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ENTERGY TEXAS, INC. - Annual Report: 2014 (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, 2014
 
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
 
1-31508
ENTERGY MISSISSIPPI, INC.
(a Mississippi corporation)
308 East Pearl Street
Jackson, Mississippi 39201
Telephone (601) 368-5000
64-0205830
 
 
 
 
 
 
 
 
 
 
1-10764
ENTERGY ARKANSAS, INC.
(an Arkansas corporation)
425 West Capitol Avenue
Little Rock, Arkansas 72201
Telephone (501) 377-4000
71-0005900
 
0-05807
ENTERGY NEW ORLEANS, INC.
(a Louisiana corporation)
1600 Perdido Street
New Orleans, Louisiana 70112
Telephone (504) 670-3700
72-0273040
 
 
 
 
 
 
 
 
 
 
0-20371
ENTERGY GULF STATES LOUISIANA, L.L.C.
(a Louisiana limited liability company)
4809 Jefferson Highway
Jefferson, Louisiana 70121
Telephone (504) 576-4000
74-0662730
 
1-34360
ENTERGY TEXAS, INC.
(a Texas corporation)
9425 Pinecroft
The Woodlands, TX 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
75-3206126
 
1-09067
SYSTEM ENERGY RESOURCES, INC.
(an Arkansas corporation)
Echelon One
1340 Echelon Parkway
Jackson, Mississippi 39213
Telephone (601) 368-5000
72-0752777

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Table of Contents

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 – 179,697,449
  shares outstanding at January 30, 2015
New York Stock Exchange, Inc.
Chicago Stock Exchange, Inc.
 
 
 
Entergy Arkansas, Inc.
Mortgage Bonds, 5.75% Series due November 2040
New York Stock Exchange, 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.
 
 
 
Entergy Louisiana, LLC
Mortgage Bonds, 6.0% Series due March 2040
New York Stock Exchange, Inc.
 
Mortgage Bonds, 5.875% Series due June 2041
New York Stock Exchange, Inc.
 
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.
 
 
 
Entergy Mississippi, Inc.
Mortgage Bonds, 6.0% Series due November 2032
New York Stock Exchange, Inc.
 
Mortgage Bonds, 6.20% Series due April 2040
New York Stock Exchange, Inc.
 
Mortgage Bonds, 6.0% Series due May 2051
New York Stock Exchange, Inc.
 
 
 
Entergy New Orleans, Inc.
Mortgage Bonds, 5.0% Series due December 2052
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
Preferred Stock, Cumulative, $0.01 Par Value
 
 
Entergy Gulf States Louisiana, L.L.C.
Common Membership Interests
 
 
Entergy Mississippi, Inc.
Preferred Stock, Cumulative, $100 Par Value
 
 
Entergy New Orleans, Inc.
Preferred Stock, Cumulative, $100 Par Value
 
 
Entergy Texas, Inc.
Common Stock, no par value

Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.
 
Yes
 
No
 
 
 
 
Entergy Corporation
ü
 
 
Entergy Arkansas, Inc.
 
 
ü
Entergy Gulf States Louisiana, L.L.C.
 
 
ü
Entergy Louisiana, LLC
ü
 
 
Entergy Mississippi, Inc.
 
 
ü
Entergy New Orleans, Inc.
 
 
ü
Entergy Texas, Inc.
 
 
ü
System Energy Resources, Inc.
 
 
ü

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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 Gulf States Louisiana, L.L.C.
 
 
ü
Entergy Louisiana, LLC
 
 
ü
Entergy Mississippi, Inc.
 
 
ü
Entergy New Orleans, Inc.
 
 
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]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definitions of “accelerated filer,” “large accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934.
 
Large
accelerated
filer
 
 
 
Accelerated filer
 
 
Non-accelerated
filer
 
Smaller
reporting
company
 
 
 
 
 
 
 
 
Entergy Corporation
ü
 
 
 
 
 
 
Entergy Arkansas, Inc.
 
 
 
 
ü
 
 
Entergy Gulf States Louisiana, L.L.C.
 
 
 
 
ü
 
 
Entergy Louisiana, LLC
 
 
 
 
ü
 
 
Entergy Mississippi, Inc.
 
 
 
 
ü
 
 
Entergy New Orleans, Inc.
 
 
 
 
ü
 
 
Entergy Texas, Inc.
 
 
 
 
ü
 
 
System Energy Resources, Inc.
 
 
 
 
ü
 
 

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

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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 2014, was $14.7 billion based on the reported last sale price of $82.09 per share for such stock on the New York Stock Exchange on June 30, 2014.  Entergy Corporation is the sole holder of the common stock of Entergy Arkansas, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc.  Entergy Corporation is the sole holder of the common stock of Entergy Louisiana Holdings, Inc., which is the sole holder of the common membership interests in Entergy Louisiana, LLC.  Entergy Corporation is the sole holder of the common stock of EGS Holdings, Inc., which is the sole holder of the common membership interests in Entergy Gulf States Louisiana, L.L.C.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders, to be held May 8, 2015, are incorporated by reference into Part III hereof.

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Table of Contents

TABLE OF CONTENTS
 
SEC Form 10-K
Reference Number
Page
Number
 
 
 
 
 
 
 
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.
Part II. Item 8.
Part I. Item 1.
Part I. Item 1.
Part I. Item 1.
Part I. Item 1.
 
 
 
Part I. Item 1A.
Unresolved Staff Comments
Part I. Item 1B.
None
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 Gulf States Louisiana, L.L.C.
 
 
Part II. Item 7.
 
Part II. Item 8.
Part II. Item 8.
Part II. Item 8.
Part II. Item 8.

i
Table of Contents

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, 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 Texas, 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.
System Energy Resources, Inc.
 
 
Part II. Item 7.
 
Part II. Item 8.
Part II. Item 8.

ii
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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.
 
 
 
 
 

This combined Form 10-K is separately filed by Entergy Corporation and its seven “Registrant Subsidiaries”: Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., 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.


iii
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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 and negotiations, including various performance-based rate discussions, Entergy’s utility supply plan, and recovery of fuel and purchased power costs;
•
the termination of Entergy Arkansas’s participation in the System Agreement, which occurred in December 2013, the termination of Entergy Mississippi’s participation in the System Agreement in November 2015, the termination of Entergy Texas’s, Entergy Gulf States Louisiana’s, and Entergy Louisiana’s participation in the System Agreement after expiration of the proposed 60-month notice period or such other period as approved by the FERC;
•
regulatory and operating challenges and uncertainties and economic risks associated with the Utility operating companies’ move to MISO, which occurred in December 2013, including the effect of current or projected MISO market rules 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 the beginning or end of 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;
•
changes in the regulation or regulatory oversight of Entergy’s nuclear generating facilities and nuclear materials and fuel, including with respect to the planned or potential 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;
•
the performance of and deliverability of power from Entergy’s generation resources, including the capacity factors at its nuclear generating facilities;
•
Entergy’s ability to develop and execute on a point of view regarding future prices of electricity, natural gas, and other energy-related commodities;
•
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;
•
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
Table of Contents

FORWARD-LOOKING INFORMATION (Concluded)

•
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, tax, and other laws, including requirements for reduced emissions of sulfur dioxide, nitrogen oxide, greenhouse gases, mercury, and other regulated air and water emissions, and changes in costs of compliance with environmental and other laws and regulations;
•
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 disposal fees charged by the U.S. government 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;
•
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, and the risk that anticipated load growth may not materialize;
•
the effects of Entergy’s strategies to reduce tax payments;
•
changes in the financial markets, particularly those affecting the availability of capital and Entergy’s ability to refinance existing debt, 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;
•
the potential effects of threatened or actual terrorism, cyber-attacks or data security breaches, including increased security costs, 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 and directors;
•
changes in accounting standards and corporate governance;
•
declines in the market prices of marketable securities and resulting funding requirements 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 or cost to decommission nuclear plant sites;
•
the implementation of the shutdown of Vermont Yankee and the related decommissioning of Vermont Yankee;
•
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 merger, acquisition, or divestiture plans, regulatory or other limitations imposed as a result of merger, acquisition, or divestiture, and the success of the business following a merger, acquisition, or divestiture.


v
Table of Contents

DEFINITIONS

Certain abbreviations or acronyms used in the text and notes are defined below:
Abbreviation or Acronym
Term
 
 
AFUDC
Allowance for Funds Used During Construction
ALJ
Administrative Law Judge
ANO 1 and 2
Units 1 and 2 of Arkansas Nuclear One (nuclear), owned by Entergy Arkansas
APSC
Arkansas Public Service Commission
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 or 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 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.
Entergy Texas
Entergy Texas, Inc., a company 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 (EWC)
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), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
FTR
Financial transmission right
Grand Gulf
Unit No. 1 of Grand Gulf Nuclear Station (nuclear), 90% owned or leased by System Energy
GWh
Gigawatt-hour(s), which equals one million kilowatt-hours
Independence
Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi, and 7% by Entergy Power, LLC
Indian Point 2
Unit 2 of Indian Point Energy Center (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment

vi
Table of Contents

DEFINITIONS (Continued)


Abbreviation or Acronym
Term
 
 
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 kilowatt(s)
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 Gulf States 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
OASIS
Open Access Same Time Information Systems
Palisades
Palisades Power Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
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 Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc.
Ritchie Unit 2
Unit 2 of the R.E. Ritchie Steam Electric Generating Station (gas/oil)
River Bend
River Bend Station (nuclear), owned by Entergy Gulf States Louisiana
RTO
Regional transmission organization
SEC
Securities and Exchange Commission
SMEPA
South Mississippi Electric Power Association, which owns a 10% interest in Grand Gulf

vii
Table of Contents

DEFINITIONS (Concluded)


Abbreviation or Acronym
Term
 
 
System Agreement
Agreement, effective January 1, 1983, as modified, among the Utility operating companies relating to the sharing of generating capacity and other power resources. Entergy Arkansas terminated its participation in the System Agreement effective December 18, 2013.
System Energy
System Energy Resources, Inc.
System Fuels
System Fuels, Inc.
TWh
Terawatt-hour(s), which equals one billion kilowatt-hours
U.K.
United Kingdom of Great Britain and Northern Ireland
Unit Power Sales Agreement
Agreement, dated as of June 10, 1982, as amended and approved by 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 Gulf States Louisiana, 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



viii
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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 operates 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.  In August 2013, Entergy announced plans to close and decommission Vermont Yankee. On December 29, 2014 the Vermont Yankee plant ceased power production and has entered its decommissioning phase. 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.

Following are the percentages of Entergy’s consolidated revenues and net income generated by its operating segments and the percentage of total assets held by them.
 
% of Revenue
 
% of Net Income
 
% of Total Assets
Segment
2014
2013
2012
 
2014
2013
2012
 
2014
2013
2012
Utility
78

80

78

 
88

116

110

 
82

82

82

Entergy Wholesale Commodities
22

20

22

 
31

6

5

 
22

22

22

Parent & Other
—

—

—

 
(19
)
(22
)
(15
)
 
(4
)
(4
)
(4
)

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


1
Table of Contents
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


Results of Operations

2014 Compared to 2013

Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2014 to 2013 showing how much the line item increased or (decreased) in comparison to the prior period.
 
 
Utility
 
Entergy
Wholesale
Commodities
 
Parent &
Other
 
 
Entergy
 
(In Thousands)
2013 Consolidated Net Income (Loss)

$846,215

 

$42,976

 

($158,619
)
 

$730,572

 
 
 
 
 
 
 
 
Net revenue (operating revenue less fuel expense,
  purchased power, and other regulatory
  charges/credits)
210,893

 
422,147

 
(17,519
)
 
615,521

Other operation and maintenance
12,369

 
(25,043
)
 
(8,724
)
 
(21,398
)
Asset write-off, impairments, and related charges
62,814

 
(221,809
)
 
(2,790
)
 
(161,785
)
Taxes other than income taxes
2,760

 
1,709

 
(213
)
 
4,256

Depreciation and amortization
(2,019
)
 
60,053

 
(440
)
 
57,594

Gain on sale of business
—

 
(43,569
)
 
—

 
(43,569
)
Other income
1,795

 
(23,642
)
 
(13,272
)
 
(35,119
)
Interest expense
22,556

 
323

 
591

 
23,470

Other expenses
7,696

 
33,699

 
—

 
41,395

Income taxes
106,231

 
254,459

 
2,926

 
363,616

2014 Consolidated Net Income (Loss)

$846,496



$294,521



($180,760
)


$960,257


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 2014 include $154 million ($100 million after-tax) of charges related to Vermont Yankee primarily resulting from the effects of an updated decommissioning cost study completed in the third quarter 2014 along with reassessment of the assumptions regarding the timing of decommissioning cash flows and severance and employee retention costs. See Note 1 to the financial statements for further discussion of the charges. Results of operations for 2014 also include the $56.2 million ($36.7 million after-tax) write-off in 2014 of Entergy Mississippi’s regulatory asset associated with new nuclear generation development costs as a result of a joint stipulation entered into with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, in which Entergy Mississippi agreed not to pursue recovery of the costs deferred by an MPSC order in the new nuclear generation docket. See Note 2 to the financial statements for further discussion of the new nuclear generation development costs and the joint stipulation.

As discussed in more detail in Note 1 to the financial statements, results of operations for 2013 include $322 million ($202 million after-tax) of impairment and other related charges to write down the carrying value of Vermont Yankee and related assets to their fair values. Also, earnings were negatively affected in 2013 by expenses, including other operation and maintenance expenses and taxes other than income taxes, of approximately $110 million ($70 million after-tax), including approximately $85 million ($55 million after-tax) for Utility and $25 million ($15 million after-tax) for Entergy Wholesale Commodities, recorded in connection with a strategic imperative intended to optimize the organization through a process known as human capital management. In December 2013, Entergy deferred for future collection approximately $45 million ($30 million after-tax) of these costs in the Arkansas and Louisiana

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Management's Financial Discussion and Analysis

jurisdictions at the Utility, as approved by the APSC and the LPSC, respectively. See “Human Capital Management Strategic Imperative” below for further discussion.

Net Revenue

Utility

Following is an analysis of the change in net revenue comparing 2014 to 2013.
  
Amount
  
(In Millions)
 
 
2013 net revenue

$5,524

Retail electric price
135

Asset retirement obligation
56

Volume/weather
36

MISO deferral
16

Net wholesale revenue
(29
)
Other
(3
)
2014 net revenue

$5,735


The retail electric price variance is primarily due to:

•
increases in the energy efficiency rider at Entergy Arkansas, as approved by the APSC, effective July 2013 and July 2014. Energy efficiency revenues are offset by costs included in other operation and maintenance expenses and have minimal effect on net income;
•
the effect of the APSC’s order in Entergy Arkansas’s 2013 rate case, including an annual base rate increase effective January 2014 offset by a MISO rider to provide customers credits in rates for transmission revenue received through MISO;
•
a formula rate plan increase at Entergy Mississippi, as approved by the MSPC, effective September 2013;
•
an increase in Entergy Mississippi’s storm damage rider, as approved by the MPSC, effective October 2013. The increase in the storm damage rider is offset by other operation and maintenance expenses and has no effect on net income;
•
an annual base rate increase at Entergy Texas, effective April 2014, as a result of the PUCT’s order in the September 2013 rate case; and
•
a formula rate plan increase at Entergy Louisiana, as approved by the LPSC, effective December 2014.

See Note 2 to the financial statements for a discussion of rate proceedings.

The asset retirement obligation affects net revenue because Entergy records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation-related costs collected in revenue. The variance is primarily caused by increases in regulatory credits because of decreases in decommissioning trust earnings and increases in depreciation and accretion expenses and increases in regulatory credits to realign the asset retirement obligation regulatory assets with regulatory treatment.

The volume/weather variance is primarily due to an increase of 3,129 GWh, or 3%, in billed electricity usage primarily due to an increase in sales to industrial customers and the effect of more favorable weather on residential sales. The increase in industrial sales was primarily due to expansions, recovery of a major refining customer from an unplanned outage in 2013, and continued moderate growth in the manufacturing sector.


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Management's Financial Discussion and Analysis


The MISO deferral variance is primarily due to the deferral in 2014 of the non-fuel MISO-related charges, as approved by the LPSC and the MPSC, partially offset by the deferral in April 2013, as approved by the APSC, of costs incurred from March 2010 through December 2012 related to the transition and implementation of joining the MISO RTO. The deferral of non-fuel MISO-related charges is partially offset in other operation and maintenance expenses. See Note 2 to the financial statements for further discussion of the recovery of non-fuel MISO-related charges.

The net wholesale variance is primarily due to a wholesale customer contract termination in December 2013 and lower margins on co-owner contracts due to contract changes.

Entergy Wholesale Commodities

Following is an analysis of the change in net revenue comparing 2014 to 2013.
  
Amount
  
(In Millions)
 
 
2013 net revenue

$1,802

Nuclear realized price changes
264

Mark-to-market
129

Nuclear volume
37

Other
(8
)
2014 net revenue

$2,224


As shown in the table above, net revenue for Entergy Wholesale Commodities increased by approximately $422 million in 2014 primarily due to:

•
higher realized wholesale energy prices primarily due to increases in Northeast market power prices and higher capacity prices. Entergy Wholesale Commodities’ hedging strategies routinely include financial instruments that manage operational and liquidity risk. These positions, in addition to a larger-than-normal unhedged position in 2014 due to Vermont Yankee being in its final year of operation, allowed Entergy Wholesale Commodities to benefit from increases in Northeast market power prices;
•
the effect of lower forward power prices on electricity derivative instruments that are not designated as hedges, including additional financial power sales conducted in the fourth quarter 2014 to lock in margins on some in-the-money purchased call options. These additional sales did not qualify for hedge accounting treatment, and decreases in forward prices after those sales were made accounted for the majority of the positive mark-to-market variance.  In fourth quarter 2013, Entergy Wholesale Commodities also entered into similar transactions, but the price movements after the forward sales were in the opposite direction and resulted in negative mark-to-market activity in 2013. When these positions settled in the first quarter 2014, the turnaround of the negative 2013 mark also contributed to the positive 2014 mark-to-market variance. See Note 16 to the financial statements for discussion of derivative instruments; and
•
higher volume in its nuclear fleet resulting from approximately 90 fewer unplanned outage days in 2014 compared to 2013, partially offset by a larger exercise of resupply options in 2013 compared to 2014 provided for in purchase power agreements where Entergy Wholesale Commodities may elect to supply power from another source when the plant is not running. Amounts related to the exercise of resupply options are included in the GWh billed in the table below.

    

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Management's Financial Discussion and Analysis

Following are key performance measures for Entergy Wholesale Commodities for 2014 and 2013.
 
2014
 
2013
Owned capacity (MW)
6,068
 
6,068
GWh billed
44,424
 
45,127
Average realized price per MWh
$60.84
 
$50.86
 

 
 
Entergy Wholesale Commodities Nuclear Fleet

 
 
Capacity factor
91%
 
89%
GWh billed
40,253
 
40,167
Average realized revenue per MWh
$60.35
 
$50.15
Refueling Outage Days:
 
 
 
FitzPatrick
44
 
—
Indian Point 2
24
 
—
Indian Point 3
—
 
28
Palisades
56
 
—
Pilgrim
—
 
45
Vermont Yankee
—
 
27

Realized Revenue per MWh for Entergy Wholesale Commodities Nuclear Plants

The effects of sustained low natural gas prices and power market structure challenges have resulted in lower market prices for electricity in the New York and New England power regions, which is where four of the five operating Entergy Wholesale Commodities nuclear power plants are located. A sixth plant, Vermont Yankee, ceased operations in December 2014. The Entergy Wholesale Commodities nuclear business experienced an annual realized price per MWh of $60.35 in 2014, $50.15 in 2013, and $50.29 in 2012. The increase in realized price in 2014 is primarily attributable to a significant increase in first quarter 2014 prices due to cold winter weather and northeastern U.S. gas pipeline infrastructure limitations. Prior to 2009 the annual realized price per MWh for Entergy Wholesale Commodities generally increased each year, reaching a peak of $61.07 in 2009. As shown in the contracted sale of energy table in “Market and Credit Risk Sensitive Instruments,” Entergy Wholesale Commodities has sold forward 86% of its planned nuclear energy output for 2015 for an expected average contracted energy price of $48 per MWh based on market prices at December 31, 2014. In addition, Entergy Wholesale Commodities has sold forward 74% of its planned nuclear energy output for 2016 for an expected average contracted energy price of $49 per MWh based on market prices at December 31, 2014. The market price trend presents a challenging economic situation for the Entergy Wholesale Commodities plants. The challenge is greater for some of these 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. If, in the future, economic conditions or regulatory activity no longer support the continued operation or recovery of the costs of a plant it could adversely affect Entergy’s results of operations through loss of revenue, impairment charges, increased depreciation rates, transitional costs, or accelerated decommissioning costs.

On August 27, 2013, Entergy announced its plan to close and decommission Vermont Yankee. This decision was approved by the Board in August 2013. The decision to shut down the plant was primarily due to 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 region in which the plant operated. On December 29, 2014 the Vermont Yankee plant ceased power production. See Note 1 to the financial statements for discussion of impairment of long-lived assets.

Impairment of long-lived assets and nuclear decommissioning costs, and the factors that influence these items, are both discussed below in “Critical Accounting Estimates.” See also the discussion below in “Entergy Wholesale

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Commodities Authorizations to Operate Its Nuclear Power Plants” regarding Entergy Wholesale Commodities nuclear plant operating license and related activity.

Other Income Statement Items

Utility

Other operation and maintenance expenses increased from $2,264 million for 2013 to $2,276 million for 2014 primarily due to:

•
an increase of $53 million in nuclear generation expenses primarily due to higher material costs, higher contract labor costs, and higher NRC fees;
•
an increase of $38 million in administration fees related to participation in the MISO RTO beginning December 2013. The net income effect is partially offset due to deferrals of these fees in certain jurisdictions. See Note 2 to the financial statements for further information on the deferrals;
•
an increase of $29 million in energy efficiency costs.  These costs are recovered through energy efficiency riders and have a minimal effect on net income;
•
an increase of $24 million in storm damage accruals primarily at Entergy Arkansas effective January 2014, as approved by the APSC, and at Entergy Mississippi effective October 2013, as approved by the MPSC;
•
an increase of $20 million in regulatory, consulting, and legal fees;
•
an increase of $19 million in contract labor primarily due to higher infrastructure and application services and call center outsourcing;
•
an increase of $11 million primarily due to higher vegetation maintenance;
•
an increase of $7 million due to higher write-offs of uncollectible customer accounts in 2014 as compared to 2013;
•
an increase of $7 million due to the amortization in 2014 of costs deferred in 2013 related to the transition and implementation of joining the MISO RTO; and
•
several individually insignificant items.

The increase was partially offset by:

•
a decrease of $146 million in compensation and benefits costs primarily due to fewer employees, an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan.  See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
•
a decrease of $36 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business;
•
a decrease of $9 million resulting from costs incurred in 2013 related to the generator stator incident at ANO, including an offset for insurance proceeds. See “ANO Damage, Outage, and NRC Reviews” below for further discussion of the incident;
•
a net decrease of $8 million related to the human capital management strategic imperative in 2014 as compared to the same period in 2013 including a decrease of $60 million in implementation costs, severance costs, and curtailment and special termination benefits, the deferral in 2013 of $44 million of costs incurred, as approved by the APSC and LPSC, and partial amortization in 2014 of $8 million of costs that were deferred in 2013. See “Human Capital Management Strategic Imperative” below for further discussion; and
•
a net decrease of $4 million related to Baxter Wilson (Unit 1) repairs. The increase in repair costs incurred in 2014 compared to the prior year were offset by expected insurance proceeds and the deferral of repair costs, as approved by the MPSC. See “Baxter Wilson Plant Event” in Note 8 to the financial statements for further discussion.

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The asset write-off, impairment, and related charges variance is due to the $56.2 million ($36.7 million after-tax) write-off in 2014 of Entergy Mississippi’s regulatory asset associated with new nuclear generation development costs and a $16 million ($10.5 million after-tax) write-off recorded in 2014 because of the uncertainty associated with the resolution of the Waterford 3 replacement steam generator project prudence review. See Note 2 to the financial statements for further discussion of new nuclear generation development costs and the prudence review.

Interest expense increased primarily due to the lease renewal in December 2013 of the Grand Gulf sale leaseback and net debt issuances of first mortgage bonds in the first quarter 2014 and the second quarter 2013 by certain Utility operating companies. See Note 5 to the financial statements for more details of long-term debt. The increase was partially offset by an increase in the allowance for borrowed funds used during construction due to a higher construction work in progress balance in 2014, including the Ninemile Unit 6 self-build project.

Other expenses increased primarily due to increases in decommissioning expenses resulting from revisions to the estimated decommissioning cost liabilities as a result of revised decommissioning cost studies in the fourth quarter 2013 and the first quarter 2014, partially offset by a decrease in nuclear refueling outage costs that are being amortized over the estimated period to the next outage. See Note 9 to the financial statements for further discussion of the decommissioning cost revisions.

Entergy Wholesale Commodities

Other operation and maintenance expenses decreased from $1,048 million for 2013 to $1,023 million for 2014 primarily due to:

•
a decrease of $63 million in compensation and benefits costs primarily due to fewer employees, an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
•
a decrease of $15 million due to the absence of expenses from Entergy Solutions District Energy, which was sold in November 2013; and
•
a decrease of $13 million in implementation costs, severance costs, and curtailment and special termination benefits related to the human capital management strategic imperative in 2014 as compared to the same period in 2013. See “Human Capital Management Strategic Imperative” below for further discussion.

The decrease was partially offset by:

•
an increase of $22 million incurred in 2014 as compared to 2013 related to the shutdown of Vermont Yankee including severance and retention costs. See “Impairment of Long-Lived Assets” in Note 1 to the financial statements for discussion regarding the shutdown of the Vermont Yankee plant in December 2014;
•
an increase of $18 million primarily due to higher contract costs and higher NRC fees; and
•
$18 million in transmission imbalance sales in 2013.

The asset write-off, impairments, and related charges variance is primarily due to $321.5 million ($202.2 million after-tax) in 2013 of impairment and other related charges primarily to write down the carrying value of Vermont Yankee and related assets to their fair values and $107.5 million ($69.8 million after-tax) in 2014 of impairment charges related to Vermont Yankee primarily resulting from the effects of an updated decommissioning cost study completed in the third quarter 2014. See Note 1 to the financial statements for further discussion of these impairment charges.

Depreciation and amortization expenses increased primarily due to a change effective in 2014 in the estimated average useful lives of plant in service as a result of a new depreciation study and an increase to depreciable plant balances.


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Management's Financial Discussion and Analysis


The gain on sale of business resulted from the sale in November 2013 of Entergy Solutions District Energy, a business wholly-owned by Entergy in the Entergy Wholesale Commodities segment that owned and operated district energy assets servicing the business districts in Houston and New Orleans. Entergy sold Entergy Solutions District Energy for $140 million and realized a pre-tax gain of $44 million on the sale.

Other income decreased primarily due to lower realized gains on nuclear decommissioning trust fund investments.

Other expenses increased primarily due to an increase in nuclear refueling outage costs that are being amortized over the estimated period to the next outage and an increase in decommissioning expenses primarily due to revisions to the estimated decommissioning cost liability for Vermont Yankee recorded in the third and fourth quarters of 2013. See “Critical Accounting Estimates - Nuclear Decommissioning Costs” below for further discussion of nuclear decommissioning costs.

Parent & Other

Other income decreased primarily due to the elimination of intersegment activity.

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 2014 was 38%.  The difference in the effective income tax rate versus the statutory rate of 35% for 2014 was primarily due to state income taxes, certain book and tax differences related to utility plant items, and the provision for uncertain tax positions, partially offset by a deferred state income tax reduction related to a New York tax law change and book and tax differences related to the allowance for equity funds used during construction.

The effective income tax rate for 2013 was 23.6%. The difference in the effective income tax rate versus the statutory rate of 35% for 2013 was primarily related to (1) IRS settlements as discussed further in Note 3 to the financial statements; and (2) a tax benefit associated with the now-terminated plan to spin off and merge the Utility’s transmission business, because certain associated costs became deductible with the termination of the transaction.


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Management's Financial Discussion and Analysis

2013 Compared to 2012

Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2013 to 2012 showing how much the line item increased or (decreased) in comparison to the prior period.
 
 
Utility
 
Entergy
Wholesale
Commodities
 
Parent &
Other
 
 
Entergy
 
(In Thousands)
2012 Consolidated Net Income (Loss)

$960,322

 

$40,427

 

($132,386
)
 

$868,363

 
 
 
 
 
 
 
 
Net revenue (operating revenue less fuel expense,
  purchased power, and other regulatory
  charges/credits)
555,233

 
(51,509
)
 
7,136

 
510,860

Other operation and maintenance
184,374

 
90,222

 
11,946

 
286,542

Asset write-off, impairments, and related charges
9,411

 
(26,188
)
 
2,790

 
(13,987
)
Taxes other than income taxes
37,547

 
5,380

 
125

 
43,052

Depreciation and amortization
76,850

 
39,824

 
(215
)
 
116,459

Gain on sale of business
—

 
43,569

 
—

 
43,569

Other income
6,378

 
29,624

 
2,268

 
38,270

Interest expense
32,688

 
(1,577
)
 
3,642

 
34,753

Other expenses
18,271

 
50,274

 
—

 
68,545

Income taxes
316,577

 
(138,800
)
 
17,349

 
195,126

2013 Consolidated Net Income (Loss)

$846,215

 

$42,976

 

($158,619
)
 

$730,572


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.

As discussed in more detail in Note 1 to the financial statements, results of operations include $322 million ($202 million after-tax) in 2013 and $356 million ($224 million after-tax) in 2012 of impairment and other related charges to write down the carrying value of Vermont Yankee and related assets to their fair values. Also, net income for Utility in 2012 was significantly affected by a settlement with the IRS related to the income tax treatment of the Louisiana Act 55 financing of the Hurricane Katrina and Hurricane Rita storm costs, which resulted in a reduction in income tax expense. The net income effect was partially offset by a regulatory charge, which reduced net revenue in 2012, associated with the storm costs settlement to reflect the obligation to customers with respect to the settlement. See Note 3 to the financial statements for additional discussion of the tax settlement.

Also, earnings were negatively affected in 2013 by expenses, including other operation and maintenance expenses and taxes other than income taxes, of approximately $110 million ($70 million after-tax), including approximately $85 million ($55 million after-tax) for Utility and $25 million ($15 million after-tax) for Entergy Wholesale Commodities, recorded in connection with a strategic imperative intended to optimize the organization through a process known as human capital management. In December 2013, Entergy deferred for future collection approximately $45 million ($30 million after-tax) of these costs in the Arkansas and Louisiana jurisdictions at the Utility, as approved by the APSC and the LPSC, respectively. See “Human Capital Management Strategic Imperative” below for further discussion.


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Management's Financial Discussion and Analysis


Net Revenue

Utility

Following is an analysis of the change in net revenue comparing 2013 to 2012.
  
Amount
  
(In Millions)
 
 
2012 net revenue

$4,969

Retail electric price
236

Louisiana Act 55 financing savings obligation
165

Grand Gulf recovery
75

Volume/weather
40

Fuel recovery
35

MISO deferral
12

Asset retirement obligation
(23
)
Other
15

2013 net revenue

$5,524


The retail electric price variance is primarily due to:

•
a formula rate plan increase at Entergy Louisiana, effective January 2013, which includes an increase relating to the Waterford 3 steam generator replacement project, which was placed in service in December 2012. The net income effect of the formula rate plan increase is limited to a portion representing an allowed return on equity with the remainder offset by costs included in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes;
•
the recovery of Hinds plant costs through the power management rider at Entergy Mississippi, as approved by the MPSC, effective with the first billing cycle of 2013. The net income effect of the Hinds plant cost recovery is limited to a portion representing an allowed return on equity on the net plant investment with the remainder offset by the Hinds plant costs in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes;
•
an increase in the capacity acquisition rider at Entergy Arkansas, as approved by the APSC, effective with the first billing cycle of December 2012, relating to the Hot Spring plant acquisition. The net income effect of the Hot Spring plant cost recovery is limited to a portion representing an allowed return on equity on the net plant investment with the remainder offset by the Hot Spring plant costs in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes;
•
increases in the energy efficiency rider, as approved by the APSC, effective July 2013 and July 2012. Energy efficiency revenues are offset by costs included in other operation and maintenance expenses and have minimal effect on net income;
•
an annual base rate increase at Entergy Texas, effective July 2012, as a result of the PUCT’s order that was issued in September 2012 in the November 2011 rate case; and
•
a formula rate plan increase at Entergy Mississippi, effective September 2013.

See Note 2 to the financial statements for a discussion of rate proceedings.

The Louisiana Act 55 financing savings obligation variance results from a regulatory charge recorded in the second quarter 2012 because Entergy Gulf States Louisiana and Entergy Louisiana were required to share with customers the savings from the tax treatment related to the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing. See Note 3 to the financial statements for additional discussion of the tax treatment.    


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The Grand Gulf recovery variance is primarily due to increased recovery of higher costs resulting from the Grand Gulf uprate.

The volume/weather variance is primarily due to the effects of more favorable weather on residential sales and an increase in industrial sales primarily due to growth in the refining segment.

The fuel recovery variance is primarily due to:

•
the deferral of increased capacity costs that will be recovered through fuel adjustment clauses;
•
the expiration of the Evangeline gas contract on January 1, 2013; and
•
an adjustment to deferred fuel costs recorded in the third quarter 2012 in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of this PUCT order issued in Entergy Texas’s 2011 rate case.

The MISO deferral variance is primarily due to the deferral in April 2013, as approved by the APSC, of costs incurred from March 2010 through December 2012 related to the transition and implementation of joining the MISO RTO.
 
The asset retirement obligation affects net revenue because Entergy records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation-related costs collected in revenue. The variance is primarily caused by a decrease in regulatory credits resulting from higher realized income on decommissioning trust fund investments.

Entergy Wholesale Commodities

Following is an analysis of the change in net revenue comparing 2013 to 2012.
  
Amount
  
(In Millions)
 
 
2012 net revenue

$1,854

Mark-to-market
(58
)
Nuclear volume
(24
)
Nuclear fuel expenses
(20
)
Nuclear realized price changes
58

Other
(8
)
2013 net revenue

$1,802


As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by approximately $52 million in 2013 primarily due to:

•
the effect of rising forward power prices on electricity derivative instruments that are not designated as hedges, including additional financial power sales conducted in the fourth quarter 2013 to offset the planned exercise of in-the-money protective call options and to lock in margins. These additional sales did not qualify for hedge accounting treatment, and increases in forward prices after those sales were made accounted for the majority of the negative mark-to-market variance. The underlying transactions resulted in earnings in first quarter 2014 as these positions settled. See Note 16 to the financial statements for discussion of derivative instruments;
•
the decrease in net revenue compared to prior year resulting from the exercise of resupply options provided for in purchase power agreements where Entergy Wholesale Commodities may elect to supply power from another source when the plant is not running. Amounts related to the exercise of resupply options are included in the GWh billed in the table below; and


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•
higher nuclear fuel expenses primarily resulting from the effect of the write-down in March 2012 of the carrying value of Vermont Yankee’s nuclear fuel, which resulted in a lower level of nuclear fuel amortization in 2012, and the subsequent purchase of additional nuclear fuel in early-2013.

These decreases were partially offset by higher capacity prices.

Following are key performance measures for Entergy Wholesale Commodities for 2013 and 2012.
 
2013
 
2012
Owned capacity (MW) (a)
6,068
 
6,612
GWh billed
45,127
 
46,178
Average realized price per MWh
$50.86
 
$50.02
 
 
 
 
Entergy Wholesale Commodities Nuclear Fleet
 
 
 
Capacity factor
89%
 
89%
GWh billed
40,167
 
41,042
Average realized revenue per MWh
$50.15
 
$50.29
Refueling Outage Days:
 
 
 
FitzPatrick
—
 
34
Indian Point 2
—
 
28
Indian Point 3
28
 
—
Palisades
—
 
34
Pilgrim
45
 
—
Vermont Yankee
27
 
—

(a)
The reduction in owned capacity is due to the retirement of the 544 MW Ritchie Unit 2 in November 2013.

Other Income Statement Items

Utility

Other operation and maintenance expenses increased from $2,080 million for 2012 to $2,264 million for 2013 primarily due to:

•
an increase of $83 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge, recognized in September 2013, related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
•
an increase of $46 million in fossil-fueled generation expenses primarily due to the acquisitions of the Hot Spring plant by Entergy Arkansas and the Hinds plant by Entergy Mississippi in November 2012. Costs related to the Hot Spring and Hinds plants are recovered through the capacity acquisition rider and power management rider, respectively, as previously discussed. Also contributing to the increases is an overall higher scope of work done during plant outages as compared to the prior year;
•
an increase of $72 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative, partially offset by the deferral of approximately $44 million of these costs. See the “Human Capital Management Strategic Imperative” below for further discussion;
•
an increase of $16 million in energy efficiency costs at Entergy Arkansas. These costs are recovered through an energy efficiency rider and have minimal effect on net income;

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Management's Financial Discussion and Analysis

•
an increase of $13 million in nuclear expenses, primarily due to higher labor costs, including higher contract labor;
•
the deferral in 2012, as approved by the LPSC and the FERC, of costs related to the transition and implementation of joining the MISO RTO, which reduced 2012 expenses by $10 million; and
•
an increase of $9 million resulting from costs related to the generator stator incident at ANO, including an offset for expected insurance proceeds. See “ANO Damage, Outage, and NRC Reviews” below for further discussion of the incident.

Also, other operation and maintenance expenses include $36 million in 2013 and $38 million in 2012 of costs incurred related to the now-terminated plan to spin off and merge the Utility’s transmission business.

Taxes other than income taxes increased primarily due to an increase in ad valorem taxes, primarily due to the Hot Spring and Hinds plant acquisitions in 2012, as well as an increase in local franchise taxes resulting from higher residential and commercial revenues as compared with prior year.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Hot Spring and Hinds plant acquisitions in 2012 and the completion of the Waterford 3 steam generator replacement project and the Grand Gulf uprate project in 2012.  Also contributing to the increase is an increase in depreciation rates as a result of the 2011 rate case order issued by the PUCT in September 2012.

Interest expense increased primarily due to net debt issuances in 2013 of $520 million by the Utility operating companies and System Energy and lower allowance for borrowed funds used during construction due to the completion of several major projects in 2012.

Entergy Wholesale Commodities

Other operation and maintenance expenses increased from $958 million for 2012 to $1,048 million for 2013 primarily due to:

•
an increase of $43 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge, recognized in September 2013, related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
•
an increase of $23 million primarily due to the effect of the final court decisions in the Vermont Yankee and Indian Point 2 lawsuits against the U.S. Department of Energy related to spent nuclear fuel disposal recorded in 2012. The damages awarded included the reimbursement of approximately $25 million of spent nuclear fuel storage costs previously recorded as operation and maintenance expenses;
•
an increase of $16 million resulting from implementation and severance costs in 2013 related to the human capital management strategic imperative. See “Human Capital Management Strategic Imperative” below for further discussion; and
•
approximately $15 million in commitments recorded in connection with the settlement agreement with parties in Vermont regarding the operation and decommissioning of Vermont Yankee. See “Impairment of Long-Lived Assets” in Note 1 to the financial statements for further discussion of the settlement agreement.

The asset impairment variance is primarily due to $321.5 million ($202.2 million after-tax) in 2013 and $355.5 million ($223.5 million after-tax) in 2012 of impairment and other related charges primarily to write down the carrying value of Vermont Yankee and related assets to their fair values. See Note 1 to the financial statements for further discussion of these charges.

Depreciation and amortization expenses increased primarily due to an adjustment in 2012 resulting from final court decisions in the Indian Point 2 and Vermont Yankee lawsuits against the U.S. Department of Energy related to

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spent nuclear fuel disposal. The effects of recording the proceeds from the judgment reduced the plant in service balances and included a $25 million reduction to previously-recorded depreciation expense.

The gain on sale of business resulted from the sale in November 2013 of Entergy Solutions District Energy, a business wholly-owned by Entergy in the Entergy Wholesale Commodities segment that owned and operated district energy assets serving the business districts in Houston and New Orleans. Entergy sold Entergy Solutions District Energy for $140 million and realized a pre-tax gain of $44 million on the sale.

Other income increased primarily due to realized decommissioning trust gains that resulted from portfolio reallocations for the Indian Point 2 and Palisades decommissioning trust funds.

Other expenses increased primarily due to a credit to decommissioning expense of $49 million in the second quarter 2012 resulting from a reduction in the decommissioning cost liability for a plant as a result of a revised decommissioning cost study. See “Critical Accounting Estimates - Nuclear Decommissioning Costs” for further discussion of nuclear decommissioning costs.

Parent & Other

Other operation and maintenance expenses increased primarily due to the elimination of intersegment activity.

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 2013 was 23.6%. The difference in the effective income tax rate versus the statutory rate of 35% for 2013 was primarily related to (1) IRS settlements as discussed further in Note 3 to the financial statements; and (2) a tax benefit associated with the now-terminated plan to spin off and merge the Utility’s transmission business, because certain associated costs became deductible with the termination of the transaction.

The effective income tax rate for 2012 was 3.4%. The difference in the effective income tax rate versus the statutory rate of 35% for 2012 was primarily related to (1) IRS settlements as discussed further in Note 3 to the financial statements; and (2) a unanimous court decision from the U.S. Court of Appeals for the Fifth Circuit affirming an earlier decision of the U.S. Tax Court holding that Entergy was entitled to claim a credit against its U.S. tax liability for the U.K. windfall tax that it paid. The decision necessitated that Entergy reverse the provision for the uncertain tax position related to that item.

Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants

The NRC operating license for Palisades expires in 2031, for Pilgrim expires in 2032, and for FitzPatrick expires in 2034. For additional discussion regarding the shutdown of the Vermont Yankee plant in December 2014, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements.
 
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 date of the NRC operating license for Indian Point 2 was in September 2013 and the original expiration date of the NRC operating license for Indian Point 3 is in December 2015. Authorization to operate Indian Point 2 rests, and for Indian Point 3 will rest, on Entergy’s having timely filed a license renewal application that remains pending before the NRC. Indian Point 2 has now entered its “period of extended operation” after expiration of the plant’s 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. Indian Point 3 is expected to reach the same milestone, and to become subject to the same statutorily prescribed extension of its license expiration date, in December 2015. The license

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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 scope of NRC license renewal applications is focused primarily on whether the licensee has in place aging management programs (detailed diagnostic analyses performed when and as prescribed) to ensure that passive systems, structures, and components (such as pipes and concrete and metal structures) can continue to perform their intended safety functions. Other aspects of nuclear plant operations (maintenance of active components like pumps and control systems, security, and emergency preparedness) are regulated by the NRC on an ongoing basis and, as such, are outside the scope of license renewal proceedings. The NRC also determines whether there are any environmental impacts that would affect license renewal.

Every application for renewal of a reactor operating license undergoes comprehensive NRC staff review to ensure the adequacy of the application and the aging management programs detailed in it. NRC staff’s conclusions following such review are set forth in a Final Safety Evaluation Report (FSER). Issuance of a renewed operating license is a “major federal action” under the National Environmental Policy Act, so NRC staff also are required to prepare an Environmental Impact Statement (EIS) regarding the proposed licensing action. The NRC has elected to address certain EIS issues on a generic basis via the rulemaking process. As a result, the EIS for a particular license renewal proceeding has two components: the Generic Environmental Impact Statement and a Final Supplemental Environmental Impact Statement (FSEIS) addressing site-specific EIS issues. Both the FSER and the FSEIS are subject to updating by NRC staff in an individual license renewal proceeding.

Where, as in the case of Indian Point, one or more intervenors proposes for admission contentions alleging errors and omissions in the applicant’s license renewal application or the NRC staff’s review of related safety and environmental issues, the NRC appoints an ASLB to determine whether the contentions satisfy threshold standards and, if so, to adjudicate such “admitted” contentions. Safety-related contentions address issues that will be or have been described in the FSER; environmental-related contentions address issues that will be or have been described in the FSEIS. Contentions may be proposed at any time before license issuance based on new and material information, subject to timeliness and admissibility standards. Final ASLB orders on admissibility or resolving contentions, whether after hearing or on summary disposition, are appealable to the NRC.

Various governmental and private intervenors have sought and obtained party status to express opposition to renewal of the Indian Point 2 and Indian Point 3 licenses. The ASLB has admitted 16 consolidated contentions based on 21 contentions originally proposed by the State of New York or other parties.

Four of the 16 admitted contentions have been resolved by the ASLB without hearing, two by means of ASLB-approved settlements, a third by summary disposition as described below, and a fourth by motion to dismiss as moot as described in the second paragraph below. In July 2011 the ASLB granted the State of New York’s motion for summary disposition of an admitted contention challenging the adequacy of a section of Indian Point’s environmental analysis as incorporated in the Final Supplemental Environmental Impact Statement (FSEIS) (discussed below). That section provided cost estimates for Severe Accident Mitigation Alternatives (SAMAs), which are hardware and procedural changes that could be implemented to mitigate estimated impacts of off-site radiological releases in case of a hypothesized severe accident. In addition to finding that the SAMA cost analysis was insufficient, the ASLB directed the NRC staff to explain why cost-beneficial SAMAs should not be required to be implemented. Entergy appealed the ASLB’s decision to the NRC and the NRC staff supported Entergy’s appeal, while the State of New York opposed it. In December 2011 the NRC denied Entergy’s appeal as premature. Entergy renewed its appeal in February 2014 in conjunction with the filing of Track 1 appeals, as discussed further below. In May 2013, Entergy filed an updated SAMA cost analysis with the NRC, and in July 2013 the ASLB granted Entergy’s motion for clarification that a future NRC staff filing would be the trigger for potential new or amended contentions on the SAMA update.

Nine of the remaining admitted contentions were designated by the ASLB as “Track 1” and were subject to hearings over 12 days in October, November, and December 2012. In November 2013 the ASLB issued a decision on the nine Track 1 contentions. The ASLB resolved eight Track 1 contentions favorably to Entergy. No appeal was

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taken from the ASLB's decision on six of those eight contentions, so they have been conclusively resolved in Entergy's favor. The ASLB resolved one Track 1 contention favorably to New York State. That contention was based on a dispute over the characterization of certain electrical equipment as “active” or “passive.” The ASLB found in favor of the State of New York despite precedent supporting the characterization advocated by Entergy and NRC staff.

Following the ASLB's November 2013 decision on Track 1 contentions, the State of New York and Clearwater each appealed the decision on a single contention (SAMA decontamination cost estimates for the State of New York and environmental justice for Clearwater), while Riverkeeper filed no appeals. Entergy and NRC staff both appealed the same three issues: (1) the ASLB’s decision on electrical transformers; (2) certain intermediate determinations in the ASLB’s overall favorable decision on environmental justice; and (3) the ASLB’s earlier decisions on SAMA cost estimates, thus renewing their appeals of that issue previously denied by the NRC as premature. Appeal (3) addressed a contention that was one of the four decided without hearing. The remaining appeals addressed contentions that were tried in Track 1 hearings.

In February 2015, the NRC granted petitions for review of two appeals for the purpose of obtaining additional information prior to making final disposition. The appeals for which the NRC requested answers to specified questions were New York State’s appeal on SAMA decontamination cost estimates and the appeal of Entergy and NRC staff on SAMA cost estimates. The NRC stated that the remaining appeals filed after the ASLB’s Track 1 decision would be resolved in the future. There is no deadline for the NRC action on either group of appeals from the ASLB.

The remaining four admitted consolidated contentions were designated by the ASLB as “Track 2.” In April 2014 the ASLB granted Entergy’s motion to dismiss as moot a contention by Riverkeeper alleging that the FSEIS failed to adequately address endangered species issues. At the same time, the ASLB denied a motion filed by Riverkeeper in August 2013 to amend its endangered species contention. These ASLB decisions were not appealed and are now final, making a total of nine of the original 16 admitted consolidated contentions that have been resolved favorably (or in the case of settlement, acceptably) to Entergy. Seven of the original 16 admitted consolidated contentions are on appeal (four total) or pending hearing on Track 2 (three total).

While Track 2 hearings have not been scheduled, the procedural steps leading to such hearings have begun. Pursuant to ASLB procedural orders, New York State filed in February 2015 proposed revisions to two of the three admitted contentions designated as Track 2. Entergy and NRC staff will have an opportunity to oppose or to seek limitations on those contention revisions, after which the ASLB will decide whether to accept New York State’s proposed revisions to previously-admitted contentions. In addition, before Track 2 hearings are convened, the parties will have the opportunity to update and complete their testimony.

Independent of the ASLB process, the NRC staff has performed its technical and environmental reviews of the Indian Point 2 and Indian Point 3 license renewal application. The NRC staff issued an FSER in August 2009, a supplement to the FSER in August 2011, an FSEIS in December 2010, a supplement to the FSEIS in June 2013, and, as noted above, a further supplement to the FSER in November 2014. In November 2014 the NRC staff advised of its proposed schedule for issuance of a further FSEIS supplement to address new information received by NRC staff since preparation and publication of the previous FSEIS supplement in June 2013. The proposed schedule identifies several milestones leading to the issuance of a new final FSEIS supplement in March 2016. The matters to be addressed in the new supplement include Entergy’s May 2013 submittal of updated cost information for SAMAs; Entergy’s February 2014 submittal of new aquatic impact information; the June 2013 revision by the NRC of its Generic Environmental Impact Statement relied upon in license renewal proceedings; and the NRC’s Continued Storage Of Spent Nuclear Fuel rule, which was published in the Federal Register in September 2014.

The hearing process is an integral component of the NRC’s regulatory framework, and evidentiary hearings on license renewal applications are not uncommon. Entergy is participating fully in the hearing and appeals processes as authorized by the NRC regulations. As noted in Entergy filings at the ASLB and the appellate levels, Entergy believes the contentions proposed by the intervenors are unsupported and without merit. Entergy will continue to work with the NRC staff as it completes its technical and environmental reviews of the Indian Point 2 and 3 license renewal

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applications. See “Nuclear Matters” below for discussion of spent nuclear fuel storage issues and their potential effect on the timing of license renewals.

The New York State Department of Environmental Conservation (NYSDEC) has taken the position that Indian Point must obtain a new state-issued Clean Water Act Section 401 water quality certification as part of the license renewal process. Entergy submitted its application for a water quality certification to NYSDEC in April 2009, with a reservation of rights regarding the applicability of Section 401 in this case. After Entergy submitted certain additional information in response to NYSDEC requests for additional information, in February 2010 the NYSDEC staff determined that Entergy’s water quality certification application was complete. In April 2010 the NYSDEC staff issued a proposed notice of denial of Entergy’s water quality certification application (the Notice). NYSDEC staff’s Notice triggered an administrative adjudicatory hearing before NYSDEC ALJs on the proposed Notice. The NYSDEC staff decision does not restrict Indian Point operations, but the issuance of a certification is potentially required prior to NRC issuance of renewed unit licenses. In June 2011, Entergy filed notice with the NRC that NYSDEC, the agency that would issue or deny a water quality certification for the Indian Point license renewal process, had taken longer than one year to take final action on Entergy’s application for a water quality certification and, therefore, had waived its opportunity to require a certification under the provisions of Section 401 of the Clean Water Act. The NYSDEC has notified the NRC that it disagrees with Entergy’s position and does not believe that it has waived the right to require a certification. The NYSDEC ALJs overseeing the agency’s certification adjudicatory process stated in a ruling issued in July 2011 that while the waiver issue is pending before the NRC, the NYSDEC hearing process will continue on selected issues. The ALJs held a Legislative Hearing (agency public comment session) and an Issues Conference (pre-trial conference) in July 2010 and set certain issues for trial in October 2011. In 2014, hearings were held on NYSDEC’s proposed best technology available, closed cycle cooling. The NYSDEC staff also has proposed annual fish protection outages of 42, 62, or 92 days at both units or at one unit with closed cycle cooling at the other. The ALJs held a further legislative hearing and issues conference on this NYSDEC staff proposal in July 2014. In January 2015, Entergy wrote NYSDEC leadership requesting an explanation of the delay in release of the ruling following an ALJ’s on-record statement that the ALJ’s draft ruling was under “executive review.” In February 2015, the ALJs issued a ruling scheduling hearings on the outage proposals and other pending issues in September and October 2015, with post-hearing briefing to follow in December 2015.

The ALJs have issued no partial decisions on the several issues that have been the subject of hearing during the past three years and have not announced a schedule for doing so. After the completion of hearings on the merits, the ALJs will issue a recommended decision to the NYSDEC Commissioner’s designated delegate who will then issue the final agency decision.  A party to the proceeding can appeal the final agency decision to state court.

In addition, before the NRC may issue renewed operating licenses it must resolve its obligation to address the requirements of the Coastal Zone Management Act (CZMA). Most commonly, those requirements are met by the applicant’s demonstration that the activity authorized by the federal permit being sought is consistent with the host state’s federally-approved coastal management policies. Entergy has undertaken three independent initiatives to resolve CZMA issues: “grandfathering;” “previous review;” and a “consistency certification.”

First, Entergy filed with the New York State Department of State (NYSDOS) in November 2012 a petition for declaratory order that Indian Point is grandfathered under either of two criteria prescribed by the New York Coastal Management Program (NYCMP), which sets forth the state coastal policies applied in a CZMA consistency review. NYSDOS denied the motion by order dated January 2013. Entergy filed a petition for judicial review of NYSDOS’s decision with the New York State Supreme Court for Albany County in March 2013. The court denied Entergy’s appeal in December 2013. Entergy initiated an appeal to the Appellate Division of the New York State Supreme Court in January 2014. In December 2014 a five-judge panel of that court unanimously held that Indian Point is exempt from CZMA consistency review by NYSDOS because it meets one of the two criteria for grandfathering established in the NYCMP. The court did not address the second criterion.

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Appeal to New York State’s highest court, the State Court of Appeals, is discretionary in this case. In January 2015, NYSDOS filed with the same court a motion for reargument or, alternatively, leave to appeal to the State Court of Appeals. Entergy timely filed opposing papers. If the Appellate Division denies NYSDOS’s motion, NYSDOS may then file a separate motion for leave to appeal directly with the State Court of Appeals.

Second, in July 2012, Entergy filed a supplement to the Indian Point license renewal applications currently pending before the NRC.  The supplement states that, based on applicable federal law and in light of prior reviews by the State of New York, the NRC may issue the requested renewed operating licenses for Indian Point without the need for an additional consistency review by the State of New York under the CZMA. In July 2012, Entergy filed a motion for declaratory order with the ASLB seeking confirmation of its position that no further CZMA consistency determination is required before the NRC may issue renewed licenses. In April 2013 the State of New York and Riverkeeper filed answers opposing Entergy’s motion. The State of New York also filed a cross-motion for declaratory order seeking confirmation that Indian Point had not been previously reviewed, and that only NYSDOS could conduct a CZMA review for NRC license renewal purposes. In April 2013 the NRC Staff filed answers recommending the ASLB deny both Entergy’s and the State of New York’s motions for declaratory order. In June 2013 the ASLB denied Entergy’s and the State of New York’s motions, without prejudice, on the ground that consultation on the matter of previous review among the NRC, Entergy (as applicant), and the State of New York had not taken place, as the ASLB determined to be required. In December 2013, NRC staff initiated consultation under federal CZMA regulations by serving on NYSDOS written questions related to whether Indian Point had been previously reviewed. In May 2014 the NYSDOS responded to questions the NRC staff submitted in December 2013. In July 2014, Entergy submitted comments on NYSDOS’s responses and NYSDOS filed a reply to those comments. Further submissions to the NRC staff with respect to the previous review issue were made by Entergy in November 2014 and by NYSDOS in December 2014. The NRC staff advised the ASLB in February 2015 that it is reviewing the information it has received regarding previous review and will provide further information when available.
    
Third, in December 2012, Entergy filed with NYSDOS a consistency determination explaining why Indian Point satisfies all applicable NYCMP policies while noting that Entergy did not concede NYSDOS’s right to conduct a new CZMA review for Indian Point. In January 2013, NYSDOS notified Entergy that it deemed the consistency determination incomplete because it did not include the final version of a further supplement to the FSEIS that was targeted for subsequent issuance by NRC staff. In June 2013, NYSDOS notified Entergy that NYSDOS had received a copy of the final version of the FSEIS on June 20, 2013, and that NYSDOS’s review of the Indian Point consistency determination had begun that date. By a series of agreements, Entergy and NYSDOS agreed to extend NYSDOS’s deadline for concurring with or objecting to the Indian Point consistency certification to December 31, 2014. In November 2014, Entergy filed with the NRC and with NYSDOS a notice withdrawing the consistency certification. Entergy cited the NRC staff’s announcement two days earlier of its intent to issue in March 2016 a new FSEIS supplement addressing, among other things, new information concerning aquatic impacts. Entergy stated that unless the previous review or grandfathering issues were first and finally resolved in Entergy’s favor, Entergy intended to file a new consistency certification after the NRC issues the FSEIS supplement. That new consistency certification would initiate NYSDOS’s review process, would allow the FSEIS supplement to also be part of the record before NYSDOS, and, were NYSDOS to object to the new certification, would also be part of the record before the U.S. Secretary of Commerce on appeal.

NYSDOS disputed the effectiveness of Entergy’s November 2014 notice withdrawing the consistency certification. In December 2014, Entergy and NYSDOS executed an agreement intended to preserve the parties’ respective positions on withdrawal. The agreement provides, among other things, that if NYSDOS is correct about withdrawal not being effective, the parties will be deemed to have agreed to a stay of NYSDOS’s deadline for decision on the 2012 consistency certification to June 30, 2015.
    


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ANO Damage, Outage, and NRC Reviews

On March 31, 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 turbine building serves both ANO 1 and 2 and is a non-radiological area of the plant. ANO 2 reconnected to the grid on April 28, 2013 and ANO 1 reconnected to the grid on August 7, 2013.  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.  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.

Entergy Arkansas is pursuing its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. Entergy is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the members’ nuclear generating plants, including ANO. NEIL has notified Entergy that it believes that a $50 million course of construction sublimit applies to any loss associated with the lifting apparatus failure and stator drop at ANO. Entergy has responded that it disagrees with NEIL’s position and is evaluating its options for enforcing its rights under the policy. During 2014, Entergy Arkansas collected $50 million from NEIL and is pursuing additional recoveries due under the policy. On July 12, 2013, Entergy Arkansas filed a complaint in the Circuit Court in Pope County, Arkansas against the owner of the heavy-lifting apparatus that collapsed, an engineering firm, a contractor, and certain individuals asserting claims of breach of contract, negligence, and gross negligence in connection with their responsibility for the stator drop.

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 May 2014 the NRC met with Entergy during a regulatory conference to discuss the preliminary red and yellow findings and Entergy’s response to the findings. During the regulatory conference, Entergy presented information on the facts and assumptions the NRC used to assess the potential findings. The NRC used the information provided by Entergy at the regulatory conference to finalize its decision regarding the inspection team’s findings. In a letter dated June 23, 2014, the NRC classified both findings as “yellow with substantial safety significance.” In an assessment follow-up letter for ANO dated July 29, 2014, the NRC stated that given the two yellow findings, it determined that the performance at ANO is in the “degraded cornerstone column,” or column 3, of the NRC’s reactor oversight process action matrix beginning the first quarter 2014. Corrective actions in response to the NRC’s findings have been taken and remain ongoing at ANO. The NRC plans to conduct supplemental inspection activity to review the actions taken to address the yellow findings. Entergy will continue to interact with the NRC to address the NRC’s findings.    

In September 2014 the NRC issued an inspection report on the flood barrier effectiveness issue that was still under review at the time of the March 2014 inspection report. While Entergy believes that the flood barrier issues that led to the finding have been addressed at ANO, NRC processes still required that the NRC assess the safety significance of the deficiencies. In its September 2014 inspection report, the NRC discussed a preliminary finding of “yellow with

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substantial safety significance” for the Unit 1 and Unit 2 auxiliary and emergency diesel fuel storage buildings.  The NRC indicated that these preliminary findings may warrant additional regulatory oversight.  Entergy requested a public regulatory conference regarding the inspection, and the conference was held in October 2014. During the regulatory conference, Entergy presented information related to the facts and assumptions used by the NRC in arriving at its preliminary finding of “yellow with substantial safety significance.” In January 2015 the NRC issued its final risk significance determination for the flood barrier violation originally cited in the September 2014 report. The NRC’s final risk significance determination was classified as “yellow with substantial safety significance.”

The NRC’s January 2015 letter did not advise ANO of the additional level of oversight that will result from the yellow finding related to the flood barrier issue, and it stated that the NRC would inform ANO of this decision by separate correspondence. The yellow finding may result in ANO being placed into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. Placement into this column would require significant additional NRC inspection activities at the ANO site, including a review of the site’s root cause evaluation associated with the flood barrier 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. The additional NRC inspection activities at the site are expected to increase ANO’s operating costs.

Human Capital Management Strategic Imperative

Entergy engaged in a strategic imperative intended to optimize the organization through a process known as human capital management. In July 2013 management completed a comprehensive review of Entergy’s organization design and processes. This effort resulted in a new internal organization structure, which resulted in the elimination of approximately 800 employee positions. Entergy incurred approximately $110 million and approximately $20 million in costs in 2013 and 2014, respectively, associated with this phase of human capital management, primarily implementation costs, severance expenses, pension curtailment losses, special termination benefits expense, and corporate property, plant, and equipment impairments. In December 2013, Entergy deferred for future recovery approximately $45 million of these costs, as approved by the APSC and the LPSC. See Note 2 to the financial statements for details of the deferrals and Note 13 to the financial statements for details of the restructuring charges.

Liquidity and Capital Resources

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

Capital Structure

Entergy’s capitalization is balanced between equity and debt, as shown in the following table.
 
2014
 
2013
Debt to capital
57.6
%
 
57.9
%
Effect of excluding securitization bonds
(1.4
%)
 
(1.6
%)
Debt to capital, excluding securitization bonds (a)
56.2
%

56.3
%
Effect of subtracting cash
(2.8
%)
 
(1.5
%)
Net debt to net capital, excluding securitization bonds (a)
53.4
%

54.8
%

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

Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable and commercial paper, capital lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt, common shareholders’ equity, and subsidiaries’ preferred stock without sinking fund. Net capital consists of capital less cash

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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, 2014. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2014. The amounts below include payments on the Entergy Louisiana and System Energy sale-leaseback transactions, which are included in long-term debt on the balance sheet.

Long-term debt maturities and
estimated interest payments
 
 
2015
 
 
2016
 
2017
 
 
2018-2019
 
 
after 2019
 
 
(In Millions)
Utility
 

$882

 

$746

 

$886

 

$2,070

 

$13,997

Entergy Wholesale Commodities
 
19

 
2

 
2

 
4

 
53

Parent and Other
 
624

 
60

 
537

 
757

 
466

Total
 

$1,525

 

$808

 

$1,425

 

$2,831

 

$14,516


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 March 2019. Entergy Corporation has the ability to issue letters of credit against 50% of the total borrowing capacity of the facility. The commitment fee is currently 0.275% 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, 2014 was 1.93% on the drawn portion of the facility.

As of December 31, 2014, amounts outstanding and capacity available under the $3.5 billion credit facility are:
 
Capacity (a)
 
 
Borrowings
 
Letters
of Credit
 
Capacity
Available
(In Millions)
$3,500
 
$695
 
$9
 
$2,796

A covenant in Entergy Corporation’s credit facility requires Entergy to maintain a consolidated debt ratio of 65% or less of its total capitalization.  The calculation of this debt ratio under Entergy Corporation’s credit facility is different than the calculation of the debt to capital ratio above. Entergy is currently in compliance with the covenant. If Entergy fails to meet this ratio, or if Entergy or one of the Utility operating companies (except Entergy New Orleans) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the Entergy Corporation credit facility’s maturity date may occur.

Entergy Corporation has a commercial paper program with a Board-approved program limit of up to $1.5 billion.  At December 31, 2014, Entergy Corporation had $484 million of commercial paper outstanding.  The weighted-average interest rate for the year ended December 31, 2014 was 0.88%.


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Capital lease obligations are a minimal part of Entergy’s overall capital structure. Following are Entergy’s payment obligations under those leases.
 
2015
 
2016
 
2017
 
2018-2019
 
after 2019
 
(In Millions)
Capital lease payments
$5
 
$4
 
$4
 
$7
 
$28

The capital leases are discussed in Note 10 to the financial statements.

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2014 as follows:
 
Company
 
 
Expiration Date
 
Amount of
Facility
 
 
Interest Rate (a)
 
Amount Drawn as
of December 31, 2014
Entergy Arkansas
 
April 2015
 
$20 million (b)
 
1.67%
 
—
Entergy Arkansas
 
March 2019
 
$150 million (c)
 
1.67%
 
—
Entergy Gulf States Louisiana
 
March 2019
 
$150 million (d)
 
1.42%
 
—
Entergy Louisiana
 
March 2019
 
$200 million (e)
 
1.42%
 
—
Entergy Mississippi
 
May 2015
 
$10 million (f)
 
1.67%
 
—
Entergy Mississippi
 
May 2015
 
$20 million (f)
 
1.67%
 
—
Entergy Mississippi
 
May 2015
 
$35 million (f)
 
1.67%
 
—
Entergy Mississippi
 
May 2015
 
$37.5 million (f)
 
1.67%
 
—
Entergy New Orleans
 
November 2015
 
$25 million
 
1.92%
 
—
Entergy Texas
 
March 2019
 
$150 million (g)
 
1.67%
 
—

(a)
The interest rate is the rate as of December 31, 2014 that would be 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 allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2014, no letters of credit were outstanding.
(d)
The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2014, no letters of credit were outstanding.
(e)
The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2014, no letters of credit were outstanding.
(f)
Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option.
(g)
The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2014, $1.3 million in letters of credit were outstanding.

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


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In addition, Entergy Arkansas, Entergy Gulf States Louisiana, 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 related to MISO. Following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2014:
 
 
 
Amount of
 
 
 
Letters of Credit Issued as of
Company
 
 
 Uncommitted Facility
 
Letter of Credit Fee
 
December 31, 2014
Entergy Arkansas
 
 
$25 million
 
0.70%
 

$2.0
 million
Entergy Gulf States Louisiana
 
 
$75 million
 
0.70%
 

$27.9
 million
Entergy Louisiana
 
 
$50 million
 
0.70%
 

$4.7
 million
Entergy Mississippi
 
 
$40 million
 
0.70%
 

$14.4
 million
Entergy Mississippi
 
 
$40 million
 
1.50%
 

$—

Entergy New Orleans
 
 
$15 million
 
0.75%
 

$8.1
 million
Entergy Texas
 
 
$50 million
 
0.70%
 

$24.5
 million

In January 2015, Entergy Nuclear Vermont Yankee entered into a credit facility guaranteed by Entergy Corporation with a borrowing capacity of $60 million which expires in January 2018. Also in January 2015, Entergy Nuclear Vermont Yankee entered into an uncommitted credit facility guaranteed by Entergy Corporation with a borrowing capacity of $85 million which expires in January 2018. See Note 4 to the financial statements for additional discussion of the Vermont Yankee 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, 2014 on non-cancelable operating leases with a term over one year:
 
2015
 
2016
 
2017
 
2018-2019
 
after 2019
 
(In Millions)
Operating lease payments
$90
 
$77
 
$62
 
$97
 
$96

The operating leases are discussed in Note 10 to the financial statements.

Summary of Contractual Obligations of Consolidated Entities

Contractual Obligations
 
2015
 
2016-2017
 
2018-2019
 
after 2019
 
Total
 
 
(In Millions)
Long-term debt (a)
 

$1,525

 

$2,233

 

$2,831

 

$14,516

 

$21,105

Capital lease payments (b)
 

$5

 

$8

 

$7

 

$28

 

$48

Operating leases (b) (c)
 

$90

 

$139

 

$97

 

$96

 

$422

Purchase obligations (d)
 

$1,898

 

$2,738

 

$2,405

 

$5,821

 

$12,862


(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.

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(d)
Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services.  Almost all of the total are fuel and purchased power obligations.

In addition to the contractual obligations given above, Entergy currently expects to contribute approximately $396.2 million to its pension plans and approximately $66.9 million to other postretirement plans in 2015, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015. 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 $441 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 2015 through 2017.
Planned construction and capital investments
 
2015
 
2016
 
2017
 
 
(In Millions)
Utility:
 
 
 
 
 
 
Generation
 

$1,585

 

$635

 

$1,040

Transmission
 
805

 
670

 
665

Distribution
 
715

 
700

 
650

Other
 
230

 
190

 
155

Total
 
3,335

 
2,195

 
2,510

Entergy Wholesale Commodities
 
425

 
265

 
275

Total
 

$3,760

 

$2,460

 

$2,785


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:

•
Potential resource planning investments, including the Union Power Station acquisition discussed below, and potential construction of additional generation.

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•
Entergy Wholesale Commodities investments associated with specific investments such as component replacements, software and security, NYPA value sharing in January 2015, dry cask storage, and nuclear license renewal.
•
Environmental compliance spending, including potential scrubbers at White Bluff to meet pending Arkansas state requirements under the Clean Air Visibility Rule. Entergy continues to review potential environmental spending needs and financing alternatives for any such spending, and future spending estimates could change based on the results of this continuing analysis and the implementation of new environmental laws and regulations.
•
NRC post-Fukushima requirements for the Utility and Entergy Wholesale Commodities nuclear fleets.
•
Transmission spending to enhance reliability, reduce congestion, and enable economic growth.

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 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. 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.

Union Power Station Purchase Agreement

In December 2014, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas entered into an asset purchase agreement to acquire 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). Pursuant to the agreement, Entergy Gulf States Louisiana will acquire two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy Texas will each acquire one power block and a 25% undivided ownership interest in such related assets. If Entergy Arkansas or Entergy Texas do not obtain approval for the purchase of their power blocks, Entergy Gulf States Louisiana will seek to purchase the power blocks not approved. The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments.  In addition, Entergy Gulf States Louisiana anticipates selling 20% of the capacity and energy associated with its two power blocks to Entergy New Orleans through a cost-based, life-of-unit power purchase agreement. The purchase is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federal and state regulatory and permitting agencies. These include regulatory approvals from the APSC, LPSC, PUCT, and FERC, as well as clearance under the Hart-Scott-Rodino anti-trust law. In December 2014, Entergy Texas filed its application with the PUCT for approval of the acquisition. The PUCT has indicated that it will convene the hearing on the merits of this case in June 2015. Entergy Texas intends to file a rate application to seek cost recovery later in 2015. In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC and Entergy Arkansas filed its application with the APSC, each for approval of the acquisition and cost recovery. Closing is targeted to occur in late-2015.
     
Ninemile Point Unit 6 Self-Build Project

In June 2011, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by Entergy Louisiana’s construction of a combined-cycle gas turbine generating facility (Ninemile 6) at its existing Ninemile Point electric generating station. Ninemile 6 is a nominally-sized 560 MW unit that is expected to cost approximately $655 million to construct when spending is complete, excluding interconnection and transmission upgrades. Entergy Gulf States Louisiana joined in the application, seeking certification of its purchase under a life-of-unit power purchase agreement of up to 25% of the capacity and energy generated by Ninemile 6. The Ninemile 6 capacity and energy is allocated 55% to Entergy Louisiana, 25% to Entergy Gulf States Louisiana, and 20% to Entergy New Orleans. In February 2012 the City Council passed a resolution

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authorizing Entergy New Orleans to purchase 20% of the Ninemile 6 energy and capacity. In March 2012 the LPSC unanimously voted to grant the certifications requested by Entergy Gulf States Louisiana and Entergy Louisiana. Following approval by the LPSC, Entergy Louisiana issued full notice to proceed to the project’s engineering, procurement, and construction contractor.

Under terms approved by the LPSC, non-fuel costs may be recovered through Entergy Louisiana’s and Entergy Gulf States Louisiana’s formula rate plans beginning in the month after the unit is placed in service. In July 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed an unopposed stipulation with the LPSC that estimates a first year revenue requirement associated with Ninemile 6 and provides a mechanism to update the revenue requirement as the in-service date approaches, which was subsequently approved by the LPSC. In late December 2014, roughly contemporaneous with the unit’s placement in service, a final updated estimated revenue requirement of $51.1 million for Entergy Louisiana and $26.8 million for Entergy Gulf States Louisiana was filed. The December 2014 estimate forms the basis of rates implemented effective with the first billing cycle of January 2015. Under terms approved by the City Council, Entergy New Orleans’s non-fuel costs associated with Ninemile 6 may be recovered through a special rider for that purpose. The unit was placed in service in December 2014. Entergy Louisiana will submit project and cost information to the LPSC in mid-2015 to enable the LPSC to review the prudence of Entergy Louisiana’s management of the project.

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 Entergy’s earnings, financial strength, and future investment opportunities. At its January 2015 meeting, the Board declared a dividend of $0.83 per share, which is the same quarterly dividend per share that Entergy has paid since the second quarter 2010. Entergy paid $596 million in 2014, $593 million in 2013, and $589 million in 2012 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 unit awards to key employees, which may be exercised to obtain shares of Entergy’s common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy’s management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans.

In addition to the authority to fund grant exercises, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2010 the Board granted authority for a $500 million share repurchase program. As of December 31, 2014, $350 million of authority remains under the $500 million share repurchase program. The amount of repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities, or if limitations in the credit markets continue for a prolonged period.

Sources of Capital

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

•
internally generated funds;
•
cash on hand ($1,422 million as of December 31, 2014);
•
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.

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Provisions within the Articles of Incorporation or pertinent indentures and various other agreements relating to the long-term debt and 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. As of December 31, 2014, under provisions in their mortgage indentures, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively. 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 and Entergy New Orleans, which are subject to the jurisdiction of the APSC and the City Council, respectively). No regulatory approvals are necessary for Entergy Corporation to issue securities. The current FERC-authorized short-term borrowing limits are effective through October 31, 2015. Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through October 2015. Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2015. Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through July 2016. Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy each have obtained long-term financing authorizations from the FERC that extend through October 2015 for issuances by its nuclear fuel company variable interest entity. In addition to borrowings from commercial banks, the FERC short-term borrowing orders authorize the Registrant Subsidiaries to continue as participants in the Entergy System money pool. The money pool is an intercompany borrowing arrangement designed to reduce Entergy’s subsidiaries’ dependence on external short-term borrowings. Borrowings from the money pool and external short-term borrowings combined may not exceed the FERC-authorized short-term borrowing limits. See Notes 4 and 5 to the financial statements for further discussion of Entergy’s borrowing limits, authorizations, and amounts outstanding.

Hurricane Isaac

In August 2012, Hurricane Isaac caused extensive damage to portions of Entergy’s service area in Louisiana, and to a lesser extent in Mississippi and Arkansas.  The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages.  In January 2013, Entergy Gulf States Louisiana and Entergy Louisiana drew $65 million and $187 million, respectively, from their funded storm reserve escrow accounts.  In April 2013, Entergy Gulf States Louisiana and Entergy Louisiana filed a joint application with the LPSC relating to Hurricane Isaac system restoration costs.  Specifically, Entergy Gulf States Louisiana and Entergy Louisiana requested that the LPSC determine the amount of such costs that were prudently incurred and are, thus, eligible for recovery from customers.  Including carrying costs and additional storm escrow funds for prior storms, Entergy Gulf States Louisiana requested an LPSC determination that $73.8 million in system restoration costs were prudently incurred and Entergy Louisiana requested an LPSC determination that $247.7 million in system restoration costs were prudently incurred.  In May 2013, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana's and Entergy Louisiana's storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55). The LPSC Staff filed direct testimony in September 2013 concluding that Hurricane Isaac system restoration costs incurred by Entergy Gulf States Louisiana and Entergy Louisiana were reasonable and prudent, subject to proposed minor adjustments which totaled approximately 1% of each company’s costs. Following an evidentiary hearing and recommendations by the ALJ, the LPSC voted in June 2014 to approve a series of orders which (i) quantify the amount of Hurricane Isaac system restoration costs prudently incurred ($66.5 million for Entergy Gulf States Louisiana and $224.3 million for Entergy Louisiana); (ii) determine the level of storm reserves to be re-established ($90 million for Entergy Gulf States Louisiana and $200 million for Entergy Louisiana); (iii) authorize Entergy Gulf States Louisiana and Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) grant other requested relief associated with storm reserves and Act 55 financing of Hurricane

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Isaac system restoration costs. Entergy Gulf States Louisiana committed to pass on to customers a minimum of $6.9 million of customer benefits through annual customer credits of approximately $1.4 million for five years.  Entergy Louisiana committed to pass on to customers a minimum of $23.9 million of customer benefits through annual customer credits of approximately $4.8 million for five years. Approvals for the Act 55 financings were obtained from the Louisiana Utilities Restoration Corporation (LURC) and the Louisiana State Bond Commission.

In July 2014, Entergy Gulf States Louisiana issued $110 million of 3.78% Series first mortgage bonds due April 2025 and used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes. In July 2014, Entergy Louisiana issued $190 million of 3.78% Series first mortgage bonds due April 2025 and used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes.

In August 2014 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $71 million in bonds under Act 55 of the Louisiana Legislature.  From the $69 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $3 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $66 million directly to Entergy Gulf States Louisiana.  Entergy Gulf States Louisiana used the $66 million received from the LURC to acquire 662,426.80 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.

In August 2014 the LCDA issued another $243.85 million in bonds under Act 55 of the Louisiana Legislature.  From the $240 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $13 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $227 million directly to Entergy Louisiana.  Entergy Louisiana used the $227 million received from the LURC to acquire 2,272,725.89 Class C preferred, non-voting, membership interest units of Entergy Holdings Company LLC 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, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA and there is no recourse against Entergy, Entergy Gulf States Louisiana, or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remit the collections to the bond indenture trustee.  Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the collections as revenue because they are merely acting as the billing and collection agents for the state.


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Cash Flow Activity

As shown in Entergy’s Statements of Cash Flows, cash flows for the years ended December 31, 2014, 2013, and 2012 were as follows:
 
2014
 
2013
 
2012
 
(In Millions)
Cash and cash equivalents at beginning of period

$739

 

$533

 

$694

 


 
 
 
 
Net cash provided by (used in):
 

 
 

 
 

Operating activities
3,890

 
3,189

 
2,940

Investing activities
(2,955
)
 
(2,602
)
 
(3,639
)
Financing activities
(252
)
 
(381
)
 
538

Net increase (decrease) in cash and cash equivalents
683

 
206

 
(161
)
 
 
 
 
 
 
Cash and cash equivalents at end of period

$1,422

 

$739

 

$533


Operating Activities

2014 Compared to 2013

Net cash provided by operating activities increased by $701 million in 2014 primarily due to:

•
higher Entergy Wholesale Commodities and Utility net revenues in 2014 as compared to the same period in 2013, as discussed previously;
•
proceeds of $310 million received from the LURC in August 2014 as a result of the Louisiana Act 55 storm cost financings. See Note 2 to the financial statements for a discussion of the Act 55 storm cost financings;
•
an increase of $60 million in 2014 as compared to 2013 as a result of $58 million margin deposits made by Entergy Wholesale Commodities in 2013;
•
a decrease in income tax payments of $50 million in 2014 compared to 2013 primarily due to state income tax effects of the settlement of the 2004-2005 IRS audit paid in 2013; and
•
approximately $25 million in spending in 2013 related to the generator stator incident at ANO, as discussed previously.

The increase was partially offset by:

•
an increase of $236 million in pension contributions in 2014, partially offset by a decrease of $38 million in lump sum retirement payments out of the non-qualified pension plan in 2014 as compared to 2013. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding;
•
proceeds of $72 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel;
•
an increase of $44 million in spending on nuclear refueling outages in 2014 as compared to 2013; and
•
an increase of $25 million in storm restoration spending in 2014.

2013 Compared to 2012

Net cash provided by operating activities increased by $249 million in 2013 primarily due to:

•
increased recovery of deferred fuel costs;
•
higher Utility net revenues in 2013 resulting from additional generation investments made in 2012;

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•
proceeds of $72 million associated with the payments received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel;
•
a decrease of approximately $84 million in storm restoration spending in 2013 due to Hurricane Isaac in August 2012, partially offset by an increase of approximately $23 million in storm restoration spending in 2013 due to the Arkansas December 2012 winter storm;
•
a refund of $30.6 million, including interest, paid to AmerenUE in June 2012. The FERC ordered Entergy Arkansas to refund to AmerenUE the rough production cost equalization payments previously collected. See Note 2 to the financial statements for further discussion of the FERC order; and
•
a decrease of $14 million in spending on nuclear refueling outages in 2013 as compared to the same period in prior year.

The increase was partially offset by:

•
an increase of $79 million in income tax payments primarily due to the 2013 state income tax effects of the settlement of the 2004-2005 IRS audit in the fourth quarter 2012;
•
an increase of $52 million in lump sum retirement payments out of the non-qualified pension plan, partially offset by a decrease of $7 million in pension contributions. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding;
•
the decrease in Entergy Wholesale Commodities net revenue that was discussed previously; and
•
approximately $25 million in spending related to the generator stator incident at ANO, as discussed previously.

Investing Activities

2014 Compared to 2013

Net cash used in investing activities increased by $353 million in 2014 primarily due to:

•
the deposit of a total of $276 million into storm reserve escrow accounts in 2014, primarily by Entergy Gulf States Louisiana and Entergy Louisiana. See “Hurricane Isaac” above for a discussion of storm reserve escrow account replenishments in 2014;
•
the withdrawal of a total of $260 million from storm reserve escrow accounts in 2013, primarily by Entergy Gulf States Louisiana and Entergy Louisiana, after Hurricane Isaac. See “Hurricane Isaac” above for discussion of storm reserve escrow account withdrawals;
•
proceeds of $140 million from the sale in November 2013 of Entergy Solutions District Energy. See Note 15 to the financial statements for further discussion of the sale;
•
proceeds of $21 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel; and
•
an increase 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.

The increase was partially offset by:

•
a decrease in construction expenditures, primarily in the Utility business, including a decrease in spending on the Ninemile 6 self-build project and spending in 2013 on the generator stator incident at ANO, partially offset by an increase in storm restoration spending. Entergy’s construction spending plans for 2015 through 2017 are discussed further in “Capital Expenditure Plans and Other Uses of Capital” above;
•
a change in collateral deposit activity, reflected in the “Decrease (increase) in other investments” line on the Consolidated Statement of Cash Flows, as Entergy received net deposits of $47 million in 2014 and returned net deposits of $88 million in 2013.  Entergy Wholesale Commodities’ forward sales contracts are discussed in the “Market and Credit Risk Sensitive Instruments” section below; and

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•
$37 million in insurance proceeds received in 2014 for property damages related to the generator stator incident at ANO, as discussed above.

2013 Compared to 2012

Net cash used in investing activities decreased by $1,038 million in 2013 primarily due to:

•
the acquisitions of the Hot Spring plant by Entergy Arkansas and the Hinds plant by Entergy Mississippi in November 2012. See Note 15 to the financial statements for further discussion of these plant acquisitions;
•
the withdrawal of a total of $260 million from storm reserve escrow accounts in 2013, primarily by Entergy Gulf States Louisiana and Entergy Louisiana, after Hurricane Isaac. See Note 2 to the financial statements for a discussion of Hurricane Isaac;
•
a decrease in construction expenditures, primarily in the Utility business, resulting from spending in 2012 on the uprate project at Grand Gulf and storm restoration spending in 2012 resulting from the Arkansas December 2012 winter storm and Hurricane Isaac, substantially offset by spending in 2013 on the Ninemile 6 self-build project and spending in 2013 related to the generator stator incident at ANO, as discussed previously; and
•
proceeds of $140 million from the sale in November 2013 of Entergy Solutions District Energy. See Note 15 to the financial statements for further discussion of the sale.

The decrease was partially offset by:

•
a change in collateral deposit activity, reflected in the “Decrease (increase) in other investments” line on the Consolidated Statement of Cash Flows, as Entergy returned $50 million more net deposits in 2013 than 2012. Entergy Wholesale Commodities’ forward sales contracts are discussed in the “Market and Credit Risk Sensitive Instruments” section below; and
•
proceeds of $21 million in 2013 compared to proceeds of $109 million in 2012 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel.

Financing Activities

2014 Compared to 2013

Net cash flow used in financing activities decreased by $129 million in 2014 primarily due to:

•
long-term debt activity providing approximately $777 million of cash in 2014 compared to using $69 million of cash in 2013.  The most significant long-term debt activity in 2014 included the net issuance of approximately $385 million of long-term debt at the Utility operating companies and System Energy and Entergy Corporation increasing borrowings outstanding on its long-term credit facility by $440 million in 2014;
•
Entergy Corporation repaid $561 million of commercial paper in 2014 and issued $380 million in 2013;
•
an increase of $112 million in 2014 compared to a decrease of $129 million in 2013 in short-term borrowings by the nuclear fuel company variable interest entities;
•
the repurchase of $183 million of Entergy common stock in 2014; and
•
an increase of $170 million in treasury stock issuances in 2014 primarily due to a larger amount of previously repurchased Entergy Corporation common stock issued in 2014 to satisfy stock option exercises.

2013 Compared to 2012

Financing activities used $381 million in net cash in 2013 compared to providing $538 million in net cash in 2012 primarily due to:

•
long-term debt activity using approximately $69 million of cash in 2013 compared to providing $348 million of cash in 2012. The most significant long-term debt activity in 2013 included the net issuance of approximately

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$520 million of long-term debt at the Utility operating companies and System Energy and Entergy Corporation decreasing borrowings outstanding on its long-term credit facility by $540 million;
•
Entergy Corporation issued $380 million of commercial paper in 2013 and $665 million in 2012, in part, to repay borrowings on its long-term credit facility;
•
a net decrease of $136 million in short-term borrowings by the nuclear fuel company variable interest entities; and
•
$51 million in proceeds from the sale to a third party in 2012 of a portion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests.

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 City Council, the LPSC, the MPSC, the PUCT, and the FERC, are primarily responsible for approval of the rates charged to customers. Following is a summary of the Utility operating companies’ authorized returns on common equity:
Company
 
Authorized
Return on
Common Equity
 
 
 
Entergy Arkansas
 
9.5%
Entergy Gulf States Louisiana
 
9.15%-10.75% Electric; 9.45%-10.45% Gas
Entergy Louisiana
 
9.15% - 10.75%
Entergy Mississippi
 
10.07%
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

Entergy’s Integration Into the MISO Regional Transmission Organization

In April 2011, Entergy announced that each of the Utility operating companies proposed to join the MISO RTO, an RTO operating in several U.S. states and also in Canada. On December 19, 2013, the Utility operating companies completed their planned integration into the MISO RTO. 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. With the Utility operating companies fully integrated as members, however, MISO assumed control of transmission planning and congestion management and, through its Day 2 market, MISO 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 market.


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The Utility operating companies obtained from each of their retail regulators the public interest findings sought by the Utility operating companies in order to move forward with their plan to join MISO. Each of the retail regulators’ orders includes conditions, some of which entail compliance prospectively. See also “System Agreement - Utility Operating Company Notices of Termination of System Agreement Participation” below.

Beginning in 2011 the Utility operating companies and the MISO RTO began submitting various filings with the FERC that contained many of the rates, terms and conditions that would govern the Utility operating companies’ integration into the MISO RTO. The Utility operating companies and the MISO RTO received the FERC orders necessary for those companies to integrate into the MISO RTO consistent with the approvals obtained from the Utility operating companies’ retail regulators, although some proceedings remain pending at the FERC.

In January 2013, Occidental Chemical Corporation filed with the FERC a petition for declaratory judgment and complaint against MISO alleging that MISO’s proposed treatment of Qualifying Facilities (QFs) in the Entergy region is unduly discriminatory in violation of sections 205 and 206 of the Federal Power Act and violates the Public Utility Regulatory Policies Act (PURPA) and the FERC’s implementing regulations. In February 2014, Occidental also filed a petition for enforcement with the FERC against the LPSC. Occidental’s petition for enforcement alleges that the LPSC’s January 2014 order, which approved Entergy Gulf States Louisiana’s and Entergy Louisiana’s application for modification of Entergy’s methodology for calculating avoided cost rates paid to QFs, is inconsistent with the requirements of PURPA and the FERC’s regulations implementing PURPA. In April 2014 the FERC issued a “Notice Of Intent Not To Act At This Time” with respect to Occidental’s petition for enforcement against the LPSC. The FERC concluded that Occidental’s petition for enforcement largely raises the same issues as those raised in the January 2013 complaint and petition for declaratory order that Occidental filed against MISO, and that the two proceedings should be addressed at the same time. The FERC reserved its ability to issue a further order or to take further action at a future date should it find that doing so is appropriate.

In April 2014, Occidental filed a complaint in federal district court for the Middle District of Louisiana against the LPSC and Entergy Louisiana that challenges the January 2014 order issued by the LPSC on grounds similar to those raised in the 2013 complaint and 2014 petition for enforcement that Occidental previously filed at the FERC.  The district court complaint also seeks damages from Entergy Louisiana and a declaration from the district court that in pursuing the January 2014 order Entergy Louisiana breached an existing agreement with Occidental and an implied covenant of good faith and fair dealing. In January 2015 the district court granted Entergy Louisiana’s motion to stay the district court proceeding, pending a decision from the FERC relating to the MISO tariff and market rules that are underlying Occidental’s district court complaint. In January 2015, Occidental filed a motion for reconsideration in the district court and also filed a notice of appeal to the U.S. Fifth Circuit Court of Appeals. In February 2015 the district court denied the motion for reconsideration as moot, finding it lacked jurisdiction to consider the motion because Occidental had sought an appeal to the U.S. Fifth Circuit Court of Appeals.

In February 2013, Entergy Services, on behalf of the Utility operating companies, made a filing with the FERC requesting to adopt the standard Attachment O formula rate template used by transmission owners to establish transmission rates within MISO. The filing proposed four transmission pricing zones for the Utility operating companies, one for Entergy Arkansas, one for Entergy Mississippi, one for Entergy Texas, and one for Entergy Louisiana, Entergy Gulf States Louisiana, and Entergy New Orleans. In June 2013 the FERC issued an order accepting the use of four transmission pricing zones and set for hearing and settlement judge procedures those issues of material fact that FERC decided could not be resolved based on the existing record. Several parties, including the City Council, filed requests for rehearing of the June 2013 order. In February 2014 the FERC issued an order addressing the rehearing requests. Among other things, the FERC denied rehearing and affirmed its prior decision allowing the four transmission pricing zones for the Utility operating companies in MISO. The FERC granted rehearing and set for hearing and settlement judge proceedings certain challenges of MISO’s regional through and out rates. In March 2014 certain parties filed a request for rehearing of the FERC’s February 2014 order on issues related to MISO’s regional through and out rates. In February 2014 and April 2014 various parties appealed the FERC’s June 2013 and February 2014 orders to the U.S. Court of Appeals for the D.C. Circuit where the appeals have been consolidated for further proceedings.


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System Agreement

The FERC regulates wholesale rates (including Entergy Utility intrasystem energy allocations pursuant to the System Agreement) and interstate transmission of electricity, as well as 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 Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC. The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement. See Note 2 to the financial statements for discussions of this litigation.

Utility Operating Company Notices of Termination of System Agreement Participation

Consistent with their written notices of termination delivered in December 2005 and November 2007, respectively, Entergy Arkansas and Entergy Mississippi filed with the FERC in February 2009 their notices of cancellation to terminate their participation in the System Agreement, effective December 18, 2013 and November 7, 2015, respectively. In November 2009 the FERC accepted the notices of cancellation and determined that Entergy Arkansas and Entergy Mississippi are permitted to withdraw from the System Agreement following the 96-month notice period without payment of a fee or the requirement to otherwise compensate the remaining Utility operating companies as a result of withdrawal. In December 2009 the LPSC and the City Council filed with the FERC a request for rehearing of the FERC's November 2009 order. In February 2011 the FERC denied the LPSC’s and the City Council’s rehearing requests. In September and October 2012 the U.S. Court of Appeals for the D.C. Circuit denied the LPSC’s and the City Council’s appeals of the FERC decisions. In January 2013 the LPSC and the City Council filed a petition for a writ of certiorari with the U.S. Supreme Court. In May 2013 the U.S. Supreme Court denied the petition for a writ of certiorari. Effective December 18, 2013, Entergy Arkansas ceased participating in the System Agreement.

In October 2012 the PUCT issued an order approving the transfer of operational control of Entergy Texas’s transmission facilities to MISO as in the public interest, subject to the terms and conditions in a non-unanimous settlement filed with the PUCT in August 2012, with several additional terms and conditions requested by the PUCT and agreed to by the settling parties. In particular, the settlement and the PUCT order required Entergy Texas, unless otherwise directed by the PUCT, to provide by October 31, 2013 its notice to exit the System Agreement, subject to certain conditions. In addition, the PUCT order requires Entergy Texas, as well as Entergy Corporation and Entergy Services, Inc., to exercise reasonable best efforts to engage the Utility operating companies and their retail regulators in searching for a consensual means, subject to FERC approval, of allowing Entergy Texas to exit the System Agreement prior to the end of the mandatory 96-month notice period.

In December 2012 the PUCT Staff filed a memo in the proceeding established by the PUCT to track compliance with its October 2012 order. In the memo, the PUCT Staff expressed concerns about the effect of Entergy Texas’s exit from the System Agreement on PPAs for gas and oil-fired generation units owned by Entergy Texas and Entergy Gulf States Louisiana that were entered into upon the December 2007 jurisdictional separation of Entergy Gulf States, Inc. and, further, expressed concerns about the implications of these issues as they relate to the continuing validity of the PUCT’s October 2012 order regarding MISO. Entergy Texas subsequently filed a position statement relating that Entergy Texas’s exit from the System Agreement would trigger the termination of the PPAs of concern to the PUCT Staff. Entergy Texas expressed its continuing commitment to work collaboratively with the PUCT Staff and other parties to address ongoing issues and challenges in implementing the PUCT order including any potential effect from termination of the PPAs. In January 2013, Entergy Texas filed an updated analysis assessing the effect on the benefits of MISO membership of terminating the particular PPAs addressed in Entergy Texas’s Statement of Position upon Entergy Texas’s exit from the System Agreement, and determined that termination of these PPAs did not adversely affect the benefits of the move to MISO once Entergy Texas exits the System Agreement. An independent consultant

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was retained to assist the PUCT Staff in its assessment of the analysis. In April 2013 the PUCT staff filed a study performed by its independent consultant assessing Entergy Texas’s January 2013 updated analysis of the effect of termination of certain PPAs on Entergy Texas’s costs upon Entergy Texas’s exit from the System Agreement. While the independent consultant study concluded that the adjustments made in Entergy Texas’s updated analysis were analytically correct, the consultant also recommended further study regarding the effect of the termination of the PPAs on the benefits associated with Entergy Texas joining MISO. Entergy Texas filed a response to the consultant study, noting a number of errors in the analysis and recommending against any further study of this matter. Entergy Texas subsequently agreed to fund further analysis, to be performed by a different independent consultant for the PUCT, regarding the effects of termination of these PPAs. In August 2013 the report of the PUCT’s second independent consultant regarding the effects of termination of these PPAs was filed with the PUCT as part of a larger report addressing the results of the consultant’s comprehensive analysis of Entergy Texas’s transition to operations post-exit from the System Agreement. The report concluded, consistent with Entergy Texas’s updated analysis, that under both the “Foundation Case” capacity price forecast and the high capacity price sensitivity that were performed, Entergy Texas and its customers would be better off on a present-value basis if these PPAs terminate. Under the low capacity price sensitivity, there was a net cost to Entergy Texas customers if these PPAs terminate. Consistent with the requirements of the PUCT conditional order approving the change in control to MISO, on October 18, 2013, Entergy Texas gave notice of cancellation to terminate its participation in the System Agreement.

In November 2012 the Utility operating companies filed amendments to the System Agreement with the FERC pursuant to section 205 of the Federal Power Act. The amendments consist primarily of the technical revisions needed to the System Agreement to (i) allocate certain charges and credits from the MISO settlement statements to the participating Utility operating companies; and (ii) address Entergy Arkansas’s withdrawal from the System Agreement. As noted in the filing, the Utility operating companies’ integration into MISO and the revisions to the System Agreement are the main feature of the Utility operating companies’ future operating arrangements, including the successor arrangements with respect to the departure of Entergy Arkansas from the System Agreement. The LPSC, MPSC, PUCT, and City Council filed protests at the FERC regarding the amendments filed in November 2012 and other aspects of the Utility operating companies’ future operating arrangements, including requests that the continued viability of the System Agreement in MISO (among other issues) be set for hearing by the FERC. On March 12, 2013, the Utility operating companies filed an answer to the protests. The answer proposed, among other things, that: (1) the FERC allow the System Agreement revisions to go into effect as of December 19, 2013, without a hearing and for an initial two-year transition period; (2) no later than October 18, 2013, Entergy Services submit a filing pursuant to section 205 of the Federal Power Act that provides Entergy Texas’s notice of cancellation to terminate participation in the System Agreement and responds to the PUCT’s position that Entergy Texas be allowed to terminate its participation prior to the end of the mandatory 96-month notice period; and (3) at least six months prior to the end of the two-year transition period, Entergy Services submits an additional filing under section 205 of the Federal Power Act that addresses the allocation of MISO charges and credits among the Utility operating companies that remain in the System Agreement. On December 18, 2013, the FERC issued an order accepting the revisions filed in November 2012, subject to a further compliance filing and other conditions. The FERC set one issue for hearing involving a settlement with Union Pacific regarding certain coal delivery issues. Consistent with the decisions described above, Entergy Arkansas’s participation in the System Agreement terminated effective December 18, 2013. 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 the methodology proposed by the MPSC. The Utility operating companies and other parties to the proceeding have filed briefs on exceptions and/or briefs opposing exceptions with the FERC challenging various aspects of the December 2014 initial decision and the matter is pending before the FERC.

In keeping with the commitments made in their March 2013 answer to the protests and after a careful evaluation of the basis for and continued reasonableness of the 96-month System Agreement termination notice period, the Utility operating companies filed with the FERC on October 11, 2013 to amend the System Agreement changing the notice period for an operating company to terminate its participation in the System Agreement from 96 months to 60 months. The proposed amendment also clarifies that the revised notice period will apply to any written notice of termination

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provided by an operating company on or after October 12, 2013. On October 18, 2013, Entergy Texas provided notice to terminate its participation in the System Agreement effective after expiration of the proposed 60-month notice period or such other period as approved by FERC. The proposed amendment and Entergy Texas’s termination notice are without prejudice to continuing efforts among affected operating companies and their retail regulators to search for a consensual means of allowing Entergy Texas an early exit from the System Agreement, which could be different from that proposed in the October 11, 2013 FERC filing. Comments on both filings were filed in November 2013.

The LPSC, the City Council, and the PUCT protested the proposed amendment to shorten the notice period for an operating company to terminate its participation in the System Agreement from 96 months to 60 months. The City Council argued that Entergy has not adequately supported its proposal to shorten the notice period from 96 months to 60 months and asked the FERC to either reject the amendment or set it for hearing. The PUCT supported shortening of the notice period, but argued that 60 months is not short enough and that the FERC should instead order Entergy to shorten the notice period to correspond to the time required for a Utility operating company to become operationally ready to participate in the MISO markets (but no longer than 36 months). The LPSC argued that the 60-month proposal was not justified and failed to make provision for the consequences that would flow from a company’s withdrawal from the System Agreement. The LPSC and the City Council both separately protested Entergy Texas’s termination notice.

In January 2014 the LPSC issued a directive that no later than February 15, 2014, Entergy Louisiana and Entergy Gulf States Louisiana each shall provide notice of their intention to terminate their participation in the System Agreement and shall make the necessary filings at the FERC of such notice. The LPSC further directed that Entergy Louisiana and Entergy Gulf States Louisiana and LPSC Staff continue utilizing their reasonable best efforts to achieve a consensual resolution permitting early termination of the System Agreement. On February 14, 2014, Entergy Louisiana and Entergy Gulf States Louisiana provided notice of their respective decisions to terminate their participation in the System Agreement and made a filing with the FERC seeking acceptance of the notice. In the FERC filing, Entergy Louisiana and Entergy Gulf States Louisiana requested an effective date of February 14, 2019 or such other effective date approved by the FERC for the termination. In March 2014 the City Council submitted comments to the FERC regarding the notices of termination. The City Council requested the FERC either to condition its acceptance of the notices on compliance with the prior 96-month notice termination period, or in the alternative, to consolidate the notice filings with the proceeding related to the Utility operating companies’ proposal to shorten the System Agreement’s termination notice period from 96 months to 60 months, and to set all of the proceedings for hearing. Also in March 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed a response to the City Council’s comments requesting that the FERC accept the notices without hearing and with an effective date subject to and consistent with the notice period established by the FERC in the proceeding related to the Utility operating companies’ proposal to shorten the System Agreement’s termination notice period.

In December 2014 the FERC issued an order setting the proposed amendment changing the notice period from 96 months to 60 months for settlement judge and hearing procedures. The FERC’s order also conditionally accepted the notices of termination filed by Entergy Texas, Entergy Louisiana, and Entergy Gulf States Louisiana, to be effective as of the dates requested in those filings, subject to the outcome of the settlement judge procedures and hearing on the proposed amendment. Entergy Louisiana, Entergy Gulf States Louisiana, Entergy New Orleans, and Entergy Texas continue to explore with the LPSC staff, City Council advisors, and the PUCT staff the early termination of the System Agreement on a consensual basis.

U.S. Department of Justice Investigation
 
In September 2010, Entergy was notified that the U.S. Department of Justice had commenced a civil investigation of competitive issues concerning certain generation procurement, dispatch, and transmission system practices and policies of the Utility operating companies. In November 2012 the U.S. Department of Justice issued a press release in which the U.S. Department of Justice stated, among other things, that the civil investigation concerning certain generation procurement, dispatch, and transmission system practices and policies of the Utility operating companies would remain open.  The release noted, however, the intention of each of the Utility operating companies

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to join MISO and Entergy’s agreement with ITC to undertake the spin-off and merger of Entergy’s transmission business.  The release stated that if Entergy follows through on these matters, the U.S. Department of Justice’s concerns will be resolved. The release further stated that the U.S. Department of Justice will monitor developments, and in the event that Entergy does not make meaningful progress, the U.S. Department of Justice can and will take appropriate enforcement action, if warranted. On December 13, 2013, Entergy and ITC mutually agreed to terminate the transaction following denial by the MPSC of the joint application related to the transaction. On December 19, 2013, the Utility operating companies successfully completed their planned integration into the MISO RTO.

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 17 to the financial statements for details regarding Entergy’s decommissioning trust funds.
•
The interest rate risk associated with changes in interest rates as a result of Entergy’s outstanding indebtedness.  Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to total capitalization.  See Notes 4 and 5 to the financial statements for the details of Entergy’s debt outstanding.

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

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

Power Generation

As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers.  Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy in the day ahead or spot markets.  In addition to selling the energy produced by its plants, Entergy Wholesale Commodities 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

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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, 2014.

Entergy Wholesale Commodities Nuclear Portfolio
 
 
2015
 
2016
 
2017
 
2018
 
2019
Energy
 
 
 
 
 
 
 
 
 
 
Percent of planned generation under contract (a):
 
 
 
 
 
 
 
 
 
 
Unit-contingent (b)
 
47%
 
23%
 
14%
 
14%
 
16%
Unit-contingent with availability guarantees (c)
 
18%
 
17%
 
18%
 
3%
 
3%
Firm LD (d)
 
40%
 
34%
 
7%
 
—%
 
—%
Offsetting positions (e)
 
(19%)
 
—%
 
—%
 
—%
 
—%
Total
 
86%
 
74%
 
39%
 
17%
 
19%
Planned generation (TWh) (f) (g)
 
35
 
36
 
35
 
35
 
36
Average revenue per MWh on contracted volumes:
 
 
 
 
 
 
 
 
 
 
Minimum
 
$47
 
$47
 
$48
 
$56
 
$57
Expected based on market prices as of December 31, 2014
 
$48
 
$49
 
$50
 
$56
 
$57
Sensitivity: -/+ $10 per MWh market price change
 
$47-$50
 
$47-$53
 
$49-$53
 
$56
 
$57
 
 
 
 
 
 
 
 
 
 
 
Capacity
 
 
 
 
 
 
 
 
 
 
Percent of capacity sold forward (h):
 
 
 
 
 
 
 
 
 
 
Bundled capacity and energy contracts (i)
 
18%
 
18%
 
18%
 
18%
 
18%
Capacity contracts (j)
 
30%
 
15%
 
16%
 
7%
 
—%
Total
 
48%
 
33%
 
34%
 
25%
 
18%
Planned net MW in operation (g)
 
4,406
 
4,406
 
4,406
 
4,406
 
4,406
Average revenue under contract per kW per month(applies to capacity contracts only)
 
$3.9
 
$3.4
 
$5.6
 
$7.0
 
$—
 
 
 
 
 
 
 
 
 
 
 
Total Nuclear Energy and Capacity Revenues
 
 
 
 
 
 
 
 
 
 
Expected sold and market total revenue per MWh
 
$53
 
$50
 
$50
 
$51
 
$53
Sensitivity: -/+ $10 per MWh market price change
 
$51-$56
 
$46-$56
 
$44-$57
 
$43-$60
 
$45-$61


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Entergy Wholesale Commodities Non-Nuclear Portfolio
 
 
2015
 
2016
 
2017
 
2018
 
2019
Energy
 
 
 
 
 
 
 
 
 
 
Percent of planned generation under contract (a):
 
 
 
 
 
 
 
 
 
 
Cost-based contracts (k)
 
38%
 
36%
 
34%
 
34%
 
34%
Firm LD (d)
 
7%
 
7%
 
7%
 
7%
 
7%
Total
 
45%
 
43%
 
41%
 
41%
 
41%
Planned generation (TWh) (f) (l)
 
5
 
6
 
6
 
6
 
6
 
 
 
 
 
 
 
 
 
 
 
Capacity
 
 
 
 
 
 
 
 
 
 
Percent of capacity sold forward (h):
 
 
 
 
 
 
 
 
 
 
Cost-based contracts (k)
 
24%
 
24%
 
26%
 
26%
 
26%
Bundled capacity and energy contracts (i)
 
8%
 
8%
 
8%
 
8%
 
8%
Capacity contracts (j)
 
54%
 
53%
 
57%
 
24%
 
—%
Total
 
86%
 
85%
 
91%
 
58%
 
34%
Planned net MW in operation (l)
 
1,052
 
1,052
 
977
 
977
 
977

(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, seller is generally not liable to buyer for any damages.
(c)
A sale of power on a unit-contingent basis coupled with a guarantee of availability provides 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.
(d)
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.
(e)
Transactions for the purchase of energy, generally to offset a Firm LD transaction.
(f)
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.
(g)
Assumes NRC license renewals for plants whose current licenses expired or expire within five years, and uninterrupted normal operation at all operating plants.  NRC license renewal applications are in process 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).  For a discussion regarding the license renewal application for Indian Point 2 and Indian Point 3, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” above.
(h)
Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions.
(i)
A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold.
(j)
A contract for the sale of an installed capacity product in a regional market.
(k)
Contracts priced in accordance with cost-based rates, a ratemaking concept used for the design and development of rate schedules to ensure that the filed rate schedules recover only the cost of providing the service; these contracts are on owned non-utility resources located within Entergy’s Utility service area and were executed

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prior to receiving market-based rate authority under MISO.  The percentage sold assumes completion of the necessary transmission upgrades required for the approved transmission rights.
(l)
Non-nuclear planned generation and net MW in operation include purchases from affiliated and non-affiliated counterparties under long-term contracts and exclude energy and capacity from Entergy Wholesale Commodities’ wind investment. The decrease in planned net MW in operation beginning in 2017 is due to the expiration of a non-affiliated 75 MW contact.

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 $107 million in 2015 and would have had a corresponding effect on pre-tax income of $240 million in 2014. 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 ($73) million in 2015 and would have had a corresponding effect on pre-tax income of ($91) million in 2014.

Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA.  In October 2007, NYPA and the subsidiaries that own the FitzPatrick and Indian Point 3 plants amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms.  Under the amended value sharing agreements, the Entergy subsidiaries agreed to make 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 is due by January 15 of the following year.  Entergy records the liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick.  In 2014, 2013, and 2012, Entergy Wholesale Commodities recorded a liability of approximately $72 million for generation during each of those years.  An amount equal to the liability was recorded each year to the plant asset account as contingent purchase price consideration for the plants.  This amount will be depreciated over the expected remaining useful life of 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 collateral to secure its obligations under the agreements.  The Entergy subsidiary is required to provide collateral based upon the difference between the current market and contracted power prices in the regions where Entergy Wholesale Commodities sells power.  The primary form of collateral to satisfy these requirements is an Entergy Corporation guaranty.  Cash and letters of credit are also acceptable forms of collateral.  At December 31, 2014, based on power prices at that time, Entergy had liquidity exposure of $159 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $5 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, 2014, Entergy would have been required to provide approximately $51 million of additional cash or letters of credit under some of the agreements. As of December 31, 2014, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $52 million for a $1 per MMBtu increase in gas prices in both the short-and long-term markets.  
    
As of December 31, 2014, substantially all of the counterparties or their guarantors for the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 2018 have public investment grade credit ratings.

Nuclear Matters

After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States.  The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently

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refined and prioritized after input from stakeholders.  The task force then issued a second report in September 2011.  Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012.  The three orders require U.S. nuclear operators to undertake plant modifications and perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating nuclear plants.  The NRC, with input from the industry, is continuing to determine the specific actions required by the orders. Entergy’s estimated capital expenditures for 2015 through 2017 for complying with the NRC orders are included in the planned construction and other capital investments estimates given in “Liquidity and Capital Resources - Capital Expenditure Plans and Other Uses of Capital” above.

In June 2012 the U.S. Court of Appeals for the D.C. Circuit vacated the NRC’s 2010 update to its Waste Confidence Decision, which had found generically that a permanent geologic repository to store spent nuclear fuel would be available when necessary and that spent nuclear fuel could be stored at nuclear reactor sites in the interim without significant environmental effects, and remanded the case for further proceedings. The court concluded that the NRC had not satisfied the requirements of the National Environmental Policy Act (NEPA) when it considered environmental effects in reaching these conclusions. The Waste Confidence Decision has been relied upon by NRC license renewal applicants to address some of the issues that the NEPA requires the NRC to address before it issues a renewed license. Certain nuclear opponents filed requests with the NRC asking it to address the issues raised by the court’s decision in the license renewal proceedings for a number of nuclear plants including Grand Gulf and Indian Point 2 and 3. In August 2012 the NRC issued an order stating that it will not issue final licenses dependent upon the Waste Confidence Decision until the D.C. Circuit’s remand is addressed, but also stating that licensing reviews and proceedings should continue to move forward. In September 2014 the NRC published a new final Waste Confidence rule, named Continued Storage of Spent Nuclear Fuel, that for licensing purposes adopts non-site specific findings concerning the environmental impacts of the continued storage of spent nuclear fuel at reactor sites - for 60 years, 100 years and indefinitely - after the reactor’s licensed period of operations. The NRC also issued an order lifting its suspension of licensing proceedings after the final rule’s effective date in October 2014. After the final rule became effective, New York, Connecticut, and Vermont filed a challenge to the rule in the U.S. Court of Appeals. The final rule remains in effect while that challenge is pending unless the court orders otherwise.

