11,169

 
16,967

 
—

Roderick K. West***
 
42,475

 
114,066

 
—

All directors and executive officers as a group (10 persons)
 
341,076

 
1,129,462

 
—

 
 
 
 
 
 
 
Entergy Louisiana
 
 
 
 
 
 
A. Christopher Bakken, III**
 
10,710

 
12,533

 
—

Marcus V. Brown**
 
27,803

 
130,066

 
—

Leo P. Denault**
 
133,457

 
565,133

 
—

Andrew S. Marsh***
 
60,425

 
166,766

 
—

Phillip R. May, Jr.***
 
18,203

 
47,100

 
12

Roderick K. West***
 
42,475

 
114,066

 
—

All directors and executive officers as a group (10 persons)
 
348,110

 
1,159,595

 
12



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Name
 
Shares (1)(2)
 
Options Exercisable Within 60 Days
 
Stock Units (3)
Entergy Mississippi
 
 
 
 
 
 
Marcus V. Brown**
 
27,803

 
130,066

 
—

Leo P. Denault**
 
133,457

 
565,133

 
—

Haley R. Fisackerly***
 
6,605

 
21,933

 
—

Andrew S. Marsh***
 
60,425

 
166,766

 
—

Roderick K. West***
 
42,475

 
114,066

 
—

All directors and executive officers as a group (9 persons)
 
325,802

 
1,121,895

 
—

 
 
 
 
 
 
 
Entergy New Orleans
 
 
 
 
 
 
Marcus V. Brown**
 
27,803

 
130,066

 
—

Leo P. Denault**
 
133,457

 
565,133

 
—

Andrew S. Marsh***
 
60,425

 
166,766

 
—

Charles L. Rice, Jr.***
 
5,855

 
10,266

 
—

Roderick K. West***
 
42,475

 
114,066

 
—

All directors and executive officers as a group (9 persons)
 
325,052

 
1,110,228

 
—

 
 
 
 
 
 
 
Entergy Texas
 
 
 
 
 
 
Marcus V. Brown**
 
27,803

 
130,066

 
—

Leo P. Denault**
 
133,457

 
565,133

 
—

Andrew S. Marsh***
 
60,425

 
166,766

 
—

Sallie T. Rainer***
 
7,884

 
14,866

 
—

Roderick K. West***
 
42,475

 
114,066

 
—

All directors and executive officers as a group (9 persons)
 
327,081

 
1,114,828

 
—

*
Director of the respective Company
**
Named Executive Officer of the respective Company
***
Director and Named Executive Officer 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, Hintz, 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.


500
Table of Contents

Equity Compensation Plan Information

The following table summarizes the equity compensation plan information as of December 31, 2017. Information is included for equity compensation plans approved by the stockholders and equity compensation plans not approved by the stockholders.

Plan
 
Number of Securities to be Issued Upon Exercise of Outstanding Options (a)
 
Weighted Average Exercise Price (b)
 
Number of Securities Remaining Available for Future Issuance (excluding securities reflected in column (a))(c)
Equity compensation plans approved by security holders (1)
 
5,164,854

 
$83.26
 
3,498,788

Equity compensation plans not approved by security holders(2)
 
—

 
—

 
—

Total
 
5,164,854

 
$83.26
 
3,498,788


(1)
Includes the 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, and the 2015 Equity Ownership 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 Ownership 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 Ownership Plan, with no more than 1,500,000 shares available for incentive stock option grants.  The 2015 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 Ownership Plan (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)
Entergy has a Board-approved stock-based compensation plan. However, effective May 9, 2003, the Board has directed that no further awards be issued under that plan. As of December 31, 2017, all options outstanding under the plan were either exercised or expired.


501
Table of Contents

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 compensation 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, 2017, neither Entergy Corporation nor any of its affiliates has participated in any Related Person Transaction.