The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system.  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.

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.


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•
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. A high probability that the plant’s license will be renewed and the plant will operate for some time beyond the original license term has been assumed for purposes of calculating the decommissioning liability for a number of Entergy’s nuclear units. 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 obligations.
•
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 3.25%. A 50 basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 9% to 15%. The timing assumption influences the significance of the effect of a change in the estimated inflation or cost escalation rate because the effect increases with the length of time assumed before decommissioning activity ends.
•
Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. The current Presidential administration, however, has defunded the Yucca Mountain project. 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, when applicable. These estimates could change in the future, however, based on the timing of when the DOE begins to fulfill its obligation to receive and store spent nuclear fuel.
•
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.
    
    Future 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, these reductions will immediately reduce operating expenses if the reduction of the liability exceeds the amount of the undepreciated asset retirement cost asset at the date of the revision. Future 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 for which the value is impaired, including a plant that is shutdown, or is nearing its shutdown date, however, for the non-rate-regulated portions of Entergy’s business the increase in the liability will immediately increase operating expense and not the asset retirement cost asset.


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In 2014, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and ANO 2 as a result of a revised decommissioning cost study.  The revised estimates resulted in a $47.6 million increase in the decommissioning cost liabilities, along with a corresponding increase in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.

See Note 1 to the financial statements for further discussion of the shutdown of Vermont Yankee and the December 2013 settlement agreement involving Entergy and Vermont parties.  In accordance with the settlement agreement, Entergy Vermont Yankee provided to the Vermont parties, in 2014, a site assessment study of the costs and tasks of radiological decommissioning, spent nuclear fuel management, and site restoration for Vermont Yankee.  Entergy Vermont Yankee also filed its Post-Shutdown Decommissioning Activities Report (PSDAR) for Vermont Yankee with the NRC in December 2014.  As part of the development of the site assessment study and PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2014.  The revised estimate, along with reassessment of the assumptions regarding the timing of decommissioning cash flows, resulted in a $101.6 million increase in the decommissioning cost liability and a corresponding impairment charge. 

In the fourth quarter 2014, Entergy Gulf States Louisiana recorded a revision to its estimated decommissioning cost liability for River Bend as a result of a revised decommissioning cost study. The revised estimate resulted in a $20 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining useful life of the unit.

In the fourth quarter 2014, 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 $99.9 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the first quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for a nuclear site as a result of a revised decommissioning cost study. The revised estimate resulted in a $46.6 million reduction in the decommissioning cost liability, along with a corresponding reduction in the related asset retirement cost asset.

In the third quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Vermont Yankee as a result of a revised decommissioning cost study. The revised estimate resulted in a $58 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. The asset retirement cost asset was included in the carrying value used to write down Vermont Yankee and related assets to their fair values in third quarter 2013.  See Note 1 to the financial statements for further discussion of the resulting impairment charge recorded in third quarter 2013.
    
In the fourth quarter 2013, 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 $102.3 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the fourth quarter 2013, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $39.4 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the fourth quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Vermont Yankee. As a result of a settlement agreement regarding the remaining operation and decommissioning of Vermont Yankee, Entergy reassessed its assumptions regarding the timing of

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decommissioning cash flows. The reassessment resulted in a $27.2 million increase in the decommissioning cost liability and a corresponding impairment charge. See Note 1 to the financial statements for further discussion of the Vermont Yankee plant.

In the second quarter 2012, Entergy Wholesale Commodities recorded a reduction of $60.6 million in the estimated decommissioning cost liability for a plant as a result of a revised decommissioning cost study.  The revised estimate resulted in a credit to decommissioning expense of $49 million, reflecting the excess of the reduction in the liability over the amount of the undepreciated asset retirement costs asset.

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 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 for Entergy to 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 expected levels; or for certain nuclear plants if their operating licenses are not renewed.

If an asset is considered held for use, and Entergy concludes that an impairment analysis has been triggered 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.

These estimates 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.

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•
Timing - Entergy currently assumes, for some of its nuclear units, that the plant’s license will be renewed.  A change in that assumption could have a significant effect on the expected future cash flows and result in a significant effect on operations.

For additional discussion regarding the shutdown of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements.

Entergy evaluates investment securities with unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred.  The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs.  If Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary-impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss).  Entergy did not have any material other than temporary impairments relating to credit losses on debt securities in 2014, 2013, or 2012.  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.  Entergy Wholesale Commodities did not record material charges to other income in 2014, 2013, or 2012 resulting from the recognition of other-than-temporary impairment of equity securities held in its decommissioning trust funds.  

Qualified Pension and Other Postretirement Benefits

Entergy sponsors qualified, defined benefit pension plans that cover substantially all employees.  Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy.  

In December 2013, Entergy announced that employees hired or rehired after June 30, 2014, will participate in a new cash balance defined benefit pension plan and will be eligible to receive an enhanced employer matching contribution under one of the Entergy defined contribution plans, rather than the current final average pay defined benefit pension plan and employer matching contribution. These changes are prospective and have no effect on the December 31, 2013 pension obligation. Additionally, at the same time, Entergy announced changes to its other postretirement benefits which include, among other things, elimination of other postretirement benefits for all non-bargaining employees hired or rehired after June 30, 2014 and for certain bargaining employees hired or rehired after June 30, 2014, or such later date provided for in their applicable collective bargaining agreement, and setting a dollar limit cap on Entergy’s contribution to retiree medical costs, effective 2019 for those non-bargaining employees who commence their Entergy retirement benefits on or after January 1, 2015 and for certain bargaining employees who commence their Entergy retirement benefits on or after January 1, 2015 or such later date as provided for in their applicable collective bargaining agreement. In accordance with accounting standards, certain of the other postretirement benefit changes have been reflected in the December 31, 2013 other postretirement obligation. The changes affecting active bargaining unit employees are being negotiated with their unions prior to implementation, where necessary, and to the extent required by law.

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 these costs include:

•
Discount rates used in determining future benefit obligations;
•
Projected health care cost trend rates;
•
Expected long-term rate of return on plan assets;
•
Rate of increase in future compensation levels;
•
Retirement rates; and
•
Mortality rates.

Entergy reviews the first four assumptions listed above on an annual basis and adjusts them as necessary.  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.  In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.

The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans.  The 2014 actuarial study reviewed plan experience from 2010 through 2013.  As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies.  These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $504.4 million in the qualified pension benefit obligation and $94.4 million in the accumulated postretirement obligation.  The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $77.4 million and other postretirement cost by approximately $12.3 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.

In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and matches these rates with Entergy’s projected stream of benefit payments.  Based on recent market trends, the discount rates used to calculate its 2014 qualified pension benefit obligation and 2015 qualified pension cost ranged from 4.03% to 4.40% for its specific pension plans (4.27% combined rate for all pension plans). The discount rates used to calculate its 2013 qualified pension benefit obligation and 2014 qualified pension cost ranged from 5.04% to 5.26% for its specific pension plans (5.14% combined rate for all pension plans).  The discount rates used to calculate its 2012 qualified pension benefit obligation and 2013 qualified pension cost ranged from 4.31% to 4.50% for its specific pension plans (4.36% combined rate for all pension plans).  The discount rate used to calculate its 2014 other postretirement benefit obligation and 2015 other postretirement benefit cost was 4.23%.  The discount rate used to calculate its 2013 other postretirement benefit obligation and 2014 other postretirement benefit cost was 5.05%. The discount rate used to calculate its 2012 other postretirement benefit obligation and 2013 other postretirement benefit cost was 4.36%.  

Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates.  Based on this review, Entergy’s health care cost trend rate assumption used in measuring the December 31, 2014 accumulated postretirement benefit obligation and 2015 postretirement cost was 7.10% for pre-65 retirees and 7.70% for post-65 retirees for 2014, gradually decreasing each successive year until it reaches 4.75% in 2023 and beyond for both pre-65 and post-65 retirees. Entergy’s assumed health care cost trend rate assumption used in measuring the December 31, 2013 accumulated postretirement benefit obligation and 2014 postretirement cost was 7.25% for pre-65 retirees and 7.00% for post-65 retirees for 2013, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees.  Entergy’s assumed health care cost trend rate assumption used in measuring 2013 postretirement cost was 7.50% for pre-65 retirees and 7.25% for post-65 retirees, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees. Entergy’s assumed

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health care cost trend rate assumption used in measuring 2012 postretirement cost was 7.75% for pre-65 retirees and 7.50% for post-65 retirees, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees.

The assumed rate of increase in future compensation levels used to calculate 2014 and 2013 benefit obligations was 4.23%.

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 investment managers.

Since 2003, Entergy has targeted an asset allocation for its qualified pension plan assets of roughly 65% equity securities and 35% fixed-income securities.  Entergy completed and adopted an optimization study in 2011 for the pension assets that 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 of 45% equity and 55% fixed income securities.  The ultimate asset allocation is expected to be attained when the plan is 105% funded.

The current target allocations for both Entergy’s non-taxable postretirement benefit assets and its taxable other postretirement benefit assets are 65% equity securities and 35% fixed-income securities.  This takes into account asset allocation adjustments that were made during 2012.

Entergy’s expected long term rate of return on qualified pension assets used to calculate 2014, 2013, and 2012 qualified pension costs was 8.5% and will be 8.25% for 2015.  Entergy’s expected long term rate of return on tax deferred other postretirement assets used to calculate other postretirement costs was 8.3% for 2014 and 8.5% for 2013 and 2012. It will be 8.05% for 2015.  For Entergy’s taxable postretirement assets, the expected long term rate of return was 6.5% for 2014, 2013, and 2012, and will be 6.25% in 2015.

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 and deferral of gains and losses arising from the difference between actuarial estimates and actual experience. Prior service costs/credits and deferred gains and losses are then amortized into expense over future periods. Certain decisions, including workforce reductions and plan amendments, 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 losses or gains. Similarly, payments made to settle benefit obligations can also result in recognition in the form of settlement losses or gains.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified pension projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption
 
Change in
Assumption
 
Impact on 2014
Qualified Pension
Cost
 
Impact on 2014
Qualified Projected
Benefit Obligation
 
 
Increase/(Decrease)
Discount rate
 
(0.25%)
 
$18,707
 
$271,656
Rate of return on plan assets
 
(0.25%)
 
$10,631
 
$—
Rate of increase in compensation
 
0.25%
 
$7,561
 
$44,183


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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 2014
Postretirement Benefit Cost
 
Impact on 2014 Accumulated
Postretirement Benefit Obligation
 
 
Increase/(Decrease)
Discount rate
 
(0.25%)
 
$4,716
 
$63,342
Health care cost trend
 
0.25%
 
$7,953
 
$55,954

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

Accounting Mechanisms

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.

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.

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.

Costs and Funding

In 2014, Entergy’s total qualified pension cost was $216.5 million, including a $0.7 million special termination charge related to workforce downsizing.  Entergy anticipates 2015 qualified pension cost to be $320.7 million.  Entergy’s pension funding was approximately $399 million for 2014.  Entergy’s contributions to the pension trust are currently estimated to be approximately $396.2 million in 2015, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015.

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.  The pension funding stabilization provisions will provide for a near-term reduction in minimum funding

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Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis

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 Highway and Transportation Funding Act (HATFA) became federal law in August 2014. HATFA’s pension provisions provided a five-year extension of the MAP-21 pension funding stabilization.

Total postretirement health care and life insurance benefit costs for Entergy in 2014 were $50.1 million.  Entergy expects 2015 postretirement health care and life insurance benefit costs to be $66.2 million.  Entergy contributed $76.5 million to its postretirement plans in 2014.  Entergy’s current estimate of contributions to its other postretirement plans is approximately $66.9 million in 2015.

Federal Healthcare Legislation

The Patient Protection and Affordable Care Act (PPACA) became federal law on March 23, 2010, and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 became federal law and amended certain provisions of the PPACA.  Entergy has implemented the major provisions of the law. 

A 40% excise tax on per capita medical benefit costs that exceed certain thresholds is due to take effect beginning in 2018.  There are still many technical issues, however, that have not been finalized.  Entergy will continue to monitor these 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 state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters.
•
The identification of additional impacts, sites, issues, or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party.
•
The resolution or progression of existing matters through the court system or resolution by the EPA or relevant state or local authority.

Litigation

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

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Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


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.

Uncertain Tax Positions

Entergy’s operations, including acquisitions and divestitures, require Entergy to evaluate risks such as the potential tax effects of a transaction, or warranties made in connection with such a transaction.  Entergy believes that it has adequately assessed and provided for these types of risks, where applicable.  Any provisions recorded for these types of issues, however, could be significantly affected by events such as claims made by third parties under warranties, additional transactions contemplated by Entergy, or completion of reviews of the tax treatment of certain transactions or issues by taxing authorities.

New Accounting Pronouncements

The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects.  Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.

In April 2014 the FASB issued ASU No. 2014-08, “Presentation of Financial Statements (Topic 205) and Property Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity” which changes the requirements for reporting discontinued operations. The ASU states that a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results when the component of an entity or group of components of an entity meets the criteria to be classified as held for sale, is disposed of by sale, or is disposed of other than by sale. The amendments in this ASU also require additional disclosures about discontinued operations. ASU 2014-08 is effective for Entergy for the first quarter 2015. Entergy does not currently expect ASU 2014-08 to affect materially its results of operations, financial position, or cash flows.

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. ASU 2014-09 is effective for Entergy for the first quarter 2017. Entergy does not expect ASU 2014-09 to affect materially its results of operations, financial position, or cash flows.

In November 2014 the FASB issued ASU No. 2014-16, “Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity.” The ASU states that for hybrid financial instruments issued in the form of a share, an entity should determine the nature of the host contract by considering all stated and implied substantive terms and features of the hybrid financial instrument, weighing each term and feature on the basis of relevant facts and circumstances. ASU 2014-16 is effective for Entergy for the first quarter 2016. Entergy does not expect ASU 2014-16 to affect materially its results of operations, financial position, or cash flows.



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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, 2014.

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, 2014.  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 Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc.
 
HUGH T. MCDONALD
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 Gulf States Louisiana, L.L.C. and 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, Inc.
 
SALLIE T. RAINER
Chair of the Board, President, and Chief Executive Officer of Entergy Texas, Inc.
 
THEODORE H. BUNTING, JR.
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










 
2014

2013

2012

2011

2010
 
(In Thousands, Except Percentages and Per Share Amounts)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$12,494,921



$11,390,947



$10,302,079



$11,229,073



$11,487,577

Income from continuing operations

$960,257



$730,572



$868,363



$1,367,372



$1,270,305

Earnings per share from continuing operations:
 

 

 


 


 

Basic

$5.24



$3.99



$4.77



$7.59



$6.72

Diluted

$5.22



$3.99



$4.76



$7.55



$6.66

Dividends declared per share

$3.32



$3.32



$3.32



$3.32



$3.24

Return on common equity
9.58
%

7.56
%

9.33
%

15.43
%

14.61
%
Book value per share, year-end

$55.83



$54.00



$51.72



$50.81



$47.53

Total assets

$46,527,854



$43,406,446



$43,202,502



$40,701,699



$38,685,276

Long-term obligations (a)

$12,740,579



$12,382,127



$12,141,370



$10,268,645



$11,575,973
















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










 
2014

2013

2012

2011

2010
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
Utility Electric Operating Revenues:
 


 


 


 


 

Residential

$3,555



$3,396



$3,022



$3,369



$3,375

Commercial
2,553


2,415


2,174


2,333


2,317

Industrial
2,623


2,405


2,034


2,307


2,207

Governmental
227


218


198


205


212

Total retail
8,958


8,434


7,428


8,214


8,111

Sales for resale
330


210


179


216


389

Other
304


298


264


244


241

Total

$9,592



$8,942



$7,871



$8,674



$8,741

 
 
 
 
 
 
 
 
 
 
Utility Billed Electric Energy Sales (GWh):





 


 


 

Residential
35,932


35,169


34,664


36,684


37,465

Commercial
28,827


28,547


28,724


28,720


28,831

Industrial
43,723


41,653


41,181


40,810


38,751

Governmental
2,428


2,412


2,435


2,474


2,463

Total retail
110,910


107,781


107,004


108,688


107,510

Sales for resale
9,462


3,020


3,200


4,111


4,372

Total
120,372


110,801


110,204


112,799


111,882

 
 
 
 
 
 
 
 
 
 
Entergy Wholesale Commodities:
 


 


 


 


 

Operating Revenues

$2,719

 

$2,313

 

$2,326

 

$2,414

 

$2,566

Billed Electric Energy Sales (GWh)
44,424

 
45,127

 
46,178

 
43,497

 
42,934



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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholders of
Entergy Corporation and Subsidiaries
New Orleans, Louisiana


We have audited the accompanying consolidated balance sheets of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2014 and 2013, and the related consolidated income statements, and consolidated statements of comprehensive income, cash flows, and changes in equity for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Corporation and Subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, 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), the Corporation’s internal control over financial reporting as of December 31, 2014, based on the 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, 2015 expressed an unqualified opinion on the Corporation’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana
February 26, 2015

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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS
 
 
 
 
 
For the Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
  (In Thousands, Except Share Data)
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$9,591,902

 

$8,942,360

 

$7,870,649

Natural gas
 
181,794

 
154,353

 
130,836

Competitive businesses
 
2,721,225

 
2,294,234

 
2,300,594

TOTAL
 
12,494,921

 
11,390,947

 
10,302,079

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
2,632,558

 
2,445,818

 
2,036,835

Purchased power
 
1,915,414

 
1,554,332

 
1,255,800

Nuclear refueling outage expenses
 
267,679

 
256,801

 
245,600

Other operation and maintenance
 
3,310,536

 
3,331,934

 
3,045,392

Asset write-offs, impairments, and related charges
 
179,752

 
341,537

 
355,524

Decommissioning
 
272,621

 
242,104

 
184,760

Taxes other than income taxes
 
604,606

 
600,350

 
557,298

Depreciation and amortization
 
1,318,638

 
1,261,044

 
1,144,585

Other regulatory charges (credits) - net
 
(13,772
)
 
45,597

 
175,104

TOTAL
 
10,488,032

 
10,079,517

 
9,000,898

 
 
 
 
 
 
 
Gain on sale of business
 
—

 
43,569

 
—

 
 
 
 
 
 
 
OPERATING INCOME
 
2,006,889

 
1,354,999

 
1,301,181

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
64,802

 
66,053

 
92,759

Interest and investment income
 
147,686

 
199,300

 
127,776

Miscellaneous - net
 
(42,016
)
 
(59,762
)
 
(53,214
)
TOTAL
 
170,472

 
205,591

 
167,321

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
661,083

 
629,537

 
606,596

Allowance for borrowed funds used during construction
 
(33,576
)
 
(25,500
)
 
(37,312
)
TOTAL
 
627,507

 
604,037

 
569,284

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
1,549,854

 
956,553

 
899,218

 
 
 
 
 
 
 
Income taxes
 
589,597

 
225,981

 
30,855

 
 
 
 
 
 
 
CONSOLIDATED NET INCOME
 
960,257

 
730,572

 
868,363

 
 
 
 
 
 
 
Preferred dividend requirements of subsidiaries
 
19,536

 
18,670

 
21,690

 
 
 
 
 
 
 
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION
 

$940,721

 

$711,902

 

$846,673

 
 
 
 
 
 
 
Earnings per average common share:
 
 

 
 

 
 

Basic
 

$5.24

 

$3.99

 

$4.77

Diluted
 

$5.22

 

$3.99

 

$4.76

 
 
 
 
 
 
 
Basic average number of common shares outstanding
 
179,506,151

 
178,211,192

 
177,324,813

Diluted average number of common shares outstanding
 
180,296,885

 
178,570,400

 
177,737,565

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
For the Years Ended December 31,
 
2014
 
2013
 
2012
 
(In Thousands)
 
 
 
 
 
 
Net Income

$960,257

 

$730,572

 

$868,363

 
 
 
 
 
 
Other comprehensive income (loss)
 

 
 

 
 

Cash flow hedges net unrealized gain (loss)
 

 
 

 
 

(net of tax expense (benefit) of $96,141, ($87,940), and ($55,750))
179,895

 
(161,682
)
 
(97,591
)
Pension and other postretirement liabilities
 

 
 

 
 

(net of tax expense (benefit) of ($152,763), $220,899, and ($61,223))
(281,566
)
 
302,489

 
(91,157
)
Net unrealized investment gains
 

 
 

 
 

(net of tax expense of $66,594, $118,878, and $61,104)
89,439

 
122,709

 
63,609

Foreign currency translation
 

 
 

 
 

(net of tax expense (benefit) of ($404), $131, and $275)
(751
)
 
243

 
508

Other comprehensive income (loss)
(12,983
)
 
263,759

 
(124,631
)
 
 
 
 
 
 
Comprehensive Income
947,274

 
994,331

 
743,732

Preferred dividend requirements of subsidiaries
19,536

 
18,670

 
21,690

Comprehensive Income Attributable to Entergy Corporation

$927,738

 

$975,661

 

$722,042

 
 
 
 
 
 
See Notes to Financial Statements.
 

 
 

 
 



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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
 
 
 
For the Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING ACTIVITIES
 
 
 
 
 
 
Consolidated net income
 

$960,257

 

$730,572

 

$868,363

Adjustments to reconcile consolidated net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 
2,127,892

 
2,012,076

 
1,771,649

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
596,935

 
311,789

 
(26,479
)
Asset write-offs, impairments and related charges
 
123,527

 
341,537

 
355,524

Gain on sale of business
 
—

 
(43,569
)
 
—

Changes in working capital:
 
 

 
 

 
 

Receivables
 
98,493

 
(180,648
)
 
(14,202
)
Fuel inventory
 
3,524

 
4,873

 
(11,604
)
Accounts payable
 
(12,996
)
 
94,436

 
(6,779
)
Prepaid taxes and taxes accrued
 
(62,985
)
 
(142,626
)
 
55,484

Interest accrued
 
25,013

 
(3,667
)
 
1,152

Deferred fuel costs
 
(70,691
)
 
(4,824
)
 
(99,987
)
Other working capital accounts
 
112,390

 
(66,330
)
 
(151,989
)
Changes in provisions for estimated losses
 
301,871

 
(248,205
)
 
(24,808
)
Changes in other regulatory assets
 
(1,061,537
)
 
1,105,622

 
(398,428
)
Changes in other regulatory liabilities
 
87,654

 
397,341

 
170,421

Changes in pensions and other postretirement liabilities
 
1,308,166

 
(1,433,663
)
 
644,099

Other
 
(647,952
)
 
314,505

 
(192,131
)
Net cash flow provided by operating activities
 
3,889,561

 
3,189,219

 
2,940,285

 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 

 
 

 
 

Construction/capital expenditures
 
(2,119,191
)
 
(2,287,593
)
 
(2,674,650
)
Allowance for equity funds used during construction
 
68,375

 
69,689

 
96,131

Nuclear fuel purchases
 
(537,548
)
 
(517,825
)
 
(557,960
)
Payment for purchase of plant
 
—

 
(17,300
)
 
(456,356
)
Proceeds from sale of assets and businesses
 
10,100

 
147,922

 
—

Insurance proceeds received for property damages
 
40,670

 
—

 
—

Changes in securitization account
 
1,511

 
155

 
4,265

NYPA value sharing payment
 
(72,000
)
 
(71,736
)
 
(72,000
)
Payments to storm reserve escrow account
 
(276,057
)
 
(7,716
)
 
(8,957
)
Receipts from storm reserve escrow account
 
—

 
260,279

 
27,884

Decrease (increase) in other investments
 
46,983

 
(82,955
)
 
15,175

Litigation proceeds for reimbursement of spent nuclear fuel storage costs
 
—

 
21,034

 
109,105

Proceeds from nuclear decommissioning trust fund sales
 
1,872,115

 
2,031,552

 
2,074,055

Investment in nuclear decommissioning trust funds
 
(1,989,446
)
 
(2,147,099
)
 
(2,196,489
)
Net cash flow used in investing activities
 
(2,954,488
)
 
(2,601,593
)
 
(3,639,797
)
 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 


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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
 
 
 
For the Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(In Thousands)
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
Proceeds from the issuance of:
 
 
 
 
 
 
Long-term debt
 
3,100,069

 
3,746,016

 
3,478,361

Preferred stock of subsidiary
 
—

 
24,249

 
—

Mandatorily redeemable preferred membership units of subsidiary
 
—

 
—

 
51,000

Treasury stock
 
194,866

 
24,527

 
62,886

Retirement of long-term debt
 
(2,323,313
)
 
(3,814,666
)
 
(3,130,233
)
Repurchase of common stock
 
(183,271
)
 
—

 
—

Changes in credit borrowings and commercial paper - net
 
(448,475
)
 
250,889

 
687,675

Other
 
23,579

 
—

 
—

Dividends paid:
 
 

 
 

 
 

Common stock
 
(596,117
)
 
(593,037
)
 
(589,209
)
Preferred stock
 
(19,511
)
 
(18,802
)
 
(22,329
)
Net cash flow provided by (used in) financing activities
 
(252,173
)
 
(380,824
)
 
538,151

 
 
 
 
 
 
 
Effect of exchange rates on cash and cash equivalents
 
—

 
(245
)
 
(508
)
 
 
 
 
 
 
 
Net increase (decrease) in cash and cash equivalents
 
682,900

 
206,557

 
(161,869
)
 
 
 
 
 
 
 
Cash and cash equivalents at beginning of period
 
739,126

 
532,569

 
694,438

 
 
 
 
 
 
 
Cash and cash equivalents at end of period
 

$1,422,026

 

$739,126

 

$532,569

 
 
 
 
 
 
 
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 

 
 

 
 

Cash paid during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$611,376

 

$570,212

 

$546,125

Income taxes
 

$77,799

 

$127,735

 

$49,214

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2014
 
2013
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$131,327

 

$129,979

Temporary cash investments
 
1,290,699

 
609,147

Total cash and cash equivalents
 
1,422,026

 
739,126

Accounts receivable:
 
 

 
 

Customer
 
596,917

 
670,641

Allowance for doubtful accounts
 
(35,663
)
 
(34,311
)
Other
 
220,342

 
195,028

Accrued unbilled revenues
 
321,659

 
340,828

Total accounts receivable
 
1,103,255

 
1,172,186

Deferred fuel costs
 
155,140

 
116,379

Accumulated deferred income taxes
 
27,783

 
175,073

Fuel inventory - at average cost
 
205,434

 
208,958

Materials and supplies - at average cost
 
918,584

 
915,006

Deferred nuclear refueling outage costs
 
214,188

 
192,474

Prepayments and other
 
343,223

 
410,489

TOTAL
 
4,389,633

 
3,929,691

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Investment in affiliates - at equity
 
36,234

 
40,350

Decommissioning trust funds
 
5,370,932

 
4,903,144

Non-utility property - at cost (less accumulated depreciation)
 
213,791

 
199,375

Other
 
405,169

 
210,616

TOTAL
 
6,026,126

 
5,353,485

 
 
 
 
 
PROPERTY, PLANT, AND EQUIPMENT
 
 

 
 

Electric
 
44,881,419

 
42,935,712

Property under capital lease
 
945,784

 
941,299

Natural gas
 
377,565

 
366,365

Construction work in progress
 
1,425,981

 
1,514,857

Nuclear fuel
 
1,542,055

 
1,566,904

TOTAL PROPERTY, PLANT AND EQUIPMENT
 
49,172,804

 
47,325,137

Less - accumulated depreciation and amortization
 
20,449,858

 
19,443,493

PROPERTY, PLANT AND EQUIPMENT - NET
 
28,722,946

 
27,881,644

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Regulatory asset for income taxes - net
 
836,064

 
849,718

Other regulatory assets (includes securitization property of $724,839 as of December 31, 2014 and $822,218 as of December 31, 2013)
 
4,968,553

 
3,893,363

Deferred fuel costs
 
238,102

 
172,202

Goodwill
 
377,172

 
377,172

Accumulated deferred income taxes
 
48,351

 
62,011

Other
 
920,907

 
887,160

TOTAL
 
7,389,149

 
6,241,626

 
 
 
 
 
TOTAL ASSETS
 

$46,527,854

 

$43,406,446

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2014
 
2013
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Currently maturing long-term debt
 

$899,375

 

$457,095

Notes payable and commercial paper
 
598,407

 
1,046,887

Accounts payable
 
1,166,431

 
1,173,313

Customer deposits
 
412,166

 
370,997

Taxes accrued
 
128,108

 
191,093

Accumulated deferred income taxes
 
38,039

 
28,307

Interest accrued
 
206,010

 
180,997

Deferred fuel costs
 
91,602

 
57,631

Obligations under capital leases
 
2,508

 
2,323

Pension and other postretirement liabilities
 
57,994

 
67,419

Other
 
248,251

 
484,510

TOTAL
 
3,848,891

 
4,060,572

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
9,133,161

 
8,724,635

Accumulated deferred investment tax credits
 
247,521

 
263,765

Obligations under capital leases
 
29,710

 
32,218

Other regulatory liabilities
 
1,383,609

 
1,295,955

Decommissioning and asset retirement cost liabilities
 
4,458,296

 
3,933,416

Accumulated provisions
 
418,128

 
115,139

Pension and other postretirement liabilities
 
3,638,295

 
2,320,704

Long-term debt (includes securitization bonds of $784,862 as of December 31, 2014 and $883,013 as of December 31, 2013)
 
12,500,109

 
12,139,149

Other
 
557,649

 
583,667

TOTAL
 
32,366,478

 
29,408,648

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
Subsidiaries’ preferred stock without sinking fund
 
210,760

 
210,760

 
 
 
 
 
EQUITY
 
 

 
 

Common Shareholders’ Equity:
 
 

 
 

Common stock, $.01 par value, authorized 500,000,000 shares; issued 254,752,788 shares in 2014 and in 2013
 
2,548

 
2,548

Paid-in capital
 
5,375,353

 
5,368,131

Retained earnings
 
10,169,657

 
9,825,053

Accumulated other comprehensive loss
 
(42,307
)
 
(29,324
)
Less - treasury stock, at cost (75,512,079 shares in 2014 and 76,381,936 shares in 2013)
 
5,497,526

 
5,533,942

Total common shareholders’ equity
 
10,007,725

 
9,632,466

Subsidiaries’ preferred stock without sinking fund
 
94,000

 
94,000

TOTAL
 
10,101,725

 
9,726,466

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$46,527,854

 

$43,406,446

 
 
 
 
 
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, 2014, 2013, and 2012
 
 
 
 
 
 
 
 

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, 2011

$94,000

 

$2,548

 

($5,680,468
)
 

$5,360,682

 

$9,446,960

 

($168,452
)
 

$9,055,270

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Consolidated net income (a)
21,690

 
—

 
—

 
—

 
846,673

 
—

 
868,363

Other comprehensive loss
—

 
—

 
—

 
—

 
—

 
(124,631
)
 
(124,631
)
Common stock issuances related to stock plans
—

 
—

 
105,649

 
(2,830
)
 
—

 
—

 
102,819

Common stock dividends declared
—

 
—

 
—

 
—

 
(589,042
)
 
—

 
(589,042
)
Preferred dividend requirements of subsidiaries (a)
(21,690
)
 
—

 
—

 
—

 
—

 
—

 
(21,690
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2012

$94,000

 

$2,548

 

($5,574,819
)
 

$5,357,852

 

$9,704,591

 

($293,083
)
 

$9,291,089

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Consolidated net income (a)
18,670

 
—

 
—

 
—

 
711,902

 
—

 
730,572

Other comprehensive income
—

 
—

 
—

 
—

 
—

 
263,759

 
263,759

Common stock issuances related to stock plans
—

 
—

 
40,877

 
10,279

 
—

 
—

 
51,156

Common stock dividends declared
—

 
—

 
—

 
—

 
(591,440
)
 
—

 
(591,440
)
Preferred dividend requirements of subsidiaries (a)
(18,670
)
 
—

 
—

 
—

 
—

 
—

 
(18,670
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2013

$94,000

 

$2,548

 

($5,533,942
)
 

$5,368,131

 

$9,825,053

 

($29,324
)
 

$9,726,466

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Consolidated net income (a)
19,536

 
—

 
—

 
—

 
940,721

 
—

 
960,257

Other comprehensive loss
—

 
—

 
—

 
—

 
—

 
(12,983
)
 
(12,983
)
Common stock repurchases
—

 
—

 
(183,271
)
 
—

 
—

 
—

 
(183,271
)
Common stock issuances related to stock plans
—

 
—

 
219,687

 
7,222

 
—

 
—

 
226,909

Common stock dividends declared
—

 
—

 
—

 
—

 
(596,117
)
 
—

 
(596,117
)
Preferred dividend requirements of subsidiaries (a)
(19,536
)
 
—

 
—

 
—

 
—

 
—

 
(19,536
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2014

$94,000

 

$2,548

 

($5,497,526
)
 

$5,375,353

 

$10,169,657

 

($42,307
)
 

$10,101,725

 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a) Consolidated net income and preferred dividend requirements of subsidiaries for 2014, 2013, and 2012 include $12.9 million, $12 million, and $15 million, respectively, 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 Gulf States Louisiana, 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 Gulf States Louisiana, 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 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 Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Louisiana, Mississippi, and Texas, respectively.  Entergy Gulf States 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, except for Algiers, where Entergy Louisiana is the electric power supplier.  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.

Entergy records revenue from sales under rates implemented subject to refund less estimated amounts accrued for probable refunds when Entergy believes it is probable that revenues will be refunded to customers based upon the status of the rate proceeding as of the date the financial statements are prepared.

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),

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Notes to Financial Statements


the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing. System Energy’s operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf.  The capital costs are 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

In December 2013, Entergy joined 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 and in operating expenses when in a net purchasing position.  

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost.  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 have been sold and leased back.  For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions.

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, 2014 and 2013, is shown below:
2014
 
 
Entergy
 
 
Utility
 
Entergy
Wholesale
Commodities
 
Parent &
Other
 
 
(In Millions)
Production
 
 

 
 

 
 

 
 

Nuclear
 

$9,639

 

$6,586

 

$3,053

 

$—

Other
 
3,425

 
3,067

 
358

 
—

Transmission
 
4,197

 
4,164

 
33

 
—

Distribution
 
6,973

 
6,973

 
—

 
—

Other
 
1,521

 
1,373

 
145

 
3

Construction work in progress
 
1,426

 
969

 
456

 
1

Nuclear fuel
 
1,542

 
840

 
702

 
—

Property, plant, and equipment - net
 

$28,723

 

$23,972

 

$4,747

 

$4



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Entergy Corporation and Subsidiaries
Notes to Financial Statements


2013
 
 
Entergy
 
 
Utility
 
Entergy
Wholesale
Commodities
 
Parent &
Other
 
 
(In Millions)
Production
 
 

 
 

 
 

 
 

Nuclear
 

$9,667

 

$6,601

 

$3,066

 

$—

Other
 
2,836

 
2,465

 
371

 
—

Transmission
 
3,929

 
3,894

 
35

 
—

Distribution
 
6,716

 
6,716

 
—

 
—

Other
 
1,652

 
1,475

 
174

 
3

Construction work in progress
 
1,515

 
1,217

 
298

 
—

Nuclear fuel
 
1,567

 
855

 
712

 
—

Property, plant, and equipment - net
 

$27,882

 

$23,223

 

$4,656

 

$3


Depreciation rates on average depreciable property for Entergy approximated 2.8% in 2014, 2.6% in 2013, and 2.5% in 2012.  Included in these rates are the depreciation rates on average depreciable Utility property of 2.5% in 2014, 2.5% in 2013, and 2.4% 2012, and the depreciation rates on average depreciable Entergy Wholesale Commodities property of 5.5% in 2014, 4.1% in 2013, and 3.5% in 2012. The increase in 2014 for Entergy Wholesale Commodities resulted from implementation of a new depreciation study.

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

“Non-utility property - at cost (less accumulated depreciation)” for Entergy is reported net of accumulated depreciation of $185.5 million and $203 million as of December 31, 2014 and 2013, respectively.

Construction expenditures included in accounts payable is $209 million and $166 million at December 31, 2014 and 2013, 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, 2014 and 2013, is shown below:
2014
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
Entergy
Texas
 
System
Energy
 
 
(In Millions)
Production
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nuclear
 

$1,097

 

$1,403

 

$2,151

 

$—

 

$—

 

$—

 

$1,935

Other
 
593

 
282

 
1,279

 
526

 
(11
)
 
399

 
—

Transmission
 
1,166

 
711

 
859

 
642

 
44

 
695

 
48

Distribution
 
1,928

 
1,004

 
1,443

 
1,125

 
357

 
1,116

 
—

Other
 
164

 
173

 
287

 
194

 
181

 
98

 
17

Construction work in progress
 
284

 
127

 
242

 
68

 
19

 
125

 
50

Nuclear fuel
 
294

 
132

 
163

 
—

 
—

 
—

 
251

Property, plant, and equipment - net
 

$5,526

 

$3,832

 

$6,424

 

$2,555

 

$590

 

$2,433

 

$2,301



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Entergy Corporation and Subsidiaries
Notes to Financial Statements


2013
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
Entergy
Texas
 
System
Energy
 
 
(In Millions)
Production
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nuclear
 

$1,047

 

$1,422

 

$2,202

 

$—

 

$—

 

$—

 

$1,930

Other
 
609

 
271

 
684

 
537

 
(7
)
 
371

 
—

Transmission
 
1,086

 
646

 
770

 
638

 
31

 
673

 
49

Distribution
 
1,831

 
950

 
1,420

 
1,096

 
340

 
1,079

 
—

Other
 
192

 
184

 
292

 
197

 
181

 
106

 
17

Construction work in progress
 
209

 
105

 
673

 
37

 
29

 
95

 
29

Nuclear fuel
 
322

 
197

 
147

 
—

 
—

 
—

 
189

Property, plant, and equipment - net
 

$5,296

 

$3,775

 

$6,188

 

$2,505

 

$574

 

$2,324

 

$2,214


Depreciation rates on average depreciable property for the Registrant Subsidiaries are shown below:
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
2014
2.4%
 
1.8%
 
2.5%
 
2.6%
 
3.1%
 
2.5%
 
3.0%
2013
2.5%
 
1.8%
 
2.5%
 
2.6%
 
3.0%
 
2.5%
 
2.8%
2012
2.5%
 
1.8%
 
2.4%
 
2.6%
 
3.0%
 
2.4%
 
2.8%

Non-utility property - at cost (less accumulated depreciation) for Entergy Gulf States Louisiana is reported net of accumulated depreciation of $151 million and $146 million as of December 31, 2014 and 2013, respectively.  Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $3.2 million and $3 million as of December 31, 2014 and 2013, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Mississippi is reported net of accumulated depreciation of $2.2 million and $2.1 million as of December 31, 2014 and 2013, respectively.  Non-utility property - at cost (less accumulated depreciation) for Entergy Texas is reported net of accumulated depreciation of $10.4 million and $10.4 million as of December 31, 2014 and 2013, respectively.

As of December 31, 2014, construction expenditures included in accounts payable are $37.3 million for Entergy Arkansas, $23.4 million for Entergy Gulf States Louisiana, $48 million for Entergy Louisiana, $7.8 million for Entergy Mississippi, $0.9 million for Entergy New Orleans, $24.1 million for Entergy Texas, and $7.7 million for System Energy.  As of December 31, 2013, construction expenditures included in accounts payable are $61.9 million for Entergy Arkansas, $13.1 million for Entergy Gulf States Louisiana, $31.1 million for Entergy Louisiana, $2.8 million for Entergy Mississippi, $1.7 million for Entergy New Orleans, $10.9 million for Entergy Texas, and $6.7 million for System Energy.

Jointly-Owned Generating Stations

Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties.  The investments and 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, 2014, the subsidiaries’ investment and accumulated depreciation in each of these generating stations were as follows:




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Notes to Financial Statements


Generating Stations
 
 
 
Fuel-Type
 
Total
Megawatt
Capability (a)
 
 
 
Ownership
 
 
 
 
Investment
 
 
Accumulated
Depreciation
 
 
 
 
 
 
 
 
 
 
 
(In Millions)
Utility business:
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Arkansas -
 
 
 
 
 
 
 
 
 
 
 
 
 
  Independence
 
Unit 1
 
Coal
 
839

 
31.50
%
 
 

$129

 

$98

 
 
Common Facilities
 
Coal
 
 
 
15.75
%
 
 

$34

 

$26

  White Bluff
 
Units 1 and 2
 
Coal
 
1,637

 
57.00
%
 
 

$503

 

$355

  Ouachita (b)
 
Common
Facilities
 
Gas
 
 
 
66.67
%
 
 

$169

 

$145

Entergy Gulf States
Louisiana -
 
 
 
 
 
 
 
 

 
 
 
 
 
  Roy S. Nelson
 
Unit 6
 
Coal
 
537

 
40.25
%
 
 

$261

 

$181

  Roy S. Nelson
 
Unit 6 Common
Facilities
 
Coal
 
 
 
17.70
%
 
 

$10

 

$4

  Big Cajun 2
 
Unit 3
 
Coal
 
594

 
24.15
%
 
 

$149

 

$105

  Ouachita (b)
 
Common
Facilities
 
Gas
 
 
 
33.33
%
 
 

$87

 

$74

Entergy Louisiana -
 
 
 
 
 
 
 
 
 
 
 
 
 
  Acadia
 
Common
Facilities
 
Gas
 
 
 
50.00
%
 
 

$19

 

$—

Entergy Mississippi -
 
 
 
 
 
 
 
 

 
 
 
 
 
  Independence
 
Units 1 and 2
and Common
Facilities
 
Coal
 
1,681

 
25.00
%
 
 

$251

 

$149

Entergy Texas -
 
 
 
 
 
 
 
 

 
 
 
 
 
  Roy S. Nelson
 
Unit 6
 
Coal
 
537

 
29.75
%
 
 

$188

 

$115

  Roy S. Nelson
 
Unit 6 Common
Facilities
 
Coal
 
 
 
13.07
%
 
 

$6

 

$2

  Big Cajun 2
 
Unit 3
 
Coal
 
594

 
17.85
%
 
 

$112

 

$72

System Energy -
 
 
 
 
 
 
 
 

 
 
 
 
 
  Grand Gulf
 
Unit 1
 
Nuclear
 
1,409

 
90.00
%
(c)
 

$4,819

 

$2,820

Entergy Wholesale
Commodities:
 
 
 
 
 
 
 
 

 
 
 
 
 
  Independence
 
Unit 2
 
Coal
 
842

 
14.37
%
 
 

$69

 

$46

  Independence
 
Common  
Facilities
 
Coal
 
 
 
7.18
%
 
 

$16

 

$11

  Roy S. Nelson
 
Unit 6
 
Coal
 
537

 
10.9
%
 
 

$107

 

$57

  Roy S. Nelson
 
Unit 6 Common Facilities
 
Coal
 
 
 
4.79
%
 
 

$2

 

$1


(a)
“Total Megawatt Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
(b)
Ouachita Units 1 and 2 are owned 100% by Entergy Arkansas and Ouachita Unit 3 is owned 100% by Entergy Gulf States Louisiana.  The investment and accumulated depreciation numbers above are only for the common facilities and not for the generating units.

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(c)
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.

Allowance for Funds Used During Construction (AFUDC)

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

Income Taxes

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

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

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

Earnings per Share

The following table presents Entergy’s basic and diluted earnings per share calculation included on the consolidated statements of income:
 
For the Years Ended December 31,
 
2014
 
2013
 
2012
 
(In Millions, Except Per Share Data)
 
 
 
$/share
 
 
 
$/share
 
 
 
$/share
Net income attributable to Entergy Corporation

$940.7

 
 

 

$711.9

 
 

 

$846.7

 
 

Basic earnings per average common share
179.5

 

$5.24

 
178.2

 

$3.99

 
177.3

 

$4.77

Average dilutive effect of:
 

 
 

 
 

 
 

 
 

 
 

Stock options
0.3

 
(0.01
)
 
0.1

 
—

 
0.3

 
(0.01
)
Other equity plans
0.5

 
(0.01
)
 
0.3

 
—

 
0.1

 
—

Diluted earnings per average common shares
180.3

 

$5.22

 
178.6

 

$3.99

 
177.7

 

$4.76


The calculation of diluted earnings per share excluded 5,743,013 options outstanding at December 31, 2014, 8,866,542 options outstanding at December 31, 2013, and 7,164,319 options outstanding at December 31, 2012 that

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could potentially dilute basic earnings per share in the future.  Those options were not included in the calculation of diluted earnings per share because the exercise price of those options exceeded the average market price for the year.

Stock-based Compensation Plans

Entergy grants stock options, restricted stock, performance units, and restricted liability 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 3 years.

Accounting for the Effects of Regulation

Entergy’s Utility operating companies and System Energy are rate-regulated enterprises whose rates meet three criteria specified in accounting standards.  The Utility operating companies and System Energy have rates that (i) are approved by a body (its regulator) empowered to set rates that bind customers; (ii) are cost-based; and (iii) can be charged to and collected from customers.  These criteria may also be applied to separable portions of a utility’s business, such as the generation or transmission functions, or to specific classes of customers.  Because the Utility operating companies and System Energy meet these criteria, each of them capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue.  Such capitalized costs are reflected as regulatory assets in the accompanying financial statements.  When an enterprise concludes that recovery of a regulatory asset is no longer probable, the regulatory asset must be removed from the entity’s balance sheet.

An enterprise that ceases to meet the three criteria for all or part of its operations should report that event in its financial statements.  In general, the enterprise no longer meeting the criteria should eliminate from its balance sheet all regulatory assets and liabilities related to the applicable operations.  Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs, it is possible that an impairment may exist that could require further write-offs of plant assets.

Entergy Gulf States 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 Gulf States 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 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 reimbursed to customers through future rates. The primary source of Entergy’s regulatory asset for income taxes is 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.

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.

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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 for decommissioning trust funds, the Registrant Subsidiaries record an offsetting amount in other regulatory liabilities/assets for the unrealized gains/(losses) on investment securities.  For the 30% interest in River Bend formerly owned by Cajun, Entergy Gulf States Louisiana has recorded an offsetting amount in other deferred credits for the unrealized gains/(losses).  Decommissioning trust funds for Pilgrim, Indian Point 2, 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 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 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.  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 17 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.  See Note 14 to the financial statements for additional information regarding Entergy’s equity method investments.

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 sales 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.


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

For other contracts for commodities in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income.  To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged.  Gains or losses accumulated in other comprehensive income are reclassified to earnings in the periods when the underlying transactions actually occur.  The ineffective portions of all hedges are recognized in current-period earnings. 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.

Fair Values

The estimated fair values of Entergy’s financial instruments and derivatives are determined using 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 accrue to the benefit or detriment of stockholders.  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 16 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 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 over the remaining life of the assets.

Two nuclear power plants in the Entergy Wholesale Commodities business segment (Indian Point 2 and Indian Point 3) have an application pending for renewed NRC licenses.  Various parties have 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.  On September 28, 2013, Indian Point 2 reached the expiration date of its original NRC operating license and entered into the period of extended operation under the timely renewal rule. In December 2015, Indian Point 3 will reach the expiration date of its original NRC operations license and, similarly, will enter the period of extended operation under the timely renewal rule if its license is not renewed before then. If the NRC does not renew the operating license for either of these plants, the plant’s operating life could be shortened, reducing its projected net cash flows and potentially impairing its value as an asset.


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In March 2011 the NRC renewed Vermont Yankee’s operating license for an additional 20 years.  The renewed operating license expires in March 2032. Vermont Yankee operated under a Certificate of Public Good from the State of Vermont that was scheduled to expire in March 2012, but had an amended petition pending before the Vermont Public Service Board (VPSB) for a renewed Certificate of Public Good to operate until March 2032.  

In June 2013 the VPSB completed hearings on Entergy’s amended petition for a Certificate of Public Good to continuing operating Vermont Yankee. In August 2013, Entergy announced that it planned to close Vermont Yankee at the end of 2014 and that same day filed a second amended petition seeking authorization to operate the plant only until that date. In December 2013, Entergy and Vermont entered into a settlement agreement, with an accompanying memorandum of understanding that was filed with the VPSB, under which Vermont agreed to support Entergy’s request to operate Vermont Yankee until the end of 2014. The settlement agreement provided for Entergy to make $10 million in economic transition payments, $5 million in clean energy development support, and a transitional $5 million payment to Vermont. The settlement agreement also provided for Entergy to set aside a new $25 million fund to ensure the Vermont Yankee site is restored after decommissioning. These terms were contingent upon the VPSB issuing by March 31, 2014 a Certificate of Public Good authorizing Vermont Yankee’s operation through 2014, and otherwise conforming to the terms of the settlement agreement. The settlement agreement also provided for the dismissal or discontinuation of other litigation between Entergy and Vermont. On March 28, 2014, the VPSB approved the memorandum of understanding and issued a Certificate of Public Good authorizing Vermont Yankee to operate until December 31, 2014.  In May 2014 the VPSB denied a motion that had been filed by one of the intervenors to amend its approval order. Pursuant to its commitment in the settlement agreement, Entergy Vermont Yankee provided to the Vermont parties in October 2014, a site assessment study of the costs and tasks of radiological decommissioning, spent nuclear fuel management, and site restoration of Vermont Yankee.  Entergy Vermont Yankee also filed its Post-Shutdown Decommissioning Activities Report (PSDAR) for Vermont Yankee with the NRC in December 2014.

Because of the uncertainty regarding the continued operation of Vermont Yankee, Entergy tested the recoverability of the plant and related assets in each quarter since the first quarter 2010 after a bill to approve the continued operation of Vermont Yankee was defeated in the Vermont legislature. Vermont law at that time required legislative approval of Vermont Yankee’s continued operation although that law was later invalidated by the U.S. federal courts as preempted by the Atomic Energy Act.  The determination of 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 pending legal and state regulatory matters, as well as projections of future revenues and expenses over the remaining life of the plant.  Prior to the first quarter 2012, the probability-weighted undiscounted net cash flows exceeded the carrying value of the Vermont Yankee plant and related assets.  The decline, however, in the overall energy market and the projected forward prices of power as of March 31, 2012, which are significant inputs in the determination of net cash flows, resulted in the probability-weighted undiscounted future cash flows being less than the asset group’s carrying value.  Entergy performed a fair value analysis based on the income approach, a discounted cash flow method, to determine the amount of impairment. The estimated fair value of the plant and related assets at March 31, 2012 was $162 million, while the carrying value was $517.5 million.  Therefore, the assets were written down to their fair value and an impairment charge of $355.5 million ($223.5 million after-tax) was recognized.  The impairment charge was recorded as a separate line item in Entergy’s consolidated statement of income for 2012, and is included within the results of the Entergy Wholesale Commodities segment.

The estimate of fair value was based on the price that Entergy would expect to receive in a hypothetical sale of the Vermont Yankee plant and related assets to a market participant on March 31, 2012. In order to determine this price, 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 plant and related assets. 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, is classified as Level 3 in the fair value hierarchy discussed in Note 16 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 Vermont Yankee plant and related assets as of March 31, 2012:
Significant Unobservable Inputs
 
Range
 
Weighted Average
 
 
 
 
 
Weighted average cost of capital
 
7.5%-8.0%
 
7.8%
Long-term pre-tax operating margin (cash basis)
 
6.1%-7.8%
 
7.2%

On August 27, 2013, Entergy announced its plan to close and decommission Vermont Yankee at the end of its fuel cycle at the end of 2014. This decision was approved by the Board in August 2013, although the exact date of shutdown was not determined. The decision to shut down the plant was primarily due to 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 region in which the plant operates.

As a result of the decision to shut down the plant, Entergy recognized non-cash impairment and other related charges of $291.5 million ($183.7 million after-tax) during the third quarter 2013 to write down the carrying value of Vermont Yankee and related assets to their fair values. Entergy performed a fair value analysis based on the income approach, a discounted cash flow method, to determine the amount of impairment. The estimated fair value of the plant and related assets was $62 million, while the carrying value was $349 million. The carrying value of $349 million reflected the effect of a $58 million increase in Vermont Yankee’s estimated decommissioning cost liability and 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. Impairment and other related charges were recorded as a separate line item in Entergy’s consolidated statements of income for 2013 and this impairment charge is included within the results of the Entergy Wholesale Commodities segment.

The estimate of fair value was based on the price that Entergy would expect to receive in a hypothetical sale of the Vermont Yankee plant and related assets to a market participant.  In order to determine this price, 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 plant and related assets.  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, is classified as Level 3 in the fair value hierarchy discussed in Note 16 to the financial statements.

The following table sets forth a description of significant unobservable inputs used in the valuation of the Vermont Yankee plant and related assets as of July 31, 2013:
Significant Unobservable Inputs
 
Amount
 
 
 
Weighted average cost of capital
 
7.5%
Long-term pre-tax operating margin (cash basis)
 
7.0%

Entergy’s Accounting Policy group, which reports to the Chief Accounting Officer, was primarily responsible for determining the valuation of the Vermont Yankee plant and related assets, in consultation with external advisors.  Accounting Policy obtained and reviewed information from other Entergy departments with expertise on the various inputs and assumptions that were necessary to calculate the fair value of the asset group.

As a result of the settlement agreement entered into by Entergy and Vermont regarding the remaining operation and decommissioning of Vermont Yankee discussed above, Entergy reassessed its assumptions regarding the timing of decommissioning cash flows for Vermont Yankee. The reassessment resulted in a $27.2 million increase in the

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decommissioning cost liability and a corresponding impairment charge, recorded in December 2013. As part of the development of the site assessment study and PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2014. The revised estimate, along with reassessment of the assumptions regarding the timing of decommissioning cash flows, resulted in a $101.6 million increase in the decommissioning cost liability and a corresponding impairment charge, recorded in September 2014. Impairment charges are recorded as a separate line item in Entergy’s consolidated statements of income for 2014 and 2013, and this impairment charge is included within the results of the Entergy Wholesale Commodities segment.

In addition to the $101.6 million impairment charge in September 2014 and depreciation recorded on the remaining plant balance in 2014, Entergy also recorded charges of $45.8 million related to severance and employee retention costs in 2014 relating to the shutdown of Vermont Yankee.

Vermont Yankee ceased operation in December 2014. In January 2015, Vermont Yankee completed the defueling of the reactor and submitted the certification of permanent cessation of operations and permanent removal of fuel from the reactor vessel to the NRC.

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 Gulf States 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 Gulf States Louisiana) are included in regulatory assets and are being amortized over the life of the related new issuances, or over the life of the original debt issuance if the debt is not refinanced, in accordance with ratemaking treatment.

Taxes Imposed on Revenue-Producing Transactions

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

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 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.  Entergy Gulf States Louisiana and Entergy Louisiana, both organized as limited liability companies, have outstanding preferred securities with similar protective rights with respect to unpaid dividends, but provide for

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the election of board members that would not constitute a majority of the board; and their preferred securities are therefore classified for all periods presented as a component of members’ equity.

The outstanding preferred securities of Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, 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 and the outstanding preferred securities of Entergy Gulf States Louisiana and Entergy Louisiana are presented within total equity in 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

The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects.  Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.

In April 2014 the FASB issued ASU No. 2014-08, “Presentation of Financial Statements (Topic 205) and Property Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity” which changes the requirements for reporting discontinued operations. The ASU states that a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results when the component of an entity or group of components of an entity meets the criteria to be classified as held for sale, is disposed of by sale, or is disposed of other than by sale. The amendments in this ASU also require additional disclosures about discontinued operations. ASU 2014-08 is effective for Entergy for the first quarter 2015. Entergy does not currently expect ASU 2014-08 to affect materially its results of operations, financial position, or cash flows.

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. ASU 2014-09 is effective for Entergy for the first quarter 2017. Entergy does not expect ASU 2014-09 to affect materially its results of operations, financial position, or cash flows.

In November 2014 the FASB issued ASU No. 2014-16, “Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity.” The ASU states that for hybrid financial instruments issued in the form of a share, an entity should determine the nature of the host contract by considering all stated and implied substantive terms and features of the hybrid financial instrument, weighing each term and feature on the basis of relevant facts and circumstances. ASU 2014-16 is effective for Entergy for the first quarter 2016. Entergy does not expect ASU 2014-16 to affect materially its results of operations, financial position, or cash flows.




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NOTE 2.  RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, 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, 2014 and 2013:

Other Regulatory Assets

Entergy
 
2014
 
2013
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)

$2,798.8

 

$1,723.1

Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 – Storm Cost Recovery Filings with Retail Regulators)
736.2

 
786.8

Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (b)
513.8

 
447.6

Removal costs - recovered through depreciation rates (Note 9) (b)
245.1

 
188.9

Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)
139.2

 
160.6

Under-recovered retail rate revenues - recovered through rate riders when rates are redetermined periodically
79.6

 
77.7

Unamortized loss on reacquired debt - recovered over term of debt
76.2

 
83.0

MISO implementation costs - recovery through retail rate riders (Note 2 - Retail Rate Proceedings)
69.6

 
74.7

Transition to competition costs - recovered over a 15-year period through February 2021
66.2

 
74.4

New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) (c)
58.4

 
115.2

Human capital management costs - recovery through retail rate mechanisms (Note 2 - Retail Rate Proceedings)
42.3

 
45.0

Other
143.2

 
116.4

Entergy Total

$4,968.6

 

$3,893.4


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Entergy Arkansas
 
2014
 
2013
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)

$838.2

 

$517.1

Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (b)
254.8

 
225.9

Storm damage costs - recovered either through securitization or retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)
125.6

 
115.2

Removal costs - recovered through depreciation rates (Note 9) (b)
59.0

 
18.6

Unamortized loss on reacquired debt - recovered over term of debt
26.2

 
28.8

MISO implementation costs - recovery through retail rates through 2018 (Note 2 - Retail Rate Proceedings) (c)
25.1

 
30.9

Under-recovered retail rate revenues - recovered through rate riders when rates are redetermined periodically
23.3

 
36.1

Human capital management costs - recovery through retail rates through June 2017 (Note 2 - Retail Rate Proceedings) (c)
17.3

 
22.0

Incremental ice storm costs - recovered through 2032
9.0

 
9.5

Other
12.8

 
10.3

Entergy Arkansas Total

$1,391.3

 

$1,014.4


Entergy Gulf States Louisiana
 
2014
 
2013
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b)

$286.8

 

$194.2

New nuclear generation development costs - recovery through formula rate plan beginning December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (c)
29.2

 
29.5

Spindletop gas storage facility - recovery period through December 2032 (a)
26.2

 
27.8

River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC)
18.6

 
20.5

MISO implementation costs - recovery through the MISO cost recovery mechanism beginning December 2014 through November 2017 (Note 2 - Retail Rate Proceedings)
15.7

 
15.3

Human capital management costs - recovery through formula rate plan beginning December 2014 through November 2017 (Note 2 - Retail Rate Proceedings)
11.2

 
10.0

Under-recovered retail rate revenues - recovered through rate riders when rates are redetermined periodically
11.1

 
3.0

Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (b)
10.8

 
11.0

Gas hedging costs - recovered through fuel rates upon settlement (Note 16 - Derivatives)
8.2

 
—

Unamortized loss on reacquired debt - recovered over term of debt
6.8

 
8.3

Other
1.8

 
1.9

Entergy Gulf States Louisiana Total

$426.4

 

$321.5



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Entergy Louisiana
 
2014
 
2013
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b)

$487.2

 

$318.4

Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (b)
156.7

 
139.2

Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)
139.2

 
160.6

New nuclear generation development costs - recovery through formula rate plan beginning December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (c)
29.2

 
29.5

MISO implementation costs - recovery through the MISO cost recovery mechanism beginning December 2014 through November 2017 (Note 2 - Retail Rate Proceedings)
21.4

 
20.8

Unamortized loss on reacquired debt - recovered over term of debt
14.3

 
15.2

Human capital management costs - recovery through formula rate plan beginning December 2014 through November 2017 (Note 2 - Retail Rate Proceedings)
13.8

 
13.0

Storm damage costs, including hurricane costs - recovered through retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)
13.7

 
3.4

Other
38.7

 
15.4

Entergy Louisiana Total

$914.2

 

$715.5


Entergy Mississippi
 
2014
 
2013
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)

$224.3

 

$135.3

Removal costs - recovered through depreciation rates (Note 9) (b)
76.3

 
64.3

Under-recovered retail rate revenues - recovered through rate riders when rates are redetermined periodically
28.7

 
39.2

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

 
8.9

Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (b)
6.3

 
5.9

Baxter Wilson outage costs - recovered through retail rates over two years beginning February 2015 (Note 8 - Baxter Wilson Plant Event)
6.0

 
—

MISO implementation costs - recovery through retail rate riders (Note 2 – Retail Rate Proceedings)
4.0

 
4.2

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

 
56.2

Other
10.9

 
4.5

Entergy Mississippi Total

$364.7

 

$318.5



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Entergy New Orleans
 
2014
 
2013
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)

$115.8

 

$76.8

Removal costs - recovered through depreciation rates (Note 9) (b)
35.2

 
34.9

Michoud plant maintenance – recovered over a 7-year period through September 2018
7.2

 
9.1

Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators)
5.0

 
4.6

Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (b)
3.8

 
3.7

Unamortized loss on reacquired debt - recovered over term of debt
1.8

 
2.0

Other
6.8

 
6.1

Entergy New Orleans Total

$175.6

 

$137.2


Entergy Texas
 
2014
 
2013
 
(In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)

$591.7

 

$663.6

Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)
217.0

 
143.0

Transition to competition costs - recovered over a 15-year period through February 2021
66.2

 
74.4

Removal costs - recovered through depreciation rates (Note 9) (b)
18.9

 
15.1

Unamortized loss on reacquired debt - recovered over term of debt
10.5

 
7.7

Rate case costs - recovered through retail rates (c)
8.4

 
10.8

Other
9.4

 
4.6

Entergy Texas Total

$922.1

 

$919.2


System Energy
 
2014
 
2013
 
(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (b)

$191.0

 

$132.9

Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (b)
80.4

 
60.8

Removal costs - recovered through depreciation rates (Note 9) (b)
55.7

 
56.0

Unamortized loss on reacquired debt - recovered over term of debt
8.5

 
12.0

System Energy Total

$335.6

 

$261.7


(a)
The jurisdictional split order assigned the regulatory asset to Entergy Texas.  The regulatory asset, however, is being recovered and amortized at Entergy Gulf States Louisiana.  As a result, a billing occurs monthly over the same term as the recovery and receipts will be submitted to Entergy Texas.  Entergy Texas has recorded a receivable from Entergy Gulf States Louisiana and Entergy Gulf States Louisiana has recorded a corresponding payable.

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

Other Regulatory Liabilities

Entergy
 
2014
 
2013
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)

$656.7

 

$529.6

Vidalia purchased power agreement (Note 8)
242.8

 
263.1

Louisiana Act 55 financing savings obligation (Note 2)
156.0

 
156.0

Removal costs - returned to customers through depreciation rates (Note 9) (a)
82.7

 
72.3

Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)
79.5

 
92.3

Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the UPSA
53.6

 
60.7

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

 
44.4

Asset retirement obligation - will be returned to customers dependent upon timing of decommissioning (Note 9) (a)
27.7

 
31.5

Other
40.2

 
46.1

Entergy Total

$1,383.6

 

$1,296.0


Entergy Arkansas
 
2014
 
2013
 
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)

$254.0

 

$214.1

Deferred capacity acquisition cost recovery - returned to customers through rate riders when rates are redetermined periodically
—

 
4.7

Other
—

 
0.6

Entergy Arkansas Total

$254.0

 

$219.4


Entergy Gulf States Louisiana
 
2014
 
2013
 
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)

$85.9

 

$64.1

Removal costs - returned to customers through depreciation rates (Note 9) (a)
36.9

 
35.3

Asset retirement obligation - will be returned to customers dependent upon timing of decommissioning (Note 9) (a)
27.7

 
31.5

Louisiana Act 55 financing savings obligation (Note 2)
25.5

 
25.5

Gas hedging costs - returned to customers through fuel rates (Note 16 - Derivatives)
—

 
2.2

Other
0.3

 
0.8

Entergy Gulf States Louisiana Total

$176.3

 

$159.4



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Entergy Louisiana
 
2014
 
2013
 
(In Millions)
Vidalia purchased power agreement (Note 8)

$242.8

 

$263.1

Louisiana Act 55 financing savings obligation (Note 2)
130.5

 
130.5

Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)
123.2

 
98.9

Removal costs - returned to customers through depreciation rates (Note 9) (a)
45.7

 
37.0

Other
3.9

 
3.7

Entergy Louisiana Total

$546.1

 

$533.2


Entergy Texas
 
2014
 
2013
 
(In Millions)
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically

$5.1

 

$4.2

Line loss adjustment - returned to customers through fuel rates
—

 
1.0

Entergy Texas Total

$5.1

 

$5.2


System Energy
 
2014
 
2013
 
(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)

$193.6

 

$152.4

Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)
79.5

 
92.3

Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the UPSA
53.6

 
60.7

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

 
44.4

System Energy Total

$371.1

 

$349.8


(a)
Offset by related asset.


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Fuel and purchased power cost recovery

Entergy Arkansas, Entergy Gulf States Louisiana, 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, 2014 and 2013 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.
 
2014
 
2013
 
(In Millions)
Entergy Arkansas (a)

$209.2

 

$68.7

Entergy Gulf States Louisiana (b)

$89.5

 

$109.7

Entergy Louisiana (b)

$17.6

 

$37.6

Entergy Mississippi

($2.2
)
 

$38.1

Entergy New Orleans (b)

($24.3
)
 

($19.1
)
Entergy Texas

$11.9

 

($4.1
)

(a)
2014 includes $65.9 million for Entergy Arkansas 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.
(b)
2014 and 2013 include $100.1 million for Entergy Gulf States Louisiana, $68 million for Entergy Louisiana, and $4.1 million 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 Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects them 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 June 2014 the APSC suspended the annual redetermination of the production cost allocation rider and scheduled a hearing in September 2014. Upon a joint motion of the parties, the APSC canceled the September 2014 hearing and 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 the first billing cycle of February 2015.


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Energy Cost Recovery Rider

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

In October 2005 the APSC initiated an investigation into Entergy Arkansas’s interim energy cost recovery rate.  The investigation focused on Entergy Arkansas’s 1) gas contracting, portfolio, and hedging practices; 2) wholesale purchases during the period; 3) management of the coal inventory at its coal generation plants; and 4) response to the contractual failure of the railroads to provide coal deliveries.  In March 2006 the APSC extended its investigation to cover the costs included in Entergy Arkansas’s March 2006 annual energy cost rate filing, and a hearing was held in the APSC investigation in October 2006.

In January 2007 the APSC issued an order in its review of the energy cost rate.  The APSC found that Entergy Arkansas failed to maintain an adequate coal inventory level going into the summer of 2005 and that Entergy Arkansas should be responsible for any incremental energy costs that resulted from two outages caused by employee and contractor error.  The coal plant generation curtailments were caused by railroad delivery problems and Entergy Arkansas has since resolved litigation with the railroad regarding the delivery problems.  The APSC staff was directed to perform an analysis with Entergy Arkansas’s assistance to determine the additional fuel and purchased energy costs associated with these findings and file the analysis within sixty days of the order.  After a final determination of the costs is made by the APSC, Entergy Arkansas will be directed to refund that amount with interest to its customers as a credit on the energy cost recovery rider.  Entergy Arkansas requested rehearing of the order.

In February 2010 the APSC denied Entergy Arkansas’s request for rehearing, and held a hearing in September 2010 to determine the amount of damages, if any, that should be assessed against Entergy Arkansas.  A decision is pending.  Entergy Arkansas expects the amount of damages, if any, to have an immaterial effect on its results of operations, financial position, or cash flows.

The APSC also established a separate docket to consider the resolved railroad litigation, and in February 2010 it established a procedural schedule that concluded with testimony through September 2010.  The testimony has been filed, and the APSC will decide the case based on the record in the proceeding.

In January 2014, Entergy Arkansas filed a motion with the APSC relating to its redetermination of its energy cost rate to be 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. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.

Entergy Gulf States Louisiana and Entergy Louisiana

Entergy Gulf States Louisiana and Entergy Louisiana recover 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 Gulf States 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.

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In April 2010 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 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. Two parties intervened in the proceeding. A procedural schedule was established for the identification of issues by the intervenors and for Entergy Louisiana to submit comments regarding the LPSC Staff report and any issues raised by intervenors. One intervenor is seeking further proceedings regarding certain issues it raised in its comments on the LPSC Staff report. Entergy Louisiana has filed responses to both the LPSC Staff report and the issues raised by the intervenor. As required by the procedural schedule, a joint status report was submitted in October 2013 by the parties. A status conference was held in December 2013. Discovery is in progress, but a procedural schedule has not been established.

In December 2011 the LPSC authorized its staff to initiate another proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates.  The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009.  Discovery is in progress, but a procedural schedule has not been established.

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 has yet to commence.

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 has yet to commence.

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 balance of $60.4 million as of March 31, 2014. In May 2014, Entergy Mississippi filed for an interim adjustment under its energy cost recovery rider. The interim adjustment proposed a net energy cost factor designed to collect over a six-month period the under-recovered deferred fuel balance as of March 31, 2014 and also reflected a natural gas price of $4.50 per MMBtu. In May 2014, Entergy Mississippi and the Public Utilities Staff entered into a joint stipulation in which Entergy Mississippi agreed to a revised net energy cost factor that reflected the proposed interim adjustment with a reduction in costs recovered through the energy cost recovery rider associated with the suspension of the DOE nuclear waste storage fee. In June 2014 the MPSC approved the joint stipulation and allowed Entergy Mississippi’s interim adjustment. In November 2014, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider.  Due to lower gas prices and a lower deferred fuel balance, the redetermined annual factor was a decrease from the revised interim net energy cost factor.  In January 2015 the MPSC approved the redetermined annual factor effective January 30, 2015.

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

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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.  The District Court’s ruling on the motion for judgment on the pleadings is pending.

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 subject to the federal law that allowed federal courts to hear those cases as “mass action” lawsuits. One day later the Attorney General renewed its motion to remand the Entergy case back to state court, citing the U.S. Supreme Court’s decision. The defendant Entergy companies have responded to that motion and the District Court held oral argument on the motion to remand in February 2014. Entergy also has asserted federal question jurisdiction as a basis for the district court having jurisdiction and also has pending the motion for judgment on the pleadings.

Entergy New Orleans

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

Entergy Texas

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates.  Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix.  The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT.

In December 2011, Entergy Texas filed with the PUCT a request to refund approximately $43 million, including interest, of fuel cost recovery over-collections through October 2011.  Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $67 million, including interest and additional over-recoveries through December 2011, over a three-month period.  Entergy Texas and the parties requested that interim rates consistent with the settlement be approved effective with the March 2012 billing month, and the PUCT approved the application in March 2012.  Entergy Texas completed this refund to customers in May 2012.

In October 2012, Entergy Texas filed with the PUCT a request to refund approximately $78 million, including interest, of fuel cost recovery over-collections through September 2012.  Entergy Texas requested that the refund be implemented over a six-month period effective with the January 2013 billing month.  Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $84 million, including interest and additional over-recoveries through October 2012, to most customers over a three-month period beginning January 2013.  The PUCT approved the stipulation in January 2013. Entergy Texas completed this refund to customers in March 2013.


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In July 2012, Entergy Texas filed with the PUCT an application to credit its customers approximately $37.5 million, including interest, resulting from the FERC’s October 2011 order in the System Agreement rough production cost equalization proceeding which is discussed below in “System Agreement Cost Equalization Proceedings.”  In September 2012 the parties submitted a stipulation resolving the proceeding.  The stipulation provided that most Entergy Texas customers would be credited over a four-month period beginning October 2012.  The credits were initiated with the October 2012 billing month on an interim basis, and the PUCT subsequently approved the stipulation, also in October 2012.

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. All parties agreed that this case should be bifurcated such that the interim refunds would become final in a separate docket. The current docket would remain in place to potentially address additional rough production cost equalization-related matters that are not part of the interim refunds discussed above. In January 2015, Entergy Texas filed a request for this severance and final approval of the interim refund. Both applications are pending.
 
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.

Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

In March 2013, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing assumed Entergy Arkansas’s transition to MISO in December 2013, and requested a rate increase of $174 million, including $49 million of revenue being transferred from collection in riders to base rates. The filing also proposed a new transmission rider and a capacity cost recovery rider. The filing requested a 10.4% return on common equity. In September 2013, Entergy Arkansas filed testimony reflecting an updated rate increase request of $145 million, with no change to its requested return on common equity of 10.4%. Hearings in the proceeding began in October 2013, and in December 2013 the APSC issued an order. The order authorized a base rate increase of $81 million and included an authorized return on common equity of 9.3%. The order allows Entergy Arkansas to amortize its human capital management costs over a three-and-a-half year period, but also orders Entergy Arkansas to file a detailed report of the Arkansas-specific costs, savings and final payroll changes upon conclusion of the human capital management strategic imperative. The detailed report was subsequently filed in February 2015. The substance of the report will be addressed in Entergy Arkansas’s next base rate filing. New rates under the January 2014 order were implemented in the first billing cycle of March 2014 and were effective as of January 2014. Additionally, in January 2014, Entergy Arkansas filed a petition for rehearing or clarification of several aspects of the APSC’s order, including the 9.3% authorized return on common equity. In February 2014 the APSC granted Entergy Arkansas’s petition for the purpose of considering the additional evidence identified by Entergy Arkansas. In August 2014 the APSC issued an order amending certain aspects of the original order, including providing for a 9.5% authorized return on common equity. Pursuant to the

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August 2014 order, revised rates are effective for all bills rendered after December 31, 2013 and were implemented in the first billing cycle of October 2014.

On January 30, 2015, Entergy Arkansas filed with the APSC a notice of intent to file a rate case within 60 to 90 days.

Filings with the LPSC

Retail Rates - Electric

(Entergy Gulf States Louisiana)

In November 2011 the LPSC approved a one-year extension of Entergy Gulf States Louisiana’s formula rate plan.  In May 2012, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2011 test year.  The filing reflected an 11.94% earned return on common equity, which was above the earnings bandwidth and indicated a $6.5 million cost of service rate decrease was necessary under the formula rate plan.  The filing also reflected a $22.9 million rate decrease for the incremental capacity rider.  Subsequently, in August 2012, Entergy Gulf States Louisiana submitted a revised filing that reflected an earned return on common equity of 11.86%, which indicated a $5.7 million cost of service rate decrease was necessary under the formula rate plan.  The revised filing also indicated that a reduction of $20.3 million should be reflected in the incremental capacity rider.  The rate reductions were implemented, subject to refund, effective for bills rendered in the first billing cycle of September 2012.  Subsequently, in December 2012, Entergy Gulf States Louisiana submitted a revised evaluation report that reflected expected retail jurisdictional cost of $17 million for the first-year capacity charges for the purchase from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy.  This rate change was implemented effective with the first billing cycle of January 2013.  The 2011 test year filings, as revised, were approved by the LPSC in February 2013. In April 2013, Entergy Gulf States Louisiana submitted a revised evaluation report increasing the incremental capacity rider by approximately $7.3 million to reflect the cost of an additional capacity contract.

In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Gulf States Louisiana, and the required filing was made in February 2013. The filing anticipated Entergy Gulf States Louisiana’s integration into MISO. In the filing Entergy Gulf States Louisiana requested, among other relief:

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authorization to increase the revenue it collects from customers by approximately $24 million;
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an authorized return on common equity of 10.4%;
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authorization to increase depreciation rates embedded in the proposed revenue requirement; and,
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authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.
 
Following a hearing before an ALJ and the ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. Major terms of the settlement include approval of a three-year formula rate plan (effective for test years 2014-2016) modeled after the formula rate plan in effect for Entergy Gulf States Louisiana for 2011, including the following: (1) a midpoint return on equity of 9.95% plus or minus 80 basis points, with 60/40 sharing of earnings outside of the bandwidth; (2) recovery outside of the sharing mechanism for the non-fuel MISO-related costs, additional capacity revenue requirement, extraordinary items, such as the Ninemile 6 project, and certain special recovery items; (3) three-year amortization of costs to achieve savings associated with

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the human capital management strategic imperative, with savings to be reflected as they are realized in subsequent years; (4) eight-year amortization of costs incurred in connection with potential development of a new nuclear unit at River Bend, without carrying costs, beginning December 2014, provided, however, that amortization of these costs shall not result in a future rate increase; (5) no change in rates related to test year 2013, except with respect to recovery of the non-fuel MISO-related costs and any changes to the additional capacity revenue requirement; and (6) no increase in rates related to test year 2014, except for those items eligible for recovery outside of the earnings sharing mechanism. Existing depreciation rates will not change. Implementation of rate changes for items recoverable outside of the earnings sharing mechanism occurred in December 2014.

Pursuant to the rate case settlement approved by the LPSC in December 2013, Entergy Gulf States Louisiana submitted a compliance filing in May 2014 reflecting the effects of the estimated MISO cost recovery mechanism revenue requirement and adjustment of the additional capacity mechanism. In November 2014, Entergy Gulf States Louisiana submitted an additional compliance filing updating the estimated MISO cost recovery mechanism for the most recent actual data. Based on this updated filing, a net increase of $5.8 million in formula rate plan revenue to be collected over nine months was implemented in December 2014. The compliance filings are subject to LPSC review in accordance with the review process set forth in Entergy Gulf States Louisiana’s formula rate plan.

In July 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed an unopposed stipulation with the LPSC 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, which was subsequently approved by the LPSC. 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 was filed. The December 2014 estimate forms the basis of rates implemented effective with the first billing cycle of January 2015.

(Entergy Louisiana)

In November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s formula rate plan.  In May 2012, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2011 test year.  The filing reflected a 9.63% earned return on common equity, which is within the earnings bandwidth and resulted in no cost of service rate change under the formula rate plan.  The filing also reflected an $18.1 million rate increase for the incremental capacity rider.  In August 2012, Entergy Louisiana submitted a revised filing that reflected an earned return on common equity of 10.38%, which is still within the earnings bandwidth, resulting in no cost of service rate change.  The revised filing also indicated that an increase of $15.9 million should be reflected in the incremental capacity rider.  The rate change was implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012.  Subsequently, in December 2012, Entergy Louisiana submitted a revised evaluation report that reflected two items: 1) a $17 million reduction for the first-year capacity charges for the purchase by Entergy Gulf States Louisiana from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy, and 2) an $88 million increase for the first-year retail revenue requirement associated with the Waterford 3 replacement steam generator project, which was in-service in December 2012.  These rate changes were implemented, subject to refund, effective with the first billing cycle of January 2013.  In April 2013, Entergy Louisiana and the LPSC staff filed a joint report resolving the 2011 test year formula rate plan and recovery related to the Grand Gulf uprate. This report was approved by the LPSC in April 2013.

With completion of the Waterford 3 replacement steam generator project, the LPSC is conducting 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. A post-hearing briefing schedule has not been established. Entergy Louisiana believes that the replacement steam

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generator costs were prudently incurred and applicable legal principles support 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 associated with the resolution of the prudence review.
 
In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Louisiana, and the required filing was made on February 15, 2013. The filing anticipated Entergy Louisiana’s integration into MISO. In the filing Entergy Louisiana requested, among other relief:

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authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service);
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an authorized return on common equity of 10.4%;
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authorization to increase depreciation rates embedded in the proposed revenue requirement; and,
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authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

Following a hearing before an ALJ and the ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. The settlement provides for a $10 million rate increase effective with the first billing cycle of December 2014. Major terms of the settlement include approval of a three-year formula rate plan (effective for test years 2014-2016) modeled after the formula rate plan in effect for Entergy Louisiana for 2011, including the following: (1) a midpoint return on equity of 9.95% plus or minus 80 basis points, with 60/40 sharing of earnings outside of the bandwidth; (2) recovery outside of the sharing mechanism for the non-fuel MISO-related costs, additional capacity revenue requirement, extraordinary items, such as the Ninemile 6 project, and certain special recovery items; (3) three-year amortization of costs to achieve savings associated with the human capital management strategic imperative, with savings reflected as they are realized in subsequent years; (4) eight-year amortization of costs incurred in connection with potential development of a new nuclear unit at River Bend, without carrying costs, beginning December 2014, provided, however, that amortization of these costs shall not result in a future rate increase; (5) recovery of non-fuel MISO-related costs and any changes to the additional capacity revenue requirement related to test year 2013 effective with the first billing cycle of December 2014; and (6) a cumulative $30 million cap on cost of service increases over the three-year formula rate plan cycle, except for those items outside of the sharing mechanism. Existing depreciation rates will not change.
    
Pursuant to the rate case settlement approved by the LPSC in December 2013, Entergy Louisiana submitted a compliance filing in May 2014 reflecting the effects of the $10 million agreed-upon increase in formula rate plan revenue, the estimated MISO cost recovery mechanism revenue requirement, and the adjustment of the additional capacity mechanism. In November 2014, Entergy Louisiana submitted an additional compliance filing updating the estimated MISO cost recovery mechanism for the most recent actual data, as well as providing for a refund and prospective reduction in rates for the true-up of the estimated revenue requirement for the Waterford 3 replacement steam generator project. Based on this updated filing, a net increase of $41.6 million in formula rate plan revenue to be collected over nine months was implemented in December 2014. The compliance filings are subject to LPSC review in accordance with the review process set forth in Entergy Louisiana’s formula rate plan. Additionally, the adjustments of rates made related to the Waterford 3 replacement steam generator project included in the December 2014 compliance filing are subject to final true-up following completion of the LPSC’s determination regarding the prudence of the project.


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In July 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed an unopposed stipulation with the LPSC 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, which was subsequently approved by the LPSC. In late December 2014, roughly contemporaneous with the unit's placement in service, a final updated estimated revenue requirement of $51.1 million for Entergy Louisiana was filed. The December 2014 estimate forms the basis of rates implemented effective with the first billing cycle of January 2015. Entergy Louisiana will submit project and cost information to the LPSC in mid-2015 to enable the LPSC to review the prudence of Entergy Louisiana’s management of the project.

Retail Rates - Gas (Entergy Gulf States Louisiana)

In January 2012, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2011.  The filing showed an earned return on common equity of 10.48%, which is within the earnings bandwidth of 10.5%, plus or minus fifty basis points.  In April 2012 the LPSC Staff filed its findings, suggesting adjustments that produced an 11.54% earned return on common equity for the test year and a $0.1 million rate reduction.  Entergy Gulf States Louisiana accepted the LPSC Staff’s recommendations, and the rate reduction was effective with the first billing cycle of May 2012.

In January 2013, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2012.  The filing showed an earned return on common equity of 11.18%, which results in a $43 thousand rate reduction.  In March 2013 the LPSC Staff issued its proposed findings and recommended two adjustments. Entergy Gulf States Louisiana and the LPSC Staff reached agreement regarding the LPSC Staff’s proposed adjustments. As reflected in an unopposed joint report of proceedings filed by Entergy Gulf States Louisiana and the LPSC Staff in May 2013, Entergy Gulf States Louisiana accepted, with modification, the LPSC Staff’s proposed adjustment to property insurance expense and agreed to: (1) a three-year extension of the gas rate stabilization plan with a midpoint return on equity of 9.95%, with a first year midpoint reset; (2) dismissal of a docket initiated by the LPSC to evaluate the allowed return on equity for Entergy Gulf States Louisiana’s gas rate stabilization plan; and (3) presentation to the LPSC by November 2014 by Entergy Gulf States Louisiana and the LPSC Staff of their recommendation for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment. The LPSC approved the agreement in May 2013.

In January 2014, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2013.  The filing showed an earned return on common equity of 5.47%, which results in a $1.5 million rate increase. In April 2014 the LPSC Staff issued a report indicating “that Entergy Gulf States Louisiana has properly determined its earnings for the test year ended September 30, 2013.” The $1.5 million rate increase was implemented effective with the first billing cycle of April 2014.

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 percent annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding ten percent; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider will commence with bills rendered on and after the first billing cycle of April 2015.

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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 results in a $706 thousand rate increase.  The rate increase, if approved, will be implemented effective with the first billing cycle of April 2015.

Filings with the MPSC (Entergy Mississippi)

Formula Rate Plan Filings

In September 2009, Entergy Mississippi filed with the MPSC proposed modifications to its formula rate plan rider.  In March 2010 the MPSC issued an order: (1) providing the opportunity for a reset of Entergy Mississippi’s return on common equity to a point within the formula rate plan bandwidth and eliminating the 50/50 sharing that had been in the plan, (2) modifying the performance measurement process, and (3) replacing the revenue change limit of two percent of revenues, which was subject to a $14.5 million revenue adjustment cap, with a limit of four percent of revenues, although any adjustment above two percent requires a hearing before the MPSC.  The MPSC did not approve Entergy Mississippi’s request to use a projected test year for its annual scheduled formula rate plan filing and, therefore, Entergy Mississippi continued to use a historical test year for its annual evaluation reports under the plan.
 
In March 2012, Entergy Mississippi submitted its formula rate plan filing for the 2011 test year.  The filing shows an earned return on common equity of 10.92% for the test year, which is within the earnings bandwidth and results in no change in rates.  In February 2013 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provided for no change in rates.

In March 2013, Entergy Mississippi submitted its formula rate plan filing for the 2012 test year. The filing requested a $36.3 million revenue increase to reset Entergy Mississippi’s return on common equity to 10.55%, which is a point within the formula rate plan bandwidth. In June 2013, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation, in which both parties agreed that the MPSC should approve a $22.3 million rate increase for Entergy Mississippi which, with other adjustments reflected in the stipulation, would have the effect of resetting Entergy Mississippi’s return on common equity to 10.59% when adjusted for performance under the formula rate plan. In August 2013 the MPSC approved the joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff authorizing the rate increase effective with September 2013 bills.  Additionally, the MPSC authorized Entergy Mississippi to defer approximately $1.2 million in MISO-related implementation costs incurred in 2012 along with other MISO-related implementation costs incurred in 2013.

In June 2014, Entergy Mississippi filed its first general rate case before the MPSC in almost 12 years.  The rate filing laid out Entergy Mississippi’s plans for improving reliability, modernizing the grid, maintaining its workforce, stabilizing rates, utilizing new technologies, and attracting new industry to its service territory.  Entergy Mississippi requested a net increase in revenue of $49 million for bills rendered during calendar year 2015, including $30 million resulting from new depreciation rates to update the estimated service life of assets.  In addition, the filing proposed, among other things: 1) realigning cost recovery of the Attala and Hinds power plant acquisitions from the power management rider to base rates; 2) including certain MISO-related revenues and expenses in the power management rider; 3) power management rider changes that reflect the changes in costs and revenues that will accompany Entergy Mississippi’s withdrawal from participation in the System Agreement; and 4) a formula rate plan forward test year to allow for known changes in expenses and revenues for the rate effective period.  Entergy Mississippi proposed maintaining the current authorized return on common equity of 10.59%. 

In October 2014, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed joint stipulations that addressed the majority of issues in the proceeding. The stipulations provided for:

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an approximate $16 million net increase in revenues, which reflected an agreed upon 10.07% return on common equity;

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revision of Entergy Mississippi’s formula rate plan by providing Entergy Mississippi with the ability to reflect known and measurable changes to historical rate base and certain expense amounts; resolving uncertainty around and obviating the need for an additional rate filing in connection with Entergy Mississippi’s withdrawal from participation in the System Agreement; updating depreciation rates; and moving costs associated with the Attala and Hinds generating plants from the power management rider to base rates;
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recovery of non-fuel MISO-related costs through a separate rider for that purpose;
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a deferral of $6 million in other operation and maintenance expenses associated with the Baxter Wilson outage and a determination that the regulatory asset should accrue carrying costs, with amortization of the regulatory asset over two years beginning in February 2015, and a provision that the capital costs will be reflected in rate base. See Note 8 to the financial statements for further discussion of the Baxter Wilson outage; and
•
consolidation of the new nuclear generation development costs proceeding with the general rate case proceeding for hearing purposes and a determination that Entergy Mississippi would not further pursue, except as noted below, recovery of the costs that were approved for deferral by the MPSC in November 2011. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. See "New Nuclear Generation Development Costs - Entergy Mississippi" below for further discussion of the new nuclear generation development costs proceeding and subsequent write-off in 2014 of the regulatory asset related to those costs.

In December 2014 the MPSC issued an order accepting the stipulations in their entirety and approving the revenue adjustments and rate changes effective with February 2015 bills.

Filings with the City Council

(Entergy Louisiana)

In March 2013, Entergy Louisiana filed a rate case for the Algiers area, which is in New Orleans and is regulated by the City Council. Entergy Louisiana is requesting a rate increase of $13 million over three years, including a 10.4% return on common equity and a formula rate plan mechanism identical to its LPSC request. In January 2014, the City Council Advisors filed direct testimony recommending a rate increase of $5.56 million over three years, including an 8.13% return on common equity. In June 2014 the City Council unanimously approved a settlement that includes the following:

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a $9.3 million base rate revenue increase to be phased in on a levelized basis over four years;
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recovery of an additional $853 thousand annually through a MISO recovery rider; and
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the adoption of a four-year formula rate plan requiring the filing of annual evaluation reports in May of each year, commencing May 2015, with resulting rates being implemented in October of each year. The formula rate plan includes a midpoint target authorized return on common equity of 9.95% with a +/- 40 basis point bandwidth.

The rate increase was effective with bills rendered on and after the first billing cycle of July 2014. Additional compliance filings were made with the Council in October 2014 for approval of the form of certain rate riders, including among others, a Ninemile 6 non-fuel cost recovery interim rider, allowing for contemporaneous recovery of capacity costs related to the commencement of commercial operation of the Ninemile 6 generating unit and a purchased power capacity cost recovery rider. The Ninemile 6 cost recovery interim rider was implemented in December 2014 to collect $915 thousand from Entergy Louisiana customers in the Algiers area.


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(Entergy New Orleans)

Formula Rate Plan

In April 2009 the City Council approved a three-year formula rate plan for Entergy New Orleans, with terms including an 11.1% benchmark electric return on common equity (ROE) with a +/-40 basis point bandwidth and a 10.75% benchmark gas ROE with a +/-50 basis point bandwidth.  Earnings outside the bandwidth reset to the midpoint benchmark ROE, with rates changing on a prospective basis depending on whether Entergy New Orleans was over- or under-earning.  The formula rate plan also included a recovery mechanism for City Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure events.

In May 2012, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2011 test year.  Subsequent adjustments agreed upon with the City Council Advisors indicate a $4.9 million electric base revenue increase and a $0.05 million gas base revenue increase as necessary under the formula rate plan.  As part of the original filing, Entergy New Orleans also requested to increase annual funding for its storm reserve by approximately $5.7 million for five years.  On September 26, 2012, Entergy New Orleans made a filing with the City Council that implemented the $4.9 million electric formula rate plan rate increase and the $0.05 million gas formula rate plan rate increase.  The new rates were effective with the first billing cycle in October 2012.  In August 2013 the City Council unanimously approved a settlement of all issues in the formula rate plan proceeding.  Pursuant to the terms of the settlement, Entergy New Orleans implemented an approximately $1.625 million net decrease to the electric rates that were in effect prior to the electric rate increase implemented in October 2012, with no change in gas rates.  Entergy New Orleans refunded to customers approximately $6 million over the four-month period from September 2013 through December 2013 to make the electric rate decrease effective as of the first billing cycle of October 2012.  Entergy New Orleans had previously recorded provisions for the majority of the refund to customers, but recorded an additional $1.1 million provision in second quarter 2013 as a result of the settlement. Entergy New Orleans’s formula rate plan ended with the 2011 test year and has not been extended.  Entergy New Orleans is recovering the costs of its power purchase agreement with Entergy Louisiana for 20% of the capacity and energy of the Ninemile Unit 6 generating station, which commenced operation in December 2014, through a special Ninemile Unit 6 rider.

A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs.  In September 2009 the City Council approved the energy efficiency programs filed by Entergy New Orleans.  The rate settlement provides an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provides 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 October 2013 the City Council approved the extension of the current Energy Smart program through December 2014. The City Council approved the use of $3.5 million of rough production cost equalization funds for program costs. In addition, Entergy New Orleans will be allowed to recover its lost contribution to fixed costs and to earn an incentive for meeting program goals. In January 2015 the City Council approved extending the Energy Smart program through March 2015 and using $1.2 million of rough production cost equalization funds to cover program costs for the extended period. Additionally, the City Council approved funding for the Energy Smart 2 programs from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, and with any remaining costs being recovered through the fuel adjustment clause.

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

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current 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 includes 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 provides 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 it 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 continues to believe that it is 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 have also filed motions for rehearing of the PUCT’s order.  The PUCT subsequently denied rehearing of substantive issues.  Several parties, including Entergy Texas, have appealed 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 appealed the Travis County District Court decision and the PUCT appealed the decision on the line-loss factor issue. Entergy Texas expects to file briefs during the first half of 2015.

2013 Rate Case

In September 2013, Entergy Texas filed a rate case requesting a $38.6 million base rate increase reflecting a 10.4% return on common equity based on an adjusted test year ending March 31, 2013. The rate case also proposed (1) a rough production cost equalization adjustment rider recovering Entergy Texas’s payment to Entergy New Orleans to achieve rough production cost equalization based on calendar year 2012 production costs and (2) a rate case expense rider recovering the cost of the 2013 rate case and certain costs associated with previous rate cases. The rate case filing also included a request to reconcile $0.9 billion of fuel and purchased power costs and fuel revenues covering the period July 2011 through March 2013. The fuel reconciliation also reflects special circumstances fuel cost recovery of approximately $22 million of purchased power capacity costs. In January 2014 the PUCT staff filed direct testimony recommending a retail rate reduction of $0.3 million and a 9.2% return on common equity. In March 2014, Entergy Texas filed an Agreed Motion for Interim Rates. The motion explained that the parties to this proceeding have agreed that Entergy Texas should be allowed to implement new rates reflecting an $18.5 million base rate increase, effective for usage on and after April 1, 2014, as well as recovery of charges for rough production cost equalization and rate case expenses. In March 2014 the State Office of Administrative Hearings, the body assigned to hear the case, approved the motion. In April 2014, Entergy Texas filed a unanimous stipulation in this case. Among other things, the stipulation provides for an $18.5 million base rate increase, recovery over three years of the calendar year 2012 rough production cost equalization charges and rate case expenses, and states a 9.8% return on common equity. In addition, the stipulation finalizes the fuel and purchased power reconciliation covering the period July 2011 through March 2013, with the parties stipulating an immaterial fuel disallowance. No special circumstances recovery of purchased power capacity costs was allowed. In April 2014 the State Office of Administrative Hearings remanded the case back to the PUCT for final processing. In May 2014 the PUCT approved the stipulation. No motions for rehearing were filed during the statutory rehearing period.

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In September 2014, Entergy Texas filed for a distribution cost recovery factor rider based on a law that was passed in 2011 allowing for the recovery of increases in capital costs associated with distribution plant. Entergy Texas requested collection of approximately $7 million annually from retail customers. The parties reached a unanimous settlement authorizing recovery of $3.6 million annually commencing with usage on and after January 1, 2015. A State Office of Administrative Hearings ALJ issued an order in December 2014 authorizing this recovery on an interim basis and remanded the case to the PUCT. In February 2015 the PUCT entered a final order, making the settlement final and the interim rates permanent.

Entergy Louisiana and Entergy Gulf States Louisiana Business Combination

In June 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed a business combination study report with the LPSC. The report contained a preliminary analysis of the potential combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility, including an overview of the combination that identified its potential customer benefits. Although not part of the business combination, Entergy Louisiana provided notice to the City Council in June 2014 that it would seek authorization to transfer to Entergy New Orleans the assets that currently support the provision of service to Entergy Louisiana’s customers in Algiers. Entergy Louisiana subsequently filed the referenced application with the City Council in October 2014. In the summer of 2014, Entergy Louisiana and Entergy Gulf States Louisiana held technical conferences and face-to-face meetings with LPSC staff and other stakeholders to discuss potential effects of the combination, solicit suggestions and concerns, and identify areas in which additional information might be needed.

On September 30, 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed an application with the LPSC seeking authorization to undertake the transactions that would result in the combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility.

The combination is subject to regulatory review and approval of the LPSC, the FERC, and the NRC. In June 2014, Entergy submitted an application to the NRC for approval of River Bend and Waterford 3 license transfers as part of the steps to complete the business combination. The combination also could be subject to regulatory review of the City Council if Entergy Louisiana continues to own the assets that currently support Entergy Louisiana’s customers in Algiers at the time the combination is effectuated. In November 2014, Entergy Louisiana filed an application with the City Council seeking authorization to undertake the combination. The application provides that if the City Council approves the Algiers asset transfer before the business combination occurs, the City Council may not need to issue a public interest finding regarding the combination. In December 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed applications with the FERC requesting authorization for the business combination and the Algiers asset transfer. In January 2015, Entergy Services filed an application with the FERC for financing authority for the combined company. If approvals are obtained from the LPSC, the FERC, the NRC, and, if required, the City Council, Entergy Louisiana and Entergy Gulf States Louisiana expect the combination will be effected in the second half of 2015.

The procedural schedule in the LPSC business combination proceeding calls for LPSC Staff and intervenor testimony to be filed in March 2015, with a hearing scheduled for June 2015. Entergy Louisiana and Entergy Gulf States Louisiana have requested that the LPSC issue its decision regarding the business combination in August 2015. In the City Council business combination proceeding, the City Council announced through a resolution that it would not initiate an active review of the business combination filing, but instead would establish a business combination docket for the limited purpose of receiving information filings relative to the business combination proceedings at the LPSC.

It is currently contemplated that Entergy Louisiana and Entergy Gulf States Louisiana will undertake multiple steps to effectuate the combination, which steps would include the following:

•
Each of Entergy Louisiana and Entergy Gulf States Louisiana will redeem or repurchase all of their respective outstanding preferred membership interests (which interests have a $100 million liquidation

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value in the case of Entergy Louisiana and $10 million liquidation value in the case of Entergy Gulf States Louisiana).
•
Entergy Gulf States Louisiana will convert from a Louisiana limited liability company to a Texas limited liability company.
•
Under the Texas Business Organizations Code (TXBOC), Entergy Louisiana will allocate substantially all of its assets to a new subsidiary (New Entergy Louisiana) and New Entergy Louisiana will assume all of the liabilities of Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Entergy Louisiana will remain in existence and hold the membership interests in New Entergy Louisiana.
•
Under the TXBOC, Entergy Gulf States Louisiana will allocate substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana will assume all of the liabilities of Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. Entergy Gulf States Louisiana will remain in existence and hold the membership interests in New Entergy Gulf States Louisiana.
•
Entergy Louisiana and Entergy Gulf States Louisiana will contribute the membership interests in New Entergy Louisiana and New Entergy Gulf States Louisiana to an affiliate the common membership interests of which will be owned by Entergy Louisiana, Entergy Gulf States Louisiana and Entergy Corporation.
•
New Entergy Gulf States Louisiana will merge into New Entergy Louisiana with New Entergy Louisiana surviving the merger.

Upon the completion of the steps, New Entergy Louisiana will hold substantially all of the assets, and will have assumed all of the liabilities, of Entergy Louisiana and Entergy Gulf States Louisiana. Entergy Louisiana and Entergy Gulf States Louisiana may modify or supplement the steps to be taken to effect the 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 currently serve Entergy Louisiana’s customers in Algiers. The transaction is expected to result in the transfer of net assets of approximately $60 million. The Algiers asset transfer is also subject to regulatory review and approval of the FERC. As discussed previously, Entergy Louisiana also filed an application with the City Council seeking authorization to undertake the Entergy Louisiana and Entergy Gulf States Louisiana business combination. The application provides that if the City Council approves the Algiers asset transfer before the business combination occurs, the City Council may not need to issue a public interest finding regarding the business combination. If the necessary approvals are obtained from the City Council and the FERC, Entergy Louisiana expects to transfer the Algiers assets to Entergy New Orleans in the second half of 2015. In November 2014 the City Council approved a resolution establishing a procedural schedule that provides for a hearing on the joint application in late-May 2015, with a decision to be rendered no later than June 2015.

System Agreement Cost Equalization Proceedings

The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC.  Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC.  The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement.

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 FERC decision concluded, among other things, that:


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•
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 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.

The FERC’s decision reallocates 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.  Under the current circumstances, this will be accomplished by payments from Utility operating companies whose production costs are more than 11% below Entergy System average production costs to Utility operating companies whose production costs are more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs are farthest above the Entergy System average.

The financial consequences of the FERC’s decision are determined by the total production cost of each Utility operating company, which are affected by the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power.  Entergy Louisiana, Entergy Gulf States Louisiana, Entergy Texas, and Entergy Mississippi are more dependent upon gas-fired generation sources than Entergy Arkansas or Entergy New Orleans.  Of these, Entergy Arkansas is the least dependent upon gas-fired generation sources.  Therefore, increases in natural gas prices generally increased the amount by which Entergy Arkansas’s total production costs were below the Entergy System average production costs.
 
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 these issues.

In October 2011, the FERC issued an order addressing the D.C. Circuit remand on these 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 the refund ruling will be held in abeyance pending the outcome of the rehearing requests in that 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 the additional 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.  As is the case with bandwidth remedy payments, these payments and receipts will ultimately be paid by Utility operating company customers to other Utility operating company customers.

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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 filing shows the following payments/receipts among the Utility operating companies:
 
Payments
(Receipts)
 
(In Millions)
Entergy Arkansas
$156
Entergy Gulf States Louisiana
($75)
Entergy Louisiana
$—
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 payment 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 have requested rehearing of the FERC’s October 2011 order.  In December 2013 the LPSC filed a petition for a writ of mandamus at the United States Court of Appeals for the D.C. Circuit. In its petition, the LPSC requested that the D.C. Circuit issue an order compelling the FERC to issue a final order on pending rehearing requests. In its response to the LPSC petition, the FERC committed to rule on the pending rehearing request before the end of February. In January 2014 the D.C. Circuit denied the LPSC’s petition. 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.

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 has sought rehearing of the February 2014 orders 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. The appeal is currently being held in abeyance pending resolution of Entergy’s request for rehearing with respect to the FERC’s determinations regarding interest.

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:


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Payments
(Receipts)
 
(In Millions)
Entergy Arkansas
$68
Entergy Gulf States Louisiana
($10)
Entergy Louisiana
$—
Entergy Mississippi
($11)
Entergy New Orleans
$2
Entergy Texas
($49)

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

Calendar Year 2014 Production Costs

Based on certain year-to-date information, Entergy preliminarily estimates that no payments and receipts are required in 2015 to implement the FERC’s remedy based on calendar year 2014 production costs. The actual payments/receipts for 2015, based on calendar year 2014 production costs, will not be calculated until the Utility operating companies’ 2014 FERC Form 1s have been filed. Once the calculation is completed, it will be filed at the FERC. The level of any payments and receipts is significantly affected by a number of factors, including, among others, weather, the price of alternative fuels, the operating characteristics of the Entergy System generating fleet, and multiple factors affecting the calculation of the non-fuel related revenue requirement components of the total production costs, such as plant investment.

Rough Production Cost Equalization Rates

Each May since 2007 Entergy has filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding.  These filings show the following payments/receipts among the Utility operating companies are 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 Gulf States Louisiana

($120
)
 

($124
)
 

($107
)
 

$—

 

($12
)
 

$—

 

$—

 

$—

Entergy Louisiana

($91
)
 

($36
)
 

($140
)
 

($22
)
 

$—

 

($41
)
 

$—

 

$—

Entergy Mississippi

($41
)
 

($20
)
 

($24
)
 

($19
)
 

($40
)
 

$—

 

$—

 

$—

Entergy New Orleans

$—

 

($7
)
 

$—

 

$—

 

($25
)
 

$—

 

($15
)
 

($15
)
Entergy Texas

($30
)
 

($65
)
 

($119
)
 

$—

 

$—

 

$—

 

$15

 

$15


Entergy Arkansas is no longer a participant in the System Agreement and was not part of the calendar year 2013 or 2014 production costs calculations.

The APSC has approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas.  Entergy Texas proposed a rough production cost equalization adjustment rider in its September 2013 rate filing, which is pending. 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.  See “2007 Rate Filing Based on Calendar Year 2006 Production Costs” below, however, for a discussion of a FERC decision that could result in trapped costs at Entergy Arkansas related to a contract with AmerenUE.


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Entergy Arkansas and, for December 2012 and 2013, Entergy Texas, record accounts payable and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy.  Entergy Arkansas and, for December 2012 and 2013, Entergy Texas, record a corresponding regulatory asset for the right to collect the payments from customers, and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record corresponding regulatory liabilities for their obligations to pass the receipts on to customers.  The regulatory asset and liabilities are shown as “System Agreement cost equalization” on the respective balance sheets.

2007 Rate Filing Based on Calendar Year 2006 Production Costs

Several parties intervened in the 2007 rate proceeding at the FERC, including the APSC, the MPSC, the Council, and the LPSC, which also filed protests.  The PUCT also intervened.  Intervenor testimony was filed in which the intervenors and also the FERC Staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for nuclear facilities.  The effect of the various positions would be to reallocate costs among the Utility operating companies.  The Utility operating companies filed rebuttal testimony explaining why the bandwidth payments are properly recoverable under the AmerenUE contract, and explaining why the positions of FERC Staff and intervenors on the other issues should be rejected.  A hearing in this proceeding concluded in July 2008, and the ALJ issued an initial decision in September 2008.  The ALJ’s initial decision concluded, among other things, that: (1) the decisions to not exercise Entergy Arkansas’s option to purchase the Independence plant in 1996 and 1997 were prudent; (2) Entergy Arkansas properly flowed a portion of the bandwidth payments through to AmerenUE in accordance with the wholesale power contract; and (3) the level of nuclear depreciation and decommissioning expense reflected in the bandwidth calculation should be calculated based on NRC-authorized license life, rather than the nuclear depreciation and decommissioning expense authorized by the retail regulators for purposes of retail ratemaking.  Following briefing by the parties, the matter was submitted to the FERC for decision. On January 11, 2010, the FERC issued its decision both affirming and overturning certain of the ALJ’s rulings, including overturning the decision on nuclear depreciation and decommissioning expense.  The FERC’s conclusion related to the AmerenUE contract does not permit Entergy Arkansas to recover a portion of its bandwidth payment from AmerenUE.  The Utility operating companies requested rehearing of that portion of the decision and requested clarification on certain other portions of the decision.

AmerenUE argued that its wholesale power contract with Entergy Arkansas, pursuant to which Entergy Arkansas sells power to AmerenUE, does not permit Entergy Arkansas to flow through to AmerenUE any portion of Entergy Arkansas’s bandwidth payment.  The AmerenUE contract expired in August 2009.  In April 2008, AmerenUE filed a complaint with the FERC seeking refunds, plus interest, in the event the FERC ultimately determines that bandwidth payments are not properly recovered under the AmerenUE contract.  In response to the FERC’s decision discussed in the previous paragraph, Entergy Arkansas recorded a regulatory provision in the fourth quarter 2009 for a potential refund to AmerenUE.

In May 2012, the FERC issued an order on rehearing in the proceeding.  The order may result in the reallocation of costs among the Utility operating companies, although there are still FERC decisions pending in other System Agreement proceedings that could affect the rough production cost equalization payments and receipts.  The FERC directed Entergy, within 45 days of the issuance of a pending FERC order on rehearing regarding the functionalization of costs in the 2007 rate filing, to file a comprehensive bandwidth recalculation report showing updated payments and receipts in the 2007 rate filing proceeding.  The May 2012 FERC order also denied Entergy’s request for rehearing regarding the AmerenUE contract and ordered Entergy Arkansas to refund to AmerenUE the rough production cost equalization payments collected from AmerenUE.  Under the terms of the FERC’s order a refund of $30.6 million, including interest, was made in June 2012.  Entergy and the LPSC appealed certain aspects of the FERC’s decisions to the U.S. Court of Appeals for the D.C. Circuit.  On December 7, 2012, the D.C. Circuit dismissed Entergy’s petition for review as premature because Entergy filed a rehearing request of the May 2012 FERC order and that rehearing request is still pending.  The court also ordered that the LPSC’s appeal be held in abeyance and that the parties file

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motions to govern further proceedings within 30 days of the FERC’s completion of the ongoing “Entergy bandwidth proceedings.” On October 16, 2013, the FERC issued two orders related to this proceeding. The first order provided clarification with regard to the derivation of the ratio that should be used to functionalize net operating loss carryforwards for purposes of the annual bandwidth filings. The first order required a compliance filing that Entergy made in November 2013. The second order denied Entergy’s request for rehearing of the FERC’s prior determination that interest should be included on recalculated payment and receipt amounts required in this particular proceeding due to the length of time that had passed. Entergy subsequently appealed certain aspects of the FERC’s decisions to the U.S. Court of Appeals for the D.C. Circuit. On January 23, 2014, the D.C. Circuit returned the LPSC’s appeal to the active docket and consolidated it with Entergy’s petition for appellate review. The appeals are pending. In July 2014 the FERC issued an order accepting Entergy Services’ November 2013 compliance filing. The FERC directed Entergy Services to make a comprehensive bandwidth recalculation report by September 15, 2014 showing all the updated payment/receipt amounts based on the 2006 calendar year data in compliance with all bandwidth formula and bandwidth calculation adjustments that the FERC has accepted or ordered for those years. The FERC also directed the Entergy Operating Companies to make any true-up bandwidth payments associated with the 2006 bandwidth recalculation report with interest following the filing of the comprehensive recalculation report. See discussion below regarding the comprehensive bandwidth recalculation and filings made with the FERC in connection with this proceeding.

2008 Rate Filing Based on Calendar Year 2007 Production Costs

Several parties intervened in the 2008 rate proceeding at the FERC, including the APSC, the LPSC, and AmerenUE, which also filed protests.  Several other parties, including the MPSC and the City Council, intervened in the proceeding without filing a protest.  In direct testimony filed in January 2009, certain intervenors and the FERC staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for the nuclear and fossil-fueled generating facilities.  The effect of these various positions would be to reallocate costs among the Utility operating companies.  In addition, three issues were raised alleging imprudence by the Utility operating companies, including whether the Utility operating companies had properly reflected generating units’ minimum operating levels for purposes of making unit commitment and dispatch decisions, whether Entergy Arkansas’s sales to third parties from its retained share of the Grand Gulf nuclear facility were reasonable, prudent, and non-discriminatory, and whether Entergy Louisiana’s long-term Evangeline gas purchase contract was prudent and reasonable.

The parties reached a partial settlement agreement of certain of the issues initially raised in this proceeding.  The partial settlement agreement was conditioned on the FERC accepting the agreement without modification or condition, which the FERC did in August 2009.  A hearing on the remaining issues in the proceeding was completed in June 2009, and in September 2009 the ALJ issued an initial decision.  The initial decision affirms Entergy’s position in the filing, except for two issues that may result in a reallocation of costs among the Utility operating companies.  In October 2011 the FERC issued an order on the ALJ’s initial decision.  The FERC’s order resulted in a minor reallocation of payments/receipts among the Utility operating companies on one issue in the 2008 rate filing.  Entergy made a compliance filing in December 2011 showing the updated payment/receipt amounts.  The LPSC filed a protest in response to the compliance filing.  In January 2013 the FERC issued an order accepting Entergy’s compliance filing.  In the January 2013 order the FERC required Entergy to include interest on the recalculated bandwidth payment and receipt amounts for the period from June 1, 2008 until the date of the Entergy intra-system bill that will reflect the bandwidth recalculation amounts for calendar year 2007.  In February 2013, Entergy filed a request for rehearing of the FERC’s ruling requiring interest. In March 2013 the LPSC filed a petition for review with the U.S. Court of Appeals for the Fifth Circuit seeking appellate review of the FERC’s earlier orders addressing the ALJ’s initial decision. In July 2014 the FERC issued an order denying Entergy’s rehearing request and decided that it is appropriate to allow interest to be paid on the bandwidth recalculation amounts. The FERC also directed Entergy to file a comprehensive bandwidth recalculation report by September 15, 2014 showing all the updated payment/receipt amounts based on the 2007 calendar year data in compliance with all bandwidth formula and bandwidth calculation adjustments that the FERC has accepted or ordered for that year. The FERC also directed the Entergy Operating Companies to make any true-up bandwidth payments associated with the 2007 bandwidth recalculation report with interest following the filing of the comprehensive

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recalculation report. In August 2014 the Fifth Circuit issued its opinion dismissing in part and denying in part the LPSC petition for review of the FERC’s order. In December 2014 the LPSC petitioned the U.S. Supreme Court for a writ of certiorari of the Fifth Circuit’s decision. In September 2014, Entergy filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit seeking appellate review of the FERC’s interest determination. See discussion below regarding the comprehensive bandwidth recalculation and filings made with the FERC in connection with this proceeding.

2009 Rate Filing Based on Calendar Year 2008 Production Costs

Several parties intervened in the 2009 rate proceeding at the FERC, including the LPSC and Ameren, which also filed protests.  In July 2009 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2009, subject to refund, and set the proceeding for hearing and settlement procedures.  Settlement procedures were terminated and a hearing before the ALJ was held in April 2010.  In August 2010 the ALJ issued an initial decision.  The initial decision substantially affirms Entergy’s position in the filing, except for one issue that may result in some reallocation of costs among the Utility operating companies.  The LPSC, the FERC trial staff, and Entergy submitted briefs on exceptions in the proceeding.  In May 2012 the FERC issued an order affirming the ALJ’s initial decision, or finding certain issues in that decision moot.  Rehearing and clarification of FERC’s order have been requested. In January 2013 the LPSC filed a protest of Entergy’s July 2012 compliance filing submitted in response to the FERC’s May 2012 order. In October 2013 the FERC issued orders denying the LPSC’s rehearing request with respect to the FERC’s May 2012 order and addressing Entergy’s compliance filing implementing the FERC’s directives in the May 2012 order. The compliance filing order referred to guidance provided in a separate order issued on that same day in the 2007 rate proceeding with respect to the ratio used to functionalize net operating loss carryforwards for bandwidth purposes and directed Entergy to make an additional compliance filing in the 2009 rate proceeding consistent with the guidance provided in that order. In November 2013 the LPSC sought rehearing of the FERC’s October 2013 order and Entergy submitted its compliance filing implementing the FERC’s directives in the October 2013 order. In August 2014, the FERC issued an order accepting the November 2013 compliance filing that was made in response to the FERC’s October 2013 order. The LPSC appealed to the U.S. Court of Appeals for the Fifth Circuit the FERC’s May 2012 and October 2013 orders. In November 2014 the Fifth Circuit issued its opinion denying the LPSC petition for review of the FERC’s order. In December 2014 the LPSC petitioned the U.S. Supreme Court for a writ of certiorari of the Fifth Circuit’s decision. See discussion below regarding the comprehensive bandwidth recalculation and filings made with the FERC in connection with this proceeding.

Comprehensive Bandwidth Recalculation for 2007, 2008, and 2009 Rate Filing Proceedings

In July 2014 the FERC issued four orders in connection with various Service Schedule MSS-3 rough production cost equalization formula compliance filings and rehearing requests. Specifically, the FERC accepted Entergy Services’ revised methodologies for calculating certain cost components of the formula and affirmed its prior ruling requiring interest on the true-up amounts. The FERC directed that a comprehensive recalculation of the formula be performed for the filing years 2007, 2008, and 2009 based on calendar years 2006, 2007, and 2008 production costs. In September 2014, Entergy filed with the FERC its compliance filing that provides the payments and receipts, including interest, among the Utility operating companies pursuant to the FERC’s orders for the 2007, 2008, and 2009 rate filing proceedings. The filing shows the following additional payments/receipts among the Utility operating companies:

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Payments
(Receipts)
 
(In Millions)
Entergy Arkansas
$38
Entergy Gulf States Louisiana
($22)
Entergy Louisiana
($16)
Entergy Mississippi
$16
Entergy New Orleans
($1)
Entergy Texas
($15)

Entergy Arkansas and Entergy Mississippi made the payments in September and October 2014. The updated compliance filings in the 2008 and 2009 rate filing proceedings have not been protested, and one protest was filed at the FERC related to the 2007 rate filing proceeding. The filings are pending at the FERC.

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, and set the proceeding for hearing and settlement procedures.  Settlement procedures have been terminated, and the ALJ scheduled hearings to begin in March 2011.  Subsequently, in January 2011 the ALJ issued an order directing the parties and FERC Staff to show cause why this proceeding should not be stayed pending the issuance of FERC decisions in the prior production cost proceedings currently before the FERC on review.  In March 2011 the ALJ issued an order placing this proceeding in abeyance. In October 2013 the FERC issued an order granting clarification and denying rehearing with respect to its October 2011 rehearing order in this proceeding. The FERC clarified that in a bandwidth proceeding parties can challenge erroneous inputs, implementation errors, or prudence of cost inputs, but challenges to the bandwidth formula itself must be raised in a Federal Power Act section 206 complaint or section 205 filing. Subsequently in October 2013 the presiding ALJ lifted the stay order holding in abeyance the hearing previously ordered by the FERC and directing that the remaining issues proceed to a hearing on the merits. The hearing was held in March 2014 and the presiding ALJ issued an initial decision in September 2014. Briefs on exception were filed in October 2014, and the case is pending before the FERC.
 
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, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review. In January 2014 the LPSC filed a petition for a writ of mandamus at the United States Court of Appeals for the Fifth Circuit. In its petition, the LPSC requested that the Fifth Circuit issue an order compelling the FERC to issue a final order in several proceedings related to the System Agreement, including the 2011 rate filing based on calendar year 2010 production costs and the 2012 and 2013 rate filings discussed below. In March 2014 the Fifth Circuit rejected the LPSC’s petition for a writ of mandamus. In December 2014 the FERC rescinded its earlier abeyance order and consolidated the 2011 Rate Filing with the 2012, 2013, and 2014 Rate Filings for settlement and hearing procedures. A procedural schedule was adopted in February 2015, and a hearing on the merits is scheduled for November 2015.

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

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filed a protest.  In August 2012 the FERC accepted Entergy’s proposed rates for filing, effective June 2012, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review. In December 2014 the FERC rescinded its earlier abeyance order and consolidated the 2012 Rate Filing with the 2011, 2013, and 2014 Rate Filings for settlement and hearing procedures. A procedural schedule was adopted in February 2015, and a hearing on the merits is scheduled for November 2015.

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, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review. In December 2014 the FERC rescinded its earlier abeyance order and consolidated the 2013 Rate Filing with the 2011, 2012, and 2014 Rate Filings for settlement and hearing procedures. A procedural schedule was adopted in February 2015, and a hearing on the merits is scheduled for November 2015.

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. A procedural schedule was adopted in February 2015, and a hearing on the merits is scheduled for November 2015.

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 a refund under the decision.  The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit.   The refunds were made in the fourth quarter 2009.

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

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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, 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 are due.  Briefs were submitted and the matter is pending.
 
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 and the settlement agreement is currently pending before the FERC.  In July 2011, Entergy filed an amended/corrected refund report and a motion to defer action on the settlement agreement until after the FERC rules on the LPSC’s rehearing request regarding the June 2011 decision denying refunds.

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.”

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 allocate 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 prohibits 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 challenges sales made beginning in 2002 and requests refunds.  In July 2009 the

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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 response further explained that the FERC already had determined that Entergy Arkansas’s short-term wholesale sales did not trigger the “right-of-first-refusal” provision of the System Agreement.  While the D.C. Circuit recently determined that the “right-of-first-refusal” issue was not properly before the FERC at the time of its earlier decision on the issue, the LPSC raised no additional claims or facts that would warrant the FERC reaching a different conclusion.

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 will require 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, which are pending with the FERC.

As required by the procedural schedule established in the calculation proceeding, Entergy filed its direct testimony that included a proposed illustrative re-run, consistent with the directives in FERC’s order, of intra-system bills for 2003, 2004, and 2006, the three years with the highest volume of opportunity sales.  Entergy’s proposed illustrative re-run of intra-system bills shows that the potential cost for Entergy Arkansas would be up to $12 million for the years 2003, 2004, and 2006, excluding interest, and the potential benefit would be significantly less than that for each of the other Utility operating companies.  Entergy’s proposed illustrative re-run of the intra-system bills also shows an offsetting potential benefit to Entergy Arkansas for the years 2003, 2004, and 2006 resulting from the effects of the FERC’s order on System Agreement Service Schedules MSS-1, MSS-2, and MSS-3, and the potential offsetting cost would be significantly less than that for each of the other Utility operating companies.  Entergy provided to the LPSC an illustrative intra-system bill recalculation as specified by the LPSC for the years 2003, 2004, and 2006, and the LPSC then filed answering testimony in December 2012.  In its testimony the LPSC claims that the damages, excluding interest, that should be paid by Entergy Arkansas to the other Utility operating company’s customers for 2003, 2004, and 2006 are $42 million to Entergy Gulf States, Inc., $7 million to Entergy Louisiana, $23 million to Entergy Mississippi, and $4 million to Entergy New Orleans. The FERC staff and certain intervenors filed direct and answering testimony in February 2013. In April 2013, Entergy filed its rebuttal testimony in that proceeding, including a revised illustrative re-run of the intra-system bills for the years 2003, 2004, and 2006. The revised calculation

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determines the re-pricing of the opportunity sales based on consideration of moveable resources only and the removal of exchange energy received by Entergy Arkansas, which increases the potential cost for Entergy Arkansas over the three years 2003, 2004, and 2006 by $2.3 million from the potential costs identified in the Utility operating companies’ prior filings in September and October 2012. A hearing was held in May 2013 to quantify the effect of repricing the opportunity sales in accordance with the FERC’s decision.

In August 2013 the presiding judge issued an initial decision in the calculation proceeding. The initial decision concludes 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 concludes 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 does recognize that the LPSC’s methodology would result in an inequitable windfall to the other Utility operating companies and, therefore, concludes 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 FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff. The FERC’s review of the initial decision is pending. 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.
    
Storm Cost Recovery Filings with Retail Regulators

Entergy Arkansas

Entergy Arkansas December 2012 Winter Storm

In December 2012 a severe winter storm consisting of ice, snow, and high winds caused significant damage to Entergy Arkansas’s distribution lines, equipment, poles, and other facilities.  Total restoration costs for the repair and/or replacement of Entergy Arkansas’s electrical facilities in areas damaged from the winter storm were $63 million, including costs recorded as regulatory assets of approximately $22 million.  In the Entergy Arkansas 2013 rate case, the APSC approved inclusion of the construction spending in rate base and approved an increase in the normal storm cost accrual, which will effectively amortize the regulatory asset over a five-year period.

Entergy Gulf States Louisiana and Entergy Louisiana

Hurricane Isaac

In August 2012, Hurricane Isaac caused extensive damage to portions of Entergy’s service area in Louisiana, and to a lesser extent in Mississippi and Arkansas.  The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages.  In January 2013, Entergy Gulf States Louisiana and Entergy Louisiana drew $65 million and $187 million, respectively, from their funded storm reserve escrow accounts.  In April 2013, Entergy Gulf States Louisiana and Entergy Louisiana filed a joint application with the LPSC relating to Hurricane Isaac system restoration costs.  Specifically, Entergy Gulf States Louisiana and Entergy Louisiana requested that the LPSC determine the amount of such costs that were prudently incurred and are, thus, eligible for recovery from customers.  Including carrying costs and additional storm escrow funds for prior storms, Entergy Gulf States Louisiana requested an LPSC determination that $73.8 million in system restoration costs were prudently incurred and Entergy Louisiana requested an LPSC determination that $247.7 million in system restoration costs were prudently incurred.  In May 2013, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana's and Entergy Louisiana's storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55). The LPSC Staff filed direct testimony in September 2013 concluding that Hurricane

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Isaac system restoration costs incurred by Entergy Gulf States Louisiana and Entergy Louisiana were reasonable and prudent, subject to proposed minor adjustments which totaled approximately 1% of each company’s costs. Following an evidentiary hearing and recommendations by the ALJ, the LPSC voted in June 2014 to approve a series of orders which (i) quantify the amount of Hurricane Isaac system restoration costs prudently incurred ($66.5 million for Entergy Gulf States Louisiana and $224.3 million for Entergy Louisiana); (ii) determine the level of storm reserves to be re-established ($90 million for Entergy Gulf States Louisiana and $200 million for Entergy Louisiana); (iii) authorize Entergy Gulf States Louisiana and Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) grant other requested relief associated with storm reserves and Act 55 financing of Hurricane Isaac system restoration costs. Entergy Gulf States Louisiana committed to pass on to customers a minimum of $6.9 million of customer benefits through annual customer credits of approximately $1.4 million for five years.  Entergy Louisiana committed to pass on to customers a minimum of $23.9 million of customer benefits through annual customer credits of approximately $4.8 million for five years. Approvals for the Act 55 financings were obtained from the Louisiana Utilities Restoration Corporation (LURC) and the Louisiana State Bond Commission.

In July 2014, Entergy Gulf States Louisiana issued $110 million of 3.78% Series first mortgage bonds due April 2025 and used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes. In July 2014, Entergy Louisiana issued $190 million of 3.78% Series first mortgage bonds due April 2025 and used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes.

In August 2014 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $71 million in bonds under Act 55 of the Louisiana Legislature.  From the $69 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $3 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $66 million directly to Entergy Gulf States Louisiana.  Entergy Gulf States Louisiana used the $66 million received from the LURC to acquire 662,426.80 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.

In August 2014 the LCDA issued another $243.85 million in bonds under Act 55 of the Louisiana Legislature.  From the $240 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $13 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $227 million directly to Entergy Louisiana.  Entergy Louisiana used the $227 million received from the LURC to acquire 2,272,725.89 Class C preferred, non-voting, membership interest units of Entergy Holdings Company LLC 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, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA and there is no recourse against Entergy, Entergy Gulf States Louisiana, or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remit the collections to the bond indenture trustee.  Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the collections as revenue because they are merely acting as the billing and collection agents for the state.


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Hurricane Gustav and Hurricane Ike

In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy’s service territory.  Entergy Gulf States Louisiana and Entergy Louisiana filed their Hurricane Gustav and Hurricane Ike storm cost recovery case with the LPSC in May 2009.  In September 2009, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Act 55).  Entergy Gulf States Louisiana’s and Entergy Louisiana’s Hurricane Katrina and Hurricane Rita storm costs were financed primarily by Act 55 financings, as discussed below.  Entergy Gulf States Louisiana and Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and Act 55 financing savings to customers via a Storm Cost Offset rider.

In December 2009, Entergy Gulf States Louisiana and Entergy Louisiana entered into a stipulation agreement with the LPSC Staff that provides for total recoverable costs of approximately $234 million for Entergy Gulf States Louisiana and $394 million for Entergy Louisiana, including carrying costs.  Under this stipulation, Entergy Gulf States Louisiana agrees not to recover $4.4 million and Entergy Louisiana agrees not to recover $7.2 million of their storm restoration spending.  The stipulation also permits replenishing Entergy Gulf States Louisiana’s storm reserve in the amount of $90 million and Entergy Louisiana’s storm reserve in the amount of $200 million when the Act 55 financings are accomplished.  In March and April 2010, Entergy Gulf States Louisiana, Entergy Louisiana, and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that includes these terms and also includes Entergy Gulf States Louisiana’s and Entergy Louisiana’s proposals under the Act 55 financings, which includes a commitment to pass on to customers a minimum of $15.5 million and $27.8 million of customer benefits, respectively, through prospective annual rate reductions of $3.1 million and $5.6 million for five years.  A stipulation hearing was held before the ALJ on April 13, 2010.  On April 21, 2010, the LPSC approved the settlement and subsequently issued two financing orders and one ratemaking order intended to facilitate the implementation of the Act 55 financings.  In June 2010 the Louisiana State Bond Commission approved the Act 55 financings.

In July 2010, the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $468.9 million in bonds under Act 55.  From the $462.4 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $200 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $262.4 million directly to Entergy Louisiana.  From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana used $262.4 million to acquire 2,624,297.11 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.

In July 2010, the LCDA issued another $244.1 million in bonds under Act 55.  From the $240.3 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $90 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $150.3 million directly to Entergy Gulf States Louisiana.  From the bond proceeds received by Entergy Gulf States Louisiana from the LURC, Entergy Gulf States Louisiana used $150.3 million to acquire 1,502,643.04 Class B preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 9% annual distribution rate.  Distributions are payable quarterly commencing on September 15, 2010, and the membership interests have a liquidation price of $100 per unit.  The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement.  The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.


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Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy, Entergy Gulf States Louisiana or Entergy Louisiana in the event of a bond default.  To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remit the collections to the bond indenture trustee.  Entergy Gulf States Louisiana and Entergy Louisiana do not report the collections as revenue because they are merely acting as the billing and collection agents for the state.
 
Hurricane Katrina and Hurricane Rita

In August and September 2005, Hurricanes Katrina and Rita caused catastrophic damage to large portions of the Utility’s service territories in Louisiana, Mississippi, and Texas, including the effect of extensive flooding that resulted from levee breaks in and around the greater New Orleans area.  The storms and flooding resulted in widespread power outages, significant damage to electric distribution, transmission, and generation and gas infrastructure, and the loss of sales and customers due to mandatory evacuations and the destruction of homes and businesses.

In March 2008, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed at the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana and Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Legislature (Act 55 financings).  The Act 55 financings are expected to produce additional customer benefits as compared to traditional securitization.  Entergy Gulf States Louisiana and 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.  On April 8, 2008, the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financings, approved requests for the Act 55 financings.  On April 10, 2008, Entergy Gulf States Louisiana and Entergy Louisiana and the LPSC Staff filed with the LPSC an uncontested stipulated settlement that includes Entergy Gulf States Louisiana and Entergy Louisiana’s proposals under the Act 55 financings, which includes a commitment to pass on to customers a minimum of $10 million and $30 million of customer benefits, respectively, through prospective annual rate reductions of $2 million and $6 million for five years.  On April 16, 2008, the LPSC approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financings.  In May 2008 the Louisiana State Bond Commission granted final approval of the Act 55 financings.

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.  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 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 Gulf States Louisiana and transferred $187.7 million directly to Entergy Gulf States Louisiana.  From the bond proceeds received by Entergy Gulf States Louisiana from the LURC, Entergy Gulf States 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

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

Entergy Mississippi

On July 1, 2013, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation, wherein both parties agreed that approximately $32 million in storm restoration costs incurred in 2011 and 2012 were prudently incurred and chargeable to the storm damage provision, while approximately $700,000 in prudently incurred costs were more properly recoverable through the formula rate plan. Entergy Mississippi and the Mississippi Public Utilities Staff also agreed that the storm damage accrual should be increased from $750,000 per month to $1.75 million per month. In September 2013 the MPSC approved the joint stipulation with the increase in the storm damage accrual effective with October 2013 bills. In February 2015, Entergy Mississippi provided notice to the Mississippi Public Utilities Staff that the storm damage accrual would be set to zero effective with the March 2015 billing cycle as a result of Entergy Mississippi's storm damage accrual balance exceeding $15 million as of January 31, 2015, but will return to its current level when the storm damage accrual balance becomes less than $10 million.

Entergy New Orleans

In October 2006, the City Council approved a rate filing settlement agreement that, among other things, authorized a $75 million storm reserve for damage from future storms, which will be created over a ten-year period through a storm reserve rider that began in March 2007.  These storm reserve funds are held in a restricted escrow account until needed in response to a storm.  

In August 2012, Hurricane Isaac caused extensive damage to Entergy New Orleans’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. Total restoration costs for the repair and/or replacement of Entergy New Orleans’s electric facilities damaged by Hurricane Isaac were $47.3 million. Entergy New Orleans withdrew $17.4 million from the storm reserve escrow account to partially offset these costs. In February 2014, Entergy New Orleans made a filing with the City Council seeking certification of the Hurricane Isaac costs. 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, remains recoverable from Entergy New Orleans’s electric customers. The resolution also directs Entergy New Orleans to file an application to securitize the unrecovered 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 is 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 achieves the 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.

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New Nuclear Generation Development Costs

Entergy Gulf States Louisiana and Entergy Louisiana

Entergy Gulf States Louisiana and Entergy Louisiana have been developing and are preserving a project option for new nuclear generation at River Bend.  In March 2010, Entergy Gulf States Louisiana and Entergy 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 Gulf States Louisiana and Entergy 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 Gulf States Louisiana and Entergy 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, 2014, Entergy Gulf States Louisiana and Entergy Louisiana each have a regulatory asset of $29.2 million on its balance sheet related to these new nuclear generation development costs.
 
Entergy Mississippi

Pursuant to the Mississippi Baseload Act and the Mississippi Public Utilities Act, Entergy Mississippi had been developing and preserving a project option for new nuclear generation at Grand Gulf Nuclear Station.  In October 2010, Entergy Mississippi filed an application with the MPSC requesting that the MPSC determine that it was in the public interest to preserve the option to construct new nuclear generation at Grand Gulf and that the MPSC approve the deferral of Entergy Mississippi’s costs incurred to date and in the future related to this project, including the accrual of AFUDC or similar carrying charges.  In October 2011, Entergy Mississippi and the Mississippi Public Utilities Staff filed with the MPSC a joint stipulation that the MPSC approved in November 2011.  The stipulation stated that there should be a deferral of the $57 million of costs incurred through September 2011 in connection with planning, evaluation, monitoring, and other and related generation resource development activities for new nuclear generation at Grand Gulf.  

In October 2014, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed joint stipulations in Entergy Mississippi’s general rate case proceeding, which are discussed above. In consideration of the comprehensive terms for settlement in that rate case proceeding, the Mississippi Public Utilities Staff and Entergy Mississippi agreed that Entergy Mississippi would request consolidation of the new nuclear generation development costs proceeding with the rate case proceeding for hearing purposes and will not further pursue, except as noted below, recovery of the costs deferred by MPSC order in the new nuclear generation development docket. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. After considering the progress of the new nuclear generation costs proceeding in light of the joint stipulations, Entergy Mississippi recorded in 2014 a $56.2 million pre-tax charge to recognize that the regulatory asset associated with new nuclear generation development is no longer probable of recovery. In December 2014 the MPSC issued an order accepting in their entirety the October 2014 stipulations, including the findings and terms of the stipulations regarding new nuclear generation development costs.


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Texas Power Price Lawsuit

In August 2003, a lawsuit was filed in the district court of Chambers County, Texas by Texas residents on behalf of a purported class of the Texas retail customers of Entergy Gulf States, Inc. who were billed and paid for electric power from January 1, 1994 to the present.  The named defendants include Entergy Corporation, Entergy Services, Entergy Power, Entergy Power Marketing Corp., and Entergy Arkansas.  Entergy Gulf States, Inc. was not a named defendant, but was alleged to be a co-conspirator.  The court granted the request of Entergy Gulf States, Inc. to intervene in the lawsuit to protect its interests.

Plaintiffs allege that the defendants implemented a “price gouging accounting scheme” to sell to plaintiffs and similarly situated utility customers higher priced power generated by the defendants while rejecting less expensive power offered from off-system suppliers.  In particular, plaintiffs allege that the defendants manipulated and continue to manipulate the dispatch of generation so that power is purchased from affiliated expensive resources instead of buying cheaper off-system power.

Plaintiffs stated in their pleadings that customers in Texas were charged at least $57 million above prevailing market prices for power.  Plaintiffs seek actual, consequential and exemplary damages, costs and attorneys’ fees, and disgorgement of profits.  The plaintiffs’ experts have tendered a report calculating damages in a large range, from $153 million to $972 million in present value, under various scenarios as of the date of the report.  The Entergy defendants have tendered expert reports challenging the assumptions, methodologies, and conclusions of the plaintiffs’ expert reports.

In March 2012 the state district court found that the case met the requirements to be maintained as a class action under Texas law.  In April 2012 the court entered an order certifying the class.  The defendants appealed the order to the Texas Court of Appeals – First District and oral argument was held in May 2013. In November 2014 the Texas Court of Appeals - First District reversed the state district court’s class certification order and dismissed the case holding that the state district court lacked subject matter jurisdiction to address the issues. Plaintiffs filed a motion for rehearing and a motion for rehearing en banc. The Entergy defendants filed responsive briefings, and the parties are awaiting rulings by the Court.


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

Income taxes from continuing operations for 2014, 2013, and 2012 for Entergy Corporation and Subsidiaries consist of the following:
 
2014
 
2013
 
2012
 
(In Thousands)
Current:
 
 
 
 
 
Federal

$90,061

 

$88,291

 

($47,851
)
Foreign
90

 
101

 
143

State
(12,637
)
 
20,584

 
(41,516
)
Total
77,514

 
108,976

 
(89,224
)
Deferred and non-current - net
528,326

 
126,935

 
131,130

Investment tax credit adjustments - net
(16,243
)
 
(9,930
)
 
(11,051
)
Income tax expense from continuing operations

$589,597

 

$225,981

 

$30,855



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Income taxes for 2014, 2013, and 2012 for Entergy’s Registrant Subsidiaries consist of the following:
2014
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
Entergy
Texas
 
System
Energy
 
 
(In Thousands)
Current:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Federal
 

($34,258
)
 

($3,857
)
 

($41,052
)
 

$8,103

 

($1,924
)
 

$48,610

 

$19,908

State
 
(678
)
 
(769
)
 
(422
)
 
7,474

 
520

 
4,877

 
15,379

Total
 
(34,936
)
 
(4,626
)
 
(41,474
)
 
15,577

 
(1,404
)
 
53,487

 
35,287

Deferred and non-current - net
 
119,841

 
96,446

 
140,348

 
42,305

 
13,952

 
(2,418
)
 
53,501

Investment tax credit adjustments - net
 
(1,276
)
 
(3,038
)
 
(2,604
)
 
(2,172
)
 
(224
)
 
(1,425
)
 
(5,478
)
Income taxes
 

$83,629

 

$88,782

 

$96,270

 

$55,710

 

$12,324

 

$49,644

 

$83,310


2013
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
Entergy
Texas
 
System
Energy
 
 
(In Thousands)
Current:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Federal
 

($13,574
)
 

$12,176

 

($30,973
)
 

$2,498

 

$15,017

 

$37,199

 

($6,199
)
State
 
6,122

 
(9,939
)
 
(5,692
)
 
4,849

 
(1,221
)
 
(843
)
 
15,845

Total
 
(7,452
)
 
2,237

 
(36,665
)
 
7,347

 
13,796

 
36,356

 
9,646

Deferred and non-current - net
 
101,253

 
57,620

 
121,416

 
41,150

 
(11,952
)
 
(4,639
)
 
60,614

Investment tax credit adjustments - net
 
(2,014
)
 
(3,038
)
 
(2,874
)
 
1,260

 
(225
)
 
(1,609
)
 
(1,407
)
Income taxes
 

$91,787

 

$56,819

 

$81,877

 

$49,757

 

$1,619

 

$30,108

 

$68,853


2012
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
Entergy
Texas
 
System
Energy
 
 
(In Thousands)
Current:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Federal
 

$64,069

 

($66,081
)
 

($132,999
)
 

$3,188

 

($9,484
)
 

($114,677
)
 

($50,491
)
State
 
6,712

 
9,535

 
(1,269
)
 
(4,425
)
 
(1,617
)
 
4,933

 
(8,544
)
Total
 
70,781

 
(56,546
)
 
(134,268
)
 
(1,237
)
 
(11,101
)
 
(109,744
)
 
(59,035
)
Deferred and non-current - net
 
26,042

 
112,390

 
8,463

 
59,045

 
18,586

 
144,471

 
137,832

Investment tax credit adjustments - net
 
(2,017
)
 
(3,228
)
 
(3,117
)
 
871

 
(245
)
 
(1,609
)
 
(1,682
)
Income taxes
 

$94,806

 

$52,616

 

($128,922
)
 

$58,679

 

$7,240

 

$33,118

 

$77,115



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Total income taxes for Entergy Corporation and Subsidiaries differ from the amounts computed by applying the statutory income tax rate to income before income taxes.  The reasons for the differences for the years 2014, 2013, and 2012 are:
 
2014
 
2013
 
2012
 
(In Thousands)
Net income attributable to Entergy Corporation

$940,721

 

$711,902

 

$846,673

Preferred dividend requirements of subsidiaries
19,536

 
18,670

 
21,690

Consolidated net income
960,257

 
730,572

 
868,363

Income taxes
589,597

 
225,981

 
30,855

Income before income taxes

$1,549,854

 

$956,553

 

$899,218

Computed at statutory rate (35%)

$542,449

 

$334,794

 

$314,726

Increases (reductions) in tax resulting from:
 

 
 

 
 

State income taxes net of federal income tax effect
44,708

 
13,599

 
40,699

Regulatory differences - utility plant items
39,321

 
32,324

 
35,527

Equity component of AFUDC
(21,108
)
 
(22,356
)
 
(30,838
)
Amortization of investment tax credits
(12,211
)
 
(13,535
)
 
(14,000
)
Flow-through / permanent differences
(18,003
)
 
(301
)
 
(14,801
)
Net-of-tax regulatory liability
—

 
(2,899
)
 
(4,356
)
New York tax law change
(21,500
)
 
—

 
—

Deferred tax asset on additional depreciation (a)
—

 
—

 
(155,300
)
Termination of business reorganization
—

 
(27,192
)
 
—

Write-off of regulatory asset for income taxes
—

 
—

 
42,159

Capital losses
—

 
—

 
(20,188
)
Provision for uncertain tax positions (b)
32,573

 
(59,249
)
 
(159,957
)
Valuation allowance
—

 
(31,573
)
 
—

Other - net
3,368

 
2,369

 
(2,816
)
Total income taxes as reported

$589,597

 

$225,981

 

$30,855

Effective Income Tax Rate
38.0
%
 
23.6
%
 
3.4
%

(a)
See “Income Tax Audits - 2004-2005 IRS Audit” below for discussion of this item.
(b)
See “Income Tax Audits - 2008-2009 IRS Audit” below for discussion of the most significant items in 2013 and 2012.

In March 2014, New York enacted legislation that substantially modifies various aspects of New York tax law. The most significant effect of the legislation for Entergy is the adoption of full water's-edge unitary combined reporting, meaning that all of Entergy's domestic entities will be included in New York's combined filing group. The effect of the tax law change resulted in a deferred state income tax reduction of approximately $21.5 million as shown in the table above.


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Total income taxes for the Registrant Subsidiaries differ from the amounts computed by applying the statutory income tax rate to income before taxes.  The reasons for the differences for the years 2014, 2013, and 2012 are:
2014
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
Entergy
Texas
 
System
Energy
 
 
(In Thousands)
Net income
 

$121,392

 

$162,491

 

$283,531

 

$74,821

 

$28,707

 

$74,804

 

$96,334

Income taxes
 
83,629

 
88,782

 
96,270

 
55,710

 
12,324

 
49,644

 
83,310

Pretax income
 

$205,021

 

$251,273

 

$379,801

 

$130,531

 

$41,031

 

$124,448

 

$179,644

Computed at statutory rate (35%)
 

$71,757

 

$87,946

 

$132,930

 

$45,686

 

$14,361

 

$43,557

 

$62,875

Increases (reductions) in tax resulting from:
 
 
 
 

 
 

 
 

 
 

 
 

 
 

State income taxes net of federal income tax effect
 
9,591

 
6,532

 
5,134

 
5,180

 
1,643

 
3,221

 
6,877

Regulatory differences - utility plant items
 
8,653

 
4,618

 
2,869

 
4,448

 
777

 
4,165

 
13,791

Equity component of AFUDC
 
(2,533
)
 
(2,602
)
 
(12,010
)
 
(833
)
 
(320
)
 
(1,035
)
 
(1,774
)
Amortization of investment tax credits
 
(1,251
)
 
(3,018
)
 
(2,576
)
 
(260
)
 
(218
)
 
(1,412
)
 
(3,476
)
Flow-through / permanent differences
 
(5,082
)
 
799

 
(1,024
)
 
555

 
(4,458
)
 
393

 
(327
)
Non-taxable dividend income
 
—

 
(10,590
)
 
(30,665
)
 
—

 
—

 
—

 
—

Provision for uncertain tax positions
 
1,881

 
4,108

 
1,228

 
718

 
405

 
522

 
5,235

Other - net
 
613

 
989

 
384

 
216

 
134

 
233

 
109

Total income taxes
 

$83,629

 

$88,782

 

$96,270

 

$55,710

 

$12,324

 

$49,644

 

$83,310

Effective Income Tax Rate
 
40.8
%
 
35.3
%
 
25.3
%
 
42.7
%
 
30.0
%
 
39.9
%
 
46.4
%


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Notes to Financial Statements


2013
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
Entergy
Texas
 
System
Energy
 
 
(In Thousands)
Net income
 

$161,948

 

$161,662

 

$252,464

 

$82,159

 

$11,683

 

$57,881

 

$113,664

Income taxes
 
91,787

 
56,819

 
81,877

 
49,757

 
1,619

 
30,108

 
68,853

Pretax income
 

$253,735

 

$218,481

 

$334,341

 

$131,916

 

$13,302

 

$87,989

 

$182,517

Computed at statutory rate (35%)
 

$88,807

 

$76,468

 

$117,019

 

$46,171

 

$4,656

 

$30,796

 

$63,881

Increases (reductions) in tax resulting from:
 
 

 
 

 
 

 
 

 
 

 
 

 
 

State income taxes net of federal income tax effect
 
10,954

 
7,719

 
11,365

 
4,564

 
1,012

 
(897
)
 
5,900

Regulatory differences - utility plant items
 
7,938

 
4,865

 
2,140

 
2,603

 
453

 
3,256

 
11,070

Equity component of AFUDC
 
(3,820
)
 
(2,822
)
 
(10,278
)
 
(764
)
 
(322
)
 
(1,626
)
 
(2,724
)
Amortization of investment tax credits
 
(1,989
)
 
(3,018
)
 
(2,846
)
 
(260
)
 
(216
)
 
(1,596
)
 
(3,476
)
Flow-through / permanent differences
 
2,540

 
2,377

 
1,269

 
1,702

 
(4,402
)
 
2,467

 
(491
)
Net-of-tax regulatory liability
 
—

 
—

 
(2,899
)
 
—

 
—

 
—

 
—

Termination of business reorganization
 
(6,753
)
 
(3,619
)
 
(3,834
)
 
(4,177
)
 
(501
)
 
(3,542
)
 
(13
)
Non-taxable dividend income
 
—

 
(9,612
)
 
(27,341
)
 
—

 
—

 
—

 
—

Provision for uncertain tax positions
 
(6,527
)
 
(15,557
)
 
(3,088
)
 
(326
)
 
795

 
1,027

 
(5,353
)
Other - net
 
637

 
18

 
370

 
244

 
144

 
223

 
59

Total income taxes
 

$91,787

 

$56,819

 

$81,877

 

$49,757

 

$1,619

 

$30,108

 

$68,853

Effective Income Tax Rate
 
36.2
%
 
26.0
%
 
24.5
%
 
37.7
%
 
12.2
%
 
34.2
%
 
37.7
%


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2012
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
Entergy
Texas
 
System
Energy
 
 
(In Thousands)
Net income
 

$152,365

 

$158,977

 

$281,081

 

$46,768

 

$17,065

 

$41,971

 

$111,866

Income taxes (benefit)
 
94,806

 
52,616

 
(128,922
)
 
58,679

 
7,240

 
33,118

 
77,115

Pretax income
 

$247,171

 

$211,593

 

$152,159

 

$105,447

 

$24,305

 

$75,089

 

$188,981

Computed at statutory rate (35%)
 

$86,510

 

$74,058

 

$53,256

 

$36,906

 

$8,507

 

$26,281

 

$66,143

Increases (reductions) resulting from:
 
 

 
 

 
 

 
 

 
 

 
 

 
 

State income taxes net of federal income tax effect
 
11,282

 
5,087

 
1,976

 
3,944

 
505

 
3,115

 
6,652

Regulatory differences - utility plant items
 
6,778

 
8,472

 
312

 
2,619

 
2,289

 
3,668

 
11,389

Equity component of AFUDC
 
(2,495
)
 
(3,042
)
 
(12,919
)
 
(1,383
)
 
(276
)
 
(1,587
)
 
(9,136
)
Amortization of investment tax credits
 
(1,992
)
 
(3,204
)
 
(3,089
)
 
(264
)
 
(240
)
 
(1,596
)
 
(3,480
)
Net-of-tax regulatory liability
 
—

 
—

 
(4,356
)
 
—

 
—

 
—

 
—

Flow-through / permanent differences
 
3,427

 
(7,646
)
 
1,397

 
1,961

 
(4,385
)
 
1,585

 
(357
)
Non-taxable dividend income
 
—

 
(9,836
)
 
(27,336
)
 
—

 
—

 
—

 
—

Expense (benefit) of Entergy Corporation expenses
 
(19,403
)
 
(17,703
)
 
—

 
14,449

 
2,758

 
—

 
(10,241
)
Provision for uncertain tax positions
 
11,227

 
8,745

 
(143,583
)
 
870

 
(2,095
)
 
1,651

 
17,966

Change in regulatory recovery
 
—

 
(553
)
 
7,854

 
—

 
—

 
—

 
—

Other - net
 
(528
)
 
(1,762
)
 
(2,434
)
 
(423
)
 
177

 
1

 
(1,821
)
Total income taxes
 

$94,806

 

$52,616

 

($128,922
)
 

$58,679

 

$7,240

 

$33,118

 

$77,115

Effective Income Tax Rate
 
38.4
%
 
24.9
%
 
(84.7
%)
 
55.6
%
 
29.8
%
 
44.1
%
 
40.8
%


116
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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, 2014 and 2013 are as follows:
 
 
2014
 
2013
 
(In Thousands)
Deferred tax liabilities:
 
 
 
Plant basis differences - net

($8,128,096
)
 

($7,941,319
)
Regulatory assets
(922,161
)
 
(922,312
)
Nuclear decommissioning trusts
(1,248,737
)
 
(1,100,439
)
Pension, net funding
(324,881
)
 
(299,951
)
Combined unitary state taxes
(162,340
)
 
(183,934
)
Power purchase agreements
(110,889
)
 
(8,096
)
Other
(500,424
)
 
(404,749
)
Total
(11,397,528
)
 
(10,860,800
)
Deferred tax assets:
 

 
 

Nuclear decommissioning liabilities
874,493

 
754,828

Regulatory liabilities
458,230

 
403,370

Pension and other post-employment benefits
586,455

 
469,190

Sale and leaseback
153,308

 
176,119

Compensation
74,692

 
125,552

Accumulated deferred investment tax credit
100,442

 
106,777

Provision for allowances and contingencies
160,551

 
66,026

Net operating loss carryforwards
457,758

 
548,756

Capital losses and miscellaneous tax credits
12,146

 
13,140

Valuation allowance
(27,387
)
 
(28,146
)
Other
58,334

 
109,606

Total
2,909,022

 
2,745,218

Noncurrent accrued taxes (including unrecognized tax benefits)
(606,560
)
 
(400,276
)
Accumulated deferred income taxes and taxes accrued

($9,095,066
)
 

($8,515,858
)

Entergy’s estimated tax attributes carryovers and their expiration dates as of December 31, 2014 are as follows:
Carryover Description
 
Carryover Amount
 
Year(s) of expiration
 
 
 
 
 
Federal net operating losses
 
$12.3 billion
 
2023-2034
State net operating losses
 
$10.2 billion
 
2015-2033
Miscellaneous federal and state credits
 
$97.6 million
 
2015-2034

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 carryovers will not be utilized, a valuation allowance of $21.2 million has been provided on the deferred tax assets relating to these state net operating loss carryovers.

In the third quarter 2013, Entergy reduced a valuation allowance by $44 million ($28 million net of the federal income tax effect) that had been provided on a state net operating loss carryover due to the prospective utilization of such loss carryover.

117
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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, 2014 and 2013 are as follows:
2014
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
Entergy
Texas
 
System
Energy
 
(In Thousands)
Deferred tax liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
Plant basis differences - net

($1,657,503
)
 

($1,233,761
)
 

($1,515,091
)
 

($753,576
)
 

($186,153
)
 

($771,135
)
 

($668,779
)
Regulatory assets
(198,662
)
 
(106,287
)
 
(274,432
)
 
(30,114
)
 
—

 
(202,402
)
 
(110,087
)
Nuclear decommissioning trusts
(130,524
)
 
(43,611
)
 
(62,551
)
 
—

 
—

 
—

 
(74,063
)
Pension, net funding
(93,355
)
 
(46,403
)
 
(53,190
)
 
(27,861
)
 
(13,285
)
 
(25,616
)
 
(23,440
)
Deferred fuel
(82,050
)
 
(3,034
)
 
(500
)
 
(5,303
)
 
(407
)
 
2,045

 
(120
)
Power purchase agreements
(17,073
)
 
(67,083
)
 
—

 
2,129

 
13

 
847

 
—

Other
(33,827
)
 
(8,850
)
 
(75,432
)
 
(11,423
)
 
(11,500
)
 
(22,546
)
 
(19,802
)
Total
(2,212,994
)
 
(1,509,029
)
 
(1,981,196
)
 
(826,148
)
 
(211,332
)
 
(1,018,807
)
 
(896,291
)
Deferred tax assets:
 

 
 

 
 

 
 

 
 

 
 

 
 

Regulatory liabilities
145,466

 
70,068

 
111,533

 
7,214

 
29,580

 
4,079

 
90,290

Nuclear decommissioning liabilities
(43,134
)
 
48,815

 
97,323

 
—

 
—

 
—

 
(62,571
)
Pension and other post-employment benefits
(17,534
)
 
88,606

 
70,055

 
(7,288
)
 
(7,504
)
 
(15,053
)
 
(1,413
)
Sale and leaseback
—

 
—

 
45,136

 
—

 
—

 
—

 
108,172

Accumulated deferred investment tax credit
14,791

 
33,941

 
24,922

 
2,436

 
332

 
5,158

 
18,862

Provision for allowances and contingencies
(7,149
)
 
43,512

 
82,293

 
19,590

 
10,986

 
8,017

 
133

Unbilled/deferred revenues
12,322

 
(18,553
)
 
(6,463
)
 
12,956

 
3,395

 
11,573

 
—

Compensation
2,085

 
641

 
(483
)
 
(846
)
 
475

 
4,155

 
—

Net operating loss carryforwards
105,063

 
—

 
241,803

 
—

 
—

 
—

 
—

Capital losses and miscellaneous tax credits
—

 
—

 
—

 
3,504

 
—

 
—

 
—

Other
258

 
8,102

 
7,406

 
5,887

 
2,891

 
3,850

 
2,000

Total
212,168

 
275,132

 
673,525

 
43,453

 
40,155

 
21,779

 
155,473

Noncurrent accrued taxes (including unrecognized tax benefits)
9,367

 
(388,230
)
 
(24,278
)
 
(12,481
)
 
(19,502
)
 
(48,921
)
 
(81,528
)
Accumulated deferred income taxes and taxes accrued

($1,991,459
)
 

($1,622,127
)
 

($1,331,949
)
 

($795,176
)
 

($190,679
)
 

($1,045,949
)
 

($822,346
)

118
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Entergy Corporation and Subsidiaries
Notes to Financial Statements


2013
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
Entergy
Texas
 
System
Energy
 
 
(In Thousands)
Deferred tax liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Plant basis differences - net
 

($1,613,195
)
 

($1,259,173
)
 

($1,347,534
)
 

($727,545
)
 

($196,726
)
 

($759,263
)
 

($698,151
)
Regulatory assets
 
(212,339
)
 
(102,362
)
 
(255,068
)
 
(33,277
)
 
—

 
(205,402
)
 
(113,849
)
Nuclear decommissioning trusts
 
(110,004
)
 
(32,574
)
 
(50,248
)
 
—

 
—

 
—

 
(58,308
)
Pension, net funding
 
(79,589
)
 
(45,342
)
 
(50,630
)
 
(24,392
)
 
(11,606
)
 
(23,598
)
 
(21,187
)
Deferred fuel
 
(26,946
)
 
(4,361
)
 
(512
)
 
(21,823
)
 
63

 
(470
)
 
(129
)
Power purchase agreements
 
(7,053
)
 
(20,234
)
 
—

 
—

 
13

 
1,269

 
—

Other
 
(62,046
)
 
(25,694
)
 
(69,194
)
 
(10,732
)
 
(13,446
)
 
(58,963
)
 
(8,969
)
Total
 
(2,111,172
)
 
(1,489,740
)
 
(1,773,186
)
 
(817,769
)
 
(221,702
)
 
(1,046,427
)
 
(900,593
)
Deferred tax assets:
 
 

 
 

 
 

 
 

 
 

 
 

 
 

Regulatory liabilities
 
120,966

 
60,176

 
94,019

 
8,357

 
35,764

 
7,952

 
76,135

Nuclear decommissioning liabilities
 
(64,571
)
 
49,439

 
92,206

 
—

 
—

 
—

 
(71,898
)
Pension and other post-employment benefits
 
(12,132
)
 
73,136

 
62,999

 
(1,345
)
 
1,532

 
(13,417
)
 
(2,073
)
Sale and leaseback
 
—

 
—

 
52,054

 
—

 
—

 
—

 
124,065

Accumulated deferred investment tax credit
 
15,281

 
35,297

 
25,913

 
3,263

 
416

 
5,651

 
20,956

Provision for allowances and contingencies
 
12,313

 
14,784

 
3,347

 
13,066

 
8,535

 
5,980

 
—

Unbilled/deferred revenues
 
37,825

 
(22,340
)
 
3,026

 
6,791

 
4,226

 
10,655

 
—

Compensation
 
7,131

 
4,701

 
3,470

 
1,778

 
1,696

 
6,774

 
822

Net operating loss carryforwards
 
85,875

 
—

 
230,592

 
19,400

 
—

 
—

 
—

Capital losses and miscellaneous tax credits
 
—

 
—

 
—

 
6,173

 
—

 
—

 
—

Other
 
3,682

 
4,939

 
4,148

 
4,224

 
2,930

 
3,807

 
2,001

Total
 
206,370

 
220,132

 
571,774

 
61,707

 
55,099

 
27,402

 
150,008

Noncurrent accrued taxes (including unrecognized tax benefits)
 
22,565

 
(279,269
)
 
25,512

 
(6,290
)
 
(5,015
)
 
(37,777
)
 
10,302

Accumulated deferred income taxes and taxes accrued
 

($1,882,237
)
 

($1,548,877
)
 

($1,175,900
)
 

($762,352
)
 

($171,618
)
 

($1,056,802
)
 

($740,283
)


119
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Entergy Corporation and Subsidiaries
Notes to Financial Statements


The Registrant Subsidiaries’ estimated tax attributes carryovers and their expiration dates as of December 31, 2014 are as follows:
 
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Federal net operating losses
 

$1.3
 billion
 

$151
 million
 

$2.1
 billion
 
—
 

$55
 million
 
—
 

$392
 million
Year(s) of expiration
 
2029-2034

 
2029-2032

 
2029-2034

 
N/A
 
2031-2034

 
N/A
 
2030-2032

 
 
 

 
 

 
 

 
 

 
 

 
 

 
 

State net operating losses
 

$235
 million
 

$580
 million
 

$3
 billion
 
—
 

$24
 million
 
—
 
—
Year(s) of expiration
 
2015-2028

 
2024-2027

 
2024-2029

 
N/A
 
2026-2029

 
N/A
 
N/A
 
 
 

 
 

 
 

 
 

 
 

 
 

 
 

Misc. federal credits
 

$1
 million
 

$6
 million
 

$13
 million
 

$1
 million
 
—
 
—
 

$10
 million
Year(s) of expiration
 
2029-2033

 
2029-2033

 
2026-2033

 
2029-2033

 
N/A
 
N/A
 
2029-2033

 
 
 

 
 

 
 

 
 

 
 

 
 

 
 

State credits
 
—
 
—
 
—
 

$9.5
 million
 
—
 

$3.4
 million
 

$15.7
 million
Year(s) of expiration
 
N/A
 
N/A
 
N/A
 
2015-2019

 
N/A
 
2026

 
2015-2019


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:
 
2014
 
2013
 
2012
 
(In Thousands)
Gross balance at January 1

$4,593,224

 

$4,170,403

 

$4,387,780

Additions based on tax positions related to the current year
348,543

 
162,338

 
163,612

Additions for tax positions of prior years
11,637

 
410,108

 
1,517,797

Reductions for tax positions of prior years
(213,401
)
 
(103,360
)
 
(476,873
)
Settlements
—

 
(43,620
)
 
(1,421,913
)
Lapse of statute of limitations
(3,218
)
 
(2,645
)
 
—

Gross balance at December 31
4,736,785

 
4,593,224

 
4,170,403

Offsets to gross unrecognized tax benefits:
 

 
 

 
 

Credit and loss carryovers
(4,295,643
)
 
(4,400,498
)
 
(4,022,535
)
Unrecognized tax benefits net of unused tax attributes and payments (a)

$441,142

 

$192,726

 

$147,868


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


120
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Entergy Corporation and Subsidiaries
Notes to Financial Statements


The balances of unrecognized tax benefits include $516 million, $176 million, and $203 million as of December 31, 2014, 2013, and 2012, 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 $4.221 billion, $4.417 billion, and $3.968 billion as of December 31, 2014, 2013, and 2012, 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, 2014, 2013, and 2012 accrued balance for the possible payment of interest is approximately $127 million, $96.4 million, and $146.3 million, respectively.

A reconciliation of the Registrant Subsidiaries’ beginning and ending amount of unrecognized tax benefits for 2014, 2013, and 2012 is as follows:
 
2014
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
Entergy
Texas
 
System
Energy
 
 
(In Thousands)
Gross balance at January 1, 2014
 

$347,713

 

$465,075

 

$611,605

 

$16,186

 

$51,679

 

$13,017

 

$265,185

Additions based on tax positions related to the current year
 
14,511

 
55,053

 
96,196

 
3,928

 
2,235

 
4,225

 
2,744

Additions for tax positions of prior years
 
1,767

 
5,204

 
1,720

 
319

 
37

 
303

 
566

Reductions for tax positions of prior years
 
(1,079
)
 
(7,995
)
 
(20,929
)
 
(289
)
 
(188
)
 
(267
)
 
(10,253
)
Settlements
 
—

 
—

 
—

 
—

 
—

 
(14
)
 
—

Gross balance at December 31, 2014
 
362,912

 
517,337

 
688,592

 
20,144

 
53,763

 
17,264

 
258,242

Offsets to gross unrecognized tax benefits:
 
 

 
 

 
 

 
 

 
 

 
 

 
 

Loss carryovers
 
(361,043
)
 
(89,448
)
 
(650,540
)
 
(6,992
)
 
(20,735
)
 
(241
)
 
(163,124
)
Unrecognized tax benefits net of unused tax attributes and payments
 

$1,869

 

$427,889

 

$38,052

 

$13,152

 

$33,028

 

$17,023

 

$95,118



121
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Entergy Corporation and Subsidiaries
Notes to Financial Statements


2013
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
Entergy
Texas
 
System
Energy
 
 
(In Thousands)
Gross balance at January 1, 2013
 

$344,669

 

$465,721

 

$536,673

 

$16,841

 

$52,018

 

$13,954

 

$260,346

Additions based on tax positions related to the current year
 
6,427

 
7,276

 
10,611

 
957

 
583

 
2,170

 
4,170

Additions for tax positions of prior years
 
1,228

 
7,189

 
118,025

 
401

 
3,506

 
587

 
8,391

Reductions for tax positions of prior years
 
(3,943
)
 
(15,045
)
 
(38,428
)
 
(1,941
)
 
(962
)
 
(4,186
)
 
(967
)
Settlements
 
(668
)
 
(66
)
 
(15,276
)
 
(72
)
 
(3,466
)
 
492

 
(6,755
)
Gross balance at December 31, 2013
 
347,713

 
465,075

 
611,605

 
16,186

 
51,679

 
13,017

 
265,185

Offsets to gross unrecognized tax benefits:
 
 

 
 

 
 

 
 

 
 

 
 

 
 

Loss carryovers
 
(345,674
)
 
(136,151
)
 
(611,605
)
 
(16,186
)
 
(22,078
)
 
(266
)
 
(225,286
)
Unrecognized tax benefits net of unused tax attributes and payments
 

$2,039

 

$328,924

 

$—

 

$—

 

$29,601

 

$12,751

 

$39,899



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Notes to Financial Statements


2012
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
Entergy
Texas
 
System
Energy
 
 
(In Thousands)
Gross balance at January 1, 2012
 

$335,493

 

$390,493

 

$446,187

 

$11,052

 

$56,052

 

$19,225

 

$281,183

Additions based on tax positions related to the current year
 
10,409

 
8,974

 
67,721

 
8,401

 
497

 
1,656

 
8,715

Additions for tax positions of prior years
 
429,232

 
392,548

 
331,432

 
4,057

 
445

 
4,834

 
271,172

Reductions for tax positions of prior years
 
(39,534
)
 
(50,518
)
 
(169,465
)
 
(5,703
)
 
(2,506
)
 
(11,649
)
 
(20,934
)
Settlements
 
(390,931
)
 
(275,776
)
 
(139,202
)
 
(966
)
 
(2,470
)
 
(112
)
 
(279,790
)
Gross balance at December 31, 2012
 
344,669

 
465,721

 
536,673

 
16,841

 
52,018

 
13,954

 
260,346

Offsets to gross unrecognized tax benefits:
 
 

 
 

 
 

 
 

 
 

 
 

 
 

Loss carryovers
 
(342,127
)
 
(160,955
)
 
(536,673
)
 
(16,841
)
 
(35,511
)
 
(1,593
)
 
(249,424
)
Unrecognized tax benefits net of unused tax attributes and payments
 

$2,542

 

$304,766

 

$—

 

$—

 

$16,507

 

$12,361

 

$10,922


The Registrant Subsidiaries’ balances of unrecognized tax benefits included amounts which, if recognized, would have reduced income tax expense as follows:
 
December 31,
 
2014
 
2013
 
2012
 
(In Millions)
Entergy Arkansas

$2.6

 

$0.6

 

$0.6

Entergy Gulf States Louisiana

$91.9

 

$44.0

 

$44.0

Entergy Louisiana

$175.4

 

$87.9

 

$92.4

Entergy Mississippi

$3.9

 

$3.9

 

$3.9

Entergy New Orleans

$50.7

 

$—

 

$—

Entergy Texas

$10.5

 

$10.1

 

$8.6

System Energy

$3.7

 

$3.3

 

$3.5



123
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Notes to Financial Statements


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,
 
2014
 
2013
 
2012
 
(In Millions)
Entergy Arkansas

$17.0

 

$15.2

 

$21.8

Entergy Gulf States Louisiana

$21.0

 

$17.0

 

$33.1

Entergy Louisiana

$1.2

 

$1.0

 

$0.9

Entergy Mississippi

$2.8

 

$2.1

 

$2.4

Entergy New Orleans

$1.3

 

$0.9

 

$0.1

Entergy Texas

$1.0

 

$0.8

 

$0.7

System Energy

$23.8

 

$19.0

 

$33.2


Income Tax Litigation

In October 2010 the U.S. Tax Court entered a decision in favor of Entergy regarding the ability to credit the U.K. Windfall Tax against U.S. income tax as a foreign tax credit.  The U.K. Windfall Tax relates to Entergy’s former investment in London Electricity.

The IRS filed an appeal of the U.K. Windfall Tax decision with the U.S. Court of Appeals for the Fifth Circuit in December 2010.  Oral arguments were heard in November 2011.  In June 2012 the U.S. Court of Appeals for the Fifth Circuit unanimously affirmed the U.S. Tax Court decision.  As a result of this decision, Entergy reversed its liability for uncertain tax positions associated with this issue.  On September 4, 2012, the U.S. Solicitor General, on behalf of the Commissioner of Internal Revenue, petitioned the U.S. Supreme Court for a writ of certiorari to review the Fifth Circuit judgment.

Concurrent with the Tax Court’s issuance of a favorable decision regarding the above issues, the Tax Court issued a favorable decision in a separate proceeding, PPL Corp. v. Commissioner, regarding the creditability of the U.K. Windfall Tax.  The IRS appealed the PPL decision to the United States Court of Appeals for the Third Circuit.  In December 2011 the Third Circuit reversed the Tax Court’s holding in PPL Corp. v. Commissioner, stating that the U.K. tax was not eligible for the foreign tax credit.  PPL Corp. petitioned the U.S. Supreme Court for a writ of certiorari to review the U.S. Court of Appeals for the Third Circuit decision.  On October 29, 2012, the U.S. Supreme Court granted PPL Corp.’s petition for certiorari.  The Solicitor General’s petition for writ of certiorari in Entergy’s case was held pending the disposition of the PPL case.

    On May 20, 2013, the U.S. Supreme Court issued a unanimous decision in PPL’s favor, holding that the U.K. Windfall Tax is a creditable tax for U.S. federal income tax purposes. On May 28, 2013, the Supreme Court denied the petition for certiorari filed by the Commissioner of Internal Revenue in Entergy’s U.K. Windfall Tax case, allowing the decision in Entergy’s favor from the United States Court of Appeals for the Fifth Circuit to become final.

Income Tax Audits

Entergy and its subsidiaries file U.S. federal and various state and foreign income tax returns.  IRS examinations are substantially completed for years before 2009. All state taxing authorities’ examinations are completed for years before 2005.

2004-2005 IRS Audit

In June 2009, Entergy filed a formal protest with the IRS Appeals Division indicating disagreement with certain issues contained in the 2004-2005 Revenue Agent’s Report (RAR).  The most significant issue disputed was the

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inclusion of nuclear decommissioning liabilities in cost of goods sold for the nuclear power plants owned by the Utility resulting from an Application for Change in Accounting Method for tax purposes (the “2004 CAM”).

During the fourth quarter 2012, Entergy settled the position relating to the 2004 CAM.   Under the settlement Entergy conceded its tax position, resulting in an increase in taxable income of approximately $2.97 billion for the tax years 2004 - 2007.  The settlement provides that Entergy Louisiana is entitled to additional tax depreciation of approximately $547 million for years 2006 and beyond.  The deferred tax asset net of interest charges associated with the settlement is $155 million for Entergy.  There was a related increase to Entergy Louisiana’s member’s equity account.

2008-2009 IRS Audit
 
In the third quarter 2008, Entergy Louisiana and Entergy Gulf States Louisiana received $679 million and $274.7 million, respectively, from the Louisiana Utilities Restoration Corporation (“LURC”).  These receipts from LURC were from the proceeds of a Louisiana Act 55 financing of the costs incurred to restore service following Hurricane Katrina and Hurricane Rita.  See Note 2 to the financial statements for further details regarding the financings.

In June 2012, Entergy effectively settled the tax treatment of the storm restoration, which resulted in an increase to 2008 taxable income of $129 million for Entergy Louisiana and $104 million for Entergy Gulf States Louisiana and a reduction of income tax expense of $172 million, including $143 million for Entergy Louisiana and $20 million for Entergy Gulf States Louisiana. Under the terms of an LPSC-approved settlement related to the Louisiana Act 55 financings, Entergy Louisiana and Entergy Gulf States Louisiana recorded, respectively, a $137 million ($84 million net-of-tax) and a $28 million ($17 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect their obligations to customers with respect to the settlement.  

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 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 disagrees with the IRS’s disallowance of the 2009 CAM and filed a protest with the IRS Appeals Division on October 24, 2013. Two conferences with the Appeals Division have taken place during 2014. The resolution of this issue is in process. The issuance of the RAR by the IRS effectively settled all other issues, which resulted in an adjustment to the provision for uncertain tax positions.

Other Tax Matters

Entergy regularly negotiates with the IRS to achieve settlements.  The resolution of the nuclear decommissioning liability audit issue, discussed above, could result in significant changes to the amounts of unrecognized tax benefits in the next twelve months.

In September 2013 the U.S. Treasury Department and the IRS issued final regulations that provide guidance on the deductibility and capitalization of costs incurred associated with tangible property. Entergy and the Registrant Subsidiaries filed with the IRS an automatic application for change in accounting method which is in compliance with the final regulations and the safe harbor provisions of the relevant IRS Revenue Procedures. Entergy estimates that the effect of this accounting method change will result in a net increase to Entergy’s taxable income of approximately $548 million, which will be recognized over a four year period beginning with the tax year ended 2014. The adoption of the final regulations and safe harbor method results in approximate changes in the Registrant Subsidiaries taxable

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income as follows: an increase of $157 million for Entergy Arkansas, an increase of $42 million for Entergy Gulf States Louisiana, an increase of $49 million for Entergy Louisiana, an increase of $23 million for Entergy Mississippi, an increase of $169 million for Entergy Texas, a decrease of $11 million for Entergy New Orleans, and an increase of $34 million for System Energy.

In March 2013, Entergy Louisiana distributed to its parent, Entergy Louisiana Holdings, Inc., Louisiana income tax credits of $20.6 million, which resulted in a decrease in Entergy Louisiana’s member’s equity account.

The Tax Increase Prevention Act of 2014 was enacted in December 2014. The most significant provisions affecting Entergy and the Registrant Subsidiaries were a one-year extension of 50% bonus depreciation and the research and experimentation tax credit. These provisions do not result in an immediate cash flow benefit but will result in cash flow benefits for Entergy in a future period.


NOTE 4.  REVOLVING CREDIT FACILITIES, LINES OF CREDIT, AND SHORT-TERM BORROWINGS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, 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 March 2019.  Entergy Corporation also has the ability to issue letters of credit against 50% of the total borrowing capacity of the credit facility.  The commitment fee is currently 0.275% 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, 2014 was 1.93% 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, 2014.
 
Capacity (a)
 
 
Borrowings
 
Letters
of Credit
 
Capacity
Available
(In Millions)
$3,500
 
$695
 
$9
 
$2,796

Entergy Corporation’s facility requires it to maintain a consolidated debt ratio 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 $1.5 billion.  At December 31, 2014, Entergy Corporation had $484 million of commercial paper outstanding.  The weighted-average interest rate for the year ended December 31, 2014 was 0.88%.


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Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2014 as follows:
 
 
 
 
 
 
 
 
Amount Drawn
as of
Company
 
Expiration Date
 
Amount of Facility
 
Interest Rate (a)
 
December 31, 2014
Entergy Arkansas
 
April 2015
 
$20 million (b)
 
1.67%
 
—
Entergy Arkansas
 
March 2019
 
$150 million (c)
 
1.67%
 
—
Entergy Gulf States Louisiana
 
March 2019
 
$150 million (d)
 
1.42%
 
—
Entergy Louisiana
 
March 2019
 
$200 million (e)
 
1.42%
 
—
Entergy Mississippi
 
May 2015
 
$10 million (f)
 
1.67%
 
—
Entergy Mississippi
 
May 2015
 
$35 million (f)
 
1.67%
 
—
Entergy Mississippi
 
May 2015
 
$20 million (f)
 
1.67%
 
—
Entergy Mississippi
 
May 2015
 
$37.5 million (f)
 
1.67%
 
—
Entergy New Orleans
 
November 2015
 
$25 million
 
1.92%
 
—
Entergy Texas
 
March 2019
 
$150 million (g)
 
1.67%
 
—

(a)
The interest rate is the rate as of December 31, 2014 that would be 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 allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2014, no letters of credit were outstanding.  
(d)
The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2014, no letters of credit were outstanding.
(e)
The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2014, no letters of credit were outstanding. 
(f)
Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option. 
(g)
The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2014, $1.3 million in letters of credit were outstanding.  

The commitment fees on the credit facilities range from 0.125% to 0.275% of the undrawn commitment amount. Each of the credit facilities requires the Registrant Subsidiary borrower to maintain a debt ratio of 65% or less of its total capitalization. Each Registrant Subsidiary is in compliance with this covenant.


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In addition, Entergy Arkansas, Entergy Gulf States Louisiana, 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 related to MISO. Following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2014:
Company
 
 
Amount of Uncommitted Facility
 
Letter of Credit Fee
 
Letters of Credit Issued as of
December 31, 2014
Entergy Arkansas
 
 
$25 million
 
0.70%
 
$2.0 million
Entergy Gulf States Louisiana
 
 
$75 million
 
0.70%
 
$27.9 million
Entergy Louisiana
 
 
$50 million
 
0.70%
 
$4.7 million
Entergy Mississippi
 
 
$40 million
 
0.70%
 
$14.4 million
Entergy Mississippi
 
 
$40 million
 
1.50%
 
—
Entergy New Orleans
 
 
$15 million
 
0.75%
 
$8.1 million
Entergy Texas
 
 
$50 million
 
0.70%
 
$24.5 million

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, 2015. In addition to borrowings from commercial banks, these companies are authorized under a FERC order to borrow from the Entergy System money pool. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ dependence on external short-term borrowings. Borrowings from the money pool 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, 2014 (aggregating both money pool and external short-term borrowings) for the Registrant Subsidiaries:
 
Authorized
 
Borrowings
 
(In Millions)
Entergy Arkansas
$250
 
—
Entergy Gulf States Louisiana
$200
 
—
Entergy Louisiana
$250
 
—
Entergy Mississippi
$175
 
—
Entergy New Orleans
$100
 
—
Entergy Texas
$200
 
—
System Energy
$200
 
—

Entergy Nuclear Vermont Yankee Credit Facilities

In January 2015, Entergy Nuclear Vermont Yankee entered into a credit facility guaranteed by Entergy Corporation with a borrowing capacity of $60 million which expires in January 2018.  Entergy Nuclear Vermont Yankee does not have the ability to issue letters of credit against this facility. This facility provides working capital to Entergy Nuclear Vermont Yankee for general business purposes including, without limitation, the decommissioning of Entergy Nuclear Vermont Yankee’s nuclear facilities. The commitment fee is currently 0.25% of the undrawn commitment amount.  The weighted average interest rate that would have applied to any outstanding borrowings at the time Entergy Nuclear Vermont Yankee entered into the facility was 1.92% on the drawn portion of the facility.  

         Also in January 2015, Entergy Nuclear Vermont Yankee entered into an uncommitted credit facility guaranteed by Entergy Corporation with a borrowing capacity of $85 million which expires in January 2018.  Entergy Nuclear Vermont Yankee does not have the ability to issue letters of credit against this facility. This facility provides an additional funding source to Entergy Nuclear Vermont Yankee for general business purposes including, without limitation, the decommissioning of Entergy Nuclear Vermont Yankee’s nuclear facilities.  The weighted average interest rate that

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would have applied to any outstanding borrowings at the time Entergy Nuclear Vermont Yankee entered into the facility was 1.92% on the drawn portion of the facility. 

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

See Note 18 to the financial statements for a discussion of the consolidation of the nuclear fuel company variable interest entities (VIE).  The nuclear fuel company variable interest entities have credit facilities and also issue commercial paper to finance the acquisition and ownership of nuclear fuel as follows as of December 31, 2014:
 
 
 
 
 
Company
 
 
 
 
 
Expiration
Date
 
 
 
 
Amount
of
Facility
 
Weighted
Average
Interest
Rate on
Borrowings
(a)
 
 
Amount
Outstanding
as of
December 31,
2014
 
 
(Dollars in Millions)
Entergy Arkansas VIE
 
June 2016
 
$85
 
1.61%
 
$48.0
Entergy Gulf States Louisiana VIE
 
June 2016
 
$100
 
n/a
 
$—
Entergy Louisiana VIE
 
June 2016
 
$90
 
1.54%
 
$46.0
System Energy VIE
 
June 2016
 
$125
 
1.68%
 
$20.4

(a)
Includes letter of credit fees and bank fronting fees on commercial paper issuances by the nuclear fuel company variable interest entities for Entergy Arkansas, Entergy Louisiana, and System Energy.  The nuclear fuel company variable interest entity for Entergy Gulf States Louisiana does not issue commercial paper, but borrows directly on its bank credit facility.

Amounts outstanding on the Entergy Gulf States Louisiana nuclear fuel company variable interest entity’s credit facility, if any, are included in long-term debt on its balance sheet and commercial paper outstanding for the other nuclear fuel company variable interest entities is classified as a current liability on the respective balance sheets.  The commitment fees on the credit facilities are 0.10% of the undrawn commitment amount for the Entergy
Louisiana and Entergy Gulf States Louisiana VIEs and 0.125% of the undrawn commitment amount for the Entergy
Arkansas and System Energy VIEs. Each credit facility requires the respective lessee of nuclear fuel (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, or Entergy Corporation as guarantor for System Energy) to maintain a consolidated debt ratio of 70% or less of its total capitalization.


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The nuclear fuel company variable interest entities had notes payable that are included in debt on the respective balance sheets as of December 31, 2014 as follows:
Company
 
Description
 
Amount
 
 
 
 
 
Entergy Arkansas VIE
 
3.23% Series J due July 2016
 
$55 million
Entergy Arkansas VIE
 
2.62% Series K due December 2017
 
$60 million
Entergy Arkansas VIE
 
3.65% Series L due July 2021
 
$90 million
Entergy Gulf States Louisiana VIE
 
3.25% Series Q due July 2017
 
$75 million
Entergy Gulf States Louisiana VIE
 
3.38% Series R due August 2020
 
$70 million
Entergy Louisiana VIE
 
3.30% Series F due March 2016
 
$20 million
Entergy Louisiana VIE
 
3.25% Series G due July 2017
 
$25 million
Entergy Louisiana VIE
 
3.92% Series H due February 2021
 
$40 million
System Energy VIE
 
5.33% Series G due April 2015
 
$60 million
System Energy VIE
 
4.02% Series H due February 2017
 
$50 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 Gulf States Louisiana, Entergy Louisiana, and System Energy each have obtained long-term financing authorizations from the FERC that extend through October 2015 for issuances by its nuclear fuel company variable interest entity.



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

Long-term debt for Entergy Corporation and subsidiaries as of December 31, 2014 and 2013 consisted of:

 
  Type of Debt and Maturity
 
Weighted
Average Interest
Rate December 31,
2014
 
 
Interest Rate Ranges at
December 31,
 
 
Outstanding at
December 31,
2014
 
2013
 
2014
 
2013
 
 
 
 
 
 
 
 
(In Thousands)
Mortgage Bonds
 
 
 
 
 
 
 
 
 
 
2014-2019
 
6.49%
 
3.25%-7.13%
 
1.88%-7.13%
 

$1,650,000

 

$2,110,000

2020-2024
 
4.18%
 
3.05%-5.60%
 
3.05%-5.60%
 
3,483,303

 
3,008,363

2025-2029
 
4.54%
 
3.78%-5.66%
 
4.44%-5.66%
 
762,859

 
462,914

2032-2039
 
6.16%
 
5.90%-6.38%
 
5.90%-7.88%
 
660,000

 
980,000

2040-2064
 
5.28%
 
4.70%-6.20%
 
4.70%-6.20%
 
2,215,000

 
1,410,000

Governmental Bonds (a)
 
 
 
 
 
 
 
 
 
 
2015-2017
 
1.75%
 
1.55%-2.88%
 
1.55%-2.88%
 
86,655

 
86,655

2021-2022
 
5.31%
 
2.375%-5.88%
 
2.375%-5.88%
 
291,000

 
291,000

2028-2030
 
5.00%
 
5.00%
 
5.00%
 
198,680

 
198,680

Securitization Bonds
 
 
 
 
 
 
 
 
 
 
2016-2023
 
3.88%
 
2.04%-5.93%
 
2.04%-5.93%
 
785,059

 
883,243

Variable Interest Entities Notes Payable (Note 4)
 
 
 
 
 
 
 
 
 
 
2014-2021
 
3.53%
 
2.62%-5.33%
 
1.38%-5.69%
 
630,000

 
634,800

Entergy Corporation Notes
 
 
 
 
 
 
 
 
 
 
due September 2015
 
n/a
 
3.625%
 
3.625%
 
550,000

 
550,000

due January 2017
 
n/a
 
4.70%
 
4.70%
 
500,000

 
500,000

due September 2020
 
n/a
 
5.125%
 
5.125%
 
450,000

 
450,000

Note Payable to NYPA
 
(b)
 
(b)
 
(b)
 
79,638

 
95,011

5 Year Credit Facility (Note 4)
 
n/a
 
1.93%
 
1.96%
 
695,000

 
255,000

Long-term DOE Obligation (c)
 
—
 
—
 
—
 
181,329

 
181,253

Waterford 3 Lease Obligation (d)
 
n/a
 
7.45%
 
7.45%
 
128,488

 
148,716

Grand Gulf Lease Obligation (d)
 
n/a
 
5.13%
 
5.13%
 
50,671

 
97,414

Term Loan - Entergy Arkansas
 
n/a
 
—
 
1.13%
 
—

 
250,000

Unamortized Premium and Discount - Net
 
 
 
 
 
 
 
(12,529
)
 
(11,172
)
Other
 
 
 
 
 
 
 
14,331

 
14,367

Total Long-Term Debt
 
 
 
 
 
 
 
13,399,484

 
12,596,244

Less Amount Due Within One Year
 
 
 
 
 
 
 
899,375

 
457,095

Long-Term Debt Excluding Amount Due Within One Year
 
 
 
 
 
 
 

$12,500,109

 

$12,139,149

Fair Value of Long-Term Debt (e)
 
 
 
 
 
 
 

$13,607,242

 

$12,439,785


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

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(b)
These notes do not have a stated interest rate, but have an implicit interest rate of 4.8%.
(c)
Pursuant to the Nuclear Waste Policy Act of 1982, Entergy’s nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service.  The contracts include a one-time fee for generation prior to April 7, 1983.  Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt.
(d)
See Note 10 to the financial statements for further discussion of the Waterford 3 and Grand Gulf lease obligations.
(e)
The fair value excludes lease obligations of $128 million at Entergy Louisiana and $51 million at System Energy, long-term DOE obligations of $181 million at Entergy Arkansas, and the note payable to NYPA of $80 million at Entergy, and includes debt due within one year.  Fair values are classified as Level 2 in the fair value hierarchy discussed in Note 16 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, 2014, for the next five years are as follows:
 
Amount
 
(In Thousands)
2015

$310,566

2016

$765,821

2017

$266,801

2018

$1,336,396

2019

$1,492,107


In November 2000, Entergy’s non-utility nuclear business purchased the FitzPatrick and Indian Point 3 power plants in a seller-financed transaction.  Entergy issued notes to NYPA with seven annual installments of approximately $108 million commencing one year from the date of the closing, and eight annual installments of $20 million commencing eight years from the date of the closing.  These notes do not have a stated interest rate, but have an implicit interest rate of 4.8%.  In accordance with the purchase agreement with NYPA, the purchase of Indian Point 2 in 2001 resulted in Entergy becoming liable to NYPA for an additional $10 million per year for 10 years, beginning in September 2003.  This liability was recorded upon the purchase of Indian Point 2 in September 2001. In July 2003 a payment of $102 million was made prior to maturity on the note payable to NYPA.  Under a provision in a letter of credit supporting these notes, if certain of the Utility operating companies or System Energy were to default on other indebtedness, Entergy could be required to post collateral to support the letter of credit.

Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through October 2015.  Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2015.  Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through July 2016.

Capital Funds Agreement

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

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

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Long-term debt for the Registrant Subsidiaries as of December 31, 2014 and 2013 consisted of:
 
 
2014
 
2013
 
 
(In Thousands)
Entergy Arkansas
 
 
 
 
Mortgage Bonds:
 
 
 
 
5.0% Series due July 2018
 

$—

 

$115,000

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

 
—

5.66% Series due February 2025
 
175,000

 
175,000

5.9% Series due June 2033
 
100,000

 
100,000

6.38% Series due November 2034
 
60,000

 
60,000

5.75% Series due November 2040
 
225,000

 
225,000

4.95% Series due December 2044
 
250,000

 
—

4.9% Series due December 2052
 
200,000

 
200,000

4.75% Series due June 2063
 
125,000

 
125,000

Total mortgage bonds
 
2,110,000

 
1,600,000

Governmental Bonds (a):
 
 
 
 
1.55% Series due 2017, Jefferson County (d)
 
54,700

 
54,700

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

 
45,000

Total governmental bonds
 
99,700

 
99,700

Variable Interest Entity Notes Payable (Note 4):
 
 
 
 
5.69% Series I due July 2014
 
—

 
70,000

3.23% Series J due July 2016
 
55,000

 
55,000

2.62% Series K due December 2017
 
60,000

 
60,000

3.65% Series L due July 2021
 
90,000

 
—

Total variable interest entity notes payable
 
205,000

 
185,000

Securitization Bonds:
 
 
 
 
2.30% Series Senior Secured due August 2021
 
76,185

 
88,986

Total securitization bonds
 
76,185

 
88,986

Other:
 
 
 
 
Long-term DOE Obligation (b)
 
181,329

 
181,253

Term Loan due January 2015, weighted avg rate 1.13%
 
—

 
250,000

Unamortized Premium and Discount – Net
 
(2,960
)
 
(1,242
)
Other
 
2,089

 
2,105

Total Long-Term Debt
 
2,671,343

 
2,405,802

Less Amount Due Within One Year
 
—

 
70,000

Long-Term Debt Excluding Amount Due Within One Year
 

$2,671,343

 

$2,335,802

Fair Value of Long-Term Debt (c)
 

$2,517,633

 

$2,142,527





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2014
 
2013
 
 
(In Thousands)
Entergy Gulf States Louisiana
 
 
 
 
Mortgage Bonds:
 
 
 
 
6.0% Series due May 2018
 

$375,000

 

$375,000

3.95% Series due October 2020
 
250,000

 
250,000

5.59% Series due October 2024
 
300,000

 
300,000

3.78% Series due April 2025
 
110,000

 
—

6.2% Series due July 2033
 
240,000

 
240,000

6.18% Series due March 2035
 
85,000

 
85,000

Total mortgage bonds
 
1,360,000

 
1,250,000

Governmental Bonds (a):
 
 
 
 
2.875% Series due 2015, Louisiana Public Facilities Authority (d)
 
31,955

 
31,955

5.0% Series due 2028, Louisiana Public Facilities Authority (d)
 
83,680

 
83,680

Total governmental bonds
 
115,635

 
115,635

Variable Interest Entity Notes Payable (Note 4):
 
 
 
 
3.25% Series Q due July 2017
 
75,000

 
75,000

3.38% Series R due August 2020
 
70,000

 
70,000

Credit Facility due June 2016, weighted avg rate 1.38%
 
—

 
14,800

Total variable interest entity notes payable
 
145,000

 
159,800

Other:
 
 
 
 
Unamortized Premium and Discount – Net
 
(1,422
)
 
(1,574
)
Other
 
3,604

 
3,604

Total Long-Term Debt
 
1,622,817

 
1,527,465

Less Amount Due Within One Year
 
31,955

 
—

Long-Term Debt Excluding Amount Due Within One Year
 

$1,590,862

 

$1,527,465

Fair Value of Long-Term Debt (c)
 

$1,743,143

 

$1,631,308



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Notes to Financial Statements


 
 
2014
 
2013
 
 
(In Thousands)
Entergy Louisiana
 
 
 
 
Mortgage Bonds:
 
 
 
 
1.875% Series due December 2014
 

$—

 

$250,000

6.50% Series due September 2018
 
300,000

 
300,000

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

5.40% Series due November 2024
 
400,000

 
400,000

3.78% Series due April 2025
 
190,000

 
—

4.44% Series due January 2026
 
250,000

 
250,000

6.4% Series due October 2034
 
—

 
70,000

6.3% Series due September 2035
 
—

 
100,000

6.0% Series due March 2040
 
150,000

 
150,000

5.875% Series due June 2041
 
150,000

 
150,000

5.0% Series due July 2044
 
170,000

 
—

4.95% Series due January 2045
 
250,000

 
—

5.25% Series due July 2052
 
200,000

 
200,000

4.7% Series due June 2063
 
100,000

 
100,000

Total mortgage bonds
 
2,885,000

 
2,695,000

Governmental Bonds (a):
 
 
 
 
5.0% Series due 2030, Louisiana Public Facilities Authority (d)
 
115,000

 
115,000

Total governmental bonds
 
115,000

 
115,000

Variable Interest Entity Notes Payable (Note 4):
 
 
 
 
5.69% Series E due July 2014
 
—

 
50,000

3.30% Series F due March 2016
 
20,000

 
20,000

3.25% Series G due July 2017
 
25,000

 
25,000

3.92% Series H due February 2021
 
40,000

 
—

Total variable interest entity notes payable
 
85,000

 
95,000

Securitization Bonds:
 
 
 
 
2.04% Series Senior Secured due June 2021
 
143,064

 
164,993

Total securitization bonds
 
143,064

 
164,993

Other:
 
 
 
 
Waterford 3 Lease Obligation 7.45% (Note 10)
 
128,488

 
148,716

Unamortized Premium and Discount - Net
 
(3,719
)
 
(2,962
)
Other
 
3,746

 
3,769

Total Long-Term Debt
 
3,356,579

 
3,219,516

Less Amount Due Within One Year
 
19,525

 
320,231

Long-Term Debt Excluding Amount Due Within One Year
 

$3,337,054

 

$2,899,285

Fair Value of Long-Term Debt (c)
 

$3,447,404

 

$3,148,877



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Notes to Financial Statements


 
 
2014
 
2013
 
 
(In Thousands)
Entergy Mississippi
 
 
 
 
Mortgage Bonds:
 
 
 
 
3.25% Series due June 2016
 

$125,000

 

$125,000

4.95% Series due June 2018
 
—

 
95,000

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

 
—

6.0% Series due November 2032
 
75,000

 
75,000

6.25% Series due April 2034
 
100,000

 
100,000

6.20% Series due April 2040
 
80,000

 
80,000

6.0% Series due May 2051
 
150,000

 
150,000

Total mortgage bonds
 
1,030,000

 
1,025,000

Governmental Bonds (a):
 
 
 
 
4.90% Series due 2022, Independence County (d)
 
30,000

 
30,000

Total governmental bonds
 
30,000

 
30,000

Other:
 
 
 
 
Unamortized Premium and Discount – Net
 
(1,162
)
 
(1,330
)
Total Long-Term Debt
 
1,058,838

 
1,053,670

Less Amount Due Within One Year
 
—

 
—

Long-Term Debt Excluding Amount Due Within One Year
 

$1,058,838

 

$1,053,670

Fair Value of Long-Term Debt (c)
 

$1,102,741

 

$1,067,006


 
 
2014
 
2013
 
 
(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

5.6% Series due September 2024
 
33,303

 
33,363

5.65% Series due September 2029
 
37,859

 
37,914

5.0% Series due December 2052
 
30,000

 
30,000

Total mortgage bonds
 
226,162

 
226,277

Other:
 
 
 
 
Unamortized Premium and Discount – Net
 
(296
)
 
(333
)
Total Long-Term Debt
 
225,866

 
225,944

Less Amount Due Within One Year
 
—

 
—

Long-Term Debt Excluding Amount Due Within One Year
 

$225,866

 

$225,944

Fair Value of Long-Term Debt (c)
 

$226,349

 

$217,692




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Notes to Financial Statements


 
 
2014
 
2013
 
 
(In Thousands)
Entergy Texas
 
 
 
 
Mortgage Bonds:
 
 
 
 
3.60% Series due June 2015
 

$200,000

 

$200,000

7.125% Series due February 2019
 
500,000

 
500,000

4.1% Series due September 2021
 
75,000

 
75,000

7.875% Series due June 2039
 
—

 
150,000

5.625% Series due June 2064
 
135,000

 
—

Total mortgage bonds
 
910,000

 
925,000

Securitization Bonds:
 
 
 
 
2.12% Series Senior Secured, Series A due February 2016
 
13,816

 
54,047

5.79% Series Senior Secured, Series A due October 2018
 
74,194

 
97,414

3.65% Series Senior Secured, Series A due August 2019
 
144,800

 
144,800

5.93% Series Senior Secured, Series A due June 2022
 
114,400

 
114,400

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

 
218,600

Total securitization bonds
 
565,810

 
629,261

Other:
 
 
 
 
Unamortized Premium and Discount - Net
 
(1,769
)
 
(2,211
)
Other
 
4,890

 
4,889

Total Long-Term Debt
 
1,478,931

 
1,556,939

Less Amount Due Within One Year
 
200,000

 
—

Long-Term Debt Excluding Amount Due Within One Year
 

$1,278,931

 

$1,556,939

Fair Value of Long-Term Debt (c)
 

$1,629,124

 

$1,726,623



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Notes to Financial Statements


 
 
2014
 
2013
 
 
(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.
 
216,000

 
216,000

Total governmental bonds
 
216,000

 
216,000

Variable Interest Entity Notes Payable (Note 4):
 
 
 
 
5.33% Series G due April 2015
 
60,000

 
60,000

4.02% Series H due February 2017
 
50,000

 
50,000

3.78% Series I due October 2018
 
85,000

 
85,000

Total variable interest entity notes payable
 
195,000

 
195,000

Other:
 
 
 
 
Grand Gulf Lease Obligation 5.13% (Note 10)
 
50,671

 
97,414

Unamortized Premium and Discount – Net
 
(867
)
 
(981
)
Other
 
2

 
3

Total Long-Term Debt
 
710,806

 
757,436

Less Amount Due Within One Year
 
76,310

 
48,653

Long-Term Debt Excluding Amount Due Within One Year
 

$634,496

 

$708,783

Fair Value of Long-Term Debt (c)
 

$677,475

 

$664,890


(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 $128 million at Entergy Louisiana and $51 million at System Energy and long-term DOE obligations of $181 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 16 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 first mortgage bonds.

The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2014, for the next five years are as follows:
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
2015

$—

 

$31,955

 

$—

 

$—

 

$—

 

$200,000

 

$60,000

2016

$55,000

 

$—

 

$20,000

 

$125,000

 

$—

 

$13,816

 

$—

2017

$114,700

 

$75,000

 

$25,000

 

$—

 

$—

 

$—

 

$50,000

2018

$—

 

$375,000

 

$300,000

 

$—

 

$—

 

$74,194

 

$85,000

2019

$—

 

$—

 

$—

 

$150,000

 

$—

 

$644,800

 

$—



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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% and an expected maturity date of August 2021.  Although the principal amount is not due until the date given above, Entergy Arkansas Restoration Funding expects to make principal payments on the bonds over the next five years in the amount of $13.2 million for 2015, $13.4 million for 2016, $13.8 million for 2017, $14.1 million for 2018, and $14.4 million for 2019.  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 cancelled 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% and an expected maturity date of June 2021.  Although the principal amount is not due until the date given above, Entergy Louisiana Investment Recovery Funding expects to make principal payments on the bonds over the next five years in the amounts of $20.5 million for 2015, $21.6 million for 2016, $21.7 million for 2017, $22.3 million for 2018, and $22.7 million for 2019.  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.


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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
114,400

Total senior secured transition bonds

$329,500


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 five years in the amounts of $24.6 million for 2015, $26 million for 2016, $27.6 million for 2017, $29.2 million for 2018, and $30.9 million for 2019.  All of the scheduled principal payments for 2015-2016 are for Tranche A-2, $23.6 million of the scheduled principal payments for 2017 are for Tranche A-2 and $4 million of the scheduled principal payments for 2017 are for Tranche A-3. All of the scheduled principal payments for 2018-2019 are for Tranche A-3.

With the proceeds, Entergy Gulf States Reconstruction Funding purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds.  The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet.  The creditors of Entergy Texas do not have recourse to the assets or revenues of Entergy Gulf States Reconstruction Funding, including the transition property, and the creditors of Entergy Gulf States Reconstruction Funding do not have recourse to the assets or revenues of Entergy Texas.  Entergy Texas has no payment obligations to Entergy Gulf States Reconstruction Funding except to remit transition charge collections.

Entergy Texas Securitization Bonds - Hurricane Ike and Hurricane Gustav

In September 2009 the PUCT authorized the issuance of securitization bonds to recover $566.4 million of Entergy Texas’s Hurricane Ike and Hurricane Gustav restoration costs, plus carrying costs and transaction costs, offset by insurance proceeds.  In November 2009, Entergy Texas Restoration Funding, LLC (Entergy Texas Restoration Funding), a company wholly-owned and consolidated by Entergy Texas, issued $545.9 million of senior secured transition bonds (securitization bonds), as follows:
 
Amount
 
(In Thousands)
Senior Secured Transition Bonds
 

Tranche A-1 (2.12%) due February 2016

$182,500

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

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

Total senior secured transition bonds

$545,900


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 $41.2 million for 2015, $42.6 million for 2016, $44.1 million for 2017, $45.8 million for 2018, and $47.6 million for 2019.  A total of $13.8 million of the scheduled principal payments for 2015 are for Tranche A-1 and $27.4 million are for Tranche A-2. All

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Notes to Financial Statements


of the scheduled principal payments for 2016-2017 are for Tranche A-2, $30.8 million of the scheduled principal payments for 2018 are for Tranche A-2 and $15 million are for Tranche A-3. All of the scheduled principle payments for 2019 are for Tranche A-3.

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 Gulf States Louisiana, Entergy Louisiana, 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, 2014 and 2013 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
 
 
 
 
 
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
Entergy Corporation
 
 
 
 
 
 
 
(Dollars in Thousands)
Utility:
 
 
 
 
 
 
 
 
 
 
 
 
Preferred Stock or Preferred Membership Interests without sinking fund:
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Arkansas, 4.32%-6.45% Series
 
3,413,500

 
3,413,500

 
3,413,500

 
3,413,500

 

$116,350

 

$116,350

Entergy Gulf States Louisiana, Series A 8.25%
 
100,000

 
100,000

 
100,000

 
100,000

 
10,000

 
10,000

Entergy Louisiana, 6.95% Series (a)
 
1,000,000

 
1,000,000

 
840,000

 
840,000

 
84,000

 
84,000

Entergy Mississippi, 4.36%-6.25% Series
 
1,403,807

 
1,403,807

 
1,403,807

 
1,403,807

 
50,381

 
50,381

Entergy New Orleans, 4.36%-5.56% Series
 
197,798

 
197,798

 
197,798

 
197,798

 
19,780

 
19,780

Total Utility Preferred Stock or Preferred Membership Interests without sinking fund
 
6,115,105

 
6,115,105

 
5,955,105

 
5,955,105

 
280,511

 
280,511

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

 
250,000

 
250,000

 
250,000

 
24,249

 
24,249

Total Subsidiaries’ Preferred Stock without sinking fund
 
6,365,105

 
6,365,105

 
6,205,105

 
6,205,105

 

$304,760

 

$304,760

 

(a)
In 2007, Entergy Louisiana Holdings, an Entergy subsidiary, purchased 160,000 of these shares from the holders.
(b)
Dollar amount outstanding is net of $751 thousand of preferred stock issuance costs.


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Notes to Financial Statements


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, 2014. 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 and membership interests for Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans as of December 31, 2014 and 2013 are presented below.  All series of the Utility operating companies’ preferred stock and membership interests 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.  The dividends received deduction is limited by Internal Revenue Code section 244 for the following preferred stock series: Entergy Arkansas 4.72%, Entergy Mississippi 4.56%, and Entergy New Orleans 4.75%.
 
 
Shares
Authorized
and Outstanding
 
 
 
Call Price per
Share as of
December 31,
 
 
2014
 
2013
 
2014
 
2013
 
2014
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

6.08% Series
 
100,000

 
100,000

 
10,000

 
10,000

 

$102.83

Cumulative, $25 par value:
 
 
 
 
 
 
 
 
 
 
6.45% Series
 
3,000,000

 
3,000,000

 
75,000

 
75,000

 

$25

Total without sinking fund
 
3,413,500

 
3,413,500

 

$116,350

 

$116,350

 
 

 
 
Units
Authorized
and Outstanding
 
 
 
Call Price per
Unit as of
December 31,
 
 
2014
 
2013
 
2014
 
2013
 
2014
Entergy Gulf States Louisiana
Preferred Membership Interests
 
 
 
 
 
(Dollars in Thousands)
 
 
Without sinking fund:
 
 
 
 
 
 
 
 
 
 
Cumulative, $100 liquidation value:
 
 
 
 
 
 
 
 
 
 
8.25% Series (a)
 
100,000

 
100,000

 

$10,000

 

$10,000

 

$—

Total without sinking fund
 
100,000

 
100,000

 

$10,000

 

$10,000

 
 


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Notes to Financial Statements


 
 
Units
Authorized
and Outstanding
 
 
 
Call Price per
Unit as of
December 31,
 
 
2014
 
2013
 
2014
 
2013
 
2014
Entergy Louisiana Preferred Membership Interests
 
 
 
 
 
(Dollars in Thousands)
 
 
Without sinking fund:
 
 
 
 
 
 
 
 
 
 
Cumulative, $100 liquidation value:
 
 
 
 
 
 
 
 
 
 
6.95% Series
 
1,000,000

 
1,000,000

 

$100,000

 

$100,000

 

$100

Total without sinking fund
 
1,000,000

 
1,000,000

 

$100,000

 

$100,000

 
 

 
 
Shares
Authorized
and Outstanding
 
 
 
Call Price per
Share as of
December 31,
 
 
2014
 
2013
 
2014
 
2013
 
2014
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

Cumulative, $25 par value
 
 
 
 
 
 
 
 
 
 
6.25% Series
 
1,200,000

 
1,200,000

 
30,000

 
30,000

 

$25

Total without sinking fund
 
1,403,807

 
1,403,807

 

$50,381

 

$50,381

 
 

 
 
Shares
Authorized
and Outstanding
 
 
 
Call Price per
Share as of
December 31,
 
 
2014
 
2013
 
2014
 
2013
 
2014
Entergy New Orleans Preferred Stock
 
 
 
 
 
(Dollars in Thousands)
 
 
Without sinking fund:
 
 
 
 
 
 
 
 
 
 
Cumulative, $100 par value:
 
 
 
 
 
 
 
 
 
 
4.36% Series
 
60,000

 
60,000

 

$6,000

 

$6,000

 

$104.58

4.75% Series
 
77,798

 
77,798

 
7,780

 
7,780

 

$105.00

5.56% Series
 
60,000

 
60,000

 
6,000

 
6,000

 

$102.59

Total without sinking fund
 
197,798

 
197,798

 

$19,780

 

$19,780

 
 

(a)
Series is callable at par on and after December 15, 2015.



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

Common Stock

Common stock and treasury stock shares activity for Entergy for 2014, 2013, and 2012 is as follows:
 
2014
 
2013
 
2012
 
Common
Shares
Issued
 

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

 
76,381,936

 
254,752,788

 
76,945,239

 
254,752,788

 
78,396,988

Repurchases
—

 
2,154,490

 
—

 
—

 
—

 
—

Issuances:
 

 
 

 
 

 
 

 
 

 
 

Employee Stock-Based Compensation Plans
—

 
(3,019,475
)
 
—

 
(557,734
)
 
—

 
(1,446,305
)
Directors’ Plan
—

 
(4,872
)
 
—

 
(5,569
)
 
—

 
(5,444
)
Ending Balance, December 31
254,752,788

 
75,512,079

 
254,752,788

 
76,381,936

 
254,752,788

 
76,945,239


Entergy Corporation reissues treasury shares to meet the requirements of the Stock Plan for Outside Directors (Directors’ Plan), two Equity Ownership Plans of Entergy Corporation and Subsidiaries, the Equity Awards Plan 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, 2014, $350 million of authority remains under the $500 million share repurchase program.

Dividends declared per common share were $3.32 in 2014, 2013, and 2012.

Retained Earnings and Dividend Restrictions

Provisions within the articles of incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of certain of Entergy Corporation’s subsidiaries could restrict the payment of cash dividends or other distributions on their common and preferred equity.  As of December 31, 2014, under provisions in their mortgage indentures, Entergy Arkansas and Entergy Mississippi had retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively.  Entergy Corporation received dividend payments from subsidiaries totaling $893 million in 2014, $702 million in 2013, and $439 million in 2012.


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Comprehensive Income

Accumulated other comprehensive income (loss) is included in the equity section of the balance sheets of Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana. The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 2014 by component:
 
Cash flow
hedges
net
unrealized
gain (loss)
 
Pension
and
other
postretirement
liabilities
 

Net
unrealized
investment
gains (loss)
 
Foreign
currency
translation
 
Total
Accumulated
Other
Comprehensive
Income (Loss)
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
Beginning balance, December 31, 2013

($81,777
)
 

($288,223
)
 

$337,256

 

$3,420

 

($29,324
)
Other comprehensive income (loss) before reclassifications
52,433

 
(278,361
)
 
99,900

 
(751
)
 
(126,779
)
Amounts reclassified from accumulated other comprehensive income (loss)
127,462

 
(3,205
)
 
(10,461
)
 
—

 
113,796

Net other comprehensive income (loss) for the period
179,895

 
(281,566
)
 
89,439

 
(751
)
 
(12,983
)
Ending balance, December 31, 2014

$98,118

 

($569,789
)
 

$426,695

 

$2,669

 

($42,307
)

The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 2013 by component:
 
Cash flow
hedges
net
unrealized
gain (loss)
 
Pension
and
other
postretirement
liabilities
 

Net
unrealized
investment
gains (loss)
 
Foreign
currency
translation
 
Total
Accumulated
Other
Comprehensive
Income (Loss)
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
Beginning balance, December 31, 2012

$79,905



($590,712
)


$214,547



$3,177

 

($293,083
)
Other comprehensive income (loss) before reclassifications
(133,312
)
 
260,567

 
143,936

 
243

 
271,434

Amounts reclassified from
accumulated other comprehensive
income (loss)
(28,370
)
 
41,922

 
(21,227
)
 
—

 
(7,675
)
Net other comprehensive income (loss) for the period
(161,682
)
 
302,489

 
122,709

 
243

 
263,759

Ending balance, December 31, 2013

($81,777
)
 

($288,223
)
 

$337,256

 

$3,420

 

($29,324
)


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The following table presents changes in accumulated other comprehensive income (loss) for Entergy Gulf States Louisiana and Entergy Louisiana for the year ended December 31, 2014:
 
 
Pension and Other
Postretirement Liabilities
 
 
Entergy
Gulf States
Louisiana
 

Entergy
Louisiana
 
 
(In Thousands)
 
 
 
 
 
Beginning balance, December 31, 2013
 

($28,202
)
 

($9,635
)
Other comprehensive income (loss) before reclassifications
 
(25,677
)
 
(15,078
)
Amounts reclassified from accumulated other
comprehensive income (loss)
 
532

 
(1,163
)
Net other comprehensive income (loss) for the period
 
(25,145
)
 
(16,241
)
Ending balance, December 31, 2014
 

($53,347
)
 

($25,876
)

The following table presents changes in accumulated other comprehensive income (loss) for Entergy Gulf States Louisiana and Entergy Louisiana for the year ended December 31, 2013:


Pension and Other
Postretirement Liabilities
 
 
Entergy
Gulf States
Louisiana
 

Entergy
Louisiana


(In Thousands)
 
 
 
 
 
Beginning balance, December 31, 2012
 

($65,229
)
 

($46,132
)
Other comprehensive income (loss) before reclassifications
 
33,233

 
33,869

Amounts reclassified from accumulated other
comprehensive income (loss)
 
3,794

 
2,628

Net other comprehensive income (loss) for the period
 
37,027

 
36,497

Ending balance, December 31, 2013
 

($28,202
)
 

($9,635
)


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Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy for the year ended December 31, 2014 are as follows:
 
 
Amounts
reclassified
from
AOCI
 
Income Statement Location
 
 
(In Thousands)
 
 
 
 
 
 
 
Cash flow hedges net unrealized gain (loss)
 
 
 
 
Power contracts
 

($193,297
)
 
Competitive business operating revenues
Interest rate swaps
 
(2,799
)
 
Miscellaneous - net
Total realized gain (loss) on cash flow hedges
 
(196,096
)
 
 
 
 
68,634

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

($127,462
)
 
 
 
 
 
 
 
Pension and other postretirement liabilities
 
 

 
 
Amortization of prior-service costs
 

$20,294

 
(a)
Amortization of loss
 
(35,836
)
 
(a)
Settlement loss
 
(3,643
)
 
(a)
Total amortization
 
(19,185
)
 
 
 
 
22,390

 
Income taxes
Total amortization (net of tax)
 

$3,205

 
 
 
 
 
 
 
Net unrealized investment gain (loss)
 
 
 
 
Realized gain (loss)
 

$20,511

 
Interest and investment income
 
 
(10,050
)
 
Income taxes
Total realized investment gain (loss) (net of tax)
 

$10,461

 
 
 
 
 
 
 
Total reclassifications for the period (net of tax)
 

($113,796
)
 
 

(a)
These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension 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 for the year ended December 31, 2013 are as follows:

 
Amounts
reclassified
from
AOCI
 
Income Statement Location

 
(In Thousands)
 
 





Cash flow hedges net unrealized gain (loss)
 

 

Power contracts


$47,019


Competitive business operating revenues
Interest rate swaps

(1,565
)

Miscellaneous - net
Total realized gain (loss) on cash flow hedges

45,454





(17,084
)

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


$28,370








Pension and other postretirement liabilities
 
 

 

Amortization of prior-service costs
 

$10,556

 
(a)
Acceleration of prior-service cost due to curtailment
 
315

 
(a)
Amortization of loss

(68,130
)

(a)
Settlement loss

(11,612
)

(a)
Total amortization

(68,871
)




26,949


Income taxes
Total amortization (net of tax)


($41,922
)







Net unrealized investment gain (loss)




Realized gain (loss)


$41,622


Interest and investment income


(20,395
)

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


$21,227








Total reclassifications for the period (net of tax)
 

$7,675

 


(a)
These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension 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 Gulf States Louisiana and Entergy Louisiana for the year ended December 31, 2014 are as follows:
 
 
Amounts reclassified
from AOCI
 
 
 
 
Entergy
Gulf States
Louisiana
 

Entergy
Louisiana
 
Income Statement Location
 
 
(In Thousands)
 
 
 
 
 
 
 
 
 
Pension and other postretirement liabilities
 
 
 
 
 
 
Amortization of prior-service costs
 

$2,237

 

$3,377

 
(a)
Amortization of loss
 
(3,126
)
 
(1,511
)
 
(a)
Total amortization
 
(889
)
 
1,866

 
 
 
 
357

 
(703
)
 
Income tax expense (benefit)
Total amortization (net of tax)
 
(532
)
 
1,163

 
 
 
 
 
 
 
 
 
Total reclassifications for the period (net of tax)
 

($532
)
 

$1,163

 
 

(a)
These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension cost. See Note 11 to the financial statements for additional details.

Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy Gulf States Louisiana and Entergy Louisiana for the year ended December 31, 2013 are as follows:


Amounts reclassified
from AOCI



 
Entergy
Gulf States
Louisiana
 

Entergy
Louisiana
 
Income Statement Location

 
(In Thousands)
 
 







Pension and other postretirement liabilities
 



 

Amortization of prior-service costs
 

$941

 

$508

 
(a)
Acceleration of prior-service cost due to curtailment
 
91

 
41

 
(a)
Amortization of loss
 
(7,644
)
 
(5,050
)
 
(a)
Total amortization

(6,612
)

(4,501
)




2,818

 
1,873


Income taxes
Total amortization (net of tax)

(3,794
)

(2,628
)









Total reclassifications for the period (net of tax)
 

($3,794
)
 

($2,628
)
 


(a)
These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension cost. See Note 11 to the financial statements for additional details.



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NOTE 8.    COMMITMENTS AND CONTINGENCIES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, 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 $152.8 million in 2014, $181.1 million in 2013, and $125.0 million in 2012.  If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $148.5 million in 2015, and a total of $2.06 billion for the years 2016 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 addition, in accordance with an LPSC settlement, Entergy Louisiana credited rates in August 2007 by $11.3 million (including interest) as a result of a settlement with the IRS of the 2001 tax treatment of the Vidalia contract.  In August 2011, Entergy agreed to a settlement with the IRS regarding the mark-to-market income tax treatment of various wholesale electric power purchase and sale contracts, including the Vidalia contract.  The agreement with the IRS effectively settled the tax treatment of such contracts which allowed Entergy Louisiana to propose a final settlement with the LPSC regarding Entergy Louisiana’s obligation to customers related to the Vidalia contract. In October 2011 the LPSC approved a final settlement under which Entergy Louisiana agreed to provide credits to the fuel adjustment clause resulting from the IRS settlement 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.  Entergy Louisiana’s use of the cash benefit of the proceeds is not reflected in rate base for ratemaking purposes.

ANO Damage, Outage, and NRC Reviews

On March 31, 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 turbine building serves both ANO 1 and 2 and is a non-radiological area of the plant. ANO 2 reconnected to the grid on April 28, 2013 and ANO 1 reconnected to the grid on August 7, 2013.  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.  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.

Entergy Arkansas is pursuing its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. Entergy is a member of Nuclear Electric Insurance Limited (NEIL), a mutual

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insurance company that provides property damage coverage to the members’ nuclear generating plants, including ANO. NEIL has notified Entergy that it believes that a $50 million course of construction sublimit applies to any loss associated with the lifting apparatus failure and stator drop at ANO. Entergy has responded that it disagrees with NEIL’s position and is evaluating its options for enforcing its rights under the policy. During 2014, Entergy Arkansas collected $50 million from NEIL. On July 12, 2013, Entergy Arkansas filed a complaint in the Circuit Court in Pope County, Arkansas against the owner of the heavy-lifting apparatus that collapsed, an engineering firm, a contractor, and certain individuals asserting claims of breach of contract, negligence, and gross negligence in connection with their responsibility for the stator drop.

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 May 2014 the NRC met with Entergy during a regulatory conference to discuss the preliminary red and yellow findings and Entergy’s response to the findings. During the regulatory conference, Entergy presented information on the facts and assumptions the NRC used to assess the potential findings. The NRC used the information provided by Entergy at the regulatory conference to finalize its decision regarding the inspection team’s findings. In a letter dated June 23, 2014, the NRC classified both findings as “yellow with substantial safety significance.” In an assessment follow-up letter for ANO dated July 29, 2014, the NRC stated that given the two yellow findings, it determined that the performance at ANO is in the “degraded cornerstone column,” or column 3, of the NRC’s reactor oversight process action matrix beginning the first quarter 2014. Corrective actions in response to the NRC’s findings have been taken and remain ongoing at ANO. The NRC plans to conduct supplemental inspection activity to review the actions taken to address the yellow findings. Entergy will continue to interact with the NRC to address the NRC’s findings.    

In September 2014 the NRC issued an inspection report on the flood barrier effectiveness issue that was still under review at the time of the March 2014 inspection report. While Entergy believes that the flood barrier issues that led to the finding have been addressed at ANO, NRC processes still required that the NRC assess the safety significance of the deficiencies. In its September 2014 inspection report, the NRC discussed a preliminary finding of “yellow with substantial safety significance” for the Unit 1 and Unit 2 auxiliary and emergency diesel fuel storage buildings.  The NRC indicated that these preliminary findings may warrant additional regulatory oversight.  Entergy requested a public regulatory conference regarding the inspection, and the conference was held on October 28, 2014. During the regulatory conference, Entergy presented information related to the facts and assumptions used by the NRC in arriving at its preliminary finding of “yellow with substantial safety significance.” In January 2015 the NRC issued its final risk significance determination for the flood barrier violation originally cited in the September 2014 report. The NRC’s final risk significance determination was classified as “yellow with substantial safety significance.”

The NRC’s January 2015 letter did not advise ANO of the additional level of oversight that will result from the yellow finding related to the flood barrier issue, and it stated that the NRC would inform ANO of this decision by separate correspondence. The yellow finding may result in ANO being placed into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. Placement into this column would require significant additional NRC inspection activities at the ANO site, including a review of the site’s root cause evaluation associated with the flood barrier 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. The additional NRC inspection activities at the site are expected to increase ANO’s operating costs.


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Baxter Wilson Plant Event

On September 11, 2013, Entergy Mississippi’s Baxter Wilson (Unit 1) power plant experienced a significant unplanned outage event.  Entergy Mississippi completed the repairs to the unit in December 2014. As of December 31, 2014, Entergy Mississippi incurred $22.3 million of capital spending and $26.6 million of operation and maintenance expenses to return the unit to service. The damage was covered by Entergy Mississippi’s property insurance policy, subject to a $20 million deductible. As of December 31, 2014, Entergy Mississippi recorded an insurance receivable of $28.2 million for the amount expected to be received from its insurance policy, allocating $12.9 million of the expected insurance proceeds to capital spending and $15.3 million to operation and maintenance expenses. In June 2014, Entergy Mississippi filed a rate case with the MPSC, which includes recovery of the costs associated with Baxter Wilson (Unit 1) repair activities, net of applicable insurance proceeds. In December 2014 the MPSC issued an order that provided for a deferral of $6 million in other operation and maintenance expenses associated with the Baxter Wilson outage and that the regulatory asset should accrue carrying costs, with amortization of the regulatory asset to occur over two years beginning in February 2015, and provided that the capital costs will be reflected in rate base. The final accounting of costs to return the unit to service and insurance proceeds will be addressed in Entergy Mississippi’s next formula rate plan filing.