502
Table of Contents

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, 2017 and 2016 by Deloitte & Touche LLP were as follows:

 
2017
 
2016
Entergy Corporation (consolidated)
 
 
 
Audit Fees

$8,401,895

 

$8,932,000

Audit-Related Fees (a)
875,000

 
865,000

Total audit and audit-related fees
9,276,895

 
9,797,000

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (b)

$9,276,895

 

$9,797,000

Entergy Arkansas
 
 
 
Audit Fees

$1,018,860

 

$1,056,881

Audit-Related Fees (a)
—

 
—

Total audit and audit-related fees
1,018,860

 
1,056,881

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (b)

$1,018,860

 

$1,056,881

Entergy Louisiana
 
 
 
Audit Fees

$1,887,719

 

$2,138,762

Audit-Related Fees (a)
500,000

 
450,000

Total audit and audit-related fees
2,387,719

 
2,588,762

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (b)

$2,387,719

 

$2,588,762

Entergy Mississippi
 
 
 
Audit Fees

$933,860

 

$971,881

Audit-Related Fees (a)
—

 
—

Total audit and audit-related fees
933,860

 
971,881

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (b)

$933,860

 

$971,881


503
Table of Contents

 
2017
 
2016
Entergy New Orleans
 
 
 
Audit Fees

$953,860

 

$1,056,881

Audit-Related Fees (a)
—

 
—

Total audit and audit-related fees
953,860

 
1,056,881

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (b)

$953,860

 

$1,056,881

Entergy Texas
 
 
 
Audit Fees

$1,093,860

 

$1,076,881

Audit-Related Fees (a)
—

 
—

Total audit and audit-related fees
1,093,860

 
1,076,881

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (b)

$1,093,860

 

$1,076,881

System Energy
 
 
 
Audit Fees

$868,860

 

$861,881

Audit-Related Fees (a)
—

 
—

Total audit and audit-related fees
868,860

 
861,881

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (b)

$868,860

 

$861,881


(a)
Includes fees for employee benefit plan audits, consultation on financial accounting and reporting, and other attestation services.
(b)
100% of fees paid in 2017 and 2016 were pre-approved by the Entergy Corporation Audit Committee.

504
Table of Contents

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.


505
Table of Contents

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 507).  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.


506
Table of Contents

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 Louisiana
(a) 1 --
 
 
(a) 2 --
 
 
(a) 3 --
 
 
(a) 4 --


(3) Articles of Incorporation and By-laws

Entergy Corporation
(a) 1 --
 
 
(a) 2 --

System Energy
*(b) 1 --
 
 
(b) 2 --

507
Table of Contents

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.
 
 
(a) 2 --
 
 
(a) 3 --
 
 
(a) 4 --

508
Table of Contents

(a) 5 --
 
 
(a) 6 --
 
 
(a) 7 --
 
 
(a) 8 --
 
 
(a) 9 --
 
 
(a) 10 --
 
 
(a) 11 --

 
 
(a) 12 --
 
 
(a) 13 --

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 --


509
Table of Contents

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); * Filed herewith (Thirtieth); * Filed herewith (Thirty-first); * Filed herewith (Thirty-ninth); * Filed herewith (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); and 4.05 to Form 8-K filed August 16, 2016 in 1-10764 (Seventy-ninth)).
 
 
(c) 2 --
 
 
(c) 3 --
 
 
(c) 4 --
 
 
(c) 5 --
 
 
(c) 6 --
 
 
(c) 7 --
 
 
(c) 8--
 
 
*(c) 9 --
 
 
(c) 10 --


510
Table of Contents

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); * Filed herewith (Sixth); 2(c) in 2-34659 (Twelfth); * Filed herewith (Thirteenth); 2(b)-2 in 2-38378 (Fourteenth); * Filed herewith (Twenty-first); * Filed herewith (Twenty-fifth); * Filed herewith (Twenty-ninth); * Filed herewith (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); 4.33 to Form 8-K filed October 4, 2016 in 1-32718 (Eighty-seventh); and 4.43 to Form 8-K filed May 23, 2017 in 1-32718 (Eighty-eighth)).
 
 
(d) 2 --
 
 
(d) 3 --
 
 
(d) 4 --
 
 
(d) 5 --
 
 
(d) 6 --
 
 
(d) 7 --
 
 

511
Table of Contents

(d) 8 --
 
 
(d) 9 --
 
 
*(d) 10 --
 
 
*(d) 11 --
 
 
*(d) 12 --
 
 
(d) 13 --
 
 
(d) 14 --
 
 
(d) 15 --
Indenture of Mortgage, dated September 1, 1926, as amended by the following Supplemental Indentures: (7-A-9 in Registration No. 2-6893 (Seventh); * Filed herewith (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 June 30, 2008 in 333-148557 (Seventy-sixth); 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); and 4.42 to Form 8-K filed May 23, 2017 in 1-32718 (Eighty-eighth)).
 
 
(d) 16 --
 
 
(d) 17 --
 
 
(d) 18 --
 
 
(d) 19 --
 
 
(d) 20 --

512
Table of Contents

 
 
(d) 21 --
 
 
(d) 22 --
 
 
(d) 23 --

Entergy Mississippi
(e) 1 --

Entergy New Orleans
(f) 1 --
 
 
(f) 2 --
 
 
(f) 3 --
 
 
(f) 4 --
 
 
(f) 5 --

Entergy Texas
(g) 1 --
 
 

513
Table of Contents

(g) 2 --
 
 
(g) 3 --
 
 
*(g) 4 --
 
 
(g) 5 --
 
 
(g) 6 --
 
 
(g) 7 --
 
 
(g) 8 --
 
 
(g) 9 --
 
 
(g) 10 --
 
 
(g) 11 --
 
 
(g) 12 --
 
 
(g) 13 --
 
 

514
Table of Contents

(g) 14 --

(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 --
 
 
+(a) 14 --
 
 

515
Table of Contents

+(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 --
 
 
+(a) 32 --
 
 

516
Table of Contents

+(a) 33 --
 
 
+(a) 34 --
 
 
+(a) 35 --
 
 
+(a) 36 --
 
 
+(a) 37 --
 
 
+(a) 38 --
 
 
+(a) 39 --
Retention Agreement effective August 3, 2006 between Leo P. Denault and Entergy Corporation (10(b) to Form 10-Q for the quarter ended June 30, 2006 in 1-11299).
 
 
+(a) 40 --
 
 
+(a) 41 --
 
 
+(a) 42 --
 
 
+(a) 43 --
 
 
+(a) 44 --
 
 
+(a) 45 --
 
 
*+(a) 46 --
 
 
*+(a) 47 --
 
 
*+(a) 48 --
 
 
*+(a) 49 --
 
 
+(a) 50 --
 
 
+(a) 51 --
 
 

517
Table of Contents

+(a) 52 --
 
 
+(a) 53 --
 
 
+(a) 54 --
 
 
+(a) 55 --

System Energy
*(b) 1 --
 
 
*(b) 2 --
 
 
*(b) 3 --
 
 
*(b) 4 --
 
 
*(b) 5 --
 
 
(b) 6 --
 
 
(b) 7 --
 
 
*(b) 8 --
 
 
*(b) 9 --
 
 
(b) 10 --
 
 
*(b) 11 --
 
 
(b) 12 --
 
 
*(b) 13 --
 
 
(b) 14 --
 
 
*(b) 15 --

518
Table of Contents

(b) 16 --

Entergy Louisiana
*(c) 1 --

(12) Statement Re Computation of Ratios
*(a)
 
 
*(b)
 
 
*(c)
 
 
*(d)
 
 
*(e)
 
 
*(f)

*(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)

519
Table of Contents

*(j)
 
 
*(k)
 
 
*(l)
 
 
*(m)
 
 
*(n)

(32)  Section 1350 Certifications
*(a)
 
 
*(b)
 
 
*(c)
 
 
*(d)
 
 
*(e)
 
 
*(f)
 
 
*(g)
 
 
*(h)
 
 
*(i)
 
 
*(j)
 
 
*(k)
 
 
*(l)
 
 
*(m)
 
 
*(n)



520
Table of Contents

(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, 2018

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, 2018

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); Maureen S. Bateman, Patrick J. Condon, Kirkland H. Donald, Philip L. Frederickson, Alexis M. Herman, Donald C. Hintz, Stuart L. Levenick, Blanche L. Lincoln, Karen A. Puckett, and W. J. Tauzin (Directors).

By: /s/ Alyson M. Mount
February 26, 2018
(Alyson M. Mount, Attorney-in-fact)
 


522
Table of Contents

ENTERGY ARKANSAS, 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 ARKANSAS, INC.
 
 
 
By  /s/ Alyson M. Mount
 
Alyson M. Mount
 
Senior Vice President and Chief Accounting Officer
 
 
 
Date: February 26, 2018

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, 2018

Richard C. Riley (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, 2018
(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, 2018

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, 2018

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, 2018
(Alyson M. Mount, Attorney-in-fact)
 

524
Table of Contents

ENTERGY MISSISSIPPI, 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 MISSISSIPPI, INC.
 