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 $375 million.  If this amount is not sufficient to cover claims arising from an accident, the second level, Secondary Financial Protection, applies.
2.
Within the Secondary Financial Protection level, each nuclear reactor has a contingent obligation to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary level, regardless of proximity to the incident or fault, up to a maximum of $127.3 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.4 billion).  This consists of a $121.3 million maximum retrospective premium plus a five percent surcharge, which equates to $127.3 million, that may be payable, if needed, at a rate that is currently set at $19.0 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 $13.6 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. The Terrorism Risk Insurance Reauthorization Act of 2007 expired on December 31, 2014. However, The Terrorism Risk Insurance Reauthorization Act of 2015 was signed into law by the President of the United States on January 12, 2015 thereby extending the Terrorism Risk Insurance Act for six years until December 31, 2020.

Currently, 104 nuclear reactors are participating in the Secondary Financial Protection program.  The product of the maximum retrospective premium assessment to the nuclear power industry and the number of nuclear power reactors provides over $13.2 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.


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Entergy Arkansas has two licensed reactors and Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy each have one licensed reactor (10% of Grand Gulf is owned by a non-affiliated company (SMEPA) 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.  Effective April 1, 2014, Entergy was insured against such losses per the following structures:

Utility Plants (ANO 1 and 2, Grand Gulf, River Bend, and Waterford 3)
•
Primary Layer (per plant) - $1.5 billion per occurrence
•
Blanket Excess Layer (shared among the Utility plants) - $100 million per occurrence
•
Total limit - $1.6 billion per occurrence
•
Deductibles:
•
$2.5 million per occurrence - Turbine/generator damage
•
$2.5 million per occurrence - Other than turbine/generator damage
•
$10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption

Note:  ANO 1 and 2 share in the primary and blanket excess layers with common policies because the policies are issued on a per site basis. Flood and earthquake coverage are excluded from the primary layer’s first $500 million in coverage. Entergy currently purchases flood coverage at Waterford 3 and River Bend for the primary layer’s first $500 million in coverage.

Entergy Wholesale Commodities Plants (FitzPatrick, Pilgrim, and Palisades)
•
Primary Layer (per plant) - $1.115 billion per occurrence
•
Total limit (per plant) - $1.115 billion per occurrence
•
Deductibles:
•
$2.5 million per occurrence - Turbine/generator damage
•
$2.5 million per occurrence - Other than turbine/generator damage
•
$10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption

Note:  Flood and earthquake coverage are excluded from the primary layer’s first $500 million in coverage. Entergy currently purchases flood and earthquake coverage at Palisades for the primary layer’s first $500 million in coverage.

Entergy Wholesale Commodities Plant (Indian Point)
•
Primary Layer (per plant) - $1.5 billion per occurrence
•
Excess Layer - $100 million per occurrence
•
Total limit - $1.6 billion per occurrence
•
Deductibles:
•
$2.5 million per occurrence - Turbine/generator damage
•
$2.5 million per occurrence - Other than turbine/generator damage
•
$10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption
    
Note: The Indian Point Units share in the primary and excess layers with common policies because the policies are issued on a per site basis. Flood and earthquake coverage are excluded from the primary layer’s first $500 million

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in coverage. Entergy currently purchases flood coverage at Indian Point for the primary layer’s first $500 million in coverage.

Entergy Wholesale Commodities Plant (Vermont Yankee)
•
Primary Layer (per plant) - $1.06 billion per occurrence
•
Total limit - $1.06 billion per occurrence
•
Deductibles:
•
$2.5 million per occurrence - Turbine/generator damage
•
$2.5 million per occurrence - Other than turbine/generator damage
•
$10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption
    
Note: Flood and earthquake coverage are excluded from the primary layer’s first $500 million in coverage. Entergy currently purchases flood and earthquake coverage at Vermont Yankee for the primary layer’s first $500 million in coverage.

Entergy Wholesale Commodities Plant (Big Rock Point)
•
Primary Layer (per plant) - $500 million per occurrence
•
Total limit - $500 million per occurrence
    
Note: Flood and earthquake coverage are excluded from the primary layer’s first $500 million in coverage. Entergy currently purchases flood and earthquake coverage at Big Rock Point for the primary layer’s first $500 million in coverage.

In addition, Waterford 3, Grand Gulf, and the Entergy Wholesale Commodities plants, with the exception of Vermont Yankee, are also covered under NEIL’s Accidental Outage Coverage program.  Due to the shutdown of the Vermont Yankee Nuclear Power Plant in December 2014, and the required 12 week deductible waiting period for the accidental outage coverage to take effect, accidental outage coverage was removed effective October 1, 2014. This coverage provides certain fixed indemnities in the event of an unplanned outage that results from a covered NEIL primary property damage loss, subject to a deductible period.  The payout for damage resulting from non-nuclear events is limited to a $327.6 million per occurrence sub-limit. The following summarizes this coverage effective October 1, 2014:

Waterford 3
•
$2.95 million weekly indemnity
•
$413 million maximum indemnity
•
Deductible: 26 week deductible period

Grand Gulf
•
$400,000 weekly indemnity (total for four policies)
•
$56 million maximum indemnity (total for four policies)
•
Deductible: 26 week deductible period 

Indian Point 2, Indian Point 3, and Palisades
•
$4.5 million weekly indemnity
•
$490 million maximum indemnity
•
Deductible: 12 week deductible period

FitzPatrick and Pilgrim
•
$4 million weekly indemnity
•
$490 million maximum indemnity
•
Deductible: 12 week deductible period

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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, 2014, the maximum amounts of such possible assessments per occurrence were as follows:
 
Assessments
 
(In Millions)
Utility:
 
Entergy Arkansas
$32.2
Entergy Gulf States Louisiana
$25.5
Entergy Louisiana
$26.1
Entergy Mississippi
$0.09
Entergy New Orleans
$0.09
Entergy Texas
N/A
System Energy
$21.5
 
 
Entergy Wholesale Commodities
$—

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

Entergy maintains property insurance for its nuclear units in excess of the NRC’s minimum requirement of $1.06 billion per site for nuclear power plant licensees.  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 of $3.24 billion plus the additional amounts recovered for such losses from reinsurance, indemnity, and any other sources applicable to such losses.  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. The Terrorism Risk Insurance Reauthorization Act of 2007 expired on December 31, 2014. However, The Terrorism Risk Insurance Reauthorization Act of 2015 was signed into law by the President of the United States on January 12, 2015 thereby extending the Terrorism Risk Insurance Act for six years until December 31, 2020.

Conventional Property Insurance

Entergy’s conventional property insurance program provides coverage of up to $400 million on an Entergy system-wide basis for all operational perils (direct physical loss or damage due to machinery breakdown, electrical failure, fire, lightning, hail, or explosion) on an “each and every loss” basis; up to $400 million in coverage for certain natural perils (direct physical loss or damage due to earthquake, tsunami, and flood) on an annual aggregate basis; up to $125 million for certain other natural perils (direct physical loss or damage due to a named windstorm and associated storm surge) on an annual aggregate basis; and up to $400 million in coverage for all other natural perils not previously stated (direct physical loss or damage due to a tornado, ice storm, or any other natural peril except named windstorm and associated storm surge, earthquake, tsunami, and flood) on an “each and every loss” basis.  The conventional property insurance program provides up to $50 million in coverage for the Entergy New Orleans gas distribution system on an “each and every loss” basis.  This $50 million limit is subject to: the $400 million annual aggregate limit for the natural perils of earthquake, tsunami, and flood; the $125 million annual aggregate limit for the natural perils of named windstorm and associated storm surge.  The coverage is subject to a $40 million self-insured retention per occurrence for the natural perils of named windstorm and associated storm surge, earthquake, flood, and tsunami; and a $20 million

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self-insured retention per occurrence for operational perils and all other natural perils not previously stated, which includes tornado and ice storm, but excludes named windstorm and associated storm surge, earthquake, tsunami, and flood.

Covered property generally includes power plants, substations, facilities, inventories, and gas distribution-related properties.  Excluded property generally includes above-ground 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. The Terrorism Risk Insurance Reauthorization Act of 2007 expired on December 31, 2014. However, The Terrorism Risk Insurance Reauthorization Act of 2015 was signed into law by the President of the United States on January 12, 2015 thereby extending the Terrorism Risk Insurance Act for six years until December 31, 2020.

In addition to the conventional property insurance program, Entergy has purchased additional coverage ($20 million per occurrence) for some of its non-regulated, non-generation assets.  This policy serves to buy-down the $20 million deductible and is placed on a scheduled location basis.  The applicable deductibles are $100,000 to $250,000, except for properties that are damaged by flooding and properties whose values are greater than $20 million; these properties have a $500,000 deductible.  Four nuclear locations have a $2.5 million deductible, which coincides with the nuclear property insurance deductible at each respective nuclear site.

Gas System Rebuild Insurance Proceeds (Entergy New Orleans)

Entergy New Orleans received insurance proceeds for future construction expenditures associated with rebuilding its gas system, and the October 2006 City Council resolution approving the settlement of Entergy New Orleans’s rate and storm-cost recovery filings requires Entergy New Orleans to record those proceeds in a designated sub-account of other deferred credits until the proceeds are spent on the rebuild project.  This other deferred credit is shown as “Gas system rebuild insurance proceeds” on Entergy New Orleans’s balance sheet.

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.


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Asbestos Litigation (Entergy Gulf States Louisiana, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)

Numerous lawsuits have been filed in federal and state courts primarily in Texas and Louisiana, primarily by contractor employees who worked in the 1940-1980s timeframe, against Entergy Gulf States Louisiana and 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 400 lawsuits involving approximately 4,000 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.  Monthly obligations are based on actual capacity and energy costs.  The average monthly payments for 2014 under the agreement are approximately $20.2 million for Entergy Arkansas, $8.0 million for Entergy Louisiana, $17.4 million for Entergy Mississippi, and $9.8 million for Entergy New Orleans.

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

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Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments.

Reallocation Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans entered into the Reallocation Agreement relating to the sale of capacity and energy from Grand Gulf and the related costs, in which Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans agreed to assume all of Entergy Arkansas’s responsibilities and obligations with respect to Grand Gulf under the Availability Agreement.  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.

Reimbursement Agreement (System Energy)

In December 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.  During the term of the leases, System Energy is required to maintain letters of credit for the equity investors to secure certain amounts payable to the equity investors under the transactions.

Under the provisions of the reimbursement agreement relating to the letters of credit, System Energy has agreed to a number of covenants regarding the maintenance of certain capitalization and fixed charge coverage ratios.  System Energy agreed, during the term of the reimbursement agreement, to maintain a ratio of debt to total liabilities and equity less than or equal to 70%.  In addition, System Energy must maintain, with respect to each fiscal quarter during the term of the reimbursement agreement, a ratio of adjusted net income to interest expense of at least 1.50 times earnings.  As of December 31, 2014, System Energy was in compliance with these covenants.


NOTE 9.   ASSET RETIREMENT OBLIGATIONS  (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, 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

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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,
 
2014
 
2013
 
(In Millions)
Entergy Arkansas
$59.0
 
$18.6
Entergy Gulf States Louisiana
($36.9)
 
($35.3)
Entergy Louisiana
($45.7)
 
($37.0)
Entergy Mississippi
$76.3
 
$64.3
Entergy New Orleans
$35.2
 
$34.9
Entergy Texas
$18.9
 
$15.1
System Energy
$55.7
 
$56.0

The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2014 by Entergy were as follows:
 
Liabilities as
of December 31,
2013
 
 
 
Accretion
 
Change in
Cash Flow
Estimate
 
 
 
Spending
 
Liabilities as
 of December 31,
2014
 
(In Millions)
Utility:
 
 
 
 
 
 
 
 
 
Entergy Arkansas
$723.8
 

$47.0

 

$47.6

 

$—

 

$818.4

Entergy Gulf States Louisiana
$403.1
 

$23.5

 

$20.0

 

$—

 

$446.6

Entergy Louisiana
$479.1
 

$24.6

 

$—

 

$—

 

$503.7

Entergy Mississippi
$6.4
 

$0.4

 

$—

 

$—

 

$6.8

Entergy New Orleans
$2.3
 

$0.2

 

$—

 

$—

 

$2.5

Entergy Texas
$4.3
 

$0.3

 

$—

 

$—

 

$4.6

System Energy
$616.2
 

$41.8

 

$99.9

 

$—

 

$757.9

Entergy Wholesale Commodities
$1,698.2
 

$139.7

 

$101.6

 

($21.7
)
 

$1,917.8



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The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2013 by Entergy were as follows:
 
Liabilities as
of December 31,
2012
 
 
 
Accretion
 
Change in
Cash Flow
Estimate
 
 
 
Spending
 
Liabilities as
 of December 31,
2013
 
(In Millions)
Utility:
 
 
 
 
 
 
 
 
 
Entergy Arkansas

$680.7

 

$43.1

 

$—

 

$—

 

$723.8

Entergy Gulf States Louisiana

$380.8

 

$22.3

 

$—

 

$—

 

$403.1

Entergy Louisiana

$418.1

 

$21.6

 

$39.4

 

$—

 

$479.1

Entergy Mississippi

$6.0

 

$0.4

 

$—

 

$—

 

$6.4

Entergy New Orleans

$2.2

 

$0.1

 

$—

 

$—

 

$2.3

Entergy Texas

$4.1

 

$0.2

 

$—

 

$—

 

$4.3

System Energy

$478.4

 

$35.5

 

$102.3

 

$—

 

$616.2

Entergy Wholesale Commodities

$1,543.3

 

$125.3

 

$38.6

 

($9.0
)
 

$1,698.2


Entergy periodically reviews and updates estimated decommissioning costs.  The actual decommissioning costs may vary from the estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment.  As described below, during 2014 and 2013 Entergy updated decommissioning cost estimates for certain nuclear power plants.

In 2014, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and ANO 2 as a result of a revised decommissioning cost study.  The revised estimates resulted in a $47.6 million increase in the decommissioning cost liabilities, along with a corresponding increase in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.

See Note 1 to the financial statements for further discussion of the shutdown of Vermont Yankee and the December 2013 settlement agreement involving Entergy and Vermont parties.  In accordance with the settlement agreement, Entergy Vermont Yankee provided to the Vermont parties, in 2014, a site assessment study of the costs and tasks of radiological decommissioning, spent nuclear fuel management, and site restoration for Vermont Yankee.  Entergy Vermont Yankee also filed its Post-Shutdown Decommissioning Activities Report (PSDAR) for Vermont Yankee with the NRC in December 2014.  As part of the development of the site assessment study and PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2014. The revised estimate, along with reassessment of the assumptions regarding the timing of decommissioning cash flows, resulted in a $101.6 million increase in the decommissioning cost liability and a corresponding impairment charge. 

In the fourth quarter 2014, Entergy Gulf States Louisiana recorded a revision to its estimated decommissioning cost liability for River Bend as a result of a revised decommissioning cost study. The revised estimate resulted in a $20 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining useful life of the unit.

In the fourth quarter 2014, 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 $99.9 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the first quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for a nuclear site as a result of a revised decommissioning cost study. The revised estimate resulted in a $46.6 million reduction in the decommissioning cost liability, along with a corresponding reduction in the related asset retirement cost asset.

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In the third quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Vermont Yankee as a result of a revised decommissioning cost study. The revised estimate resulted in a $58 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. The asset retirement cost asset was included in the carrying value used to write down Vermont Yankee and related assets to their fair values in third quarter 2013.  See Note 1 to the financial statements for further discussion of the resulting impairment charge recorded in third quarter 2013.

In the fourth quarter 2013, 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 $102.3 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the fourth quarter 2013, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $39.4 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the fourth quarter 2013, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Vermont Yankee. As a result of the settlement agreement regarding the remaining operation and decommissioning of Vermont Yankee, Entergy reassessed its assumptions regarding the timing of decommissioning cash flows. The reassessment resulted in a $27.2 million increase in the decommissioning cost liability and a corresponding impairment charge, which will not result in future cash expenditures. See Note 1 to the financial statements for further discussion of the Vermont Yankee plant.

In the second quarter 2012, Entergy Wholesale Commodities recorded a reduction of $60.6 million in the estimated decommissioning cost liability for a plant as a result of a revised decommissioning cost study.  The revised estimate resulted in a credit to decommissioning expense of $49 million, reflecting the excess of the reduction in the liability over the amount of the undepreciated asset retirement costs asset.

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.  The PSDAR for Vermont Yankee, including a site specific cost estimate, was submitted to the NRC 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.  Entergy expects that amounts available in Vermont Yankee’s decommissioning trust fund, including expected earnings, together with the credit facilities entered into in January 2015 that are expected to be repaid with recoveries from DOE litigation related to spent fuel storage, will be sufficient to cover expected costs of decommissioning, spent fuel management costs, and site restoration.  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.

For the Indian Point 3 and FitzPatrick plants purchased in 2000, NYPA retained the decommissioning trusts and the decommissioning liabilities.  NYPA and Entergy subsidiaries executed decommissioning agreements, which specify their decommissioning obligations.  NYPA has 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.  If the decommissioning liabilities are retained by NYPA, the Entergy subsidiaries will perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts.  Entergy recorded an asset, which is $599.9 million as of December 31, 2014, representing its estimate of the present value of the difference between the stipulated contract amount for decommissioning the

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plants less the decommissioning costs estimated in independent decommissioning cost studies.  The asset is 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 is recorded as interest income.

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, 2014 are as follows:
 
Decommissioning
Trust Fair Values
 
Regulatory
Asset (Liability)
 
(In Millions)
Utility:
 
 
 
ANO 1 and ANO 2

$769.9

 

$247.6

River Bend

$637.7

 

($25.5
)
Waterford 3

$383.6

 

$145.5

Grand Gulf

$679.8

 

$80.4

Entergy Wholesale Commodities

$2,899.9

 

$—


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, 2013 are as follows:
 
Decommissioning
Trust Fair Values
 
Regulatory
Asset (Liability)
 
(In Millions)
Utility:
 
 
 
ANO 1 and ANO 2

$710.9

 

$219.1

River Bend

$573.7

 

($28.7
)
Waterford 3

$347.3

 

$128.5

Grand Gulf

$603.9

 

$60.8

Entergy Wholesale Commodities

$2,667.3

 

$—




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

General

As of December 31, 2014, 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 and Waterford 3 sale and leaseback transactions, all of which are discussed elsewhere):
 
Year
 
Operating
Leases
 
Capital
Leases
 
 
(In Thousands)
2015
 

$90,010

 

$4,615

2016
 
77,060

 
4,457

2017
 
62,103

 
4,457

2018
 
49,630

 
3,672

2019
 
47,527

 
2,887

Years thereafter
 
95,530

 
27,664

Minimum lease payments
 
421,860

 
47,752

Less:  Amount representing interest
 
—

 
15,773

Present value of net minimum lease payments
 

$421,860

 

$31,979


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 $59 million in 2014, $63.7 million in 2013, and $69.9 million in 2012.

As of December 31, 2014 the Registrant Subsidiaries had a capital lease 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 and Waterford 3 sale and leaseback transactions, all of which are discussed elsewhere):

Capital Leases
 
Year
 
Entergy
Mississippi
 
 
(in Thousands)
2015
 

$1,570

2016
 
1,570

2017
 
1,570

2018
 
785

2019
 
—

Years thereafter
 
—

Minimum lease payments
 
5,495

Less:  Amount representing interest
 
656

Present value of net minimum lease payments
 

$4,839



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Operating Leases
 
 
Year
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
(In Thousands)
2015
 

$28,647

 

$12,643

 

$11,006

 

$6,885

 

$2,115

 

$5,837

2016
 
23,674

 
10,880

 
9,695

 
5,388

 
1,856

 
5,111

2017
 
16,501

 
10,035

 
7,784

 
4,020

 
1,587

 
4,239

2018
 
10,736

 
9,100

 
6,343

 
3,376

 
1,264

 
3,707

2019
 
11,365

 
10,795

 
5,003

 
3,073

 
1,087

 
2,719

Years thereafter
 
8,412

 
26,671

 
5,458

 
3,212

 
2,227

 
2,981

Minimum lease payments
 

$99,335

 

$80,124

 

$45,289

 

$25,954

 

$10,136

 

$24,594


Rental Expenses
 
 
Year
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
 
(In Millions)
2014
 

$12.0

 

$10.9

 

$9.8

 

$4.3

 

$1.2

 

$3.8

 

$2.0

2013
 

$12.0

 

$10.9

 

$10.1

 

$4.6

 

$1.3

 

$4.1

 

$2.5

2012
 

$12.6

 

$11.9

 

$11.2

 

$5.5

 

$1.5

 

$6.4

 

$1.5


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 $4.8 million in 2014, $8.6 million in 2013, and $8.5 million in 2012 for Entergy Arkansas and $1.7 million in 2014, $2.2 million in 2013, and $1.7 million in 2012 for Entergy Gulf States Louisiana.  Oil tank facilities lease payments for Entergy Mississippi were $1.6 million in 2014, $3.4 million in 2013, and $3.4 million in 2012.

Power Purchase Agreements

As of December 31, 2014, 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)

2015
 

$28,450

 

$28,450

2016
 
29,104

 
29,104

2017
 
29,772

 
29,772

2018
 
30,458

 
30,458

2019
 
31,158

 
31,158

Years thereafter
 
74,664

 
74,664

Minimum lease payments
 
223,606

 
223,606


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

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Total capacity expense under the power purchase agreement accounted for as an operating lease at Entergy Texas was $29.2 million in 2014, $28.6 million in 2013, and $19.2 million in 2012.

Sale and Leaseback Transactions

Waterford 3 Lease Obligations

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 expire in July 2017.  At the end of the lease terms, Entergy Louisiana has the option to repurchase the leased interests in Waterford 3 at fair market value or to renew the leases for either fair market value or, under certain conditions, a fixed rate.  In the event that Entergy Louisiana does not renew or purchase the interests, Entergy Louisiana would surrender such interests and their associated entitlement of Waterford 3’s capacity and energy.

Entergy Louisiana issued $208.2 million of non-interest bearing first mortgage bonds as collateral for the equity portion of certain amounts payable under the leases.

Upon the occurrence of certain events, Entergy Louisiana may be obligated to assume the outstanding bonds used to finance the purchase of the interests in the unit and to pay an amount sufficient to withdraw from the lease transaction.  Such events include lease events of default, events of loss, deemed loss events, or certain adverse “Financial Events.”  “Financial Events” include, among other things, failure by Entergy Louisiana, following the expiration of any applicable grace or cure period, to maintain (i) total equity capital (including preferred membership interests) at least equal to 30% of adjusted capitalization, or (ii) a fixed charge coverage ratio of at least 1.50 computed on a rolling 12 month basis.  As of December 31, 2014, Entergy Louisiana was in compliance with these provisions.

As of December 31, 2014, Entergy Louisiana, in connection with the Waterford 3 sale and leaseback transactions, had future minimum lease payments (reflecting an overall implicit rate of 7.45%) that are recorded as long-term debt, as follows:
 
Amount
 
(In Thousands)
 
 
2015

$28,827

2016
16,938

2017
106,335

2018
—

2019
—

Years thereafter
—

Total
152,100

Less: Amount representing interest
23,612

Present value of net minimum lease payments

$128,488


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 was to expire in July 2015.  In December 2013, System Energy exercised its options to renew the leases for fair market value with a renewal term for one lease expiring in July 2018 and the renewal term of the other lease 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.

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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 $62.9 million and $61.6 million as of December 31, 2014 and 2013, respectively.

As of December 31, 2014, 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)
 
 
2015

$52,253

2016
13,750

2017
13,750

2018
13,750

2019
13,750

Years thereafter
233,750

Total
341,003

Less: Amount representing interest
290,332

Present value of net minimum lease payments

$50,671



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

Qualified Pension Plans

Entergy has nine qualified pension plans covering substantially all employees. The “Entergy Corporation Retirement Plan for Non-Bargaining Employees,” “Entergy Corporation Retirement Plan for Bargaining Employees,” “Entergy Corporation Retirement Plan II for Non-Bargaining Employees,” “Entergy Corporation Retirement Plan II for Bargaining Employees,” “Entergy Corporation Retirement Plan IV for Non-Bargaining Employees,” and “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.  The “Entergy Corporation Retirement Plan III” is a final average pay plan that provides pension benefits that are based on employees’ credited service and compensation during the final years before retirement and includes a mandatory employee contribution of 3% of earnings during the first 10 years of plan participation, and allows voluntary contributions from 1% to 10% of earnings for a limited group of employees. Non-bargaining employees hired or rehired after June 30, 2014 participate in the “Entergy Corporation Cash Balance Plan for Non-Bargaining Employees.” 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.” The Registrant Subsidiaries participate in these four plans: “Entergy Corporation Retirement Plan for Non-Bargaining Employees,” “Entergy Corporation Retirement Plan for Bargaining Employees,” “Entergy Corporation Cash Balance Plan for Non-Bargaining Employees,” and “Entergy Cash Balance Plan for Bargaining Employees.”


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The assets of the seven final average pay qualified pension plans are held in a master trust established by Entergy and the assets of the two cash balance pension plans are held in a second master trust established by Entergy.  Each pension plan has an undivided beneficial interest in each of the investment accounts in its respective master trust that is maintained by a trustee.  Use of the master trusts permits the commingling of the trust assets of the pension plans of Entergy Corporation and its Registrant Subsidiaries for investment and administrative purposes.  Although assets in the master trusts are commingled, the trustee maintains supporting records for the purpose of allocating the trust level equity in net earnings (loss) and the administrative expenses of the investment accounts in each trust to the various participating pension plans in that particular trust.  The fair value of the trusts’ assets is determined by the trustee and certain investment managers.  For each trust, the trustee calculates a daily earnings factor, including realized and unrealized gains or losses, collected and accrued income, and administrative expenses, and allocates earnings to each plan in the master trusts on a pro rata basis.

Within each pension plan, the record of each Registrant Subsidiary’s beneficial interest in the plan assets is maintained by the plan’s actuary and is updated quarterly.  Assets for each Registrant Subsidiary are increased for investment 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 costs in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended.  The assets of the plans include common and preferred stocks, fixed-income securities, interest in a money market fund, and insurance contracts.  The Registrant Subsidiaries’ pension costs are recovered from customers as a component of cost of service in each of their respective jurisdictions.


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Notes to Financial Statements


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 2014, 2013, and 2012 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:
 
2014
 
2013
 
2012
 
(In Thousands)
Net periodic pension cost:
 

 
 

 
 

Service cost - benefits earned during the period

$140,436

 

$172,280

 

$150,763

Interest cost on projected benefit obligation
290,076

 
263,296

 
260,929

Expected return on assets
(361,462
)
 
(328,227
)
 
(317,423
)
Amortization of prior service cost
1,600

 
2,125

 
2,733

Recognized net loss
145,095

 
213,194

 
167,279

Curtailment loss
—

 
16,318

 
—

Special termination benefit
732

 
13,139

 
—

Net periodic pension costs

$216,477

 

$352,125

 

$264,281

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

$1,389,912

 

($894,150
)
 

$552,303

Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
 
 
 
 
 
Amortization of prior service cost
(1,600
)
 
(2,125
)
 
(2,733
)
Acceleration of prior service cost to curtailment
—

 
(1,307
)
 
—

Amortization of net loss
(145,095
)
 
(213,194
)
 
(167,279
)
Total
1,243,217

 
(1,110,776
)
 
382,291

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

$1,459,694

 

($758,651
)
 

$646,572

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

$1,561

 

$1,600

 

$2,268

Net loss

$237,013

 

$146,958

 

$219,805



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Notes to Financial Statements


The Registrant Subsidiaries’ total 2014, 2013, and 2012 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:
2014
 
 
Entergy
Arkansas
 
Entergy
Gulf States
 Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
 
(In Thousands)
Net periodic pension cost:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Service cost - benefits earned during the period
 

$20,090

 

$11,524

 

$14,182

 

$6,094

 

$2,666

 

$5,142

 

$5,785

Interest cost on projected
benefit obligation
 
59,537

 
29,114

 
37,870

 
17,273

 
8,164

 
17,746

 
13,561

Expected return on assets
 
(73,218
)
 
(37,950
)
 
(45,796
)
 
(22,794
)
 
(10,019
)
 
(23,723
)
 
(16,619
)
Amortization of prior service cost
 
—

 
—

 
—

 
—

 
—

 
—

 
2

Recognized net loss
 
35,956

 
15,923

 
24,523

 
9,415

 
5,796

 
9,356

 
9,500

Net pension cost
 

$42,365

 

$18,611

 

$30,779

 

$9,988

 

$6,607

 

$8,521

 

$12,229

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

$300,907

 

$125,090

 

$193,842

 

$88,199

 

$38,161

 

$65,363

 

$60,763

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

 
—

 
—

 
—

 
—

 
—

 
(2
)
Amortization of net loss
 
(35,956
)
 
(15,923
)
 
(24,523
)
 
(9,415
)
 
(5,796
)
 
(9,356
)
 
(9,500
)
Total
 

$264,951

 

$109,167

 

$169,319

 

$78,784

 

$32,365

 

$56,007

 

$51,261

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

$307,316

 

$127,778

 

$200,098

 

$88,772

 

$38,972

 

$64,528

 

$63,490

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

$54,254

 

$23,098

 

$36,704

 

$14,896

 

$8,053

 

$12,950

 

$13,055



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Notes to Financial Statements


2013
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
 
(In Thousands)
Net periodic pension cost:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Service cost - benefits earned during the period
 

$25,229

 

$14,258

 

$17,044

 

$7,295

 

$3,264

 

$6,475

 

$7,242

Interest cost on projected
benefit obligation
 
54,473

 
26,741

 
34,857

 
15,802

 
7,462

 
16,303

 
12,170

Expected return on assets
 
(66,951
)
 
(34,982
)
 
(41,948
)
 
(21,139
)
 
(9,117
)
 
(22,277
)
 
(17,249
)
Amortization of prior service cost
 
23

 
9

 
83

 
10

 
2

 
6

 
9

Recognized net loss
 
49,517

 
23,374

 
34,107

 
13,189

 
7,878

 
13,302

 
9,560

Curtailment loss
 
4,938

 
805

 
3,542

 
767

 
343

 
1,559

 
—

Special termination benefit
 
1,784

 
808

 
1,631

 
359

 
581

 
855

 
1,970

Net pension cost
 

$69,013

 

$31,013

 

$49,316

 

$16,283

 

$10,413

 

$16,223

 

$13,702

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

($177,105
)
 

($98,610
)
 

($123,234
)
 

($52,525
)
 

($25,419
)
 

($55,772
)
 

($35,511
)
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amortization of prior service cost
 
(23
)
 
(9
)
 
(83
)
 
(10
)
 
(2
)
 
(6
)
 
(9
)
Amortization of net loss
 
(49,517
)
 
(23,374
)
 
(34,107
)
 
(13,189
)
 
(7,878
)
 
(13,302
)
 
(9,560
)
Total
 

($226,645
)
 

($121,993
)
 

($157,424
)
 

($65,724
)
 

($33,299
)
 

($69,080
)
 

($45,080
)
Total recognized as net
periodic pension income,
regulatory asset, and/or AOCI (before tax)
 

($157,632
)
 

($90,980
)
 

($108,108
)
 

($49,441
)
 

($22,886
)
 

($52,857
)
 

($31,378
)
Estimated amortization
amounts from regulatory
asset and/or AOCI to net
periodic cost in the following year
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prior service cost
 

$—

 

$—

 

$—

 

$—

 

$—

 

$—

 

$2

Net loss
 

$35,984

 

$15,935

 

$24,360

 

$9,421

 

$5,802

 

$9,363

 

$9,510



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Notes to Financial Statements


2012
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
 
(In Thousands)
Net periodic pension cost:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Service cost - benefits earned during the period
 

$22,169

 

$12,273

 

$14,675

 

$6,410

 

$2,824

 

$5,684

 

$5,920

Interest cost on projected
benefit obligation
 
55,686

 
25,679

 
35,201

 
16,279

 
7,608

 
16,823

 
12,987

Expected return on assets
 
(65,763
)
 
(34,370
)
 
(40,836
)
 
(20,945
)
 
(8,860
)
 
(22,325
)
 
(16,436
)
Amortization of prior service cost
 
200

 
19

 
208

 
30

 
7

 
15

 
13

Recognized net loss
 
40,772

 
16,173

 
28,197

 
10,532

 
6,878

 
10,179

 
9,001

Net pension cost
 

$53,064

 

$19,774

 

$37,445

 

$12,306

 

$8,457

 

$10,376

 

$11,485

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

$105,133

 

$77,207

 

$76,163

 

$27,106

 

$14,282

 

$28,745

 

$10,266

Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amortization of prior service cost
 
(200
)
 
(19
)
 
(208
)
 
(30
)
 
(7
)
 
(15
)
 
(13
)
Amortization of net loss
 
(40,772
)
 
(16,173
)
 
(28,197
)
 
(10,532
)
 
(6,878
)
 
(10,179
)
 
(9,001
)
Total
 

$64,161

 

$61,015

 

$47,758

 

$16,544

 

$7,397

 

$18,551

 

$1,252

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

$117,225

 

$80,789

 

$85,203

 

$28,850

 

$15,854

 

$28,927

 

$12,737

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

$23

 

$9

 

$83

 

$10

 

$2

 

$6

 

$10

Net loss
 

$50,175

 

$23,731

 

$34,906

 

$13,375

 

$8,046

 

$13,494

 

$9,717



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Notes to Financial Statements


Qualified Pension Obligations, Plan Assets, Funded Status, Amounts Recognized in the Balance Sheet for Entergy Corporation and its Subsidiaries as of December 31, 2014 and 2013
 
December 31,
 
2014
 
2013
 
(In Thousands)
Change in Projected Benefit Obligation (PBO)
 

 
 

Balance at beginning of year

$5,770,999

 

$6,096,639

Service cost
140,436

 
172,280

Interest cost
290,076

 
263,296

Curtailment
—

 
15,011

Special termination benefit
732

 
13,139

Actuarial loss/(gain)
1,284,049

 
(571,990
)
Employee contributions
560

 
598

Benefits paid
(256,310
)
 
(217,974
)
Balance at end of year

$7,230,542

 

$5,770,999

Change in Plan Assets
 

 
 

Fair value of assets at beginning of year

$4,429,237

 

$3,832,860

Actual return on plan assets
255,599

 
650,386

Employer contributions
398,880

 
163,367

Employee contributions
560

 
598

Benefits paid
(256,310
)
 
(217,974
)
Fair value of assets at end of year

$4,827,966

 

$4,429,237

Funded status

($2,402,576
)
 

($1,341,762
)
Amount recognized in the balance sheet
 
 
 
Non-current liabilities

($2,402,576
)
 

($1,341,762
)
Amount recognized as a regulatory asset
 
 
 
Prior service cost

$3,704

 

$5,027

Net loss
2,451,172

 
1,494,117

 

$2,454,876

 

$1,499,144

Amount recognized as AOCI (before tax)
 
 
 
Prior service cost

$1,015

 

$1,292

Net loss
671,682

 
383,920

 

$672,697

 

$385,212



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Notes to Financial Statements


Qualified Pension Obligations, Plan Assets, Funded Status, and Amounts Recognized in the Balance Sheet for the Registrant Subsidiaries as of December 31, 2014 and 2013
2014
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
 
(In Thousands)
Change in Projected Benefit Obligation (PBO)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at beginning of year
 

$1,192,640

 

$579,862

 

$761,350

 

$345,824

 

$163,707

 

$356,080

 

$270,789

Service cost
 
20,090

 
11,524

 
14,182

 
6,094

 
2,666

 
5,142

 
5,785

Interest cost
 
59,537

 
29,114

 
37,870

 
17,273

 
8,164

 
17,746

 
13,561

Actuarial loss
 
279,781

 
113,883

 
180,763

 
81,600

 
35,131

 
58,556

 
55,410

Benefits paid
 
(66,330
)
 
(24,389
)
 
(37,624
)
 
(18,622
)
 
(7,113
)
 
(19,026
)
 
(11,233
)
Balance at end of year
 

$1,485,718

 

$709,994

 

$956,541

 

$432,169

 

$202,555

 

$418,498

 

$334,312

Change in Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair value of assets at beginning of year
 

$896,295

 

$469,295

 

$561,892

 

$281,837

 

$122,960

 

$295,751

 

$196,328

Actual return on plan assets
 
52,092

 
26,744

 
32,716

 
16,196

 
6,988

 
16,916

 
11,265

Employer contributions
 
95,464

 
30,176

 
54,549

 
21,839

 
10,509

 
17,072

 
21,261

Benefits paid
 
(66,330
)
 
(24,389
)
 
(37,624
)
 
(18,622
)
 
(7,113
)
 
(19,026
)
 
(11,233
)
Fair value of assets at end of
year
 

$977,521

 

$501,826

 

$611,533

 

$301,250

 

$133,344

 

$310,713

 

$217,621

Funded status
 

($508,197
)
 

($208,168
)
 

($345,008
)
 

($130,919
)
 

($69,211
)
 

($107,785
)
 

($116,691
)
Amounts recognized in the
 balance sheet (funded status)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-current liabilities
 

($508,197
)
 

($208,168
)
 

($345,008
)
 

($130,919
)
 

($69,211
)
 

($107,785
)
 

($116,691
)
Amounts recognized as
 regulatory asset
 
 
 
 
 
 
 
 
 
 
 
 
 
 

Net loss
 

$722,119

 

$272,695

 

$468,779

 

$198,972

 

$102,141

 

$176,522

 

$172,463

Amounts recognized as AOCI (before tax)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
 

$—

 

$40,748

 

$—

 

$—

 

$—

 

$—

 

$—



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Entergy Corporation and Subsidiaries
Notes to Financial Statements


2013
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
 
(In Thousands)
Change in Projected Benefit Obligation (PBO)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at beginning of year
 

$1,274,886

 

$623,068

 

$817,745

 

$369,852

 

$174,585

 

$382,176

 

$282,841

Service cost
 
25,229

 
14,258

 
17,044

 
7,295

 
3,264

 
6,475

 
7,242

Interest cost
 
54,473

 
26,741

 
34,857

 
15,802

 
7,462

 
16,303

 
12,170

Curtailment
 
4,938

 
805

 
3,542

 
767

 
343

 
1,559

 
—

Special termination benefit
 
1,784

 
808

 
1,631

 
359

 
581

 
855

 
1,970

Actuarial gain
 
(110,943
)
 
(64,119
)
 
(80,794
)
 
(31,684
)
 
(16,276
)
 
(33,792
)
 
(23,882
)
Benefits paid
 
(57,727
)
 
(21,699
)
 
(32,675
)
 
(16,567
)
 
(6,252
)
 
(17,496
)
 
(9,552
)
Balance at end of year
 

$1,192,640

 

$579,862

 

$761,350

 

$345,824

 

$163,707

 

$356,080

 

$270,789

Change in Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair value of assets at beginning of year
 

$785,527

 

$409,971

 

$489,027

 

$248,272

 

$106,778

 

$262,110

 

$168,697

Actual return on plan assets
 
133,113

 
69,473

 
84,388

 
41,980

 
18,259

 
44,257

 
28,878

Employer contributions
 
35,382

 
11,550

 
21,152

 
8,152

 
4,175

 
6,880

 
8,305

Benefits paid
 
(57,727
)
 
(21,699
)
 
(32,675
)
 
(16,567
)
 
(6,252
)
 
(17,496
)
 
(9,552
)
Fair value of assets at end of year
 

$896,295

 

$469,295

 

$561,892

 

$281,837

 

$122,960

 

$295,751

 

$196,328

Funded status
 

($296,345
)
 

($110,567
)
 

($199,458
)
 

($63,987
)
 

($40,747
)
 

($60,329
)
 

($74,461
)
Amounts recognized in the  balance sheet (funded status)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-current liabilities
 

($296,345
)
 

($110,567
)
 

($199,458
)
 

($63,987
)
 

($40,747
)
 

($60,329
)
 

($74,461
)
Amounts recognized as
 regulatory asset
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prior service cost
 

$—

 

$—

 

($1
)
 

$—

 

$—

 

$—

 

($4
)
Net loss
 
457,485

 
178,990

 
299,740

 
120,290

 
69,856

 
120,619

 
121,327

 
 

$457,485

 

$178,990

 

$299,739

 

$120,290

 

$69,856

 

$120,619

 

$121,323

Amounts recognized as AOCI  (before tax)
 
 

 
 
 
 
 
 
 
 
 
 
 
 
Net loss
 

$—

 

$25,437

 

$—

 

$—

 

$—

 

$—

 

$—


Other Postretirement Benefits

Entergy also currently offers retiree medical, dental, vision, and life insurance benefits (other postretirement benefits) for eligible retired employees.  Employees who commenced employment before July 1, 2014 and who satisfy certain eligibility requirements (including retiring from Entergy after a certain age and/or years of service with Entergy and immediately commencing their Entergy pension benefit), may become eligible for other postretirement benefits.

In December 2013, Entergy announced changes to its other postretirement benefits which include, among other things, elimination of other postretirement benefits for all non-bargaining employees hired or rehired after June 30, 2014 and for certain bargaining employees hired or rehired after June 30, 2014, or such later date provided for in their applicable collective bargaining agreement, and setting a dollar limit cap on Entergy’s contribution to retiree medical costs, effective 2019 for those non-bargaining employees who commence their Entergy retirement benefits on or after

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Notes to Financial Statements


January 1, 2015 and for certain bargaining employees who commence their Entergy retirement benefits on or after January 1, 2015 or such later date as provided for in their applicable collective bargaining agreement. In accordance with accounting standards, certain of the other postretirement benefit changes have been reflected in the December 31, 2013 other postretirement obligation. The changes affecting active bargaining unit employees are being negotiated with the unions prior to implementation, where necessary, and to the extent required by law.
 
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.  At January 1, 1993, the actuarially determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be approximately $241.4 million for Entergy (other than the former Entergy Gulf States) and $128 million for the former Entergy Gulf States (now split into Entergy Gulf States Louisiana and Entergy Texas).  Such obligations were being amortized over a 20-year period that began in 1993 and ended in 2012.  For the most part, the Registrant Subsidiaries recover accrued other postretirement benefit costs from customers and are required to contribute the other postretirement benefits collected in rates to an external trust.

Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, and Entergy Texas have received regulatory approval to recover accrued other postretirement benefit costs through rates.  Entergy Arkansas began recovery in 1998, pursuant to an APSC order.  This order also allowed Entergy Arkansas to amortize a regulatory asset (representing the difference between other postretirement benefit costs and cash expenditures for other postretirement benefits incurred from 1993 through 1997) over a 15-year period that began in January 1998 and ended in December 2012.

The LPSC ordered Entergy Gulf States Louisiana and 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 bank-administered master trusts, established by Entergy Corporation and maintained by a trustee.  Each participating Registrant Subsidiary holds a beneficial interest in the trusts’ assets.  The assets in the master trusts are commingled for investment and administrative purposes.  Although assets are commingled, supporting records are maintained for the purpose of allocating the beneficial interest in net earnings/(losses) and the administrative expenses of the investment accounts to the various participating plans and participating Registrant Subsidiaries. Beneficial interest in an investment account’s net income/(loss) is comprised of interest and dividends, realized and unrealized gains and losses, and expenses.  Beneficial interest from these investments is allocated to the plans and participating Registrant Subsidiary based on their portion of net assets in the pooled accounts.



    


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Notes to Financial Statements


Components of Net Other Postretirement Benefit Cost and Other Amounts Recognized as a Regulatory Asset and/or AOCI

Entergy Corporation’s and its subsidiaries’ total 2014, 2013, and 2012 other postretirement benefit costs, including amounts capitalized and amounts recognized as a regulatory asset and/or other comprehensive income, included the following components:
 
2014
 
2013
 
2012
 
(In Thousands)
Other postretirement costs:
 
 
 
 
 
Service cost - benefits earned during the period

$43,493

 

$74,654

 

$68,883

Interest cost on APBO
71,841

 
79,453

 
82,561

Expected return on assets
(44,787
)
 
(40,323
)
 
(34,503
)
Amortization of transition obligation
—

 
—

 
3,177

Amortization of prior service credit
(31,590
)
 
(14,904
)
 
(18,163
)
Recognized net loss
11,143

 
44,178

 
36,448

Curtailment loss
—

 
12,729

 
—

Net other postretirement benefit cost

$50,100

 

$155,787

 

$138,403

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

($35,864
)
 

($116,571
)
 

$—

Net loss/(gain)
287,313

 
(405,976
)
 
92,584

Amounts reclassified from regulatory asset and /or AOCI to net periodic benefit cost in the current year:
 
 
 
 
 
Amortization of transition obligation
—

 
—

 
(3,177
)
Amortization of prior service credit
31,590

 
14,904

 
18,163

Acceleration of prior service credit due to curtailment
—

 
1,989

 
—

Amortization of net loss
(11,143
)
 
(44,178
)
 
(36,448
)
Total

$271,896

 

($549,832
)
 

$71,122

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

$321,996

 

($394,045
)
 

$209,525

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

($37,280
)
 

($31,589
)
 

($13,336
)
Net loss

$31,591

 

$11,197

 

$45,217



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Notes to Financial Statements


Total 2014, 2013, and 2012 other postretirement benefit costs of the Registrant Subsidiaries, including amounts capitalized and deferred, for their employees included the following components:
2014
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
 
(In Thousands)
Other postretirement costs:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Service cost - benefits earned during the period
 

$5,957

 

$4,896

 

$4,518

 

$1,900

 

$868

 

$2,378

 

$2,058

Interest cost on APBO
 
12,261

 
8,378

 
8,264

 
3,655

 
2,805

 
5,652

 
2,611

Expected return on assets
 
(19,135
)
 
—

 
—

 
(5,771
)
 
(4,475
)
 
(10,358
)
 
(3,727
)
Amortization of prior credit
 
(2,441
)
 
(2,237
)
 
(3,377
)
 
(915
)
 
(709
)
 
(1,300
)
 
(824
)
Recognized net loss
 
1,267

 
1,212

 
1,511

 
149

 
56

 
801

 
443

Net other postretirement benefit (income)/cost
 

($2,091
)
 

$12,249

 

$10,916

 

($982
)
 

($1,455
)
 

($2,827
)
 

$561

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
 

$—

 

($12,845
)
 

$—

 

$—

 

$—

 

($8,536
)
 

($3,845
)
Net loss
 

$55,642

 

$36,467

 

$24,582

 

$9,525

 

$6,309

 

$24,482

 

$10,596

Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
 

 
 
 
 
 
 
 
 
 
 
 
 
Amortization of prior service credit
 
2,441

 
2,237

 
3,377

 
915

 
709

 
1,300

 
824

Amortization of net loss
 
(1,267
)
 
(1,212
)
 
(1,511
)
 
(149
)
 
(56
)
 
(801
)
 
(443
)
Total
 

$56,816

 

$24,647

 

$26,448

 

$10,291

 

$6,962

 

$16,445

 

$7,132

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

$54,725

 

$36,896

 

$37,364

 

$9,309

 

$5,507

 

$13,618

 

$7,693

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

($2,441
)
 

($4,086
)
 

($3,381
)
 

($916
)
 

($709
)
 

($2,723
)
 

($1,465
)
Net loss
 

$5,356

 

$3,908

 

$3,210

 

$860

 

$470

 

$2,740

 

$1,198



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Notes to Financial Statements


2013
 
 
Entergy
Arkansas

Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
 
(In Thousands)
Other postretirement costs:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Service cost - benefits earned during the period
 

$9,619

 

$7,910

 

$8,541

 

$3,246

 

$1,752

 

$3,760

 

$3,580

Interest cost on APBO
 
13,545

 
8,964

 
9,410

 
4,289

 
3,135

 
6,076

 
2,945

Expected return on assets
 
(16,843
)
 
—

 
—

 
(5,335
)
 
(4,101
)
 
(9,391
)
 
(3,350
)
Amortization of prior credit
 
(689
)
 
(942
)
 
(508
)
 
(204
)
 
(24
)
 
(501
)
 
(126
)
Recognized net loss
 
7,976

 
4,598

 
5,050

 
2,534

 
1,509

 
3,744

 
1,896

Curtailment loss
 
4,517

 
1,546

 
1,848

 
596

 
354

 
1,436

 
760

Net other postretirement benefit cost
 

$18,125

 

$22,076

 

$24,341

 

$5,126

 

$2,625

 

$5,124

 

$5,705

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
 

($11,617
)
 

($8,705
)
 

($18,844
)
 

($4,714
)
 

($4,469
)
 

($5,359
)
 

($4,591
)
Net loss
 

($81,236
)
 

($40,938
)
 

($43,743
)
 

($30,018
)
 

($18,508
)
 

($34,562
)
 

($17,579
)
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amortization of prior service credit
 
689

 
942

 
508

 
204

 
24

 
501

 
126

Acceleration of prior service credit/(cost) due to curtailment
 
78

 
91

 
41

 
20

 
(4
)
 
62

 
9

Amortization of net loss
 
(7,976
)
 
(4,598
)
 
(5,050
)
 
(2,534
)
 
(1,509
)
 
(3,744
)
 
(1,896
)
Total
 

($100,062
)
 

($53,208
)
 

($67,088
)
 

($37,042
)
 

($24,466
)
 

($43,102
)
 

($23,931
)
Total recognized as net periodic other postretirement cost, regulatory asset, and/or AOCI (before tax)
 

($81,937
)
 

($31,132
)
 

($42,747
)
 

($31,916
)
 

($21,841
)
 

($37,978
)
 

($18,226
)
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost  in the following year
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prior service credit
 

($2,441
)
 

($2,236
)
 

($3,376
)
 

($918
)
 

($709
)
 

($1,301
)
 

($824
)
Net loss
 

$1,267

 

$1,212

 

$1,511

 

$149

 

$56

 

$800

 

$464


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Notes to Financial Statements


2012
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
 
(In Thousands)
Other postretirement costs:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Service cost - benefits earned during the period
 

$9,089

 

$7,521

 

$7,796

 

$3,093

 

$1,689

 

$3,651

 

$3,293

Interest cost on APBO
 
14,452

 
9,590

 
9,781

 
4,716

 
3,422

 
6,650

 
3,028

Expected return on assets
 
(14,029
)
 
—

 
—

 
(4,521
)
 
(3,711
)
 
(8,415
)
 
(2,601
)
Amortization of transition
obligation
 
820

 
238

 
382

 
351

 
1,189

 
187

 
8

Amortization of prior service cost/(credit)
 
(530
)
 
(824
)
 
(247
)
 
(139
)
 
38

 
(428
)
 
(63
)
Recognized net loss
 
8,305

 
4,737

 
4,359

 
2,920

 
1,559

 
4,320

 
1,970

Net other postretirement benefit cost
 

$18,107

 

$21,262

 

$22,071

 

$6,420

 

$4,186

 

$5,965

 

$5,635

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

$9,066

 

$5,818

 

$16,215

 

$271

 

$2,260

 

$191

 

$2,043

Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amortization of transition
obligation
 
(820
)
 
(238
)
 
(382
)
 
(351
)
 
(1,189
)
 
(187
)
 
(8
)
Amortization of prior service (cost)/credit
 
530

 
824

 
247

 
139

 
(38
)
 
428

 
63

Amortization of net loss
 
(8,305
)
 
(4,737
)
 
(4,359
)
 
(2,920
)
 
(1,559
)
 
(4,320
)
 
(1,970
)
Total
 

$471

 

$1,667

 

$11,721

 

($2,861
)
 

($526
)
 

($3,888
)
 

$128

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

$18,578

 

$22,929

 

$33,792

 

$3,559

 

$3,660

 

$2,077

 

$5,763

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

($530
)
 

($824
)
 

($247
)
 

($139
)
 

$38

 

($428
)
 

($62
)
Net loss
 

$8,163

 

$4,693

 

$5,149

 

$2,650

 

$1,587

 

$3,905

 

$1,915



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Notes to Financial Statements


Other Postretirement Benefit Obligations, Plan Assets, Funded Status, and Amounts Not Yet Recognized and Recognized in the Balance Sheet of Entergy Corporation and its Subsidiaries as of December 31, 2014 and 2013
 
December 31,
 
2014
 
2013
 
(In Thousands)
Change in APBO
 

 
 

Balance at beginning of year

$1,461,910

 

$1,846,922

Service cost
43,493

 
74,654

Interest cost
71,841

 
79,453

Plan amendments
(35,864
)
 
(116,571
)
Curtailment
—

 
14,718

Plan participant contributions
22,160

 
19,141

Actuarial loss/(gain)
274,061

 
(370,004
)
Benefits paid
(102,439
)
 
(89,713
)
Medicare Part D subsidy received
4,395

 
3,310

Balance at end of year

$1,739,557

 

$1,461,910

Change in Plan Assets
 

 
 

Fair value of assets at beginning of year

$569,850

 

$488,448

Actual return on plan assets
31,535

 
76,314

Employer contributions
76,521

 
75,660

Plan participant contributions
22,160

 
19,141

Benefits paid
(102,439
)
 
(89,713
)
Fair value of assets at end of year

$597,627

 

$569,850

Funded status

($1,141,930
)
 

($892,060
)
Amounts recognized in the balance sheet
 
 
 
Current liabilities

($41,821
)
 

($40,602
)
Non-current liabilities
(1,100,109
)
 
(851,458
)
Total funded status

($1,141,930
)
 

($892,060
)
Amounts recognized as a regulatory asset
 
 
 
Prior service credit

($54,508
)
 

($93,332
)
Net loss
248,918

 
165,270

 

$194,410

 

$71,938

Amounts recognized as AOCI (before tax)
 
 
 
Prior service credit

($104,086
)
 

($60,988
)
Net loss
300,518

 
107,996

 

$196,432

 

$47,008



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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, 2014 and 2013
2014
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
 
(In Thousands)
Change in APBO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at beginning of year
 

$250,734

 

$170,302

 

$168,764

 

$74,539

 

$57,874

 

$115,418

 

$53,051

Service cost
 
5,957

 
4,896

 
4,518

 
1,900

 
868

 
2,378

 
2,058

Interest cost
 
12,261

 
8,378

 
8,264

 
3,655

 
2,805

 
5,652

 
2,611

Plan amendments
 
—

 
(12,845
)
 
—

 
—

 
—

 
(8,536
)
 
(3,845
)
Plan participant contributions
 
5,195

 
2,304

 
2,767

 
1,396

 
1,044

 
1,655

 
1,061

Actuarial loss
 
49,573

 
36,467

 
24,582

 
7,939

 
5,097

 
21,471

 
9,524

Benefits paid
 
(20,984
)
 
(10,613
)
 
(14,012
)
 
(6,589
)
 
(4,131
)
 
(8,333
)
 
(3,858
)
Medicare Part D subsidy received
 
980

 
520

 
654

 
322

 
222

 
440

 
152

Balance at end of year
 

$303,716

 

$199,409

 

$195,537

 

$83,162

 

$63,779

 

$130,145

 

$60,754

Change in Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair value of assets at beginning of year
 

$231,663

 

$—

 

$—

 

$73,438

 

$66,539

 

$131,618

 

$48,101

Actual return on plan assets
 
13,066

 
—

 
—

 
4,185

 
3,263

 
7,347

 
2,655

Employer contributions
 
15,251

 
8,309

 
11,245

 
8,505

 
4,289

 
3,446

 
334

Plan participant contributions
 
5,195

 
2,304

 
2,767

 
1,396

 
1,044

 
1,655

 
1,061

Benefits paid
 
(20,984
)
 
(10,613
)
 
(14,012
)
 
(6,589
)
 
(4,131
)
 
(8,333
)
 
(3,858
)
Fair value of assets at end of year
 

$244,191

 

$—

 

$—

 

$80,935

 

$71,004

 

$135,733

 

$48,293

Funded status
 

($59,525
)
 

($199,409
)
 

($195,537
)
 

($2,227
)
 

$7,225

 

$5,588

 

($12,461
)
Amounts recognized in the
balance sheet
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 

$—

 

($8,884
)
 

($9,840
)
 

$—

 

$—

 

$—

 

$—

Non-current liabilities
 
(59,525
)
 
(190,525
)
 
(185,697
)
 
(2,227
)
 
7,225

 
5,588

 
(12,461
)
Total funded status
 

($59,525
)
 

($199,409
)
 

($195,537
)
 

($2,227
)
 

$7,225

 

$5,588

 

($12,461
)
Amounts recognized in
regulatory asset
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prior service credit
 

($10,555
)
 

$—

 

$—

 

($4,141
)
 

($3,626
)
 

($13,741
)
 

($7,723
)
Net loss
 
94,647

 
—

 
—

 
18,680

 
12,738

 
46,453

 
20,450

 
 

$84,092

 

$—

 

$—

 

$14,539

 

$9,112

 

$32,712

 

$12,727

Amounts recognized in AOCI (before tax)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prior service credit
 

$—

 

($20,967
)
 

($16,013
)
 

$—

 

$—

 

$—

 

$—

Net loss
 
—

 
66,832

 
58,072

 
—

 
—

 
—

 
—

 
 

$—

 

$45,865

 

$42,059

 

$—

 

$—

 

$—

 

$—




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Notes to Financial Statements


2013
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
 
(In Thousands)
Change in APBO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at beginning of year
 

$315,308

 

$207,987

 

$220,017

 

$100,508

 

$74,200

 

$142,114

 

$67,934

Service cost
 
9,619

 
7,910

 
8,541

 
3,246

 
1,752

 
3,760

 
3,580

Interest cost
 
13,545

 
8,964

 
9,410

 
4,289

 
3,135

 
6,076

 
2,945

Plan amendments
 
(11,617
)
 
(8,705
)
 
(18,844
)
 
(4,714
)
 
(4,469
)
 
(5,359
)
 
(4,591
)
Curtailment
 
4,595

 
1,637

 
1,889

 
616

 
350

 
1,498

 
769

Plan participant contributions
 
4,564

 
1,998

 
2,509

 
1,292

 
915

 
1,498

 
860

Actuarial gain
 
(67,253
)
 
(40,941
)
 
(43,747
)
 
(25,527
)
 
(13,739
)
 
(26,048
)
 
(14,639
)
Benefits paid
 
(18,764
)
 
(8,958
)
 
(11,524
)
 
(5,416
)
 
(4,464
)
 
(8,455
)
 
(3,912
)
Medicare Part D subsidy received
 
737

 
410

 
513

 
245

 
194

 
334

 
105

Balance at end of year
 

$250,734

 

$170,302

 

$168,764

 

$74,539

 

$57,874

 

$115,418

 

$53,051

Change in Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair value of assets at beginning of year
 

$194,018

 

$—

 

$—

 

$62,951

 

$58,651

 

$115,824

 

$39,474

Actual return on plan assets
 
30,830

 
—

 
—

 
9,826

 
8,870

 
17,905

 
6,292

Employer contributions
 
21,015

 
6,960

 
9,015

 
4,785

 
2,567

 
4,846

 
5,387

Plan participant contributions
 
4,564

 
1,998

 
2,509

 
1,292

 
915

 
1,498

 
860

Benefits paid
 
(18,764
)
 
(8,958
)
 
(11,524
)
 
(5,416
)
 
(4,464
)
 
(8,455
)
 
(3,912
)
Fair value of assets at end of year
 

$231,663

 

$—

 

$—

 

$73,438

 

$66,539

 

$131,618

 

$48,101

Funded status
 

($19,071
)
 

($170,302
)
 

($168,764
)
 

($1,101
)
 

$8,665

 

$16,200

 

($4,950
)
Amounts recognized in the
balance sheet
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 

$—

 

($8,803
)
 

($10,249
)
 

$—

 

$—

 

$—

 

$—

Non-current liabilities
 
(19,071
)
 
(161,499
)
 
(158,515
)
 
(1,101
)
 
8,665

 
16,200

 
(4,950
)
Total funded status
 

($19,071
)
 

($170,302
)
 

($168,764
)
 

($1,101
)
 

$8,665

 

$16,200

 

($4,950
)
Amounts recognized in
regulatory asset
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prior service credit
 

($12,996
)
 

$—

 

$—

 

($5,056
)
 

($4,335
)
 

($6,505
)
 

($4,702
)
Net loss
 
40,272

 
—

 
—

 
9,304

 
6,485

 
22,772

 
10,297

 
 

$27,276

 

$—

 

$—

 

$4,248

 

$2,150

 

$16,267

 

$5,595

Amounts recognized in AOCI (before tax)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prior service credit
 

$—

 

($10,359
)
 

($19,390
)
 

$—

 

$—

 

$—

 

$—

Net loss
 
—

 
31,577

 
35,001

 
—

 
—

 
—

 
—

 
 

$—

 

$21,218

 

$15,611

 

$—

 

$—

 

$—

 

$—



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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 $32.4 million in 2014, $54.5 million in 2013, and $26.5 million in 2012.  In 2014, 2013, and 2012 Entergy recognized $15.1 million, $33 million, and $6.3 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 $151.8 million and $154.3 million as of December 31, 2014 and 2013, respectively.  The accumulated benefit obligation was $130.6 million and $131.4 million as of December 31, 2014 and 2013, respectively.

Entergy’s non-qualified, non-current pension liability at December 31, 2014 and 2013 was $135.6 million and $127.5 million, respectively; and its current liability was $16.2 million and $26.8 million, respectively.  The unamortized prior service cost and net loss are recognized in regulatory assets ($60.3 million at December 31, 2014 and $59.1 million at December 31, 2013) and accumulated other comprehensive income before taxes ($23.5 million at December 31, 2014 and $26.1 million at December 31, 2013).

The Registrant Subsidiaries (except System Energy) 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 2014, 2013, and 2012, was as follows:
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
(In Thousands)
2014

$754

 

$130

 

$5

 

$190

 

$95

 

$491

2013

$448

 

$151

 

$12

 

$192

 

$92

 

$1,001

2012

$464

 

$158

 

$12

 

$183

 

$79

 

$648


Included in the 2014 net periodic pension cost above are settlement charges of $337 thousand and $16 thousand for Entergy Arkansas and Entergy Texas, respectively, related to the lump sum benefits paid out of the plan. Included in the 2013 net periodic pension cost above are settlement charges of $415 thousand for Entergy Texas related to the lump sum benefits paid out of the plan.  Included in the 2012 net periodic pension cost above are settlement charges of $38 thousand for Entergy Arkansas 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, 2014 and 2013 was as follows:
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
(In Thousands)
2014

$4,495

 

$2,693

 

$158

 

$2,128

 

$476

 

$9,567

2013

$4,162

 

$2,511

 

$50

 

$1,752

 

$434

 

$7,910



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Notes to Financial Statements


The accumulated benefit obligation for their employees for the non-qualified plans as of December 31, 2014 and 2013 was as follows:
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
(In Thousands)
2014

$4,086

 

$2,693

 

$131

 

$1,761

 

$436

 

$9,215

2013

$3,765

 

$2,510

 

$50

 

$1,528

 

$387

 

$7,496


The following amounts were recorded on the balance sheet as of December 31, 2014 and 2013:
2014
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
(In Thousands)
Current liabilities
 

($347
)
 

($241
)
 

($18
)
 

($119
)
 

($23
)
 

($753
)
Non-current liabilities
 
(4,148
)
 
(2,452
)
 
(140
)
 
(2,009
)
 
(453
)
 
(8,814
)
Total funded status
 

($4,495
)
 

($2,693
)
 

($158
)
 

($2,128
)
 

($476
)
 

($9,567
)
Regulatory asset/(liability)
 

$2,368

 

$659

 

$37

 

$942

 

($65
)
 

$296

Accumulated other
comprehensive income (before taxes)
 

$—

 

$98

 

$—

 

$—

 

$—

 

$—


2013
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
(In Thousands)
Current liabilities
 

($367
)
 

($262
)
 

($6
)
 

($118
)
 

($20
)
 

($786
)
Non-current liabilities
 
(3,795
)
 
(2,249
)
 
(44
)
 
(1,634
)
 
(414
)
 
(7,124
)
Total funded status
 

($4,162
)
 

($2,511
)
 

($50
)
 

($1,752
)
 

($434
)
 

($7,910
)
Regulatory asset/(liability)
 

$1,979

 

$422

 

($87
)
 

$637

 

($18
)
 

($1,631
)
Accumulated other
comprehensive income (before taxes)
 

$—

 

$57

 

$—

 

$—

 

$—

 

$—



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Notes to Financial Statements


Reclassification out of Accumulated Other Comprehensive Income

Entergy and the Registrant Subsidiaries reclassified the following costs out of accumulated other comprehensive income (before taxes and including amounts capitalized) as of December 31, 2014:

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

($1,559
)
 

$22,280

 

($427
)
 

$20,294

Amortization of loss
(26,934
)
 
(6,689
)
 
(2,213
)
 
(35,836
)
Settlement loss
—

 
—

 
(3,643
)
 
(3,643
)
 

($28,493
)
 

$15,591

 

($6,283
)
 

($19,185
)
Entergy Gulf States Louisiana
 
 
 
 
 
 
 
Amortization of prior service cost

$—

 

$2,237

 

$—

 

$2,237

Amortization of loss
(1,911
)
 
(1,212
)
 
(3
)
 
(3,126
)
 

($1,911
)
 

$1,025

 

($3
)
 

($889
)
Entergy Louisiana
 
 
 
 
 
 
 
Amortization of prior service cost

$—

 

$3,377

 

$—

 

$3,377

Amortization of loss
—

 
(1,511
)
 
—

 
(1,511
)
 

$—

 

$1,866

 

$—

 

$1,866



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Notes to Financial Statements


Entergy and the Registrant Subsidiaries reclassified the following costs out of accumulated other comprehensive income (before taxes and including amounts capitalized) as of December 31, 2013:
 
Qualified
Pension
Costs
 
Other
Postretirement
Costs
 
Non-Qualified
Pension Costs
 
Total
 
(In Thousands)
Entergy
 
 
 
 
 
 
 
Amortization of prior service cost

($1,866
)


$12,925

 

($503
)
 

$10,556

Acceleration of prior service cost due to curtailment
(1,304
)
 
1,797

 
(178
)
 
315

Amortization of loss
(43,971
)
 
(21,590
)
 
(2,569
)
 
(68,130
)
Settlement loss
—

 
—

 
(11,612
)
 
(11,612
)
 

($47,141
)
 

($6,868
)
 

($14,862
)
 

($68,871
)
Entergy Gulf States Louisiana
 
 
 
 
 
 
 
Amortization of prior service cost

($1
)


$942

 

$—

 

$941

Acceleration of prior service cost due to curtailment
—

 
91

 
—

 
91

Amortization of loss
(3,039
)
 
(4,598
)
 
(7
)
 
(7,644
)
 

($3,040
)
 

($3,565
)
 

($7
)
 

($6,612
)
Entergy Louisiana
 
 
 
 
 
 
 
Amortization of prior service cost

$—



$508

 

$—

 

$508

Acceleration of prior service cost due to curtailment
—

 
41

 
—

 
41

Amortization of loss
—

 
(5,050
)
 
—

 
(5,050
)
 

$—

 

($4,501
)
 

$—

 

($4,501
)

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 Gulf States 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 Gulf States Louisiana and Entergy Louisiana recover other postretirement benefit costs on a pay-as-you-go basis and record the unrecognized prior service cost, gains and losses, and transition obligation for its other postretirement benefit obligation as other comprehensive income.  Accounting standards also require that changes in the funded status be recorded as other comprehensive income and/or a regulatory asset in the period in which the changes occur.

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.

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Notes to Financial Statements


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. 

The target and range asset allocation for postretirement assets reflects changes made in 2012 as recommended in the latest optimization study.

Entergy’s qualified pension and postretirement weighted-average asset allocations by asset category at December 31, 2014 and 2013 and the target asset allocation and ranges are as follows:
Pension
Asset Allocation
 
Target
 
Range
 
Actual
2014
 
Actual
2013
Domestic Equity Securities
 
45%
 
34%
to
53%
 
45%
 
46%
International Equity Securities
 
20%
 
16%
to
24%
 
19%
 
20%
Fixed Income Securities
 
35%
 
31%
to
41%
 
35%
 
33%
Other
 
0%
 
0%
to
10%
 
1%
 
1%

Postretirement
Asset Allocation
 
Non-Taxable and Taxable
 

Target

Range
Actual
2014
Actual
2013
Domestic Equity Securities
39%
34%
to
44%
42%
40%
International Equity Securities
26%
21%
to
31%
25%
26%
Fixed Income Securities
35%
30%
to
40%
33%
34%
Other
0%
0%
to
5%
0%
0%

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

The expected long-term rate of return for the qualified pension plans’ assets is based primarily on the geometric average of the historical annual performance of a representative portfolio weighted by the target asset allocation defined in the table above, along with other indications of expected return on assets. The time period reflected is a long dated period spanning several decades.


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Notes to Financial Statements


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 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 trust assets (as described above), 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, 2014, 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 risk in Entergy’s pension and other postretirement benefit plan assets.

Fair Value Measurements

Accounting standards provide the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements).

The three levels of the fair value hierarchy are described below:

•
Level 1 - Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in active markets that the Plan has the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

•
Level 2 - Level 2 inputs are inputs other than quoted prices included in Level 1 that are, either directly or indirectly, observable for the asset or liability at the measurement date.  Assets are valued based on prices derived by an independent party that uses inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads.  Prices are reviewed and can be challenged with the independent parties and/or overridden if it is believed such would be more reflective of fair value.  Level 2 inputs include the following:
 
-     quoted prices for similar assets or liabilities in active markets;
-     quoted prices for identical assets or liabilities in inactive markets;
-     inputs other than quoted prices that are observable for the asset or liability; or
-     inputs that are derived principally from or corroborated by observable market data by correlation or other means.

If an asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability.

•
Level 3 - Level 3 refers to securities valued based on significant unobservable inputs.
    
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  The following tables set forth by level within the fair value hierarchy, measured at fair value

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Entergy Corporation and Subsidiaries
Notes to Financial Statements


on a recurring basis at December 31, 2014, and December 31, 2013, 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

Final Average Pay Pension Plans’ Trust

2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Thousands)
Equity securities:
 
 
 
 
 
 
 
 
Corporate stocks:
 
 
 
 
 
 
 
 
Preferred
 

$10,017

(b)

$—

(a)

$—

 

$10,017

Common
 
717,685

(b)
97

 
—

 
717,782

Common collective trusts
 
—

 
1,886,897

(c)
—

 
1,886,897

103-12 investment entities
 
—

 
259,995

(h)
—

 
259,995

Fixed income securities:
 
 
 
 
 
 
 
 
U.S. Government securities
 
240

(b)
400,059

(a)
—

 
400,299

Corporate debt instruments
 
—

 
548,788

(a)
—

 
548,788

Registered investment companies
 
286,534

(d)
576,641

(e)
—

 
863,175

Other
 
—

 
130,295

(f)
—

 
130,295

Other:
 
 
 
 
 
 
 
 
Insurance company general account (unallocated contracts)
 
—

 
37,818

  
(g)
—

 
37,818

Total investments
 

$1,014,476

 

$3,840,590

 

$—

 

$4,855,066

Cash
 
 
 
 
 
 
 
314

Other pending transactions
 
 
 
 
 
 
 
7,359

Less: Other postretirement assets included in total investments
 
 
 
 
 
 
 
(34,954
)
Total fair value of qualified
pension assets
 
 
 
 
 
 
 

$4,827,785


Cash Balance Pension Plans’ Trust

The Cash Balance pension plans’ trust held $181 thousand of cash as of December 31, 2014.



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2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Thousands)
Equity securities:
 
 
 
 
 
 
 
 
Corporate stocks:
 
 
 
 
 
 
 
 
Preferred
 

$6,847

(b)

$6,038

(a)

$—

 

$12,885

Common
 
915,996

(b)
—

 
—

 
915,996

Common collective trusts
 
—

 
1,753,958

(c)
—

 
1,753,958

Fixed income securities:
 
 
 
 
 
 
 
 
U.S. Government securities
 
180,718

(b)
152,915

(a)
—

 
333,633

Corporate debt instruments
 
—

 
464,652

(a)
—

 
464,652

Registered investment companies
 
316,863

(d)
486,748

(e)
—

 
803,611

Other
 
—

 
129,169

(f)
—

 
129,169

Other:
 
 
 
 
 
 
 
 
Insurance company general account (unallocated contracts)
 
—

 
36,886

 
(g)
—

 
36,886

Total investments
 

$1,420,424

 

$3,030,366

 

$—

 

$4,450,790

Cash
 
 
 
 
 
 
 
280

Other pending transactions
 
 
 
 
 
 
 
8,081

Less: Other postretirement
assets included in total investments
 
 
 
 
 
 
 
(29,914
)
Total fair value of qualified
   pension assets
 
 
 
 
 
 
 

$4,429,237


Other Postretirement Trusts
2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Thousands)
Equity securities:
 
 
 
 
 
 
 
 
Common collective trust
 

$—

 

$370,228

(c)

$—

 

$370,228

Fixed income securities:
 
 
 
 
 
 
 
 

U.S. Government securities
 
36,306

(b)
45,618

(a)
—

 
81,924

Corporate debt instruments
 
—

 
57,830

(a)
—

 
57,830

Registered investment companies
 
5,558

(d)
—

 
—

 
5,558

Other
 
—

 
46,968

(f)
—

 
46,968

Total investments
 

$41,864

 

$520,644

 

$—

 

$562,508

Other pending transactions
 
 
 
 
 
 
 
165

Plus:  Other postretirement assets included in the investments of the qualified
pension trust
 
 
 
 
 
 
 
34,954

Total fair value of other
postretirement assets
 
 
 
 
 
 
 

$597,627



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2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Thousands)
Equity securities:
 
 
 
 
 
 
 
 
Common collective trust
 

$—

 

$356,700

(c)

$—

 

$356,700

Fixed income securities:
 
 
 
 
 
 
 
 

U.S. Government securities
 
40,808

(b)
43,471

(a)
—

 
84,279

Corporate debt instruments
 
—

 
50,563

(a)
—

 
50,563

Registered investment
companies
 
4,163

 
(d)
—

 
—

 
4,163

Other
 
—

 
43,458

(f)
—

 
43,458

Total investments
 

$44,971

 

$494,192

 

$—

 

$539,163

Other pending transactions
 
 
 
 
 
 
 
773

Plus:  Other postretirement assets included in the investments of the qualified pension trust
 
 
 
 
 
 
 
29,914

Total fair value of other
postretirement assets
 
 
 
 
 
 
 

$569,850


(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 the common collective trusts estimate fair value.
(d)
The registered investment company is a money market mutual fund with a stable net asset value of one dollar per share.
(e)
The registered investment company holds investments in domestic and international bond markets and estimates fair value using net asset value per share.
(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. Net asset value per share of the 103-12 investment entities estimate fair value.

Accumulated Pension Benefit Obligation

The accumulated benefit obligation for Entergy’s qualified pension plans was $6.6 billion and $5.2 billion at December 31, 2014 and 2013, respectively.


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The qualified pension accumulated benefit obligation for each of the Registrant Subsidiaries for their employees as of December 31, 2014 and 2013 was as follows:
 
December 31,
 
2014
 
2013
 
(In Thousands)
Entergy Arkansas

$1,379,108

 

$1,107,023

Entergy Gulf States Louisiana

$649,932

 

$530,974

Entergy Louisiana

$873,759

 

$697,945

Entergy Mississippi

$399,300

 

$318,941

Entergy New Orleans

$186,473

 

$150,239

Entergy Texas

$391,296

 

$332,484

System Energy

$305,556

 

$247,807


Estimated Future Benefit Payments

Based upon the assumptions used to measure Entergy’s qualified pension and other postretirement benefit obligations at December 31, 2014, 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)
 
 
 
 
 
 
 
2015

$262,792

 

$16,173

 

$78,601

 

$455

2016

$277,307

 

$9,976

 

$80,601

 

$525

2017

$292,841

 

$10,774

 

$83,425

 

$595

2018

$310,200

 

$12,598

 

$88,049

 

$1,785

2019

$328,533

 

$11,431

 

$92,253

 

$1,984

2020 - 2024

$1,966,776

 

$70,791

 

$506,086

 

$13,539


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
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
 
(In Thousands)
Year(s)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015
 

$66,156

 

$25,450

 

$37,892

 

$18,702

 

$7,397

 

$19,078

 

$11,432

2016
 

$67,639

 

$26,805

 

$39,070

 

$19,625

 

$7,836

 

$19,697

 

$11,949

2017
 

$69,207

 

$28,340

 

$40,675

 

$20,517

 

$8,304

 

$20,558

 

$12,357

2018
 

$71,306

 

$30,279

 

$42,336

 

$21,444

 

$8,895

 

$21,448

 

$12,977

2019
 

$73,795

 

$32,445

 

$44,058

 

$22,306

 

$9,368

 

$22,291

 

$13,724

2020 - 2024
 

$418,009

 

$196,323

 

$256,639

 

$125,761

 

$56,659

 

$125,001

 

$87,663


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Estimated Future
Non-Qualified
Pension Benefits Payments
 

 
Entergy
Arkansas
 
 
Entergy
Gulf States
Louisiana
 

 
Entergy
Louisiana
 

 
Entergy
Mississippi
 

Entergy
New Orleans
 

 
Entergy
Texas
 
 
(In Thousands)
Year(s)
 
 
 
 
 
 
 
 
 
 
 
 
2015
 

$347

 

$241

 

$18

 

$119

 

$23

 

$753

2016
 

$300

 

$228

 

$17

 

$115

 

$23

 

$837

2017
 

$291

 

$241

 

$16

 

$124

 

$23

 

$784

2018
 

$282

 

$205

 

$15

 

$114

 

$23

 

$749

2019
 

$339

 

$199

 

$17

 

$112

 

$46

 

$720

2020 - 2024
 

$2,684

 

$924

 

$90

 

$825

 

$199

 

$3,442


Estimated Future
Other Postretirement
Benefits Payments (before Medicare Part D Subsidy)
 
 
Entergy
Arkansas
 
 
Entergy
Gulf States
Louisiana
 
 
 
Entergy
Louisiana
 
 
 
 
 
Entergy
Mississippi
 
 
 
 
Entergy
New Orleans
 
 
 
Entergy
Texas
 
 
 
System
Energy
 
 
(In Thousands)
Year(s)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015
 

$15,699

 

$8,921

 

$9,885

 

$3,926

 

$4,261

 

$6,617

 

$2,796

2016
 

$15,745

 

$9,219

 

$10,016

 

$4,001

 

$4,253

 

$6,785

 

$2,802

2017
 

$15,830

 

$9,580

 

$10,148

 

$4,125

 

$4,280

 

$7,012

 

$2,883

2018
 

$16,305

 

$10,110

 

$10,654

 

$4,433

 

$4,373

 

$7,438

 

$2,984

2019
 

$16,528

 

$10,706

 

$11,048

 

$4,599

 

$4,412

 

$7,771

 

$3,138

2020 - 2024
 

$86,854

 

$59,199

 

$60,735

 

$25,341

 

$21,584

 

$41,303

 

$17,664


Estimated
Future
Medicare Part D
Subsidy
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
 
Entergy
Louisiana
 
 
 
Entergy
Mississippi
 
 
 
Entergy
New Orleans
 
 
 
Entergy
Texas
 
 
 
System
Energy
 
 
(In Thousands)
Year(s)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015
 

$77

 

$37

 

$45

 

$29

 

$23

 

$34

 

$9

2016
 

$87

 

$41

 

$50

 

$32

 

$24

 

$37

 

$11

2017
 

$96

 

$46

 

$56

 

$34

 

$25

 

$40

 

$1

2018
 

$358

 

$168

 

$204

 

$125

 

$87

 

$142

 

$52

2019
 

$398

 

$184

 

$223

 

$136

 

$90

 

$151

 

$59

2020 - 2024
 

$2,593

 

$1,243

 

$1,434

 

$839

 

$506

 

$922

 

$456


Contributions

Entergy currently expects to contribute approximately $396 million to its qualified pension plans and approximately $66.9 million to other postretirement plans in 2015.  The expected 2015 pension and other postretirement plan contributions of the Registrant Subsidiaries for their employees are shown below.  The required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015.


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The Registrant Subsidiaries expect to contribute approximately the following to the qualified pension and other postretirement plans for their employees in 2015:
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
(In Thousands)
Pension Contributions

$92,523

 

$32,455

 

$56,960

 

$22,472

 

$10,910

 

$17,166

 

$20,778

Other Postretirement Contributions

$16,904

 

$8,921

 

$9,885

 

$535

 

$3,669

 

$3,231

 

$475


Actuarial Assumptions

The significant actuarial assumptions used in determining the pension PBO and the other postretirement benefit APBO as of December 31, 2014, and 2013 were as follows:
 
2014
 
2013
Weighted-average discount rate:
 
 
 
Qualified pension
4.03% - 4.40% Blended 4.27%
 
5.04% - 5.26% Blended 5.14%
Other postretirement
4.23%
 
5.05%
Non-qualified pension
3.61%
 
4.29%
Weighted-average rate of increase in future compensation levels
4.23%
 
4.23%
Assumed health care trend rate:
 
 
 
Pre-65
7.10%
 
7.25%
Post-65
7.70%
 
7.00%
Ultimate rate
4.75%
 
4.75%
Year ultimate rate is reached and beyond:

 

    Pre-65
2023
 
2022
    Post-65
2023
 
2022


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The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2014,  2013, and 2012 were as follows:
 
2014
 
2013
 
2012
Weighted-average discount rate:
 
 
 
 
 
Qualified pension
5.04%-5.26% Blended 5.14%
 
4.31% - 4.5% Blended 4.36%
 
5.10% - 5.20% Blended 5.11%
Other postretirement
5.05%
 
4.36%
 
5.10%
Non-qualified pension
4.29%
 
3.37%
 
4.40%
Weighted-average rate of increase
  in future compensation levels
4.23%
 
4.23%
 
4.23%
Expected long-term rate of
  return on plan assets:
 
 
 
 
 
Pension assets
8.50%
 
8.50%
 
8.50%
Other postretirement tax deferred assets
8.30%
 
8.50%
 
8.50%
Other postretirement taxable assets
6.50%
 
6.50%
 
6.50%
Assumed health care trend rate:
 
 
 
 
 
Pre-65
7.25%
 
7.50%
 
7.75%
Post-65
7.00%
 
7.25%
 
7.50%
Ultimate rate
4.75%
 
4.75%
 
4.75%
Year ultimate rate is reached and beyond:

 

 

    Pre-65
2022
 
2022
 
2022
    Post-65
2022
 
2022
 
2022

Entergy’s other postretirement benefit transition obligations were amortized over 20 years ending in 2012.

With respect to mortality assumptions, Entergy used the RP-2014 Employee and Health Annuitant Tables, with a fully generational MP-2014 projection scale, in determining its December 31, 2014 pension plans’ PBOs and other postretirement benefit APBO. The mortality assumptions used in determining Entergy’s December 31, 2013 pension plans’ PBOs were the 1994 Group Annuity Mortality Table and RP 2000 Combined Health Mortality, with generational (using Scale AA) projected mortality improvement. The mortality assumption used in determining the December 31, 2013 other postretirement APBO was the 1994 Group Annuity Mortality Table, with generational (using Scale AA) projected mortality improvement.

A one percentage point change in the assumed health care cost trend rate for 2014 would have the following effects: 
 
 
1 Percentage Point Increase
 
1 Percentage Point Decrease
2014
 
 
 
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
 

$234,971

 

$16,769

 

($190,996
)
 

($13,566
)


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A one percentage point change in the assumed health care cost trend rate for 2014 would have the following effects for the Registrant Subsidiaries for their employees:
 
 
1 Percentage Point Increase
 
1 Percentage Point Decrease
2014
 
 
 
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
 

$39,286

 

$2,448

 

($31,753
)
 

($1,971
)
Entergy Gulf States Louisiana
 

$27,929

 

$2,092

 

($22,591
)
 

($1,671
)
Entergy Louisiana
 

$23,779

 

$1,681

 

($19,452
)
 

($1,366
)
Entergy Mississippi
 

$10,596

 

$754

 

($8,596
)
 

($606
)
Entergy New Orleans
 

$6,373

 

$386

 

($5,317
)
 

($321
)
Entergy Texas
 

$16,246

 

$1,148

 

($13,397
)
 

($927
)
System Energy
 

$8,716

 

$734

 

($7,044
)
 

($586
)

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 employing Entergy subsidiary makes matching contributions to the System Savings Plan for all eligible participating employees in an amount equal to either 70% or 100% of the participants’ basic contributions, up to 6% of their eligible earnings per pay period.  The matching contribution is allocated to investments as directed by the employee.

Entergy also sponsors the Savings Plan of Entergy Corporation and Subsidiaries 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 $43.3 million in 2014, $44.5 million in 2013, and $43.7 million in 2012.  The majority of the contributions were to the System Savings Plan.

The Registrant Subsidiaries’ 2014, 2013, and 2012 contributions to defined contribution plans for their employees were as follows:
 
 
Year
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
(In Thousands)
2014
 

$3,044

 

$1,867

 

$2,266

 

$1,855

 

$710

 

$1,563

2013
 

$3,351

 

$1,906

 

$2,393

 

$1,954

 

$769

 

$1,616

2012
 

$3,223

 

$1,842

 

$2,327

 

$1,875

 

$740

 

$1,601



NOTE 12.    STOCK-BASED COMPENSATION (Entergy Corporation)

Entergy grants stock options, restricted stock, performance units, and restricted unit awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans which are shareholder-approved stock-based compensation

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plans.  The Equity Ownership Plan, as restated in February 2003 (2003 Plan), had 885,200 authorized shares remaining for long-term incentive and restricted unit awards as of December 31, 2014.  Effective January 1, 2007, Entergy’s shareholders approved the 2007 Equity Ownership and Long-Term Cash Incentive Plan (2007 Plan).  The maximum aggregate number of common shares that can be issued from the 2007 Plan for stock-based awards is 7,000,000 with no more than 2,000,000 available for non-option grants.  The 2007 Plan, which only applies to awards made on or after January 1, 2007, will expire after 10 years.  As of December 31, 2014, there were 1,104,547 authorized shares remaining for stock-based awards, all of which are available for non-option grants.  Effective May 6, 2011, Entergy’s shareholders approved the 2011 Equity Ownership and Long-Term Cash Incentive Plan (2011 Plan).  The maximum number of common shares that can be issued from the 2011 Plan for stock-based awards is 5,500,000 with no more than 2,000,000 available for incentive stock option grants.  The 2011 Plan, which only applies to awards made on or after May 6, 2011, will expire after 10 years.  As of December 31, 2014, there were 1,579,563 authorized shares remaining for stock-based awards, including 2,000,000 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 ten 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:
 
2014
 
2013
 
2012
 
(In Millions)
Compensation expense included in Entergy’s Consolidated Net Income
$4.1
 
$4.1
 
$7.7
Tax benefit recognized in Entergy’s Consolidated Net Income
$1.6
 
$1.6
 
$3.0
Compensation cost capitalized as part of fixed assets and inventory
$0.7
 
$0.7
 
$1.5

Entergy determines the fair value of the stock option grants by considering factors such as lack of marketability, stock retention requirements, and regulatory restrictions on exercisability in accordance with accounting standards.  The stock option weighted-average assumptions used in determining the fair values are as follows:
 
2014
 
2013
 
2012
Stock price volatility
24.67%
 
24.61%
 
25.11%
Expected term in years
6.95
 
6.69
 
6.55
Risk-free interest rate
2.16%
 
1.31%
 
1.22%
Dividend yield
4.75%
 
4.75%
 
4.50%
Dividend payment per share
$3.32
 
$3.32
 
$3.32

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 after-tax net profit upon exercise of the option to be held in Entergy Corporation common stock.  The reduction in fair value of the stock options due to this restriction is based upon an estimate of the call option value of the reinvested gain discounted to present value over the applicable reinvestment period. 


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A summary of stock option activity for the year ended December 31, 2014 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, 2014
9,639,849

 
$80.06
 
 
 
 
Options granted
611,700

 
$63.17
 
 
 
 
Options exercised
(2,852,350
)
 
$68.19
 
 
 
 
Options forfeited/expired
(117,803
)
 
$82.48
 
 
 
 
Options outstanding as of December 31, 2014
7,281,396

 
$83.25
 
$30,830,809
 
4.3 years
Options exercisable as of December 31, 2014
6,232,998

 
$86.41
 
$6,657,504
 
3.6 years
Weighted-average grant-date fair value of
options granted during 2014
$8.71
 
 
 
 
 
 

The weighted-average grant-date fair value of options granted during the year was $8.00 for 2013 and $9.42 for 2012.  The total intrinsic value of stock options exercised was $25.5 million during 2014, $5.7 million during 2013, and $39.8 million during 2012.  The intrinsic value, which has no effect on net income, of the stock options exercised is calculated by the difference in Entergy Corporation’s common stock price on the date of exercise and the exercise price of the stock options granted.  The aggregate intrinsic value of the stock options outstanding as of December 31, 2014 was $30.8 million. Entergy recognizes compensation cost over the vesting period of the options based on their grant-date fair value.  The total fair value of options that vested was approximately $4 million during 2014, $11 million during 2013, and $11 million during 2012.

The following table summarizes information about stock options outstanding as of December 31, 2014:
 
 
 
Options Outstanding
 
Options Exercisable
Range of
 
As of
 
Weighted-Avg.
Remaining
Contractual
Life-Yrs.
 
Weighted
Avg. Exercise
Price
 
Number
Exercisable
as of
 
Weighted
Avg. Exercise
Price
Exercise Prices
 
12/31/2014
 
 
 
12/31/2014
 

$51
 -
$64.99
 
1,138,602

 
8.6
 
$63.84
 
192,152

 
$64.60

$65
 -
$78.99
 
3,095,377

 
4.4
 
$74.31
 
2,993,429

 
$74.41

$79
 -
$91.99
 
1,604,717

 
2.1
 
$91.82
 
1,604,717

 
$91.82

$92
 -
$108.20
 
1,442,700

 
3.1
 
$108.20
 
1,442,700

 
$108.20

$51
 -
$108.20
 
7,281,396

 
4.3
 
$83.25
 
6,232,998

 
$86.41

Stock-based compensation cost related to non-vested stock options outstanding as of December 31, 2014 not yet recognized is approximately $5.4 million and is expected to be recognized over a weighted-average period of 1.7 years.

Restricted Stock Awards

In January 2014 the Board approved and Entergy granted 352,600 restricted stock awards under the 2011 Equity Ownership and Long-term Cash Incentive Plan.  The restricted stock awards were made effective as of January 30, 2014 and were valued at $63.17 per share, which was the closing price of Entergy Corporation’s common stock on that date.  One-third of the restricted stock awards will vest upon each anniversary of the grant date and are expensed

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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.

The following table includes financial information for restricted stock for each of the years presented:
 
2014
 
2013
 
2012
 
(In Millions)
Compensation expense included in Entergy’s Consolidated Net Income
$19.3
 
$16.4
 
$11.4
Tax benefit recognized in Entergy’s Consolidated Net Income
$7.5
 
$6.3
 
$4.4
Compensation cost capitalized as part of fixed assets and inventory
$3.1
 
$2.6
 
$2.0

Long-Term Performance Unit Program

Entergy grants long-term incentive awards earned under its stock benefit plans in the form of performance units, which are equal to the cash value of shares of Entergy Corporation common stock at the end of the performance period, which is the last trading day of the year.  Performance units will pay out to the extent that the performance conditions are satisfied.  In addition to the potential for equivalent share appreciation or depreciation, performance units will earn the cash equivalent of the dividends paid during the 3-year performance period applicable to each plan.  The costs of incentive awards are charged to income over the 3-year period.  Beginning with the 2012-2014 performance period, upon vesting, the performance units granted under the Long-Term Performance Unit Program will be settled in shares of Entergy common stock rather than cash.  In January 2014 the Board approved and Entergy granted 226,792 performance units under the 2011 Equity Ownership and Long-Term Cash Incentive Plan.  The performance units were made effective as of January 30, 2014, and were valued at $67.16 per share. Entergy considers factors, primarily market conditions, in determining the value of the performance units. 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 financial information for the long-term performance units for each of the years presented:
 
2014
 
2013
 
2012
 
(In Millions)
Fair value of long-term performance units as of December 31,
$23.4
 

$11.1

 

$4.3

Compensation expense included in Entergy’s Consolidated Net Income
$10.7
 

$6.0

 

($5.0
)
Tax benefit (expense) recognized in Entergy’s Consolidated Net Income
$4.1
 

$2.3

 

($1.9
)
Compensation cost capitalized as part of fixed assets and inventory
$1.5
 

$0.9

 

($0.9
)

There was no payout in 2014 for the performance units granted in 2011 applicable to the 2011 – 2013 performance period.

Restricted Unit Awards

Entergy grants restricted unit awards earned under its stock benefit plans in the form of stock units that are subject to time-based restrictions.  The restricted units are equal to the cash value of shares of Entergy Corporation common stock at the time of vesting.  The costs of restricted unit awards are charged to income over the restricted period, which varies from grant to grant.  The average vesting period for restricted unit awards granted is 36 months.  As of December 31, 2014, there were 98,334 unvested restricted units that are expected to vest over an average period of 21 months.


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The following table includes financial information for restricted unit awards for each of the years presented:
 
2014
 
2013
 
2012
 
(In Millions)
Fair value of restricted awards as of December 31,
$3.3
 
$2.5
 
$3.0
Compensation expense included in Entergy’s Consolidated Net Income
$2.2
 
$1.4
 
$1.3
Tax benefit recognized in Entergy’s Consolidated Net Income
$0.9
 
$0.6
 
$0.5
Compensation cost capitalized as part of fixed assets and inventory
$0.3
 
$0.2
 
$0.2

Entergy paid $1.7 million in 2014 for awards under the Restricted Units Awards Plan.


NOTE 13. BUSINESS SEGMENT INFORMATION  (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi,  Entergy New Orleans, Entergy Texas, and System Energy)

Entergy’s reportable segments as of December 31, 2014 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.

Entergy’s segment financial information is as follows:
2014
 
 
 
Utility
 
Entergy
Wholesale
Commodities*
 
 
 
All Other
 
 
 
Eliminations
 
 
 
Consolidated
 
 
(In Thousands)
Operating revenues
 

$9,773,822

 

$2,719,404

 

$1,821

 

($126
)
 

$12,494,921

Depreciation, amortization, & decommissioning
 

$1,170,122

 

$417,435

 

$3,702

 

$—

 

$1,591,259

Interest and investment income
 

$171,217

 

$113,959

 

$22,159

 

($159,649
)
 

$147,686

Interest expense
 

$531,729

 

$16,646

 

$120,908

 

($41,776
)
 

$627,507

Income taxes
 

$472,148

 

$176,988

 

($59,539
)
 

$—

 

$589,597

Consolidated net income (loss)
 

$846,496

 

$294,521

 

($62,887
)
 

($117,873
)
 

$960,257

Total assets
 

$38,295,309

 

$10,279,500

 

($654,831
)
 

($1,392,124
)
 

$46,527,854

Investment in affiliates - at equity
 

$199

 

$36,035

 

$—

 

$—

 

$36,234

Cash paid for long-lived asset
additions
 

$2,113,631

 

$615,021

 

$87

 

$—

 

$2,728,739



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2013
 
 
 
Utility
 
Entergy
Wholesale
Commodities*
 
 
 
All Other
 
 
 
Eliminations
 
 
 
Consolidated
 
 
(In Thousands)
Operating revenues
 

$9,101,786

 

$2,312,758

 

$3,558

 

($27,155
)
 

$11,390,947

Depreciation, amortization, & decommissioning
 

$1,157,843

 

$341,163

 

$4,142

 

$—

 

$1,503,148

Interest and investment income
 

$186,724

 

$137,727

 

$24,179

 

($149,330
)
 

$199,300

Interest expense
 

$509,173

 

$16,323

 

$122,291

 

($43,750
)
 

$604,037

Income taxes
 

$365,917

 

($77,471
)
 

($62,465
)
 

$—

 

$225,981

Consolidated net income (loss)
 

$846,215

 

$42,976

 

($53,039
)
 

($105,580
)
 

$730,572

Total assets
 

$35,539,585

 

$9,696,705

 

($486,438
)
 

($1,343,406
)
 

$43,406,446

Investment in affiliates - at equity
 

$199

 

$40,151

 

$—

 

$—

 

$40,350

Cash paid for long-lived asset
additions
 

$2,268,083

 

$626,322

 

$49

 

$—

 

$2,894,454


2012
 
 
 
Utility
 
Entergy
Wholesale
Commodities*
 
 
 
All Other
 
 
 
Eliminations
 
 
 
Consolidated
 
 
(In Thousands)
Operating revenues
 

$8,005,091

 

$2,326,309

 

$4,048

 

($33,369
)
 

$10,302,079

Depreciation, amortization, & decommissioning
 

$1,076,845

 

$248,143

 

$4,357

 

$—

 

$1,329,345

Interest and investment income
 

$150,292

 

$105,062

 

$30,656

 

($158,234
)
 

$127,776

Interest expense
 

$476,485

 

$17,900

 

$126,913

 

($52,014
)
 

$569,284

Income taxes
 

$49,340

 

$61,329

 

($79,814
)
 

$—

 

$30,855

Consolidated net income (loss)
 

$960,322

 

$40,427

 

($26,167
)
 

($106,219
)
 

$868,363

Total assets
 

$35,438,130

 

$9,623,345

 

($509,985
)
 

($1,348,988
)
 

$43,202,502

Investment in affiliates - at equity
 

$199

 

$46,539

 

$—

 

$—

 

$46,738

Cash paid for long-lived asset
additions
 

$3,182,695

 

$577,652

 

$619

 

$—

 

$3,760,966


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.

Earnings were negatively affected by expenses in 2013 of approximately $110 million ($70 million after-tax), including approximately $85 million ($55 million after-tax) for Utility and $25 million ($15 million after-tax) for Entergy Wholesale Commodities, and expenses in 2014 of approximately $20 million ($12 million after-tax), including approximately $15 million ($9 million after-tax) for Utility and $5 million ($3 million after-tax) for Entergy Wholesale Commodities, recorded in connection with a strategic imperative intended to optimize the organization through a process known as human capital management. In July 2013 management completed a comprehensive review of Entergy’s organization design and processes. This effort resulted in a new internal organization structure, which resulted in the elimination of approximately 800 employee positions. The restructuring costs associated with this phase of human capital management included implementation costs, severance expenses, benefits-related costs, including pension curtailment losses and special termination benefits, and impairments of corporate property, plant, and equipment. The implementation costs, severance costs, and benefits-related costs are included in “Other operation and maintenance” in the consolidated income statements. The property, plant, and equipment impairments are included in “Asset write-offs, impairments, and related charges” in the consolidated income statements. Total restructuring charges were comprised of the following:

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2013
 
2014
 
Remaining Accrual as of December 31, 2014
 
Restructuring Costs
 
Paid In Cash
 
Non-Cash Portion
 
Restructuring Costs
 
Paid In Cash
 
Non-Cash Portion
 
 
(In Millions)
Implementation costs

$19

 

$19

 

$—

 

$9

 

$9

 

$—

 

$—

Severance costs
45

 
6

 
—

 
11

 
44

 
—

 
6

Benefits-related costs
26

 
—

 
26

 
—

 
—

 
—

 
—

Property, plant, and equipment impairments
20

 
—

 
20

 
—

 
—

 
—

 
—

  Total

$110

 

$25

 

$46

 

$20

 

$53

 

$—

 

$6


Geographic Areas

For the years ended December 31, 2014, 2013, and 2012, the amount of revenue Entergy derived from outside of the United States was insignificant.  As of December 31, 2014 and 2013, Entergy had no long-lived assets located outside of the United States.

Registrant Subsidiaries

Each of the Registrant Subsidiaries has one reportable segment, which is an integrated utility business, except for System Energy, which is an electricity generation business.  Each of the Registrant Subsidiaries’ operations is managed on an integrated basis by that company because of the substantial effect of cost-based rates and regulatory oversight on the business process, cost structures, and operating results.


NOTE 14.  EQUITY METHOD INVESTMENTS (Entergy Corporation)

As of December 31, 2014, Entergy owns investments in the following companies that it accounts for under the equity method of accounting:
Investment
 
Ownership
 
Description
 
 
 
 
 
 
RS Cogen LLC
 
50
%
member interest
 
Co-generation project that produces power and steam on an industrial and merchant basis in the Lake Charles, Louisiana area.
 
 
 
 
 
 
Top Deer
 
50
%
member interest
 
Wind-powered electric generation joint venture.

Following is a reconciliation of Entergy’s investments in equity affiliates:
 
2014
 
2013
 
2012
 
(In Thousands)
Beginning of year

$40,350

 

$46,738

 

$44,876

Income (loss) from the investments
(5,169
)
 
(1,702
)
 
1,162

Dispositions and other adjustments
1,053

 
(4,686
)
 
700

End of year

$36,234

 

$40,350

 

$46,738



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Transactions with equity method investees

Entergy Gulf States Louisiana purchased approximately $3.2 million in 2013 and $2.8 million in 2012 of electricity generated from Entergy’s share of RS Cogen. Entergy Gulf States Louisiana made no purchases in 2014 of electricity generated from Entergy’s share of RS Cogen. Entergy’s operating transactions with its other equity method investees were not significant in 2014, 2013, or 2012.


NOTE 15.  ACQUISITIONS AND DISPOSITIONS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and Entergy Mississippi)

Acquisitions

Hot Spring Energy Facility

In November 2012, Entergy Arkansas purchased the Hot Spring Energy Facility, a 620 MW combined-cycle natural gas turbine unit located in Malvern, Arkansas, from KGen Hot Spring LLC for approximately $253 million.  The FERC and the APSC approved the transaction.

Hinds Energy Facility

In November 2012, Entergy Mississippi purchased the Hinds Energy Facility, a 450 MW combined-cycle natural gas turbine unit located in Jackson, Mississippi, from KGen Hinds LLC for approximately $206 million.  The FERC and the MPSC approved the transaction.

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 difference between 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 $16 million in 2014, $18 million in 2013, and $17 million in 2012.  The amounts to be amortized to revenue for the next five years will be $15 million in 2015, $13 million for 2016, $12 million for 2017, $8 million for 2018, and $13 million for 2019.

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 cap of $24 million.  The annual payment for each year’s output was due by January 15 of the following year.  Entergy recorded the liability for payments to NYPA as power is 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.  In 2014, 2013, and 2012, Entergy Wholesale Commodities recorded approximately $72 million as plant for generation during each of those years.  This amount was depreciated over the expected remaining useful life of the plants.


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Dispositions

In November 2013, Entergy sold Entergy Solutions District Energy, a business wholly-owned by Entergy in the Entergy Wholesale Commodities segment that owns and operates district energy assets serving the business districts in Houston and New Orleans. Entergy sold Entergy Solutions District Energy for $140 million and realized a pre-tax gain of $44 million on the sale.


NOTE 16.  RISK MANAGEMENT AND FAIR VALUES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi,  Entergy New Orleans, Entergy Texas, and System Energy)

Market Risk

In the normal course of business, Entergy is exposed to a number of market risks.  Market risk is the potential loss that Entergy may incur as a result of changes in the market or fair value of a particular commodity or instrument.  All financial and commodity-related instruments, including derivatives, are subject to market risk including commodity price risk, equity price, and interest rate risk.  Entergy uses derivatives primarily to mitigate commodity price risk, particularly power price and fuel price risk.

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

As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers.  Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy and capacity in the day ahead or spot markets.  In addition to its forward physical power 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

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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 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 is currently hedging the variability in future cash flows with derivatives for forecasted power transactions at December 31, 2014 is approximately 3 years.  Planned generation currently under contract from Entergy Wholesale Commodities nuclear power plants is 86% for 2015, of which approximately 62% is sold under financial derivatives and the remainder under normal purchase/normal sale contracts.  Total planned generation for 2015 is 35 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. 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 collateral to secure its obligations when the current market prices exceed the contracted power prices.  The primary form of collateral to satisfy these requirements is an Entergy Corporation guarantee.  As of December 31, 2014, derivative contracts with 1 counterparty were in a liability position (approximately $1 million total). As of December 31, 2013, derivative contracts with 9 counterparties were in a liability position (approximately $187 million total). In addition to the corporate guarantee, $47 million in cash collateral was required to be posted. If the Entergy Corporation credit rating falls below investment grade, the effect of the corporate guarantee is typically ignored and 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 Gulf States Louisiana, 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 and projected winter purchases for gas distribution at Entergy Gulf States Louisiana and Entergy New Orleans. The total volume of natural gas swaps outstanding as of December 31, 2014 is 21,475,000 MMBtu for Entergy, including 8,740,000 MMBtu for Entergy Gulf States Louisiana, 8,810,000 MMBtu for Entergy Louisiana, 3,230,000 MMBtu for Entergy Mississippi, and 695,000 MMBtu for Entergy New Orleans.  Credit support for these natural gas swaps is covered by master agreements that do not require collateralization based on mark-to-market value, but do carry adequate assurance language that may lead to collateralization requests.

During the second quarter 2014, Entergy participated in the annual FTR auction process for the MISO planning year of June 1, 2014 through May 31, 2015. FTRs 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 FTRs 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 FTRs 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 FTRs. The total volume of FTRs outstanding as of December 31, 2014 is 45,196 GWh for Entergy, including 9,844 GWh for Entergy Arkansas, 9,881 GWh for Entergy Gulf States Louisiana, 10,691 GWh for Entergy Louisiana, 5,403 GWh for Entergy Mississippi, 3,633 GWh for Entergy New Orleans, and 5,669 GWh for Entergy Texas. Credit support for FTRs held by the Utility operating

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companies is covered by cash or letters of credit issued by each Utility operating company as required by MISO. Credit support for FTRs held by Entergy Wholesale Commodities is covered by cash. As of December 31, 2014, letters of credit posted with MISO covered the FTR exposure for Entergy Arkansas and Entergy Mississippi. No cash collateral was required to be posted for FTR exposure for the Utility operating companies or Entergy Wholesale Commodities.

The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 2014 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)
 
$149
 
($53)
 
$96
 
Entergy Wholesale Commodities
Electricity swaps and options

Other deferred debits and other assets (non-current portion)
 
$48
 
$—
 
$48
 
Entergy Wholesale Commodities
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Other current liabilities (current portion)
 
$24
 
($24)
 
$—
 
Entergy Wholesale Commodities
Derivatives not designated as hedging instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Prepayments and other (current portion)
 
$97
 
($25)
 
$72
 
Entergy Wholesale Commodities
Electricity swaps and options
 
Other deferred debits and other assets (non-current portion)
 
$9
 
($8)
 
$1
 
Entergy Wholesale Commodities
FTRs
 
Prepayments and other
 
$50
 
($3)
 
$47
 
Utility and Entergy Wholesale Commodities
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Other current liabilities (current portion)
 
$57
 
($55)
 
$2
 
Entergy Wholesale Commodities
Electricity swaps and options
 
Other non-current liabilities (non-current portion)
 
$8
 
($8)
 
$—
 
Entergy Wholesale Commodities
Natural gas swaps
 
Other current liabilities
 
$20
 
$—
 
$20
 
Utility


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The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 2013 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)
 
$118
 
($99)
 
$19
 
Entergy Wholesale Commodities
Electricity swaps and options
 
Other deferred debits and other assets (non-current portion)
 
$17
 
($17)
 
$—
 
Entergy Wholesale Commodities
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Other current liabilities (current portion)
 
$197
 
($131)
 
$66
 
Entergy Wholesale Commodities
Electricity swaps and options
 
Other non-current liabilities (non-current portion)
 
$46
 
($17)
 
$29
 
Entergy Wholesale Commodities
Derivatives not designated as hedging instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Prepayments and other (current portion)
 
$177
 
($122)
 
$55
 
Entergy Wholesale Commodities
Natural gas swaps
 
Prepayments and other
 
$6
 
$—
 
$6
 
Utility
FTRs
 
Prepayments and other
 
$36
 
($2)
 
$34
 
Utility and Entergy Wholesale Commodities
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
Electricity swaps and options
 
Other current liabilities (current portion)
 
$201
 
($89)
 
$112
 
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 Consolidated Balance Sheets
(d)
Excludes cash collateral in the amounts of $25 million held as of December 31, 2014 and $47 million posted and $4 million held as of December 31, 2013, respectively


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The effect of Entergy’s derivative instruments designated as cash flow hedges on the consolidated income statements for the years ended December 31, 2014, 2013, and 2012 are as follows:
 
 
Instrument
 
Amount of gain (loss)
recognized in other
comprehensive income
 
 
 
Income Statement location
 
Amount of gain (loss) reclassified from
AOCI into income (a)
 
 
(In Millions)
 
 
 
(In Millions)
2014
 
 
 
 
 
 
Electricity swaps and options
 
$81
 
Competitive business operating revenues
 
($193)
 
 
 
 
 
 
 
2013
 
 
 
 
 
 
Electricity swaps and options
 
($190)
 
Competitive business operating revenues
 
$47
 
 
 
 
 
 
 
2012
 
 
 
 
 
 
Electricity swaps and options
 
$111
 
Competitive business operating revenues
 
$268

(a)
Before taxes of ($68) million, $18 million, and $94 million, for the years ended December 31, 2014, 2013, and 2012, 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 $7 million, ($6) million, and ($14) million for the years ended December 31, 2014, 2013, and 2012, respectively.
   
Based on market prices as of December 31, 2014, unrealized gains recorded in AOCI on cash flow hedges relating to power sales totaled $156 million of net unrealized gains.  Approximately $109 million is expected to be reclassified from AOCI to operating revenues in the next twelve months.  The actual amount reclassified from AOCI, 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 effect of Entergy’s derivative instruments not designated as hedging instruments on the consolidated income statements for the years ended December 31, 2014, 2013, and 2012 is as follows:
 
Instrument
 
Amount of gain (loss)
recognized in AOCI
 
Income Statement
location
 
Amount of gain (loss)
recorded in the income statement
 
 
(In Millions)
 
 
 
(In Millions)
2014
 
 
 
 
 
 
Natural gas swaps
 
—
 
Fuel, fuel-related expenses, and gas purchased for resale
(a)
($8)
FTRs
 
—
 
Purchased power expense
(b)
$229
Electricity swaps and options
 
($13)
 
Competitive business operating revenues
 
$56
 
 
 
 
 
 
 
2013
 
 
 
 
 
 
Natural gas swaps
 
—
 
Fuel, fuel-related expenses, and gas purchased for resale
(a)
$13
FTRs
 
—
 
Purchased power
(b)
$3
Electricity swaps and options
 
$1
 
Competitive business operating revenues
 
($50)
 
 
 
 
 
 
 
2012
 
 
 
 
 
 
Natural gas swaps
 
—
 
Fuel, fuel-related expenses, and gas purchased for resale
(a)
($42)
Electricity swaps and options
 
$1
 
Competitive business operating revenues
 
$1

(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 FTRs 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 FTRs for the Utility operating companies are settled are recovered or refunded through fuel cost recovery mechanisms.


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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, 2014 and 2013 are as follows:
Instrument
 
Balance Sheet Location
 
Fair Value (a)
 
Registrant
 
 
 
 
(In Millions)
 
 
2014
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
FTRs
 
Prepayments and other
 
$0.7
 
Entergy Arkansas
FTRs
 
Prepayments and other
 
$14.4
 
Entergy Gulf States Louisiana
FTRs
 
Prepayments and other
 
$11.1
 
Entergy Louisiana
FTRs
 
Prepayments and other
 
$3.4
 
Entergy Mississippi
FTRs
 
Prepayments and other
 
$4.1
 
Entergy New Orleans
FTRs
 
Prepayments and other
 
$12.3
 
Entergy Texas
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Natural gas swaps
 
Other current liabilities
 
$8.2
 
Entergy Gulf States Louisiana
Natural gas swaps
 
Other current liabilities
 
$7.6
 
Entergy Louisiana
Natural gas swaps
 
Other current liabilities
 
$2.8
 
Entergy Mississippi
Natural gas swaps
 
Other current liabilities
 
$0.9
 
Entergy New Orleans
 
 
 
 
 
 
 
2013
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
Natural gas swaps
 
Gas hedge contracts
 
$2.2
 
Entergy Gulf States Louisiana
Natural gas swaps
 
Gas hedge contracts
 
$2.9
 
Entergy Louisiana
Natural gas swaps
 
Prepayments and other
 
$0.7
 
Entergy Mississippi
Natural gas swaps
 
Prepayments and other
 
$0.1
 
Entergy New Orleans
 
 
 
 
 
 
 
FTRs
 
Prepayments and other
 
$6.7
 
Entergy Gulf States Louisiana
FTRs
 
Prepayments and other
 
$5.7
 
Entergy Louisiana
FTRs
 
Prepayments and other
 
$1.0
 
Entergy Mississippi
FTRs
 
Prepayments and other
 
$2.0
 
Entergy New Orleans
FTRs
 
Prepayments and other
 
$18.4
 
Entergy Texas

(a)
No cash collateral was required to be posted as of December 31, 2014 and 2013, respectively.


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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, 2014, 2013, and 2012 are as follows:
 
 
Instrument
 
Income Statement Location
 
Amount of gain (loss)
recorded
in the income statement
 
 
 
Registrant
 
 
 
 
(In Millions)
 
 
2014
 
 
 
 
 
 
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
($3.9)
 
Entergy Gulf States Louisiana
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
($1.6)
 
Entergy Louisiana
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
($2.5)
 
Entergy Mississippi
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
($0.2)
 
Entergy New Orleans
 
 
 
 
 
 
 
FTRs
 
Purchased power
 
$21.6
 
Entergy Arkansas
FTRs
 
Purchased power
 
$56.3
 
Entergy Gulf States Louisiana
FTRs
 
Purchased power
 
$47.2
 
Entergy Louisiana
FTRs
 
Purchased power
 
$19.0
 
Entergy Mississippi
FTRs
 
Purchased power
 
$16.5
 
Entergy New Orleans
FTRs
 
Purchased power
 
$65.8
 
Entergy Texas
 
 
 
 
 
 
 
2013
 
 
 
 
 
 
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
$4.5
 
Entergy Gulf States Louisiana
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
$6.0
 
Entergy Louisiana
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
$2.5
 
Entergy Mississippi
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
$0.1
 
Entergy New Orleans
 
 
 
 
 
 
 
FTRs
 
Purchased power
 
($0.1)
 
Entergy Arkansas
FTRs
 
Purchased power
 
$0.3
 
Entergy Gulf States Louisiana
FTRs
 
Purchased power
 
$0.2
 
Entergy Louisiana
FTRs
 
Purchased power
 
$1.0
 
Entergy Mississippi
FTRs
 
Purchased power
 
$1.2
 
Entergy New Orleans
FTRs
 
Purchased power
 
$0.8
 
Entergy Texas
 
 
 
 
 
 
 
2012
 
 
 
 
 
 
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
($12.9)
 
Entergy Gulf States Louisiana
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
($16.2)
 
Entergy Louisiana
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
($11.2)
 
Entergy Mississippi
Natural gas swaps
 
Fuel, fuel-related expenses, and gas purchased for resale
 
($1.5)
 
Entergy New Orleans

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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
-
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 or shares in common trusts.  Common trust funds are stated at estimated fair value based on the fair market value of the underlying investments.

•
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 FTRs 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

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valuations of these assets and liabilities are performed by the Entergy Wholesale Commodities Risk Control group and the Entergy Wholesale Commodities Accounting Policy and External Reporting group.  The primary functions of the Entergy Wholesale Commodities 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 Risk Control group is also responsible for managing the energy trading and risk management system, forecasting revenues, forward positions and analysis.  The Entergy Wholesale Commodities Accounting Policy and External Reporting group performs functions related to market and counterparty settlements, revenue reporting and analysis and financial accounting. The Entergy Wholesale Commodities Risk Control group reports to the Vice President and Treasurer while the Entergy Wholesale Commodities Accounting Policy and External Reporting group reports to the Vice President, Accounting Policy and External Reporting.

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 US 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, Entergy Wholesale Commodities Risk Control group calculates the mark-to-market for electricity swaps and options.  Entergy Wholesale Commodities 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 uses multiple 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 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 FTRs are based on unobservable inputs, including estimates of future congestion costs in MISO between applicable generation and load pricing nodes based on prices published by MISO.  They are classified as Level 3 assets and liabilities.  The valuations of these assets and liabilities are performed by the Entergy Wholesale Commodities Risk Control group for the unregulated business and by the System Planning and Operations Risk Control group for the Utility operating companies.  Entergy’s Accounting Policy group reviews these valuations for reasonableness, with the assistance of others within the organization with knowledge of the various inputs and

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assumptions used in the valuation. The System Planning and Operations Risk Control group reports to the Vice President and Treasurer.  The Accounting Policy group reports to the Vice President, Accounting Policy and External Reporting.

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, 2014 and December 31, 2013.  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.
2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$1,291

 

$—

 

$—

 

$1,291

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
452

 
2,834

(b)
—

 
3,286

Debt securities
 
880

 
1,205

 
—

 
2,085

Power contracts
 
—

 
—

 
217

 
217

Securitization recovery trust account
 
44

 
—

 
—

 
44

Escrow accounts
 
362

 
—

 
—

 
362

FTRs
 
—

 
—

 
47

 
47

 
 

$3,029

 

$4,039

 

$264

 

$7,332

Liabilities:
 
 
 
 
 
 
 
 
Power contracts
 

$—

 

$—

 

$2

 

$2

Gas hedge contracts
 
20

 
—

 
—

 
20

 
 

$20

 

$—

 

$2

 

$22


2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$609

 

$—

 

$—

 

$609

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
472

 
2,601

(b)
—

 
3,073

Debt securities
 
783

 
1,047

 
—

 
1,830

Power contracts
 
—

 
—

 
74

 
74

Securitization recovery trust account
 
46

 
—

 
—

 
46

Escrow accounts
 
115

 
—

 
—

 
115

Gas hedge contracts
 
6

 
—

 
—

 
6

FTRs
 
—

 
—

 
34

 
34

 
 

$2,031

 

$3,648

 

$108

 

$5,787

Liabilities:
 
 
 
 
 
 
 
 
Power contracts
 

$—

 

$—

 

$207

 

$207


(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 17 to the financial statements for additional information on the investment portfolios.
(b)
Commingled equity funds may be redeemed semi-monthly.


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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 years ended December 31, 2014, 2013, and 2012:
 
2014
 
2013
 
2012
 
Power Contracts
 
FTRs
 
Power Contracts
 
FTRs
 
Power Contracts
 
(In Millions)
Balance as of January 1,

($133
)
 

$34

 

$178

 

$—

 

$312

Realized losses included in earnings
(65
)
 
—

 
(38
)
 
—

 
(11
)
Unrealized gains (losses) included in earnings
120

 
2

 
(35
)
 
—

 
(4
)
Unrealized gains (losses) included in OCI
131

 
—

 
(204
)
 
—

 
140

Unrealized gains included as a regulatory liability / asset
—

 
119

 
—

 
—

 
—

Issuances of FTRs
—

 
121

 
—

 
37

 
—

Purchases
17

 
—

 
14

 
—

 
9

Settlements
145

 
(229
)
 
(48
)
 
(3
)
 
(268
)
Balance as of December 31,

$215

 

$47

 

($133
)
 

$34

 

$178


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, 2014:
Transaction Type
 
Fair Value
as of
December 31,
2014
 
Significant
Unobservable Inputs
 
Range
from
Average
%
 
Effect on
Fair Value
 
 
(In Millions)
 
 
 
 
 
(In Millions)
Electricity swaps
 
$165
 
Unit contingent discount
 
+/-3%
 
$10
Electricity options
 
$50
 
Implied volatility
 
+/-130%
 
$43
 
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)
Implied volatility
 
Electricity options
 
Sell
 
Increase (Decrease)
 
Increase (Decrease)
Implied volatility
 
Electricity options
 
Buy
 
Increase (Decrease)
 
Increase (Decrease)










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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, 2014 and December 31, 2013.  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
2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$208.0

 

$—

 

$—

 

$208.0

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
7.2

 
480.1

(b)
—

 
487.3

Debt securities
 
72.2

 
210.4

 
—

 
282.6

Securitization recovery trust account
 
4.1

 
—

 
—

 
4.1

Escrow accounts
 
12.2

 
—

 
—

 
12.2

FTRs
 
—

 
—

 
0.7

 
0.7

 
 

$303.7

 

$690.5

 

$0.7

 

$994.9


2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$122.8

 

$—

 

$—

 

$122.8

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
13.6

 
449.7

(b)
—

 
463.3

Debt securities
 
58.6

 
189.0

 
—

 
247.6

Securitization recovery trust account
 
3.8

 
—

 
—

 
3.8

Escrow accounts
 
26.0

 
—

 
—

 
26.0

 
 

$224.8

 

$638.7

 

$—

 

$863.5


Entergy Gulf States Louisiana
2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$109.6

 

$—

 

$—

 

$109.6

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
10.5

 
385.4

(b)
—

 
395.9

Debt securities
 
81.9

 
159.9

 
—

 
241.8

Escrow accounts
 
90.1

 
—

 
—

 
90.1

FTRs
 
—

 
—

 
14.4

 
14.4

 
 

$292.1

 

$545.3

 

$14.4

 

$851.8

 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
Gas hedge contracts
 

$8.2

 

$—

 

$—

 

$8.2



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2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$13.8

 

$—

 

$—

 

$13.8

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
27.6

 
343.2

(b)
—

 
370.8

Debt securities
 
71.7

 
131.2

 
—

 
202.9

Escrow accounts
 
21.5

 
—

 
—

 
21.5

Gas hedge contracts
 
2.2

 
—

 
—

 
2.2

FTRs
 
—

 
—

 
6.7

 
6.7

 
 

$136.8

 

$474.4

 

$6.7

 

$617.9


Entergy Louisiana
2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$157.1

 

$—

 

$—

 

$157.1

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
4.8

 
234.8

(b)
—

 
239.6

Debt securities
 
68.7

 
75.3

 
—

 
144.0

Securitization recovery trust account
 
3.1

 
—

 
—

 
3.1

Escrow accounts
 
200.1

 
—

 
—

 
200.1

FTRs
 
—

 
—

 
11.1

 
11.1

 
 

$433.8

 

$310.1

 

$11.1

 

$755.0

 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
Gas hedge contracts
 

$7.6

 

$—

 

$—

 

$7.6


2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$123.6

 

$—

 

$—

 

$123.6

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
13.5

 
210.7

(b)
—

 
224.2

Debt securities
 
61.7

 
61.4

 
—

 
123.1

Securitization recovery trust account
 
4.5

 
—

 
—

 
4.5

Gas hedge contracts
 
2.9

 
—

 
—

 
2.9

FTRs
 
—

 
—

 
5.7

 
5.7

 
 

$206.2

 

$272.1

 

$5.7

 

$484.0


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Entergy Mississippi
2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$60.4

 

$—

 

$—

 

$60.4

Escrow accounts
 
41.8

 
—

 
—

 
41.8

FTRs
 
—

 
—

 
3.4

 
3.4

 
 

$102.2

 

$—

 

$3.4

 

$105.6

 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
Gas hedge contracts
 

$2.8

 

$—

 

$—

 

$2.8


2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Escrow accounts
 

$51.8

 

$—

 

$—

 

$51.8

Gas hedge contracts
 
0.7

 
—

 
—

 
0.7

FTRs
 
—

 
—

 
1.0

 
1.0

 
 

$52.5

 

$—

 

$1.0

 

$53.5


Entergy New Orleans
2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$41.4

 

$—

 

$—

 

$41.4

Escrow accounts
 
18.0

 
—

 
—

 
18.0

FTRs
 
—

 
—

 
4.1

 
4.1

 
 

$59.4

 

$—

 

$4.1

 

$63.5

 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
Gas hedge contracts
 

$0.9

 

$—

 

$—

 

$0.9


2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$33.2

 

$—

 

$—

 

$33.2

Escrow accounts
 
10.5

 
—

 
—

 
10.5

Gas hedge contracts
 
0.1

 
—

 
—

 
0.1

FTRs
 
—

 
—

 
2.0

 
2.0

 
 

$43.8

 

$—

 

$2.0

 

$45.8


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Entergy Texas
2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$28.7

 

$—

 

$—

 

$28.7

Securitization recovery trust account
 
37.2

 
—

 
—

 
37.2

FTRs
 
—

 
—

 
12.3

 
12.3

 
 

$65.9

 

$—

 

$12.3

 

$78.2


2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$44.1

 

$—

 

$—

 

$44.1

Securitization recovery trust account
 
37.5

 
—

 
—

 
37.5

FTRs
 
—

 
—

 
18.4

 
18.4

 
 

$81.6

 

$—

 

$18.4

 

$100.0


System Energy
2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$222.4

 

$—

 

$—

 

$222.4

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
2.0

 
422.5

(b)
—

 
424.5

Debt securities
 
194.2

 
61.1

 
—

 
255.3

 
 

$418.6

 

$483.6

 

$—

 

$902.2


2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
 
(In Millions)
Assets:
 
 
 
 
 
 
 
 
Temporary cash investments
 

$64.6

 

$—

 

$—

 

$64.6

Decommissioning trust funds (a):
 
 
 
 
 
 
 
 
Equity securities
 
2.2

 
377.8

(b)
—

 
380.0

Debt securities
 
152.9

 
71.0

 
—

 
223.9

 
 

$219.7

 

$448.8

 

$—

 

$668.5


(a)
The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices.  Fixed income securities are held in various governmental and corporate securities.  See Note 17 to the financial statements for additional information on the investment portfolios.
(b)
Commingled equity funds may be redeemed semi-monthly.


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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, 2014.

Entergy
Arkansas
 
Entergy
Gulf States
Louisiana

Entergy
Louisiana

Entergy
Mississippi

Entergy
New
Orleans

Entergy
Texas
 
(In Millions)

 
 














Balance as of January 1,

$—

 

$6.7

 

$5.7

 

$1.0

 

$2.0

 

$18.4

Issuances of FTRs
4.2

 
37.3

 
21.5

 
15.2

 
8.3

 
33.2

Unrealized gains (losses) included as a regulatory liability / asset
18.1

 
26.7

 
31.1

 
6.2

 
10.3

 
26.5

Settlements
(21.6
)
 
(56.3
)
 
(47.2
)
 
(19.0
)
 
(16.5
)
 
(65.8
)
Balance as of December 31,

$0.7

 

$14.4

 

$11.1

 

$3.4

 

$4.1

 

$12.3


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, 2013.
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New
Orleans
 
Entergy
Texas
 
(In Millions)
 
 
 
 
 
 
 
 
 
 
 
 
Balance as of January 1,

$—

 

$—

 

$—

 

$—

 

$—

 

$—

Issuances of FTRs
—

 
7.2

 
6.2

 
1.1

 
2.2

 
20.0

Unrealized gains (losses) included as a regulatory liability / asset
(0.1
)
 
(0.2
)
 
(0.3
)
 
0.9

 
1.0

 
(0.8
)
Settlements
0.1

 
(0.3
)
 
(0.2
)
 
(1.0
)
 
(1.2
)
 
(0.8
)
Balance as of December 31,

$—

 

$6.7

 

$5.7

 

$1.0

 

$2.0

 

$18.4



NOTE 17.    DECOMMISSIONING TRUST FUNDS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, 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 and 2, Vermont Yankee, and Palisades (NYPA currently retains the decommissioning trusts and liabilities for Indian Point 3 and FitzPatrick).  The funds are invested primarily in equity securities, fixed-rate debt securities, and cash and cash equivalents.

Entergy records decommissioning trust funds on the balance sheet at their fair value.  Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the Registrant Subsidiaries have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets.  For the 30% interest in River Bend formerly owned by Cajun, Entergy Gulf States Louisiana has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits.  Decommissioning trust funds for Pilgrim, Indian Point 1 and 2, 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

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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, 2014 and 2013 are summarized as follows:
 
 
 
Fair
Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
 
 
(In Millions)
2014
 
 

 
 

 
 

Equity Securities
 

$3,286

 

$1,513

 

$1

Debt Securities
 
2,085

 
76

 
6

Total
 

$5,371

 

$1,589

 

$7

 
 
 
Fair
Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
 
 
(In Millions)
2013
 
 

 
 

 
 

Equity Securities
 

$3,073

 

$1,260

 

$—

Debt Securities
 
1,830

 
47

 
29

Total
 

$4,903

 

$1,307

 

$29


Deferred taxes on unrealized gains/(losses) are recorded in other comprehensive income 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 $396 million and $329 million as of December 31, 2014 and 2013, respectively.  The amortized cost of debt securities was $2,019 million as of December 31, 2014 and $1,843 million as of December 31, 2013.  As of December 31, 2014, the debt securities have an average coupon rate of approximately 3.31%, an average duration of approximately 5.65 years, and an average maturity of approximately 8.45 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, 2014:
 
Equity Securities
 
Debt Securities
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
(In Millions)
Less than 12 months

$9

 

$1

 

$277

 

$2

More than 12 months
—

 
—

 
163

 
4

Total

$9

 

$1

 

$440

 

$6



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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, 2013:
 
Equity Securities
 
Debt Securities
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
(In Millions)
Less than 12 months

$—

 

$—

 

$892

 

$24

More than 12 months
—

 
—

 
60

 
5

Total

$—

 

$—

 

$952

 

$29


The unrealized losses in excess of twelve months on equity securities above relate to Entergy’s Utility operating companies and System Energy.

The fair value of debt securities, summarized by contractual maturities, as of December 31, 2014 and 2013 are as follows:
 
2014
 
2013
 
(In Millions)
less than 1 year

$94

 

$83

1 year - 5 years
783

 
752

5 years - 10 years
681

 
620

10 years - 15 years
173

 
169

15 years - 20 years
79

 
52

20 years+
275

 
154

Total

$2,085

 

$1,830


During the years ended December 31, 2014, 2013, and 2012, proceeds from the dispositions of securities amounted to $1,872 million, $2,032 million, and $2,074 million, respectively.  During the years ended December 31, 2014, 2013, and 2012, gross gains of $39 million, $91 million, and $39 million, respectively, and gross losses of $8 million, $11 million, and $7 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, 2014 and 2013 are summarized as follows:
 
 
 
Fair
Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
 
 
(In Millions)
2014
 
 
 
 
 
 
Equity Securities
 

$487.3

 

$248.9

 

$—

Debt Securities
 
282.6

 
6.2

 
1.1

Total
 

$769.9

 

$255.1

 

$1.1

2013
 
 
 
 
 
 
Equity Securities
 

$463.3

 

$214.0

 

$—

Debt Securities
 
247.6

 
5.3

 
5.2

Total
 

$710.9

 

$219.3

 

$5.2


The amortized cost of debt securities was $277.4 million as of December 31, 2014 and $248.9 million as of December 31, 2013.  As of December 31, 2014, the debt securities have an average coupon rate of approximately 2.55%, an average duration of approximately 4.68 years, and an average maturity of approximately 5.32 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, 2014:
 
Equity Securities
 
Debt Securities
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
(In Millions)
Less than 12 months

$0.1

 

$—

 

$56.5

 

$0.3

More than 12 months
—

 
—

 
34.8

 
0.8

Total

$0.1

 

$—

 

$91.3

 

$1.1


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, 2013:
 
Equity Securities
 
Debt Securities
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
(In Millions)
Less than 12 months

$—

 

$—

 

$153.2

 

$4.8

More than 12 months
—

 
—

 
6.9

 
0.4

Total

$—

 

$—

 

$160.1

 

$5.2


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The fair value of debt securities, summarized by contractual maturities, as of December 31, 2014 and 2013 are as follows:
 
2014
 
2013
 
(In Millions)
less than 1 year

$14.9

 

$8.1

1 year - 5 years
127.3

 
110.9

5 years - 10 years
128.2

 
118.0

10 years - 15 years
1.7

 
3.9

15 years - 20 years
1.0

 
0.9

20 years+
9.5

 
5.8

Total

$282.6

 

$247.6


During the years ended December 31, 2014, 2013, and 2012, proceeds from the dispositions of securities amounted to $181.5 million, $266.4 million, and $144.3 million, respectively.  During the years ended December 31, 2014, 2013, and 2012, gross gains of $8.7 million, $16.8 million, and $3.4 million, respectively, and gross losses of $0.3 million, $0.6 million, and $0.1 million, respectively, were recorded in earnings.

Entergy Gulf States Louisiana

Entergy Gulf States Louisiana holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts.  The securities held as of December 31, 2014 and 2013 are summarized as follows:
 
 
 
Fair
Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
 
 
(In Millions)
2014
 
 
 
 
 
 
Equity Securities
 

$395.9

 

$177.6

 

$—

Debt Securities
 
241.8

 
11.9

 
0.3

Total
 

$637.7

 

$189.5

 

$0.3

2013
 
 
 
 
 
 
Equity Securities
 

$370.8

 

$141.8

 

$—

Debt Securities
 
202.9

 
7.4

 
3.5

Total
 

$573.7

 

$149.2

 

$3.5


The amortized cost of debt securities was $231.5 million as of December 31, 2014 and $199.1 million as of December 31, 2013.  As of December 31, 2014, the debt securities have an average coupon rate of approximately 4.40%, an average duration of approximately 5.87 years, and an average maturity of approximately 11.13 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.


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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, 2014:
 
Equity Securities
 
Debt Securities
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
(In Millions)
Less than 12 months

$0.1

 

$—

 

$14.0

 

$0.1

More than 12 months
—

 
—

 
15.0

 
0.2

Total

$0.1

 

$—

 

$29.0

 

$0.3


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, 2013:
 
Equity Securities
 
Debt Securities
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
(In Millions)
Less than 12 months

$—

 

$—

 

$91.9

 

$3.1

More than 12 months
—

 
—

 
4.6

 
0.4

Total

$—

 

$—

 

$96.5

 

$3.5


The fair value of debt securities, summarized by contractual maturities, as of December 31, 2014 and 2013 are as follows:
 
2014
 
2013
 
(In Millions)
less than 1 year

$6.4

 

$7.9

1 year - 5 years
59.8

 
51.2

5 years - 10 years
68.3

 
75.5

10 years - 15 years
43.6

 
55.8

15 years - 20 years
14.8

 
4.6

20 years+
48.9

 
7.9

Total

$241.8

 

$202.9


During the years ended December 31, 2014, 2013, and 2012, proceeds from the dispositions of securities amounted to $173.5 million, $193.8 million, and $131.0 million, respectively.  During the years ended December 31, 2014, 2013, and 2012, gross gains of $1.9 million, $16.0 million, and $6.7 million, respectively, and gross losses of $0.3 million, $0.1 million, and $0.04 million, respectively, were recorded in earnings.


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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, 2014 and 2013 are summarized as follows:
 
 
 
Fair
Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
 
 
(In Millions)
2014
 
 
 
 
 
 
Equity Securities
 

$239.6

 

$116.7

 

$—

Debt Securities
 
144.0

 
6.9

 
0.4

Total
 

$383.6

 

$123.6

 

$0.4

2013
 
 
 
 
 
 
Equity Securities
 

$224.2

 

$96.1

 

$—

Debt Securities
 
123.1

 
4.7

 
1.9

Total
 

$347.3

 

$100.8

 

$1.9


The amortized cost of debt securities was $137.9 million as of December 31, 2014 and $120.6 million as of December 31, 2013.  As of December 31, 2014, the debt securities have an average coupon rate of approximately 3.05%, an average duration of approximately 5.39 years, and an average maturity of approximately 8.39 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, 2014:
 
Equity Securities
 
Debt Securities
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
(In Millions)
Less than 12 months

$0.1

 

$—

 

$19.1

 

$0.1

More than 12 months
—

 
—

 
12.1

 
0.3

Total

$0.1

 

$—

 

$31.2

 

$0.4


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, 2013:
 
Equity Securities
 
Debt Securities
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
(In Millions)
Less than 12 months

$—

 

$—

 

$38.3

 

$1.7

More than 12 months
—

 
—

 
1.7

 
0.2

Total

$—

 

$—

 

$40.0

 

$1.9


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The fair value of debt securities, summarized by contractual maturities, as of December 31, 2014 and 2013 are as follows:
 
2014
 
2013
 
(In Millions)
less than 1 year

$5.6

 

$14.8

1 year - 5 years
58.2

 
41.9

5 years - 10 years
44.2

 
37.0

10 years - 15 years
7.3

 
6.6

15 years - 20 years
9.4

 
6.2

20 years+
19.3

 
16.6

Total

$144.0

 

$123.1


During the years ended December 31, 2014, 2013, and 2012, proceeds from the dispositions of securities amounted to $43.2 million, $109.9 million, and $27.6 million, respectively.  During the years ended December 31, 2014, 2013, and 2012, gross gains of $0.3 million, $6.0 million, and $0.2 million, respectively, and gross losses of $0.02 million, $0.1 million, and $0.04 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, 2014 and 2013 are summarized as follows:
 
 
 
Fair
Value
 
Total
Unrealized
Gains
 
Total
Unrealized
Losses
 
 
(In Millions)
2014
 
 
 
 
 
 
Equity Securities
 

$424.5

 

$188.0

 

$—

Debt Securities
 
255.3

 
5.9

 
0.3

Total
 

$679.8

 

$193.9

 

$0.3

2013
 
 
 
 
 
 
Equity Securities
 

$380.0

 

$150.8

 

$—

Debt Securities
 
223.9

 
3.5

 
1.8

Total
 

$603.9

 

$154.3

 

$1.8


The amortized cost of debt securities was $251 million as of December 31, 2014 and $223.4 million as of December 31, 2013.  As of December 31, 2014, the debt securities have an average coupon rate of approximately 2.23%, an average duration of approximately 4.48 years, and an average maturity of approximately 5.95 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.


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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, 2014:
 
Equity Securities
 
Debt Securities
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
(In Millions)
Less than 12 months

$0.1

 

$—

 

$51.6

 

$0.2

More than 12 months
—

 
—

 
6.5

 
0.1

Total

$0.1

 

$—

 

$58.1

 

$0.3


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, 2013:
 
Equity Securities
 
Debt Securities
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
 
Fair
Value
 
Gross
Unrealized
Losses
 
(In Millions)
Less than 12 months

$—

 

$—

 

$121.7

 

$1.7

More than 12 months
—

 
—

 
0.9

 
0.1

Total

$—

 

$—

 

$122.6

 

$1.8


The fair value of debt securities, summarized by contractual maturities, as of December 31, 2014 and 2013 are as follows:
 
2014
 
2013
 
(In Millions)
less than 1 year

$33.5

 

$5.5

1 year - 5 years
139.7

 
144.9

5 years - 10 years
53.5

 
44.3

10 years - 15 years
3.4

 
9.3

15 years - 20 years
3.2

 
1.6

20 years+
22.0

 
18.3

Total

$255.3

 

$223.9


During the years ended December 31, 2014, 2013, and 2012, proceeds from the dispositions of securities amounted to $392.9 million, $215.5 million, and $349.4 million, respectively.  During the years ended December 31, 2014, 2013, and 2012, gross gains of $1.8 million, $1.5 million, and $3.6 million, respectively, and gross losses of $0.9 million, $1.3 million, and $0.3 million, respectively, were recorded in earnings.

Other-than-temporary impairments and unrealized gains and losses

Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy evaluate 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

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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, 2014, 2013, and 2012.  The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment continues to be 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 2014, 2013, and 2012, respectively, resulting from the recognition of the other-than-temporary impairment of certain equity securities held in its decommissioning trust funds.


NOTE 18.  VARIABLE INTEREST ENTITIES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Under applicable authoritative accounting guidance, a variable interest entity (VIE) is an entity that conducts a business or holds property that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity holders do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations, and is required to consolidate a VIE if it is the VIE’s primary beneficiary. The primary beneficiary of a VIE is the entity that has the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance, and has the obligation to absorb losses or has the right to residual returns that would potentially be significant to the entity.

Entergy Arkansas, Entergy Gulf States Louisiana, 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 Gulf States Louisiana, 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 Gulf States Louisiana, 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.

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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 Louisiana and System Energy are also considered to each hold a variable interest in the lessors from which they lease undivided interests in the Waterford 3 and Grand Gulf nuclear plants, respectively.  Entergy Louisiana and System Energy are the lessees under these arrangements, which are described in more detail in Note 10 to the financial statements.  Entergy Louisiana made payments on its lease, including interest, of $31.0 million in 2014, $26.3 million in 2013, and $39.1 million in 2012.  System Energy made payments on its lease, including interest, of $51.6 million in 2014, $50.5 million in 2013, and $50.0 million in 2012.  The lessors are banks acting in the capacity of owner trustee for the benefit of equity investors in the transactions pursuant to trust agreements entered solely for the purpose of facilitating the lease transactions.  It is possible that Entergy Louisiana and System Energy may be considered as the primary beneficiary of the lessors, but Entergy is unable to apply the authoritative accounting guidance with respect to these VIEs because the lessors are not required to, and could not, provide the necessary financial information to consolidate the lessors.  Because Entergy accounts for these leasing arrangements as capital financings, however, Entergy believes that consolidating the lessors 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 sheets materially represent each company’s potential exposure to loss.

Entergy has also reviewed various lease arrangements, power purchase agreements, and other agreements in which it holds a variable interest.  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.



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NOTE 19.   TRANSACTIONS WITH AFFILIATES (Entergy Arkansas, Entergy Gulf States Louisiana, 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 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.  In addition, Entergy Power sold electricity to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans prior to the expiration of the contract in 2013.  RS Cogen sells electricity to Entergy Gulf States Louisiana.

As described in Note 1 to the financial statements, all of System Energy’s operating revenues consist of billings to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

As described in Note 4 to the financial statements, the Registrant Subsidiaries participate in Entergy’s money pool and earn interest income from the money pool.  As described in Note 2 to the financial statements, Entergy Gulf States Louisiana and Entergy Louisiana receive preferred membership 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
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New
Orleans
 
Entergy
Texas
 
System
Energy
 
(In Millions)
2014

$131.2

 

$418.0

 

$258.5

 

$169.8

 

$76.8

 

$316.1

 

$664.4

2013

$349.9

 

$383.1

 

$114.9

 

$107.3

 

$27.0

 

$369.4

 

$735.1

2012

$324.0

 

$380.6

 

$138.2

 

$36.1

 

$43.9

 

$313.2

 

$622.1


Intercompany Operating Expenses
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New
Orleans
 
Entergy
Texas
 
System
Energy
 
(In Millions)
 
(a)
 
(b)
 
(c)
 
 
 
(d)
 
 
 
 
2014

$596.6

 

$773.1

 

$490.9

 

$367.6

 

$241.5

 

$445.3

 

$156.7

2013

$656.1

 

$672.8

 

$667.6

 

$399.0

 

$279.6

 

$418.1

 

$175.2

2012

$580.7

 

$532.3

 

$597.4

 

$352.7

 

$247.2

 

$386.1

 

$147.4


(a)
Includes power purchased from Entergy Power of $3.3 million in 2013 and $1.4 million in 2012. The contract with Entergy Power expired in May 2013.
(b)
Includes power purchased from RS Cogen of $3.2 million in 2013 and $2.8 million in 2012.
(c)
Includes power purchased from Entergy Power of $8.1 million in 2013 and $14.3 million in 2012. The contract with Entergy Power expired in May 2013.
(d)
Includes power purchased from Entergy Power of $8 million in 2013 and $14.1 million in 2012. The contract with Entergy Power expired in May 2013.


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Intercompany Interest and Investment Income
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New
Orleans
 
Entergy
Texas
 
System
Energy
 
(In Millions)
2014

$—

 

$30.3

 

$87.6

 

$—

 

$—

 

$—

 

$—

2013

$—

 

$27.5

 

$78.2

 

$—

 

$—

 

$—

 

$—

2012

$—

 

$28.2

 

$78.2

 

$—

 

$—

 

$0.1

 

$—



NOTE 20.  QUARTERLY FINANCIAL DATA (UNAUDITED) (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Operating results for the four quarters of 2014 and 2013 for Entergy Corporation and subsidiaries were:
 
Operating
Revenues
 
Operating
Income
 
Consolidated
Net Income
 
Net Income
Attributable to
Entergy
Corporation
 
(In Thousands)
2014:
 
 
 
First Quarter

$3,208,843

 

$739,877

 

$406,053

 

$401,174

Second Quarter

$2,996,650

 

$454,477

 

$194,281

 

$189,383

Third Quarter

$3,458,110

 

$492,859

 

$234,916

 

$230,037

Fourth Quarter

$2,831,318

 

$319,674

 

$125,006

 

$120,127

2013:
 
 
 
First Quarter

$2,608,874

 

$394,045

 

$166,982

 

$161,400

Second Quarter

$2,738,208

 

$346,512

 

$168,055

 

$163,723

Third Quarter

$3,351,959

 

$388,894

 

$244,182

 

$239,850

Fourth Quarter

$2,691,906

 

$225,548

 

$151,353

 

$146,929


Earnings per Average Common Share
 
2014
 
2013
 
Basic
 
Diluted
 
Basic
 
Diluted
First Quarter

$2.24

 

$2.24

 

$0.91

 

$0.90

Second Quarter

$1.06

 

$1.05

 

$0.92

 

$0.92

Third Quarter

$1.28

 

$1.27

 

$1.35

 

$1.34

Fourth Quarter

$0.67

 

$0.66

 

$0.82

 

$0.82


As discussed in more detail in Note 1 to the financial statements, operating results for 2014 include $154 million ($100 million after-tax) of charges related to Vermont Yankee primarily resulting from the effects of an updated decommissioning cost study completed in the third quarter 2014 along with reassessment of assumptions regarding the timing of decommissioning cash flows and severance and employee retention costs. Results of operations for 2014 also include the $56.2 million ($36.7 million after-tax) write-off of Entergy Mississippi’s regulatory asset associated with new nuclear generation development costs as a result of a joint stipulation entered into with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, in which Entergy Mississippi agreed not to pursue recovery of

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the costs deferred by an MPSC order in the new nuclear generation docket. See Note 2 to the financial statements for further discussion of the new nuclear generation development costs and the joint stipulation.

Results of operations for 2013 include $322 million ($202 million after-tax) of impairment and other related charges primarily to write down the carrying value of Vermont Yankee and related assets to their fair values. See Note 1 to the financial statements for further discussion of the charges. Also, as discussed in more detail in Note 13 to the financial statements, operating results include approximately $110 million ($70 million after-tax) in costs in 2013 associated with the human capital management strategic imperative, primarily implementation costs, severance expenses, pension curtailment losses, and special termination benefits expense. In December 2013, Entergy deferred for future recovery approximately $45 million ($30 million after-tax) of these costs in the Arkansas and Louisiana jurisdictions, as approved by the APSC and the LPSC, respectively.

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 2014 and 2013 were:

Operating Revenues
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
(In Thousands)
2014:
 
 
 
 
 
 
 
 
 
 
 
 
 
First Quarter

$514,981

 

$513,295

 

$623,494

 

$348,196

 

$186,567

 

$440,256

 

$157,667

Second Quarter

$511,522

 

$554,034

 

$736,408

 

$370,638

 

$169,989

 

$482,932

 

$163,830

Third Quarter

$627,153

 

$610,493

 

$870,181

 

$425,341

 

$182,971

 

$528,508

 

$172,151

Fourth Quarter

$518,735

 

$473,104

 

$595,798

 

$380,018

 

$150,558

 

$400,286

 

$170,716

2013:
 
 
 
 
 
 
 
 
 
 
 
 
 
First Quarter

$542,392

 

$419,955

 

$606,085

 

$291,641

 

$146,466

 

$306,173

 

$168,578

Second Quarter

$508,653

 

$492,361

 

$635,805

 

$326,039

 

$142,841

 

$455,100

 

$172,177

Third Quarter

$647,671

 

$558,331

 

$782,789

 

$397,833

 

$178,641

 

$526,978

 

$192,679

Fourth Quarter

$491,443

 

$470,486

 

$602,256

 

$319,027

 

$152,208

 

$440,548

 

$201,655


Operating Income (Loss)
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
(In Thousands)
2014:
 
 
 
 
 
 
 
 
 
 
 
 
 
First Quarter

$66,360

 

$82,576

 

$85,057

 

$57,132

 

$15,281

 

$43,056

 

$52,029

Second Quarter

$68,970

 

$70,350

 

$100,176

 

$59,063

 

$12,862

 

$53,158

 

$56,547

Third Quarter

$115,357

 

$96,698

 

$160,595

 

$9,403

 

$24,866

 

$82,911

 

$58,484

Fourth Quarter

$19,317

 

$43,766

 

$38,615

 

$61,162

 

($539
)
 

$29,590

 

$54,056

2013:
 
 
 
 
 
 
 
 
 
 
 
 
 
First Quarter

$43,314

 

$52,083

 

$64,728

 

$37,123

 

$4,272

 

$26,277

 

$52,052

Second Quarter

$80,942

 

$53,856

 

$88,691

 

$46,809

 

$3,627

 

$38,355

 

$51,632

Third Quarter

$157,681

 

$85,284

 

$145,847

 

$70,186

 

$15,895

 

$79,430

 

$52,029

Fourth Quarter

$23,123

 

$56,114

 

$56,128

 

$36,112

 

$3,070

 

$30,071

 

$47,367



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Net Income (Loss)
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
Entergy
Texas
 
System
Energy
 
(In Thousands)
2014:
 
 
 
 
 
 
 
 
 
 
 
 
 
First Quarter

$28,370

 

$46,472

 

$58,378

 

$25,839

 

$8,294

 

$13,165

 

$24,619

Second Quarter

$29,005

 

$36,171

 

$69,667

 

$26,564

 

$6,374

 

$18,585

 

$25,931

Third Quarter

$62,980

 

$55,535

 

$123,821

 

($6,464
)
 

$13,932

 

$39,559

 

$26,730

Fourth Quarter

$1,037

 

$24,313

 

$31,665

 

$28,882

 

$107

 

$3,495

 

$19,054

2013:
 
 
 
 
 
 
 
 
 
 
 
 
 
First Quarter

$14,719

 

$27,165

 

$45,376

 

$13,934

 

$1,307

 

$922

 

$28,006

Second Quarter

$40,483

 

$29,720

 

$61,377

 

$18,954

 

$598

 

$10,953

 

$27,734

Third Quarter

$82,577

 

$62,642

 

$100,597

 

$33,813

 

$8,086

 

$35,801

 

$35,105

Fourth Quarter

$24,169

 

$42,135

 

$45,114

 

$15,458

 

$1,692

 

$10,205

 

$22,819


Earnings (Loss) Applicable to Common Equity
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
Entergy
Louisiana
 
Entergy
Mississippi
 
Entergy
New Orleans
 
(In Thousands)
2014:
 
 
 
 
 
 
 
 
 
First Quarter

$26,652

 

$46,266

 

$56,640

 

$25,132

 

$8,053

Second Quarter

$27,287

 

$35,962

 

$67,910

 

$25,857

 

$6,133

Third Quarter

$61,262

 

$55,329

 

$122,083

 

($7,171
)
 

$13,691

Fourth Quarter

($682
)
 

$24,107

 

$29,929

 

$28,175

 

($135
)
2013:
 
 
 
 
 
 
 
 
 
First Quarter

$13,001

 

$26,959

 

$43,638

 

$13,227

 

$1,066

Second Quarter

$38,765

 

$29,514

 

$59,639

 

$18,247

 

$357

Third Quarter

$80,859

 

$62,436

 

$98,859

 

$33,106

 

$7,845

Fourth Quarter

$22,450

 

$41,928

 

$43,378

 

$14,751

 

$1,450



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ENTERGY’S BUSINESS

Entergy is an integrated energy company engaged primarily in electric power production and retail electric distribution operations.  Entergy owns and operates power plants with approximately 30,000 MW of aggregate electric generating capacity, including nearly 10,000 MW of nuclear-fueled capacity. Entergy’s Utility business delivers electricity to 2.8 million utility customers in Arkansas, Louisiana, Mississippi, and Texas.  Entergy generated annual revenues of $12.5 billion in 2014 and had approximately 13,000 employees as of December 31, 2014.

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 operates 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.  In August 2013, Entergy announced plans to close and decommission Vermont Yankee. On December 29, 2014 the Vermont Yankee plant ceased power production and has entered its decommissioning phase. 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 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 core utility and nuclear 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 grow the business by leveraging the industrial expansion underway in the Gulf region of the United States, and for Entergy Wholesale Commodities, the strategic imperative is to manage the risk and preserve value in the business.

Utility

The Utility business segment includes six wholly-owned retail electric utility subsidiaries: Entergy Arkansas, Entergy Gulf States Louisiana, 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 Gulf States 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 six 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, 2014, 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
 
702

 
25
%
 
 
 
 
Entergy Gulf States
Louisiana
 
Portions of Louisiana
 
396

 
14
%
 
93

 
47
%
Entergy Louisiana
Portions of Louisiana
 
680

 
24
%
 
 
 
 
Entergy Mississippi
Portions of Mississippi
 
442

 
16
%
 
 
 
 
Entergy New Orleans
City of New Orleans (a)
 
171

 
6
%
 
105

 
53
%
Entergy Texas
Portions of Texas
 
427

 
15
%
 
 
 
 
Total customers
 
 
2,818

 
100
%
 
198

 
100
%

(a)
Excludes the Algiers area of the city, where Entergy Louisiana provides electric service.

Electric Energy Sales

The electric energy sales of the Utility operating companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year.  On August 22, 2014, Entergy reached a 2014 peak demand of 20,472 MWh, compared to the 2013 peak of 21,581 MWh recorded on August 8, 2013.  Selected electric energy sales data is shown in the table below:

Selected 2014 Electric Energy Sales Data
 
 
Entergy
Arkansas
 
Entergy
Gulf States
Louisiana
 
 
Entergy
Louisiana
 
 
Entergy
Mississippi
 
 
Entergy
New Orleans
 
 
Entergy
Texas
 
 
System
Energy
 
 
Entergy
(a)
 
(In GWh)
Sales to retail
 customers
21,050

 
20,823

 
32,904

 
13,204

 
5,229

 
17,698

 
—

 
110,910

Sales for resale:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Affiliates
2,299

 
6,966

 
4,450

 
2,657

 
1,322

 
4,763

 
9,219

 
—

Others
8,003

 
925

 
126

 
193

 
16

 
200

 
—

 
9,462

Total
31,352

 
28,714

 
37,480

 
16,054

 
6,567

 
22,661

 
9,219

 
120,372

Average use per
residential customer
(kWh)
13,774

 
15,865

 
15,355

 
15,319

 
12,870

 
15,560

 
—

 
14,911


(a)
Includes the effect of intercompany eliminations.


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The following table illustrates the Utility operating companies’ 2014 combined electric sales volume as a percentage of total electric sales volume, and 2014 combined electric revenues as a percentage of total 2014 electric revenue, each by customer class.
Customer Class
 
% of Sales Volume
 
% of Revenue
Residential
 
29.9
 
37.1
Commercial
 
23.9
 
26.6
Industrial (a)
 
36.3
 
27.3
Governmental
 
2.0
 
2.4
Wholesale/Other
 
7.9
 
6.6

(a)
Major industrial customers are in the chemical, petroleum refining, and pulp and paper industries.

See “Selected Financial Data” for each of the Utility operating companies for the detail of their sales by customer class for 2010-2014.

Selected 2014 Natural Gas Sales Data

Entergy New Orleans and Entergy Gulf States Louisiana provide both electric power and natural gas to retail customers.  Entergy New Orleans and Entergy Gulf States Louisiana sold 11,296,179 and 7,933,968 Mcf, respectively, of natural gas to retail customers in 2014.  In 2014, 97% of Entergy Gulf States Louisiana’s operating revenue was derived from the electric utility business, and only 3% from the natural gas distribution business.  For Entergy New Orleans, 84% of operating revenue was derived from the electric utility business and 16% from the natural gas distribution business in 2014.  

Following is data concerning Entergy New Orleans’s 2014 retail operating revenue sources.
 
Customer Class
 
Electric Operating
Revenue
 
Natural Gas
Revenue
Residential
 
42%
 
51%
Commercial
 
38%
 
26%
Industrial
 
7%
 
8%
Governmental/Municipal
 
13%
 
15%

Retail Rate Regulation

General (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and 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.

Entergy Arkansas

Fuel and Purchased Power Cost Recovery

Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased energy 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

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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.

Storm Cost Recovery

See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Arkansas’s storm restoration costs.

Entergy Gulf States Louisiana

Fuel Recovery

Entergy Gulf States Louisiana’s electric rates 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 Gulf States Louisiana’s fuel adjustment clause filings.

To help stabilize electricity costs, Entergy Gulf States Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments.  Entergy Gulf States 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.

Entergy Gulf States 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 Gulf States 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 Gulf States 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.

Storm Cost Recovery

See Note 2 to the financial statements for a discussion of Entergy Gulf States Louisiana’s filings to recover storm-related costs.

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-

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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 Entergy Louisiana’s filings to recover storm-related costs.

Entergy Mississippi

Fuel Recovery

Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased energy 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.

Power Management Rider

In November 2005 the MPSC approved the purchase of the Attala power plant and recovery of the investment cost through Entergy Mississippi’s power management rider.  Entergy Mississippi recovered the annual ownership costs of the Attala plant through the power management rider until resolution of its general rate case.  In 2012 the MPSC approved the purchase of the Hinds power plant recovery of the investment cost through Entergy Mississippi’s power management rider.  Entergy Mississippi recovered the annual ownership costs of the Hinds plant through the power management rider until resolution of its general rate case.  See Note 2 to the financial statements for a discussion of Entergy Mississippi’s 2014 general rate case. Included in the rate changes and revenue adjustments effective with February 2015 bills was the realignment of the annual ownership costs associated with the Attala plant and the Hinds plant from the power management rider to base rates.

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

Entergy Mississippi maintains a storm damage provision pursuant to orders of the MPSC and consistent with regulatory accounting requirements.  Entergy Mississippi’s storm damage provision is funded through its storm damage rider schedule.  In two orders issued in July 2012, the MPSC temporarily increased Entergy Mississippi’s storm damage provision monthly accrual from $750,000 to $2 million for bills rendered during the billing months of August 2012 through December 2012, and approved recovery of $14.9 million in prudently incurred storm costs to be amortized over five months, beginning with August 2012 bills.  Beginning with January 2013 bills, the monthly accrual to the storm damage provision reverted back to $750,000.  On July 1, 2013, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation, in which both parties agreed that approximately $32 million in storm restoration costs incurred in 2011 and 2012 were prudently incurred and chargeable to storm damages, while approximately $700,000 in prudently incurred costs were more properly recoverable through the formula rate plan. Entergy Mississippi and the Mississippi Public Utilities Staff also agreed that the storm damage accrual should be increased from $750,000 per month to $1.75 million per month. In September 2013 the MPSC approved the joint stipulation with the increase in the storm damage accrual effective with October 2013 bills. In February 2015, Entergy Mississippi provided notice to the Mississippi Public Utilities Staff that the storm damage accrual would be set to zero effective with the March 2015 billing cycle as a result of Entergy Mississippi's storm damage accrual balance exceeding

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$15 million as of January 31, 2015, but will return to its current level when the storm damage accrual balance becomes less than $10 million.

The MPSC has also ordered that Entergy Mississippi will annually submit its storm costs for audit.

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.  In October 2005 the City Council approved modification of the current gas cost collection mechanism effective November 2005 in order to address concerns regarding its fluctuations, particularly during the winter heating season.  The modifications are intended to minimize fluctuations in gas rates during the winter months.

To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives.  The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to serve Entergy New Orleans gas customers.  Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.

Storm Cost Recovery

See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.

Entergy Texas

Fuel Recovery

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included in base rates.  Semi-annual revisions of the fixed fuel factor are made in March and 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.

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.


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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.

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, and expires in January 2017, unless otherwise extended by the Texas Legislature.

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. The appeal remains pending.

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 Gulf States Louisiana holds non-exclusive franchises to provide electric service in approximately 59 incorporated municipalities and the unincorporated areas of approximately 22 parishes, and to provide gas service in the City of Baton Rouge and the unincorporated areas of two parishes.  Most of Entergy Gulf States Louisiana’s franchises have a term of 60 years.  Entergy Gulf States Louisiana’s current electric and gas franchises expire during 2015-2055.

Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 117 incorporated Louisiana municipalities.  Most of these franchises have 25-year terms.  Entergy Louisiana also supplies electric service in approximately 52 Louisiana parishes in which it holds non-exclusive franchises.  Entergy Louisiana’s electric franchises expire during 2015-2039.


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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 (except electric service in Algiers, which is provided by Entergy Louisiana).  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 2016-2058.

The business of System Energy is limited to wholesale power sales.  It has no distribution franchises.

Property and Other Generation Resources

Generating Stations

The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2014, is indicated below:
 
 
Owned and Leased Capability MW(a)
Company
 
Total
 
Gas/Oil
 
Nuclear
 
Coal
 
Hydro
Entergy Arkansas
 
4,721

 
1,630

 
1,820

 
1,198

 
73

Entergy Gulf States Louisiana
 
2,963

 
1,630

 
973

 
360

 
—

Entergy Louisiana
 
6,321

 
5,157

 
1,164

 
—

 
—

Entergy Mississippi
 
3,495

 
3,075

 
—

 
420

 
—

Entergy New Orleans
 
782

 
782

 
—

 
—

 
—

Entergy Texas
 
2,553

 
2,287

 
—

 
266

 
—

System Energy
 
1,268

 
—

 
1,268

 
—

 
—

Total
 
22,103

 
14,561

 
5,225

 
2,244

 
73


(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 23,269 MW over the previous decade.  The Utility operating companies, in aggregate, are projected to have approximately 224 MW more than their minimum capacity requirements needed to meet MISO Resource Adequacy for 2015.

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, and the availability and price of power, the location of new load, the economy, and the age and condition of Entergy’s existing infrastructure. The resource planning processes also consider the Entergy Arkansas exit from the System Agreement on December 18, 2013, and Entergy Mississippi’s (in November 2015), Entergy Texas’s, Entergy Louisiana’s, and Entergy Gulf States Louisiana’s notices of their future withdrawal from the System Agreement.


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The Utility operating companies’ long-term resource strategy, the “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 6,500 MW of new long-term resources. 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.

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 summer 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 resulted, among other things, in:

•
Entergy Louisiana’s June 2005 purchase of the 718 MW, gas-fired Perryville plant, of which a total of 75% of the output is sold to Entergy Gulf States Louisiana and Entergy Texas;
•
Entergy Arkansas’s September 2008 purchase of the 789 MW, combined-cycle, gas-fired Ouachita Generating Facility. Entergy Gulf States Louisiana purchased one-third of the facility from Entergy Arkansas in November 2009;
•
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; and
•
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. For additional discussion of the Ninemile 6 project see “Capital Expenditure Plans and Other Uses of Capital” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

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 PPAs totaling approximately 300 MW between Entergy Gulf States Louisiana and Entergy Louisiana (200 MW), and between Entergy Gulf States Louisiana and Entergy New Orleans (100 MW) related to Entergy Gulf States 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);
•
12-month agreements originally executed in 2005 and which are renewed annually between Entergy Arkansas and Entergy Gulf States Louisiana and Entergy Texas, and between Entergy Arkansas and Entergy Mississippi, relating 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 Gulf States Louisiana purchases 50% of the facility's capacity and energy from Entergy Texas;

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•
In October 2012, Entergy Arkansas and Union Power Partners, L.P. executed a 3 ½-year agreement for 495 MW from the Union Power Station located in El Dorado, Arkansas.  Cost recovery for this agreement was approved within Entergy Arkansas’s general rate case filed in March 2013; and
•
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 December 2010 on behalf of Entergy Gulf States Louisiana and Entergy Louisiana, Entergy Services issued the 2010 RFP for Long-Term Renewable Energy Resources seeking up to 233 MW of renewable generation resources to meet the requirements of an LPSC general order issued on December 9, 2010.  In September 2012, Entergy Gulf States Louisiana executed a 20-year contract for 28 MW, with the potential to purchase an additional 9 megawatts when available, from Rain CII Carbon LLC’s pet coke calcining facility in Sulphur, Louisiana.  The facility began commercial operation in May 2013.  In March 2013, Entergy Gulf States Louisiana executed a 20-year contract for 8.5 MW from Agrilectric Power Partners, LP’s refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. In September 2013, Entergy Louisiana executed a 10-year contract 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. LPSC certification of these three contracts has been received.

In May 2014, Entergy Arkansas issued the 2014 Entergy Arkansas RFP for Long-Term, Supply-Side and Renewable Generation Resources. This RFP is seeking between 200 to 600 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes from traditional resources (CT, CCTG or solid fuel) for deliveries beginning in 2017 and approximately 200 MW of the same products from renewable resources (wind, solar, biomass and hydro) for deliveries starting as early as 2015.

In September 2014, on behalf of one or more of Entergy Gulf States Louisiana, Entergy Louisiana, and Entergy New Orleans, Entergy Services issued the 2014 Amite South RFP for Long-Term Supply Side Developmental Resources to be constructed in the Amite South planning region. This RFP is seeking between 650 and 1000 MW of capacity, energy, and related products and environmental attributes from a new, single integrated generation resource located in Amite South, preferably in close proximity to the Downstream of Gypsy region. This RFP includes a self-build option at Entergy Louisiana’s Little Gypsy site.

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; and Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2.  The Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.

In December 2014, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas entered into an asset purchase agreement to acquire 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). Pursuant to the agreement, Entergy Gulf States Louisiana will acquire two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy Texas will each acquire one power block and a 25% undivided ownership interest in the related assets. If Entergy Arkansas or Entergy Texas do not obtain approval for the purchase of their power blocks, Entergy Gulf States Louisiana will seek to purchase the power blocks not approved. The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments.  In addition, Entergy Gulf States Louisiana anticipates selling 20% of the capacity and energy associated with its two power blocks to Entergy New Orleans through a cost-based, life-of-unit power purchase

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agreement. The purchase is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federal and state regulatory and permitting agencies. These include regulatory approvals from the APSC, LPSC, PUCT, and FERC, as well as clearance under the Hart-Scott-Rodino anti-trust law. In December 2014, Entergy Texas filed its application with the PUCT for approval of the acquisition. The PUCT has indicated that it will convene the hearing on the merits of this case in June 2015. Entergy Texas intends to file a rate application to seek cost recovery later in 2015. In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC and Entergy Arkansas filed its application with the APSC, each for approval of the acquisition and cost recovery. Closing is targeted to occur in late-2015.

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 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, 2014, Entergy New Orleans distributed and transported natural gas for distribution within Algiers and New Orleans, Louisiana, through approximately 2,500 miles of gas pipeline.  As of December 31, 2014, the gas properties of Entergy Gulf States Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Gulf States 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 Gulf States Louisiana, 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.


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Fuel Supply

The sources of generation and average fuel cost per kWh for the Utility operating companies and System Energy for the years 2012-2014 were:
 
 
 
Natural Gas
 
 
Nuclear
 
 
Coal
 
Purchased
Power
 
 
Year
 
%
of
Gen
 
Cents
Per
kWh
 
%
of
Gen
 
Cents
Per
kWh
 
%
of
Gen
 
Cents
Per
kWh
 
%
of
Gen
 
Cents
Per
kWh
2014
 
28
 
4.36

 
33
 
0.89

 
11
 
2.63

 
28
 
5.14

2013
 
26
 
4.12

 
39
 
0.92

 
10
 
2.70

 
25
 
4.32

2012
 
27
 
3.15

 
33
 
0.85

 
11
 
2.60

 
29
 
3.58


Actual 2014 and projected 2015 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
 
2014
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
2015
Entergy Arkansas (a)
12
%
 
13
%
 
53
%
 
58
%
 
24
%
 
23
%
 
11
%
 
5
%
Entergy Gulf States Louisiana
43
%
 
30
%
 
15
%
 
15
%
 
9
%
 
12
%
 
33
%
 
43
%
Entergy Louisiana
26
%
 
25
%
 
36
%
 
35
%
 
1
%
 
1
%
 
37
%
 
39
%
Entergy Mississippi
37
%
 
32
%
 
22
%
 
25
%
 
16
%
 
16
%
 
25
%
 
27
%
Entergy New Orleans
30
%
 
31
%
 
45
%
 
43
%
 
3
%
 
3
%
 
22
%
 
23
%
Entergy Texas
19
%
 
14
%
 
13
%
 
13
%
 
8
%
 
10
%
 
60
%
 
63
%
System Energy (b)
—

 
—

 
100
%
 
100
%
 
—

 
—

 
—

 
—

Utility (a)
28
%
 
23
%
 
33
%
 
33
%
 
11
%
 
11
%
 
28
%
 
33
%

(a)
Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2014 and is expected to provide less than 1% of its generation in 2015.
(b)
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 Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

Some of the Utility’s gas-fired plants are capable of also using fuel oil, if necessary.  In addition, two small peaking units burn only oil. Any oil use is included in the total for gas.

Natural Gas

The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation.  Long-term firm contracts for power plants comprise less than 25% of the Utility operating companies’ total requirements.  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

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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.

Coal

Entergy Arkansas has committed to eight one- to three-year contracts that will supply approximately 87% of the total coal supply needs in 2015.  These contracts are staggered in term so that not all contracts have to be renewed the same year.  The remaining 13% 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 2015.  Entergy Arkansas is currently negotiating a new rail agreement that will provide all of Entergy Arkansas’s coal transportation requirements through 2015. The current agreement is set to expire June 30, 2015.

Entergy Gulf States Louisiana has committed to four one- to three-year contracts that will supply approximately 79% of Nelson Unit 6 coal needs in 2015.  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 2015.  Coal will be transported to Nelson via an existing transportation agreement that is expected to provide all of Entergy Gulf States Louisiana’s rail transportation requirements for 2015.

For the year 2014, coal transportation delivery to Entergy Arkansas- and Entergy Gulf States Louisiana-operated coal-fired units met coal demand at the plants and it is expected that delivery times experienced in 2014 will continue to improve through 2015.  Both Entergy Arkansas and Entergy Gulf States 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 Gulf States Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2015.  Entergy Gulf States 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 Gulf States Louisiana, 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.


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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 2015.  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 Gulf States Louisiana, 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 ten 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 Atmos Energy 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 Atmos Energy 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.  In recent years, natural gas deliveries to Entergy New Orleans have been subject primarily to weather-related curtailments.

Entergy Gulf States Louisiana purchases natural gas for resale under a firm contract from Enbridge Marketing (U.S.) Inc.  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 Gulf States 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 rates (including intrasystem sales pursuant to the System Agreement) and

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interstate transmission of electricity, as well as 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.

System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC.  Under the terms of the System Agreement, generating capacity and other power resources are jointly operated by the Utility operating companies that are participating in the System Agreement.  The System Agreement provides, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) shall receive payments from those parties having generating reserves that are less than their allocated share of reserves (short companies).  Such payments are 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 are 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 are 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 will terminate its participation in the System Agreement in November 2015.

See “System Agreement” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional discussion of the System Agreement, including other Utility operating companies’ notices to terminate participation in the future. See Note 2 to the financial statements for discussion of legal proceedings at the FERC involving the System Agreement.

Transmission

See “Entergy’s Integration into the MISO Regional Transmission Organization” in the “Rate, Cost-recovery, and Other Regulation - Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

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.  The FERC’s decision also affected other aspects of System Energy’s charges to the Utility operating companies that it supplies with power.  In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations.  Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC.

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

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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 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 September 1989 write-off of System Energy’s investment in Grand Gulf 2, amounting to approximately $900 million, is being amortized for Availability Agreement purposes over 27 years.

The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.

System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for its first mortgage bonds and reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 10 to the financial statements under “Sale and Leaseback Transactions - Grand Gulf Lease Obligations.”  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

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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 supplements as security for its first mortgage bonds and for reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 10 to the financial statements under “Sale and Leaseback Transactions - Grand Gulf Lease Obligations.”  Each such 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 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.

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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.

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 Gulf States Louisiana, 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 now 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 Gulf States Louisiana now 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 Gulf States 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.  Entergy Gulf States Louisiana purchases a 57.5% share of capacity and energy from the gas-fired generating plants owned by Entergy Texas, and Entergy Texas purchases a 42.5% share of capacity and energy from the gas-fired generating plants owned by Entergy Gulf States Louisiana.  The purchased power agreements associated with the gas-fired generating plants will terminate when the unit(s) is/are removed from Entergy System dispatch.  The dispatch and operation of the generating plants did not change as a result of the jurisdictional separation.  The LPSC staff has asserted that the purchased power agreements would terminate if Entergy Texas and Entergy Gulf States Louisiana join MISO.  Entergy Gulf States Louisiana filed testimony opposing that position.  The LPSC stayed consideration of this issue until December 31, 2013. No further action has been taken regarding this matter. See additional discussion of the purchased power agreements in the “Federal Regulation - Entergy’s Integration Into the MISO Regional Transmission Organization” section in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

Entergy Louisiana and Entergy Gulf States Louisiana Business Combination

See Note 2 to the financial statements for a discussion of the planned Entergy Louisiana and Entergy Gulf States Louisiana business combination.


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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,
 
2014
 
2013
 
2012
 
2011
 
2010
Entergy Arkansas
3.08
 
3.62
 
3.79
 
4.31
 
3.91
Entergy Gulf States Louisiana
3.84
 
3.63
 
3.48
 
4.36
 
3.58
Entergy Louisiana
3.23
 
3.13
 
2.08
 
1.86
 
3.41
Entergy Mississippi
3.23
 
3.19
 
2.79
 
3.55
 
3.35
Entergy New Orleans
3.96
 
1.93
 
3.02
 
5.37
 
4.43
Entergy Texas
2.39
 
1.94
 
1.76
 
2.34
 
2.10
System Energy
4.04
 
5.66
 
5.12
 
3.85
 
3.64

 
Ratios of Earnings to Combined Fixed
Charges and Preferred Dividends or Distributions
Years Ended December 31,
 
2014
 
2013
 
2012
 
2011
 
2010
Entergy Arkansas
2.76
 
3.25
 
3.36
 
3.83
 
3.60
Entergy Gulf States Louisiana
3.78
 
3.57
 
3.43
 
4.30
 
3.54
Entergy Louisiana
3.03
 
2.92
 
1.93
 
1.70
 
3.19
Entergy Mississippi
3.00
 
2.97
 
2.59
 
3.27
 
3.16
Entergy New Orleans
3.56
 
1.74
 
2.67
 
4.74
 
4.08

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, or participation in joint ventures that own, non-nuclear power plants and the sale to wholesale customers of the electric power produced by these plants.
    
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 was announced in August 2013, as a result of 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.


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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
 
IS0-NE
 
1972
 
July 1999
 
Plymouth, MA
 
688 MW - Boiling Water
 
2032
FitzPatrick
 
NYISO
 
1975
 
Nov. 2000
 
Oswego, NY
 
838 MW - Boiling Water
 
2034
Indian Point 3
 
NYISO
 
1976
 
Nov. 2000
 
Buchanan, NY
 
1,041 MW - Pressurized Water
 
2015
Indian Point 2
 
NYISO
 
1974
 
Sept. 2001
 
Buchanan, NY
 
1,028 MW - Pressurized Water
 
2013 (b)
Vermont Yankee (a)
 
IS0-NE
 
1972
 
July 2002
 
Vernon, VT
 
605 MW - Boiling Water
 
2032
Palisades
 
MISO
 
1971
 
Apr. 2007
 
Covert, MI
 
811 MW - Pressurized Water
 
2031

(a)
On December 29, 2014, the Vermont Yankee plant ceased power production.
(b)
The original expiration date of the NRC operating license for Indian Point 2 was September 28, 2013. Indian Point 2 has now entered its “period of extended operation” after expiration of the plant’s 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. The Indian Point license renewal application qualifies for timely renewal protection because it met NRC regulatory standards for timely filing.

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 date of the NRC operating license for Indian Point 2 was in September 2013 and the original expiration date of the NRC operating license for Indian Point 3 is in December 2015. Authorization to operate Indian Point 2 rests, and for Indian Point 3 will likely rest, on Entergy’s having timely filed a license renewal application that remains pending before the NRC. Indian Point 2 has now entered its “period of extended operation” after expiration of the plant’s 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. Indian Point 3 is expected to reach the same milestone, and to become subject to the same statutorily prescribed extension of its license expiration date, in December 2015. 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. For additional discussion of the license renewal applications, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.


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Non-nuclear Generating Stations

Entergy Wholesale Commodities includes the ownership, or interests in joint ventures that own, the following non-nuclear power plants:
 
Plant
 
 
Location
 
 
Ownership
 
Net Owned
Capacity(a)
 
 
Type
Rhode Island State Energy Center; 583 MW
 
Johnston, RI
 
100%
 
583 MW
 
Gas
Independence Unit 2;   842 MW
 
Newark, AR
 
14%
 
121 MW(b)
 
Coal
Top of Iowa;   80 MW (c)
 
Worth County, IA
 
50%
 
40 MW
 
Wind
White Deer;   80 MW (c)
 
Amarillo, TX
 
50%
 
40 MW
 
Wind
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 and Vermont Yankee and Rhode Island plants fall under the authority of the Independent System Operator (ISO) New England and the FitzPatrick and 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 New England, 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 sells energy in the day ahead or spot markets.  In addition to selling the energy produced by its plants, Entergy Wholesale Commodities 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 fixed price 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 will receive the value of any new environmental credits for the first ten years of the agreement.  Palisades and Consumers Energy will share on a 50/50 basis the value of any new environmental credits for years 11 through 15 of the agreement.  The environmental credits are defined as benefits from a change in law that causes capability of the plant as of the purchase date to become a tradable attribute (e.g., emission credit, renewable energy credit, environmental credit, “green” credit, etc.) or otherwise to have a market value.


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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 New England, NYISO, and MISO.  Substantially all of the counterparties or their guarantors for the planned energy output under contract for Entergy Wholesale Commodities nuclear plants have public investment grade credit ratings.

Competition

The ISO New England 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’s current output is contracted to Consumers Energy through 2022 and, therefore, 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 scheduled for the spring and the fall, and cause volumetric decreases during those seasons.  When outdoor and cooling water temperatures are lower, generally during colder months, Entergy Wholesale Commodities nuclear power plants operate more efficiently, and consequently, generate more electricity.  Many of Entergy Wholesale Commodities’ contracts provide for shaped pricing over the course of the year.  As a result of these factors, Entergy Wholesale Commodities’ revenues are typically higher in the first and third quarters than in the second and fourth quarters.

Fuel Supply

Nuclear Fuel

See “Fuel Supply - Nuclear Fuel” in the Utility portion of Part I, Item 1 for a discussion of the nuclear fuel cycle and markets.  Entergy Nuclear Fuels Company, a wholly-owned subsidiary, is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for Entergy Wholesale Commodities nuclear power plants, while Entergy Nuclear Operations, Inc. acts as the agent for the purchase of nuclear fuel assembly fabrication services.  All contracts for the disposal of spent nuclear fuel are between the DOE and each of the nuclear power plants.

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

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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 functions include origination of new energy and capacity transactions and generation scheduling.

Entergy Nuclear, Inc. pursues 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 and continues to pursue opportunities for Entergy Wholesale Commodities with other nuclear plant owners through operating agreements.

Entergy Nuclear, Inc. also offers operating license renewal and life extension services to nuclear power plant owners.  TLG Services, a subsidiary of Entergy Nuclear Inc., offers decommissioning, engineering, and related services to nuclear power plant owners.  In April 2009, Entergy announced that it will team with energy firm ENERCON to offer nuclear development services ranging from plant relicensing to full-service, new plant deployment.  ENERCON has experience in engineering, environmental, technical and management services.

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.  Entergy continues to provide implementation services for the renewed license.  In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029.

Regulation of Entergy’s Business

Federal Power Act

The Federal Power Act provides the FERC the authority to regulate:

•
the transmission and wholesale sale of electric energy in interstate commerce;
•
sale or acquisition of certain assets;
•
securities issuances;
•
the licensing of certain hydroelectric projects;
•
certain other activities, including accounting policies and practices of electric and gas utilities; and
•
changes in control of FERC jurisdictional entities or rate schedules.

The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over some of the rates charged by Entergy Arkansas and Entergy Gulf States 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.


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Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 70 MW of capacity.

State Regulation

Utility

Entergy Arkansas is subject to regulation by the APSC, 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 and as a result, may be required to submit certain matters approved by the APSC for consideration by the Tennessee Regulatory Authority. 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 Gulf States Louisiana’s electric and gas business and Entergy Louisiana are subject to regulation by the LPSC as to:

•
utility service;
•
retail rates and charges;
•
certification of generating facilities;
•
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.

Entergy Louisiana is also subject to the jurisdiction of the City Council with respect to such matters within Algiers in Orleans Parish, although the precise scope of that jurisdiction differs from that of the LPSC.

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.


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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;
•
issuance and sale of certain securities; and
•
other matters.

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 Gulf States Louisiana, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend, 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 operator of Pilgrim, Indian Point Energy Center, FitzPatrick, Vermont Yankee, and Palisades.  Substantial capital expenditures at Entergy’s nuclear plants because of revised safety requirements of the NRC could be required in the future.

Nuclear Waste Policy Act of 1982

Spent Nuclear Fuel

Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors.  Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982.  The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date.  Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2014 of $181.3 million for the one-time fee.  Entergy accepted assignment of the Pilgrim, FitzPatrick and Indian Point 3, Indian Point 1 and 2, Vermont Yankee, Palisades, and Big Rock Point spent fuel disposal contracts with the DOE held by their previous owners.  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

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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. Moreover, the current Presidential administration has taken specific steps to discontinue the Yucca Mountain project and study a new spent fuel strategy. Such actions included 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. This amount of money is not expected to be sufficient to complete the review. 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 current Presidential administration’s 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. In November 2003 these subsidiaries, except for the owner of Palisades, began litigation to recover the damages caused by the DOE’s delay in performance. Through 2014, Entergy’s subsidiaries have won and collected on judgments in excess of $200 million , including approximately $48 million collected by Entergy Arkansas in 2013, against the U.S. for damages caused by the DOE’s breach of the contract. First round or second round damages cases are in progress covering each of the nuclear plants owned by Entergy subsidiaries. In 2014 trials were held in three additional cases (second round ANO case, second round Grand Gulf case, and first round Waterford 3 case) but judgments have not yet been issued in any of those cases. A second round case was filed for the Vermont Yankee plant in April 2014 and a second round case was filed for the Pilgrim plant in December 2014. 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.  


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Nuclear Plant Decommissioning

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Texas, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, the portion of River Bend subject to retail rate regulation, Waterford 3, and Grand Gulf, respectively.  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.

Following a review in 2009, Entergy concluded that there was a funding shortfall for Vermont Yankee of approximately $40 million, which it satisfied with a $40 million guarantee from Entergy Corporation that is still in place subject to a 120-day notice of cancellation sent to the NRC in December 2014.  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.  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. See Note 1 to the financial statements for further discussion of Vermont Yankee decommissioning costs.

For the Indian Point 3 and FitzPatrick plants purchased in 2000, NYPA retained the decommissioning trusts and the decommissioning liabilities.  NYPA and Entergy subsidiaries executed decommissioning agreements, which specify their decommissioning obligations.  NYPA has 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.  If the decommissioning liabilities are retained by NYPA, the responsible Entergy subsidiary will perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts.

In March 2014, Entergy Nuclear Operations made filings with the NRC reporting on decommissioning funding for certain of Entergy’s nuclear plants. Those reports all showed that decommissioning funding for 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 17 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 $127.318 million per reactor (with 104 nuclear industry reactors currently participating).  In the case of a nuclear event in which Entergy Arkansas, Entergy Gulf States Louisiana, 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.


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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.  Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated.  Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.

Clean Air Act and Subsequent Amendments

The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other  facilities.  Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements.  These programs include:

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New source review and preconstruction permits for new sources of criteria air pollutants, new and existing sources of 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 permits program for administration and enforcement of these and other Clean Air Act programs;
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Regional Haze and Best Available Retrofit Technology 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 has followed 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.

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.  In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA.  Entergy responded to both requests.  Neither EPA request for information alleged that the facilities are in violation of law.


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Acid Rain Program

The Clean Air Act provides SO2 allowances to most of the affected Entergy generating units for emissions based upon past emission levels and operating characteristics.  Each allowance is an entitlement to emit one ton of SO2 per year.  Plant owners are required to possess allowances for SO2 emissions from affected generating units.  Virtually all Entergy fossil-fueled generating units are subject to SO2 allowance requirements.  Entergy could be required to purchase additional allowances when it generates power using fuel oil.  Fuel oil usage is determined by economic dispatch and influenced by the price and availability of natural gas, incremental emission allowance costs, and the availability and cost of purchased power.

Ozone Nonattainment

Entergy Texas operates one fossil-fueled generating unit (Lewis Creek) in a geographic area that is not in attainment of 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 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.  The area’s new attainment date for the 8-hour ozone standard is as expeditiously as practicable, but no later than June 15, 2019.

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.

For these marginal areas attainment must be demonstrated no later than July 20, 2015 (with EPA evaluating whether the area attained the standard based on monitored ozone data from 2013-2015).  In the final designation rule, EPA states that it anticipates the marginal areas will be able to attain by that date based upon reductions attendant with other rules and programs such as the interstate transport rules.  Entergy facilities in these areas may be subject to installation of NOx controls, but the degree of control will remain unknown until the states are further along in implementation in the marginal areas.   Entergy will continue to monitor and engage in the state’s implementation process in Entergy states.

In December 2014 the EPA published a proposed rule to lower the primary and secondary NAAQS for ozone to a level within a range of 65 to 75 parts per billion (ppb). The agency also is asking for comment on the potential for leaving the standard at its current level of 75 ppb, or lowering the standard to 60 ppb. Entergy is analyzing the proposal and is engaged with industry groups, regulators, and lawmakers. If the standard is lowered, this may result in additional counties/parishes in which Entergy operates being designated as nonattainment and potentially requiring further emission reductions. Comments are due in March 2015, and a final rule is anticipated in late-2015 according to the EPA’s regulatory agenda.

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 has indicated that it will delay designations except for those areas with existing monitoring data from 2009

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to 2011 indicating violations of the new standard. In July 2013 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 1-hour national ambient air quality standard of 75 parts per billion. Entergy does not have a generation asset in that parish. In all other areas, analysis is required once EPA issues additional final regulations and guidance. Additional capital projects or operational changes may be required for Entergy facilities in these areas.

Hazardous Air Pollutants

The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011 and the rule became effective in April 2012. Entergy currently is on schedule to have the required controls in place for compliance at Entergy’s coal-fired units. Compliance with MATS is required by the Clean Air Act within three years, or by 2015, although certain extensions of this deadline are available from state permit authorities and the EPA. Entergy has applied for and received a one-year extension, as allowed by the Clean Air Act, for its affected facilities in Arkansas and Louisiana.

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, the CAIR was vacated and remanded to the EPA by the D.C. Circuit in 2008.  The court allowed the CAIR to become effective in January 2009, while the EPA revised the rule.  In July 2011 the EPA released its final Cross-State Air Pollution Rule (CSAPR, which previously was referred to as the Transport Rule).  The rule was directed at limiting the interstate transport of emissions of NOx and SO2 as precursors to ozone and fine particulate matter.  The final rule provided a significantly lower number of allowances to Entergy’s Utility states than did the draft rule.  Entergy’s capital investment and annual allowance purchase costs under the CSAPR would depend on the economic assessment of NOx and SO2 allowance markets, the cost of control technologies, generation unit utilization, and the availability and cost of purchased power.

Entergy filed a petition for review with the United States Court of Appeals for the D.C. Circuit and a petition with the EPA for reconsideration of the rule and stay of its effectiveness. Several other parties filed similar petitions. In December 2011 the Court of Appeals for the D.C. Circuit Court stayed CSAPR and instructed the EPA to continue administering CAIR, pending further judicial review. In August 2012 the court issued a decision vacating CSAPR and leaving CAIR in place pending the promulgation of a lawful replacement for both rules. In January 2013 the court denied petitions for reconsideration filed by the EPA and certain states and intervenors. In March 2013 the EPA and other parties filed petitions for certiorari with the U.S. Supreme Court. The U.S. Supreme Court issued an order in June 2013 granting the EPA’s and environmental groups’ petitions for review of the D.C. Circuit’s decision vacating CSAPR. In April 2014 the U.S. Supreme Court reversed the D.C. Circuit and remanded the case to the D.C. Circuit for further proceedings. In June 2014 the EPA filed a motion with the D.C. Circuit Court requesting that the court lift the stay and extend CSAPR’s deadlines by three years so that the Phase 1 emissions budgets apply in 2015 and 2016 and the Phase 2 emissions budgets apply in 2017 and beyond. In October 2014 the D.C. Circuit granted EPA’s motion to lift the stay. Accordingly, CSAPR Phase 1 implementation became effective January 1, 2015. Entergy is developing a compliance plan that could include installation of controls at certain facilities and an emission allowance procurement strategy. Litigation concerning several issues not determined by the U.S. Supreme Court continues in the D.C. Circuit.

Regional Haze

In June 2005, the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that could potentially result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology

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(BART) on certain of Entergy’s coal and oil generation units.  The rule leaves certain CAVR determinations to the states.  The Arkansas Department of Environmental Quality (ADEQ) prepared a State Implementation Plan (SIP) for Arkansas facilities to implement its obligations under the CAVR.  The ADEQ determined that Entergy Arkansas’s White Bluff power plant affects a Class I Area’s visibility and will be subject to the EPA’s presumptive BART limits, which likely would require the installation of scrubbers and low NOx burners.  Under then-current state regulations, the scrubbers would have had to be operational by October 2013.  Entergy Arkansas filed a petition in December 2009 with the Arkansas Pollution Control and Ecology Commission requesting a variance from this deadline because the EPA had expressed concerns about Arkansas’s Regional Haze SIP and questioned the appropriateness of issuing an air permit prior to that approval.  Entergy Arkansas’s petition requested that, consistent with federal law, the compliance deadline be changed to as expeditiously as practicable, but in no event later than five years after EPA approval of the Arkansas Regional Haze SIP.  The Arkansas Pollution Control and Ecology Commission approved the variance in March 2010.  In October 2011 the EPA released a proposed rule addressing the Arkansas Regional Haze SIP.  In the proposal the EPA disapproved a large portion of the Arkansas Regional Haze SIP, including the emission limits for NOx and SO2 at White Bluff.  The final rule was published, mostly unchanged, in March 2012 and became final in April 2012.  This triggered a two-year timeframe in which the EPA was required to either approve a revised SIP issued by Arkansas or issue a Federal Implementation Plan (FIP).  This two-year time frame expired in April 2014. In December 2014 a draft consent decree between the Sierra Club and the EPA was filed with the U.S. District Court for the Eastern District of Arkansas. This consent decree states that the EPA is to issue a draft FIP addressing Regional Haze requirements in Arkansas by no later than March 6, 2015 and a final FIP for these same requirements by no later than December 15, 2015. The consent decree has not been finalized. These decisions could impact the timing and level of control installation at Entergy's units in Arkansas.

Fine Particle (PM2.5) National Ambient Air Quality Standard

In December 2012 the EPA released regulations that lowered the NAAQS for fine particle pollution or PM2.5.  In December 2014 the EPA issued final area designations for this standard. All areas in Entergy’s service territory were designated as “Unclassifiable/Attainment” for this standard.  Entergy will continue to monitor and engage in the state’s implementation process in Entergy states.

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;
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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;
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efforts in Congress or at the EPA to establish a mandatory federal carbon dioxide emission control structure or unit performance standards;
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revisions to the estimates of the Social Cost of Carbon used for regulatory impact analysis of Federal laws and regulations;
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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;
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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;

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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;
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efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of PCBs; and
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efforts by certain external groups to encourage reporting and disclosure of carbon dioxide emissions and risk.  Entergy has prepared responses for the Carbon Disclosure Project’s (CDP) annual questionnaire for the past several years and has given permission for those responses to be posted to CDP’s website.

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 kilowatt-hour of electricity generated.  In anticipation of the potential 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 actually 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 and now includes 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, approximately 45.5 million tons in 2012, approximately 46.2 million tons in 2013, and approximately 41.8 million tons in 2014. The decrease in this number in 2014 is 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.
    
Greenhouse Gas Reporting

In September 2009, the EPA finalized a rule to require reporting of several greenhouse gases.  This rule requires Entergy to report annually greenhouse gas emissions from operating power plants, various combustion sources, certain transmission and distribution equipment, and natural gas distribution operations.  

New and Existing Source Performance Standards for Greenhouse Gas Emissions

As a part of a climate plan announced in June 2013, President Obama directed the EPA 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 September 2013 the EPA issued the proposed New Source Performance Standards rule for new sources. The rule was published in the Federal Register in January 2014. In June 2014 the EPA issued proposed standards for existing power plants.  Entergy is actively engaged in the rulemaking process, having submitted comments to the EPA in December 2014. Cost and methods of compliance remain unknown at this time.

Nelson Unit 6 (Entergy Gulf States Louisiana)

Entergy Gulf States Louisiana has self-reported to the LDEQ an annual carbon monoxide (CO) emission limit deviation at the Nelson Unit 6 coal-fired facility for the years 2006-2010 and the failure to report these deviations in semi-annual reporting and in annual Title V compliance certifications. Entergy Gulf States Louisiana is not required

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to monitor carbon monoxide emissions from Nelson Unit 6 using a continuous emissions monitoring system (CEMS). Stack tests performed in 2010 appear to indicate CO emissions in excess of the maximum hourly limit for three - 1 hour test runs; however, comparison of the 2010 stack tests with the most recent previous tests, from 2006, appear to indicate that the permit limits were calculated incorrectly in the Title V Permit application and should have been higher using the 2006 stack test as the basis. The 2010 test emission levels did not cause a violation of NAAQS. Additionally, the 2010 stack testing, which was performed in compliance with an EPA data request connected to the agency’s development of a new air emissions rule, was not taken during a period of normal and representative operations for Nelson 6. Settlement negotiations continue with the LDEQ.

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.  Additionally, the State of New York has taken the position that a new state-issued water quality certification is required as part of the NRC license renewal process.  Entergy Wholesale Commodities’ Indian Point nuclear facility in New York is seeking a new Section 401 certification prior to license renewal under full reservation of rights.

Indian Point

Entergy is involved 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.  In November 2003 the NYSDEC issued a draft permit indicating that closed cycle cooling would be considered the “best technology available” for minimizing alleged adverse environmental effects attributable to the intake of cooling water at Indian Point, subject to a feasibility determination and alternatives analysis for that technology, if Entergy applied for and received NRC license renewal for Indian Point 2 and Indian Point 3.  Upon becoming effective, the draft permit also would have required payment of approximately $24 million annually, and an annual 42 unit-day outage period, until closed cycle cooling is implemented.  Entergy is participating in the administrative process to request that the draft permit be modified prior to final issuance, and opposes any requirement to install cooling towers at Indian Point.

An August 2008 ruling by the NYSDEC’s Assistant Commissioner restructured the permitting and administrative process, including the application of a new economic test designed to implement the U.S. Second Circuit Court of Appeals standard in that court’s review of the EPA’s cooling water intake structure rules, which is discussed in the 316(b) Cooling Water Intake Structures section below.  The NYSDEC has directed Entergy to develop detailed feasibility information regarding the construction and operation of cooling towers, and alternatives to closed cycle cooling, prior to the issuance of a new draft permit by the NYSDEC staff and commencement of the adjudicatory proceeding.  The reports include a visual impact and aesthetics report filed in June 2009, a plume and emissions report filed in September 2009, a technical feasibility report and alternatives analysis filed in February 2010, and an economic report to establish whether the technology, if feasible, satisfies the economic test that is part of the New York standard.  Entergy requested that the NYSDEC Assistant Commissioner reconsider the New York standard in light of the U.S. Supreme Court decision reversing the Second Circuit’s alternative economic test adopted in the August 2008 ruling.  In November 2012 the NYSDEC Assistant Commissioner’s delegate issued a decision overturning the alternative economic test adopted in the August 2008 ruling and reestablishing the “wholly disproportionate” test

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derived from previous New York precedent. The wholly disproportionate test considers whether the costs of a technology are wholly disproportionate to the environmental benefits gained from the technology.

In February 2010, Entergy provided to the NYSDEC an updated estimate of the capital cost to retrofit Indian Point 2 and Indian Point 3 with cooling towers. Construction costs for retrofitting with cooling towers are estimated to be at least $1.19 billion, in addition to lost generation of approximately 14.5 terawatt-hours (TWh) during the forced outage of both units that is estimated to take at least 42 weeks. Entergy also proposed an alternative to the cooling towers, the use of cylindrical wedgewire screens, the construction costs of which are now expected to be approximately $250 million to $300 million. Because a cooling tower retrofitting of this size and complexity has never been undertaken at an operating nuclear facility, significant uncertainties exist in the capital cost estimates and, therefore, the actual capital costs could be materially higher than estimated. Moreover, construction outage-related costs to Entergy have not been calculated because of the significant variability in power pricing at any given time, but they are expected to be significant and may exceed the capital costs. The capital cost estimate for the wedgewire screen construction is also subject to uncertainty. Hearings on certain issues began in 2011 in consolidation with certain issues in the water quality certification matter.

Hearings were held in July 2013 before NYSDEC ALJs on environmental issues related to Indian Point’s wedgewire screen proposal for “best technology available.” In 2014, hearings were held on NYSDEC’s proposed best technology available, closed cycle cooling. NYSDEC also has proposed annual fish protection outages of 42, 62, or 92 days at both units or at one unit with closed cycle cooling at the other. The ALJs held a further legislative hearing and issues conference on this NYSDEC staff proposal in July 2014. In January 2015, Entergy wrote NYSDEC leadership requesting an explanation of the delay in release of the ruling following an ALJ's on-record statement that the ALJ's draft ruling was under "executive review." In February 2015 the ALJs issued a ruling scheduling hearings on the outage proposals and other pending issues in September and October 2015, with post-hearing briefing to follow in December 2015. For additional discussion of this and other proceedings related to Indian Point, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
Pilgrim Nuclear Power Station

In October 2012, EcoLaw, a coalition of several environmental groups, served Entergy Nuclear Generating Company and Entergy Nuclear Operations, Inc. with a notice of intent (NOI) to sue under the Clean Water Act for alleged violations at the Pilgrim Nuclear Power Station.  The NOI alleges 33,253 discharge permit violations since 1994 (including alleged violations prior to Entergy’s ownership; Entergy purchased the plant in 1999) and seeks $25,000 per violation for a total of $831,325,000.  The Clean Water Act states that an alleged violator must be given 60 days notice prior to a citizen’s suit being filed.  Review of the NOI indicates that many of the alleged violations were discharges in compliance with the current EPA facility discharge permit, which the putative plaintiff alleges was improperly issued or modified.  An additional NOI was served by EcoLaw to the same Entergy parties and the Massachusetts Department of Environmental Protection alleging violations of state water quality standards and requesting revocation of the state-issued Section 401 Water Quality Certification associated with the plant’s water discharge permit.  In November and December 2012, Entergy filed responses to the state and federal notices of intent to sue.  To date, Pilgrim has not received notice that EcoLaw has initiated any lawsuits against Pilgrim.

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. In January 2007 the U.S. Second Circuit Court of Appeals remanded the rule to the EPA for reconsideration. The court instructed the EPA to reconsider several aspects of the rule that were beneficial to businesses affected by the rule after finding that these provisions of the rule were contrary to the language of the Clean Water Act or were not sufficiently explained in

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the rule. In April 2008 the U.S. Supreme Court agreed to review the Second Circuit decision on the question of whether the EPA may take into consideration a cost-benefit analysis in developing these regulations, a consideration of potential benefit to businesses affected by the rule that the Second Circuit disallowed. In March 2009 the Supreme Court ruled in favor of the petitioners that cost-benefit analysis may be taken into consideration. The EPA reissued the proposed rule in April 2011. Entergy filed comments with the EPA on the proposed rule. The EPA further extended the finalization deadline to November 2013, then to January 2014, and then to April 2014. In May 2014 the EPA issued the final 316(b) rule, followed by publication in the Federal Register in August 2014, with the final rule effective in October 2014. Entergy is developing a compliance plan for each affected facility in accordance with the requirements of the final rule.

Entergy filed as a co-petitioner with the Utility Water Act Group a petition for review of the final rule. The case will be heard in the U.S. Second Circuit Court of Appeals. Entergy expects briefing on the case to occur in 2015.

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. The CZMA gives the state six months to act once the consistency determination is deemed complete; failure to act is treated as a deemed concurrence. Entergy is pursuing three independent paths to ensure that CZMA requirements for Indian Point license renewal are met. For additional discussion of the CZMA proceedings related to Indian Point license renewal see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

Effluent Limitation Guidelines

In April 2013 the EPA issued proposed effluent limitation guidelines that, if adopted as final, would apply to discharges from Entergy’s generating facilities that hold national pollutant discharge elimination system permits under the Clean Water Act.  The limitations proposed primarily affect coal units. The proposal includes several options for public consideration.  Entergy submitted comments on the proposed rule and will continue to engage in the public comment process as appropriate. The EPA announced that the final rule will be issued no later than September 30, 2015.

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 says will inform the rulemaking. The proposed rule was published in the Federal Register in April 2014. The initial 90-day public comment period was extended until November 2014. Preliminary review indicates that this proposal 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. Entergy is actively engaged in the rulemaking process and anticipates a final rule in April 2015.

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Groundwater at Certain Nuclear Sites

The NRC requires nuclear power plants to regularly monitor and report 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, FitzPatrick, 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.

Indian Point Units 1 and 2 Hazardous Waste Remediation

Prior to Entergy’s purchase of Indian Point Unit 1, the previous owner completed the cleanup and desludging of the Unit 1 water storage pool, generating mixed waste. The existing mixed waste storage permit and an associated order on consent were transferred to Entergy upon purchasing the unit. The waste is stored in the Unit 1 containment building in accordance with NRC regulations controlling low level radioactive waste. An order on consent with NYSDEC requires a quarterly survey of the availability of any commercial facility capable of treating, processing, and disposing of this waste in a commercially reasonable manner. However, in 2005, NYSDEC revised its regulations to conditionally exempt the storage and disposal of mixed waste that is regulated by the NRC. Thus, in October 2005 and again in January 2013, Entergy requested that NYSDEC terminate the mixed waste permit and order on consent because the waste falls within the mixed waste exemption. In April 2013, NYSDEC agreed with Entergy’s request to terminate the permit finding that as long as the facility continues to meet the exemption, the mixed waste permit is not required. NYSDEC denied the request to terminate the consent order, however, reasoning that it contains provisions for storage and reporting that are still applicable. Entergy continues to manage the waste according to applicable regulatory requirements.

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

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such environmental clean-up and restoration activities.  Details of CERCLA and similar state program liabilities that are not de minimis 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 used in certain processes would remain excluded from hazardous waste regulation. In December 2014 the EPA issued 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.  

Other Environmental Matters

Entergy Gulf States Louisiana and Entergy Texas

Several class action and other suits have been filed in state and federal courts seeking relief from Entergy Gulf States, Inc. and others for damages caused by the disposal of hazardous waste and for asbestos-related disease allegedly resulting from exposure on Entergy Gulf States, Inc.’s premises (see “Litigation” below).

Entergy Gulf States Louisiana is currently 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, was apparently routed to a portion of the property for disposal.  The same area has also 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.  In 2010 the EPA conducted a Five Year Review (FYR) of the 10-year groundwater monitoring program at Lake Charles.  Negotiations are on-going regarding whether additional actions will be necessary at the site.  If additional actions are necessary, site expenditures will increase commensurate with the additional chosen site remedies. Entergy does not have sufficient information at this time to estimate additional site costs, if any. Entergy also has made a payment to the EPA of $275,000 for past agency oversight costs. Entergy Gulf States Louisiana and Entergy Texas each believe that its remaining responsibility for this site will not materially exceed the existing clean-up provisions of $0.3 million for Entergy Gulf States Louisiana and $0.2 million for Entergy Texas. Meetings to discuss the status of this project with the EPA are scheduled in 2015.

Entergy Louisiana, and Entergy New Orleans

Several class action and other suits have been filed in state and federal courts seeking relief from Entergy Louisiana and Entergy New Orleans and others for damages caused by the disposal of hazardous waste and for asbestos-related disease allegedly resulting from exposure on Entergy Louisiana’s and Entergy New Orleans’s premises (see “Litigation” below).


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Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy New Orleans, and Entergy Texas

The Texas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, Entergy Gulf States Louisiana, 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 Gulf States Louisiana, Entergy Texas, Entergy Louisiana, and Entergy Arkansas responded to an information request from the TCEQ and continue to cooperate in this investigation.  Entergy Gulf States Louisiana, Entergy Texas, and Entergy Louisiana 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 Gulf States Louisiana, 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 preliminary and variable depending on the level of third-party cost contributions, indicate that Entergy’s total share of remediation costs likely will be in the range of $1.5 million to $2 million.  Remediation activities continue at the site.

Entergy Mississippi, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy New Orleans, and Entergy Texas

The EPA notified Entergy Mississippi, Entergy Gulf States Louisiana, Entergy Texas, and Entergy New Orleans that the EPA believes those entities are PRPs concerning contamination of an area known as “Devil’s Swamp Lake” near the Port of Baton Rouge, Louisiana.  The area allegedly was contaminated by the operations of Rollins Environmental (LA), Inc, which operated a disposal facility to which many companies contributed waste.  Documents provided by the EPA indicate that Entergy Louisiana may also be a PRP.  Entergy continues to monitor this developing situation.

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)

Texas Power Price Lawsuit

See Note 2 to the financial statements for a discussion of this proceeding.

Mississippi Attorney General Complaint

See Note 2 to the financial statements for a discussion of this proceeding.
 
Asbestos Litigation (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

See Note 8 to the financial statements for a discussion of this litigation.


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Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

See Note 8 to the financial statements for a discussion of these proceedings.

Employees

Employees are an integral part of Entergy’s commitment to serving customers.  As of December 31, 2014, Entergy subsidiaries employed 13,393 people.

Utility:
 

Entergy Arkansas
1,160

Entergy Gulf States Louisiana
729

Entergy Louisiana
890

Entergy Mississippi
673

Entergy New Orleans
298

Entergy Texas
596

System Energy
—

Entergy Operations
2,764

Entergy Services
2,852

Entergy Nuclear Operations
3,376

Other subsidiaries
55

Total Entergy
13,393


Approximately 5,200 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 our annual and quarterly reports on Forms 10-K and 10-Q (including related filings in XBRL format) and current reports on Form 8-K; our 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 Gulf States Louisiana, 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 are 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.

In addition, regulators can 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 can 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.  The proceedings 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 the 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 Arkansas and Entergy Texas are established in traditional base rate case proceedings. Entergy Arkansas recovers fuel and purchased energy and certain non-fuel costs through other APSC-approved tariffs. Entergy Mississippi infrequently has traditional base rate cases, although one was filed and settled in 2014. More commonly, it obtains base rate adjustments through its formula rate plan, which operates annually. In the event that this formula rate plan were terminated, Entergy Mississippi would at that time revert to the more traditional rate case environment.

In January 2013, Entergy Gulf States Louisiana’s and Entergy Louisiana’s then-existing formula rate plans expired, and each company filed full rate cases in February 2013. As part of the rate cases that Entergy Louisiana and Entergy Gulf States Louisiana filed, each company requested that the LPSC approve new formula rate plans.  In December 2013 the LPSC voted to approve a settlement that provides for the continued use, through the test year 2016 filing, of formula rate plans by Entergy Louisiana and Entergy Gulf States Louisiana. Entergy Louisiana’s formula rate plan changes are capped at a cumulative total of $30 million through the formula rate plan cycle. Entergy Gulf States Louisiana has no cap but is not permitted to increase rates prior to the test year 2015 filing. As part of the settlement, both companies established mechanisms to recover non-fuel MISO-related costs calculated separately from the formula rate plan requirements, but embedded in the formula rate plan factor applied on customer bills. MISO fuel and energy-related costs are recoverable in Entergy Gulf States Louisiana’s and Entergy Louisiana’s fuel adjustment

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clauses. The formula rate plans continue to retain exceptions from the rate cap/restrictions and sharing requirements for certain large capital investment projects, including the Ninemile 6 generating facility. In the event that these formula rate plans were terminated, or expire without renewal or extension, Entergy Gulf States Louisiana and Entergy Louisiana would at that time revert to the more traditional rate case environment. Additionally, in September 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed with the LPSC a joint application seeking to combine the two companies. In connection with this request, the companies are also seeking to combine the formula rate plans approved for each company into a single formula rate plan with a single combined-company filing for 2014. Most of the provisions under the existing separate formula rate plans would be retained under the combined formula rate plan. Further, Entergy Louisiana and Entergy New Orleans have filed with the Council of the City of New Orleans a joint application seeking authorization to transfer certain assets of Entergy Louisiana used to serve the Fifteenth Ward of New Orleans (commonly referred to as Algiers) to Entergy New Orleans. Entergy New Orleans has operated under a formula rate plan that ended with the 2011 test year and has not yet been extended. If no formula rate plan is approved going forward, Entergy New Orleans will continue operating in the more traditional rate case environment.

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 certain of 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 with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs.  Regulators can 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.

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.

As a result of a challenge by the LPSC, the manner in which the Utility operating companies have traditionally shared the costs associated with coordinated planning, construction, and operation of generating resources has been changed by the FERC, a development which has had and could continue to require adjustment of retail and wholesale rates in the jurisdictions where the Utility operating companies provide service and has introduced additional uncertainty in the ratemaking process.

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 has been approved by the FERC.  In 2005 the FERC issued a decision requiring changes to the cost allocation methodology used in that rate schedule.

In 2007 through 2012, payments were made by Entergy Arkansas to certain of the Utility operating companies in compliance with the 2005 FERC decision on the cost allocation methodology, and in 2013 and 2014, payments were made by Entergy Texas to Entergy New Orleans.  There have been challenges to the level and timing of payments

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made by Entergy Arkansas under the FERC’s decision and the prudence of the Utility operating companies’ production costs.  The ability to recover in rates any changes to the cost allocation resulting from the challenges, and timing of such recovery, could be uncertain and could be the subject of additional regulatory and other proceedings.  For information regarding these and other proceedings associated with the System Agreement, as well as additional information regarding the System Agreement itself, see Note 2 to financial statements, System Agreement Cost Equalization Proceedings. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.

The withdrawal and notices of withdrawal of certain Utility operating companies from the System Agreement create uncertainty regarding the System Agreement and the effect of the absence of such an arrangement on the Utility operating companies.

Entergy Arkansas’s participation in the System Agreement terminated in December 2013, and Entergy Mississippi’s participation in the System Agreement is scheduled to terminate in November 2015.

In October 2013, the Utility operating companies filed at the FERC seeking to shorten to 60 months the provision in the System Agreement that requires a Utility operating company seeking to withdraw from the System Agreement to provide 96 months advance notice of termination of participation. In October 2013, Entergy Texas provided its notice to the other Utility operating companies to terminate its participation in the System Agreement after expiration of the proposed 60-month notice period or such other period as approved by the FERC. Subsequently, Entergy Texas filed its notice to terminate its participation in the System Agreement at FERC in October 2013. In January 2014, the LPSC directed Entergy Louisiana and Entergy Gulf States Louisiana to provide no later than February 15, 2014 notice of their intention to terminate their participation in the System Agreement, and to use their reasonable best efforts to achieve a consensual resolution permitting early termination of the System Agreement. Entergy Louisiana and Entergy Gulf States Louisiana provided notice of their termination on February 14, 2014. Accordingly, there is uncertainty regarding the continuation of the System Agreement and the effect of the absence of such an arrangement on the Utility operating companies.

For further information regarding the regulatory proceedings relating to the System Agreement, see the “Rate, Cost-recovery, and Other Regulation - Federal Regulation - System Agreement” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries.

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. For further information regarding the FERC and proceedings related to the MISO RTO, see the “Rate, Cost-recovery, and Other Regulation - Federal Regulation - Entergy’s Integration Into the MISO Regional Transmission Organization” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. 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, including the implementation of competition among transmission providers, that cause additional risk.


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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. 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 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.

(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, 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 and Regulatory Risks

(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, 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.  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.

Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities nuclear plant owners periodically shut down their nuclear power plants to replenish fuel.  Plant maintenance and upgrades are often scheduled during such refueling outages.  If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.


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Outages at nuclear power plants to replenish fuel require the plant to be “turned off.”  Refueling outages generally are planned to occur once every 18 to 24 months and average approximately 30 days in duration.  Plant maintenance and upgrades are often scheduled during such planned outages.  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), and the risk of being unable to effectively manage these risks by purchasing from a diversified mix of sellers located in a diversified mix of countries 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 2015.  Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners and enrichers.  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 also may draw upon its own inventory intended for later generation periods, depending upon its risk management strategy 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 increases 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.

Certain of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations or suspend or revoke their licenses, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.

Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants.  The NRC may modify, suspend, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for nuclear facilities.  A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses 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.  Events at nuclear plants owned by others, as well as those owned by one of these companies, may cause the NRC to initiate such actions.  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

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the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, System Energy, or Entergy Wholesale Commodities.  For example, the earthquake of March 11, 2011 that affected the Fukushima Daiichi nuclear plants in Japan resulted in the NRC issuing three orders effective on March 12, 2012 requiring U.S. nuclear operators, including Entergy, to undertake plant modifications or perform additional analyses that will, among other things, result in increased capital and operating costs associated with operating Entergy’s nuclear plants, some of which could be material.

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 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 reduced profitability.  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 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.  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 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 on a periodic basis 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 Obama administration has expressed its intention and taken specific steps to discontinue the Yucca Mountain project and study a new spent fuel strategy.  These actions may prolong 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 plans to 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.  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 Gulf States Louisiana, Entergy Louisiana, and System Energy.


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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 $127.318 million per reactor.   With 104 reactors currently participating, this translates to a total public liability cap of approximately $13.241 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 (currently $375 million for each operating site).  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 $375 million in 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 $375 million primary level, up to a maximum of $127.318 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.4 billion).  The retrospective premium payment is currently limited to $18.963 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $127.318 million cap.

NEIL is a utility industry mutual insurance company, owned by its members.  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 April 1, 2014, the maximum annual assessment amounts total $105.7 million for the Utility plants and $126.4 million for the Entergy Wholesale Commodities plants.  Retrospective Premium Insurance available through NEIL’s reinsurance treaty can cover the potential assessments.  The Entergy Wholesale Commodities plants currently maintain the Retrospective Premium Insurance to cover this potential assessment.

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.

Market performance and other changes may decrease the value of assets in the decommissioning trusts, 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 are based upon operating license lives as well as estimated trust fund earnings and decommissioning costs.  In connection with the acquisition of certain nuclear plants, the Entergy Wholesale Commodities plant owners also acquired decommissioning trust funds that are funded in accordance with NRC regulations.  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.  As part of the Pilgrim, Indian Point 1 and 2, Vermont Yankee, and Palisades/Big Rock Point purchases, the former owners transferred decommissioning trust funds, along with the liability to decommission the plants, to the

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respective Entergy Wholesale Commodities nuclear power plant owners.  In addition, the former owner of Indian Point 3 and FitzPatrick retained the decommissioning trusts and related liability to decommission these plants, but has the right to require the respective Entergy Wholesale Commodities nuclear plant owners to assume the decommissioning liability provided that it assigns the funds in the corresponding decommissioning trust, up to a specified level, to such owners.  Alternatively, the former owner may contract with Entergy Nuclear, Inc. for the decommissioning work at a price equal to the funds in the corresponding decommissioning trust up to a specified amount.  As part of the Indian Point 1 and 2 purchase, the Entergy Wholesale Commodities nuclear power plant owner also funded an additional $25 million to a supplemental decommissioning trust fund.  As part of the Palisades transaction, the Entergy Wholesale Commodities business assumed responsibility for spent fuel at the decommissioned Big Rock Point nuclear plant, which is located near Charlevoix, Michigan.  Once the spent fuel is removed from the site, the Entergy Wholesale Commodities business will dismantle the spent fuel storage facility and complete site decommissioning.  The Entergy Wholesale Commodities business expects to fund this activity from operating revenue, and Entergy is providing $5 million in credit support to provide financial assurance to the NRC for this obligation.

In 2008, Entergy experienced declines in the market value of assets held in the trust funds for meeting its decommissioning funding assurance obligations for its plants.  This decline adversely affected Entergy’s ability to demonstrate compliance with the NRC’s requirements for providing financial assurance for decommissioning funding for some of its plants, which deficiencies have now been corrected.  An early plant shutdown, poor investment results or higher than anticipated decommissioning costs could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that the Entergy Wholesale Commodities nuclear plant owners may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.  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 Gulf States Louisiana, Entergy Louisiana, and System Energy and Note 9 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 the 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 Gulf States Louisiana, 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 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 five of the six units in the current fleet of Entergy Wholesale Commodities nuclear power plants are 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, restrictions on nuclear units as a result of unavailability of sites for spent nuclear fuel storage and disposal, or other adverse effects on owning and operating 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.


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(Entergy Corporation)

A failure to obtain renewed licenses or other approvals required for the continued operation of the Entergy Wholesale Commodities nuclear power plants could have a material effect on Entergy’s results of operations, financial condition, and liquidity and could lead to an increase in depreciation rates or an acceleration of the timing for the funding of decommissioning obligations.

The license renewal and related processes for the Entergy Wholesale Commodities 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 is 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.  Various parties have expressed opposition to renewal of these licenses.  Renewal of the Indian Point licenses is the subject of ongoing proceedings before the Atomic Safety and Licensing Board (ASLB) of the NRC and, with respect to issues resolved by the ASLB, before the NRC on appeal.

In relation to Indian Point 2 and Indian Point 3, the New York State Department of Environmental Conservation has taken the position that these plant owners must obtain a new state-issued Clean Water Act Section 401 water quality certification as part of the license renewal process.  In addition, before the NRC may issue renewed operating licenses it must resolve its obligation to address the requirements of the Coastal Zone Management Act (CZMA). Most commonly, those requirements are met by the applicant's demonstration that the activity authorized by the federal permit being sought is consistent with the host state's federally-approved coastal management policies. Entergy has undertaken three independent initiatives to resolve CZMA issues: "grandfathering," "previous review," and a "consistency certification." In December 2014 the New York Supreme Court, Appellate Division, issued a unanimous ruling stating that Indian Point 2 and Indian Point 3 “are exempt from New York’s Coastal Management Program.”  That decision could be appealed. For further information regarding these environmental regulations see the “Regulation of Entergy's Business - Environmental Regulation - Clean Water Act” section in Part I, Item 1.

If the NRC finally denies the applications for the renewal of operating licenses for one or more of the Entergy Wholesale Commodities nuclear power plants, or a state in which any such nuclear power plant is located is able to prevent the continued operation of such plant, 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, 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 Entergy Wholesale Commodities nuclear power plants, see the “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

The decommissioning trust fund assets for the nuclear power plants owned by Entergy Wholesale Commodities nuclear plant owners may not be adequate to meet decommissioning obligations if one or more of their nuclear power plants is retired earlier than the anticipated shutdown date, the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require additional funding.

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 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

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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, and funding is otherwise inadequate, or if the formula 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.

If any Entergy Wholesale Commodities subsidiary decides to shut down one of its nuclear power plants earlier than the scheduled shutdown date and conduct decommissioning without the benefit of a safe storage period, the applicable Entergy subsidiary may be unable to rely upon only the decommissioning trust to fund the entire decommissioning obligations, which would require it to obtain funding from other sources.

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.  The Post Shutdown Decommissioning Activities Report for Vermont Yankee, including a site specific cost estimate, was submitted to the NRC 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.  Entergy expects that amounts available in Vermont Yankee’s decommissioning trust fund, including expected earnings, together with the credit facilities entered into in January 2015 that are expected to be repaid with recoveries from DOE litigation related to spent fuel storage, will be sufficient to cover expected costs of decommissioning, spent fuel management costs, and site restoration.  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.

Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, or accelerate the timing for funding of, the obligations related to the decommissioning of Entergy Wholesale Commodities nuclear power plants.  As a result, under any of these circumstances, Entergy’s results of operations, liquidity, and financial condition could be materially affected.

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.  In particular, 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, 2014, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 86%, 74%, 39%, 17%, and 19% of its generation portfolio’s planned energy output for 2015, 2016, 2017, 2018, and 2019, respectively.

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.

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Market prices may fluctuate substantially, sometimes over relatively short periods of time, and at other times experience sustained increases or decreases.  Demand for electricity and its fuel stock can fluctuate dramatically, creating periods of substantial under- or over-supply.  During periods of over-supply, prices might be depressed.  Also, from time to time there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, credit requirements, bidding rules and other mechanisms to address volatility and other issues in these markets.

The 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 “Results of Operations - Realized Revenue per MWh for Entergy Wholesale Commodities Nuclear Plants” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries.  With operating licenses for Indian Point 2 and Indian Point 3 expiring in 2013 and 2015, respectively (see discussion above regarding the continued operation of Indian Point 2 and 3 past the license expiration dates), and as a consequence of any delays in obtaining extension of the operating licenses and any other approvals required for continued operation of the plants, Entergy Wholesale Commodities may enter into fewer unit-contingent forward sales contracts for output from such plants for periods beyond the license expiration.

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;

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•
changes in Federal and state energy and environmental laws and regulations and other initiatives, including but not limited to, the price impacts of proposed emission controls such as the Regional Greenhouse Gas Initiative (RGGI);
•
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 federal, state, and local laws and regulation.  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 impose, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in these markets.  These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of the Entergy Wholesale Commodities business’ generation facilities that sell energy and capacity into the wholesale power markets.  For further information regarding federal, state and local laws and regulation applicable to the Entergy Wholesale Commodities business, see the “Regulation of Entergy’s Business” section in Part I, Item 1.