 
 
By  /s/ Alyson M. Mount
 
Alyson M. Mount
 
Senior Vice President and Chief Accounting Officer
 
 
 
Date: February 26, 2018

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, 2018

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, 2018
(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, 2018

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, 2018

Charles L. Rice, 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, 2018
(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, 2018

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, 2018

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, 2018
(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, 2018

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, 2018

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, 2018
(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, and 333-206556 on Form S-8 of our reports dated February 26, 2018, 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, 2017.

We consent to the incorporation by reference in Registration Statement No. 333-213335-06 on Form S-3 of our reports dated February 26, 2018, relating to the consolidated financial statements and financial statement schedule of Entergy Arkansas, Inc. and Subsidiaries appearing in this Annual Report on Form 10-K of Entergy Arkansas, Inc. for the year ended December 31, 2017.

We consent to the incorporation by reference in Registration Statement No. 333-213335-03 on Form S-3 of our reports dated February 26, 2018, 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, 2017.

We consent to the incorporation by reference in Registration Statement No. 333-213335-05 on Form S-3 of our reports dated February 26, 2018, 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, 2017.

We consent to the incorporation by reference in Registration Statement No. 333-213335-04 on Form S-3 of our report dated February 26, 2018, 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, 2017.


/s/ DELOITTE & TOUCHE LLP


New Orleans, Louisiana
February 26, 2018

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, 2017 and 2016, and for each of the three years in the period ended December 31, 2017, and the Corporation’s internal control over financial reporting as of December 31, 2017, and have issued our reports thereon dated February 26, 2018. 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, 2018



530
Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the shareholders and Board of Directors of
Entergy Arkansas, Inc. and Subsidiaries
Entergy Mississippi, Inc.
Entergy Texas, Inc. and Subsidiaries

To the members and Board of Directors of
Entergy Louisiana, LLC and Subsidiaries
Entergy New Orleans, LLC and Subsidiaries


Opinion on the Financial Statement Schedules


We have audited the consolidated financial statements of Entergy Arkansas, Inc. 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, Inc. (collectively the “Companies”) as of December 31, 2017 and 2016, and for each of the three years in the period ended December 31, 2017, and have issued our reports thereon dated February 26, 2018. 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, 2018


531
Table of Contents

INDEX TO FINANCIAL STATEMENT SCHEDULES



Schedule
 
Page
 
 
 
II
Valuation and Qualifying Accounts 2017, 2016, and 2015:
 
 
 
 
 
 
 

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, 2017, 2016, and 2015
(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
 
 
 
 
 
 
 
 
2017
 

$11,924

 

$4,211

 

$2,548

 

$13,587

2016
 

$39,895

 

$7,505

 

$35,476

 

$11,924

2015
 

$35,663

 

$6,926

 

$2,694

 

$39,895

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, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2017, 2016, and 2015
(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
 
 
 
 
 
 
 
 
2017
 

$1,211

 

$503

 

$651

 

$1,063

2016
 

$34,226

 

$902

 

$33,917

 

$1,211

2015
 

$32,247

 

$2,759

 

$780

 

$34,226

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, 2017, 2016, and 2015
(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
 
 
 
 
 
 
 
 
2017
 

$6,277

 

$3,108

 

$955

 

$8,430

2016
 

$4,209

 

$2,942

 

$874

 

$6,277

2015
 

$1,609

 

$3,464

 

$864

 

$4,209

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, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2017, 2016, and 2015
(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
 
 
 
 
 
 
 
 
2017
 

$549

 

$255

 

$230

 

$574

2016
 

$718

 

$259

 

$428

 

$549

2015
 

$873

 

$247

 

$402

 

$718

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, 2017, 2016, and 2015
(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
 
 
 
 
 
 
 
 
2017
 

$3,059

 

$152

 

$154

 

$3,057

2016
 

$268

 

$2,872

 

$81

 

$3,059

2015
 

$262

 

$217

 

$211

 

$268

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, 2017, 2016, and 2015
(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
 
 
 
 
 
 
 
 
2017
 

$828

 

$192

 

$557

 

$463

2016
 

$474

 

$531

 

$177

 

$828

2015
 

$672

 

$239

 

$437

 

$474

Notes:
 
 

 
 

 
 

 
 

(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.



S-7