The regulatory environment applicable to the electric power industry has undergone substantial changes over the past several years as a result of restructuring initiatives at both the state and federal levels.  These changes are ongoing and 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 and 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, as well as proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share.  Other

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proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models.  If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, the Entergy Wholesale Commodities business’ results of operations, financial condition, and liquidity could be materially affected.

The power plants owned by the Entergy Wholesale Commodities business are subject to impairment charges in certain circumstances, which could have a material effect on Entergy’s results of operations, financial condition or liquidity.

Entergy reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain.  Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from the operations of such assets.  Projected net cash flows depend on the 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 impairment if adverse market conditions arise and continue (such as expected long-term declines in market prices for electricity), if adverse regulatory events occur (including with respect to environmental regulation), if a unit ceases operation or if a unit’s operating license is not renewed.  Moreover, 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, or a decline in observable industry market multiples could all result in potential impairment charges for the affected assets.

As discussed in the “Entergy Wholesale Commodities - Property” section in Part I, Item 1, the original expiration dates of the operating licenses for Indian Point 2 and Indian Point 3 are 2013 and 2015, respectively (see discussion above regarding the continued operation of Indian Point 2 and 3 past the license expiration dates),and are currently the subject of license renewal processes at the NRC and the state in which the plants operate. 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. If Entergy concludes that any of its nuclear power plants is unlikely to operate through its current useful life, which conclusion would be based on a variety of factors, such a conclusion could result in an 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 - Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries.

General Business

(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, 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-

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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, such as future storms, 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, such as the volatility and disruption in global capital and credit markets in 2008 and 2009, 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 Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

A downgrade in Entergy Corporation’s or its subsidiaries’ credit ratings could negatively affect Entergy Corporation’s and its subsidiaries’ ability to access capital and/or could require Entergy Corporation or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.

There are a number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy Corporation and the Registrant Subsidiaries, including each Registrant’s regulatory framework, ability to recover costs and earn returns, diversification and financial strength and liquidity.  If one or more rating agencies downgrade Entergy Corporation’s, any of the Utility operating companies’, or System Energy’s ratings, particularly below investment grade, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases, and other agreements.

Most of Entergy Corporation’s and its subsidiaries’ 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, 2014, based on power prices at that time, Entergy had liquidity exposure of $159 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $5 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, 2014, Entergy would have been required to provide approximately $51 million of additional cash or letters of credit under some of the agreements. As of December 31, 2014, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $52 million for a $1 per MMBtu increase in gas prices in both the short- and long-term markets.


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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. In particular, as discussed in Note 2 to the financial statements, two of Entergy’s subsidiaries, Entergy Louisiana and Entergy Gulf States Louisiana, are undertaking a transaction that would result in the combination of those entities into a single public utility. In addition, as discussed in the “Capital Expenditure Plans and Other Uses of Capital - Union Power Station Purchase Agreement” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries, certain of Entergy’s subsidiaries have entered into an asset purchase agreement to acquire the Union Power Station, consisting of four natural gas-fired, combined-cycle gas turbine power blocks, each rated at 495 MW (summer rating), from Union Power Partners, L.P. Each of these transactions is subject to regulatory approval and other material conditions or contingencies. The failure to complete these transactions 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:

•
acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;
•
acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;
•
Entergy and/or its subsidiaries may assume liabilities that were not disclosed to them, that exceed their estimates, or for which their rights to indemnification from the seller are limited;
•
Entergy 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.

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 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 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.  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, 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 Gulf States Louisiana, 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 summer cooling electricity demand and revenues, and temperatures below moderate levels in the winter tend to increase winter heating electricity and gas demand and revenues.  As a corollary, moderate temperatures 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 the state of the national and regional economies, weather, customer bill sizes (large bills tend to induce conservation), trends in energy efficiency, and 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 impact on Entergy’s operating results.  Others, such as the increasing adoption of energy efficient appliances and building codes, are having a more permanent impact of reducing sales growth rates from historical norms. Newer technologies such as distributed generation have not yet had a substantive impact on Entergy’s electricity sales, but further advances have the potential to do so in the future.  Since the national economy emerged from the last recession in 2009, Entergy’s industrial sales in particular have benefited from steady economic growth and relatively low natural gas prices from an historical perspective.  Any substantial negative change in any of these factors has the potential to result in slower or declining sales growth 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, 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.  In 2012 and 2013, EPA proposed a CO2 emission standard for new sources; this standard is expected to be finalized in 2015. Additionally, EPA proposed a CO2 existing source performance standard regulation in 2014 for finalization in 2015.  As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative (RGGI) establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been developed in California.


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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.  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 currently are pending 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, 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 changes in precipitation, drought, 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.  Two 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.

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.  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

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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 has guaranteed or indemnified the performance of a portion of the obligations relating to hedging and risk management activities.  Reductions in Entergy’s or its subsidiaries’ credit quality or changes in the market prices of energy commodities could increase the cash or letter of credit collateral required to be posted in connection with hedging and risk management activities, which could materially affect Entergy’s or its subsidiaries’ liquidity and financial position.

The Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy Wholesale Commodities.

The hedging and risk management practices of the Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties that owe Entergy and its subsidiaries money, energy, or other commodities will not perform their obligations.  Currently, some hedging agreements contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to Entergy or its subsidiaries.  If the counterparties to these arrangements fail to perform, Entergy or its subsidiaries may enforce and recover the proceeds from the credit support provided and acquire alternative hedging arrangements, which credit support may not always be adequate to cover the related obligations.  In such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties.  In addition, the credit commitments of Entergy’s lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially affect the adequacy of its liquidity sources.

The Wall Street Transparency and Accountability Act of 2010 and rules and regulations promulgated under the act may adversely affect the ability of the Utility operating companies and the Entergy Wholesale Commodities business to utilize certain commodity derivatives for hedging and mitigating commercial risk.

The Wall Street Transparency and Accountability Act of 2010, which was enacted on July 21, 2010 as part of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Act), and the rules and regulations promulgated under the act impose governmental regulation on the over-the-counter derivative market, including the commodity

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swaps used by the Utility operating companies and the Entergy Wholesale Commodities business to hedge and mitigate commercial risk.  Under the Act, certain swaps are subject to mandatory clearing and exchange trading requirements.  Swap dealers and major market participants in the swap market are subject to capital, margin, registration, reporting, recordkeeping, and business conduct requirements with respect to their swap activities.  Entergy is not a swap dealer or a major swap participant, and does not expect to qualify as either in the future. Non-swap dealers and non-major swap participants, such as Entergy, are subject to reporting, recordkeeping, and business conduct requirements (i.e., anti-manipulation, anti-disruptive trading practices, and whistleblower provisions) with respect to their swap activities. Position limits may also apply to certain swaps activities. Position limit rules promulgated by the Commodity Futures Trading Commission were vacated by the US District Court for the District of Columbia. The Commodity Futures Trading Commission has subsequently proposed new position limit rules. If the Commodity Futures Trading Commission’s issues final position limit rules, those rules may apply to certain of Entergy’s swaps activities.

The Act required the applicable regulators, which in the case of commodity swaps will be the Commodity Futures Trading Commission, to engage in substantial rulemaking in order to implement the provisions of the Act and such rulemaking has been largely completed.  Both the Utility operating companies and the Entergy Wholesale Commodities business currently utilize commodity swaps to hedge and mitigate commodity price risk.  It is not known whether the Act and regulations promulgated under the Act will have an adverse effect upon the market for the commodity swaps used by the Utility operating companies and the Entergy Wholesale Commodities business.  However, to the extent that the Act and regulations promulgated under the Act have the effect of increasing the price of such commodity swaps or limiting or reducing the availability of such commodity swaps, whether through the imposition of additional capital, margin, or compliance costs upon market participants, the imposition of position limits, or otherwise, the financial performance of the Utility operating companies and/or the Entergy Wholesale Commodities business may be adversely affected.  To the extent that the Utility operating companies and the Entergy Wholesale Commodities business may be required to post margin in connection with existing or future commodity swaps in addition to any margin currently posted by such entities, such entities may need to secure additional sources of capital to meet such liquidity needs or cease utilizing such commodity swaps.

Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding.

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.  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.  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

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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 the necessary information technology systems and network infrastructure. 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.

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 prescriptive standards. Despite the implementation of multiple layers of security by Entergy and its subsidiaries, 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. If Entergy’s or its subsidiaries’ technology systems were compromised and unable to recover timely 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.

If any such attacks, failures or breaches were to occur, Entergy’s and the Utility operating companies’ business, financial condition, and results of operations could be materially and adversely affected. 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 nuclear power plants and other facilities, such as additional physical facility security and additional 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 judgments and fines.

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, refer to Note 3 to the financial statements.

(Entergy Gulf States Louisiana and Entergy New Orleans)

The effect of higher purchased gas cost charges to customers may adversely affect Entergy Gulf States Louisiana’s and 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 Gulf States Louisiana or Entergy New Orleans, and distribution charges, which provide

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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 Gulf States Louisiana or Entergy New Orleans recovers from its customers.  Entergy Gulf States Louisiana’s or 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 Gulf States Louisiana or Entergy New Orleans, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy Gulf States Louisiana or Entergy New Orleans, which could adversely affect results of operations.

(System Energy)

System Energy owns and 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 is currently due to expire on November 1, 2024.  System Energy filed in October 2011 an application with the NRC for an extension of Grand Gulf’s operating license to 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 Agreement), see the “Grand Gulf-Related Agreements” section of Note 8 to the financial statements and the “Sale and Leaseback Transactions” section of Note 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 organizational documents, indentures for debt issuances, and other agreements 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 the “Retained Earnings and Dividend Restrictions” section of 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

2014 Compared to 2013

Net income decreased by $40.6 million primarily due to higher other operation and maintenance expenses, lower other income, higher depreciation and amortization expenses, and a higher effective income tax rate, partially offset by higher net revenue.

2013 Compared to 2012

Net income increased $9.6 million primarily due to higher net revenue, higher other income, lower nuclear refueling outage expenses, and a lower effective income tax rate, partially offset by higher other operation and maintenance expenses, higher interest expense, and higher depreciation and amortization expenses.

Net Revenue

2014 Compared to 2013

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 2014 to 2013.
 
Amount
 
(In Millions)
 
 
2013 net revenue

$1,301.5

Retail electric price
43.3

Reserve equalization
16.5

Transmission revenue
13.7

Asset retirement obligation
12.7

MISO deferral
(11.1
)
Volume/weather
(13.0
)
Net wholesale revenue
(20.5
)
Other
(7.2
)
2014 net revenue

$1,335.9


The retail electric price variance is primarily due to an increase in the energy efficiency rider, as approved by the APSC, effective July 2013 and July 2014, and the effect of the APSC’s order in the 2013 rate case, including an annual base rate increase effective January 2014, offset by a MISO rider to provide customers credits in rates for transmission revenue received through MISO. Energy efficiency revenues are largely offset by costs included in other operation and maintenance expenses and have minimal effect on net income. See Note 2 to the financial statements for further discussion of the rate case.

The reserve equalization variance is primarily due to the absence of reserve equalization expenses as compared to 2013 resulting from Entergy Arkansas’s exit from the System Agreement.

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The transmission revenue variance is primarily due to changes as a result of participation in the MISO RTO in 2014.

The asset retirement obligation affects net revenue because Entergy Arkansas records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation related costs collected in revenue. The variance is primarily caused by an increase in regulatory credits because of a decrease in decommissioning trust earnings.
    
The MISO deferral variance is due to the deferral in April 2013, as approved by the APSC, of costs incurred
from March 2010 through December 2012 related to the transition and implementation of joining the MISO RTO.

The volume/weather variance is primarily due to a decrease in sales volume during the unbilled sales period, partially offset by an increase of 190 GWh, or 1%, in billed electricity usage primarily in the residential sector.
        
The net wholesale revenue variance is primarily due to lower margins on co-owner contracts due to contract changes.

2013 Compared to 2012

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 2013 to 2012.
 
Amount
 
(In Millions)
 
 
2012 net revenue

$1,253.0

Retail electric price
46.4

MISO deferral
11.1

Net wholesale revenue
6.5

Volume/weather
(10.7
)
Asset retirement obligation
(10.4
)
Other
5.6

2013 net revenue

$1,301.5


The retail electric price variance is primarily due to:

•
an increase in the capacity acquisition rider, as approved by the APSC, effective with the first billing cycle of December 2012, relating to the Hot Spring plant acquisition. The net income effect of the Hot Spring plant cost recovery is limited to a portion representing an allowed return on equity on the net plant investment with the remainder offset by the Hot Spring plant costs in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes; and
•
increases in the energy efficiency rider, as approved by the APSC, effective July 2014 and July 2013. Energy efficiency revenues are largely offset by costs included in other operation and maintenance expenses and have minimal effect on net income.
    
The MISO deferral variance is due to the deferral in April 2013, as approved by the APSC, of costs incurred
from March 2010 through December 2012 related to the transition and implementation of joining the MISO RTO.

The net wholesale revenue variance is primarily due to higher margins on co-owner contracts.


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The volume/weather variance is due to lower weather-adjusted usage across all sectors, partially offset by the effect of more favorable weather on residential sales. The decrease in the industry usage was primarily driven by the pulp and paper industry, the chemicals industry, and the food products industry.

The asset retirement obligation affects net revenue because Entergy Arkansas records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust 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 earnings.

Other Income Statement Variances

2014 Compared to 2013

Other operation and maintenance expenses increased primarily due to:

•
a net increase of $26.4 million in energy efficiency costs, including a $4.3 million true-up to the 2013 energy efficiency filing for fixed costs collected from customers. These costs are recovered through the energy efficiency rider and have a minimal effect on net income;
•
an increase of $21.2 million in nuclear generation expenses primarily due to higher material costs, higher nuclear labor costs, including contract labor, and higher NRC fees;
•
an increase of $13.9 million due to an increase in storm damage accruals effective January 2014, as approved by the APSC;
•
an increase of $7.5 million in administration fees in 2014 related to participation in the MISO RTO;
•
an increase of $7.2 million due to the amortization in 2014 of human capital management costs that were deferred in 2013, as approved by the APSC. See Note 2 to the financial statements for further discussion of the deferral of these costs;
•
an increase of $5.2 million due to the amortization in 2014 of costs deferred in 2013 related to the transition and implementation of joining the MISO RTO, as discussed above; and
•
the effects of recording the final court decision in 2013 in the Entergy Arkansas lawsuit against the U.S. Department of Energy related to spent nuclear fuel disposal. The damages awarded include the reimbursement of approximately $3.2 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense.

The increase was partially offset by:

•
a decrease of $20.8 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
•
a decrease of $9 million resulting from costs incurred in 2013 related to the generator stator incident at ANO, including an offset for insurance proceeds. See “ANO Damage, Outage, and NRC Reviews” below for further discussion of the incident; and
•
a decrease of $8.6 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business.

Depreciation and amortization expenses increased primarily due to additions to plant in service, higher depreciation rates in 2014, as approved by the APSC, and the effects of recording the final court decision in 2013 in the Entergy Arkansas lawsuit against the U.S. Department of Energy related to spent nuclear fuel disposal. The damages awarded include the reimbursement of approximately $3.6 million of spent nuclear fuel storage costs previously recorded as depreciation expense.


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Other income decreased primarily due to lower earnings in 2014 on decommissioning trust fund investments. There is no effect on net income as the trust fund earnings are offset by a corresponding amount of regulatory charges.

2013 Compared to 2012

Nuclear refueling outage expenses decreased primarily due to lower costs associated with the most recent outage as compared to the previous outages.

Other operation and maintenance expenses increased primarily due to:

•
an increase of $24.3 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative, partially offset by the deferral, as approved by the APSC, of $21.8 million of these costs. See “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion;
•
an increase of $16.2 million in fossil-fueled generation expenses primarily due to the addition of the Hot Spring plant in November 2012;
•
an increase of $16.1 million in energy efficiency costs. These costs are recovered through the energy efficiency rider and have minimal effect on net income;
•
an increase of $10.8 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge, recognized in September 2013, related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs; and
•
an increase of $9 million resulting from costs related to the generator stator incident at ANO, including an offset for expected insurance proceeds. See “ANO Damage, Outage, and NRC Reviews” below for further discussion of the incident.

The increase was partially offset by:

•
a decrease of $4.6 million due to costs incurred in 2012 related to the transition and implementation of joining the MISO RTO. In April 2013, Entergy Arkansas began deferring these costs as approved by the APSC; and
•
the effects of recording the final court decision in 2013 in the Entergy Arkansas lawsuit against the U.S. Department of Energy related to spent nuclear fuel disposal. The damages awarded include the reimbursement of approximately $3.2 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense.

Also, other operation and maintenance expenses include $8.6 million in 2013 and $13.3 million in 2012 of costs incurred related to the now terminated plan to spin off and merge the transmission business.

Depreciation and amortization expenses increased primarily due to the acquisition of the Hot Spring plant in November 2012, partially offset by the effects of recording the final court decision in 2013 in the Entergy Arkansas lawsuit against the U.S. Department of Energy related to spent nuclear fuel disposal. The damages awarded include the reimbursement of approximately $3.6 million of spent nuclear fuel storage costs previously recorded as depreciation expense.

Other income increased primarily due to higher realized gains in 2013 on the ANO 1 and ANO 2 decommissioning trust fund investments. There is no effect on net income as these investment gains are offset by a corresponding amount of regulatory charges.


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Interest expense increased primarily due to:

•
the issuance of $200 million of 4.90% Series first mortgage bonds in December 2012;
•
the issuance of $250 million of 3.05% Series first mortgage bonds bonds in May 2013; and
•
the issuance of $125 million of 4.75% Series first mortgage bonds in June 2013.

This increase was offset by the retirement, at maturity, of $300 million of 5.40% Series first mortgage bonds in August 2013.

Income Taxes

The effective income tax rates for 2014, 2013, and 2012 were 40.8%, 36.2% and 38.4%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.

ANO Damage, Outage, and NRC Reviews

On March 31, 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 turbine building serves both ANO 1 and 2 and is a non-radiological area of the plant. ANO 2 reconnected to the grid on April 28, 2013 and ANO 1 reconnected to the grid on August 7, 2013.  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.  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.

Entergy Arkansas is pursuing its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. Entergy is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the members’ nuclear generating plants, including ANO. NEIL has notified Entergy that it believes that a $50 million course of construction sublimit applies to any loss associated with the lifting apparatus failure and stator drop at ANO. Entergy has responded that it disagrees with NEIL’s position and is evaluating its options for enforcing its rights under the policy. During 2014, Entergy Arkansas collected $50 million from NEIL and is pursuing additional recoveries due under the policy. On July 12, 2013, Entergy Arkansas filed a complaint in the Circuit Court in Pope County, Arkansas against the owner of the heavy-lifting apparatus that collapsed, an engineering firm, a contractor, and certain individuals asserting claims of breach of contract, negligence, and gross negligence in connection with their responsibility for the stator drop.

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.


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In May 2014 the NRC met with Entergy during a regulatory conference to discuss the preliminary red and yellow findings and Entergy’s response to the findings. During the regulatory conference, Entergy presented information on the facts and assumptions the NRC used to assess the potential findings. The NRC used the information provided by Entergy at the regulatory conference to finalize its decision regarding the inspection team’s findings. In a letter dated June 23, 2014, the NRC classified both findings as “yellow with substantial safety significance.” In an assessment follow-up letter for ANO dated July 29, 2014, the NRC stated that given the two yellow findings, it determined that the performance at ANO is in the “degraded cornerstone column,” or column 3, of the NRC’s reactor oversight process action matrix beginning the first quarter 2014. Corrective actions in response to the NRC’s findings have been taken and remain ongoing at ANO. The NRC plans to conduct supplemental inspection activity to review the actions taken to address the yellow findings. Entergy will continue to interact with the NRC to address the NRC’s findings.    

In September 2014 the NRC issued an inspection report on the flood barrier effectiveness issue that was still under review at the time of the March 2014 inspection report. While Entergy believes that the flood barrier issues that led to the finding have been addressed at ANO, NRC processes still required that the NRC assess the safety significance of the deficiencies. In its September 2014 inspection report, the NRC discussed a preliminary finding of “yellow with substantial safety significance” for the Unit 1 and Unit 2 auxiliary and emergency diesel fuel storage buildings.  The NRC indicated that these preliminary findings may warrant additional regulatory oversight.  Entergy requested a public regulatory conference regarding the inspection, and the conference was held on October 28, 2014. During the regulatory conference, Entergy presented information related to the facts and assumptions used by the NRC in arriving at its preliminary finding of “yellow with substantial safety significance.” In January 2015 the NRC issued its final risk significance determination for the flood barrier violation originally cited in the September 2014 report. The NRC’s final risk significance determination was classified as “yellow with substantial safety significance.”

The NRC’s January 2015 letter did not advise ANO of the additional level of oversight that will result from the yellow finding related to the flood barrier issue, and it stated that the NRC would inform ANO of this decision by separate correspondence. The yellow finding may result in ANO being placed into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. Placement into this column would require significant additional NRC inspection activities at the ANO site, including a review of the site’s root cause evaluation associated with the flood barrier 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. The additional NRC inspection activities at the site are expected to increase ANO’s operating costs.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2014, 2013, and 2012 were as follows:
 
2014
 
2013
 
2012
 
 
(In Thousands)
Cash and cash equivalents at beginning of period

$127,022

 

$34,533

 

$22,599

 
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 

 
 

 
Operating activities
403,826

 
401,250

 
509,117

 
Investing activities
(600,628
)
 
(524,473
)
 
(723,248
)
 
Financing activities
288,285

 
215,712

 
226,065

 
Net increase in cash and cash equivalents
91,483

 
92,489

 
11,934

 
 
 
 
 
 
 
 
Cash and cash equivalents at end of period

$218,505

 

$127,022

 

$34,533

 

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Operating Activities

Net cash flow provided by operating activities increased $2.6 million in 2014 primarily due to:

•
income tax refunds of $48.9 million in 2014 compared to income tax payments of $184.6 million in 2013. Entergy Arkansas received income tax refunds in 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax refunds in 2014 resulted primarily from the utilization of Entergy Arkansas’s net operating losses by the consolidated group whereas the income tax payments in 2013 resulted primarily from the reversal of temporary differences for which Entergy Arkansas had previously claimed a tax deduction;
•
approximately $25 million in spending in 2013 related to the generator stator incident at ANO, as discussed
above; and
•
$13.4 million in insurance proceeds received in 2014 for property damages related to the generator stator
incident at ANO, as discussed above.

The increase was partially offset by:

•
a decrease in the recovery of fuel and purchased power costs including a $68 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 and a $33.7 million System Agreement bandwidth remedy payment made in September 2014 as a result of the compliance filing pursuant to the FERC’s orders related to the bandwidth payments/receipts for the comprehensive recalculation for 2007, 2008, and 2009. See Note 2 to the financial statements for a discussion of the System Agreement bandwidth remedy payments;
•
an increase of $60.1 million in pension contributions in 2014. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding;
•
proceeds of $38 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel;
•
the timing of payments to vendors; and
•
an increase of $24.6 million in storm spending in 2014.

Net cash flow provided by operating activities decreased $107.9 million in 2013 primarily due to:

•
income tax payments of $184.6 million in 2013 compared to income tax refunds of $20.5 million in 2012. Entergy Arkansas had income tax payments in 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax payments in 2013 resulted primarily from the reversal of temporary differences for which Entergy Arkansas had previously claimed a tax deduction;
•
approximately $25 million in spending related to the generator stator incident at ANO, as discussed above;
•
$22.6 million in storm restoration spending in 2013 resulting from the December 2012 winter storm which caused significant damage to Entergy Arkansas’s distribution lines, equipment, poles and other facilities; and
•
a decrease in the recovery of fuel and purchased power costs.

The decrease was partially offset by:

•
proceeds of $38 million associated with the payments received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel; and
•
the $30.6 million June 2012 refund to AmerenUE, including interest, in rough production cost equalization payments previously collected from Ameren UE .


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Investing Activities

Net cash used in investing activities increased $76.2 million in 2014 primarily due to:

•
an increase of $101.4 million storm spending in 2014;
•
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
•
proceeds of $10.3 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel.

The decrease was partially offset by:

•
approximately $69 million in spending in 2013 related to the generator stator incident at ANO, as discussed above;
•
$36.6 million in insurance proceeds received in 2014 for property damages related to the generator stator incident at ANO, as discussed above; and
•
money pool activity.

Decreases in Entergy Arkansas’s receivable from the money pool are a source of cash flow, and Entergy Arkansas’s receivable from the money pool decreased by $15.3 million in 2014 as compared to increasing by $9.5 million in 2013. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.

Net cash used in investing activities decreased $198.8 million in 2013 primarily due to the purchase of the Hot Spring Energy Facility for approximately $253 million in November 2012 and 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. See Note 15 to the financial statements for a discussion of the purchase of the Hot Spring Energy Facility.

The decrease was partially offset by:

•
approximately $69 million in spending related to the generator stator incident at ANO, as discussed above;
•
$39.6 million in storm restoration spending in 2013 resulting from the December 2012 winter storm;
•
$7.6 million in storm restoration spending in 2013 resulting from the December 2013 winter storm; and
•
money pool activity.  

Increases in Entergy Arkansas’s receivable from the money pool are a use of cash flow, and Entergy Arkansas’s receivable from the money pool increased by $9.5 million in 2013 as compared to decreasing by $9.3 million in 2012.

Financing Activities

Net cash provided by financing activities increased $72.6 million in 2014 primarily due to:

•
the issuance of $375 million of 3.70% Series first mortgage bonds in March 2014;
•
the retirement, at maturity, of $300 million of 5.40% Series first mortgage bonds in August 2013;
•
the issuance of $90 million of 9% Series L notes by the nuclear fuel company variable interest entity in July 2014;
•
the issuance of $250 million of 4.95% Series first mortgage bonds in December 2014;
•
net borrowings of $48 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2014 compared to net repayments of $36.7 million in 2013;

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•
the retirement, at maturity, of $30 million of 9% Series H notes by the nuclear fuel company variable interest entity in June 2013; and
•
a decrease of $5 million in common stock dividends paid in 2014.

The increase was partially offset by:

•
borrowings on a $250 million term loan credit facility entered into in July 2013 and its repayment, prior to maturity, in March 2014;
•
the issuance of $250 million of 3.05% Series first mortgage bonds in May 2013;
•
the issuance of $125 million of 4.75% Series first mortgage bonds in June 2013;
•
the retirement, prior to maturity, of $115 million of 5.0% Series first mortgage bonds in April 2014; and
•
the retirement, at maturity, of $70 million of 5.69% Series I notes by the nuclear fuel company variable interest entity in July 2014.

Net cash provided by financing activities decreased $10.4 million in 2013 primarily due to:

•
the retirement, at maturity, of $30 million of 9% Series H notes by the nuclear fuel company variable interest entity in June 2013;
•
the retirement, at maturity, of $300 million of 5.40% Series first mortgage bonds in August 2013;
•
the issuance of $200 million of 4.9% Series first mortgage bonds in December 2012;
•
the issuance of $60 million of 2.62% Series K notes by the nuclear fuel company variable interest entity in December 2012; and
•
the net repayment of $36.7 million of borrowings on the nuclear fuel company variable interest entity credit facility in 2013 compared to net borrowings of $2.8 million in 2012.

The decrease was partially offset by:

•
the issuance of $250 million of 3.05% Series first mortgage bonds in May 2013 and $125 million of 4.75% Series first mortgage bonds in June 2013; and
•
borrowings on a $250 million term loan credit facility entered into in July 2013.

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

Capital Structure

Entergy Arkansas’s capitalization is balanced between equity and debt, as shown in the following table. The
increase in the debt to capital ratio for Entergy Arkansas is primarily due to an increase in long-term debt as a result of the issuance of $375 million of 3.70% Series first mortgage bonds in March 2014.
 
December 31,
2014
 
December 31,
2013
Debt to capital
58.4%
 
56.7%
Effect of excluding the securitization bonds
(0.7%)
 
(0.9%)
Debt to capital, excluding securitization bonds (a)
57.7%
 
55.8%
Effect of subtracting cash
(2.2%)
 
(1.4%)
Net debt to net capital, excluding securitization bonds (a)
55.5%
 
54.4%

(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

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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.

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.

Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
 
2015
 
2016
 
2017
 
(In Millions)
Planned construction and capital investment:
 
 
 

 
 

Generation

$405

 

$155

 

$235

Transmission
255

 
130

 
80

Distribution
195

 
180

 
165

Other
35

 
20

 
20

Total

$890

 

$485

 

$500


Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2015
 
2016-2017
 
2018-2019
 
after 2020
 
Total
 
(In Millions)
Long-term debt (a)

$105

 

$378

 

$203

 

$3,963

 

$4,649

Operating leases

$28

 

$40

 

$22

 

$9

 

$99

Purchase obligations (b)

$760

 

$986

 

$761

 

$1,694

 

$4,201


(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 $92.5 million to its pension plans and approximately $16.9 million to other postretirement plans in 2015, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015.  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 $1.9 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably

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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 the Union Power Station acquisition discussed below; NRC post-Fukushima requirements; environmental compliance spending, including potential scrubbers at White Bluff to meet pending Arkansas state requirements under the Clean Air Visibility Rule; transmission projects to enhance reliability, reduce congestion, and enable economic growth; resource planning; 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, requirements, and oversight, 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 Arkansas pays dividends to Entergy Corporation from its earnings at a percentage determined monthly.  Entergy Arkansas’s long-term debt indenture restricts the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock.  As of December 31, 2014, Entergy Arkansas had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million.

Union Power Station Purchase Agreement
    
In December 2014, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas entered into an asset purchase agreement to acquire 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). Pursuant to the agreement, Entergy Gulf States Louisiana will acquire two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy Texas will each acquire one power block and a 25% undivided ownership interest in such related assets. (If Entergy Arkansas or Entergy Texas do not obtain approval for the purchase of their power blocks, Entergy Gulf States Louisiana will seek to purchase the power blocks not approved.) The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments.  In addition, Entergy Gulf States Louisiana anticipates selling 20% of the capacity and energy associated with its two power blocks to Entergy New Orleans through a cost-based, life-of-unit power purchase agreement. The purchase is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federal and state regulatory and permitting agencies. These include regulatory approvals from the APSC, LPSC, PUCT, and FERC, as well as clearance under the Hart-Scott-Rodino anti-trust law. In December 2014, Entergy Texas filed its application with the PUCT for approval of the acquisition. The PUCT has indicated that it will convene the hearing on the merits of this case in June 2015. Entergy Texas intends to file a rate application to seek cost recovery later in 2015. In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC and Entergy Arkansas filed its application with the APSC, each for approval of the acquisition and cost recovery. Closing is targeted to occur in late-2015.

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.


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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.

Entergy Arkansas’s receivables from the money pool were as follows as of December 31 for each of the following years.
2014
 
2013
 
2012
 
2011
(In Thousands)
$2,218
 
$17,531
 
$8,035
 
$17,362

See Note 4 to the financial statements for a description of the money pool.

Entergy Arkansas has credit facilities in the amount of $20 million and $150 million scheduled to expire in April 2015 and March 2019, respectively.  The $150 million credit facility allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2014, there were no cash borrowings and no letters of credit outstanding under the credit facilities.  In addition, Entergy Arkansas entered into an uncommitted letter of credit facility in 2014 as a means to post collateral to support its obligations under MISO. As of December 31, 2014, a $2 million letter of credit was outstanding under Entergy Arkansas’s letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $85 million scheduled to expire in June 2016.  As of December 31, 2014, $48 million was outstanding on the credit facility.  See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facility.

Entergy Arkansas obtained authorizations from the FERC through October 2015 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and long-term 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 Tennessee Regulatory Authority; the current authorizations extend through December 2015.

In March 2014, Entergy Arkansas issued $375 million of 3.70% Series first mortgage bonds due June 2024. Entergy Arkansas used the proceeds to pay, prior to maturity, its $250 million term loan, to pay, prior to maturity, its $115 million of 5.0% Series first mortgage bonds due July 2018, and for general corporate purposes.

In July 2014 the Entergy Arkansas nuclear fuel trust variable interest entity issued $90 million of 3.65% Series L notes due July 2021. The Entergy Arkansas nuclear fuel trust variable interest entity used the proceeds to pay, at maturity, its $70 million of 5.69% Series I notes due July 2014 and to purchase additional nuclear fuel.

In December 2014, Entergy Arkansas issued $250 million of 4.95% Series first mortgage bonds due December 2044. Entergy Arkansas used the proceeds for general corporate purposes.



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State and Local Rate Regulation and Fuel-Cost Recovery

Retail Rates

2013 Base Rate Filing

In March 2013, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing assumed Entergy Arkansas’s transition to MISO in December 2013, and requested a rate increase of $174 million, including $49 million of revenue being transferred from collection in riders to base rates. The filing also proposed a new transmission rider and a capacity cost recovery rider. The filing requested a 10.4% return on common equity. In September 2013, Entergy Arkansas filed testimony reflecting an updated rate increase request of $145 million, with no change to its requested return on common equity of 10.4%. Hearings in the proceeding began in October 2013, and in December 2013 the APSC issued an order. The order authorized a base rate increase of $81 million and included an authorized return on common equity of 9.3%. The order allows Entergy Arkansas to amortize its human capital management costs over a three-and-a-half year period, but also orders Entergy Arkansas to file a detailed report of the Arkansas-specific costs, savings and final payroll changes upon conclusion of the human capital management strategic imperative. The detailed report was subsequently filed in February 2015. The substance of the report will be addressed in Entergy Arkansas’s next base rate filing. New rates were implemented in the first billing cycle of March 2014, effective as of January 2014. Additionally, in January 2014, Entergy Arkansas filed a petition for rehearing or clarification of several aspects of the APSC’s order, including the 9.3% authorized return on common equity. In February 2014 the APSC granted Entergy Arkansas’s petition for the purpose of considering the additional evidence identified by Entergy Arkansas. In August 2014 the APSC issued an order amending certain aspects of the original order, including providing for a 9.5% authorized return on common equity. Pursuant to the August 2014 order, revised rates are effective for all bills rendered after December 31, 2013 and were implemented in the first billing cycle of October 2014.

On January 30, 2015, Entergy Arkansas filed with the APSC a notice of intent to file a rate case within 60 to 90 days.

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.  These costs cause an increase in Entergy Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects them from customers over twelve months. See Note 2 to the financial statements and Entergy Corporation and Subsidiaries “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - System Agreement” for discussions of the System Agreement proceedings.

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 June 2014 the APSC suspended the annual redetermination of the production cost allocation rider and scheduled a hearing in September 2014. Upon a joint motion of the parties, the APSC canceled the September 2014 hearing and 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 the first billing cycle of February 2015.


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Energy Cost Recovery Rider

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

In October 2005 the APSC initiated an investigation into Entergy Arkansas’s interim energy cost recovery rate.  The investigation focused on Entergy Arkansas’s 1) gas contracting, portfolio, and hedging practices; 2) wholesale purchases during the period; 3) management of the coal inventory at its coal generation plants; and 4) response to the contractual failure of the railroads to provide coal deliveries.  In March 2006 the APSC extended its investigation to cover the costs included in Entergy Arkansas’s March 2006 annual energy cost rate filing, and a hearing was held in the APSC investigation in October 2006.

In January 2007 the APSC issued an order in its review of the energy cost rate.  The APSC found that Entergy Arkansas failed to maintain an adequate coal inventory level going into the summer of 2005 and that Entergy Arkansas should be responsible for any incremental energy costs that resulted from two outages caused by employee and contractor error.  The coal plant generation curtailments were caused by railroad delivery problems and Entergy Arkansas has since resolved litigation with the railroad regarding the delivery problems.  The APSC staff was directed to perform an analysis with Entergy Arkansas’s assistance to determine the additional fuel and purchased energy costs associated with these findings and file the analysis within sixty days of the order.  After a final determination of the costs is made by the APSC, Entergy Arkansas will be directed to refund that amount with interest to its customers as a credit on the energy cost recovery rider.  Entergy Arkansas requested rehearing of the order.  

In February 2010 the APSC denied Entergy Arkansas’s request for rehearing, and held a hearing in September 2010 to determine the amount of damages, if any, that should be assessed against Entergy Arkansas.  A decision is pending.  Entergy Arkansas expects the amount of damages, if any, to have an immaterial effect on its results of operations, financial position, or cash flows.

The APSC also established a separate docket to consider the resolved railroad litigation, and in February 2010 it established a procedural schedule that concluded with testimony through September 2010.  The testimony has been filed, and the APSC will decide the case based on the record in the proceeding.

In January 2014, Entergy Arkansas filed a motion with the APSC relating to its redetermination of its energy cost rate to be 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. See the “ANO Damage, Outage, and NRC Reviews” section above for further discussion of the ANO stator incident.

Storm Cost Recovery

Entergy Arkansas December 2012 Winter Storm

In December 2012 a severe winter storm consisting of ice, snow, and high winds caused significant damage to Entergy Arkansas’s distribution lines, equipment, poles, and other facilities.  Total restoration costs for the repair and/or replacement of Entergy Arkansas’s electrical facilities in areas damaged from the winter storm were $63 million,

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including costs recorded as regulatory assets of approximately $22 million.  In the Entergy Arkansas 2013 rate case, the APSC approved inclusion of the construction spending in rate base and approved an increase in the normal storm cost accrual, which will effectively amortize the regulatory asset over a five-year period.

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 allocate 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 prohibits 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 challenges 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 response further explained that the FERC already had determined that Entergy Arkansas’s short-term wholesale sales did not trigger the “right-of-first-refusal” provision of the System Agreement.  While the D.C. Circuit recently determined that the “right-of-first-refusal” issue was not properly before the FERC at the time of its earlier decision on the issue, the LPSC raised no additional claims or facts that would warrant the FERC reaching a different conclusion.

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 will require 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, which are pending with the FERC.

As required by the procedural schedule established in the calculation proceeding, Entergy filed its direct testimony that included a proposed illustrative re-run, consistent with the directives in FERC’s order, of intra-system bills for 2003, 2004, and 2006, the three years with the highest volume of opportunity sales.  Entergy’s proposed illustrative re-run of intra-system bills shows that the potential cost for Entergy Arkansas would be up to $12 million

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for the years 2003, 2004, and 2006, excluding interest, and the potential benefit would be significantly less than that for each of the other Utility operating companies.  Entergy’s proposed illustrative re-run of the intra-system bills also shows an offsetting potential benefit to Entergy Arkansas for the years 2003, 2004, and 2006 resulting from the effects of the FERC’s order on System Agreement Service Schedules MSS-1, MSS-2, and MSS-3, and the potential offsetting cost would be significantly less than that for each of the other Utility operating companies.  Entergy provided to the LPSC an illustrative intra-system bill recalculation as specified by the LPSC for the years 2003, 2004, and 2006, and the LPSC then filed answering testimony in December 2012.  In its testimony the LPSC claims that the damages, excluding interest, that should be paid by Entergy Arkansas to the other Utility operating company’s customers for 2003, 2004, and 2006 are $42 million to Entergy Gulf States, Inc., $7 million to Entergy Louisiana, $23 million to Entergy Mississippi, and $4 million to Entergy New Orleans. The FERC staff and certain intervenors filed direct and answering testimony in February 2013. In April 2013, Entergy filed its rebuttal testimony in that proceeding, including a revised illustrative re-run of the intra-system bills for the years 2003, 2004, and 2006. The revised calculation determines the re-pricing of the opportunity sales based on consideration of moveable resources only and the removal of exchange energy received by Entergy Arkansas, which increases the potential cost for Entergy Arkansas over the three years 2003, 2004, and 2006 by $2.3 million from the potential costs identified in the Utility operating companies’ prior filings in September and October 2012. A hearing was held in May 2013 to quantify the effect of repricing the opportunity sales in accordance with the FERC’s decision.

In August 2013 the presiding judge issued an initial decision in the calculation proceeding. The initial decision concludes 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 concludes 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 does recognize that the LPSC’s methodology would result in an inequitable windfall to the other Utility operating companies and, therefore, concludes that any payments by Entergy Arkansas should be reduced by 20%. The Utility operating companies are currently analyzing the effects of the initial decision. 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 FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff. The FERC’s review of the initial decision is pending. 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.

Federal Regulation

See “Entergy’s Integration Into the MISO Regional Transmission Organization,” “System Agreement,” and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of these topics.

Nuclear Matters

Entergy Arkansas owns and operates, through an affiliate, 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 from the use, storage, handling and disposal of high-level and low-level radioactive materials, regulatory requirement changes, including changes resulting from events at other plants, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts.  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.


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The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system.  The issue is applicable to ANO 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.

After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States.  The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders.  The task force then issued a second report in September 2011.  Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012.  The three orders require U.S. nuclear operators to undertake plant modifications and perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating nuclear plants.  The NRC, with input from the industry, is continuing to determine the specific actions required by the orders. Entergy Arkansas’s estimated capital expenditures for 2015 through 2017 for complying with the NRC orders are included in the planned construction and other capital investments estimates given in “Liquidity and Capital Resources - Uses of Capital” above.

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.  Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

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

Nuclear Decommissioning Costs

See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.

In 2014, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and ANO 2 as a result of a revised decommissioning cost study.  The revised estimates resulted in a $47.6 million increase in the decommissioning cost liabilities, along with a corresponding increase in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.

Unbilled Revenue

As discussed in Note 1 to the financial statements, Entergy Arkansas 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

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unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized 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.

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.

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 2014
Qualified Pension Cost
 
Impact on 2014
Qualified Projected
Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$3,172
 
$51,882
Rate of return on plan assets
 
(0.25%)
 
$2,153
 
$—
Rate of increase in compensation
 
0.25%
 
$1,238
 
$7,401

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 2014
Postretirement Benefit Cost
 
Impact on 2014 Accumulated
Postretirement Benefit
Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$749
 
$10,813
Health care cost trend
 
0.25%
 
$1,276
 
$9,378

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 2014 was $42.4 million.  Entergy Arkansas anticipates 2015 qualified pension cost to be $62.7 million.  Entergy Arkansas contributed $95.5 million to its pension plan in 2014 and estimates 2015 pension contributions to be approximately $92.5 million, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015.

Total postretirement health care and life insurance benefit income for Entergy Arkansas in 2014 was $2.1 million.  Entergy Arkansas expects 2015 postretirement health care and life insurance benefit costs of approximately

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$3.2 million.  Entergy Arkansas contributed $15.3 million to its other postretirement plans in 2014 and expects to contribute approximately $16.9 million in 2015.

The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans.  The 2014 actuarial study reviewed plan experience from 2010 through 2013.  As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies.  These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of  $106.9 million in the qualified pension benefit obligation and $16 million in the accumulated postretirement obligation.  The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $15.4 million and other postretirement cost by approximately $2.2 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.

Federal Healthcare Legislation

See the “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.

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholders of
Entergy Arkansas, Inc. and Subsidiaries
Little Rock, Arkansas


We have audited the accompanying consolidated balance sheets of Entergy Arkansas, Inc. and Subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated income statements, consolidated statements of cash flows, and consolidated statements of changes in common equity (pages 316 through 320 and applicable items in page 61 through 234) for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Arkansas, Inc. and Subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana
February 26, 2015


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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS
 
 
 
 
 
For the Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$2,172,391

 

$2,190,159

 

$2,127,004

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
327,695

 
426,316

 
480,464

Purchased power
 
528,815

 
473,326

 
431,932

Nuclear refueling outage expenses
 
43,258

 
40,499

 
47,103

Other operation and maintenance
 
647,461

 
592,892

 
545,782

Decommissioning
 
46,972

 
43,058

 
40,484

Taxes other than income taxes
 
91,470

 
89,471

 
89,527

Depreciation and amortization
 
236,770

 
230,512

 
222,734

Other regulatory credits - net
 
(20,054
)
 
(10,975
)
 
(38,406
)
TOTAL
 
1,902,387

 
1,885,099

 
1,819,620

 
 
 
 
 
 
 
OPERATING INCOME
 
270,004

 
305,060

 
307,384

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
7,238

 
10,913

 
9,070

Interest and investment income
 
23,075

 
30,148

 
15,169

Miscellaneous - net
 
(5,144
)
 
(4,275
)
 
(4,049
)
TOTAL
 
25,169

 
36,786

 
20,190

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
93,921

 
91,318

 
82,860

Allowance for borrowed funds used during construction
 
(3,769
)
 
(3,207
)
 
(2,457
)
TOTAL
 
90,152

 
88,111

 
80,403

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
205,021

 
253,735

 
247,171

 
 
 
 
 
 
 
Income taxes
 
83,629

 
91,787

 
94,806

 
 
 
 
 
 
 
NET INCOME
 
121,392

 
161,948

 
152,365

 
 
 
 
 
 
 
Preferred dividend requirements
 
6,873

 
6,873

 
6,873

 
 
 
 
 
 
 
EARNINGS APPLICABLE TO COMMON STOCK
 

$114,519

 

$155,075

 

$145,492

 
 
 
 
 
 
 
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,
 

2014

2013

2012
 

(In Thousands)
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$121,392

 

$161,948

 

$152,365

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 
387,945

 
357,639

 
357,913

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
130,132

 
130,707

 
(67,482
)
Changes in assets and liabilities:
 
 

 
 

 
 

Receivables
 
25,661

 
(26,320
)
 
(30,786
)
Fuel inventory
 
(9,394
)
 
7,471

 
(68
)
Accounts payable
 
(120,097
)
 
141,041

 
(179,009
)
Prepaid taxes and taxes accrued
 
14,261

 
(204,990
)
 
178,688

Interest accrued
 
(1,786
)
 
(6,382
)
 
(1,463
)
Deferred fuel costs
 
(140,483
)
 
28,609

 
112,471

Other working capital accounts
 
72,411

 
(34,909
)
 
55,735

Provisions for estimated losses
 
(57
)
 
(76
)
 
182

Other regulatory assets
 
(367,234
)
 
214,131

 
(88,119
)
Pension and other postretirement liabilities
 
252,639

 
(295,435
)
 
75,725

Other assets and liabilities
 
38,436

 
(72,184
)
 
(57,035
)
Net cash flow provided by operating activities
 
403,826

 
401,250

 
509,117

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(535,464
)
 
(489,079
)
 
(361,858
)
Allowance for equity funds used during construction
 
10,789

 
14,550

 
12,441

Nuclear fuel purchases
 
(195,092
)
 
(88,637
)
 
(215,968
)
Proceeds from sale of nuclear fuel
 
75,860

 
36,478

 
96,700

Proceeds from nuclear decommissioning trust fund sales
 
181,489

 
266,391

 
144,275

Investment in nuclear decommissioning trust funds
 
(190,062
)
 
(274,519
)
 
(154,608
)
Payment for purchase of plant
 
—

 
—

 
(253,043
)
Change in money pool receivable - net
 
15,313

 
(9,496
)
 
9,327

Changes in securitization account
 
(261
)
 
568

 
(514
)
Litigation proceeds for reimbursement of spent nuclear fuel storage costs
 
—

 
10,271

 
—

Counterparty collateral deposit
 
—

 
9,000

 
—

Insurance proceeds
 
36,600

 
—

 
—

Other
 
200

 
—

 
—

Net cash flow used in investing activities
 
(600,628
)

(524,473
)

(723,248
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
707,465

 
716,595

 
252,347

Retirement of long-term debt
 
(447,815
)
 
(442,302
)
 
(12,230
)
Changes in short-term borrowings - net
 
47,968

 
(36,735
)
 
2,821

Dividends paid:
 
 

 
 

 
 

Common stock
 
(10,000
)
 
(15,000
)
 
(10,000
)
Preferred stock
 
(6,873
)
 
(6,873
)
 
(6,873
)
Other
 
(2,460
)
 
27

 
—

Net cash flow provided by financing activities
 
288,285

 
215,712

 
226,065

Net increase in cash and cash equivalents
 
91,483

 
92,489

 
11,934

Cash and cash equivalents at beginning of period
 
127,022

 
34,533

 
22,599

Cash and cash equivalents at end of period
 

$218,505

 

$127,022

 

$34,533

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 
 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$90,285

 

$92,353

 

$79,271

Income taxes
 

($48,948
)
 

$184,592

 

($20,480
)
See Notes to Financial Statements.

 


 


 


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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2014
 
2013
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$10,526

 

$4,181

Temporary cash investments
 
207,979

 
122,841

Total cash and cash equivalents
 
218,505

 
127,022

Securitization recovery trust account
 
4,096

 
3,835

Accounts receivable:
 
 

 
 

Customer
 
97,314

 
102,328

Allowance for doubtful accounts
 
(32,247
)
 
(30,113
)
Associated companies
 
32,187

 
68,875

Other
 
110,269

 
94,256

Accrued unbilled revenues
 
80,704

 
82,298

Total accounts receivable
 
288,227

 
317,644

Accumulated deferred income taxes
 
21,533

 
33,556

Deferred fuel costs
 
143,279

 
68,696

Fuel inventory - at average cost
 
50,898

 
41,504

Materials and supplies - at average cost
 
162,792

 
152,429

Deferred nuclear refueling outage costs
 
29,690

 
31,135

System agreement cost equalization
 
—

 
30,000

Prepayments and other
 
9,588

 
58,911

TOTAL
 
928,608

 
864,732

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Decommissioning trust funds
 
769,883

 
710,913

Other
 
14,170

 
30,845

TOTAL
 
784,053

 
741,758

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
9,139,181

 
8,798,458

Property under capital lease
 
961

 
1,064

Construction work in progress
 
284,322

 
209,036

Nuclear fuel
 
293,695

 
321,901

TOTAL UTILITY PLANT
 
9,718,159

 
9,330,459

Less - accumulated depreciation and amortization
 
4,191,959

 
4,034,880

UTILITY PLANT - NET
 
5,526,200

 
5,295,579

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Regulatory asset for income taxes - net
 
64,214

 
73,864

Other regulatory assets (includes securitization property of $67,877 as of December 31, 2014 and $80,963 as of December 31, 2013)
 
1,391,276

 
1,014,392

Deferred fuel costs
 
65,900

 
—

Other
 
47,674

 
44,565

TOTAL
 
1,569,064

 
1,132,821

 
 
 
 
 
TOTAL ASSETS
 

$8,807,925

 

$8,034,890

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2014
 
2013
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Currently maturing long-term debt
 

$—

 

$70,000

Short-term borrowings
 
47,968

 
—

Accounts payable:
 
 

 
 

Associated companies
 
56,078

 
149,802

Other
 
174,998

 
228,160

Customer deposits
 
115,647

 
86,512

Taxes accrued
 
24,240

 
9,979

Accumulated deferred income taxes
 
15,009

 
9,231

Interest accrued
 
20,250

 
22,036

Other
 
27,872

 
55,656

TOTAL
 
482,062

 
631,376

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
1,997,983

 
1,906,562

Accumulated deferred investment tax credits
 
37,708

 
38,958

Other regulatory liabilities
 
254,036

 
219,370

Decommissioning
 
818,351

 
723,771

Accumulated provisions
 
5,689

 
5,746

Pension and other postretirement liabilities
 
571,870

 
319,211

Long-term debt (includes securitization bonds of $76,164 as of December 31, 2014 and $88,961 as of December 31, 2013)
 
2,671,343

 
2,335,802

Other
 
28,296

 
18,026

TOTAL
 
6,385,276

 
5,567,446

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
Preferred stock without sinking fund
 
116,350

 
116,350

 
 
 
 
 
COMMON EQUITY
 
 

 
 

Common stock, $0.01 par value, authorized 325,000,000 shares; issued and outstanding 46,980,196 shares in 2014 and 2013
 
470

 
470

Paid-in capital
 
588,471

 
588,471

Retained earnings
 
1,235,296

 
1,130,777

TOTAL
 
1,824,237

 
1,719,718

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$8,807,925

 

$8,034,890

 
 
 
 
 
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, 2014, 2013, and 2012
 
 
 
 
 
 
 
Common Equity
 
 
 
 
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Total
 
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2011
 

$470

 

$588,444

 

$855,210

 

$1,444,124

Net income
 
—

 
—

 
152,365

 
152,365

Common stock dividends
 
—

 
—

 
(10,000
)
 
(10,000
)
Preferred stock dividends
 
—

 
—

 
(6,873
)
 
(6,873
)
Balance at December 31, 2012
 

$470

 

$588,444

 

$990,702

 

$1,579,616

Net income
 
—

 
—

 
161,948

 
161,948

Common stock dividends
 
—

 
—

 
(15,000
)
 
(15,000
)
Preferred stock dividends
 
—

 
—

 
(6,873
)
 
(6,873
)
Other
 
—

 
27

 
—

 
27

Balance at December 31, 2013
 

$470

 

$588,471

 

$1,130,777

 

$1,719,718

Net income
 
—

 
—

 
121,392

 
121,392

Common stock dividends
 
—

 
—

 
(10,000
)
 
(10,000
)
Preferred stock dividends
 
—

 
—

 
(6,873
)
 
(6,873
)
Balance at December 31, 2014
 

$470

 

$588,471

 

$1,235,296

 

$1,824,237

 
 
 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 

 
 



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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 

$2,172,391

 

$2,190,159

 

$2,127,004

 

$2,084,310

 

$2,082,447

Net Income
 

$121,392

 

$161,948

 

$152,365

 

$164,891

 

$172,618

Total assets
 

$8,807,925

 

$8,034,890

 

$7,819,445

 

$7,212,212

 

$6,751,368

Long-term obligations (a)
 

$2,787,693

 

$2,452,152

 

$1,910,245

 

$1,992,271

 

$1,946,494

 
 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund.
 
 
 
 
 
 
 
 
 
 
 
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
 
Electric Operating Revenues:
 
 

 
 

 
 

 
 

 
 

Residential
 

$755

 

$772

 

$766

 

$756

 

$773

Commercial
 
461

 
469

 
472

 
450

 
441

Industrial
 
424

 
433

 
439

 
421

 
415

Governmental
 
18

 
19

 
20

 
20

 
20

Total retail
 
1,658

 
1,693

 
1,697

 
1,647

 
1,649

 
 
 
 
 
 
 
 
 
 
 
Sales for resale:
 
 

 
 

 
 

 
 

 
 

Associated companies
 
131

 
346

 
320

 
279

 
302

Non-associated companies
 
282

 
83

 
49

 
96

 
78

Other
 
101

 
68

 
61

 
62

 
53

Total
 

$2,172

 

$2,190

 

$2,127

 

$2,084

 

$2,082

 
 
 
 
 
 
 
 
 
 
 
Billed Electric Energy Sales (GWh):
 
 
 
 

 
 

 
 

 
 

Residential
 
8,070

 
7,921

 
7,859

 
8,229

 
8,501

Commercial
 
5,934

 
5,929

 
6,046

 
6,051

 
6,144

Industrial
 
6,808

 
6,769

 
6,925

 
7,029

 
7,082

Governmental
 
238

 
241

 
257

 
275

 
277

Total retail
 
21,050

 
20,860

 
21,087

 
21,584

 
22,004

 
 
 
 
 
 
 
 
 
 
 
Sales for resale:
 
 

 
 

 
 

 
 

 
 

Associated companies
 
2,299

 
7,918

 
7,926

 
6,893

 
7,853

Non-associated companies
 
8,003

 
1,011

 
1,093

 
1,304

 
850

Total
 
31,352

 
29,789

 
30,106

 
29,781

 
30,707



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ENTERGY GULF STATES LOUISIANA, L.L.C.

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Entergy Louisiana and Entergy Gulf States Louisiana Business Combination

In June 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed a business combination study report with the LPSC. The report contained a preliminary analysis of the potential combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility, including an overview of the combination that identified its potential customer benefits. Although not part of the business combination, Entergy Louisiana provided notice to the City Council in June 2014 that it would seek authorization to transfer to Entergy New Orleans the assets that currently support the provision of service to Entergy Louisiana’s customers in Algiers. Entergy Louisiana subsequently filed the referenced application with the City Council in October 2014. In the summer of 2014, Entergy Louisiana and Entergy Gulf States Louisiana held technical conferences and face-to-face meetings with LPSC staff and other stakeholders to discuss potential effects of the combination, solicit suggestions and concerns, and identify areas in which additional information might be needed.

On September 30, 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed an application with the LPSC seeking authorization to undertake the transactions that would result in the combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility.

The combination is subject to regulatory review and approval of the LPSC, the FERC, and the NRC. In June 2014, Entergy submitted an application to the NRC for approval of River Bend and Waterford 3 license transfers as part of the steps to complete the business combination. The combination also could be subject to regulatory review of the City Council if Entergy Louisiana continues to own the assets that currently support Entergy Louisiana’s customers in Algiers at the time the combination is effectuated. In November 2014, Entergy Louisiana filed an application with the City Council seeking authorization to undertake the combination. The application provides that if the City Council approves the Algiers asset transfer before the business combination occurs, the City Council may not need to issue a public interest finding regarding the combination. In December 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed applications with the FERC requesting authorization for the business combination and the Algiers asset transfer. In January 2015, Entergy Services filed an application with the FERC for financing authority for the combined company. If approvals are obtained from the LPSC, the FERC, the NRC, and, if required, the City Council, Entergy Louisiana and Entergy Gulf States Louisiana expect the combination will be effected in the second half of 2015.

The procedural schedule in the LPSC business combination proceeding calls for LPSC Staff and intervenor testimony to be filed in March 2015, with a hearing scheduled for June 2015. Entergy Louisiana and Entergy Gulf States Louisiana have requested that the LPSC issue its decision regarding the business combination in August 2015. In the City Council business combination proceeding, the City Council announced through a resolution that it would not initiate an active review of the business combination filing, but instead would establish a business combination docket for the limited purpose of receiving information filings relative to the business combination proceedings at the LPSC.

It is currently contemplated that Entergy Louisiana and Entergy Gulf States Louisiana will undertake multiple steps to effectuate the combination, which steps would include the following:

•
Each of Entergy Louisiana and Entergy Gulf States Louisiana will redeem or repurchase all of their respective outstanding preferred membership interests (which interests have a $100 million liquidation value in the case of Entergy Louisiana and $10 million liquidation value in the case of Entergy Gulf States Louisiana).
•
Entergy Gulf States Louisiana will convert from a Louisiana limited liability company to a Texas limited liability company.

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Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis


•
Under the Texas Business Organizations Code (TXBOC), Entergy Louisiana will allocate substantially all of its assets to a new subsidiary (New Entergy Louisiana) and New Entergy Louisiana will assume all of the liabilities of Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Entergy Louisiana will remain in existence and hold the membership interests in New Entergy Louisiana.
•
Under the TXBOC, Entergy Gulf States Louisiana will allocate substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana will assume all of the liabilities of Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. Entergy Gulf States Louisiana will remain in existence and hold the membership interests in New Entergy Gulf States Louisiana.
•
Entergy Louisiana and Entergy Gulf States Louisiana will contribute the membership interests in New Entergy Louisiana and New Entergy Gulf States Louisiana to an affiliate the common membership interests of which will be owned by Entergy Louisiana, Entergy Gulf States Louisiana and Entergy Corporation.
•
New Entergy Gulf States Louisiana will merge into New Entergy Louisiana with New Entergy Louisiana surviving the merger.

Upon the completion of the steps, New Entergy Louisiana will hold substantially all of the assets, and will have assumed all of the liabilities, of Entergy Louisiana and Entergy Gulf States Louisiana. Entergy Louisiana and Entergy Gulf States Louisiana may modify or supplement the steps to be taken to effect the combination.

Results of Operations

Net Income

2014 Compared to 2013

Net income increased slightly, by $0.8 million, primarily due to higher net revenue and lower other operation and maintenance expenses, substantially offset by a higher effective income tax rate, lower other income, higher depreciation and amortization expenses, higher interest expense, and higher taxes other than income taxes.

2013 Compared to 2012

Net income increased $2.7 million primarily due to higher net revenue and higher other income, substantially offset by higher other operation and maintenance expenses, higher depreciation and amortization expenses, higher taxes other than income taxes, and a higher effective income tax rate partially due to the settlement of the tax treatment related to Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing in June 2012. See Note 3 to the financial statements for additional discussion of the tax treatment.


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Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis


Net Revenue

2014 Compared to 2013

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 2014 to 2013.
 
Amount
  
(In Millions)
 
 

2013 net revenue

$913.4

Volume/weather
19.2

Asset retirement obligation
14.3

MISO deferral
8.4

Transmission equalization
3.5

Retail electric price
3.3

Other
1.5

2014 net revenue

$963.6

    
The volume/weather variance is primarily due to an increase of 1,160 GWh, or 6%, in billed electricity usage, including the effect of more favorable weather on residential sales and higher industrial usage primarily in the chemicals industry.

The asset retirement obligation affects net revenue because Entergy Gulf States Louisiana records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation-related costs collected in revenue. The variance is primarily caused by an increase in regulatory credits because of a decrease in decommissioning trust earnings and an increase in regulatory credits to realign the asset retirement obligation regulatory asset with regulatory treatment.

The MISO deferral variance is due to the deferral in 2014 of the non-fuel MISO-related charges, as approved by the LPSC. The deferral of non-fuel MISO-related charges is partially offset in other operation and maintenance expenses. See Note 2 to the financial statements for further discussion of the recovery of non-fuel MISO-related charges.

The transmission equalization variance is primarily due to changes in transmission investment equalization billings under the Entergy System Agreement compared to the same period in 2013 primarily as a result of Entergy Arkansas’s exit from the System Agreement in December 2013.

The retail electric price variance is primarily due to an increase in purchased power capacity costs that are recovered through base rates set in the annual formula rate plan mechanism. See Note 2 to the financial statements for further discussion of Entergy Gulf States Louisiana’s formula rate plan.


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Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis


2013 Compared to 2012

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 2013 to 2012.
 
Amount
  
(In Millions)
 
 

2012 net revenue

$865.9

Louisiana Act 55 financing savings obligation
27.8

Net wholesale revenue
8.3

Volume/weather
7.5

Other
3.9

2013 net revenue

$913.4

    
The Louisiana Act 55 financing savings obligation variance results from a regulatory charge recorded in the second quarter 2012 because Entergy Gulf States Louisiana was required to share with customers the savings from the tax treatment related to the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing. See Note 3 to the financial statements for additional discussion of the tax treatment.

The net wholesale revenue variance is primarily due to higher prices.

The volume/weather variance is primarily due to an increase of 82 GWh, or 0.4%, in billed electricity usage as a result of the effect of more favorable weather, as compared to the prior period, primarily on residential sales. The increase was also driven by higher industrial usage primarily in the chemicals industry.

Other Income Statement Variances

2014 Compared to 2013

Other operation and maintenance expenses decreased primarily due to:

•
a decrease of $20.7 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan.  See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
•
a decrease of $7.2 million due to costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business; and
•
a decrease of $2.3 million in loss reserves.

The decrease was partially offset by:

•
an increase of $6.9 million due to administration fees in 2014 related to participation in the MISO RTO. The LPSC approved deferral of these expenses resulting in no net income effect;
•
an increase of $3.6 million in outside regulatory, consulting, and legal fees;
•
an increase of $1.7 million in customer service costs primarily due to write-offs in 2014 of uncollectible customer accounts; and
•
several individually insignificant items.
    

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Management’s Financial Discussion and Analysis


Taxes other than income taxes increased primarily due to an increase in local franchise taxes resulting from higher residential and commercial revenues as compared to prior year and an increase in ad valorem taxes resulting from higher assessments.

Depreciation and amortization expenses increased primarily due to additions to plant in service.

Other income decreased primarily due to higher realized gains in 2013 on the River Bend decommissioning trust fund investments. There is no effect on net income as these investment gains are offset by a corresponding amount of regulatory charges.

Interest expense increased primarily due to $3.6 million of carrying charges recorded in 2014 on storm restoration costs related to Hurricane Isaac, as approved by the LPSC, and the issuance of $110 million of 3.78% Series first mortgage bonds in July 2014.

2013 Compared to 2012

Other operation and maintenance expenses increased primarily due to:

•
an increase of $15 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge, recognized in September 2013, related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
•
the deferral recorded in the second quarter 2012, as approved by the LPSC and the FERC, of costs related to the transition and implementation of joining the MISO RTO, which reduced expenses by $4.2 million in 2012;
•
an increase of $13.5 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative, partially offset by the deferral, as approved by the LPSC, of $9.8 million of these costs. See the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion;
•
an increase of $3.5 million in fossil-fueled generation expenses due to an overall higher scope of work done during plant outages as compared to the prior year;
•
an increase of $2.9 million in loss reserves; and
•
several individually insignificant items.

Also, other operation and maintenance expenses include $7.2 million in 2013 and $4.7 million in 2012 of costs incurred related to the now terminated plan to spin off and merge the transmission business.

Taxes other than income taxes increased primarily due to an increase in local franchise taxes resulting from higher residential and commercial revenues as compared to prior year and an increase in ad valorem taxes resulting from higher assessments. Franchise taxes have no effect on net income as these taxes are recovered through the franchise tax rider.

Depreciation and amortization expenses increased primarily due to increased plant in service.

Other income increased primarily due to higher realized gains in 2013 on the River Bend decommissioning trust fund investments. There is no effect on net income as these investment gains are offset by a corresponding amount of regulatory charges.


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Income Taxes

The effective income tax rates were 35.3%, 26%, and 24.9% for 2014, 2013, and 2012, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2014, 2013, and 2012 were as follows:
 
2014
 
2013
 
2012
 
(In Thousands)
Cash and cash equivalents at beginning of period

$15,581

 

$35,686

 

$24,845

 
 
 
 
 
 
Net cash provided by (used in):
 

 
 

 
 

Operating activities
592,551

 
434,726

 
346,208

Investing activities
(391,283
)
 
(336,644
)
 
(201,440
)
Financing activities
(53,886
)
 
(118,187
)
 
(133,927
)
Net increase (decrease) in cash and cash equivalents
147,382

 
(20,105
)
 
10,841

 
 
 
 
 
 
Cash and cash equivalents at end of period

$162,963

 

$15,581

 

$35,686


Operating Activities

Net cash flow provided by operating activities increased $157.8 million in 2014 primarily due to:

•
proceeds of $69 million received from the Louisiana Utilities Restoration Corporation as a result of the Louisiana Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;
•
lower nuclear refueling outage spending at River Bend. River Bend had a refueling outage in 2013 and did not have one in 2014; and
•
the timing of collections from customers.

The increase was partially offset by an increase of $18.6 million in pension contributions in 2014. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Net cash flow provided by operating activities increased $88.5 million in 2013 primarily due to:

•
a decrease of $84.1 million in income tax payments in 2013 compared to 2012. Entergy Gulf States Louisiana had income tax payments in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. In 2013, the payments resulted primarily from the reversal of temporary differences for which Entergy Gulf States Louisiana had previously claimed a tax deduction. In 2012, Entergy Gulf States Louisiana no longer had a net operating loss carryover from prior years to reduce current taxable income; and
•
decreased Hurricane Isaac storm spending in 2013.

The increase was partially offset by higher nuclear refueling outage spending at River Bend. River Bend had a refueling outage in 2013 and did not have one in 2012.
    

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Investing Activities

Net cash flow used in investing activities increased $54.6 million in 2014 primarily due to:

•
the deposit in 2014 of $68.5 million into the storm escrow account;
•
the investment in 2014 of $66.2 million in affiliate securities as a result of the Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;
•
the withdrawal of $65.5 million from the storm reserve escrow account in 2013; and
•
an increase in fossil-fueled generation expenditures as a result of an increased scope of work in 2014.

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 services deliveries, and the timing of cash payments during the nuclear fuel cycle;
•
a decrease in nuclear construction expenditures as a result of spending on nuclear projects during the River Bend refueling outage in 2013. River Bend had a refueling outage in 2013 and did not have one in 2014; and
•
a decrease in transmission construction expenditures due to a decreased scope of work performed in 2014.

Net cash flow used in investing activities increased $135.2 million in 2013 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;
•
$51 million in proceeds in 2012 from the sale of a portion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests to a third party. See Note 2 to the financial statements for discussion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests;
•
money pool activity;
•
an increase in nuclear construction expenditures as a result of spending on nuclear projects during the River Bend refueling outage in 2013; and
•
an increase in transmission construction expenditures due to additional reliability work performed in 2013.

The increase was partially offset by:

•
the withdrawal of $65.5 million from the storm reserve escrow account in 2013;
•
a decrease in distribution construction expenditures due to prior year Hurricane Isaac spending; and
•
a decrease in fossil-fueled generation construction expenditures as a result of decreased scope of work in 2013.

Increases in Entergy Gulf States Louisiana’s receivable from the money pool are a use of cash flow, and Entergy Gulf States Louisiana’s receivable from the money pool increased by $1.9 million in 2013 compared to decreasing by $23.6 million in 2012. The money pool is an inter-company borrowing arrangement designed to reduce the Utility operating companies’ need for external short-term borrowings.
    
Financing Activities

Net cash flow used in financing activities decreased $64.3 million in 2014 primarily due to:

•
the issuance of $110 million of 3.78% Series first mortgage bonds in July 2014;
•
the retirement, at maturity, of $75 million of 5.56% Series N notes by the nuclear fuel company variable interest entity in May 2013; and

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•
money pool activity.

The decrease was partially offset by:

•
the issuance of $70 million of 3.38% Series R notes by the nuclear fuel company variable interest entity in February 2013;
•
an increase of $47 million in common equity distributions in 2014; and
•
payments of $14.8 million on credit borrowings in 2014 compared to an increase of $14.8 million in credit borrowings in 2013 against the nuclear fuel company variable interest entity credit facility.

    Decreases in Entergy Gulf States Louisiana’s payable to the money pool are a use of cash flow, and Entergy Gulf States Louisiana’s payable to the money pool decreased by $7.1 million in 2013.

Net cash flow used in financing activities decreased $15.7 million in 2013 primarily due to $14.8 million in credit borrowings in 2013 compared to payments of $29.4 million on credit borrowings in 2012 against the nuclear fuel company variable interest entity credit facility.

The decrease was partially offset by:

•
money pool activity;
•
an increase of $5.7 million in common equity distributions;
•
the issuance of $75 million of 3.25% Series Q notes by the nuclear fuel company variable interest entity in July 2012 compared to the issuance of $70 million of 3.38% Series R notes by the nuclear fuel company variable interest entity in February 2013;
•
the retirement, at maturity, of $75 million of 5.56% Series N notes by the nuclear fuel company variable interest entity in May 2013 compared to the retirement, at maturity, of $60 million of 5.41% Series O notes by the nuclear fuel company variable interest entity in July 2012; and
•
the redemption of $10.84 million of pollution control revenue bonds in 2012.

Decreases in Entergy Gulf States Louisiana’s payable to the money pool are a use of cash flow, and Entergy Gulf States Louisiana’s payable to the money pool decreased by $7.1 million in 2013 compared to increasing by $7.1 million in 2012.

See Note 5 to the financial statements for more details on long-term debt.

Capital Structure

Entergy Gulf States Louisiana’s capitalization is balanced between equity and debt, as shown in the following table. The increase in the debt to capital ratio for Entergy Gulf States Louisiana is primarily due to an increase in long-term debt as a result of the issuance of $110 million of 3.78% Series first mortgage bonds in July 2014.

 
December 31,
2014
 
December 31,
2013
Debt to capital
53.1
%
 
51.1
%
Effect of subtracting cash
(2.6
%)
 
(0.2
%)
Net debt to net capital
50.5
%
 
50.9
%

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Gulf States Louisiana uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Gulf States Louisiana’s

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financial condition. Entergy Gulf States Louisiana uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Gulf States Louisiana’s financial condition because net debt indicates Entergy Gulf States Louisiana’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Uses of Capital

Entergy Gulf States Louisiana requires capital resources for:

•
construction and other capital investments;
•
debt and preferred equity maturities or retirements;
•
working capital purposes, including the financing of fuel and purchased power costs; and
•
distribution and interest payments.

Following are the amounts of Entergy Gulf States Louisiana’s planned construction and other capital investments.
 
2015
 
2016
 
2017
 
(In Millions)
Planned construction and capital investment:
 
 
 
 
 
Generation

$570

 

$145

 

$210

Transmission
195

 
150

 
160

Distribution
95

 
100

 
125

Other
40

 
30

 
30

Total

$900

 

$425

 

$525


Following are the amounts of Entergy Gulf States Louisiana’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2015
 
2016-2017
 
2018-2019
 
After 2019
 
Total
 
(In Millions)
Long-term debt (a)

$115

 

$244

 

$509

 

$1,582

 

$2,450

Operating leases

$13

 

$21

 

$20

 

$26

 

$80

Purchase obligations (b)

$308

 

$490

 

$398

 

$275

 

$1,471


(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 Gulf States Louisiana, it primarily includes unconditional fuel and purchased power obligations.

In addition to the contractual obligations given above, Entergy Gulf States Louisiana expects to contribute approximately $32.5 million to its pension plans and approximately $8.9 million to other postretirement plans in 2015, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015. 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 Gulf States Louisiana has $427.9 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.
    

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In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Gulf States Louisiana includes specific investments, such as the Union Power Station acquisition discussed below; NRC post-Fukushima requirements; environmental compliance spending; transmission projects to enhance reliability, reduce congestion, and enable economic growth; resource planning; generation projects; system improvements; 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, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.

Management provides more information on long-term debt maturities in Note 5 to the financial statements.

As an indirect, wholly-owned subsidiary of Entergy Corporation, Entergy Gulf States Louisiana pays distributions from its earnings at a percentage determined monthly. Entergy Gulf States Louisiana’s long-term debt indenture contains restrictions on the payment of cash dividends or other distributions on its common and preferred membership interests.

Union Power Station Purchase Agreement

In December 2014, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas entered into an asset purchase agreement to acquire 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). Pursuant to the agreement, Entergy Gulf States Louisiana will acquire two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy Texas will each acquire one power block and a 25% undivided ownership interest in such related assets. (If Entergy Arkansas or Entergy Texas do not obtain approval for the purchase of their power blocks, Entergy Gulf States Louisiana will seek to purchase the power blocks not approved.) The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments.  In addition, Entergy Gulf States Louisiana anticipates selling 20% of the capacity and energy associated with its two power blocks to Entergy New Orleans through a cost-based, life-of-unit power purchase agreement. The purchase is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federal and state regulatory and permitting agencies. These include regulatory approvals from the APSC, LPSC, PUCT, and FERC, as well as clearance under the Hart-Scott-Rodino anti-trust law. In December 2014, Entergy Texas filed its application with the PUCT for approval of the acquisition. The PUCT has indicated that it will convene the hearing on the merits of this case in June 2015. Entergy Texas intends to file a rate application to seek cost recovery later in 2015. In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC and Entergy Arkansas filed its application with the APSC, each for approval of the acquisition and cost recovery. Closing is targeted to occur in late-2015.

New Nuclear Development

Entergy Gulf States Louisiana and Entergy Louisiana have been developing and are preserving a project option for new nuclear generation at River Bend. In the first quarter 2010, Entergy Gulf States Louisiana and Entergy Louisiana each paid for and recognized on its books $24.9 million in costs associated with the development of new nuclear generation at the River Bend site; these costs previously had been recorded on the books of Entergy New Nuclear Utility Development, LLC, a System Energy subsidiary. Entergy Gulf States Louisiana and Entergy Louisiana will share costs going forward on a 50/50 basis, which reflects each company’s current participation level in the project.

In March 2010, Entergy Gulf States Louisiana and Entergy 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.

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At its June 2012 meeting the LPSC voted to uphold an ALJ recommendation that the request of Entergy Gulf States Louisiana and Entergy 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 Gulf States Louisiana and Entergy 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 a 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, 2014, Entergy Gulf States Louisiana and Entergy Louisiana each have a regulatory asset of $29.2 million on its balance sheet related to these new nuclear generation development costs.

Sources of Capital

Entergy Gulf States 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 Gulf States Louisiana may refinance, redeem, or otherwise retire debt and preferred equity/membership interests prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common and preferred equity/membership interest issuances by Entergy Gulf States Louisiana require prior regulatory approval. Preferred equity/membership interest and debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. Entergy Gulf States Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs.

Entergy Gulf States Louisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
2014
 
2013
 
2012
 
2011
(In Thousands)
$1,166
 
$1,925
 
($7,074)
 
$23,596

See Note 4 to the financial statements for a description of the money pool.

Entergy Gulf States Louisiana has a credit facility in the amount of $150 million scheduled to expire in March 2019. The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility.  No borrowings were outstanding under the credit facility as of December 31, 2014.   In addition, Entergy Gulf States Louisiana entered into an uncommitted letter of credit facility in 2014 as a means to post collateral to support its obligations under MISO. As of December 31, 2014, a $27.9 million letter of credit was outstanding under Entergy Gulf States Louisiana’s letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

Entergy Gulf States Louisiana obtained authorizations from the FERC through October 2015 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.

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See Note 4 to the financial statements for further discussion of Entergy Gulf States Louisiana’s short-term borrowing limits.
    
The Entergy Gulf States Louisiana nuclear fuel company variable interest entity has a credit facility in the amount of $100 million scheduled to expire in June 2016. No borrowings were outstanding under the credit facility as of December 31, 2014. See Note 4 to the financial statements for additional discussion of the variable interest entity credit facility.

In July 2014, Entergy Gulf States Louisiana issued $110 million of 3.78% Series first mortgage bonds due April 2025. Entergy Gulf States Louisiana used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes.

Hurricane Isaac

In August 2012, Hurricane Isaac caused extensive damage to Entergy Gulf States 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 January 2013, Entergy Gulf States Louisiana drew $65 million from its funded storm reserve escrow accounts.  In April 2013, Entergy Gulf States Louisiana and Entergy Louisiana filed a joint application with the LPSC relating to Hurricane Isaac system restoration costs.  In May 2013, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55). The LPSC Staff filed direct testimony in September 2013 concluding that Hurricane Isaac system restoration costs incurred by Entergy Gulf States Louisiana and Entergy Louisiana were reasonable and prudent, subject to proposed minor adjustments which totaled approximately 1% of each company’s costs. Following an evidentiary hearing and recommendations by the ALJ, the LPSC voted in June 2014 to approve a series of orders which (i) quantify the amount of Hurricane Isaac system restoration costs prudently incurred ($66.5 million for Entergy Gulf States Louisiana and $224.3 million for Entergy Louisiana); (ii) determine the level of storm reserves to be re-established ($90 million for Entergy Gulf States Louisiana and $200 million for Entergy Louisiana); (iii) authorize Entergy Gulf States Louisiana and Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) grant other requested relief associated with storm reserves and Act 55 financing of Hurricane Isaac system restoration costs. Entergy Gulf States Louisiana committed to pass on to customers a minimum of $6.9 million of customer benefits through annual customer credits of approximately $1.4 million for five years.  Approvals for the Act 55 financings were obtained from the Louisiana Utilities Restoration Corporation (LURC) and the Louisiana State Bond Commission.

In July 2014, Entergy Gulf States Louisiana issued $110 million of 3.78% Series first mortgage bonds due April 2025 and used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes. In August 2014 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $71 million in bonds under Act 55 of the Louisiana Legislature.  From the $69 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $3 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $66 million directly to Entergy Gulf States Louisiana.  Entergy Gulf States Louisiana used the $66 million received from the LURC to acquire 662,426.80 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 Gulf States Louisiana does not report the bonds on its balance sheet because the bonds are the obligation of the LCDA and there is no recourse against Entergy Gulf States Louisiana in the event of a bond default.  To service

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the bonds, Entergy Gulf States Louisiana collects a system restoration charge on behalf of the LURC, and remits the collections to the bond indenture trustee.  Entergy Gulf States Louisiana does not report the collections as revenue because it is merely acting as the billing and collection agent for the state.

Entergy Louisiana’s Ninemile Point Unit 6 Self-Build Project

In June 2011, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by Entergy Louisiana’s construction of a combined-cycle gas turbine generating facility (Ninemile 6) at its existing Ninemile Point electric generating station. Ninemile 6 is a nominally-sized 560 MW unit that is expected to cost approximately $655 million to construct when spending is complete, excluding interconnection and transmission upgrades. Entergy Gulf States Louisiana joined in the application, seeking certification of its purchase under a life-of-unit power purchase agreement of up to 25% of the capacity and energy generated by Ninemile 6. The Ninemile 6 capacity and energy is allocated 55% to Entergy Louisiana, 25% to Entergy Gulf States Louisiana, and 20% to Entergy New Orleans. In February 2012 the City Council passed a resolution authorizing Entergy New Orleans to purchase 20% of the Ninemile 6 energy and capacity. In March 2012 the LPSC unanimously voted to grant the certifications requested by Entergy Gulf States Louisiana and Entergy Louisiana. Following approval by the LPSC, Entergy Louisiana issued full notice to proceed to the project’s engineering, procurement, and construction contractor.

Under the terms approved by the LPSC, non-fuel costs may be recovered through Entergy Gulf States Louisiana’s formula rate plan beginning in the month after the unit is placed in service. In July 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed an unopposed stipulation with the LPSC that estimates a first year revenue requirement associated with Ninemile 6 and provides a mechanism to update the revenue requirement as the in-service date approaches, which was subsequently approved by the LPSC. 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 was filed.  The December 2014 estimate forms the basis of rates implemented effective with the first billing cycle of January 2015.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Gulf States Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Gulf States 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
    
In November 2011 the LPSC approved a one-year extension of Entergy Gulf States Louisiana’s formula rate plan.  In May 2012, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2011 test year.  The filing reflected an 11.94% earned return on common equity, which was above the earnings bandwidth and indicated a $6.5 million cost of service rate decrease was necessary under the formula rate plan.  The filing also reflected a $22.9 million rate decrease for the incremental capacity rider.  Subsequently, in August 2012, Entergy Gulf States Louisiana submitted a revised filing that reflected an earned return on common equity of 11.86%, which indicated a $5.7 million cost of service rate decrease was necessary under the formula rate plan.  The revised filing also indicated that a reduction of $20.3 million should be reflected in the incremental capacity rider.  The rate reductions were implemented, subject to refund, effective for bills rendered in the first billing cycle of September 2012.  Subsequently, in December 2012, Entergy Gulf States Louisiana submitted a revised evaluation report that reflected expected retail jurisdictional cost of $17 million for the first-year capacity charges for the purchase from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy.  This rate change was implemented effective with the first billing cycle of January 2013.  The 2011 test year filings, as revised, were approved by the LPSC in February 2013. In April 2013, Entergy Gulf States Louisiana submitted a revised evaluation report increasing the incremental capacity rider by approximately $7.3 million to reflect the cost of an additional capacity contract.

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In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Gulf States Louisiana, and the required filing was made in February 2013. The filing anticipated Entergy Gulf States Louisiana’s integration into MISO. In the filing Entergy Gulf States Louisiana requested, among other relief:

•
authorization to increase the revenue it collects from customers by approximately $24 million;
•
an authorized return on common equity of 10.4%;
•
authorization to increase depreciation rates embedded in the proposed revenue requirement; and,
•
authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.
 
Following a hearing before an ALJ and the ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. Major terms of the settlement include approval of a three-year formula rate plan (effective for test years 2014-2016) modeled after the formula rate plan in effect for Entergy Gulf States Louisiana for 2011, including the following: (1) a midpoint return on equity of 9.95% plus or minus 80 basis points, with 60/40 sharing of earnings outside of the bandwidth; (2) recovery outside of the sharing mechanism for the non-fuel MISO-related costs, additional capacity revenue requirement, extraordinary items, such as the Ninemile 6 project, and certain special recovery items; (3) three-year amortization of costs to achieve savings associated with the human capital management strategic imperative, with savings to be reflected as they are realized in subsequent years; (4) eight-year amortization of costs incurred in connection with potential development of a new nuclear unit at River Bend, without carrying costs, beginning December 2014, provided, however, that amortization of these costs shall not result in a future rate increase; (5) no change in rates related to test year 2013, except with respect to recovery of the non-fuel MISO-related costs and any changes to the additional capacity revenue requirement; and (6) no increase in rates related to test year 2014, except for those items eligible for recovery outside of the earnings sharing mechanism. Existing depreciation rates will not change. Implementation of rate changes for items recoverable outside of the earnings sharing mechanism occurred in December 2014.

Pursuant to the rate case settlement approved by the LPSC in December 2013, Entergy Gulf States Louisiana submitted a compliance filing in May 2014 reflecting the effects of the estimated MISO cost recovery mechanism revenue requirement and adjustment of the additional capacity mechanism. In November 2014, Entergy Gulf States Louisiana submitted an additional compliance filing updating the estimated MISO cost recovery mechanism for the most recent actual data. Based on this updated filing, a net increase of $5.8 million in formula rate plan revenue to be collected over nine months was implemented in December 2014. The compliance filings are subject to the review in accordance with the review process set forth in Entergy Gulf States Louisiana’s formula rate plan.

Retail Rates - Gas

In January 2012, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2011.  The filing showed an earned return on common equity of 10.48%, which is within the earnings bandwidth of 10.5%, plus or minus fifty basis points.  In April 2012 the LPSC Staff filed its findings, suggesting adjustments that produced an 11.54% earned return on common equity for the test year and a $0.1 million rate reduction.  Entergy Gulf States Louisiana accepted the LPSC Staff’s recommendations, and the rate reduction was effective with the first billing cycle of May 2012.

In January 2013, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2012.  The filing showed an earned return on common equity of 11.18%, which results in

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a $43 thousand rate reduction.  In March 2013 the LPSC Staff issued its proposed findings and recommended two adjustments. Entergy Gulf States Louisiana and the LPSC Staff reached agreement regarding the LPSC Staff’s proposed adjustments. As reflected in an unopposed joint report of proceedings filed by Entergy Gulf States Louisiana and the LPSC Staff in May 2013, Entergy Gulf States Louisiana accepted, with modification, the LPSC Staff’s proposed adjustment to property insurance expense and agreed to: (1) a three-year extension of the gas rate stabilization plan with a midpoint return on equity of 9.95%, with a first year midpoint reset; (2) dismissal of a docket initiated by the LPSC to evaluate the allowed return on equity for Entergy Gulf States Louisiana’s gas rate stabilization plan; and (3) presentation to the LPSC by November 2014 by Entergy Gulf States Louisiana and the LPSC Staff of their recommendation for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment. The LPSC approved the agreement in May 2013.

In January 2014, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2013.  The filing showed an earned return on common equity of 5.47% which results in a $1.5 million rate increase. In April 2014 the LPSC Staff issued a report indicating “that Entergy Gulf States Louisiana has properly determined its earnings for the test year ended September 30, 2013.” The $1.5 million rate increase was implemented effective with the first billing cycle of April 2014.

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 percent annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding ten percent; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider will commence with bills rendered on and after the first billing cycle of April 2015.

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 results in a $706 thousand rate increase.  The rate increase, if approved, will be implemented effective with the first billing cycle of April 2015.

Fuel and purchased power cost recovery

Entergy Gulf States 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 Gulf States Louisiana’s purchased gas adjustments include estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
        
In December 2011 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates.  The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009.  Discovery is in progress, but a procedural schedule has not been established.


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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 has yet to commence.

Industrial and Commercial Customers

Entergy Gulf States 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 Gulf States Louisiana’s industrial customer base. Entergy Gulf States 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 Gulf States Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers. Entergy Gulf States Louisiana does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Gulf States Louisiana’s marketing efforts in retaining industrial customers.

Federal Regulation

See “Entergy’s Integration Into the MISO Regional Transmission Organization,” “System Agreement,” and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of these topics.

Nuclear Matters

Entergy Gulf States Louisiana owns and, through an affiliate, operates the River Bend nuclear power plant. Entergy Gulf States Louisiana is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, regulatory requirement changes, including changes resulting from events at other plants, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of River Bend, Entergy Gulf States Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.

The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system.  The issue is applicable to River Bend 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.

After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States.  The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders.  The task force then issued a second report in September 2011.  Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012.  The three orders require U.S. nuclear operators to undertake plant modifications and perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating nuclear plants.  The NRC, with input from the industry, is continuing to determine the specific actions required by the orders. Entergy Gulf States Louisiana’s estimated capital expenditures for 2015 through 2017 for complying with the NRC orders are included in the planned construction and other capital investments estimates given in “Liquidity and Capital Resources - Uses of Capital” above.

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Environmental Risks

Entergy Gulf States 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 Gulf States Louisiana is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy Gulf States 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’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 fourth quarter 2014, Entergy Gulf States Louisiana recorded a revision to its estimated decommissioning cost liability for River Bend as a result of a revised decommissioning cost study. The revised estimate resulted in a $20 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining useful life of the unit.

Unbilled Revenue

As discussed in Note 1 to the financial statements, Entergy Gulf States Louisiana 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 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.

Qualified Pension and Other Postretirement Benefits

Entergy Gulf States 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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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 2014
Qualified Pension Cost
 
Impact on 2014
Qualified Projected
Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$1,737
 
$26,342
Rate of return on plan assets
 
(0.25%)
 
$1,117
 
$—
Rate of increase in compensation
 
0.25%
 
$669
 
$4,020

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 2014
Postretirement Benefit Cost
 
Impact on 2014 Accumulated
Postretirement Benefit
Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$534
 
$7,188
Health care cost trend
 
0.25%
 
$956
 
$6,643

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

Costs and Funding

Total qualified pension cost for Entergy Gulf States Louisiana in 2014 was $18.6 million. Entergy Gulf States Louisiana anticipates 2015 qualified pension cost to be $27.5 million.  Entergy Gulf States Louisiana contributed $30.2 million to its pension plans in 2014 and estimates 2015 pension contributions to be approximately $32.5 million, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015.

Total postretirement health care and life insurance benefit costs for Entergy Gulf States Louisiana in 2014 were $12.2 million.   Entergy Gulf States Louisiana expects 2015 postretirement health care and life insurance benefit costs of approximately $13.1 million. Entergy Gulf States Louisiana contributed $8.3 million to its other postretirement plans in 2014 and expects to contribute approximately $8.9 million in 2015.

The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans.  The 2014 actuarial study reviewed plan experience from 2010 through 2013.  As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies.  These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of  $51.3 million in the qualified pension benefit obligation and $11.8 million in the accumulated postretirement obligation.  The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $7.6 million and other postretirement cost by approximately $1.6 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.


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Federal Healthcare Legislation

See the “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.

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Members of
Entergy Gulf States Louisiana, L.L.C.
Jefferson, Louisiana


We have audited the accompanying balance sheets of Entergy Gulf States Louisiana, L.L.C. (the “Company”) as of December 31, 2014 and 2013, and the related income statements, statements of comprehensive income, statements of cash flows, and statements of changes in equity (pages 343 through 348 and applicable items in pages 61 through 234) for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Gulf States Louisiana, L.L.C. as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana
February 26, 2015


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ENTERGY GULF STATES LOUISIANA, L.L.C.
INCOME STATEMENTS
 
 
 
 
 
For the Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$2,079,236

 

$1,881,895

 

$1,606,165

Natural gas
 
71,690

 
59,238

 
48,729

TOTAL
 
2,150,926

 
1,941,133

 
1,654,894

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
350,765

 
286,625

 
194,878

Purchased power
 
849,165

 
731,611

 
562,247

Nuclear refueling outage expenses
 
21,443

 
20,345

 
17,565

Other operation and maintenance
 
392,398

 
398,589

 
361,415

Decommissioning
 
16,844

 
15,908

 
15,024

Taxes other than income taxes
 
84,178

 
80,307

 
76,295

Depreciation and amortization
 
155,383

 
150,929

 
146,673

Other regulatory charges (credits) - net
 
(12,640
)
 
9,482

 
31,835

TOTAL
 
1,857,536

 
1,693,796

 
1,405,932

 
 
 
 
 
 
 
OPERATING INCOME
 
293,390

 
247,337

 
248,962

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
7,433

 
8,062

 
8,694

Interest and investment income
 
40,448

 
52,953

 
42,773

Miscellaneous - net
 
(7,608
)
 
(11,567
)
 
(8,928
)
TOTAL
 
40,273

 
49,448

 
42,539

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
86,705

 
81,118

 
83,251

Allowance for borrowed funds used during construction
 
(4,315
)
 
(2,814
)
 
(3,343
)
TOTAL
 
82,390

 
78,304

 
79,908

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
251,273

 
218,481

 
211,593

 
 
 
 
 
 
 
Income taxes
 
88,782

 
56,819

 
52,616

 
 
 
 
 
 
 
NET INCOME
 
162,491

 
161,662

 
158,977

 
 
 
 
 
 
 
Preferred distribution requirements and other
 
827

 
825

 
825

 
 
 
 
 
 
 
EARNINGS APPLICABLE TO COMMON EQUITY
 

$161,664

 

$160,837

 

$158,152

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY GULF STATES LOUISIANA, L.L.C.
STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
For the Years Ended December 31,
 
2014
 
2013
 
2012
 
(In Thousands)
 
 
 
 
 
 
Net Income

$162,491

 

$161,662

 

$158,977

 
 
 
 
 
 
Other comprehensive income
 

 
 

 
 

Pension and other postretirement liabilities
 

 
 

 
 

(net of tax expense (benefit) of ($15,777), $34,126, and $8,732)
(25,145
)
 
37,027

 
4,381

Other comprehensive income
(25,145
)
 
37,027

 
4,381

 
 
 
 
 
 
Comprehensive Income

$137,346

 

$198,689

 

$163,358

 
 
 
 
 
 
See Notes to Financial Statements.
 

 
 

 
 



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ENTERGY GULF STATES LOUISIANA, L.L.C.
STATEMENTS OF CASH FLOWS
 
 
 
 
 
For the Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(In Thousands)
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$162,491

 

$161,662

 

$158,977

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 
230,795

 
223,420

 
214,929

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
99,404

 
86,125

 
92,523

Changes in working capital:
 
 

 
 

 
 

Receivables
 
31,710

 
(61,561
)
 
87,089

Fuel inventory
 
10,348

 
412

 
(3,718
)
Accounts payable
 
3,646

 
24,694

 
(1,725
)
Prepaid taxes and taxes accrued
 
(2,050
)
 
(43,029
)
 
(86,346
)
Interest accrued
 
1,267

 
371

 
(647
)
Deferred fuel costs
 
20,205

 
(10,573
)
 
(96,230
)
Other working capital accounts
 
22,323

 
(5,434
)
 
(5,548
)
Changes in provisions for estimated losses
 
69,839

 
(60,084
)
 
(2,222
)
Changes in other regulatory assets
 
(101,173
)
 
123,254

 
(73,082
)
Changes in pension and other postretirement liabilities
 
126,889

 
(140,643
)
 
83,440

Other
 
(83,143
)
 
136,112

 
(21,232
)
Net cash flow provided by operating activities
 
592,551

 
434,726

 
346,208

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(272,738
)
 
(267,122
)
 
(284,458
)
Allowance for equity funds used during construction
 
7,433

 
8,062

 
8,694

Nuclear fuel purchases
 
(40,319
)
 
(141,176
)
 
(51,610
)
Proceeds from sale of nuclear fuel
 
66,220

 
19,401

 
67,632

Investment in affiliates
 
(66,243
)
 
—

 
—

Payment to storm reserve escrow account
 
(68,523
)
 
(29
)
 
(99
)
Receipts from storm reserve escrow account
 
—

 
65,475

 
3,364

Proceeds from nuclear decommissioning trust fund sales
 
173,530

 
193,792

 
131,042

Investment in nuclear decommissioning trust funds
 
(191,402
)
 
(213,122
)
 
(150,601
)
Change in money pool receivable - net
 
759

 
(1,925
)
 
23,596

Proceeds from the sale of investment
 
—

 
—

 
51,000

Net cash flow used in investing activities
 
(391,283
)
 
(336,644
)
 
(201,440
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
108,730

 
69,770

 
74,251

Retirement of long-term debt
 
—

 
(75,000
)
 
(70,840
)
Change in money pool payable - net
 
—

 
(7,074
)
 
7,074

Changes in credit borrowings - net
 
(14,800
)
 
14,800

 
(29,400
)
Dividends/distributions paid:
 
 

 
 

 
 

Common equity
 
(166,901
)
 
(119,900
)
 
(114,200
)
Preferred membership interests
 
(825
)
 
(825
)
 
(825
)
Other
 
19,910

 
42

 
13

Net cash flow used in financing activities
 
(53,886
)
 
(118,187
)
 
(133,927
)
 
 
 
 
 
 
 
Net increase (decrease) in cash and cash equivalents
 
147,382

 
(20,105
)
 
10,841

Cash and cash equivalents at beginning of period
 
15,581

 
35,686

 
24,845

Cash and cash equivalents at end of period
 

$162,963

 

$15,581

 

$35,686

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 

 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$82,531

 

$77,882

 

$80,848

Income taxes
 

($1,009
)
 

$5,064

 

$89,191

See Notes to Financial Statements.
 
 

 
 

 
 


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ENTERGY GULF STATES LOUISIANA, L.L.C.
BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2014
 
2013
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$53,394

 

$1,739

Temporary cash investments
 
109,569

 
13,842

Total cash and cash equivalents
 
162,963

 
15,581

Accounts receivable:
 
 

 
 

Customer
 
67,006

 
69,648

Allowance for doubtful accounts
 
(625
)
 
(909
)
Associated companies
 
86,966

 
107,723

Other
 
18,379

 
22,945

Accrued unbilled revenues
 
54,079

 
58,867

Total accounts receivable
 
225,805

 
258,274

Deferred fuel costs
 
—

 
9,625

Fuel inventory - at average cost
 
16,207

 
26,555

Materials and supplies - at average cost
 
121,237

 
122,909

Deferred nuclear refueling outage costs
 
7,416

 
25,975

Prepayments and other
 
45,122

 
36,698

TOTAL
 
578,750

 
495,617

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Investment in affiliate preferred membership interests
 
355,906

 
289,664

Decommissioning trust funds
 
637,744

 
573,744

Non-utility property - at cost (less accumulated depreciation)
 
193,407

 
174,134

Storm reserve escrow account
 
90,061

 
21,538

Other
 
14,887

 
14,145

TOTAL
 
1,292,005

 
1,073,225

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
7,600,730

 
7,400,689

Natural gas
 
148,586

 
143,902

Construction work in progress
 
127,436

 
105,314

Nuclear fuel
 
131,901

 
196,508

TOTAL UTILITY PLANT
 
8,008,653

 
7,846,413

Less - accumulated depreciation and amortization
 
4,176,242

 
4,071,762

UTILITY PLANT - NET
 
3,832,411

 
3,774,651

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Regulatory asset for income taxes - net
 
161,714

 
165,456

Other regulatory assets
 
426,381

 
321,466

Deferred fuel costs
 
100,124

 
100,124

Other
 
12,438

 
12,049

TOTAL
 
700,657

 
599,095

 
 
 
 
 
TOTAL ASSETS
 

$6,403,823

 

$5,942,588

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY GULF STATES LOUISIANA, L.L.C.
BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2014
 
2013
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Currently maturing long-term debt
 

$31,955

 

$—

Accounts payable:
 
 

 
 

Associated companies
 
102,933

 
95,853

Other
 
108,874

 
103,314

Customer deposits
 
56,749

 
51,839

Accumulated deferred income taxes
 
21,095

 
36,330

Interest accrued
 
27,075

 
25,808

Deferred fuel costs
 
10,580

 
—

Other
 
44,517

 
43,097

TOTAL
 
403,778

 
356,241

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
1,601,032

 
1,512,547

Accumulated deferred investment tax credits
 
72,277

 
75,295

Other regulatory liabilities
 
176,305

 
159,429

Decommissioning and asset retirement cost liabilities
 
446,619

 
403,084

Accumulated provisions
 
106,985

 
37,146

Pension and other postretirement liabilities
 
401,144

 
274,315

Long-term debt
 
1,590,862

 
1,527,465

Long-term payables - associated companies
 
26,156

 
27,900

Other
 
148,102

 
108,189

TOTAL
 
4,569,482

 
4,125,370

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
EQUITY
 
 

 
 

Preferred membership interests without sinking fund
 
10,000

 
10,000

Member’s equity
 
1,473,910

 
1,479,179

Accumulated other comprehensive loss
 
(53,347
)
 
(28,202
)
TOTAL
 
1,430,563

 
1,460,977

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$6,403,823

 

$5,942,588

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 



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ENTERGY GULF STATES LOUISIANA, L.L.C.
STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2014, 2013, and 2012
 
 
 
 
 
 
 
 
 
Common Equity
 
 
 
Preferred
Membership
Interests
 
Member’s Equity
 
Accumulated Other Comprehensive Loss
 
Total
 
(In Thousands)
 
 
 
 
 
 
 
 
Balance at December 31, 2011

$10,000

 

$1,393,386

 

($69,610
)
 

$1,333,776

Net income
—

 
158,977

 
—

 
158,977

Member contribution
—

 
1,000

 
—

 
1,000

Other comprehensive income
—

 
—

 
4,381

 
4,381

Dividends/distributions declared on common equity
—

 
(114,200
)
 
—

 
(114,200
)
Dividends/distributions declared on preferred membership interests
—

 
(825
)
 
—

 
(825
)
Other
—

 
(105
)
 
—

 
(105
)
Balance at December 31, 2012

$10,000

 

$1,438,233

 

($65,229
)
 

$1,383,004

Net income
—

 
161,662

 
—

 
161,662

Other comprehensive income
—

 
—

 
37,027

 
37,027

Dividends/distributions declared on common equity
—

 
(119,900
)
 
—

 
(119,900
)
Dividends/distributions declared on preferred membership interests
—

 
(825
)
 
—

 
(825
)
Other
—

 
9

 
—

 
9

Balance at December 31, 2013

$10,000

 

$1,479,179

 

($28,202
)
 

$1,460,977

Net income
—

 
162,491

 
—

 
162,491

Other comprehensive income
—

 
—

 
(25,145
)
 
(25,145
)
Dividends/distributions declared on common equity
—

 
(166,901
)
 
—

 
(166,901
)
Dividends/distributions declared on preferred membership interests
—

 
(827
)
 
—

 
(827
)
Other
—

 
(32
)
 
—

 
(32
)
Balance at December 31, 2014

$10,000

 

$1,473,910

 

($53,347
)
 

$1,430,563

 
 
 
 
 
 
 
 
See Notes to Financial Statements.
 

 
 

 
 

 
 



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ENTERGY GULF STATES LOUISIANA, L.L.C.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$2,150,926

 

$1,941,133

 

$1,654,894

 

$2,134,409

 

$2,097,021

Net Income

$162,491

 

$161,662

 

$158,977

 

$201,604

 

$174,319

Total assets

$6,403,823

 

$5,942,588

 

$5,803,119

 

$5,763,719

 

$5,690,376

Long-term obligations (a)

$1,590,862

 

$1,527,465

 

$1,442,429

 

$1,482,430

 

$1,584,332

 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (excluding currently maturing debt).
 
 
 
 
 
 
 
 
 
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
Electric Operating Revenues:
 

 
 

 
 

 
 

 
 

Residential

$502

 

$465

 

$389

 

$479

 

$498

Commercial
448

 
417

 
349

 
416

 
426

Industrial
588

 
502

 
392

 
490

 
489

Governmental
23

 
22

 
18

 
22

 
21

Total retail
1,561

 
1,406

 
1,148

 
1,407

 
1,434

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
407

 
375

 
377

 
562

 
463

Non-associated companies
62

 
45

 
34

 
52

 
79

Other
49

 
56

 
47

 
49

 
40

Total

$2,079

 

$1,882

 

$1,606

 

$2,070

 

$2,016

 
 
 
 
 
 
 
 
 
 
Billed Electric Energy Sales (GWh):
 
 
 

 
 

 
 

 
 

Residential
5,368

 
5,206

 
5,176

 
5,383

 
5,538

Commercial
5,298

 
5,208

 
5,287

 
5,239

 
5,274

Industrial
9,925

 
9,021

 
8,890

 
9,041

 
8,801

Governmental
232

 
228

 
228

 
222

 
210

Total retail
20,823

 
19,663

 
19,581

 
19,885

 
19,823

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
6,966

 
6,580

 
7,727

 
8,595

 
8,516

Non-associated companies
925

 
887

 
941

 
1,013

 
1,705

Total
28,714

 
27,130

 
28,249

 
29,493

 
30,044



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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Entergy Louisiana and Entergy Gulf States Louisiana Business Combination

In June 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed a business combination study report with the LPSC. The report contained a preliminary analysis of the potential combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility, including an overview of the combination that identified its potential customer benefits. Although not part of the business combination, Entergy Louisiana provided notice to the City Council in June 2014 that it would seek authorization to transfer to Entergy New Orleans the assets that currently support the provision of service to Entergy Louisiana’s customers in Algiers. Entergy Louisiana subsequently filed the referenced application with the City Council in October 2014. In the summer of 2014, Entergy Louisiana and Entergy Gulf States Louisiana held technical conferences and face-to-face meetings with LPSC staff and other stakeholders to discuss potential effects of the combination, solicit suggestions and concerns, and identify areas in which additional information might be needed.

On September 30, 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed an application with the LPSC seeking authorization to undertake the transactions that would result in the combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility.

The combination is subject to regulatory review and approval of the LPSC, the FERC, and the NRC. In June 2014, Entergy submitted an application to the NRC for approval of River Bend and Waterford 3 license transfers as part of the steps to complete the business combination. The combination also could be subject to regulatory review of the City Council if Entergy Louisiana continues to own the assets that currently support Entergy Louisiana’s customers in Algiers at the time the combination is effectuated. In November 2014, Entergy Louisiana filed an application with the City Council seeking authorization to undertake the combination. The application provides that if the City Council approves the Algiers asset transfer before the business combination occurs, the City Council may not need to issue a public interest finding regarding the combination. In December 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed applications with the FERC requesting authorization for the business combination and the Algiers asset transfer. In January 2015, Entergy Services filed an application with the FERC for financing authority for the combined company. If approvals are obtained from the LPSC, the FERC, the NRC, and, if required, the City Council, Entergy Louisiana and Entergy Gulf States Louisiana expect the combination will be effected in the second half of 2015.

The procedural schedule in the LPSC business combination proceeding calls for LPSC Staff and intervenor testimony to be filed in March 2015, with a hearing scheduled for June 2015. Entergy Louisiana and Entergy Gulf States Louisiana have requested that the LPSC issue its decision regarding the business combination in August 2015. In the City Council business combination proceeding, the City Council announced through a resolution that it would not initiate an active review of the business combination filing, but instead would establish a business combination docket for the limited purpose of receiving information filings relative to the business combination proceedings at the LPSC.

It is currently contemplated that Entergy Louisiana and Entergy Gulf States Louisiana will undertake multiple steps to effectuate the combination, which steps would include the following:

•
Each of Entergy Louisiana and Entergy Gulf States Louisiana will redeem or repurchase all of their respective outstanding preferred membership interests (which interests have a $100 million liquidation value in the case of Entergy Louisiana and $10 million liquidation value in the case of Entergy Gulf States Louisiana).
•
Entergy Gulf States Louisiana will convert from a Louisiana limited liability company to a Texas limited liability company.
•
Under the Texas Business Organizations Code (TXBOC), Entergy Louisiana will allocate substantially all of its assets to a new subsidiary (New Entergy Louisiana) and New Entergy Louisiana will assume all

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of the liabilities of Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Entergy Louisiana will remain in existence and hold the membership interests in New Entergy Louisiana.
•
Under the TXBOC, Entergy Gulf States Louisiana will allocate substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana will assume all of the liabilities of Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. Entergy Gulf States Louisiana will remain in existence and hold the membership interests in New Entergy Gulf States Louisiana.
•
Entergy Louisiana and Entergy Gulf States Louisiana will contribute the membership interests in New Entergy Louisiana and New Entergy Gulf States Louisiana to an affiliate the common membership interests of which will be owned by Entergy Louisiana, Entergy Gulf States Louisiana and Entergy Corporation.
•
New Entergy Gulf States Louisiana will merge into New Entergy Louisiana with New Entergy Louisiana surviving the merger.

Upon the completion of the steps, New Entergy Louisiana will hold substantially all of the assets, and will have assumed all of the liabilities, of Entergy Louisiana and Entergy Gulf States Louisiana. Entergy Louisiana and Entergy Gulf States Louisiana may modify or supplement the steps to be taken to effect the combination.

Results of Operations

Net Income

2014 Compared to 2013

Net income increased $31.1 million primarily due to higher net revenue and higher other income, partially offset by higher other operation and maintenance expenses, higher depreciation and amortization expenses, and higher interest expense.

2013 Compared to 2012

Net income decreased $28.6 million primarily due to higher other operation and maintenance expenses, higher depreciation and amortization expenses, higher interest expense, and higher nuclear refueling outage expenses, partially offset by higher net revenue. Also contributing to the decrease in net income was the settlement of the tax treatment related to the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing in June 2012, which resulted in a $142.7 million reduction of income tax expense partially offset by a $137.1 million ($84.3 million net-of-tax) regulatory charge, which reduced net revenue in 2012. See Note 3 to the financial statements for additional discussion of the tax treatment.


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Net Revenue

2014 Compared to 2013

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 2014 to 2013.
 
Amount
 
(In Millions)
 
 
2013 net revenue

$1,208.8

MISO deferral
16.9

Retail electric price
15.7

Asset retirement obligation
15.2

Volume/weather
12.6

Other
13.3

2014 net revenue

$1,282.5


The MISO deferral variance is due to the deferral in 2014 of non-fuel MISO-related charges, as approved by the LPSC. The deferral of non-fuel MISO-related charges is partially offset in other operation and maintenance expenses. See Note 2 to the financial statements for further discussion of the recovery of non-fuel MISO-related charges.

The retail electric price variance is primarily due to an increase in affiliated purchased power capacity costs that are recovered through base rates set in the annual formula rate plan mechanism and a formula rate plan increase effective December 2014. Entergy Louisiana’s formula rate plan is discussed in Note 2 to the financial statements.

The asset retirement obligation affects net revenue because Entergy Louisiana records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation-related costs collected in revenue. The variance is primarily caused by an increase in regulatory credits because of a decrease in decommissioning trust earnings, increases in depreciation and accretion expenses, and an increase in regulatory credits to realign the asset retirement obligation regulatory asset with regulatory treatment.

The volume/weather variance is primarily due to an increase of 682 GWh, or 2%, in billed electricity usage, including the effect of more favorable weather on residential and commercial sales as compared to the prior year and an increase in industrial usage primarily due to increased consumption by a large industrial customer in the chemicals industry as a result of a prior year plant outage and the addition of new mid-small industrial customers.


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2013 Compared to 2012

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 2013 to 2012.
 
Amount
 
(In Millions)
 
 
2012 net revenue

$933.3

Louisiana Act 55 financing savings obligation
137.6

Retail electric price
91.5

Volume/weather
23.9

Net wholesale revenue
18.1

Fuel recovery
9.4

Other
(5.0
)
2013 net revenue

$1,208.8


The Louisiana Act 55 financing savings obligation variance results from a regulatory charge recorded in the second quarter 2012 because Entergy Louisiana was required to share with customers the savings from the tax treatment related to the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing.  See Note 3 to the financial statements for additional discussion of the tax treatment.

The retail electric price variance is primarily due to a formula rate plan increase effective January 2013. See Note 2 to the financial statements for discussion of the formula rate plan increase.

The volume/weather variance is primarily due to an increase of 512 GWh in billed electricity usage in all sectors due to the effect of more favorable weather as compared to the previous year on residential sales and the effect of Hurricane Isaac, which decreased sales volume in 2012. The increase in industrial usage was also driven by a higher capacity factor in the petroleum industry.

The net wholesale revenue variance is primarily due to the sale to Entergy Gulf States Louisiana of one-third of Acadia Unit 2 capacity and energy.

The fuel recovery variance is primarily due to the expiration of the Evangeline gas contract on January 1, 2013.

Other Income Statement Variances

2014 Compared to 2013

Other operation and maintenance expenses increased primarily due to:

•
a $16 million write-off recorded in 2014 because of the uncertainty associated with the resolution of the Waterford 3 replacement steam generator project prudence review. See Note 2 to the financial statements for further discussion of the prudence review;
•
an increase of $10.5 million due to administration fees related to the participation in the MISO RTO effective December 2013. The LPSC approved deferral of these expenses resulting in no net income effect;
•
an increase of $9.7 million in regulatory, consulting, and legal fees;
•
an increase of $7.9 million in nuclear generation expenses primarily due to higher labor costs, including contract labor, higher materials costs, and higher NRC fees;

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•
an increase of $7.3 million in fossil-fueled generation expenses primarily due to an overall higher scope of work done during plant outages as compared to prior year;
•
an increase of $4.4 million in transmission expenses primarily due to increased transmission equalization expenses and higher vegetation maintenance;
•
an increase of $2.1 million as a result of higher write-offs of uncollectible accounts in 2014;
•
an increase of $1.7 million in distribution vegetation maintenance expenses; and
•
several individually insignificant items.

The increase was partially offset by:

•
a decrease of $24 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan.  See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
•
a decrease of $6.1 million relating to the sale of surplus oil inventory in 2014; and
•
a decrease of $5.9 million due to costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business.

Depreciation and amortization expenses increased primarily due to additions to plant in service.

Other income increased primarily due to:

•
an increase of $9.5 million due to distributions earned on preferred membership interests purchased from Entergy Holdings Company with the proceeds received in August 2014 from the Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;
•
$7.6 million of carrying charges recorded in 2014 on storm restoration costs related to Hurricane Isaac as approved by the LPSC; and
•
the increase in allowance for equity funds used during construction due to a higher construction work in progress balance in 2014, including the Ninemile Unit 6 Self-Build Project.

The increase was partially offset by higher realized gains in 2013 on Waterford 3 decommissioning trust fund investments.

Interest expense increased primarily due to:

•
the issuance of $325 million of 4.05% Series first mortgage bonds in August 2013;
•
the issuance of $170 million of 5.0% Series first mortgage bonds in June 2014; and
•
the issuance of $190 million of 3.78% Series first mortgage bonds in July 2014.

The increase was partially offset by an increase in the allowance for borrowed funds used during construction due to a higher construction work in progress balance in 2014, including the Ninemile Unit 6 Self-Build Project.

2013 Compared to 2012

Nuclear refueling outage expenses increased primarily due to the amortization of higher expenses associated with the refueling outage at Waterford 3.

Other operation and maintenance expenses increased primarily due to:

•
an increase of $20.9 million in compensation and benefits costs primarily due to a decrease in the discount

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rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge, recognized in September 2013, related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
•
an increase of $16.5 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative, substantially offset by the deferral, as approved by the LPSC, of $13 million of these costs. See the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion;
•
an increase of $5.4 million in nuclear generation expenses primarily due to higher labor and materials costs; and
•
the prior year deferral, as approved by the LPSC and the FERC, of costs related to the transition and implementation of joining the MISO RTO, which reduced 2012 expenses by $5.2 million.

The increase was partially offset by a decrease of $9.2 million in fossil-fueled generation expenses due to an overall lower scope of work done during plant outages as compared to the prior year.

Also, other operation and maintenance expenses include $5.9 million in 2013 and $6.7 million in 2012 of costs incurred related to the now terminated plan to spin off and merge the transmission business.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including placing in service the Waterford 3 steam generator project in December 2012.

Interest expense increased primarily due to:

•
the issuance of $200 million of 5.25% Series first mortgage bonds in July 2012;
•
the issuance of $200 million of 3.30% Series first mortgage bonds in December 2012;
•
the issuance of $100 million of 4.70% Series first mortgage bonds in May 2013; and
•
the issuance of $325 million of 4.05% Series first mortgage bonds in August 2013.

Income Taxes

The effective income tax rates for 2014, 2013, and 2012, were 25.3%, 24.5%, and (84.7%), respectively. The effective income tax rate of (84.7%) for 2012 was primarily due to the settlement of the tax treatment of the Louisiana Act 55 financing of the Hurricane Katrina and Hurricane Rita storm costs and the reversal of the provision for the uncertain tax positions related to that item. 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 a discussion of the IRS settlement and audits.


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Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2014, 2013, and 2012 were as follows:
 
2014
 
2013
 
2012
 
(In Thousands)
Cash and cash equivalents at beginning of period

$124,007

 

$30,086

 

$878

 
 
 
 
 
 
Net cash provided by (used in):
 

 
 

 
 

Operating activities
1,126,040

 
662,772

 
447,698

Investing activities
(938,758
)
 
(540,807
)
 
(850,866
)
Financing activities
(153,736
)
 
(28,044
)
 
432,376

Net increase in cash and cash equivalents
33,546

 
93,921

 
29,208

 
 
 
 
 
 
Cash and cash equivalents at end of period

$157,553

 

$124,007

 

$30,086


Operating Activities

Net cash flow provided by operating activities increased $463.3 million in 2014 primarily due to proceeds of $240 million received from the Louisiana Utilities Restoration Corporation as a result of the Louisiana Act 55 storm cost financing, an increase in income tax refunds of $207.8 million, and the timing of collections from customers.  The increase was partially offset by an increase of $33.4 million in pension contributions in 2014 and an increase of $15.6 million in interest paid resulting from an increase in interest expense, as discussed above.  Entergy Louisiana had income tax refunds in 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds are primarily due to favorable adjustments allowed in the IRS Audit of the 2006-2007 tax years and a carryback of a 2008 net operating loss. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Net cash flow provided by operating activities increased $215.1 million in 2013 primarily due to decreased Hurricane Isaac storm spending in 2013 and a decrease of $7.7 million in pension contributions. The increase was partially offset by an increase of $12.4 million in interest paid resulting from the increase in interest expense, as discussed above, and a decrease of $7.8 million in income tax refunds. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Investing Activities

Net cash flow used in investing activities increased $398 million in 2014 primarily due to:
 
•
the investment in 2014 of $227 million in affiliate securities as a result of the Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;
•
the deposit of $200 million into the storm reserve escrow account in 2014;
•
receipts of $187 million from the storm reserve escrow account in 2013;
•
an increase 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

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•
an increase in transmission construction expenditures as a result of additional reliability work performed in 2014.

The increase was partially offset by a decrease in fossil-fueled generation construction expenditures due to lower spending on the Ninemile Unit 6 self-rebuild project and money pool activity.

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 $16 million in 2014 compared to increasing by $8.2 million in 2013.  The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.

Net cash flow used in investing activities decreased $310.1 million in 2013 primarily due to:

•
receipts of $187 million from the storm reserve escrow account in 2013 compared to receipts of $14.5 million in 2012;
•
a decrease in nuclear construction expenditures due to the Waterford 3 steam generator replacement project in 2012;
•
a decrease 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
•
a decrease in distribution construction expenditures due to higher Hurricane Isaac spending in prior year.

The decrease was partially offset by an increase in fossil-fueled generation construction expenditures due to spending on the Ninemile Unit 6 self-build project and an increase in transmission construction expenditures as a result of additional reliability work performed in 2013.

Financing Activities

Net cash used by financing activities increased $125.7 million in 2014 primarily due to the net issuance of $130.7 million of long-term debt in 2014 compared to the net issuance of $386.9 million of long-term debt in 2013, partially offset by borrowings of $43.1 million on the nuclear fuel company variable interest entity’s credit facility in 2014 compared to the repayment of borrowings of $51.7 million in 2013 and a decrease of $35.7 million in common equity distributions in 2014.

Entergy Louisiana’s financing activities used $28 million of cash in 2013 compared to providing $432.4 million of cash in 2012 primarily due to:

•
an increase of $340.7 million in common equity distributions in 2013;
•
the net issuance of $386.9 million of long-term debt in 2013 compared to the net issuance of $613.1 million of long-term debt in 2012; and
•
money pool activity.

Decreases in Entergy Louisiana’s payable to the money pool are a use of cash flow, and Entergy Louisiana’s payable to the money pool decreased by $118.4 million in 2012.

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. The increase in the debt to capital ratio for Entergy Louisiana is primarily due to an increase in long-term debt as a result of the issuance of $190 million of 3.78% Series first mortgage bonds in July 2014.
 
December 31,
2014
 
December 31,
2013
Debt to capital
53.8
%
 
52.0
%
Effect of excluding securitization bonds
(1.0
%)
 
(1.3
%)
Debt to capital, excluding securitization bonds (a)
52.8
%
 
50.7
%
Effect of subtracting cash
(1.3
%)
 
(1.1
%)
Net debt to net capital, excluding securitization bonds (a)
51.5
%
 
49.6
%

(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, preferred stock without sinking fund, 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. Entergy Louisiana 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 evaluation 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.

Uses of Capital

Entergy Louisiana requires capital resources for:

•
construction and other capital investments;
•
debt and preferred equity maturities or retirements;
•
working capital purposes, including the financing of fuel and purchased power costs; and
•
distribution and interest payments.

Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.
 
2015
 
2016
 
2017
 
(In Millions)
Planned construction and capital investment:
 
 
 
 
 
Generation

$225

 

$205

 

$395

Transmission
100

 
90

 
155

Distribution
160

 
185

 
140

Other
30

 
20

 
20

Total

$515

 

$500

 

$710



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Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2015
 
2016-2017
 
2018-2019
 
After 2019
 
Total
 
(In Millions)
Long-term debt (a)

$183

 

$476

 

$580

 

$4,682

 

$5,921

Operating leases

$11

 

$18

 

$11

 

$5

 

$45

Purchase obligations (b)

$682

 

$1,260

 

$1,135

 

$3,623

 

$6,700


(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 $57 million to its pension plans and approximately $9.9 million to other postretirement plans in 2015, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015. 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 $38.1 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 NRC post-Fukushima requirements; environmental compliance spending; transmission projects to enhance reliability, reduce congestion, and enable economic growth; resource planning; generation projects; system improvements; 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, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.

Management provides more information on long-term debt maturities in Note 5 to the financial statements.

As an indirect, majority-owned subsidiary of Entergy Corporation, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly. Entergy Louisiana’s long-term debt indenture contains restrictions on the payment of cash dividends or other distributions on its common and preferred membership interests.

Ninemile Point Unit 6 Self-Build Project

In June 2011, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by Entergy Louisiana’s construction of a combined-cycle gas turbine generating facility (Ninemile 6) at its existing Ninemile Point electric generating station. Ninemile 6 is a nominally-sized 560 MW unit that is expected to cost approximately $655 million to construct when spending is complete, excluding interconnection and transmission upgrades. Entergy Gulf States Louisiana joined in the application, seeking certification of its purchase under a life-of-unit power purchase agreement of up to 25% of the capacity and energy

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generated by Ninemile 6. The Ninemile 6 capacity and energy is allocated 55% to Entergy Louisiana, 25% to Entergy Gulf States Louisiana, and 20% to Entergy New Orleans. In February 2012 the City Council passed a resolution authorizing Entergy New Orleans to purchase 20% of the Ninemile 6 energy and capacity. In March 2012 the LPSC unanimously voted to grant the certifications requested by Entergy Gulf States Louisiana and Entergy Louisiana. Following approval by the LPSC, Entergy Louisiana issued full notice to proceed to the project’s engineering, procurement, and construction contractor.

Under terms approved by the LPSC, non-fuel costs may be recovered through Entergy Louisiana’s formula rate plan beginning in the month after the unit is placed in service. In July 2014, Entergy Louisiana and Entergy Gulf States Louisiana filed an unopposed stipulation with the LPSC that estimates a first year revenue requirement associated with Ninemile 6 and provides a mechanism to update the revenue requirement as the in-service date approaches, which was subsequently approved by the LPSC. In late December 2014, roughly contemporaneous with the unit’s placement in service, a final updated estimated revenue requirement of $51.1 million for Entergy Louisiana was filed. The December 2014 estimate forms the basis of rates implemented effective with the first billing cycle of January 2015. Entergy Louisiana will submit project and cost information to the LPSC in mid-2015 to enable the LPSC to review the prudence of Entergy Louisiana’s management of the project.

New Nuclear Development

Entergy Gulf States Louisiana and Entergy Louisiana have been developing and are preserving a project option for new nuclear generation at River Bend. In the first quarter 2010, Entergy Gulf States Louisiana and Entergy Louisiana each paid for and recognized on its books $24.9 million in costs associated with the development of new nuclear generation at the River Bend site; these costs previously had been recorded on the books of Entergy New Nuclear Utility Development, LLC, a System Energy subsidiary. Entergy Gulf States Louisiana and Entergy Louisiana will share costs going forward on a 50/50 basis, which reflects each company’s current participation level in the project.

In March 2010, Entergy Gulf States Louisiana and Entergy 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 Gulf States Louisiana and Entergy 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 Gulf States Louisiana and Entergy 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 a 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, 2014, Entergy Gulf States Louisiana and Entergy Louisiana each have a regulatory asset of $29.2 million on its balance sheet related to these new nuclear generation development costs.

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 and preferred membership interests prior to maturity, to the extent market conditions and interest and distribution rates are favorable.

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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 or (payables to) the money pool were as follows as of December 31 for each of the following years.
2014
 
2013
 
2012
 
2011
(In Thousands)
$1,649
 
$17,648
 
$9,433
 
($118,415)

See Note 4 to the financial statements for a description of the money pool.

Entergy Louisiana has a credit facility in the amount of $200 million scheduled to expire in March 2019. The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2014, there were no cash borrowings and no letters of credit outstanding under the credit facility. See Note 4 to the financial statements for additional discussion of the credit facility. In addition, Entergy Louisiana entered into an uncommitted letter of credit facility in 2014 as a means to post collateral to support its obligations under MISO.  As of December 31, 2014, a $4.7 million letter of credit was outstanding under Entergy Louisiana’s letter of credit facility.

The Entergy Louisiana nuclear fuel company variable interest entity has a credit facility in the amount of $90 million scheduled to expire in June 2016. As of December 31, 2014, $46.1 million of letters of credit were outstanding under the credit facility to support a like amount of commercial paper issued by the Entergy Louisiana nuclear fuel company variable interest entity. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facility.

Entergy Louisiana obtained authorizations from the FERC through October 2015 for the following:

•
short-term borrowings not to exceed an aggregate amount of $250 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 Entergy Louisiana’s short-term borrowing limits.

In February 2014 the Entergy Louisiana nuclear fuel company variable interest entity issued $40 million of 3.92% Series H Notes due February 2021. The Entergy Louisiana nuclear fuel company variable interest entity used the proceeds to purchase additional nuclear fuel.

In June 2014, Entergy Louisiana issued $170 million of 5% Series first mortgage bonds due July 2044. Entergy Louisiana used the proceeds to pay, prior to maturity, its $70 million 6.4% Series first mortgage bonds due October 2034 and to pay, prior to maturity, its $100 million 6.3% Series first mortgage bonds due September 2035.

In July 2014, Entergy Louisiana issued $190 million of 3.78% Series first mortgage bonds due April 2025. Entergy Louisiana used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes.

In July 2014 the Entergy Louisiana nuclear fuel company variable interest entity redeemed, at maturity, its $50 million of 5.69% Series E Notes.


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In November 2014, Entergy Louisiana issued $250 million of 4.95% Series first mortgage bonds due January 2045. Entergy Louisiana used the proceeds to repay, at maturity, its $250 million of 1.875% Series first mortgage bonds due December 2014.

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 January 2013, Entergy Louisiana drew $187 million from its funded storm reserve escrow account.  In April 2013, Entergy Gulf States Louisiana and Entergy Louisiana filed a joint application with the LPSC relating to Hurricane Isaac system restoration costs.  In May 2013, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55). The LPSC Staff filed direct testimony in September 2013 concluding that Hurricane Isaac system restoration costs incurred by Entergy Gulf States Louisiana and Entergy Louisiana were reasonable and prudent, subject to proposed minor adjustments which totaled approximately 1% of each company’s costs. Following an evidentiary hearing and recommendations by the ALJ, the LPSC voted in June 2014 to approve a series of orders which (i) quantify the amount of Hurricane Isaac system restoration costs prudently incurred ($66.5 million for Entergy Gulf States Louisiana and $224.3 million for Entergy Louisiana); (ii) determine the level of storm reserves to be re-established ($90 million for Entergy Gulf States Louisiana and $200 million for Entergy Louisiana); (iii) authorize Entergy Gulf States Louisiana and Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) grant 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 $23.9 million of customer benefits through annual customer credits of approximately $4.8 million for five years. Approvals for the Act 55 financings were obtained from the Louisiana Utilities Restoration Corporation (LURC) and the Louisiana State Bond Commission.

In July 2014, Entergy Louisiana issued $190 million of 3.78% Series first mortgage bonds due April 2025 and used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes.
In August 2014 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $243.85 million in bonds under Act 55 of the Louisiana Legislature.  From the $240 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $13 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $227 million directly to Entergy Louisiana.  Entergy Louisiana used the $227 million received from the LURC to acquire 2,272,725.89 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 Louisiana does not report the bonds on its balance sheet because the bonds are the obligation of the LCDA and there is no recourse against 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 Louisiana does not report the collections as revenue because it is merely acting as the billing and collection agent for the state.
    
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

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temporarily suspend the repowering project and, based upon an analysis of the project’s economic viability, to make a recommendation regarding whether to proceed with the project. This action was based upon a number of factors including the recent decline in natural gas prices, as well as environmental concerns, the unknown costs of carbon legislation and changes in the capital/financial markets. In April 2009, Entergy Louisiana complied with the LPSC’s directive and recommended that the project be suspended for an extended period of time of three years or more. In May 2009 the LPSC issued an order declaring that Entergy Louisiana’s decision to place the Little Gypsy project into a longer-term suspension of three years or more is in the public interest and prudent.
    
In October 2009, Entergy Louisiana made a filing with the LPSC seeking permission to cancel the Little Gypsy repowering project and seeking project cost recovery over a five-year period. In June 2010 and August 2010, the LPSC Staff and Intervenors filed testimony. The LPSC Staff (1) agreed that it was prudent to move the project from long-term suspension to cancellation and that the timing of the decision to suspend on a longer-term basis was not imprudent; (2) indicated that, except for $0.8 million in compensation-related costs, the costs incurred should be deemed prudent; (3) recommended recovery from customers over ten years but stated that the LPSC may want to consider 15 years; (4) allowed for recovery of carrying costs and earning a return on project costs, but at a reduced rate approximating the cost of debt, while also acknowledging that the LPSC may consider ordering no return; and (5) indicated that Entergy Louisiana should be directed to securitize project costs, if legally feasible and in the public interest. In the third quarter 2010, in accordance with accounting standards, Entergy Louisiana determined that it was probable that the Little Gypsy repowering project would be abandoned and accordingly reclassified $199.8 million of project costs from construction work in progress to a regulatory asset. A hearing on the issues, except for cost allocation among customer classes, was held before the ALJ in November 2010. In January 2011 all parties participated in a mediation on the disputed issues, resulting in a settlement of all disputed issues, including cost recovery and cost allocation. The settlement provides for Entergy Louisiana to recover $200 million as of March 31, 2011, and carrying costs on that amount on specified terms thereafter. The settlement also provides for Entergy Louisiana to recover the approved project costs by securitization. In April 2011, Entergy Louisiana filed an application with the LPSC to authorize the securitization of the investment recovery costs associated with the project and to issue a financing order by which Entergy Louisiana could accomplish such securitization. In August 2011 the LPSC issued an order approving the settlement and also issued a financing order for the securitization. See Note 5 to the financial statements for a discussion of the September 2011 issuance of the securitization bonds.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Louisiana is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approval of the rates charged to customers.

Retail Rates

Filings with the LPSC

In May 2005 the LPSC approved a rate filing settlement that included the adoption of a three-year formula rate plan, the terms of which included an ROE mid-point of 10.25% for the initial three-year term of the plan and permit Entergy Louisiana to recover incremental capacity costs outside of a traditional base rate proceeding. Under the formula rate plan, over- and under-earnings outside an allowed regulatory range of 9.45% to 11.05% will be allocated 60% to customers and 40% to Entergy Louisiana. The initial formula rate plan filing was made in May 2006. As discussed below the formula rate plan has been extended, with return on common equity provisions consistent with previously approved provisions, to cover the 2008, 2009, 2010, and 2011 test years.

In November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s formula rate plan.  In May 2012, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2011 test year.  The filing reflected a 9.63% earned return on common equity, which is within the earnings bandwidth and resulted in no cost of service rate

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change under the formula rate plan.  The filing also reflected an $18.1 million rate increase for the incremental capacity rider.  In August 2012, Entergy Louisiana submitted a revised filing that reflected an earned return on common equity of 10.38%, which is still within the earnings bandwidth, resulting in no cost of service rate change.  The revised filing also indicated that an increase of $15.9 million should be reflected in the incremental capacity rider.  The rate change was implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012.  Subsequently, in December 2012, Entergy Louisiana submitted a revised evaluation report that reflected two items: 1) a $17 million reduction for the first-year capacity charges for the purchase by Entergy Gulf States Louisiana from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy, and 2) an $88 million increase for the first-year retail revenue requirement associated with the Waterford 3 replacement steam generator project, which was in-service in December 2012.  These rate changes were implemented, subject to refund, effective with the first billing cycle of January 2013.  In April 2013, Entergy Louisiana and the LPSC staff filed a joint report resolving the 2011 test year formula rate plan and recovery related to the Grand Gulf uprate. This report was approved by the LPSC in April 2013.

With completion of the Waterford 3 replacement steam generator project, the LPSC is conducting 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. A post-hearing briefing schedule has not been established. Entergy Louisiana believes that the replacement steam generator costs were prudently incurred and applicable legal principles support 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 associated with the resolution of the prudence review.

In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Louisiana, and the required filing was made on February 15, 2013. The filing anticipated Entergy Louisiana’s integration into MISO. In the filing Entergy Louisiana requested, among other relief:

•
authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service);
•
an authorized return on common equity of 10.4%;
•
authorization to increase depreciation rates embedded in the proposed revenue requirement; and
•
authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirements on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

Following a hearing before an ALJ and the ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. The settlement provides for a $10 million rate increase effective with the first billing cycle of December 2014. Major terms of the settlement include approval of a three-year formula rate plan (effective for test years 2014-2016) modeled after the formula rate plan in effect for Entergy Louisiana for 2011, including the following: (1) a midpoint return on equity of 9.95% plus or minus 80 basis points, with 60/40 sharing of earnings outside of the bandwidth; (2) recovery outside of the sharing mechanism for the non-fuel MISO-related costs, additional capacity revenue requirement, extraordinary items, such as the Ninemile 6 project, and certain

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special recovery items; (3) three-year amortization of costs to achieve savings associated with the human capital management strategic imperative, with savings reflected as they are realized in subsequent years; (4) eight-year amortization of costs incurred in connection with potential development of a new nuclear unit at River Bend, without carrying costs, beginning December 2014, provided, however, that amortization of these costs shall not result in a future rate increase; (5) recovery of non-fuel MISO-related costs and any changes to the additional capacity revenue requirement related to test year 2013 effective with the first billing cycle of December 2014; and (6) a cumulative $30 million cap on cost of service increases over the three-year formula rate plan cycle, except for those items outside of the sharing mechanism. Existing depreciation rates will not change.

Pursuant to the rate case settlement approved by the LPSC in December 2013, Entergy Louisiana submitted a compliance filing in May 2014 reflecting the effects of the $10 million agreed-upon increase in formula rate plan revenue, the estimated MISO cost recovery mechanism revenue requirement, and the adjustment of the additional capacity mechanism. In November 2014, Entergy Louisiana submitted an additional compliance filing updating the estimated MISO cost recovery mechanism for the most recent actual data, as well as providing for a refund and prospective reduction in rates for the true-up of the estimated revenue requirement for the Waterford 3 replacement steam generator project. Based on this updated filing, a net increase of $41.7 million in formula rate plan revenue to be collected over nine months was implemented in December 2014. The compliance filings are subject to the review in accordance with the review process set forth in Entergy Louisiana’s formula rate plan. Additionally, the adjustments of rates made related to the Waterford 3 replacement steam generator project included in the December 2014 compliance filing are subject to final true-up following completion of the LPSC’s determination regarding the prudence of the project.

Filings with the City Council

In March 2013, Entergy Louisiana filed a rate case for the Algiers area, which is in New Orleans and is regulated by the City Council. Entergy Louisiana requested a rate increase of $13 million over three years, including a 10.4% return on common equity and a formula rate plan mechanism identical to its LPSC request made in February 2013. In January 2014, the City Council Advisors filed direct testimony recommending a rate increase of $5.56 million over three years, including an 8.13% return on common equity. In June 2014 the City Council unanimously approved a settlement that includes the following:

•
a $9.3 million base rate revenue increase to be phased in on a levelized basis over four years;
•
recovery of an additional $853 thousand annually through a MISO recovery rider; and
•
adoption of a four-year formula rate plan requiring the filing of annual evaluation reports in May of each year, commencing May 2015, with resulting rates being implemented in October of each year. The formula rate plan includes a midpoint target authorized return on common equity of 9.95% with a +/- 40 basis point bandwidth.

The rate increase was effective with bills rendered on and after the first billing cycle of July 2014. Additional compliance filings were made with the Council in October 2014 for approval of the form of certain rate riders, including among others, a Ninemile 6 non-fuel cost recovery interim rider, allowing for contemporaneous recovery of capacity costs related to the commencement of commercial operation of the Ninemile 6 generating unit and a purchased power capacity cost recovery rider. The Ninemile 6 cost recovery interim rider was implemented in December 2014 to collect $915 thousand from Entergy Louisiana customers in the Algiers area.

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.

In April 2010 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 through the fuel adjustment clause by

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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. Two parties intervened in the proceeding. A procedural schedule was established for the identification of issues by the intervenors and for Entergy Louisiana to submit comments regarding the LPSC Staff report and any issues raised by intervenors. One intervenor is seeking further proceedings regarding certain issues it raised in its comments on the LPSC Staff report. Entergy Louisiana has filed responses to both the LPSC Staff report and the issues raised by the intervenor. As required by the procedural schedule, a joint status report was submitted in October 2013 by the parties. A status conference was held in December 2013. Discovery is in progress, but a procedural schedule has not been established.

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 has yet to commence.

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 currently support the provision of service to Entergy Louisiana’s customers in Algiers. The transaction is expected to result in the transfer of net assets of approximately $60 million. The Algiers asset transfer is also subject to regulatory review and approval of the FERC. As discussed previously, Entergy Louisiana also filed an application with the City Council seeking authorization to undertake the Entergy Louisiana and Entergy Gulf States Louisiana business combination. The application provides that if the City Council approves the Algiers asset transfer before the business combination occurs, the City Council may not need to issue a public interest finding regarding the business combination. If the necessary approvals are obtained from the City Council and the FERC, Entergy Louisiana expects to transfer the Algiers assets to Entergy New Orleans in the second half of 2015. In November 2014 the City Council approved a resolution establishing a procedural schedule that provides for a hearing on the joint application in late-May 2015, with a decision to be rendered no later than June 2015.

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. Entergy Louisiana does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Louisiana’s marketing efforts in retaining industrial customers.

Federal Regulation

See “Entergy’s Integration Into the MISO Regional Transmission Organization,” “System Agreement,” and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of these topics.



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Nuclear Matters

Entergy Louisiana owns and, through an affiliate, operates the Waterford 3 nuclear power plant. Entergy Louisiana is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, regulatory requirement changes, including changes resulting from events at other plants, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.

The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system.  The issue is applicable to Waterford 3 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.

After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States.  The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders.  The task force then issued a second report in September 2011.  Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012.  The three orders require U.S. nuclear operators to undertake plant modifications and perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating nuclear plants.  The NRC, with input from the industry, is continuing to determine the specific actions required by the orders. Entergy Louisiana’s estimated capital expenditures for 2015 through 2017 for complying with the NRC orders are included in the planned construction and other capital investments estimates given in “Liquidity and Capital Resources - Uses of Capital” above.
    
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. 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.

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In the fourth quarter 2013, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $39.4 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement costs asset that will be depreciated over the remaining life of the unit.

Unbilled Revenue

As discussed in Note 1 to the financial statements, Entergy Louisiana 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 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.

Qualified Pension and Other Postretirement Benefits

Entergy Louisiana’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms.   See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.  Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
 
Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
 
 
Actuarial Assumption
 
 
Change in
Assumption
 
 
Impact on 2014
Qualified Pension Cost
 
Impact on 2014
Projected Qualified Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$2,235
 
$35,324
Rate of return on plan assets
 
(0.25%)
 
$1,346
 
$—
Rate of increase in compensation
 
0.25%
 
$892
 
$5,860

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 2014
Postretirement Benefit Cost
 
Impact on 2014 Accumulated
Postretirement Benefit
Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$465
 
$6,598
Health care cost trend
 
0.25%
 
$820
 
$5,691

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


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Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis


Costs and Funding

Total qualified pension cost for Entergy Louisiana in 2014 was $30.8 million. Entergy Louisiana anticipates 2015 qualified pension cost to be $45.4 million.  Entergy Louisiana contributed $54.5 million to its pension plans in 2014 and estimates 2015 pension contributions to be approximately $57 million, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015.

Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 2014 were $10.9 million.  Entergy Louisiana expects 2015 postretirement health care and life insurance benefit costs of approximately $12.8 million.  Entergy Louisiana contributed $11.2 million to its other postretirement plans in 2014 and expects to contribute approximately $9.9 million in 2015.

The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans.  The 2014 actuarial study reviewed plan experience from 2010 through 2013.  As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies.  These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of  $70.3 million in the qualified pension benefit obligation and $9.7 million in the accumulated postretirement obligation.  The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $10.5 million and other postretirement cost by approximately $1.2 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.

Federal Healthcare Legislation

See the “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.

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Members of
Entergy Louisiana, LLC and Subsidiaries
Jefferson, Louisiana


We have audited the accompanying consolidated balance sheets of Entergy Louisiana, LLC and Subsidiaries (the “Company”) as of December 31, 2014 and 2013 and the related consolidated income statements, consolidated statements of comprehensive income, consolidated statements of cash flows, and consolidated statements of changes in equity (pages 371 through 376 and applicable items in pages 61 through 234) for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Louisiana, LLC and Subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana
February 26, 2015

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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS
 
 
 
 
 
For the Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$2,825,881

 

$2,626,935

 

$2,149,443

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
679,028

 
570,956

 
360,964

Purchased power
 
895,242

 
850,998

 
728,170

Nuclear refueling outage expenses
 
30,347

 
34,566

 
24,344

Other operation and maintenance
 
514,910

 
480,166

 
449,172

Decommissioning
 
24,649

 
21,612

 
23,406

Taxes other than income taxes
 
75,416

 
74,241

 
69,186

Depreciation and amortization
 
252,690

 
242,787

 
218,140

Other regulatory charges (credits) - net
 
(30,844
)
 
(3,785
)
 
127,050

TOTAL
 
2,441,438

 
2,271,541

 
2,000,432

 
 
 
 
 
 
 
OPERATING INCOME
 
384,443

 
355,394

 
149,011

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
38,807

 
31,544

 
39,610

Interest and investment income
 
94,437

 
91,599

 
84,478

Miscellaneous - net
 
8,458

 
(3,990
)
 
(2,584
)
TOTAL
 
141,702

 
119,153

 
121,504

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
166,750

 
153,529

 
136,967

Allowance for borrowed funds used during construction
 
(20,406
)
 
(13,323
)
 
(18,611
)
TOTAL
 
146,344

 
140,206

 
118,356

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
379,801

 
334,341

 
152,159

 
 
 
 
 
 
 
Income taxes
 
96,270

 
81,877

 
(128,922
)
 
 
 
 
 
 
 
NET INCOME
 
283,531

 
252,464

 
281,081

 
 
 
 
 
 
 
Preferred distribution requirements and other
 
6,969

 
6,950

 
6,950

 
 
 
 
 
 
 
EARNINGS APPLICABLE TO COMMON EQUITY
 

$276,562

 

$245,514

 

$274,131

 
 
 
 
 
 
 
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,
 
 
2014
 
2013
 
2012
 
 
(In Thousands)
 
 
 
 
 
 
 
Net Income
 

$283,531

 

$252,464

 

$281,081

 
 
 
 
 
 
 
Other comprehensive income (loss)
 
 

 
 

 
 

Pension and other postretirement liabilities
 
 

 
 

 
 

(net of tax expense (benefit) of ($10,207), $30,591, and $5,095)
 
(16,241
)
 
36,497

 
(6,625
)
Other comprehensive income (loss)
 
(16,241
)
 
36,497

 
(6,625
)
 
 
 
 
 
 
 
Comprehensive Income
 

$267,290

 

$288,961

 

$274,456

 
 
 
 
 
 
 
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,
 
 
2014
 
2013
 
2012
 
 
(In Thousands)
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$283,531

 

$252,464

 

$281,081

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 
349,947

 
337,333

 
293,774

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
149,282

 
310,964

 
(59,069
)
Changes in working capital:
 
 

 
 

 
 

Receivables
 
60,747

 
(121,118
)
 
43,850

Fuel inventory
 
(7,640
)
 
272

 
336

Accounts payable
 
(22,560
)
 
(29,151
)
 
40,085

Prepaid taxes and taxes accrued
 
185,363

 
(176,566
)
 
(39,275
)
Interest accrued
 
2,300

 
4,808

 
729

Deferred fuel costs
 
20,040

 
56,960

 
(93,103
)
Other working capital accounts
 
(4,562
)
 
41,693

 
(79,771
)
Changes in provisions for estimated losses
 
204,510

 
(188,741
)
 
(16,586
)
Changes in other regulatory assets
 
(213,664
)
 
111,049

 
(116,249
)
Changes in other regulatory liabilities
 
12,837

 
156,446

 
81,259

Changes in pension and other postretirement liabilities
 
172,430

 
(180,601
)
 
80,027

Other
 
(66,521
)
 
86,960

 
30,610

Net cash flow provided by operating activities
 
1,126,040

 
662,772

 
447,698

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(484,638
)
 
(711,470
)
 
(787,075
)
Allowance for equity funds used during construction
 
38,807

 
31,544

 
39,610

Nuclear fuel purchases
 
(131,978
)
 
(51,016
)
 
(159,501
)
Proceeds from the sale of nuclear fuel
 
59,784

 
23,438

 
62,248

Investment in affiliates
 
(227,273
)
 
—

 
—

Payments to storm reserve escrow account
 
(200,053
)
 
—

 
—

Receipts from storm reserve escrow account
 
—

 
187,008

 
14,478

Changes in securitization account
 
1,480

 
(157
)
 
818

Proceeds from nuclear decommissioning trust fund sales
 
43,158

 
109,856

 
27,577

Investment in nuclear decommissioning trust funds
 
(54,044
)
 
(121,773
)
 
(39,374
)
Change in money pool receivable - net
 
15,999

 
(8,215
)
 
(9,433
)
Other
 
—

 
(22
)
 
(214
)
Net cash flow used in investing activities
 
(938,758
)
 
(540,807
)
 
(850,866
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
642,835

 
417,740

 
663,975

Retirement of long-term debt
 
(512,180
)
 
(30,846
)
 
(50,899
)
Change in money pool payable - net
 
—

 
—

 
(118,415
)
Changes in credit borrowings - net
 
43,110

 
(51,734
)
 
(39,735
)
Distributions paid:
 
 

 
 

 
 

Common equity
 
(320,601
)
 
(356,254
)
 
(15,600
)
Preferred membership interests
 
(6,950
)
 
(6,950
)
 
(6,950
)
Other
 
50

 
—

 
—

Net cash flow provided by (used in) financing activities
 
(153,736
)
 
(28,044
)
 
432,376

Net increase in cash and cash equivalents
 
33,546

 
93,921

 
29,208

Cash and cash equivalents at beginning of period
 
124,007

 
30,086

 
878

Cash and cash equivalents at end of period
 

$157,553

 

$124,007

 

$30,086

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 

 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$158,905

 

$143,257

 

$130,934

Income taxes
 

($241,411
)
 

($33,622
)
 

($41,423
)
See Notes to Financial Statements.
 
 

 
 

 
 


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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2014
 
2013
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$431

 

$427

Temporary cash investments
 
157,122

 
123,580

Total cash and cash equivalents
 
157,553

 
124,007

Accounts receivable:
 
 

 
 

Customer
 
124,125

 
144,836

Allowance for doubtful accounts
 
(984
)
 
(965
)
Associated companies
 
48,474

 
87,820

Other
 
9,150

 
21,420

Accrued unbilled revenues
 
88,673

 
93,073

Total accounts receivable
 
269,438

 
346,184

Accumulated deferred income taxes
 
74,558

 
100,022

Fuel inventory
 
30,951

 
23,311

Materials and supplies - at average cost
 
154,295

 
156,487

Deferred nuclear refueling outage costs
 
23,067

 
13,670

Prepaid taxes
 
—

 
184,503

Prepayments and other
 
24,962

 
22,651

TOTAL
 
734,824

 
970,835

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Investment in affiliate preferred membership interests
 
1,034,696

 
807,423

Decommissioning trust funds
 
383,615

 
347,274

Storm reserve escrow account
 
200,053

 
—

Non-utility property - at cost (less accumulated depreciation)
 
214

 
396

TOTAL
 
1,618,578

 
1,155,093

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
9,627,495

 
8,799,393

Property under capital lease
 
334,716

 
331,895

Construction work in progress
 
241,923

 
672,883

Nuclear fuel
 
162,721

 
147,385

TOTAL UTILITY PLANT
 
10,366,855

 
9,951,556

Less - accumulated depreciation and amortization
 
3,942,916

 
3,763,234

UTILITY PLANT - NET
 
6,423,939

 
6,188,322

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Regulatory asset for income taxes - net
 
324,555

 
309,617

Other regulatory assets (includes securitization property of $135,538 as of December 31, 2014 and $156,103 as of December 31, 2013)
 
914,229

 
715,503

Deferred fuel costs
 
67,998

 
67,998

Other
 
45,182

 
43,025

TOTAL
 
1,351,964

 
1,136,143

 
 
 
 
 
TOTAL ASSETS
 

$10,129,305

 

$9,450,393

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2014
 
2013
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Currently maturing long-term debt
 

$19,525

 

$320,231

Short-term borrowings
 
46,033

 
2,923

Accounts payable:
 
 

 
 

Associated companies
 
74,692

 
83,655

Other
 
164,329

 
162,507

Customer deposits
 
93,010

 
90,393

Taxes accrued
 
860

 
—

Accumulated deferred income taxes
 
—

 
338

Interest accrued
 
44,372

 
42,072

Deferred fuel costs
 
50,432

 
30,392

Other
 
48,250

 
46,698

TOTAL
 
541,503

 
779,209

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
1,406,507

 
1,275,584

Accumulated deferred investment tax credits
 
64,771

 
67,347

Other regulatory liabilities
 
546,084

 
533,247

Decommissioning
 
503,734

 
479,086

Accumulated provisions
 
212,243

 
7,733

Pension and other postretirement liabilities
 
530,844

 
358,017

Long-term debt (includes securitization bonds of $143,039 as of December 31, 2014 and $164,965 as of December 31, 2013)
 
3,337,054

 
2,899,285

Other
 
70,141

 
75,233

TOTAL
 
6,671,378

 
5,695,532

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
EQUITY
 
 

 
 

Preferred membership interests without sinking fund
 
100,000

 
100,000

Member’s equity
 
2,842,300

 
2,885,287

Accumulated other comprehensive loss
 
(25,876
)
 
(9,635
)
TOTAL
 
2,916,424

 
2,975,652

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$10,129,305

 

$9,450,393

 
 
 
 
 
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, 2014, 2013, and 2012
 
 
 
 
 
 
 
 
 
Common Equity
 
 
 
Preferred Membership Interests
 
Member’s Equity
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
(In Thousands)
 
 
 
 
 
 
 
 
Balance at December 31, 2011

$100,000

 

$2,504,436

 

($39,507
)
 

$2,564,929

Net income
—

 
281,081

 
—

 
281,081

Additional contribution from parent
—

 
253,661

 
—

 
253,661

Other comprehensive loss
—

 
—

 
(6,625
)
 
(6,625
)
Distributions to parent
—

 
(15,600
)
 
—

 
(15,600
)
Distributions declared on preferred membership interests
—

 
(6,950
)
 
—

 
(6,950
)
Balance at December 31, 2012

$100,000

 

$3,016,628

 

($46,132
)
 

$3,070,496

Net income
—

 
252,464

 
—

 
252,464

Other comprehensive income
—

 
—

 
36,497

 
36,497

Distributions to parent
—

 
(376,855
)
 
—

 
(376,855
)
Distributions declared on preferred membership interests
—

 
(6,950
)
 
—

 
(6,950
)
Balance at December 31, 2013

$100,000

 

$2,885,287

 

($9,635
)
 

$2,975,652

Net income
—

 
283,531

 
—

 
283,531

Other comprehensive loss
—

 
—

 
(16,241
)
 
(16,241
)
Contributions from parent
—

 
1,052

 
—

 
1,052

Distributions to parent
—

 
(320,601
)
 
—

 
(320,601
)
Distributions declared on preferred membership interests
—

 
(6,969
)
 
—

 
(6,969
)
Balance at December 31, 2014

$100,000

 

$2,842,300

 

($25,876
)
 

$2,916,424

 
 
 
 
 
 
 
 
See Notes to Financial Statements.
 

 
 

 
 

 
 



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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$2,825,881

 

$2,626,935

 

$2,149,443

 

$2,508,915

 

$2,538,766

Net Income

$283,531

 

$252,464

 

$281,081

 

$473,923

 

$231,435

Total assets

$10,129,305

 

$9,450,393

 

$9,074,084

 

$8,063,867

 

$7,488,423

Long-term obligations (a)

$3,337,054

 

$2,899,285

 

$2,811,859

 

$2,177,003

 

$1,771,566

 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (excluding currently maturing debt).
 
 
 
 
 
 
 
 
 
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
Electric Operating Revenues:
 

 
 

 
 

 
 

 
 

Residential

$856

 

$839

 

$687

 

$830

 

$840

Commercial
596

 
586

 
482

 
549

 
543

Industrial
981

 
955

 
731

 
867

 
817

Governmental
47

 
46

 
38

 
42

 
42

Total retail

$2,480

 

$2,426

 

$1,938

 

$2,288

 

$2,242

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
256

 
114

 
137

 
137

 
220

Non-associated companies
18

 
3

 
2

 
8

 
5

Other
72

 
84

 
72

 
76

 
72

Total

$2,826

 

$2,627

 

$2,149

 

$2,509

 

$2,539

 
 
 
 
 
 
 
 
 
 
Billed Electric Energy Sales (GWh):
 

 
 

 
 

 
 

 
 

Residential
9,047

 
8,820

 
8,703

 
9,303

 
9,533

Commercial
6,257

 
6,194

 
6,112

 
6,155

 
6,164

Industrial
17,100

 
16,713

 
16,416

 
15,813

 
14,473

Governmental
500

 
495

 
479

 
473

 
479

Total retail
32,904

 
32,222

 
31,710

 
31,744

 
30,649

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
4,450

 
1,844

 
2,156

 
2,145

 
2,860

Non-associated companies
126

 
92

 
65

 
185

 
101

Total
37,480

 
34,158

 
33,931

 
34,074

 
33,610



377
Table of Contents


ENTERGY MISSISSIPPI, INC.

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

2014 Compared to 2013

Net income decreased $7.3 million primarily due to the write-off in 2014 of the regulatory asset associated with new nuclear generation development costs as a result of a joint stipulation entered into with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, in which Entergy Mississippi agreed not to pursue recovery of the costs deferred by an MPSC order in the new nuclear generation docket. See Note 2 to the financial statements for discussion of the new nuclear generation development costs and the joint stipulation. Also contributing to the decrease were higher depreciation and amortization expenses and higher taxes other than income taxes. These decreases were significantly offset by higher net revenue and lower other operation and maintenance expenses.

2013 Compared to 2012

Net income increased $35.4 million primarily due to higher net revenue and a lower effective income tax rate, partially offset by higher other operation and maintenance expenses.

Net Revenue

2014 Compared to 2013

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 2014 to 2013.
 
Amount
 
(In Millions)
 
 
2013 net revenue

$644.4

Retail electric price
39.7

Reserve equalization
11.2

Transmission equalization
1.3

Volume/weather
1.3

Other
3.3

2014 net revenue

$701.2

    
The retail electric price variance is primarily due to a formula rate plan increase, as approved by the MPSC, effective September 2013 and an increase in the storm damage rider, as approved by the MPSC, effective October 2013. The increase in the storm damage rider is offset by other operation and maintenance expenses and has no effect on net income. See Note 2 to the financial statements for a discussion of the formula rate plan and storm damage rider.

The reserve equalization variance is primarily due to an increase in reserve equalization revenue primarily due to the changes in the Entergy System generation mix as a result of Entergy Arkansas’s exit from the System Agreement in December 2013.

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The transmission equalization variance is primarily due to changes in transmission investment equalization billings under the Entergy System Agreement compared to the same period in 2013 primarily as a result of Entergy Arkansas’s exit from the System Agreement in December 2013.

The volume/weather variance is primarily due to an increase of 86 GWh, or 1%, in billed electricity usage, including the effect of more favorable weather on residential sales as compared to the prior year and an increase in industrial. The increase in industrial usage is primarily in the primary metals and pipelines industries.

2013 Compared to 2012

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 2013 to 2012.
 
Amount
 
(In Millions)
 
 
2012 net revenue

$578.0

Retail electric price
55.1

Reserve equalization
8.0

Other
3.3

2013 net revenue

$644.4


The retail electric price variance is primarily due to the recovery of Hinds plant costs through the power management rider, as approved by the MPSC, effective with the first billing cycle of 2013 and a formula rate plan increase effective September 2013. The net income effect of the Hinds plant cost recovery is limited to a portion representing an allowed return on equity on the net plant investment with the remainder offset by the Hinds plant costs in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes.  The increase is partially offset by a temporary increase in 2012 in the storm cost recovery rider, as approved by the MPSC for a five-month period effective August 2012.  This temporary increase in revenues in 2012 was offset by costs included in other operation and maintenance expenses and had no effect on net income. See Note 2 to the financial statements for discussion of the formula rate plan increase.
    
The reserve equalization variance is primarily due to increased reserve equalization revenue resulting from the acquisition of the Hinds plant in November 2012.

Other Income Statement Variances

2014 Compared to 2013

Other operation and maintenance expenses decreased primarily due to:

•
a decrease of $11.6 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
•
a decrease of $7.6 million in fossil-fueled generation expenses primarily due to a lower scope of work done during plant outages in 2014 as compared to the same period in 2013;
•
a decrease of $5.9 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business;

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•
a decrease of $5.1 million in implementation costs, severance costs, and curtailment and special termination benefits related to the human capital management strategic imperative in 2014 as compared to the same period in 2013. See the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion; and
•
a net decrease of $3.8 million related to Baxter Wilson (Unit 1) repairs. The increase in repair costs incurred in 2014 compared to the prior year were offset by expected insurance proceeds and the deferral of repair costs, as approved by the MPSC. See “Baxter Wilson Plant Event” below for further discussion.

The decrease was partially offset by:

•
an increase of $10 million in storm damage accruals, as approved by the MPSC, effective October 2013;
•
an increase of $5.1 million in 2014 as compared to 2013 in administration fees related to participation in the MISO RTO;
•
an increase of $4 million in regulatory, consulting, and legal fees;
•
an increase of $2.3 million in distribution and transmission vegetation maintenance;
•
an increase of $1.3 million due to higher write-offs of uncollectible customer accounts in 2014 as compared to 2013; and
•
several individually insignificant items.

The asset write-off resulted from the $56.2 million ($36.7 million after-tax) write-off in 2014 of the regulatory asset associated with new nuclear generation development costs as a result of a joint stipulation entered into with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, in which Entergy Mississippi agreed not to pursue recovery of the costs deferred by an MPSC order in the new nuclear generation docket. See Note 2 to the financial statements for discussion of the new nuclear generation development costs and the joint stipulation.

Taxes other than income taxes increased primarily due to an increase in ad valorem taxes in 2014 as compared to prior year and an increase in local franchise taxes due to higher revenues.

Depreciation and amortization expenses increased primarily due to additions to plant in service.

2013 Compared to 2012

Other operation and maintenance expenses increased primarily due to:

•
an increase of $30.6 million in fossil-fueled generation expenses resulting from a higher scope of work done during plant outages in 2013 as compared to 2012, the acquisition of the Hinds plant in November 2012, and the Baxter Wilson (Unit 1) unplanned outage in September 2013;
•
an increase of $7.1 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative. See the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion; and
•
an increase of $5.9 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge, recognized in September 2013, related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs.

The increase was partially offset by a temporary increase in 2012 of $17.8 million in storm damage accruals, as approved by the MPSC for a five-month period effective August 2012, and several individually insignificant items.
 
Also, other operation and maintenance expenses include $5.9 million in 2013 and $7.6 million in 2012 of costs incurred related to the now terminated plan to spin off and merge the transmission business.

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Taxes other than income taxes increased primarily due to an increase in ad valorem taxes as a result of a higher assessment in 2013 primarily due to the acquisition of the Hinds plant in November 2012.

Depreciation and amortization expenses increased primarily due to an increase in plant in service, including the acquisition of the Hinds plant in November 2012.

Income Taxes

The effective income tax rates for 2014, 2013, and 2012 were 42.7%, 37.7%, and 55.6%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.

Baxter Wilson Plant Event

On September 11, 2013, Entergy Mississippi’s Baxter Wilson (Unit 1) power plant experienced a significant unplanned outage event.  Entergy Mississippi completed the repairs to the unit in December 2014. As of December 31, 2014, Entergy Mississippi incurred $22.3 million of capital spending and $26.6 million of operation and maintenance expenses to return the unit to service. The damage was covered by Entergy Mississippi’s property insurance policy, subject to a $20 million deductible. As of December 31, 2014, Entergy Mississippi recorded an insurance receivable of $28.2 million for the amount expected to be received from its insurance policy, allocating $12.9 million of the expected insurance proceeds to capital spending and $15.3 million to operation and maintenance expenses. In June 2014, Entergy Mississippi filed a rate case with the MPSC, which includes recovery of the costs associated with Baxter Wilson (Unit 1) repair activities, net of applicable insurance proceeds. In December 2014 the MPSC issued an order that provided for a deferral of $6 million in other operation and maintenance expenses associated with the Baxter Wilson outage and that the regulatory asset should accrue carrying costs, with amortization of the regulatory asset to occur over two years beginning in February 2015, and provided that the capital costs will be reflected in rate base. The final accounting of costs to return the unit to service and insurance proceeds will be addressed in Entergy Mississippi’s next formula rate plan filing.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2014, 2013, and 2012 were as follows:
 
2014
 
2013
 
2012
 
(In Thousands)
Cash and cash equivalents at beginning of period

$31

 

$52,970

 

$16

 
 
 
 
 
 
Net cash provided by (used in):
 

 
 

 
 

Operating activities
303,463

 
219,665

 
202,406

Investing activities
(177,765
)
 
(149,410
)
 
(391,127
)
Financing activities
(64,096
)
 
(123,194
)
 
241,675

Net increase (decrease) in cash and cash equivalents
61,602

 
(52,939
)
 
52,954

 
 
 
 
 
 
Cash and cash equivalents at end of period

$61,633

 

$31

 

$52,970



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Operating Activities

Net cash flow provided by operating activities increased $83.8 million in 2014 primarily due to:

•
increased recovery of fuel costs;
•
the timing of collections of receivables from customers; and
•
System Agreement bandwidth remedy payments of $11.3 million received in the second quarter 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.

The increase was partially offset by:

•
System Agreement bandwidth remedy payments made in September 2014 of $16.4 million as a result of the compliance filing pursuant to the FERC’s orders related to the bandwidth payments/receipts for the 2007 - 2009 period;
•
an increase of $15 million in income tax payments in 2014. Entergy Mississippi had income tax payments in 2014 and 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The 2013 and 2014 payments resulted primarily from the reversal of temporary differences for which Entergy Mississippi had previously claimed a tax deduction; and
•
an increase of $13.7 million in pension contributions in 2014 as compared to 2013.  See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

See Note 2 to the financial statements for a discussion of the System Agreement proceedings.

Net cash flow provided by operating activities increased $17.3 million in 2013 primarily due to the timing of collections of receivables from customers and a $1.5 million decrease in pension contributions in 2013 as compared to 2012. The increase was partially offset by income tax payments of $4.7 million in 2013, as discussed above, as compared to income tax refunds of $0.7 million in 2012. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Investing Activities

Net cash flow used in investing activities increased $28.4 million in 2014 primarily due to money pool activity and an increase in fossil-fueled generation construction expenditures primarily due to a higher scope of work done during plant outages in 2014 and an increase in spending on Baxter Wilson (Unit 1) repairs in 2014. The increase was partially offset by a decrease in transmission construction expenditures as a result of a decrease in reliability work performed in 2014.

Increases in Entergy Mississippi’s receivable from the money pool are a use of cash flow, and Entergy Mississippi’s receivable from the money pool increased by $0.6 million in 2014 compared to decreasing by $16.9 million in 2013.  The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.

Net cash flow used in investing activities decreased $241.7 million in 2013 primarily due to the payment for the purchase of Hinds Energy Facility in November 2012 of approximately $203 million, including adjustments to the purchase price, and money pool activity. See Note 15 to the financial statements for a discussion of the purchase of Hinds Energy Facility.

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 $16.9 million in 2013 compared to increasing by $16.9 million in 2012.

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Financing Activities

Net cash flow used in financing activities decreased $59.1 million in 2014 primarily due to the issuance of $100 million of 3.75% Series first mortgage bonds in March 2014 and the payment, at maturity, of $100 million of 5.15% Series first mortgage bonds in February 2013.

The decrease was partially offset by:

•
the payment, prior to maturity, of $95 million of 4.95% Series first mortgage bonds in April 2014;
•
an increase of $54 million in common stock dividends paid in 2014 as compared to 2013; and
•
money pool activity.

Decreases in Entergy Mississippi’s payable to the money pool are a use of cash flow, and Entergy Mississippi’s payable to the money pool decreased by $3.5 million in 2014 compared to increasing by $3.5 million in 2013.

Entergy Mississippi’s financing activities used $123.2 million of cash in 2013 as compared to providing $241.7 million of cash in 2012 primarily due to the payment, at maturity, of $100 million of 5.15% Series first mortgage bonds in February 2013 and the issuance of $250 million of 3.1% Series first mortgage bonds in December 2012.

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.
 
December 31,
2014
 
December 31,
2013
Debt to capital
51.2
%
 
51.4
%
Effect of subtracting cash
(1.5
%)
 
—
%
Net debt to net capital
49.7
%
 
51.4
%

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 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.

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.


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Following are the amounts of Entergy Mississippi’s planned construction and other capital investments.
 
2015
 
2016
 
2017
 
(In Millions)
Planned construction and capital investment:
 
 
 
 
 
Generation

$35

 

$15

 

$20

Transmission
70

 
115

 
180

Distribution
125

 
115

 
100

Other
25

 
15

 
15

Total

$255

 

$260

 

$315


Following are the amounts of Entergy Mississippi’s existing debt obligations and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2015
 
2016-2017
 
2018-2019
 
After 2019
 
Total
 
(In Millions)
Long-term debt (a)

$52

 

$222

 

$240

 

$1,245

 

$1,759

Capital lease payments

$2

 

$3

 

$1

 

$—

 

$6

Operating leases

$7

 

$9

 

$6

 

$4

 

$26

Purchase obligations (b)

$318

 

$563

 

$496

 

$1,033

 

$2,410


(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 $22.5 million to its pension plans and approximately $535 thousand to its other postretirement plans in 2015, although the 2015 required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015.  See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
 
Also in addition to the contractual obligations, Entergy Mississippi has $13.2 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions.  See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Mississippi includes amounts associated with specific investments such as environmental compliance spending; transmission projects to enhance reliability, reduce congestion, and enable economic growth; resource planning; 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.  Entergy Mississippi’s long-term debt indenture restricts the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock.  As of

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December 31, 2014, Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $68.5 million.

New Nuclear Generation Development Costs

Pursuant to the Mississippi Baseload Act and the Mississippi Public Utilities Act, Entergy Mississippi had been developing and preserving a project option for new nuclear generation at Grand Gulf Nuclear Station.  In October 2010, Entergy Mississippi filed an application with the MPSC requesting that the MPSC determine that it was in the public interest to preserve the option to construct new nuclear generation at Grand Gulf and that the MPSC approve the deferral of Entergy Mississippi’s costs incurred to date and in the future related to this project, including the accrual of AFUDC or similar carrying charges.  In October 2011, Entergy Mississippi and the Mississippi Public Utilities Staff filed with the MPSC a joint stipulation that the MPSC approved in November 2011.  The stipulation stated that there should be a deferral of the $57 million of costs incurred through September 2011 in connection with planning, evaluating, monitoring, and other related generation resource development activities for new nuclear generation at Grand Gulf.  

In October 2014, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed joint stipulations in Entergy Mississippi’s general rate case proceeding, which are discussed below. In consideration of the comprehensive terms for settlement in that rate case proceeding, the Mississippi Public Utilities Staff and Entergy Mississippi agreed that Entergy Mississippi would request consolidation of the new nuclear generation development costs proceeding with the rate case proceeding for hearing purposes and will not further pursue, except as noted below, recovery of the costs deferred by MPSC order in the new nuclear generation development docket. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. After considering the progress of the new nuclear generation costs proceeding in light of the joint stipulation, Entergy Mississippi recorded in 2014 a $56.2 million pre-tax charge to recognize that the regulatory asset associated with new nuclear generation development is no longer probable of recovery. In December 2014 the MPSC issued an order accepting in their entirety the October 2014 stipulations, including the findings and terms of the stipulations regarding new nuclear generation development costs.

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.

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.


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Entergy Mississippi’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
2014
 
2013
 
2012
 
2011
(In Thousands)
$644
 
($3,536)
 
$16,878
 
($1,999)
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 2015. No borrowings were outstanding under the credit facilities as of December 31, 2014.  See Note 4 to the financial statements for additional discussion of the credit facilities. In addition, Entergy Mississippi entered into an uncommitted letter of credit facility in 2013 and an uncommitted letter of credit facility in 2014 as a means to post collateral to support its obligations under MISO. As of December 31, 2014, a $14.4 million letter of credit was outstanding under Entergy Mississippi’s letter of credit facility which was issued in 2014.

Entergy Mississippi obtained authorizations from the FERC through October 2015 for short-term borrowings not to exceed an aggregate amount of $175 million at any time outstanding and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Mississippi’s short-term borrowing limits. Entergy Mississippi has also obtained an order from the FERC authorizing long-term securities issuances through October 2015.

In March 2014, Entergy Mississippi issued $100 million of 3.75% Series first mortgage bonds due July 2024. Entergy Mississippi used the proceeds to pay, prior to maturity, its $95 million of 4.95% Series first mortgage bonds due June 2018 and for general corporate purposes.

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 September 2009, Entergy Mississippi filed with the MPSC proposed modifications to its formula rate plan rider. In March 2010 the MPSC issued an order: (1) providing the opportunity for a reset of Entergy Mississippi’s return on common equity to a point within the formula rate plan bandwidth and eliminating the 50/50 sharing that had been in the plan, (2) modifying the performance measurement process, and (3) replacing the revenue change limit of two percent of revenues, which was subject to a $14.5 million revenue adjustment cap, with a limit of four percent of revenues, although any adjustment above two percent requires a hearing before the MPSC. The MPSC did not approve Entergy Mississippi’s request to use a projected test year for its annual scheduled formula rate plan filing and, therefore, Entergy Mississippi continued to use a historical test year for its annual evaluation reports under the plan.

In March 2012, Entergy Mississippi submitted its formula rate plan filing for the 2011 test year. The filing shows an earned return on common equity of 10.92% for the test year, which is within the earnings bandwidth and results in no change in rates. In February 2013 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provided for no change in rates.

In March 2013, Entergy Mississippi submitted its formula rate plan filing for the 2012 test year. The filing requested a $36.3 million revenue increase to reset Entergy Mississippi’s return on common equity to 10.55%, which is a point within the formula rate plan bandwidth. In June 2013, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation, in which both parties agreed that the MPSC should approve a $22.3 million rate

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increase for Entergy Mississippi which, with other adjustments reflected in the stipulation, would have the effect of resetting Entergy Mississippi’s return on common equity to 10.59% when adjusted for performance under the formula rate plan. In August 2013 the MPSC approved the joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff authorizing the rate increase effective with September 2013 bills.  Additionally, the MPSC authorized Entergy Mississippi to defer approximately $1.2 million in MISO-related implementation costs incurred in 2012 along with other MISO-related implementation costs incurred in 2013.

In June 2014, Entergy Mississippi filed its first general rate case before the MPSC in almost 12 years.  The rate filing laid out Entergy Mississippi’s plans for improving reliability, modernizing the grid, maintaining its workforce, stabilizing rates, utilizing new technologies, and attracting new industry to its service territory.  Entergy Mississippi requested a net increase in revenue of $49 million for bills rendered during calendar year 2015, including $30 million resulting from new depreciation rates to update the estimated service life of assets.  In addition, the filing proposed, among other things: 1) realigning cost recovery of the Attala and Hinds power plant acquisitions from the power management rider to base rates; 2) including certain MISO-related revenues and expenses in the power management rider; 3) power management rider changes that reflect the changes in costs and revenues that will accompany Entergy Mississippi’s withdrawal from participation in the System Agreement; and 4) a formula rate plan forward test year to allow for known changes in expenses and revenues for the rate effective period.  Entergy Mississippi proposed maintaining the current authorized return on common equity of 10.59%. 

In October 2014, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed joint stipulations that addressed the majority of issues in the proceeding. The stipulations provided for:

•
an approximate $16 million net increase in revenues, which reflected an agreed upon 10.07% return on common equity;
•
revision of Entergy Mississippi’s formula rate plan by providing Entergy Mississippi with the ability to reflect known and measurable changes to historical rate base and certain expense amounts; resolving uncertainty around and obviating the need for an additional rate filing in connection with Entergy Mississippi’s withdrawal from participation in the System Agreement; updating depreciation rates; and moving costs associated with the Attala and Hinds generating plants from the power management rider to base rates;
•
recovery of non-fuel MISO-related costs through a separate rider for that purpose;
•
a deferral of $6 million in other operation and maintenance expenses associated with the Baxter Wilson outage and a determination that the regulatory asset should accrue carrying costs, with amortization of the regulatory asset over two years beginning in February 2015, and a provision that the capital costs will be reflected in rate base. See "Baxter Wilson Plant Event" above for further discussion of the Baxter Wilson outage; and
•
consolidation of the new nuclear generation development costs proceeding with the general rate case proceeding for hearing purposes and a determination that Entergy Mississippi would not further pursue, except as noted below, recovery of the costs that were approved for deferral by the MPSC in November 2011. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. See "New Nuclear Generation Development Costs" above for further discussion of the new nuclear generation development costs proceeding and subsequent write-off in 2014 of the regulatory asset related to those costs.

In December 2014 the MPSC issued an order accepting the stipulations in their entirety and approving the revenue adjustments and rate changes effective with February 2015 bills.

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 is still appropriate or can 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

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2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans.

In Entergy Mississippi’s 2014 general rate case, the Mississippi Public Utilities Staff conducted a review of Entergy Mississippi’s proposed changes to its formula rate plan and recommended changes in that proceeding that may be duplicative of the review being conducted simultaneously in the above-described formula rate plan docket. Consequently, the MPSC found in the general rate case order that the changes to Entergy Mississippi's formula rate plan schedule approved in that order are just and reasonable and should remain unchanged by any MPSC action in the above-described formula rate plan docket, but that any provisions of Entergy Mississippi's formula rate plan schedule not specifically addressed in the general rate case order may be reviewed and changed.

Fuel and Purchased Power Cost Recovery

Entergy Mississippi’s rate schedules include an energy cost recovery rider that, effective January 1, 2013, 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 balance of $60.4 million as of March 31, 2014. In May 2014, Entergy Mississippi filed for an interim adjustment under its energy cost recovery rider. The interim adjustment proposed a net energy cost factor designed to collect over a six-month period the under-recovered deferred fuel balance as of March 31, 2014 and also reflected a natural gas price of $4.50 per MMBtu. In May 2014, Entergy Mississippi and the Public Utilities Staff entered into a joint stipulation in which Entergy Mississippi agreed to a revised net energy cost factor that reflected the proposed interim adjustment with a reduction in costs recovered through the energy cost recovery rider associated with the suspension of the DOE nuclear waste storage fee. In June 2014 the MPSC approved the joint stipulation and allowed Entergy Mississippi’s interim adjustment. In November 2014, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider.  Due to lower gas prices and a lower deferred fuel balance, the redetermined annual factor was a decrease from the revised interim net energy cost factor.  In January 2015 the MPSC approved the redetermined annual factor effective January 30, 2015.

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.


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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.  The District Court’s ruling on the motion for judgment on the pleadings is pending.

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 subject to the federal law that allowed federal courts to hear those cases as “mass action” lawsuits. One day later the Attorney General renewed its motion to remand the Entergy case back to state court, citing the U.S. Supreme Court’s decision. The defendant Entergy companies have responded to that motion and the District Court held oral argument on the motion to remand in February 2014. Entergy also has asserted federal question jurisdiction as a basis for the district court having jurisdiction and also has pending the motion for judgment on the pleadings.

Storm Damage Accrual and Storm Cost Recovery

In two orders issued in July 2012 the MPSC temporarily increased Entergy Mississippi’s storm damage provision monthly accrual from $0.75 million to $2 million for bills rendered during the billing months of August 2012 through December 2012, and approved recovery of $14.9 million in prudently incurred storm costs to be amortized over five months, beginning with August 2012 bills.
In August 2012, Hurricane Isaac caused damage to Entergy Mississippi’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. Total restoration costs for the repair and/or replacement of Entergy Mississippi’s electric facilities damaged by Hurricane Isaac were $22 million.
On July 1, 2013, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation, wherein both parties agreed that approximately $32 million in storm restoration costs incurred in 2011 and 2012 were prudently incurred and chargeable to the storm damage provision, while approximately $700,000 in prudently incurred costs were more properly recoverable through the formula rate plan. Entergy Mississippi and the Mississippi Public Utilities Staff also agreed that the storm damage accrual should be increased from $750,000 per month to $1.75 million per month. In September 2013 the MPSC approved the joint stipulation with the increase in the storm damage accrual effective with October 2013 bills. In February 2015, Entergy Mississippi provided notice to the Mississippi Public Utilities Staff that the storm damage accrual would be set to zero effective with the March 2015 billing cycle as a result of Entergy Mississippi's storm damage accrual balance exceeding $15 million as of January 31, 2015, but will return to its current level when the storm damage accrual balance becomes less than $10 million.

Federal Regulation

See “Entergy’s Integration Into the MISO Regional Transmission Organization,” “System Agreement,” and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of these topics.

Nuclear Matters

See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.



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Environmental Risks

Entergy 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.  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.

Unbilled Revenue

As discussed in Note 1 to the financial statements, Entergy Mississippi 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 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.

Qualified Pension and Other Postretirement Benefits

Entergy Mississippi’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms.   See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.  Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected qualified benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
 
 
Actuarial Assumption
 
 
Change in
Assumption
 
 
Impact on 2014
Qualified Pension Cost
 
Impact on 2014
Projected Qualified Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$906
 
$14,873
Rate of return on plan assets
 
(0.25%)
 
$671
 
$—
Rate of increase in compensation
 
0.25%
 
$361
 
$2,205


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Entergy Mississippi, Inc.
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 2014
Postretirement Benefit Cost
 
Impact on 2014 Accumulated
Postretirement Benefit
Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$225
 
$2,925
Health care cost trend
 
0.25%
 
$377
 
$2,531

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 2014 was $10 million. Entergy Mississippi anticipates 2015 qualified pension cost to be $16.4 million. Entergy Mississippi contributed $21.8 million to its qualified pension plans in 2014 and estimates 2015 pension contributions to be approximately $22.5 million, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015.

Total postretirement health care and life insurance benefit income for Entergy Mississippi in 2014 was $982 thousand. Entergy Mississippi expects 2015 postretirement health care and life insurance benefit income of approximately $758 thousand. Entergy Mississippi contributed $8.5 million to its other postretirement plans in 2014 and expects to contribute $535 thousand in 2015.

The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans.  The 2014 actuarial study reviewed plan experience from 2010 through 2013.  As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies.  These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of  $33.5 million in the qualified pension benefit obligation and $4.6 million in the accumulated postretirement obligation.  The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $4.8 million and other postretirement cost by approximately $0.6 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.

Federal Healthcare Legislation

See the “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.

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholders of
Entergy Mississippi, Inc.
Jackson, Mississippi


We have audited the accompanying balance sheets of Entergy Mississippi, Inc. (the “Company”) as of December 31, 2014 and 2013, and the related income statements, statements of cash flows, and statements of changes in common equity (pages 394 through 398 and applicable items in pages 61 through 234) for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Mississippi, Inc. as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana
February 26, 2015


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ENTERGY MISSISSIPPI, INC.
INCOME STATEMENTS
 
 
 
 
 
For the Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$1,524,193

 

$1,334,540

 

$1,120,366

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
325,643

 
328,934

 
227,133

Purchased power
 
493,533

 
375,745

 
320,923

Other operation and maintenance
 
256,339

 
261,832

 
244,722

Asset write-off
 
56,225

 
—

 
—

Taxes other than income taxes
 
87,936

 
83,630

 
75,006

Depreciation and amortization
 
113,903

 
108,714

 
97,768

Other regulatory charges (credits) - net
 
3,854

 
(14,545
)
 
(5,701
)
TOTAL
 
1,337,433

 
1,144,310

 
959,851

 
 
 
 
 
 
 
OPERATING INCOME
 
186,760

 
190,230

 
160,515

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
2,380

 
2,182

 
3,955

Interest and investment income
 
1,055

 
817

 
170

Miscellaneous - net
 
(3,905
)
 
(3,821
)
 
(3,951
)
TOTAL
 
(470
)
 
(822
)
 
174

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
57,002

 
59,031

 
57,345

Allowance for borrowed funds used during construction
 
(1,243
)
 
(1,539
)
 
(2,103
)
TOTAL
 
55,759

 
57,492

 
55,242

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
130,531

 
131,916

 
105,447

 
 
 
 
 
 
 
Income taxes
 
55,710

 
49,757

 
58,679

 
 
 
 
 
 
 
NET INCOME
 
74,821

 
82,159

 
46,768

 
 
 
 
 
 
 
Preferred dividend requirements and other
 
2,828

 
2,828

 
2,828

 
 
 
 
 
 
 
EARNINGS APPLICABLE TO COMMON STOCK
 

$71,993

 

$79,331

 

$43,940

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY MISSISSIPPI, INC.
STATEMENTS OF CASH FLOWS
 
 
 
 
 
For the Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$74,821

 

$82,159

 

$46,768

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation and amortization
 
113,903

 
108,714

 
97,768

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
32,472

 
47,878

 
58,221

Changes in assets and liabilities:
 
 

 
 

 
 

Receivables
 
(27,444
)
 
(31,647
)
 
42,222

Fuel inventory
 
6,163

 
(121
)
 
(6,202
)
Accounts payable
 
(14,618
)
 
38,727

 
(3,796
)
Taxes accrued
 
318

 
920

 
6,791

Interest accrued
 
2,789

 
2,157

 
(3,324
)
Deferred fuel costs
 
40,251

 
(11,567
)
 
(42,331
)
Other working capital accounts
 
17,567

 
(12,820
)
 
(6,859
)
Provisions for estimated losses
 
14,468

 
(146
)
 
(2,469
)
Other regulatory assets
 
(36,875
)
 
87,907

 
(6,501
)
Pension and other postretirement liabilities
 
68,434

 
(94,143
)
 
16,782

Other assets and liabilities
 
11,214

 
1,647

 
5,336

Net cash flow provided by operating activities
 
303,463

 
219,665

 
202,406

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(179,544
)
 
(168,510
)
 
(175,544
)
Allowance for equity funds used during construction
 
2,380

 
2,182

 
3,955

Payment for purchase of plant
 
—

 
—

 
(202,668
)
Change in money pool receivable - net
 
(644
)
 
16,878

 
(16,878
)
Other
 
43

 
40

 
8

Net cash flow used in investing activities
 
(177,765
)
 
(149,410
)
 
(391,127
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
98,668

 
—

 
246,502

Retirement of long-term debt
 
(95,000
)
 
(116,030
)
 
—

Change in money pool payable - net
 
(3,536
)
 
3,536

 
(1,999
)
Dividends paid:
 
 

 
 

 
 

Common stock
 
(61,400
)
 
(7,400
)
 
—

Preferred stock
 
(2,828
)
 
(2,828
)
 
(2,828
)
Other
 
—

 
(472
)
 
—

Net cash flow provided by (used in) financing activities
 
(64,096
)
 
(123,194
)
 
241,675

Net increase (decrease) in cash and cash equivalents
 
61,602

 
(52,939
)
 
52,954

Cash and cash equivalents at beginning of period
 
31

 
52,970

 
16

Cash and cash equivalents at end of period
 

$61,633

 

$31

 

$52,970

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 
 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$51,509

 

$54,120

 

$58,043

Income taxes
 

$19,650

 

$4,657

 

($696
)
See Notes to Financial Statements.
 
 

 
 

 
 


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ENTERGY MISSISSIPPI, INC.
BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2014
 
2013
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$1,223

 

$22

Temporary cash investments
 
60,410

 
9

Total cash and cash equivalents
 
61,633

 
31

Accounts receivable:
 
 

 
 

Customer
 
78,593

 
76,534

Allowance for doubtful accounts
 
(873
)
 
(906
)
Associated companies
 
21,233

 
13,794

Other
 
42,009

 
9,117

Accrued unbilled revenues
 
43,374

 
44,777

Total accounts receivable
 
184,336

 
143,316

Deferred fuel costs
 
—

 
38,057

Accumulated deferred income taxes
 
5,198

 
—

Fuel inventory - at average cost
 
42,736

 
48,899

Materials and supplies - at average cost
 
37,741

 
40,849

Prepayments and other
 
7,315

 
19,813

TOTAL
 
338,959

 
290,965

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Non-utility property - at cost (less accumulated depreciation)
 
4,642

 
4,670

Escrow accounts
 
41,752

 
51,795

TOTAL
 
46,394

 
56,465

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
3,999,918

 
3,875,737

Property under capital lease
 
4,185

 
5,329

Construction work in progress
 
67,514

 
37,316

TOTAL UTILITY PLANT
 
4,071,617

 
3,918,382

Less - accumulated depreciation and amortization
 
1,516,540

 
1,413,484

UTILITY PLANT - NET
 
2,555,077

 
2,504,898

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Regulatory asset for income taxes - net
 
49,306

 
58,716

Other regulatory assets
 
364,747

 
318,462

Other
 
19,121

 
20,819

TOTAL
 
433,174

 
397,997

 
 
 
 
 
TOTAL ASSETS
 

$3,373,604

 

$3,250,325

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY MISSISSIPPI, INC.
BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2014
 
2013
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Accounts payable:
 
 

 
 

Associated companies
 

$49,832

 

$74,144

Other
 
63,300

 
52,129

Customer deposits
 
77,753

 
74,211

Taxes accrued
 
53,565

 
53,247

Accumulated deferred income taxes
 
—

 
15,413

Interest accrued
 
23,172

 
20,383

Deferred fuel costs
 
2,194

 
—

Other
 
17,533

 
19,021

TOTAL
 
287,349

 
308,548

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
800,374

 
746,939

Accumulated deferred investment tax credits
 
6,370

 
8,530

Asset retirement cost liabilities
 
6,786

 
6,401

Accumulated provisions
 
50,142

 
35,674

Pension and other postretirement liabilities
 
135,156

 
66,722

Long-term debt
 
1,058,838

 
1,053,670

Other
 
16,038

 
21,883

TOTAL
 
2,073,704

 
1,939,819

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
Preferred stock without sinking fund
 
50,381

 
50,381

 
 
 
 
 
COMMON EQUITY
 
 

 
 

Common stock, no par value, authorized 12,000,000 shares; issued and outstanding 8,666,357 shares in 2014 and 2013
 
199,326

 
199,326

Capital stock expense and other
 
(690
)
 
(690
)
Retained earnings
 
763,534

 
752,941

TOTAL
 
962,170

 
951,577

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$3,373,604

 

$3,250,325

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 



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ENTERGY MISSISSIPPI, INC.
STATEMENTS OF CHANGES IN COMMON EQUITY
For the Years Ended December 31, 2014, 2013, and 2012
 
 
 
 
 
Common Equity
 
 
 
Common Stock
 
Capital Stock Expense and Other
 
Retained Earnings
 
Total
 
(In Thousands)
 
 
 
 
 
 
 
 
Balance at December 31, 2011

$199,326

 

($690
)
 

$637,070

 

$835,706

Net income
—

 
—

 
46,768

 
46,768

Preferred stock dividends
—

 
—

 
(2,828
)
 
(2,828
)
Balance at December 31, 2012

$199,326

 

($690
)
 

$681,010

 

$879,646

Net income
—

 
—

 
82,159

 
82,159

Common stock dividends
—

 
—

 
(7,400
)
 
(7,400
)
Preferred stock dividends
—

 
—

 
(2,828
)
 
(2,828
)
Balance at December 31, 2013

$199,326

 

($690
)
 

$752,941

 

$951,577

Net income
—

 
—

 
74,821

 
74,821

Common stock dividends
—

 
—

 
(61,400
)
 
(61,400
)
Preferred stock dividends
—

 
—

 
(2,828
)
 
(2,828
)
Balance at December 31, 2014

$199,326

 

($690
)
 

$763,534

 

$962,170

 
 
 
 
 
 
 
 
See Notes to Financial Statements.
 

 
 

 
 

 
 



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ENTERGY MISSISSIPPI, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$1,524,193

 

$1,334,540

 

$1,120,366

 

$1,266,470

 

$1,232,922

Net Income

$74,821

 

$82,159

 

$46,768

 

$108,729

 

$85,377

Total assets

$3,373,604

 

$3,250,325

 

$3,354,027

 

$2,943,394

 

$2,772,778

Long-term obligations (a)

$1,112,161

 

$1,108,236

 

$1,125,229

 

$978,932

 

$806,506

 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and preferred stock without sinking fund.
 
 
 
 
 
 
 
 
 
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
Electric Operating Revenues:
 

 
 

 
 

 
 

 
 

Residential

$585

 

$527

 

$454

 

$490

 

$509

Commercial
481

 
432

 
381

 
401

 
406

Industrial
175

 
156

 
140

 
146

 
145

Governmental
47

 
42

 
37

 
37

 
38

Total retail
1,288

 
1,157

 
1,012

 
1,074

 
1,098

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
153

 
92

 
23

 
104

 
55

Non-associated companies
14

 
24

 
24

 
27

 
33

Other
69

 
62

 
61

 
61

 
47

Total

$1,524

 

$1,335

 

$1,120

 

$1,266

 

$1,233

 
 
 
 
 
 
 
 
 
 
Billed Electric Energy Sales (GWh):
 
 
 

 
 

 
 

 
 

Residential
5,672

 
5,629

 
5,550

 
5,848

 
6,077

Commercial
4,821

 
4,815

 
4,915

 
4,985

 
5,000

Industrial
2,297

 
2,265

 
2,400

 
2,326

 
2,250

Governmental
414

 
409

 
408

 
415

 
416

Total retail
13,204

 
13,118

 
13,273

 
13,574

 
13,743

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
2,657

 
1,543

 
232

 
431

 
268

Non-associated companies
193

 
304

 
265

 
332

 
402

Total
16,054

 
14,965

 
13,770

 
14,337

 
14,413



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ENTERGY NEW ORLEANS, INC.

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

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 currently support the provision of service to Entergy Louisiana’s customers in Algiers. The transaction is expected to result in the transfer of net assets of approximately $60 million. The Algiers asset transfer is also subject to regulatory review and approval of the FERC. Entergy Louisiana also filed an application with the City Council seeking authorization to undertake the Entergy Louisiana and Entergy Gulf States Louisiana business combination. The application provides that if the City Council approves the Algiers asset transfer before the business combination occurs, the City Council may not need to issue a public interest finding regarding the business combination. If the necessary approvals are obtained from the City Council and the FERC, Entergy Louisiana expects to transfer the Algiers assets to Entergy New Orleans in the second half of 2015. In November 2014 the City Council approved a resolution establishing a procedural schedule that provides for a hearing on the joint application in late-May 2015, with a decision to be rendered no later than June 2015.

Results of Operations

Net Income

2014 Compared to 2013

Net income increased $17 million primarily due to higher net revenue and lower other operation and maintenance expenses, partially offset by a higher effective income tax rate.

2013 Compared to 2012

Net income decreased $5.4 million primarily due to higher other operation and maintenance expenses, higher taxes other than income taxes, and higher interest expense, partially offset by higher net revenue and a lower effective income tax rate.

Net Revenue

2014 Compared to 2013

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 2014 to 2013.
 
Amount
 
(In Millions)
 
 
2013 net revenue

$249.2

Volume/weather
4.5

Net gas revenue
3.5

Transmission revenue
1.4

Other
1.5

2014 net revenue

$260.1


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The volume/weather variance is primarily due to an increase of 125 GWh, or 2%, in billed electricity usage, primarily in the residential and commercial sectors, including the effect of favorable weather on residential sales in 2014 as compared to the prior year and a 2% increase in the average number of electric customers.

The net gas revenue variance is primarily due to the effect of favorable weather, primarily in the residential and commercial sectors, in 2014 as compared to the prior year.

The transmission revenue variance is primarily due to changes as a result of participation in the MISO RTO in 2014.

2013 Compared to 2012

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 2013 to 2012.
 
Amount
 
(In Millions)
 
 
2012 net revenue

$237.9

Volume/weather
6.6

Rider revenue
2.7

Net gas revenue
2.6

Retail electric price
(1.9
)
Other
1.3

2013 net revenue

$249.2


The volume/weather variance is primarily due to an increase of 125 GWh, or 3%, in billed electricity usage in the residential and commercial sectors primarily due to the effects of Hurricane Isaac, which decreased sales volume in 2012, and in part to a 2% increase in the average number of both residential and commercial customers.

The rider revenue variance is primarily due to an increase in franchise tax rider revenue as a result of higher retail revenues. There is a corresponding increase in taxes other than income taxes, resulting in no effect on net income.

The net gas revenue variance is primarily due to the effect of more favorable weather, primarily in the residential and commercial sectors, in 2013 as compared to prior year.

The retail electric price variance is primarily due to a formula rate plan decrease effective September 2013. See Note 2 to the financial statements for a discussion of the formula rate plan filing.

Other Income Statement Variances

2014 Compared to 2013

Other operation and maintenance expenses decreased primarily due to:

•
a decrease of $7.7 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;

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•
a decrease of $6.7 million in fossil-fueled generation expenses due to an overall lower scope of work done during plant outages as compared to prior year; and
•
a decrease of $2.4 million in outside regulatory consultant fees.

2013 Compared to 2012

Other operation and maintenance expenses increased primarily due to:

•
an increase of $9 million in fossil-fueled generation expenses due to an overall higher scope of work done during plant outages as compared to prior year;
•
an increase of $4.4 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative. See the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion; and
•
an increase of $3.1 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs.

The increase was partially offset by a decrease of $3 million in loss reserves and a decrease of $1.5 million due to expenses recorded in 2012 related to the Energy Smart Program.

Taxes other than income taxes increased primarily due to an increase in local franchise taxes resulting from higher electric and gas retail revenues as compared to prior year and an increase in ad valorem taxes resulting from higher assessments. Franchise taxes have no effect on net income as these taxes are recovered through the franchise tax rider.

Interest expense increased primarily due to the issuance of $100 million of 3.90% Series first mortgage bonds in June 2013 and the issuance of $30 million of 5.00% Series first mortgage bonds in November 2012, partially offset by the retirement, at maturity, of $70 million of 5.25% Series first mortgage bonds in August 2013.

Income Taxes

The effective income tax rates for 2014, 2013, and 2012 were 30%, 12.2%, and 29.8%, 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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Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2014, 2013, and 2012 were as follows:
 
2014
 
2013
 
2012
 
(In Thousands)
Cash and cash equivalents at beginning of period

$33,489

 

$9,391

 

$9,834

 
 
 
 
 
 
Net cash provided by (used in):
 

 
 

 
 

Operating activities
81,064

 
86,326

 
52,089

Investing activities
(64,514
)
 
(89,666
)
 
(78,040
)
Financing activities
(7,650
)
 
27,438

 
25,508

Net increase (decrease) in cash and cash equivalents
8,900

 
24,098

 
(443
)
 
 
 
 
 
 
Cash and cash equivalents at end of period

$42,389

 

$33,489

 

$9,391


Operating Activities

Net cash flow provided by operating activities decreased $5.3 million in 2014 primarily due to the payment of calendar year 2012 System Agreement bandwidth remedy payments of $15 million to the City of New Orleans in June 2014 for use in the streetlight conversion program, as directed by the City Council, an increase of $6.3 million in pension contributions, and income tax payments of $4.9 million in 2014 compared to income tax refunds of $1.4 million in 2013. The decrease in cash flow was offset by the timing of collections from customers. See “Critical Accountings Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Net cash provided by operating activities increased $34.2 million in 2013 primarily due to the increased recovery of fuel costs and decreased Hurricane Isaac storm spending in 2013, partially offset by a decrease of $11.5 million in income tax refunds. The income tax refunds of $13 million in 2012 resulted primarily from a decrease of previously estimated 2011 taxable income due to the recognition of additional bonus depreciation.

Investing Activities

Net cash flow used in investing activities decreased $25.2 million in 2014 primarily due to:

•
a decrease in fossil-fueled generation construction expenditures primarily due to spending on the Michoud turbine blade replacement projects in 2013;
•
a decrease in transmission construction expenditures as a result of decreased scope of work in 2014; and
•
money pool activity.

The decrease was partially offset by receipts from the storm reserve escrow account of $7.8 million in 2013.

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 $4.3 million in 2014 compared to increasing $1.8 million in 2013.  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 $11.6 million in 2013 primarily due to:

•
money pool activity;
•
an increase in transmission construction expenditures as a result of additional reliability work performed in 2013; and
•
an increase in fossil-fueled generation construction expenditures as a result of increased scope of work in 2013.
 
The increase was partially offset by a decrease in distribution construction expenditures due to higher spending related to Hurricane Isaac in 2012.

Increases in Entergy New Orleans’s receivable from the money pool are a use of cash flow, and Entergy New Orleans’s receivable from the money pool increased $1.8 million in 2013 compared to decreasing $6.2 million in 2012.
        
Financing Activities
    
Entergy New Orleans’s financing activities used $7.7 million of cash in 2014 compared to providing $27.4 million of cash in 2013 primarily due to the issuance of $100 million of 3.9% Series first mortgage bonds in June 2013 and $6 million in common stock dividends paid in 2014, partially offset by the retirement of $70 million of 5.25% Series first mortgage bonds in August 2013.
    
Net cash provided by financing activities increased $1.9 million in 2013 primarily due to the issuance of $100 million of 3.90% Series first mortgage bonds in June 2013 compared to the issuance of $30 million of 5.0% Series first mortgage bonds in November 2012. The increase was substantially offset by the retirement of $70 million of 5.25% Series first mortgage bonds in August 2013.

See Note 5 to the financial statements for more details on long-term debt.

Capital Structure

Entergy New Orleans’s capitalization is balanced between equity and debt as shown in the following table. The decrease in debt to capital ratio is due to an increase in retained earnings.
 
December 31,
2014
 
December 31,
2013
Debt to capital
47.7
%
 
50.0
%
Effect of subtracting cash
(5.2
%)
 
(4.0
%)
Net debt to net capital
42.5
%
 
46.0
%

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 New Orleans 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 New Orleans’s financial condition. Entergy New Orleans 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 evaluation 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.


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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 and preferred stock maturities or retirements; and
•
dividend payments.

Following are the amounts of Entergy New Orleans’s planned construction and other capital investments.
 
2015
 
2016
 
2017
 
(In Millions)
Planned construction and capital investment:
 
 
 
 
 
Generation

$—

 

$—

 

$40

Transmission
15

 
10

 
5

Distribution
35

 
25

 
25

Other
25

 
30

 
25

Total

$75

 

$65

 

$95


Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2015
 
2016-2017
 
2018-2019
 
After 2019
 
Total
 
(In Millions)
Long-term debt (a)

$11

 

$21

 

$21

 

$320

 

$373

Operating leases

$2

 

$4

 

$2

 

$2

 

$10

Purchase obligations (b)

$215

 

$425

 

$397

 

$579

 

$1,616


(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 $10.9 million to its pension plan in 2015, and approximately $3.7 million to other postretirement plans in 2015, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015. 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 $33 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 environmental compliance spending; transmission projects to enhance reliability, reduce congestion, and enable economic growth; resource planning; 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,

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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 Corporation, Entergy New Orleans pays dividends from its earnings at a percentage determined monthly. Entergy New Orleans’s long-term debt indenture contains restrictions on the payment of cash dividends or other distributions on its common and preferred stock.

Sources of Capital

Entergy New Orleans’s sources to meet its capital requirements include:

•
internally generated funds;
•
cash on hand;
•
debt and preferred stock issuances; and
•
bank financing under new or existing facilities.

Entergy New Orleans 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.

Entergy New Orleans’s receivables from the money pool were as follows as of December 31 for each of the following years.
2014
 
2013
 
2012
 
2011
(In Thousands)
$442
 
$4,737
 
$2,923
 
$9,074

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 2015. No borrowings were outstanding under the facility as of December 31, 2014. See Note 4 to the financial statements for additional discussion of the credit facility. In addition, Entergy New Orleans entered into an uncommitted letter of credit facility as a means to post collateral to support its obligations under MISO.  As of December 31, 2014, an $8.1 million letter of credit was outstanding under Entergy New Orleans’s letter of credit facility.

Entergy New Orleans obtained authorization from the FERC through October 2015 for short-term borrowings not to exceed an aggregate amount of $100 million at any time outstanding. 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 by the City Council, and the current authorization extends through July 2016.

Entergy Louisiana’s Ninemile Point Unit 6 Self-Build Project

In June 2011, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by Entergy Louisiana’s construction of a combined-cycle gas turbine generating facility (Ninemile 6) at its existing Ninemile Point electric generating station. Ninemile 6 is a nominally-sized 560 MW unit that is expected to cost approximately $655 million to construct when spending is complete, excluding interconnection and transmission upgrades. Entergy Gulf States Louisiana joined in the application, seeking certification of its purchase under a life-of-unit power purchase agreement of up to 25% of the capacity and energy generated by Ninemile 6. The Ninemile 6 capacity and energy is allocated 55% to Entergy Louisiana, 25% to Entergy Gulf States Louisiana, and 20% to Entergy New Orleans. In February 2012 the City Council passed a resolution authorizing Entergy New Orleans to purchase 20% of the Ninemile 6 energy and capacity. In March 2012 the LPSC

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unanimously voted to grant the certifications requested by Entergy Gulf States Louisiana and Entergy Louisiana. Following approval by the LPSC, Entergy Louisiana issued full notice to proceed to the project’s engineering, procurement, and construction contractor. Under terms approved by the City Council, non-fuel costs associated with Ninemile 6 may be recovered through a special rider for that purpose. The unit was placed in service in December 2014.

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.    

Rate Cases and Formula Rate Plans

In April 2009 the City Council approved a three-year formula rate plan for Entergy New Orleans, with terms including an 11.1% benchmark electric return on common equity (ROE) with a +/-40 basis point bandwidth and a 10.75% benchmark gas ROE with a +/-50 basis point bandwidth.  Earnings outside the bandwidth reset to the midpoint benchmark ROE, with rates changing on a prospective basis depending on whether Entergy New Orleans was over- or under-earning.  The formula rate plan also included a recovery mechanism for City Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure events.

In May 2012, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2011 test year.  Subsequent adjustments agreed upon with the City Council Advisors indicate a $4.9 million electric base revenue increase and a $0.05 million gas base revenue increase as necessary under the formula rate plan.  As part of the original filing, Entergy New Orleans also requested to increase annual funding for its storm reserve by approximately $5.7 million for five years.  On September 26, 2012, Entergy New Orleans made a filing with the City Council that implemented the $4.9 million electric formula rate plan rate increase and the $0.05 million gas formula rate plan rate increase.  The new rates were effective with the first billing cycle in October 2012.  In August 2013 the City Council unanimously approved a settlement of all issues in the formula rate plan proceeding.  Pursuant to the terms of the settlement, Entergy New Orleans implemented an approximately $1.625 million net decrease to the electric rates that were in effect prior to the electric rate increase implemented in October 2012, with no change in gas rates.  Entergy New Orleans refunded to customers approximately $6 million over the four-month period from September 2013 through December 2013 to make the electric rate decrease effective as of the first billing cycle of October 2012.  Entergy New Orleans had previously recorded provisions for the majority of the refund to customers, but recorded an additional $1.1 million provision in second quarter 2013 as a result of the settlement. Entergy New Orleans’s formula rate plan ended with the 2011 test year and has not been extended.  Entergy New Orleans is recovering the costs of its power purchase agreement with Entergy Louisiana for 20% of the capacity and energy of the Ninemile Unit 6 generating station, which commenced operation in December 2014, through a special Ninemile Unit 6 rider.

A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs.  In September 2009 the City Council approved the energy efficiency programs filed by Entergy New Orleans.  The rate settlement provides an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provides 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 October 2013 the City Council approved the extension of the current Energy Smart program through December 2014. The City Council approved the use of $3.5 million of rough production cost equalization funds for program costs. In addition, Entergy New Orleans will be allowed to recover its lost contribution to fixed costs and to earn an incentive for meeting program goals. In January 2015 the City Council approved extending the Energy Smart program through March 2015 and using $1.2 million of rough production cost equalization funds to cover program costs for the extended period. Additionally, the City Council approved funding for the Energy Smart 2 programs from April 2015 through March 2017 using the

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remainder of the approximately $12.4 million of 2014 rough production cost equalization funds, and with any remaining costs being recovered through the fuel adjustment clause.

Storm Cost Recovery

In October 2006, the City Council approved a rate filing settlement agreement that, among other things, authorized a $75 million storm reserve for damage from future storms, which will be created over a ten-year period through a storm reserve rider that began in March 2007. These storm reserve funds are held in a restricted escrow account until needed in response to a storm.

In August 2012, Hurricane Isaac caused extensive damage to Entergy New Orleans’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. Total restoration costs for the repair and/or replacement of Entergy New Orleans’s electric facilities damaged by Hurricane Isaac were $47.3 million. Entergy New Orleans withdrew $17.4 million from the storm reserve escrow account to partially offset these costs. In February 2014, Entergy New Orleans made a filing with the City Council seeking certification of the Hurricane Isaac costs. 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, remains recoverable from Entergy New Orleans’s electric customers. The resolution also directs Entergy New Orleans to file an application to securitize the unrecovered 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 is 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 achieves the 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.

Federal Regulation

See “Entergy’s Integration Into the MISO Regional Transmission Organization,” “System Agreement,” and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of these topics.
 
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.  Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.


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Critical Accounting Estimates

The preparation of Entergy 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.

Unbilled Revenue

As discussed in Note 1 to the financial statements, Entergy New Orleans 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 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, in addition to changes in certain components of the calculation.

Qualified Pension and Other Postretirement Benefits

Entergy New Orleans’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms.  See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.  Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
 
 
Actuarial Assumption
 
 
Change in
Assumption
 
 
Impact on 2014
Qualified Pension Cost
 
Impact on 2014
Projected Qualified Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$451
 
$7,348
Rate of return on plan assets
 
(0.25%)
 
$295
 
$—
Rate of increase in compensation
 
0.25%
 
$175
 
$1,092


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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 2014
Postretirement Benefit Cost
 
Impact on 2014 Accumulated
Postretirement Benefit
Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$79
 
$1,813
Health care cost trend
 
0.25%
 
$210
 
$1,537

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 2014 was $6.6 million. Entergy New Orleans anticipates 2015 qualified pension cost to be $9 million.  Entergy New Orleans contributed $10.5 million to its pension plans in 2014 and estimates 2015 pension contributions to be approximately $10.9 million, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015.

Total postretirement health care and life insurance benefit income for Entergy New Orleans in 2014 was $1.5 million.   Entergy New Orleans expects 2015 postretirement health care and life insurance benefit income of approximately $1.6 million. Entergy New Orleans contributed $4.3 million to its other postretirement plans in 2014 and expects to contribute $3.7 million in 2015.

The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans.  The 2014 actuarial study reviewed plan experience from 2010 through 2013.  As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies.  These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of  $15 million in the qualified pension benefit obligation and $3.6 million in the accumulated postretirement obligation.  The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $2.2 million and other postretirement cost by approximately $0.4 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.

Federal Healthcare Legislation

See the “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.

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholders of
Entergy New Orleans, Inc.
New Orleans, Louisiana


We have audited the accompanying balance sheets of Entergy New Orleans, Inc. (the “Company”) as of December 31, 2014 and 2013, and the related income statements, statements of cash flows, and statements of changes in common equity (pages 412 through 416 and applicable items in pages 61 through 234) for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy New Orleans, Inc. as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana
February 26, 2015


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ENTERGY NEW ORLEANS, INC.
INCOME STATEMENTS
 
 
 
 
 
For the Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$579,981

 

$525,041

 

$487,633

Natural gas
 
110,104

 
95,115

 
82,107

TOTAL
 
690,085

 
620,156

 
569,740

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
169,605

 
116,715

 
107,616

Purchased power
 
259,680

 
253,202

 
222,193

Other operation and maintenance
 
120,610

 
136,003

 
122,143

Taxes other than income taxes
 
48,142

 
48,659

 
43,189

Depreciation and amortization
 
38,884

 
37,717

 
36,726

Other regulatory charges - net
 
694

 
996

 
1,983

TOTAL
 
637,615

 
593,292

 
533,850

 
 
 
 
 
 
 
OPERATING INCOME
 
52,470

 
26,864

 
35,890

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
915

 
920

 
791

Interest and investment income
 
79

 
89

 
47

Miscellaneous - net
 
430

 
(1,401
)
 
(1,453
)
TOTAL
 
1,424

 
(392
)
 
(615
)
 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
13,310

 
13,675

 
11,344

Allowance for borrowed funds used during construction
 
(447
)
 
(505
)
 
(374
)
TOTAL
 
12,863

 
13,170

 
10,970

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
41,031

 
13,302

 
24,305

 
 
 
 
 
 
 
Income taxes
 
12,324

 
1,619

 
7,240

 
 
 
 
 
 
 
NET INCOME
 
28,707

 
11,683

 
17,065

 
 
 
 
 
 
 
Preferred dividend requirements and other
 
965

 
965

 
965

 
 
 
 
 
 
 
EARNINGS APPLICABLE TO COMMON STOCK
 

$27,742

 

$10,718

 

$16,100

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY NEW ORLEANS, INC.
STATEMENTS OF CASH FLOWS
 
 
 
 
 
For the Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(In Thousands)
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$28,707

 

$11,683

 

$17,065

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation and amortization
 
38,884

 
37,717

 
36,726

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
24,388

 
(7,427
)
 
15,016

Changes in assets and liabilities:
 
 

 
 

 
 

Receivables
 
20,506

 
(6,508
)
 
(29,046
)
Fuel inventory
 
(17
)
 
(1,222
)
 
2,029

Accounts payable
 
(7,702
)
 
5,987

 
4,828

Interest accrued
 
(60
)
 
578

 
180

Deferred fuel costs
 
5,252

 
20,988

 
(9,464
)
Other working capital accounts
 
(18,050
)
 
3,155

 
12,862

Provisions for estimated losses
 
10,877

 
(31
)
 
(812
)
Other regulatory assets
 
(38,405
)
 
64,810

 
(23,188
)
Pension and other postretirement liabilities
 
29,942

 
(51,293
)
 
9,773

Other assets and liabilities
 
(13,258
)
 
7,889

 
16,120

Net cash flow provided by operating activities
 
81,064

 
86,326

 
52,089

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(62,199
)
 
(88,864
)
 
(86,373
)
Allowance for equity funds used during construction
 
915

 
920

 
791

Change in money pool receivable - net
 
4,295

 
(1,814
)
 
6,151

Payments to storm reserve escrow account
 
(7,525
)
 
(7,663
)
 
(8,609
)
Receipts from storm reserve escrow account
 
—

 
7,755

 
10,000

Net cash flow used in investing activities
 
(64,514
)
 
(89,666
)
 
(78,040
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
—

 
98,471

 
28,422

Retirement of long-term debt
 
—

 
(70,068
)
 
—

Dividends paid:
 
 

 
 

 
 

Common stock
 
(6,000
)
 
—

 
(1,700
)
Preferred stock
 
(965
)
 
(965
)
 
(965
)
Other
 
(685
)
 
—

 
(249
)
Net cash flow provided by (used in) financing activities
 
(7,650
)
 
27,438

 
25,508

Net increase (decrease) in cash and cash equivalents
 
8,900

 
24,098

 
(443
)
Cash and cash equivalents at beginning of period
 
33,489

 
9,391

 
9,834

Cash and cash equivalents at end of period
 

$42,389

 

$33,489

 

$9,391

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 

 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$12,477

 

$12,050

 

$10,183

Income taxes
 

$4,871

 

($1,448
)
 

($12,952
)
See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY NEW ORLEANS, INC.
BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2014
 
2013
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents
 
 
 
 
Cash
 

$1,006

 

$317

Temporary cash investments
 
41,383

 
33,172

Total cash and cash equivalents
 
42,389

 
33,489

Accounts receivable:
 
 

 
 

Customer
 
35,663

 
38,872

Allowance for doubtful accounts
 
(262
)
 
(974
)
Associated companies
 
11,693

 
32,273

Other
 
3,223

 
2,667

Accrued unbilled revenues
 
16,465

 
18,745

Total accounts receivable
 
66,782

 
91,583

Accumulated deferred income taxes
 
8,562

 
12,018

Fuel inventory - at average cost
 
3,016

 
2,999

Materials and supplies - at average cost
 
12,650

 
11,696

Prepayments and other
 
6,887

 
4,178

TOTAL
 
140,286

 
155,963

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Non-utility property at cost (less accumulated depreciation)
 
1,016

 
1,016

Storm reserve escrow account
 
18,038

 
10,513

TOTAL
 
19,054

 
11,529

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
936,862

 
889,629

Natural gas
 
228,979

 
222,463

Construction work in progress
 
18,866

 
29,312

TOTAL UTILITY PLANT
 
1,184,707

 
1,141,404

Less - accumulated depreciation and amortization
 
594,945

 
566,948

UTILITY PLANT - NET
 
589,762

 
574,456

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Deferred fuel costs
 
4,080

 
4,080

Other regulatory assets
 
175,596

 
137,191

Other
 
5,345

 
5,577

TOTAL
 
185,021

 
146,848

 
 
 
 
 
TOTAL ASSETS
 

$934,123

 

$888,796

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY NEW ORLEANS, INC.
BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
December 31,
 
 
2014
 
2013
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Accounts payable:
 
 

 
 

Associated companies
 

$33,170

 

$36,193

Other
 
22,435

 
27,840

Customer deposits
 
24,681

 
22,959

Interest accrued
 
3,538

 
3,598

Deferred fuel costs
 
28,397

 
23,145

System agreement cost equalization
 
—

 
17,040

Other
 
6,830

 
5,896

TOTAL CURRENT LIABILITIES
 
119,051

 
136,671

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
199,241

 
183,636

Accumulated deferred investment tax credits
 
864

 
1,082

Regulatory liability for income taxes - net
 
20,640

 
28,711

Asset retirement cost liabilities
 
2,511

 
2,347

Accumulated provisions
 
25,877

 
15,000

Pension and other postretirement liabilities
 
62,440

 
32,497

Long-term debt
 
225,866

 
225,944

Gas system rebuild insurance proceeds
 
23,218

 
32,760

Other
 
6,610

 
4,085

TOTAL NON-CURRENT LIABILITIES
 
567,267

 
526,062

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
Preferred stock without sinking fund
 
19,780

 
19,780

 
 
 
 
 
COMMON EQUITY
 
 

 
 

Common stock, $4 par value, authorized 10,000,000 shares; issued and outstanding 8,435,900 shares in 2014 and 2013
 
33,744

 
33,744

Paid-in capital
 
36,294

 
36,294

Retained earnings
 
157,987

 
136,245

TOTAL
 
228,025

 
206,283

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$934,123

 

$888,796

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 



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ENTERGY NEW ORLEANS, INC.
STATEMENTS OF CHANGES IN COMMON EQUITY
For the Years Ended December 31, 2014, 2013, and 2012
 
 
 
 
 
Common Equity
 
 
 
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Total
 
(In Thousands)
 
 
 
 
 
 
 
 
Balance at December 31, 2011

$33,744

 

$36,294

 

$111,127

 

$181,165

Net income
—

 
—

 
17,065

 
17,065

Common stock dividends
—

 
—

 
(1,700
)
 
(1,700
)
Preferred stock dividends
—

 
—

 
(965
)
 
(965
)
Balance at December 31, 2012

$33,744

 

$36,294

 

$125,527

 

$195,565

Net income
—

 
—

 
11,683

 
11,683

Preferred stock dividends
—

 
—

 
(965
)
 
(965
)
Balance at December 31, 2013

$33,744

 

$36,294

 

$136,245

 

$206,283

Net income
—

 
—

 
28,707

 
28,707

Common stock dividends
—

 
—

 
(6,000
)
 
(6,000
)
Preferred stock dividends
—

 
—

 
(965
)
 
(965
)
Balance at December 31, 2014

$33,744

 

$36,294

 

$157,987

 

$228,025

 
 
 
 
 
 
 
 
See Notes to Financial Statements.
 

 
 

 
 

 
 



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ENTERGY NEW ORLEANS, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$690,085

 

$620,156

 

$569,740

 

$630,185

 

$659,449

Net Income

$28,707

 

$11,683

 

$17,065

 

$35,976

 

$31,114

Total assets

$934,123

 

$888,796

 

$881,789

 

$806,035

 

$850,076

Long-term obligations (a)

$245,646

 

$245,724

 

$146,080

 

$186,317

 

$186,995

 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund.
 
 
 
 
 
 
 
 
 
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
Electric Operating Revenues:
 

 
 

 
 

 
 

 
 

Residential

$202

 

$197

 

$174

 

$176

 

$196

Commercial
184

 
183

 
164

 
154

 
174

Industrial
33

 
35

 
31

 
30

 
36

Governmental
66

 
67

 
63

 
59

 
70

Total retail
485

 
482

 
432

 
419

 
476

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
77

 
27

 
44

 
95

 
56

Non-associated companies
4

 
—

 
—

 
1

 
1

Other
14

 
16

 
12

 
14

 
10

Total

$580

 

$525

 

$488

 

$529

 

$543

 
 
 
 
 
 
 
 
 
 
Billed Electric Energy Sales (GWh):
 
 
 

 
 

 
 

 
 

Residential
1,963

 
1,867

 
1,772

 
1,888

 
1,858

Commercial
2,046

 
1,998

 
1,968

 
1,939

 
1,899

Industrial
452

 
481

 
484

 
498

 
503

Governmental
768

 
758

 
785

 
795

 
809

Total retail
5,229

 
5,104

 
5,009

 
5,120

 
5,069

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
1,322

 
495

 
978

 
1,167

 
906

Non-associated companies
16

 
13

 
8

 
19

 
13

Total
6,567

 
5,612

 
5,995

 
6,306

 
5,988



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ENTERGY TEXAS, INC. AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

2014 Compared to 2013

Net income increased $16.9 million primarily due to higher net revenue and lower other operation and maintenance expenses, partially offset by a higher effective income tax rate, higher taxes other than income taxes, and higher depreciation and amortization expenses.

2013 Compared to 2012

Net income increased $15.9 million primarily due to higher net revenue and a lower effective income tax rate, partially offset by higher other operation and maintenance expenses and higher depreciation and amortization expenses.

Net Revenue

2014 Compared to 2013

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 2014 to 2013.
 
Amount
 
(In Millions)
 
 

2013 net revenue

$586.5

Purchased power capacity
37.5

Retail electric price
17.3

Volume/weather
11.6

Transmission revenue
(7.6
)
Reserve equalization
(18.0
)
Net wholesale revenue
(21.0
)
Other
5.4

2014 net revenue

$611.7


The purchased power capacity variance is primarily due to a decrease in expenses due to contract changes.

The retail electric price variance is primarily due to an annual base rate increase of $18.5 million, effective April 2014, as a result of the PUCT’s order in the September 2013 rate case. See Note 2 to the financial statements for further discussion of the PUCT rate order.

The volume/weather variance is primarily due to an increase of 884 GWh, or 5%, in billed electricity usage, including the effect of more favorable weather on residential sales and increased industrial usage primarily in the petroleum industry as a result of expansions.


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The transmission revenue variance is primarily due to changes as a result of the participation in the MISO RTO in 2014.

The reserve equalization variance is primarily due to an increase in reserve equalization expense as compared to the same period in 2013 primarily due to the changes in the Entergy System generation mix compared to the same period in 2013 as a result of the Entergy Arkansas’s exit from the System Agreement in December 2013.
        
The net wholesale revenue variance is primarily due to a wholesale customer contract termination in December 2013.

2013 Compared to 2012

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 2013 to 2012.
 
Amount
 
(In Millions)
 
 

2012 net revenue

$551.0

Volume/weather
13.9

Retail electric price
13.3

Fuel recovery
6.5

Hurricane Rita regulatory asset adjustment
6.4

Net wholesale revenue
4.7

Purchased power capacity
(10.5
)
Other
1.2

2013 net revenue

$586.5


The volume/weather variance is primarily due to an increase of 470 GWh, or 3%, in billed electricity usage, including the effect of more favorable weather compared to last year on residential sales and increased usage in the industrial sector compared to prior year as a result of an unplanned outage in the refining industry in 2012.

The retail electric price variance is primarily due to an annual base rate increase of $28 million, effective July 2012, as a result of the PUCT’s order in the November 2011 rate case. See Note 2 to the financial statements for further discussion of the PUCT rate order.

The fuel recovery variance is primarily the result of a $6 million adjustment to deferred fuel costs recorded in third quarter 2012 in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT order issued in Entergy Texas’s 2011 rate case.

The Hurricane Rita regulatory asset adjustment of $6.4 million was recorded in third quarter 2012 in accordance with the rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order.

The net wholesale revenue variance is primarily due to contract changes for municipals and co-op customers.

The purchased power capacity variance is primarily due to additional capacity purchases as well as price increases for ongoing purchased power capacity.


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Other Income Statement Variances

2014 Compared to 2013

Other operation and maintenance expenses decreased primarily due to:

•
an decrease of $14.9 million in compensation and benefit costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, and a settlement charge in 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
•
a decrease of $7.4 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business; and
•
a decrease of $7.1 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative. See the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.

The decrease was partially offset by an increase of $5.9 million primarily due to administration fees in 2014 related to participation in the MISO RTO.

Taxes other than income taxes increased primarily due to a reduction in the provision recorded for sales and use taxes in 2013, an increase in local franchise taxes, and an increase in ad valorem taxes. Franchise taxes have no effect on net income as these taxes are recovered through the franchise tax rider.

Depreciation and amortization expenses increased primarily due to additions to plant in service.

2013 Compared to 2012

Other operation and maintenance expenses increased primarily due to:

•
an increase of $9 million in compensation and benefit costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs and a settlement charge, recognized in September 2013, related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
•
an increase of $8.8 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative. See the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion;
•
an increase of $2.3 million primarily due to storm damage accruals in accordance with a rate order from PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order;
•
an increase of $1.7 million in distribution contract work relating primarily to vegetation maintenance; and
•
an increase of $1.4 million in insurance expenses primarily due to increases in premiums.

The increase was partially offset by:

•
the amortization of $4.3 million of Hurricane Rita storm costs in prior year in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order; and
•
a decrease of $2.7 million in fossil-fueled expenses due to a reduced scope of work and fewer outages compared to 2012.


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Also, other operation and maintenance expenses include $7.4 million in 2013 and $4.8 million in 2012 of costs incurred related to the now-terminated plan to spin off and merge the transmission business.

Taxes other than income taxes increased primarily due to a reduction in the provision recorded for sales and use taxes in 2012.    

Depreciation and amortization expenses increased primarily due to additions to plant in service and an increase in depreciation rates as a result of the 2011 rate case order issued by the PUCT in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order.

Other income increased primarily due to the reversal in 2012 of $6.7 million of disallowed carrying charges on Hurricane Rita storm restoration costs in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order.

Income Taxes

The effective income tax rates were 39.9%, 34.2%, and 44.1% for 2014, 2013, and 2012, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2014, 2013, and 2012 were as follows:
 
2014
 
2013
 
2012
 
(In Thousands)
Cash and cash equivalents at beginning of period

$46,488

 

$60,236

 

$65,289

 
 
 
 
 
 
Net cash provided by (used in):
 

 
 

 
 

Operating activities
315,164

 
237,054

 
271,081

Investing activities
(186,540
)
 
(164,309
)
 
(128,904
)
Financing activities
(144,671
)
 
(86,493
)
 
(147,230
)
Net decrease in cash and cash equivalents
(16,047
)
 
(13,748
)
 
(5,053
)
 
 
 
 
 
 
Cash and cash equivalents at end of period

$30,441

 

$46,488

 

$60,236


Operating Activities

Net cash flow provided by operating activities increased $78.1 million in 2014 primarily due to:

•
$86.1 million of fuel cost refunds in 2013;
•
System Agreement bandwidth remedy payments of $48.6 million received in the second quarter 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. Entergy Texas received approval to apply a portion of the payments to the under-collected fuel balance. The remaining balance of $24.6 million was refunded to Entergy Texas customers as of December 31, 2014; and
•
the timing of collections from customers.

See Note 2 to the financial statements for a discussion of fuel cost refunds and the System Agreement proceedings.

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Management’s Financial Discussion and Analysis


The increase was partially offset by:

•
a decrease of $54.8 million in income tax refunds in 2014 compared to 2013. Entergy Texas had income tax refunds in 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds in 2013 resulted from the utilization of Entergy Texas’s taxable losses against taxable income of other members of the Entergy consolidated group; and
•
an increase of $10.2 million in pension contributions in 2014.  See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Net cash flow provided by operating activities decreased $34 million in 2013 primarily due to:

•
the receipt, in January 2012, of $43 million in System Agreement bandwidth remedy payments required to implement the FERC’s remedy in an October 2011 order for the period June-December 2005. As of March 31, 2013, all of the $43 million, plus interest, had been credited to Entergy Texas customers, with the final $9.5 million being credited in the first quarter 2013. See Note 2 to the financial statements for a discussion of the System Agreement proceedings;
•
$86.1 million of fuel cost refunds in 2013, compared to $67.2 million of fuel cost refunds in 2012. See Note 2 to the financial statements for discussion of the fuel cost refunds; and
•
the timing of collections of receivables from customers.

The decrease was partially offset by an increase of $55.3 million in income tax refunds. Entergy Texas had income tax refunds in 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds resulted from the utilization of Entergy Texas’s taxable losses against taxable income of other members of the Entergy consolidated group.

Investing Activities

Net cash used in investing activities increased $22.2 million in 2014 primarily due to an increase in transmission construction expenditures and an increase in fossil-fueled generation construction expenditures due to a greater scope of projects in 2014 and money pool activity.

Decreases in Entergy Texas’s receivable from the money pool are a source of cash flow, and Entergy Texas’s receivable from the money pool decreased by $6 million in 2014 compared to decreasing by $12.9 million in 2013. The money pool is an inter-company borrowing arrangement designed to reduce Entergy’s subsidiaries’ need for external short-term borrowings.

Net cash used in investing activities increased $35.4 million in 2013 primarily due to:

•
money pool activity;
•
an increase in transmission construction expenditures due to reliability work performed in 2013; and
•
an increase in distribution construction expenditures due to an increased scope of work in 2013.

The increase was partially offset by lower fossil-fueled generation construction expenditures due to a greater scope of projects in 2012.

Decreases in Entergy Texas’s receivable from the money pool are a source of cash flow, and Entergy Texas’s receivable from the money pool decreased by $12.9 million in 2013 compared to decreasing by $44 million in 2012.

Financing Activities

Net cash flow used in financing activities increased $58.2 million in 2014 primarily due to the retirement of $150 million of 7.875% Series first mortgage bonds in June 2014 and an increase of $45 million in common stock

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dividends paid, partially offset by the issuance of $135 million of 5.625% Series first mortgage bonds in May 2014. See Note 5 to the financial statements for more details on long-term debt.

Net cash flow used in financing activities decreased $60.7 million in 2013 primarily due to a decrease of $62.2 million in common stock dividends paid.

Capital Structure

Entergy Texas’s capitalization is balanced between equity and debt, as shown in the following table.
 
December 31,
2014
 
December 31,
2013
Debt to capital
62.4
%
 
63.7
%
Effect of excluding the securitization bonds
(11.8
%)
 
(12.6
%)
Debt to capital, excluding securitization bonds (a)
50.6
%
 
51.1
%
Effect of subtracting cash
(0.9
%)
 
(1.3
%)
Net debt to net capital, excluding securitization bonds (a)
49.7
%
 
49.8
%

(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.

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.

Following are the amounts of Entergy Texas’s planned construction and other capital investments.
 
2015
 
2016
 
2017
 
(In Millions)
Planned construction and capital investment:
 
 
 
 
 
Generation

$275

 

$45

 

$100

Transmission
140

 
165

 
85

Distribution
105

 
95

 
95

Other
35

 
35

 
10

Total

$555

 

$340

 

$290



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Following are the amounts of Entergy Texas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2015
 
2016-2017
 
2018-2019
 
After 2019
 
Total
 
(In Millions)
Long-term debt (a)

$276

 

$158

 

$356

 

$1,444

 

$2,234

Operating leases (b)

$6

 

$9

 

$6

 

$4

 

$25

Purchase obligations (c)

$244

 

$494

 

$492

 

$213

 

$1,443


(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 $17.2 million to its pension plans and approximately $3.2 million to other postretirement plans in 2015, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015. 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 $17 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 amounts associated with specific investments, such as the Union Power Station acquisition discussed below; NRC post-Fukushima requirements; environmental compliance spending; transmission projects to enhance reliability, reduce congestion, and enable economic growth; resource planning; 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 in Note 5 to the financial statements.

As a wholly-owned subsidiary, Entergy Texas pays dividends to Entergy Corporation from its earnings at a percentage determined monthly.

Union Power Station Purchase Agreement

In December 2014, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas entered into an asset purchase agreement to acquire 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). Pursuant to the agreement, Entergy Gulf States Louisiana will acquire two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy Texas will each acquire one power block and a 25% undivided ownership interest in such related assets. (If Entergy Arkansas or Entergy Texas do not obtain approval for the purchase of their power blocks, Entergy Gulf States Louisiana will seek to purchase the power blocks not approved.) The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments.  In addition, Entergy Gulf States Louisiana anticipates selling 20% of the capacity and energy associated with its two power blocks to Entergy New Orleans through a cost-based, life-of-unit power purchase

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agreement. The purchase is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federal and state regulatory and permitting agencies. These include regulatory approvals from the APSC, LPSC, PUCT, and FERC, as well as clearance under the Hart-Scott-Rodino anti-trust law. In December 2014, Entergy Texas filed its application with the PUCT for approval of the acquisition. The PUCT has indicated that it will convene the hearing on the merits of this case in June 2015. Entergy Texas intends to file a rate application to seek cost recovery later in 2015. In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC and Entergy Arkansas filed its application with the APSC, each for approval of the acquisition and cost recovery. Closing is targeted to occur in late-2015.

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.

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 the money pool were as follows as of December 31 for each of the following years.
2014
 
2013
 
2012
 
2011
(In Thousands)
$306
 
$6,287
 
$19,175
 
$63,191

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 March 2019. The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2014, there were no borrowings and $1.3 million of letters of credit outstanding under the facility. In addition, Entergy Texas entered into an uncommitted letter of credit facility in 2014 as a means to post collateral to support its obligations under MISO. As of December 31, 2014, a $24.5 million letter of credit was outstanding under Entergy Texas’s letter of credit facility.

Entergy Texas obtained authorizations from the FERC through October 2015 for short-term borrowings not to exceed an aggregate amount of $200 million at any time outstanding and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Texas’s short-term borrowing limits.

In May 2014, Entergy Texas issued $135 million of 5.625% Series first mortgage bonds due June 2064. Entergy Texas used the proceeds to pay, prior to maturity, a portion of its $150 million of 7.875% Series first mortgage bonds due June 2039.


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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 current 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 includes 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 provides 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 measureable; 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 it 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 continues to believe that it is 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 have also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, have appealed 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 appealed the Travis County District Court decision and the PUCT appealed the decision on the line-loss factor issue. Entergy Texas expects to file briefs during the first half of 2015.

2013 Rate Case

In September 2013, Entergy Texas filed a rate case requesting a $38.6 million base rate increase reflecting a 10.4% return on common equity based on an adjusted test year ending March 31, 2013. The rate case also proposed (1) a rough production cost equalization adjustment rider recovering Entergy Texas’s payment to Entergy New Orleans to achieve rough production cost equalization based on calendar year 2012 production costs and (2) a rate case expense rider recovering the cost of the 2013 rate case and certain costs associated with previous rate cases. The rate case filing also included a request to reconcile $0.9 billion of fuel and purchased power costs and fuel revenues covering the period July 2011 through March 2013. The fuel reconciliation also reflects special circumstances fuel cost recovery of approximately $22 million of purchased power capacity costs. In January 2014 the PUCT staff filed direct testimony recommending a retail rate reduction of $0.3 million and a 9.2% return on common equity. In March 2014, Entergy Texas filed an Agreed Motion for Interim Rates. The motion explained that the parties to this proceeding have agreed

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that Entergy Texas should be allowed to implement new rates reflecting an $18.5 million base rate increase, effective for usage on and after April 1, 2014, as well as recovery of charges for rough production cost equalization and rate case expenses. In March 2014 the State Office of Administrative Hearings, the body assigned to hear the case, approved the motion. In April 2014, Entergy Texas filed a unanimous stipulation in this case. Among other things, the stipulation provides for an $18.5 million base rate increase, recovery over three years of the calendar year 2012 rough production cost equalization charges and rate case expenses, and states a 9.8% return on common equity. In addition, the stipulation finalizes the fuel and purchased power reconciliation covering the period July 2011 through March 2013, with the parties stipulating an immaterial fuel disallowance. No special circumstances recovery of purchased power capacity costs was allowed. In April 2014 the State Office of Administrative Hearings remanded the case back to the PUCT for final processing. In May 2014 the PUCT approved the stipulation. No motions for rehearing were filed during the statutory rehearing period.

In September 2014, Entergy Texas filed for a distribution cost recovery factor rider based on a law that was passed in 2011 allowing for the recovery of increases in capital costs associated with distribution plant. Entergy Texas requested collection of approximately $7 million annually from retail customers. The parties reached a unanimous settlement authorizing recovery of $3.6 million annually commencing with usage on and after January 1, 2015. A State Office of Administrative Hearings ALJ issued an order in December 2014 authorizing this recovery on an interim basis and remanded the case to the PUCT. In February 2015 the PUCT entered a final order, making the settlement final and the interim rates permanent.

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 December 2011, Entergy Texas filed with the PUCT a request to refund approximately $43 million, including interest, of fuel cost recovery over-collections through October 2011.  Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $67 million, including interest and additional over-recoveries through December 2011, over a three-month period.  Entergy Texas and the parties requested that interim rates consistent with the settlement be approved effective with the March 2012 billing month, and the PUCT approved the application in March 2012.  Entergy Texas completed this refund to customers in May 2012.

In October 2012, Entergy Texas filed with the PUCT a request to refund approximately $78 million, including interest, of fuel cost recovery over-collections through September 2012.  Entergy Texas requested that the refund be implemented over a six-month period effective with the January 2013 billing month.  Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $84 million, including interest and additional over-recoveries through October 2012, to most customers over a three-month period beginning January 2013.  The PUCT approved the stipulation in January 2013. Entergy Texas completed this refund to customers in March 2013.

In July 2012, Entergy Texas filed with the PUCT an application to credit its customers approximately $37.5 million, including interest, resulting from the FERC’s October 2011 order in the System Agreement rough production cost equalization proceeding. See Note 2 to the financial statements for a discussion of the FERC’s October 2011 order.  In September 2012 the parties submitted a stipulation resolving the proceeding.  The stipulation provided that most Entergy Texas customers would be credited over a four-month period beginning October 2012.  The credits were initiated with the October 2012 billing month on an interim basis, and the PUCT subsequently approved the stipulation, also in October 2012.

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

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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. All parties agreed that this case should be bifurcated such that the interim refunds would become final in a separate docket. The current docket would remain in place to potentially address additional rough production cost equalization-related matters that are not part of the interim refunds discussed above. In January 2015, Entergy Texas filed a request for this severance and final approval of the interim refund. Both applications are pending.
 
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.

Federal Regulation

See “Entergy’s Integration Into the MISO Regional Transmission Organization,” “System Agreement,” and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of these topics.

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. Entergy Texas does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Texas’s marketing efforts in retaining industrial 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. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy Texas’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that

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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.

Unbilled Revenue

As discussed in Note 1 to the financial statements, Entergy Texas 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 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 and fuel price fluctuations, in addition to changes in certain components of the calculation.

Qualified Pension and Other Postretirement Benefits

Entergy Texas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms.   See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries’ Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension and qualified projected benefit obligation cost to changes in certain actuarial assumptions (dollars in thousands).
 
 
Actuarial Assumption
 
 
Change in
Assumption
 
 
Impact on 2014
Qualified Pension Cost
 
Impact on 2014
Qualified Projected Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$842
 
$13,906
Rate of return on plan assets
 
(0.25%)
 
$697
 
$—
Rate of increase in compensation
 
0.25%
 
$322
 
$1,769

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 2014
Postretirement Benefit Cost
 
Impact on 2014 Accumulated
Postretirement Benefit
Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$230
 
$4,221
Health care cost trend
 
0.25%
 
$536
 
$3,884

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


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Costs and Funding

Total qualified pension cost for Entergy Texas in 2014 was $8.5 million. Entergy Texas anticipates 2015 qualified pension cost to be $12.1 million. Entergy Texas contributed $17.1 million to its qualified pension plans in 2014 and estimates 2015 pension contributions to be approximately $17.2 million, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015.

Total postretirement health care and life insurance benefit income for Entergy Texas in 2014 was $2.8 million. Entergy Texas expects 2015 postretirement health care and life insurance benefit income to approximate $3.0 million. Entergy Texas contributed $3.4 million to its other postretirement plans in 2014 and expects to contribute approximately $3.2 million in 2015.

The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans.  The 2014 actuarial study reviewed plan experience from 2010 through 2013.  As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies.  These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of  $30.8 million in the qualified pension benefit obligation and $8.2 million in the accumulated postretirement obligation.  The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $4.3 million and other postretirement cost by approximately $1 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.

Federal Healthcare Legislation

See the “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.

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.



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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholder of
Entergy Texas, Inc. and Subsidiaries
The Woodlands, Texas


We have audited the accompanying consolidated balance sheets of Entergy Texas, Inc. and Subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated income statements, consolidated statements of cash flows, and consolidated statements of changes in common equity (pages 432 through 436 and applicable items in pages 61 through 234) for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Texas, Inc. and Subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana
February 26, 2015


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ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS
 
 
 
 
 
For the Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$1,851,982

 

$1,728,799

 

$1,581,496

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
282,809

 
207,310

 
243,877

Purchased power
 
881,438

 
857,512

 
717,876

Other operation and maintenance
 
232,955

 
253,786

 
233,503

Taxes other than income taxes
 
70,439

 
63,823

 
59,348

Depreciation and amortization
 
99,609

 
94,744

 
88,307

Other regulatory charges - net
 
76,017

 
77,491

 
68,772

TOTAL
 
1,643,267

 
1,554,666

 
1,411,683

 
 
 
 
 
 
 
OPERATING INCOME
 
208,715

 
174,133

 
169,813

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
2,959

 
4,647

 
4,537

Interest and investment income (loss)
 
1,106

 
1,369

 
(2,220
)
Miscellaneous - net
 
(2,345
)
 
(3,328
)
 
(4,264
)
TOTAL
 
1,720

 
2,688

 
(1,947
)
 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
88,049

 
92,156

 
96,035

Allowance for borrowed funds used during construction
 
(2,062
)
 
(3,324
)
 
(3,258
)
TOTAL
 
85,987

 
88,832

 
92,777

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
124,448

 
87,989

 
75,089

 
 
 
 
 
 
 
Income taxes
 
49,644

 
30,108

 
33,118

 
 
 
 
 
 
 
NET INCOME
 

$74,804

 

$57,881

 

$41,971

 
 
 
 
 
 
 
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,
 
 
2014
 
2013
 
2012
 
 
(In Thousands)
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$74,804

 

$57,881

 

$41,971

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation and amortization
 
99,609

 
94,744

 
88,307

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
2,829

 
86,152

 
123,167

Changes in assets and liabilities:
 
 

 
 

 
 

Receivables
 
24,318

 
(49,252
)
 
32,912

Fuel inventory
 
5,433

 
53

 
(1,504
)
Accounts payable
 
(19,854
)
 
29,718

 
19,980

Prepaid taxes and taxes accrued
 
57,484

 
(1,967
)
 
(93,979
)
Interest accrued
 
(1,489
)
 
(920
)
 
(929
)
Deferred fuel costs
 
(15,954
)
 
(89,241
)
 
28,670

Other working capital accounts
 
9,045

 
6,918

 
(58,691
)
Provisions for estimated losses
 
3,139

 
2,470

 
1,585

Other regulatory assets
 
2,809

 
197,520

 
62,166

Pension and other postretirement liabilities
 
59,725

 
(104,055
)
 
17,330

Other assets and liabilities
 
13,266

 
7,033

 
10,096

Net cash flow provided by operating activities
 
315,164

 
237,054

 
271,081

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(195,794
)
 
(181,546
)
 
(181,404
)
Allowance for equity funds used during construction
 
2,981

 
4,647

 
4,537

Changes in money pool receivable - net
 
5,981

 
12,888

 
44,016

Changes in securitization account
 
292

 
(256
)
 
3,960

Other
 
—

 
(42
)
 
(13
)
Net cash flow used in investing activities
 
(186,540
)
 
(164,309
)
 
(128,904
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
131,163

 
—

 
—

Retirement of long-term debt
 
(213,450
)
 
(61,316
)
 
(59,322
)
Dividends paid:
 
 

 
 

 
 

Common stock
 
(70,000
)
 
(25,000
)
 
(87,180
)
Other
 
7,616

 
(177
)
 
(728
)
Net cash flow used in financing activities
 
(144,671
)
 
(86,493
)
 
(147,230
)
Net decrease in cash and cash equivalents
 
(16,047
)
 
(13,748
)
 
(5,053
)
Cash and cash equivalents at beginning of period
 
46,488

 
60,236

 
65,289

Cash and cash equivalents at end of period
 

$30,441

 

$46,488

 

$60,236

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 

 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$85,695

 

$89,021

 

$92,632

Income taxes
 

($2,653
)
 

($57,473
)
 

($2,207
)
See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2014
 
2013
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$1,733

 

$2,432

Temporary cash investments
 
28,708

 
44,056

Total cash and cash equivalents
 
30,441

 
46,488

Securitization recovery trust account
 
37,219

 
37,511

Accounts receivable:
 
 

 
 

Customer
 
70,993

 
76,957

Allowance for doubtful accounts
 
(672
)
 
(443
)
Associated companies
 
57,004

 
76,494

Other
 
10,985

 
10,897

Accrued unbilled revenues
 
38,363

 
43,067

Total accounts receivable
 
176,673

 
206,972

Deferred fuel costs
 
11,861

 
—

Accumulated deferred income taxes
 
669

 
—

Fuel inventory - at average cost
 
49,902

 
55,335

Materials and supplies - at average cost
 
33,892

 
34,068

Prepaid taxes
 
—

 
55,635

Prepayments and other
 
29,211

 
50,498

TOTAL
 
369,868

 
486,507

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Investments in affiliates - at equity
 
655

 
687

Non-utility property - at cost (less accumulated depreciation)
 
376

 
376

Other
 
19,085

 
18,161

TOTAL
 
20,116

 
19,224

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
3,761,847

 
3,616,061

Construction work in progress
 
125,425

 
94,743

TOTAL UTILITY PLANT
 
3,887,272

 
3,710,804

Less - accumulated depreciation and amortization
 
1,454,701

 
1,387,303

UTILITY PLANT - NET
 
2,432,571

 
2,323,501

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Regulatory asset for income taxes - net
 
123,407

 
129,069

  Other regulatory assets (includes securitization property of $521,424 as of
December 31, 2014 and $585,152 as of December 31, 2013)
 
922,087

 
919,234

Long-term receivables - associated companies
 
26,156

 
27,900

Other
 
13,880

 
16,425

TOTAL
 
1,085,530

 
1,092,628

 
 
 
 
 
TOTAL ASSETS
 

$3,908,085

 

$3,921,860

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2014
 
2013
 
 
(In Thousands)
CURRENT LIABILITIES
 
 
 
 
Currently maturing long-term debt
 

$200,000

 

$—

Accounts payable:
 
 
 
 
Associated companies
 
91,481

 
112,309

Other
 
87,910

 
73,682

Customer deposits
 
44,308

 
38,721

Taxes accrued
 
1,849

 
—

Accumulated deferred income taxes
 
—

 
33,847

Interest accrued
 
29,757

 
31,246

Deferred fuel costs
 
—

 
4,093

Other
 
18,238

 
36,276

TOTAL
 
473,543

 
330,174

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
1,046,618

 
1,022,955

Accumulated deferred investment tax credits
 
14,735

 
16,147

Other regulatory liabilities
 
5,125

 
5,194

Asset retirement cost liabilities
 
4,610

 
4,349

Accumulated provisions
 
12,218

 
9,079

Pension and other postretirement liabilities
 
111,011

 
51,253

Long-term debt (includes securitization bonds of $565,659 as of December 31, 2014 and $629,087 as of December 31, 2013)
 
1,278,931

 
1,556,939

Other
 
69,463

 
38,743

TOTAL
 
2,542,711

 
2,704,659

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
COMMON EQUITY
 
 

 
 

Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2014 and 2013
 
49,452

 
49,452

Paid-in capital
 
481,994

 
481,994

Retained earnings
 
360,385

 
355,581

TOTAL
 
891,831

 
887,027

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$3,908,085

 

$3,921,860

 
 
 
 
 
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, 2014, 2013, and 2012
 
 
 
 
 
Common Equity
 
 
 
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Total
 
(In Thousands)
 
 
 
 
 
 
 
 
Balance at December 31, 2011

$49,452

 

$481,994

 

$367,909

 

$899,355

Net income
—

 
—

 
41,971

 
41,971

Common stock dividends
—

 
—

 
(87,180
)
 
(87,180
)
Balance at December 31, 2012

$49,452

 

$481,994

 

$322,700

 

$854,146

Net income
—

 
—

 
57,881

 
57,881

Common stock dividends
—

 
—

 
(25,000
)
 
(25,000
)
Balance at December 31, 2013

$49,452

 

$481,994

 

$355,581

 

$887,027

Net income
—

 
—

 
74,804

 
74,804

Common stock dividends
—

 
—

 
(70,000
)
 
(70,000
)
Balance at December 31, 2014

$49,452

 

$481,994

 

$360,385

 

$891,831

 
 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 



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ENTERGY TEXAS, INC. AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
(In Thousands)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$1,851,982

 

$1,728,799

 

$1,581,496

 

$1,757,199

 

$1,690,431

Net Income

$74,804

 

$57,881

 

$41,971

 

$80,845

 

$66,200

Total assets

$3,908,085

 

$3,921,860

 

$4,025,781

 

$4,059,006

 

$3,783,864

Long-term obligations (a)

$1,278,931

 

$1,556,939

 

$1,617,813

 

$1,677,127

 

$1,659,230

 
 
 
 
 
 
 
 
 
 
(a) Includes long-term debt (excluding currently maturing debt).
 
 
 
 
 
 
 
 
 
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
(Dollars In Millions)
 
 
 
 
 
 
 
 
 
 
Electric Operating Revenues:
 

 
 

 
 

 
 

 
 

Residential

$654

 

$596

 

$553

 

$638

 

$559

Commercial
384

 
327

 
325

 
369

 
321

Industrial
422

 
325

 
299

 
352

 
305

Governmental
26

 
24

 
24

 
26

 
23

Total retail
1,486

 
1,272

 
1,201

 
1,385

 
1,208

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
316

 
369

 
313

 
262

 
373

Non-associated companies
23

 
47

 
36

 
74

 
76

Other
27

 
41

 
31

 
36

 
33

Total

$1,852

 

$1,729

 

$1,581

 

$1,757

 

$1,690

 
 
 
 
 
 
 
 
 
 
Billed Electric Energy Sales (GWh):
 
 
 

 
 

 
 

 
 

Residential
5,810

 
5,726

 
5,604

 
6,034

 
5,958

Commercial
4,471

 
4,402

 
4,396

 
4,433

 
4,271

Industrial
7,140

 
6,404

 
6,066

 
6,102

 
5,642

Governmental
277

 
282

 
278

 
294

 
271

Total retail
17,698

 
16,814

 
16,344

 
16,863

 
16,142

Sales for resale:
 

 
 

 
 

 
 

 
 

Associated companies
4,763

 
6,287

 
5,702

 
4,158

 
3,758

Non-associated companies
200

 
712

 
827

 
1,258

 
1,300

Total
22,661

 
23,813

 
22,873

 
22,279

 
21,200



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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

2014 Compared to 2013

Net income decreased $17.3 million primarily due to a higher effective income tax rate and lower operating revenues resulting from lower rate base as compared with the same period in the prior year, partially offset by higher other regulatory credits. System Energy records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation-related costs collected in revenue. The increase in regulatory credits for 2014 compared to 2013 is primarily caused by increases in depreciation and accretion expenses and regulatory credits recorded in 2014 to realign the asset retirement obligation regulatory asset with regulatory treatment.

2013 Compared to 2012

Net income increased $1.8 million primarily due to higher operating income and a lower effective income tax rate, partially offset by lower other income. Operating income was higher because of higher rate base compared to 2012 resulting from capital spending at Grand Gulf, including the uprate project. The lower effective income tax rate was primarily due to the reversal of a portion of the provision for uncertain tax positions. Other income was lower due to AFUDC accrued on the Grand Gulf uprate project in 2012. Grand Gulf’s Spring 2012 refueling outage was completed in June 2012, and the majority of uprate-related capital improvements were completed during this outage.

Income Taxes

The effective income tax rates for 2014, 2013, and 2012 were 46.4%, 37.7%, and 40.8%, 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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Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2014, 2013, and 2012 were as follows:
 
2014
 
2013
 
2012
 
(In Thousands)
Cash and cash equivalents at beginning of period

$127,142

 

$83,622

 

$185,157

 
 
 
 
 
 
Net cash provided by (used in):
 
 
 

 
 

Operating activities
428,265

 
279,638

 
412,000

Investing activities
(203,930
)
 
(96,852
)
 
(502,637
)
Financing activities
(128,298
)
 
(139,266
)
 
(10,898
)
Net increase (decrease) in cash and cash equivalents
96,037

 
43,520

 
(101,535
)
 
 
 
 
 
 
Cash and cash equivalents at end of period

$223,179

 

$127,142

 

$83,622


Operating Activities

Net cash flow provided by operating activities increased $148.6 million in 2014 primarily due to income tax refunds of $10.1 million in 2014 compared to income tax payments of $211.2 million in 2013. The increase was partially offset by spending on the Grand Gulf refueling outage in 2014 and an increase of $12.9 million in pension contributions in 2014. System Energy made income tax payments in 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax payments in 2013 resulted primarily from the reversal of temporary differences for which System Energy had previously claimed a tax deduction. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Net cash provided by operating activities decreased $132.4 million in 2013 primarily due to income tax payments of $211.2 million in 2013, as discussed above, compared to income tax refunds of $56.8 million in 2012, partially offset by spending on the Grand Gulf refueling outage in 2012. System Energy received income tax refunds in 2012 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax refunds of $56.8 million in 2012 resulted primarily from a decrease of previously estimated 2011 taxable income due to the recognition of additional bonus depreciation.

Investing Activities

Net cash flow used in investing activities increased $107.1 million in 2014 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;
•
an increase in nuclear construction expenditures primarily as a result of spending on nuclear projects during the Grand Gulf refueling outage in 2014; and
•
money pool activity.

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 $6.9 million in 2014 compared to decreasing by $17.7 million in 2013. 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 used in investing activities decreased $405.8 million in 2013 primarily due to a decrease in construction expenditures resulting from spending on the uprate project at Grand Gulf completed during the refueling outage in 2012 and a decrease in nuclear fuel activity primarily due to the Grand Gulf refueling outage in 2012. The decrease was partially offset by money pool activity.

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 $17.7 million in 2013 compared to decreasing by $93.5 million in 2012.

 Financing Activities

Net cash used in financing activities decreased $11 million in 2014 primarily due to:

•
the redemption of $70 million of 6.29% Series F notes by the nuclear fuel company variable interest entity in September 2013; and
•
net borrowings of $20.4 million on the nuclear fuel company variable interest entity’s credit facility in 2014 compared to net repayments of $40 million on the nuclear fuel company variable interest entity’s credit facility in 2013.

The decrease was partially offset by the issuance of $85 million of 3.78% Series I notes by the nuclear fuel company variable interest entity in October 2013 and an increase of $31.6 million in common stock dividends paid in 2014.

Net cash used in financing activities increased $128.4 million in 2013 primarily due to:

•
the issuance of $250 million of 4.10% Series first mortgage bonds in September 2012;
•
the issuance of $50 million of 4.02% Series H notes by the nuclear fuel company variable interest entity in February 2012; and
•
the redemption of $70 million of 6.29% Series F notes by the nuclear fuel company variable interest entity in September 2013.

The increase was partially offset by:

•
the redemption of $152.975 million of pollution control revenue bonds in 2012;
•
the redemption of $70 million of 6.2% Series first mortgage bonds in October 2012;
•
an increase in borrowings of $40 million on the nuclear fuel company variable interest entity’s credit facility in 2013 compared to the repayment of borrowings of $40 million on the nuclear fuel company variable interest entity’s credit facility in 2012; and
•
a decrease of $9.4 million in common stock dividends paid in 2013.

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.
 
December 31,
2014
 
December 31,
2013
Debt to capital
45.7
%
 
46.4
%
Effect of subtracting cash
(8.8
%)
 
(4.6
%)
Net debt to net capital
36.9
%
 
41.8
%

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

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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.

Uses of Capital

System Energy requires capital resources for:

•
construction and other capital investments;
•
debt maturities or retirements;
•
working capital purposes, including the financing of fuel costs; and
•
dividend and interest payments.

Following are the amounts of System Energy’s planned construction and other capital investments.
 
2015
 
2016
 
2017
 
(In Millions)
Planned construction and capital investment:
 
 
 
 
 
Generation

$70

 

$65

 

$35

Other
5

 
5

 
5

Total

$75

 

$70

 

$40


Following are the amounts of System Energy’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
 
2015
 
2016-2017
 
2018-2019
 
After 2019
 
Total
 
(In Millions)
Long-term debt (a)

$141

 

$132

 

$161

 

$762

 

$1,196

Purchase obligations (b)

$5

 

$28

 

$30

 

$53

 

$116


(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 $20.8 million to its pension plans and approximately $475 thousand to its other postretirement plans in 2015, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015.  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 $95.1 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 investments and initiatives such as NRC post-Fukushima requirements and plant improvements.


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As a wholly-owned subsidiary, System Energy dividends its earnings to Entergy Corporation at a percentage determined monthly.  Currently, all of System Energy’s retained earnings are available for distribution.

Sources of Capital

System Energy’s sources to meet its capital requirements include:

•
internally generated funds;
•
cash on hand;
•
debt issuances; and
•
bank financing under new or existing facilities.

System Energy may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest 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.
2014
 
2013
 
2012
 
2011
(In Thousands)
$2,373
 
$9,223
 
$26,915
 
$120,424

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 $125 million scheduled to expire in June 2016. As of December 31, 2014, $20.4 million was outstanding on the variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the variable interest entity credit facilities.

System Energy obtained authorizations from the FERC through October 2015 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.

Nuclear Matters

System Energy owns and operates Grand Gulf.  System Energy is, therefore, subject to the risks related to owning and operating a nuclear plant.  These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, regulatory requirement changes, including changes resulting from events at other plants, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts.  In the event of an unanticipated early shutdown of Grand Gulf, System Energy may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.  Grand Gulf’s operating license is currently due to expire in November

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2024.  In October 2011, System Energy filed an application with the NRC for an extension of Grand Gulf’s operating license to 2044, which application is pending.

In June 2012 the U.S. Court of Appeals for the D.C. Circuit vacated the NRC’s 2010 update to its Waste Confidence Decision, which had found generically that a permanent geologic repository to store spent nuclear fuel would be available when necessary and that spent nuclear fuel could be stored at nuclear reactor sites in the interim without significant environmental effects, and remanded the case for further proceedings. The court concluded that the NRC had not satisfied the requirements of the National Environmental Policy Act (NEPA) when it considered environmental effects in reaching these conclusions. The Waste Confidence Decision has been relied upon by NRC license renewal applicants to address some of the issues that the NEPA requires the NRC to address before it issues a renewed license. Certain nuclear opponents filed requests with the NRC asking it to address the issues raised by the court’s decision in the license renewal proceedings for a number of nuclear plants including Grand Gulf. In August 2012 the NRC issued an order stating that it will not issue final licenses dependent upon the Waste Confidence Decision until the D.C. Circuit’s remand is addressed, but also stating that licensing reviews and proceedings should continue to move forward. In September 2014 the NRC published a new final Waste Confidence rule, named Continued Storage of Spent Nuclear Fuel, that for licensing purposes adopts non-site specific findings concerning the environmental impacts of the continued storage of spent nuclear fuel at reactor sites - for 60 years, 100 years and indefinitely - after the reactor’s licensed period of operations. The NRC also issued an order lifting its suspension of licensing proceedings after the final rule’s effective date in October 2014. After the final rule became effective, New York, Connecticut, and Vermont filed a challenge to the rule in the U.S. Court of Appeals. The final rule remains in effect while that challenge is pending unless the court orders otherwise.
    
The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system.  The issue is applicable to Grand Gulf 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.

After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States.  The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders.  The task force then issued a second report in September 2011.  Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012.  The three orders require U.S. nuclear operators to undertake plant modifications and perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating nuclear plants.  The NRC, with input from the industry, is continuing to determine the specific actions required by the orders. System Energy’s estimated capital expenditures for 2015 through 2017 for complying with the NRC orders are included in the planned construction and other capital investments estimates given in “Liquidity and Capital Resources - Uses of Capital” above.

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.  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

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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 fourth quarter 2014, 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 $99.9 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the fourth quarter 2013, 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 $102.3 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

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 2014
Qualified Pension Cost
 
Impact on 2014
Projected Qualified Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$858
 
$12,797
Rate of return on plan assets
 
(0.25%)
 
$489
 
$—
Rate of increase in compensation
 
0.25%
 
$330
 
$1,934


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System Energy Resources, Inc.
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 2014
Postretirement Benefit Cost
 
Impact on 2014
Accumulated Postretirement
Benefit Obligation
 
 
 
 
Increase/(Decrease)
 
 
Discount rate
 
(0.25%)
 
$191
 
$2,252
Health care cost trend
 
0.25%
 
$318
 
$2,071

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 2014 was $12.2 million.  System Energy anticipates 2015 qualified pension cost to be $16.6 million.  System Energy contributed $21.2 million to its pension plans in 2014 and estimates 2015 pension contributions to be approximately $20.8 million, although the required pension contributions will not be known with more certainty until the January 1, 2015 valuations are completed by April 1, 2015.
 
Total postretirement health care and life insurance benefit costs for System Energy in 2014 were $561 thousand. System Energy expects 2015 postretirement health care and life insurance benefit costs to approximate $481 thousand. System Energy contributed $334 thousand to its other postretirement plans in 2014 and expects to contribute $475 thousand in 2015.

The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans.  The 2014 actuarial study reviewed plan experience from 2010 through 2013.  As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies.  These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of  $17.7 million in the qualified pension benefit obligation and $3.1 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $2.7 million and other postretirement cost by approximately $0.4 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.

Federal Healthcare Legislation

See the “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.

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

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System Energy Resources, Inc.
Management’s Financial Discussion and Analysis



























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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholder of
System Energy Resources, Inc.
Jackson, Mississippi


We have audited the accompanying balance sheets of System Energy Resources, Inc. (the “Company”) as of December 31, 2014 and 2013, and the related income statements, statements of cash flows, and statements of changes in common equity (pages 448 through 452 and applicable items in pages 61 through 234) for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of System Energy Resources, Inc. as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana
February 26, 2015


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SYSTEM ENERGY RESOURCES, INC.
INCOME STATEMENTS
 
 
 
 
 
For the Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(In Thousands)
 
 
 
 
 
 
 
OPERATING REVENUES
 
 
 
 
 
 
Electric
 

$664,364

 

$735,089

 

$622,118

 
 
 
 
 
 
 
OPERATING EXPENSES
 
 

 
 

 
 

Operation and Maintenance:
 
 

 
 

 
 

Fuel, fuel-related expenses, and gas purchased for resale
 
84,658

 
103,358

 
62,918

Nuclear refueling outage expenses
 
23,309

 
29,551

 
21,824

Other operation and maintenance
 
156,502

 
174,772

 
149,346

Decommissioning
 
41,835

 
35,472

 
33,019

Taxes other than income taxes
 
25,160

 
25,537

 
19,468

Depreciation and amortization
 
142,583

 
176,387

 
154,561

Other regulatory credits - net
 
(30,799
)
 
(13,068
)
 
(10,429
)
TOTAL
 
443,248

 
532,009

 
430,707

 
 
 
 
 
 
 
OPERATING INCOME
 
221,116

 
203,080

 
191,411

 
 
 
 
 
 
 
OTHER INCOME
 
 

 
 

 
 

Allowance for equity funds used during construction
 
5,069

 
7,784

 
26,102

Interest and investment income
 
11,037

 
9,844

 
10,134

Miscellaneous - net
 
(529
)
 
(804
)
 
(617
)
TOTAL
 
15,577

 
16,824

 
35,619

 
 
 
 
 
 
 
INTEREST EXPENSE
 
 

 
 

 
 

Interest expense
 
58,384

 
38,173

 
45,214

Allowance for borrowed funds used during construction
 
(1,335
)
 
(786
)
 
(7,165
)
TOTAL
 
57,049

 
37,387

 
38,049

 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
179,644

 
182,517

 
188,981

 
 
 
 
 
 
 
Income taxes
 
83,310

 
68,853

 
77,115

 
 
 
 
 
 
 
NET INCOME
 

$96,334

 

$113,664

 

$111,866

 
 
 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 

 
 



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SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF CASH FLOWS
 
 
 
 
 
For the Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(In Thousands)
OPERATING ACTIVITIES
 
 
 
 
 
 
Net income
 

$96,334

 

$113,664

 

$111,866

Adjustments to reconcile net income to net cash flow provided by operating activities:
 
 
 
 
 
 
Depreciation, amortization, and decommissioning, including nuclear fuel amortization
 
254,199

 
293,537

 
235,881

Deferred income taxes, investment tax credits, and non-current taxes accrued
 
79,835

 
29,996

 
43,651

Changes in assets and liabilities:
 
 

 
 

 
 

Receivables
 
37,345

 
(29,226
)
 
(12,557
)
Accounts payable
 
(6,372
)
 
6,685

 
(10,511
)
Prepaid taxes and taxes accrued
 
12,146

 
(170,356
)
 
89,022

Interest accrued
 
21,371

 
(3,794
)
 
(2,157
)
Other working capital accounts
 
(11,688
)
 
24,863

 
(22,917
)
Other regulatory assets
 
(64,262
)
 
79,345

 
(44,004
)
Pension and other postretirement liabilities
 
49,741

 
(63,206
)
 
2,898

Other assets and liabilities
 
(40,384
)
 
(1,870
)
 
20,828

Net cash flow provided by operating activities
 
428,265

 
279,638

 
412,000

INVESTING ACTIVITIES
 
 

 
 

 
 

Construction expenditures
 
(63,774
)
 
(51,584
)
 
(450,236
)
Allowance for equity funds used during construction
 
5,069

 
7,784

 
26,102

Nuclear fuel purchases
 
(181,209
)
 
(65,691
)
 
(194,314
)
Proceeds from sale of nuclear fuel
 
61,076

 
26,522

 
52,708

Proceeds from nuclear decommissioning trust fund sales
 
392,872

 
215,467

 
349,427

Investment in nuclear decommissioning trust funds
 
(424,814
)
 
(247,042
)
 
(379,833
)
Change in money pool receivable - net
 
6,850

 
17,692

 
93,509

Net cash flow used in investing activities
 
(203,930
)
 
(96,852
)
 
(502,637
)
FINANCING ACTIVITIES
 
 

 
 

 
 

Proceeds from the issuance of long-term debt
 
—

 
85,000

 
297,908

Retirement of long-term debt
 
(46,743
)
 
(111,479
)
 
(262,867
)
Changes in credit borrowings - net
 
20,404

 
(39,986
)
 
39,986

Dividends paid:
 
 

 
 

 
 

Common stock
 
(101,930
)
 
(70,286
)
 
(79,700
)
Other
 
(29
)
 
(2,515
)
 
(6,225
)
Net cash flow used in financing activities
 
(128,298
)
 
(139,266
)
 
(10,898
)
Net increase (decrease) in cash and cash equivalents
 
96,037

 
43,520

 
(101,535
)
Cash and cash equivalents at beginning of period
 
127,142

 
83,622

 
185,157

Cash and cash equivalents at end of period
 

$223,179

 

$127,142

 

$83,622

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 

 
 

 
 

Cash paid (received) during the period for:
 
 

 
 

 
 

Interest - net of amount capitalized
 

$27,834

 

$32,178

 

$34,012

Income taxes
 

($10,065
)
 

$211,210

 

($56,808
)
See Notes to Financial Statements.
 
 

 
 

 
 


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SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
ASSETS
 
 
 
 
 
December 31,
 
 
2014
 
2013
 
 
(In Thousands)
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
Cash and cash equivalents:
 
 
 
 
Cash
 

$789

 

$62,561

Temporary cash investments
 
222,390

 
64,581

Total cash and cash equivalents
 
223,179

 
127,142

Accounts receivable:
 
 

 
 

Associated companies
 
60,907

 
104,419

Other
 
5,717

 
6,400

Total accounts receivable
 
66,624

 
110,819

Materials and supplies - at average cost
 
80,049

 
85,118

Deferred nuclear refueling outage costs
 
26,580

 
7,853

Prepayments and other
 
2,312

 
1,727

TOTAL
 
398,744

 
332,659

 
 
 
 
 
OTHER PROPERTY AND INVESTMENTS
 
 

 
 

Decommissioning trust funds
 
679,840

 
603,896

TOTAL
 
679,840

 
603,896

 
 
 
 
 
UTILITY PLANT
 
 

 
 

Electric
 
4,244,902

 
4,124,647

Property under capital lease
 
573,784

 
570,872

Construction work in progress
 
50,382

 
29,061

Nuclear fuel
 
251,376

 
188,824

TOTAL UTILITY PLANT
 
5,120,444

 
4,913,404

Less - accumulated depreciation and amortization
 
2,819,688

 
2,699,263

UTILITY PLANT - NET
 
2,300,756

 
2,214,141

 
 
 
 
 
DEFERRED DEBITS AND OTHER ASSETS
 
 

 
 

Regulatory assets:
 
 

 
 

Regulatory asset for income taxes - net
 
105,882

 
115,492

Other regulatory assets
 
335,613

 
261,740

Other
 
9,251

 
15,996

TOTAL
 
450,746

 
393,228

 
 
 
 
 
TOTAL ASSETS
 

$3,830,086

 

$3,543,924

 
 
 
 
 
See Notes to Financial Statements.
 
 

 
 


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SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
LIABILITIES AND EQUITY
 
 
 
 
 
December 31,
 
 
2014
 
2013
 
 
(In Thousands)
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
 
Currently maturing long-term debt
 

$76,310

 

$48,653

Short-term borrowings
 
20,404

 
—

Accounts payable:
 
 

 
 

Associated companies
 
6,252

 
12,778

Other
 
33,096

 
31,862

Taxes accrued
 
23,267

 
11,121

Accumulated deferred income taxes
 
14,175

 
2,310

Interest accrued
 
33,196

 
11,825

Other
 
2,365

 
2,312

TOTAL
 
209,065

 
120,861

 
 
 
 
 
NON-CURRENT LIABILITIES
 
 

 
 

Accumulated deferred income taxes and taxes accrued
 
808,171

 
737,973

Accumulated deferred investment tax credits
 
49,313

 
54,786

Other regulatory liabilities
 
371,110

 
349,846

Decommissioning
 
757,918

 
616,157

Pension and other postretirement liabilities
 
129,152

 
79,411

Long-term debt
 
634,496

 
708,783

Other
 
350

 
—

TOTAL
 
2,750,510

 
2,546,956

 
 
 
 
 
Commitments and Contingencies
 


 


 
 
 
 
 
COMMON EQUITY
 
 

 
 

Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2014 and 2013
 
789,350

 
789,350

Retained earnings
 
81,161

 
86,757

TOTAL
 
870,511

 
876,107

 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 

$3,830,086

 

$3,543,924

 
 
 
 
 
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, 2014, 2013, and 2012
 
 
 
 
 
Common Equity
 
 
 
Common Stock
 
Retained Earnings
 
Total
 
(In Thousands)
 
 
 
 
 
 
Balance at December 31, 2011

$789,350

 

$11,213

 

$800,563

Net income
—

 
111,866

 
111,866

Common stock dividends
—

 
(79,700
)
 
(79,700
)
Balance at December 31, 2012

$789,350

 

$43,379

 

$832,729

Net income
—

 
113,664

 
113,664

Common stock dividends
—

 
(70,286
)
 
(70,286
)
Balance at December 31, 2013

$789,350

 

$86,757

 

$876,107

Net income
—

 
96,334

 
96,334

Common stock dividends
—

 
(101,930
)
 
(101,930
)
Balance at December 31, 2014

$789,350

 

$81,161

 

$870,511

 
 
 
 
 
 
See Notes to Financial Statements.
 

 
 

 
 



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SYSTEM ENERGY RESOURCES, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
 
 
 
 
 
 
 
 
 
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
(Dollars In Thousands)
 
 
 
 
 
 
 
 
 
 
Operating revenues

$664,364

 

$735,089

 

$622,118

 

$563,411

 

$558,584

Net Income

$96,334

 

$113,664

 

$111,866

 

$64,197

 

$82,624

Total assets

$3,830,086

 

$3,543,924

 

$3,623,516

 

$3,245,365

 

$3,224,070

Long-term obligations (a)

$634,496

 

$708,783

 

$671,945

 

$636,885

 

$796,728

Electric energy sales (GWh)
9,219

 
9,794

 
6,602

 
9,293

 
8,692

 
 
 
 
 
 
 
 
 
 
(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. - 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 2014 are discussed in Part I. Item 1. - Business under the sections titled “Retail Rate Regulation”, “Environmental Regulation”, and  “Litigation” and “Impairment of Long-Lived Assets” in Note 1 to the financial statements in this report.

Item 4.   Mine Safety Disclosures

Not applicable.

EXECUTIVE OFFICERS OF ENTERGY CORPORATION

Executive Officers

Name
 
Age
 
Position
 
Period
Leo P. Denault (a)
 
55
 
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
 
 
 
 
 
 
 
William M. Mohl (a)
 
55
 
President, Entergy Wholesale Commodities
 
2013-Present
 
 
 
 
President and Chief Executive Officer of Entergy Gulf States Louisiana and Entergy Louisiana
 
2010-2013
 
 
 
 
Director of Entergy Gulf States Louisiana and Entergy Louisiana
 
2010-2013
 
 
 
 
Vice President, System Planning of Entergy Services, Inc.
 
2007-2010
 
 
 
 
 
 
 
Theodore H. Bunting, Jr. (a)
 
56
 
Group President Utility Operations of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
 
2012-Present
 
 
 
 
President, Chief Executive Officer, and Director of System Energy
 
2014-Present
 
 
 
 
Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas
 
2012-Present
 
 
 
 
Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
 
2007-2012

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Name
 
Age
 
Position
 
Period
Marcus V. Brown (a)
 
53
 
Executive 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
 
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
 
 
 
 
 
 
 
Andrew S. Marsh (a)
 
43
 
Executive Vice President and Chief Financial Officer of Entergy Corporation
 
2013-Present
 
 
 
 
Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy
 
2013-Present
 
 
 
 
Chief Financial Officer of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, 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
 
 
 
 
 
 
 
Mark T. Savoff (a)
 
58
 
Executive Vice President and Chief Operating Officer of Entergy Corporation
 
2010-Present
 
 
 
 
Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and Entergy Mississippi
 
2004-Present
 
 
 
 
Director of Entergy Texas
 
2007-Present
 
 
 
 
Director of Entergy New Orleans
 
2011-Present
 
 
 
 
Executive Vice President, Operations of Entergy Corporation
 
2004-2010
 
 
 
 
 
 
 
Roderick K. West (a)
 
46
 
Executive Vice President and Chief Administrative Officer of Entergy Corporation
 
2010-Present
 
 
 
 
President and Chief Executive Officer of Entergy New Orleans
 
2007-2010
 
 
 
 
Director of Entergy New Orleans
 
2005-2011
 
 
 
 
 
 
 
Jeffrey S. Forbes (a)
 
58
 
Executive Vice President, Nuclear Operations/Chief Nuclear Officer of Entergy Corporation
 
2013-Present
 
 
 
 
Executive Vice President and Chief Nuclear Officer of Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Louisiana
 
2013-Present
 
 
 
 
Executive Vice President and Chief Nuclear Officer of System Entergy
 
2014-Present
 
 
 
 
Director of System Energy
 
2013-Present
 
 
 
 
President and Chief Executive Officer of System Energy
 
2013-2014
 
 
 
 
Senior Vice President, Nuclear Operations of Entergy Services, Inc.
 
2011-2013
 
 
 
 
Senior Vice President and Chief Operating Officer of Entergy Operations, Inc.
 
2003-2011


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Name
 
Age
 
Position
 
Period
Alyson M. Mount (a)
 
44
 
Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, 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
 
 
 
 
 
 
 
Donald W. Vinci (a)
 
56
 
Senior Vice President, Human Resources and Chief Diversity Officer of Entergy Corporation
 
2013-Present
 
 
 
 
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, 2014.

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 2014 and 2013 were as follows:
 
2014
 
2013
 
High
 
Low
 
High
 
Low
 
(In Dollars)
First
67.02
 
60.40
 
65.39
 
61.09
Second
82.30
 
66.41
 
72.10
 
63.12
Third
82.48
 
70.70
 
72.60
 
61.66
Fourth
92.02
 
76.51
 
68.63
 
60.22

Consecutive quarterly cash dividends on common stock were paid to stockholders of Entergy Corporation in 2014 and 2013.  Quarterly dividends of $0.83 per share were paid in 2014 and 2013.

As of January 31, 2015, there were 30,762 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)
 
 
 
 
 
 
 
 
 
 
10/01/2014
-10/31/2014
 
—

 

$—

 
—

 

$350,052,918

11/01/2014
-11/30/2014
 
—

 

$—

 
—

 

$350,052,918

12/01/2014
-12/31/2014
 
1,906,300

 

$86.56

 
1,906,300

 

$350,052,918

Total
 
 
1,906,300

 

$86.56

 
1,906,300

 
 

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 2014, Entergy withheld 55,076 shares of its common stock at $61.29 per share and 43,246 shares of its common stock at $63.03 per share to pay income taxes due upon vesting of restricted stock granted 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 Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy

There is no market for the common stock of Entergy Corporation’s wholly owned subsidiaries.  Cash dividends on common stock paid by the Registrant Subsidiaries during 2014 and 2013, were as follows:
 
2014
 
2013
 
(In Millions)
Entergy Arkansas

$10.0

 

$15.0

Entergy Gulf States Louisiana

$166.9

 

$119.9

Entergy Louisiana

$320.6

 

$356.3

Entergy Mississippi

$61.4

 

$7.4

Entergy New Orleans

$6.0

 

$—

Entergy Texas

$70.0

 

$25.0

System Energy

$101.9

 

$70.3


Information with respect to restrictions that limit the ability of the Registrant Subsidiaries to pay dividends 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 GULF STATES LOUISIANA, L.L.C., ENTERGY LOUISIANA, LLC, ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., 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 GULF STATES, LOUISIANA, L.L.C., ENTERGY LOUISIANA, LLC, ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., 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 Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., 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 Gulf States Louisiana, 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, 2014, evaluations were performed under the supervision and with the participation of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (individually “Registrant” and collectively the “Registrants”) management, including their respective Principal Executive Officers (PEO) and Principal Financial Officers (PFO).  The evaluations assessed the effectiveness of the Registrants’ disclosure controls and procedures.  Based on the evaluations, each PEO and PFO has concluded that, as to the Registrant or Registrants for which they serve as PEO or PFO, the Registrant’s or Registrants’ disclosure controls and procedures are effective to ensure that information required to be disclosed by each Registrant in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms; and that the Registrant’s or Registrants’ disclosure controls and procedures are also effective in reasonably assuring that such information is accumulated and communicated to the Registrant’s or Registrants’ management, including their respective PEOs and PFOs, as appropriate to allow timely decisions regarding required disclosure.


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Internal Control over Financial Reporting

(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

The managements of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, 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, 2014.  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, 2014.

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 on page 529. The report of Deloitte & Touche LLP is not applicable to Entergy Arkansas, Entergy Gulf States Louisiana, 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, 2014 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 Board of Directors and Shareholders of
Entergy Corporation and Subsidiaries
New Orleans, Louisiana

We have audited the internal control over financial reporting of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2014, based on criteria established in Internal Control -Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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 conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control -Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2014 of the Corporation and our report dated February 26, 2015 expressed an unqualified opinion on those consolidated financial statements.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana
February 26, 2015

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PART III

Item 10.  Directors and Executive Officers of the Registrants (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, 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 8, 2015, 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
 
 
 
 
 
 
Hugh T. McDonald
 
56
 
President and Chief Executive Officer of Entergy Arkansas
 
2000-Present
 
 
 
 
Director of Entergy Arkansas
 
2000-Present
 
 
 
 
 
 
 
Theodore H. Bunting, Jr.
 
 
 
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.
 
 
Mark T. Savoff
 
 
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Officers
 
 
 
 
 
 
 
 
 
Marcus V. Brown
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Theodore H. Bunting, Jr.
 
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.
 
 
Jeffrey S. Forbes
 
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.
 
 
Hugh T. McDonald
 
See information under the Entergy Arkansas Directors Section above.
 
 
Alyson M. Mount
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Mark T. Savoff
 
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 GULF STATES LOUISIANA, L.L.C.
Directors
 
 
 
 
Phillip R. May, Jr.
52
Director of Entergy Gulf States Louisiana and Entergy Louisiana
 
2013-Present
 
 
President and Chief Executive Officer of Entergy Gulf States Louisiana and Entergy Louisiana
 
2013-Present
 
 
Vice President, Regulatory Services of Entergy Services, Inc.
 
2002-2013
 
 
 
 
 
Theodore H. Bunting, Jr.
 
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.
 
 
Mark T. Savoff
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Officers
 
 
 
 
 
 
 
 
 
Marcus V. Brown
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Theodore H. Bunting, Jr.
 
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.
 
 
Jeffrey S. Forbes
 
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 Gulf States Louisiana Directors Section above.
 
 
Alyson M. Mount
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Mark T. Savoff
 
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 LOUISIANA, LLC
Directors
 
 
 
 
 
 
 
 
 
Phillip R. May, Jr.
 
See information under the Entergy Gulf States Louisiana Directors Section above.
 
 
Theodore H. Bunting, Jr.
 
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.
 
 
Mark T. Savoff
 
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.
 
 
Theodore H. Bunting, Jr.
 
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.
 
 
Jeffrey S. Forbes
 
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 Gulf States Louisiana Directors Section above.
 
 
Alyson M. Mount
 
See information under the Entergy Corporation Officers Section in Part I.
 
 
Mark T. Savoff
 
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
49
President and Chief Executive Officer of Entergy Mississippi
 
2008-Present
 
 
Director of Entergy Mississippi
 
2008-Present
 
 
 
 
 
Theodore H. Bunting, Jr.
 
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.
 
 
Mark T. Savoff
 
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.
 
 
Theodore H. Bunting, Jr.
 
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.
 
 
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.
 
 
Mark T. Savoff
 
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, INC.
Directors
 
 
 
 
Charles L. Rice, Jr.
50
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, L.L.C.
 
2005-2009
 
 
 
 
 
Theodore H. Bunting, Jr.
 
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.
 
 
Mark T. Savoff
 
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.
 
 
Theodore H. Bunting, Jr.
 
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.
 
 
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.
 
 
Mark T. Savoff
 
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
53
Director of Entergy Texas
 
2012-Present
 
 
President and Chief Executive Officer 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
 
 
 
 
 
Theodore H. Bunting, Jr.
 
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.
 
 
Mark T. Savoff
 
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.
 
 
Theodore H. Bunting, Jr.
 
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.
 
 
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.
 
 
Mark T. Savoff
 
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 stockholder with the exception of the directors and officers of Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, LLC, who are elected yearly to serve by the unanimous consent of the sole common membership owners, EGS Holdings, Inc. and Entergy Louisiana Holdings, respectively.  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:

Steven V. Wilkinson (Chairman)
Maureen S. Bateman
Stuart L. Levenick
Blanche L. Lincoln

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.  Steven V. Wilkinson qualifies as an “audit committee financial expert,” as that term is defined in the SEC rules.


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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 Provision 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 required 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 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 does not have any single method for identifying director candidates but will consider candidates suggested by a wide range of sources including director candidates recommended by 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 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 set forth above; and
•
the candidate’s signed consent to serve as a director if elected and to be named in the Proxy Statement.
    
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 8, 2015, 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 GULF STATES LOUISIANA, 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 2014 is discussed. Each officer’s title is provided as of December 31, 2014.
Name
Title
Leo P. Denault
Chairman of the Board and Chief Executive Officer
Haley R. Fisackerly
President, Entergy Mississippi
Andrew S. Marsh
Executive Vice President and Chief Financial Officer Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans and Entergy Texas
Phillip R. May, Jr.
President, Entergy Gulf States Louisiana and Entergy Louisiana
Hugh T. McDonald
President, Entergy Arkansas
Alyson M. Mount
Senior Vice President and Chief Accounting Officer Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans and Entergy Texas
Sallie T. Rainer
President, Entergy Texas
Charles L. Rice, Jr.
President, Entergy New Orleans
Mark T. Savoff
Executive Vice President and Chief Operating Officer
Roderick K. West
Executive Vice President and Chief Administrative Officer

Mr. Denault, Mr. Marsh, Ms. Mount, Mr. Savoff, and Mr. West serve as executive officers of Entergy Corporation. No additional compensation was paid in 2014 to Mr. Denault, Mr. Marsh, Ms. Mount, Mr. Savoff, or Mr. West for their service as Named Executive Officers of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas (the “Subsidiaries”). Ms. Mount is included in the Executive Compensation section of this Form 10-K because she served as the principal financial officer of the Subsidiaries for a portion of 2014.



Table of Contents

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. Following are some highlights of Entergy Corporation’s executive compensation practices:

Things Entergy Corporation Does

•
Require a “double trigger” for severance payments or equity acceleration in the event of a change in control
•
Maintain a “clawback” policy that goes beyond Sarbanes-Oxley requirements
•
Cap the maximum payout 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
•
Require minimum vesting periods for equity based awards
•
Target the long-term compensation mix to give more weight to performance units than to time-based restricted stock and stock options combined
•
Settle 100% of long-term performance unit payouts in shares of Entergy stock
•
Require executives to hold substantially all equity compensation received from Entergy Corporation until stock ownership guidelines are met
•
Prohibit directors and officers from pledging or entering into hedging or other derivative transactions with respect to their Entergy Corporation shares

Things Entergy Corporation Doesn’t Do

•
No 280(G) tax “gross up” payments in the event of a change in control
•
No option repricing or cash buy-outs for underwater options under the equity plans
•
No agreements providing for severance payments to executive officers that exceed 2.99 times annual base salary and annual incentive awards without shareholder approval
•
No unusual or excessive perquisites
•
New officers are excluded from participation in the System Executive Retirement Plan
•
No grants of supplemental service credit for newly-hired officers under any of Entergy Corporation's non-qualified retirement plans

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. In keeping with this philosophy approximately 80% of the annual target compensation of Entergy Corporation’s Chief Executive Officer is “at risk,” equity or performance-based compensation.

2014 Incentive Pay Outcomes

Pay outcomes for the Named Executive Officers during 2014 demonstrated the application of this pay-for-performance philosophy.

Annual Incentive Plan Awards

Awards under Entergy Corporation’s Annual Incentive Plan are tied to its financial performance through the Entergy Achievement Multiplier, which is the performance metric used to determine the funding of awards under the plan. For 2014, the Entergy Achievement Multiplier was determined based in equal part on Entergy Corporation’s success in achieving its operational earnings per share and operating cash flow goals. These goals were approved by the Personnel Committee at the beginning of the year based on Entergy Corporation’s financial plan and the Board’s overall goals for Entergy Corporation and were consistent with its published earnings guidance.

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For 2014, the Personnel Committee, based on the recommendation of the Finance Committee, determined that management exceeded its operational earnings per share goal of $5.00 per share by $0.83 per share and exceeded its operational operating cash flow goal of $3.43 billion by approximately $517 million. Based on the targets previously determined by the Committee, Entergy Corporation’s outstanding financial performance in 2014 would have resulted in an Entergy Achievement Multiplier of 200% of target. From a qualitative standpoint, the Committee also took into account management’s strong performance executing on Entergy Corporation’s strategies in 2014 and various accomplishments and challenges in 2014. Included in those challenges was a decline in Entergy Corporation’s employee safety performance, as a result of which the Committee decided to exercise its discretion to reduce the calculated Entergy Achievement Multiplier to 195%. This resulted in payouts under the Annual Incentive Plan to the Named Executive Officers who are members of the Office of the Chief Executive, including Entergy Corporation’s Chief Executive Officer, at 195% of each officer’s target award, which the Personnel Committee considered to be appropriate in light of management’s performance and the outstanding results achieved in 2014.
  
Long-Term Performance Unit Program Payouts

Under the Long-Term Performance Unit Program, a substantial portion of targeted executive officer pay is tied directly to Entergy Corporation’s relative total shareholder return. Under this program, Entergy Corporation measures performance over a three-year period by assessing Entergy’s total shareholder return in relation to the total shareholder return of the companies included in the Philadelphia Utility Index, with payouts based solely on Entergy Corporation’s performance relative to the other companies in the index. Entergy Corporation measures performance based on relative total shareholder return because it encourages the executives to deliver superior shareholder value in relation to Entergy Corporation’s peers and rewards not just stock price appreciation, but also the ability to deliver significant dividends to shareholders, and takes into account market fluctuations in the utility sector.

Entergy Corporation’s total shareholder return, which had substantially lagged the returns of its peer group in 2012, improved significantly in 2013 and, for 2014, was near the top of the Philadelphia Utility Index. As a result, following a review by the Finance Committee and the Personnel Committee of Entergy Corporation’s total shareholder return in relation to the total shareholder return of the companies in the Philadelphia Utility Index, the Personnel Committee determined that Entergy Corporation’s relative total shareholder return fell within the third quartile of the Philadelphia Utility Index for the 2012-2014 performance period, resulting in payouts of 64.64% of target. Such payouts were made 100% in shares of Entergy Corporation stock that are required to be held by the executives until they satisfy the executive stock ownership guidelines.

What Entergy Corporation Pays and Why

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. Entergy Corporation believes the executive pay programs described in this section and in the accompanying tables have played a material 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 operational financial metrics that are deemed by the Personnel Committee to be consistent with the overall goals and strategic direction that the Board has approved for Entergy Corporation. Entergy Corporation’s long-term incentive programs further align the interests of its executives and its shareholders by directly tying the value of the equity awards granted to executives under these programs to the performance of Entergy Corporation’s stock price and its 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 its owners, customers, employees, and communities.
 

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How Entergy Corporation Sets Target Pay

To develop a competitive compensation program, the Personnel Committee annually reviews compensation data from two sources:

Survey Data

The Committee uses published and private compensation survey data to develop marketplace compensation levels for the executive officers. The data, which are compiled by Pay Governance, LLC, the Committee’s independent compensation consultant, 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. For non-industry specific positions such as a chief financial officer, the Committee reviews 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, the Committee reviews data from utility companies for total cash compensation. However, for long-term incentives, all positions are reviewed relative to utility market data. The survey data reviewed by the Committee cover hundreds of companies across a broad range of industries and over 60 investor-owned utility companies in the utility sector. In evaluating compensation levels against the survey data, the Committee considers only the aggregated survey data. The identities of the companies participating in 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. 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 eight (8) other executive officers who constitute what Entergy Corporation refers to as its Office of the Chief Executive each have 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, corporate performance, and internal pay equity. For 2014, the total target compensation of each of the Named Executive Officers fell within the targeted range except for three officers whose total target compensation fell below the targeted range.

Proxy Analysis

Although the survey data described above are the primary data used in determining 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 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, based on pay rank and without regard to roles and responsibilities, except with respect to the Chief Executive Officer and Chief Financial Officer, for whom comparable roles are used. The Personnel Committee uses this analysis to evaluate the overall reasonableness of the Entergy Corporation’s compensation programs. The following companies were included in the Philadelphia Utility Index at the time the proxy data from the 2014 filings of the Index were compiled:



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Ÿ
AES Corporation
Ÿ
El Paso International
 
Ÿ
Ameren Corporation
Ÿ
Exelon Corporation
 
Ÿ
American Electric Power Co. Inc.
Ÿ
FirstEnergy Corporation
 
Ÿ
CenterPoint Energy Inc.
Ÿ
NextEra Energy
 
Ÿ
Consolidated Edison Inc.
Ÿ
Northeast Utilities
 
Ÿ
Covanta Holding Corporation
Ÿ
PGE Corporation
 
Ÿ
Dominion Resources Inc.
Ÿ
Public Service Enterprise Group, Inc.
 
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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 target direct compensation granted or paid to the executive officers under the 2014 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. Incentives are designed to drive overall corporate performance, specific business unit strategies, and individual performance using performance and operational measures the Committee believes correlate to shareholder value and align with Entergy Corporation’s strategic vision and operating priorities. The 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.

Element
Key Characteristics
Why This Element Is Paid
How This Amount Is Determined
2014 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 2%-5%.
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 equity.
 
For 2014, awards were determined based on success in meeting operational earnings per share and operating cash flow targets, subject to downward adjustment at the Personnel Committee’s discretion.
The CEO’s target annual incentive award for 2014 was 120% of base salary, and target awards were in the range of 40%-70% of base salary for the other Named Executive Officers.

Strong operational and financial performance resulted in awards in the range of 130%-195% of target for each of the Named Executive Officers, after downward adjustment for failure to meet Board expectations as to safety performance.
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 granted in 2014 represented approximately 12% of total target compensation for Entergy Corporation’s Chief Executive Officer and approximately 7%-10% for the other Named Executive Officers.

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Element
Key Characteristics
Why This Element Is Paid
How This Amount Is Determined
2014 Decisions
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’s common stock.
Job scope, market data, individual performance, and Entergy Corporation performance.

Restricted stock granted in 2014 represented approximately 12% of total target compensation for Entergy Corporation’s Chief Executive Officer and approximately 7%-10% for the other Named Executive Officers.

Long-Term Performance Unit Program
Each performance unit equals the value of 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 are settled in shares of Entergy common stock rather than in cash.
Focuses the executive officers on building long-term shareholder value and increases the executive officers’ ownership of Entergy Corporation’s common stock.

Payout based on Entergy Corporation’s total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index.

Performance unit grants for the 2014 to 2016 performance cycle represented approximately 34% of total target compensation for Entergy Corporation’s Chief Executive Officer and approximately 22%-31% for the other Named Executive Officers.

Strong relative total shareholder return for 2014 resulted in third quartile performance for the 2012 to 2014 performance period, yielding a payout of 64.64% of target for the Named Executive Officers.

Short-Term Compensation

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 2014, all of the Named Executive Officers received merit increases in their base salaries ranging from 2 to 5 percent. The increases in base salary were made in light of current economic conditions and the projected growth in executive salaries in 2014 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.


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The following table sets forth the 2013 and 2014 base salaries for the Named Executive Officers. Changes in base salaries for 2014 were effective in April.

Named Executive Officer
 
2013 Base Salary
 
2014 Base Salary
Leo P. Denault
 
$1,085,000
 
$1,110,000
Haley R. Fisackerly
 
$296,174
 
$302,934
Andrew S. Marsh
 
$500,000
 
$517,500
Phillip R. May, Jr.
 
$330,000
 
$338,250
Hugh T. McDonald
 
$345,220
 
$352,121
Alyson M. Mount
 
$286,700
 
$301,100
Sallie T. Rainer
 
$291,000
 
$298,275
Charles L. Rice, Jr.
 
$257,144
 
$262,287
Mark T. Savoff
 
$632,251
 
$644,896
Roderick K. West
 
$612,726
 
$628,044

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.

Under the Annual Incentive Plan, Entergy Corporation uses a performance metric known as the Entergy Achievement Multiplier to determine the percentage of target annual plan opportunities that will be paid each year to each Named Executive Officer, subject to adjustment based on individual performance. For 2014, the Personnel Committee maintained the following target award levels of base salary for the Named Executive Officers:

•
120% for Mr. Denault;
•
70% for Mr. Marsh, Mr. Savoff, and Mr. West;
•
60% for Mr. May and Ms. Mount;
•
50% for Mr. McDonald; and
•
40% for Mr. Fisackerly, Ms. Rainer, and Mr. Rice.

The target opportunities established for these officers were comparable to the target opportunities historically set for these positions and levels of responsibility. The Named Executive Officers who are members of the Office of the Chief Executive may earn a payout ranging from 0% to 200% of their target opportunity calculated as described in the table below. The target awards for the Named Executive Officers (other than the Entergy Corporation Named Executive Officers) were set by their respective supervisors (subject to ultimate approval of Entergy Corporation’s Chief Executive Officer) who allocated a potential incentive pool established by the Personnel Committee among various of their direct and indirect reports.

Target awards are set based on an executive officer’s position and executive management level within the Entergy organization. Executive management levels at Entergy range from Level 1 through Level 4. At December 31, 2014, Mr. Denault held a Level 1 position, Messrs. Marsh, Savoff, and West held positions in Level 2, Ms. Mount and Mr. May held Level 3 positions and the remaining Named Executive Officers held positions in Level 4. Accordingly, their respective incentive targets differ one from another based on the external market data developed by the Committee’s independent compensation consultant and the other factors noted above.

Each year the Personnel Committee reviews the performance measures used to determine the Entergy Achievement Multiplier. In December 2013, the Personnel Committee decided to retain for 2014 the performance measures used for determining the 2013 Entergy Achievement Multiplier. These measures were operational earnings per share and operating cash flow, with each measure weighted equally. The Committee considered a variety of other potential measures, but determined that operational earnings per share and operating cash flow continued to be the

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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 targets for the Annual Incentive Plan 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 for Entergy Corporation, 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, including changes in commodity market conditions and other key drivers of anticipated changes in performance from the preceding year. The Committee further confirms that the targets it approves are aligned with the earnings guidance that will be communicated to the financial markets, which assures that the internal targets approved for purposes of Entergy Corporation’s incentive compensation plans are aligned with the external expectations set and communicated to its shareholders.

In December 2013, after full Board review of management’s 2014 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 bonuses for 2014. 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 as-reported results of activities related to special items that would be excluded in determining operational results, and the effect of any major storms that may occur during the year.

The following table shows the Annual Incentive Plan targets established by the Personnel Committee in December 2013, and 2014 results:

Annual Incentive Plan Targets and Results
 
Performance Goals(1)
 
 
Minimum
Target
Maximum
2014 Results
Operational Earnings Per Share ($)
$4.50
$5.00
$5.50
$5.83
Operational Operating Cash Flow ($ billion)
$3.02
$3.43
$3.84
$3.947
Payout as % of Target
25%
100%
200%
195%(2)
(1)
Payouts for performance between minimum and target achievement levels and between target and maximum levels are calculated using straight-line interpolation. There is no payout for performance below minimum.
(2)
Reflects downward adjustment by Personnel Committee, as further described below.

In January 2015, the Finance and Personnel Committees reviewed Entergy Corporation’s financial results against the performance objectives reflected in the table above. Based on the Finance Committee’s recommendation, the Personnel Committee determined that management exceeded its operational earnings per share goal of $5.00 per share by $0.83 per share and exceeded its operational operating cash flow goal of $3.43 billion by approximately $517 million. Operational results excluded from as-reported results special items recorded for (i) expenses associated with the shutdown in December 2014 of the Vermont Yankee Nuclear Power Station and the related settlement agreement reached with the State of Vermont in 2014, and (ii) expenses for the implementation of the Human Capital Management strategic imperative in 2014. The exclusion of these items was consistent with the Committee’s decision to approve the annual incentive plan targets for 2014 on the basis of Entergy Corporation’s operational financial results, because such results form the basis for Entergy Corporation’s financial plan and guidance to investors and are the primary basis on which its financial performance is evaluated by investors.

Based on the targets previously determined by the Committee, Entergy Corporation’s outstanding financial performance in 2014 exceeded the maximum target achievement approved by the Committee, and would have resulted

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in an Entergy Achievement Multiplier of 200%. However, in determining the Entergy Achievement Multiplier, the Committee also took into account management’s strong performance executing on Entergy Corporation’s strategies in 2014 and various accomplishments and challenges in 2014. Included in those challenges was a decline in Entergy Corporation’s employee safety performance from 2013, which included an increase in OSHA recordable accidents from the preceding year and two electrical contact incidents involving critical safety rule violations. The Committee concluded that despite management’s outstanding performance overall and Entergy Corporation’s strong financial performance for the year, this decline in safety performance warranted a downward adjustment in the Entergy Achievement Multiplier to 195%.

Based on the foregoing evaluation of management performance and the recommendation of the Finance Committee, the Personnel Committee certified an Entergy Achievement Multiplier of 195% for 2014 for the members of the Office of the Chief Executive. After the Entergy Achievement Multiplier was established to determine overall funding for the Annual Incentive Plan, Entergy Corporation’s Chief Executive Officer allocated incentive award funding to the business units based on their business unit results (referred to as the “line of business multiplier). Individual awards were determined based on the line of business multiplier as well as individual officer performance taking into account customer, operational, and safety measures.

The following table shows the Annual Incentive Plan payouts to each Named Executive Officer for 2014.

Named Executive Officer
Base Salary
Target as Percentage of Base Salary
Payout as Percentage of Base Salary
2014 Annual
Incentive Award
Leo P. Denault
$1,110,000
120%
234%
$2,597,400
Haley R. Fisackerly
$302,934
40%
64%
$193,878
Andrew S. Marsh
$517,500
70%
137%
$706,388
Phillip R. May, Jr.
$338,250
60%
78%
$263,835
Hugh T. McDonald
$352,121
50%
65%
$228,879
Alyson M. Mount
$301,100
60%
108%
$325,188
Sallie T. Rainer
$298,275
40%
58%
$171,500
Charles L. Rice, Jr.
$262,275
40%
64%
$167,864
Mark T. Savoff
$644,896
70%
137%
$880,283
Roderick K. West
$628,044
70%
137%
$857,280

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 its shareholders. In its long-term incentive compensation program, Entergy Corporation uses a mix of performance units, restricted stock, and stock options. 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. 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, all based on their grant date fair values. Awards for individual Named Executive Officers may vary from this target as a result of individual performance, promotions, and internal pay equity.

All of the performance units, shares of restricted stock, and stock options granted to the Named Executive Officers in 2014 were awarded under Entergy Corporation’s 2011 Equity Ownership Plan and Long-Term Cash

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Incentive Plan (“2011 Equity Ownership Plan”), which requires both a change in control and an involuntary job loss or substantial diminution of duties (a “double trigger”) for the acceleration of these awards upon a change in control.

Performance Unit Program

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’s common stock at the end of the three-year performance period, plus dividends accrued during the performance period. The Personnel Committee approves 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 common stock rather than cash. 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. 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, approximate 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. The range of potential payouts under the program is shown below.

Performance Level
Minimum
Target
Maximum
Total Shareholder Return
Bottom of Third Quartile
50th  percentile
Top Quartile
Payout
25% of target
100% of target
200% of Target

There is no payout for performance below the 25th percentile. Payouts between minimum and target and between target and maximum are calculated by interpolating between the bottom position of the third quartile and the median or between the median and the bottom position of the top quartile, respectively. For top quartile performance, a maximum payout of 200% of target is earned. At any given time, a participant in the Long-Term Performance Unit Program may be participating in up to three performance periods. Currently, participants are participating in the 2013-2015, the 2014-2016, and the 2015-2017 performance periods.

Performance Unit Program Grants. Subject to achievement of the applicable performance levels, the Personnel Committee established the following target performance unit payout opportunities for each of the 2012-2014, 2013-2015, and 2014-2016 performance periods. Each Named Executive Officer received a larger number of performance units in 2013 and 2014 than were granted to officers at their respective levels in the preceding years to reflect the lower stock price at the time of the award as compared to the preceding year and a slight increase in targeted long-term value required to result in awards approximating the 50th percentile of the utility market data.

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Named Executive Officer
2012-2014 Target Opportunity
2013-2015 Target Opportunity
2014-2016 Target Opportunity
Leo P. Denault(1)
19,136
37,156
40,000
Haley R. Fisackerly
1,500
1,900
2,200
Andrew S. Marsh(1)
3,992
7,442
9,400
Phillip R. May, Jr.(1)
2,075
2,969
3,100
Hugh T. McDonald
1,500
1,900
2,200
Alyson M. Mount
2,067
3,000
3,100
Sallie T. Rainer
1,292
1,900
2,200
Charles L. Rice, Jr.
1,500
1,900
2,200
Mark T. Savoff
5,400
7,600
9,400
Roderick K. West
5,400
7,600
9,400
(1)
Messrs. Denault, Marsh, and May received pro-rated awards for the 2012-2014 and 2013-2015 performance cycles as a result of their promotions in 2013.

     Payout for the 2012-2014 Performance Period. In January 2015, the Committee reviewed the Entergy Corporation’s total shareholder return for the 2012-2014 performance period in order to determine the payout to participants for the 2012-2014 performance period. 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 2012-2014 performance similar to the range of payouts discussed above for the 2014-2016 performance period. As recommended by the Finance Committee, the Personnel Committee determined that Entergy Corporation’s relative total shareholder return fell within the third quartile of the Philadelphia Utility Index for the 2012-2014 performance period, resulting in payouts to the Named Executive Officers of 64.64% of target. Beginning with the 2012-2014 performance period, payouts under the performance unit program are made in shares of Entergy common stock. For the 2012-2014 performance period, the following numbers of shares of Entergy common stock were issued:

•
Mr. Denault - 13,777 shares;
•
Mr. Marsh - 2,874 shares;
•
Mr. Savoff and Mr. West - 3,888 shares;
•
Mr. May - 1,494 shares;
•
Ms. Mount - 1,462 shares;
•
Mr. Fisackerly, Mr. McDonald, and Mr. Rice - 1,080 shares; and
•
Ms. Rainer - 914 shares.

Stock Options and Restricted Stock
Entergy Corporation grants stock options and restricted stock as part of the long-term incentive program 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 individual performance, 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. 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. Mr. Denault's 2014 awards are comparable to historical awards granted to Entergy Corporation's Chief Executive Officer and reflects the decreased stock price at the time of grant. The Committee, in consultation with Entergy Corporation’s Chief Executive Officer, reviews each other Named Executive Officer’s performance, role and responsibilities, strengths, and developmental opportunities. Stock option and restricted stock awards for Entergy Corporation’s Chief Executive Officer are determined solely by the Personnel Committee on the basis of the same considerations. For all equity awards, the Committee also considers Entergy Corporation’s significant achievements for the prior year.


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The following table sets forth the number of stock options and shares of restricted stock granted to each Named Executive Officer in 2014. The exercise price for each option was $63.17, which was the closing price of Entergy’s common stock on the date of grant.
Named Executive Officer
Stock Options
Shares of Restricted Stock
Leo P. Denault
106,000
13,900
Haley R. Fisackerly
5,800
1,400
Andrew S. Marsh
35,000
4,900
Phillip R. May, Jr.
8,000
1,800
Hugh T. McDonald
5,500
1,300
Alyson M. Mount
8,500
1,800
Sallie T. Rainer
5,800
1,400
Charles L. Rice, Jr.
5,200
1,150
Mark T. Savoff
27,500
4,200
Roderick K. West
36,000
6,000

Benefits, Perquisites, Agreements and Post-Termination Plans
Retirement Plans
The Named Executive Officers participate in an Entergy Corporation-sponsored tax qualified final average pay defined benefit pension plan that covers a broad group of employees. In addition, each Named Executive Officer participates in the Pension Equalization Plan, a non-qualified restoration plan, and the System Executive Retirement Plan, a non-qualified supplemental retirement plan. Both plans are sponsored by Entergy Corporation. Under the terms of the Pension Equalization Plan and System Executive Retirement Plan, an employee participating in both plans is eligible to receive only the greater of the two benefits computed in accordance with the terms of, and conditions of each plan.

Effective July 1, 2014, the Pension Equalization Plan was amended to provide that employees who participate in Entergy Corporation’s new cash balance pension plan are not eligible to participate in the Pension Equalization Plan. These employees instead will participate in a new cash balance restoration plan. In addition, the Pension Equalization Plan and all other non-qualified plans sponsored by Entergy Corporation were amended, as necessary, to eliminate the grant of supplemental credited service to new executive officers under any of those plans. The plan amendments were authorized by the Personnel Committee after reviewing comparative market data to better align Entergy Corporation’s retirement plans with emerging market practice. Also to better align with emerging market practice, effective July 1, 2014, the System Executive Retirement Plan and the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries were closed to new participants.

See the 2014 Pension Benefits Table for additional information regarding the operation of the plans described under this caption.

Savings Plan

The Named Executive Officers are eligible to participate in Entergy Corporation-sponsored Savings Plan that covers a broad group of employees. The Savings Plan is a tax-qualified 401(k) retirement savings plan, wherein total combined before-tax and after-tax contributions may not exceed 30% of a participant’s base salary up to certain contribution limits defined by law. In addition, under the Savings Plan, the employer of Savings Plan participants, who participate in the final average pay defined benefit pension plan, matches an amount equal to seventy cents for each dollar contributed by participating employees, including the Named Executive Officers, with respect to the first six percent of their eligible earnings under the plan for that pay period.


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Executive Deferred Compensation Plan

The Named Executive Officers are eligible to defer up to 100% of their Annual Incentive Plan awards into either or both of the Entergy Corporation-sponsored Executive Deferred Compensation Plan and the 2011 Equity Plan. In addition, they are eligible to defer up to 100% of their base salary into the Executive Deferred Compensation Plan. Entergy Corporation believes that providing this benefit is important as a retention and recruitment tool because many, if not all, of the companies with which it competes for executive talent provide a similar arrangement to their senior executive officers. See the 2014 Non-qualified Deferred Compensation discussion for additional information regarding the operation of the Executive Deferred Compensation Plan.

Health & Welfare Benefits

The Named Executive Officers are eligible to participate in various health and welfare benefits available to a broad group of employees. These benefits include 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.

Executive Disability Plan

All of the executive officers, including the Named Executive Officers, are eligible to participate in the Executive Disability Plan of Entergy Corporation and Subsidiaries. Individuals who elect to participate in this plan and become disabled under the terms of the plan are eligible for 65% of the difference between their base salary and $276,923 (i.e. the base salary that produces the maximum $15,000 monthly disability payment under the general long-term disability plan).

Perquisites

Entergy Corporation provides the Named Executive Officers with a limited number of perquisites and other personal benefits as part of providing a competitive executive compensation program and for employee retention. The Personnel Committee reviews all perquisites, including the personal use of corporate aircraft, on an annual basis. In 2014, the Named Executive Officers were offered corporate aircraft usage, relocation assistance, annual physical exams, and event tickets. Named Executive Officers who are not members of the Office of Chief Executive were provided in 2014 with club dues and tax gross up payment on some perquisites. For security and business convenience reasons, Entergy Corporation’s Chief Executive Officer is allowed to use corporate aircraft at Entergy Corporation’s expense for personal use. The other Named Executive Officers may use corporate aircraft for personal travel subject to the approval of Entergy Corporation’s Chief Executive Officer. From time to time, tickets to cultural and sporting events are made available to employees, including the Named Executive Officers, for business purposes. If not utilized for business purposes, the tickets are made available to employees, including the Named Executive Officers, for personal use. Entergy Corporation does not provide personal financial counseling. Relocation benefits to executive officers, including tax gross-up payments, are similar to those provided to all eligible employees. For additional information regarding perquisites, see the “All Other Compensation” column in the Summary Compensation Table.

Post-Termination Agreements and other Compensation Arrangements

The 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 all or nearly all of the companies with which Entergy Corporation competes for executive talent have similar arrangements in place for its 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

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officer’s employment is involuntarily terminated in connection with a change in control of Entergy Corporation. Severance payments under the System Executive Continuity Plan 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 fiscal years immediately preceding the fiscal year in which the termination of employment occurs. Under no circumstances can this multiple exceed 2.99 times the sum of (a) the executive officer’s annual base salary as in effect at any time within one year prior to the commencement of a change in control period or if higher, immediately prior to a circumstance constituting good reason plus (b) his or her annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the officer’s termination occurs, or if higher the annual incentive award actually received under the Annual Incentive Plan for the fiscal year immediately preceding the fiscal year in which the termination of employment occurs. Entergy Corporation strives to ensure that the benefits and payment levels under the System Executive Continuity Plan are consistent with market practices. 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 “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 has a retention agreement with Mr. Denault. In general, Mr. Denault’s retention agreement provides for severance payments and other benefits in the event of termination of employment other than for cause or on account of death or disability in lieu of those provided under the System Executive Continuity Plan. As with any severance benefits paid under the System Executive Continuity Plan, Mr. Denault will not receive tax gross-up payments on any severance 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 plays 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 believes the benefits and payment levels under Mr. Denault’s retention agreement are consistent with market practices.

For additional information regarding the System Executive Continuity Plan and Mr. Denault’s retention agreement described above, see “2014 Potential Payments Upon Termination or Change in Control."

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 the utility industry as well as other companies in the S&P 500. Some of these practices include the following:

Clawback Provisions

Entergy Corporation has adopted a clawback policy that covers all individuals subject to Section 16 of the Exchange Act, including all of the members of the Office of the Chief Executive. Under the policy, 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

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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 the financial statements, Entergy Corporation will seek to recover any compensation received by its Chief Executive Officer and Chief Financial Officer that is required to be reimbursed under Section 304 of the Sarbanes-Oxley Act of 2002.

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. The ownership guidelines are as follows:

Role
Value of Common Stock to be Owned
Chief Executive Officer
6 times base salary
Executive Vice Presidents
3 times base salary
Senior Vice Presidents
2 times base salary
Vice Presidents
1 time base salary

Further, to 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 Entergy Corporation’s restricted stock 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.

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 open trading windows occurring 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 company 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’s securities or entering into margin accounts involving Entergy securities. It prohibits these transactions because of the potential that sales of Entergy Corporation’s securities could occur outside trading periods and without the required approval of the General Counsel.

Entergy Corporation also has adopted an anti-hedging policy that prohibits officers, directors, and employees from entering into hedging or monetization transactions involving its common stock. Prohibited transactions include,

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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 the Entergy Corporation’s stock or transactions involving “short-sales” of its stock. Entergy Corporation's Board of Directors adopted this policy to require officers, directors, and employees to continue to own Entergy Corporation stock with the full risks and rewards of ownership, thereby ensuring continued alignment of their objectives with those of Entergy Corporation’s other shareholders.
 
Roles and Responsibilities

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 the Named Executive Officers. The Committee works with Entergy Corporation’s executive management to ensure that the compensation policies and practices are consistent with Entergy Corporation’s values and support the successful recruitment, development, and retention of executive talent so Entergy Corporation can achieve its business objectives and optimize its long-term financial returns. Each year, Entergy Corporation’s Senior Vice President, Human Resources and Chief Diversity Officer presents 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 the compensation policies and practices are consistent with Entergy Corporation’s 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 the 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. Entergy Corporation’s Chief Executive Officer provides the Personnel Committee with an assessment of the performance of each of the other Named Executive Officers and recommends compensation levels to be awarded to each of them. In addition, the Committee may request that the Chief Executive Officer provide management feedback and recommendations on changes in the design of compensation programs, such as special retention plans or changes in the structure of bonus programs. However, Entergy Corporation’s 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 senior human resources executives with respect to compensation decisions, policies, and practices.

Entergy Corporation’s Chief Executive Officer may attend meetings of the Personnel Committee only at the invitation of the chair of the Personnel Committee and cannot call a meeting of the Committee. In addition, he is not in attendance at the portion of any meeting when the Committee approves the compensation to be paid to the Named Executive Officers. Since he is not a member of the Committee, he has no vote on matters submitted to the Committee. During 2014, Mr. Denault attended 6 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. In 2014, the Personnel Committee 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 the compensation programs.

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During 2014, 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 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 plan for consideration by the Committee. A senior consultant from Pay Governance attended all Personnel Committee meetings to which he was invited in 2014.

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 and 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 2014, the Personnel Committee’s independent compensation consultant, Pay Governance LLC, did not provide any services to Entergy Corporation other than its services to the Personnel Committee. 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 Code limits the tax deductibility by a publicly held corporation of compensation in excess of $1 million paid to the Chief Executive Officer or any of its other Named Executive Officers who may be Section 162(m) covered employees, unless that compensation is “performance-based compensation” within the meaning of Section 162(m). The Personnel Committee considers deductibility under Section 162(m) as it structures the compensation packages that are provided to its Named Executive Officers. Likewise, the Personnel Committee considers financial accounting consequences as it structures the compensation packages that are provided to the Named Executive Officers. However, the Personnel Committee and the Board believe that it is in the best interest of Entergy Corporation that the Personnel Committee retains the flexibility and discretion 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 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

2014 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, 2014, and to the extent required by SEC rules, for the fiscal years ended 2013 and 2012.  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.  None of the Entergy System companies has entered into any employment agreements with any of the Named Executive Officers (other than the retention agreements described in “2014 Potential Payments upon Termination or Change in Control”).  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
 
 
 
 
 
 
 
Year
 
 
 
 
 
 
 
 
Salary
(1)(2)
 
 
 
 
 
 
 
Bonus
(3)
 
 
 
 
 
 
Stock
Awards
 (4)
 
 
 
 
 
 
Option
Awards
 (5)
 
 
 
 
Non-Equity
Incentive
Plan
Compensation
(6)
 
Change in
Pension
Value and
Non-qualified
Deferred
Compensation
Earnings
 (7)
 
 
 
 
 
All
Other
Compensation (8)
 
 
 
 
 
 
 
Total
 
Leo P. Denault
 
2014
 

$1,103,173

 

$—

 

$3,564,463

 

$923,260

 

$2,597,400

 

$3,578,200

 

$57,538

 

$11,824,034

Chairman of the
 
2013
 

$1,039,253

 

$—

 

$3,780,189

 

$400,000

 

$1,770,720

 

$630,800

 

$44,690

 

$7,665,652

Board and CEO -
 
2012
 

$669,564

 

$—

 

$647,594

 

$282,600

 

$448,779

 

$972,400

 

$22,657

 

$3,043,594

Entergy Corp.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Haley R. Fisackerly
 
2014
 

$300,941

 

$—

 

$236,190

 

$50,518

 

$193,878

 

$281,100

 

$33,311

 

$1,095,938

CEO - Entergy
 
2013
 

$294,090

 

$10,000

 

$214,624

 

$48,000

 

$142,368

 

$—

 

$28,058

 

$737,140

Mississippi
 
2012
 

$287,296

 

$30,000

 

$186,225

 

$43,332

 

$139,000

 

$284,900

 

$26,781

 

$997,534

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Andrew S. Marsh
 
2014


$512,721



$—



$940,837



$304,850



$706,388



$750,900



$26,722



$3,242,418

Executive Vice
 
2013
 

$477,846

 

$—

 

$921,927

 

$256,000

 

$476,000

 

$157,700

 

$213,663

 

$2,503,136

President and CFO -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Corp.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Acting principal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
financial officer
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Arkansas,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Gulf States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Louisiana, Entergy
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Louisiana, Entergy
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mississippi, Entergy
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
New Orleans,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Texas
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Phillip R. May, Jr.
 
2014
 

$335,997

 

$—

 

$321,902

 

$69,680

 

$263,835

 

$546,000

 

$20,641

 

$1,558,055

CEO - Entergy Gulf
 
2013


$321,860



$5,000



$325,813



$48,000



$238,223



$—



$16,547



$955,443

States Louisiana and
 

























Entergy Louisiana
 

























 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Hugh T. McDonald
 
2014
 

$350,104

 

$—

 

$229,873

 

$47,905

 

$228,879

 

$400,800

 

$48,766

 

$1,306,327

CEO - Entergy
 
2013
 

$342,791

 

$10,000

 

$214,624

 

$48,000

 

$191,562

 

$—

 

$48,326

 

$855,303

Arkansas
 
2012
 

$334,891

 

$30,000

 

$193,355

 

$43,332

 

$202,000

 

$452,900

 

$38,819

 

$1,295,297


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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(a)
 
(b)
 
(c)
 
(d)
 
(e)
 
(f)
 
(g)
 
(h)
 
(i)
 
(j)
 
 
 
 
 
Name and
Principal Position
 
 
 
 
 
 
 
Year
 
 
 
 
 
 
 
 
Salary
(1)(2)
 
 
 
 
 
 
 
Bonus
(3)
 
 
 
 
 
 
Stock
Awards
 (4)
 
 
 
 
 
 
Option
Awards
 (5)
 
 
 
 
Non-Equity
Incentive
Plan
Compensation
(6)
 
Change in
Pension
Value and
Non-qualified
Deferred
Compensation
Earnings
 (7)
 
 
 
 
 
All
Other
Compensation (8)
 
 
 
 
 
 
 
Total
 
Alyson M. Mount
 
2014
 

$297,166

 

$—

 

$321,902

 

$74,035

 

$325,188

 

$369,400

 

$21,549

 

$1,409,240

Former acting
 
2013
 

$284,896

 

$—

 

$312,360

 

$71,200

 

$245,000

 

$69,200

 

$14,553

 

$997,209

principal financial
 
2012
 

$252,389

 

$—

 

$320,401

 

$—

 

$210,000

 

$384,700

 

$11,556

 

$1,179,046

officer Entergy
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Arkansas, Entergy
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gulf States Louisiana
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Louisiana,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Mississippi,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy New
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Orleans, Entergy
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Texas
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sallie T. Rainer
 
2014
 

$296,288

 

$—

 

$236,190

 

$50,518

 

$171,500

 

$504,000

 

$32,250

 

$1,290,746

CEO - Entergy
 
2013
 

$286,692

 

$10,000

 

$214,624

 

$46,400

 

$140,184

 

$57,800

 

$22,779

 

$778,479

Texas
 
2012
 

$251,907

 

$30,000

 

$215,262

 

$—

 

$128,000

 

$581,300

 

$13,714

 

$1,220,183

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Charles L. Rice, Jr.
 
2014
 

$260,880

 

$—

 

$220,398

 

$45,292

 

$167,864

 

$135,700

 

$31,402

 

$861,536

CEO - Entergy New
 
2013
 

$255,786

 

$10,000

 

$201,704

 

$40,000

 

$112,446

 

$67,900

 

$24,078

 

$711,914

Orleans
 
2012
 

$250,781

 

$30,000

 

$175,530

 

$43,332

 

$115,000

 

$96,900

 

$24,422

 

$735,965

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mark T. Savoff
 
2014
 

$641,443

 

$—

 

$896,618

 

$239,525

 

$880,283

 

$733,800

 

$49,902

 

$3,441,571

Executive Vice
 
2013
 

$628,913

 

$—

 

$677,616

 

$200,000

 

$601,903

 

$197,400

 

$33,141

 

$2,338,973

President and Chief
 
2012
 

$616,583

 

$—

 

$540,644

 

$169,560

 

$412,203

 

$664,500

 

$35,775

 

$2,439,265

Operating Officer -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Entergy Corp.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Roderick K. West
 
2014
 

$623,854

 

$—

 

$1,010,324

 

$313,560

 

$857,280

 

$782,400

 

$43,648

 

$3,631,066

Executive Vice
 
2013
 

$606,381

 

$—

 

$2,318,926

 

$320,000

 

$583,315

 

$147,800

 

$27,045

 

$4,003,467

President and Chief
 
2012
 

$584,540

 

$—

 

$647,594

 

$282,600

 

$391,791

 

$991,000

 

$46,097

 

$2,943,622

Administrative
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Officer - Entergy Corp.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

(1)
The amounts in column (c) represent the actual base salary paid to the Named Executive Officer.  The 2014 changes in base salaries noted in the Compensation Discussion and Analysis were effective in April 2014.
(2)
Mr. Marsh was not a Named Executive officer in 2012.
(3)
The amounts in column (d) in 2013 and 2012 for Mr. Fisackerly, Mr. McDonald, Ms. Rainer, and Mr. Rice and in 2013 for Mr. May represent a cash bonus paid in recognition of their work supporting the move to MISO.
(4)
The amounts in column (e) represent the aggregate grant date fair value of restricted stock, restricted units, and performance units granted under the 2011 Equity Ownership Plan calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures.  The grant date fair value of the restricted stock and the restricted 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 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

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that will be received with respect to the performance units granted in 2014 are as follows:  Mr. Denault, $5,053,600; Mr. Fisackerly, $277,948; Mr. Marsh, $1,187,596; Mr. May, $391,654; Mr. McDonald, $277,948; Ms. Mount, $391,654; Ms. Rainer, $277,948; Mr. Rice, $277,948; Mr. Savoff, $1,187,596; and Mr. West, $1,187,596.
(5)
The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the 2011 Equity Ownership Plan calculated in accordance with FASB ASC Topic 718.  For a discussion of the relevant assumptions used in valuing these awards, see Note 12 to the financial statements.
(6)
The amounts in column (g) represent cash payments made under the Annual Incentive Plan.
(7)
The amounts in column (h) include the annual actuarial increase in the present value of the 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 “2014 Pension Benefits”).  None of the increase is attributable to above-market or preferential earnings on non-qualified deferred compensation (see “2014 Non-qualified Deferred Compensation”).
(8)
The amounts in column (i) for 2014 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 (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
Leo P. Denault

$10,920


$31,934


$7,482


$—


$7,202


$57,538

Haley R. Fisackerly

$10,890


$7,150


$995


$3,893


$10,383


$33,311

Andrew S. Marsh

$10,919


$10,816


$3,157


$—


$1,830


$26,722

Phillip R. May, Jr.

$10,920


$6,655


$2,646


$—


$420


$20,641

Hugh T. McDonald

$10,920


$7,366


$6,976


$8,073


$15,431


$48,766

Alyson M. Mount

$10,920


$7,598


$297


$—


$2,734


$21,549

Sallie T. Rainer

$10,920


$6,047


$3,137


$2,955


$9,191


$32,250

Charles L. Rice, Jr.

$10,920


$5,779


$4,870


$1,743


$8,090


$31,402

Mark T. Savoff

$10,920


$18,486


$7,482


$—


$13,014


$49,902

Roderick K. West

$10,920


$24,208


$2,610


$—


$5,910


$43,648


Perquisites and Other Compensation

The amounts set forth in column (i) include perquisites and other personal benefits that Entergy Corporation provides to the Named Executive Officers as part of providing a competitive executive compensation program and for employee retention. The following perquisites and other compensation were provided by Entergy Corporation in 2014.

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Named Executive Officer
Personal Use of
Corporate Aircraft
Club Dues
Executive
Physicals
Event
Tickets
Leo P. Denault
X
 
X
 
Haley R. Fisackerly
 
X
X
 
Andrew S. Marsh
 
 
X
X
Phillip R. May, Jr.
 
 
 
X
Hugh T. McDonald
 
X
 
 
Alyson M. Mount
 
 
X
 
Sallie T. Rainer
X
X
 
 
Charles L. Rice, Jr.
 
X
X
X
Mark T. Savoff
X
 
X
 
Roderick K. West
X
 
X
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 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 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. None of the perquisites referenced above exceeded $25,000 for any of the other Named Executive Officers.


488
Table of Contents

2014 Grants of Plan-Based Awards

The following table summarizes award grants during 2014 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)
Leo P.
 
1/30/14
 
—
$1,332,000
$2,664,000
 
 
 
 
 
 
 
 
 
 
 
 
Denault
 
1/30/14
 
 
 
 
 
10,000

40,000

80,000

 
 
 
 
 
 
 
$2,686,400
 
 
1/30/14
 
 
 
 
 
 
 
 
 
13,900

 
 
 
 
 
$878,063
 
 
1/30/14
 
 
 
 
 
 
 
 
 
 
 
106,000

 
$63.17
 
$923,260
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Haley R.
 
1/30/14
 
—
$121,174
$242,347
 
 
 
 
 
 
 
 
 
 
 
 
Fisackerly
 
1/30/14
 
 
 
 
 
550

2,200

4,400

 
 
 
 
 
 
 
$147,752
 
 
1/30/14
 
 
 
 
 
 
 
 
 
1,400

 
 
 
 
 
$88,438
 
 
1/30/14
 
 
 
 
 
 
 
 
 
 
 
5,800

 
$63.17
 
$50,518
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Andrew S.
 
1/30/14

—
$362,250
$724,500









 
 
 
 
 
 
Marsh
 
1/30/14





2,350

9,400

18,800




 
 
 
 
 
$631,304
 
 
1/30/14
 
 
 
 
 
 
 
 
 
4,900

 
 
 
 
 
$309,533
 
 
1/30/14
 
 
 
 
 
 
 
 
 
 
 
35,000

 
$63.17
 
$304,850
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Phillip R.
 
1/30/14
 
—
$202,950
$405,900
 
 
 
 
 
 
 
 
 
 
 
 
May, Jr.
 
1/30/14
 
 
 
 
 
775

3,100

6,200

 
 
 
 
 
 
 
$208,196
 
 
1/30/14
 
 
 
 
 
 
 
 
 
1,800

 
 
 
 
 
$113,706
 
 
1/30/14
 
 
 
 
 
 
 
 
 
 
 
8,000

 
$63.17
 
$69,680
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Hugh T.
 
1/30/14
 
—
$176,060
$352,121
 
 
 
 
 
 
 
 
 
 
 
 
McDonald
 
1/30/14
 
 
 
 
 
550

2,200

4,400

 
 
 
 
 
 
 
$147,752
 
 
1/30/14
 
 
 
 
 
 
 
 
 
1,300

 
 
 
 
 
$82,121
 
 
1/30/14
 
 
 
 
 
 
 
 
 
 
 
5,500

 
$63.17
 
$47,905
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alyson M.
 
1/30/14
 
—
$180,660
$361,320
 
 
 
 
 
 
 
 
 
 
 
 
Mount
 
1/30/14
 
 
 
 
 
775

3,100

6,200

 
 
 
 
 
 
 
$208,196
 
 
1/30/14
 
 
 
 
 
 
 
 
 
1,800

 
 
 
 
 
$113,706
 
 
1/30/14
 
 
 
 
 
 
 
 
 
 
 
8,500

 
$63.17
 
$74,035
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sallie T.
 
1/30/14
 
—
$119,310
$238,620
 
 
 
 
 
 
 
 
 
 
 
 
Rainer
 
1/30/14
 
 
 
 
 
550

2,200

4,400

 
 
 
 
 
 
 
$147,752
 
 
1/30/14
 
 
 
 
 
 
 
 
 
1,400

 
 
 
 
 
$88,438
 
 
1/30/14
 
 
 
 
 
 
 
 
 
 
 
5,800

 
$63.17
 
$50,518

489
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)
Charles L.
 
1/30/14
 
—
$104,915
$209,829
 
 
 
 
 
 
 
 
 
 
 
 
Rice, Jr.
 
1/30/14
 
 
 
 
 
550

2,200

4,400

 
 
 
 
 
 
 
$147,752
 
 
1/30/14
 
 
 
 
 
 
 
 
 
1,150

 
 
 
 
 
$72,646
 
 
1/30/14
 
 
 
 
 
 
 
 
 
 
 
5,200

 
$63.17
 
$45,292
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mark T.
 
1/30/14
 
—
$451,427
$902,854
 
 
 
 
 
 
 
 
 
 
 
 
Savoff
 
1/30/14
 
 
 
 
 
2,350

9,400

18,800

 
 
 
 
 
 
 
$631,304
 
 
1/30/14
 
 
 
 
 
 
 
 
 
4,200

 
 
 
 
 
$265,314
 
 
1/30/14
 
 
 
 
 
 
 
 
 
 
 
27,500

 
$63.17
 
$239,525
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Roderick K.
 
1/30/14
 
—
$439,631
$879,262
 
 
 
 
 
 
 
 
 
 
 
 
West
 
1/30/14
 
 
 
 
 
2,350

9,400

18,800

 
 
 
 
 
 
 
$631,304
 
 
1/30/14
 
 
 
 
 
 
 
 
 
6,000

 
 
 
 
 
$379,020
 
 
1/30/14
 
 
 
 
 
 
 
 
 
 
 
36,000

 
$63.17
 
$313,560

(1)
The amounts in columns (c), (d), and (e) represent minimum, target, and maximum payment levels under the Annual Incentive Plan.  The actual amounts awarded are reported in column (g) of the Summary Compensation Table.
(2)
The amounts in columns (f), (g), and (h) represent the minimum, target, and maximum payment levels under the Long-Term Performance Unit Program.  Performance under the program is measured by Entergy Corporation’s total shareholder return relative to the total shareholder returns of the companies included in the Philadelphia Utility Index.  If Entergy Corporation’s total shareholder return is not at least 25% of that for the Philadelphia Utility Index, there is no payout.  Subject to 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, 2016.)  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 2011 Equity Ownership Plan.  Shares of restricted stock vest one-third on each of the first through third anniversaries of the grant, 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 2011 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 Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value.



490
Table of Contents

2014 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 the end of 2014.
 
 
Option Awards
 
Stock Awards
(a)
 
(b)
 
(c)
 
(d)
 
(e)
 
(f)
 
(g)
 
(h)
 
(i)
 
(j)
Name
 
Number
 of
Securities
Underlying
Unexercised
Options
Exercisable
 
Number
 of
Securities
Underlying
Unexercised
Options
Unexercisable
 
Equity
Incentive
Plan
Awards:
Number
of
Securities
Underlying
Unexercised
Unearned
Options
 
Option
Exercise
Price
 
Option
Expiration
Date
 
Number
of Shares
or Units
of Stock
That Have
Not
Vested
 
Market
Value of
Shares or
Units of
Stock
That Have
Not Vested
 
Equity
Incentive
Plan
Awards:
Number of
Unearned
Shares,
Units or
Other
 Rights
That Have
Not Vested
 
Equity
Incentive
Plan Awards:
Market or Payout Value of
Unearned
Shares,
Units or
Other
Rights
That Have
Not Vested
 
 
(#)
 
(#)
 
(#)
 
($)
 
 
 
(#)
 
($)
 
(#)
 
($)
Leo P.
 
—

 
106,000(1)

 
 
 
$63.17
 
1/30/2024
 
 
 
 
 
 
 
 
Denault
 
16,666

 
33,334(2)

 
 
 
$64.60
 
1/31/2023
 
 
 
 
 
 
 
 
 
 
20,000

 
10,000(3)

 
 
 
$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
 
 
 
 
 
 
 
 
 
 
60,000

 
—

 
 
 
$91.82
 
1/25/2017
 
 
 
 
 
 
 
 
 
 
50,000

 
—

 
 
 
$68.89
 
1/26/2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
80,000(4)
 
$6,998,400
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
74,312(5)
 
$6,500,814
 
 
 
 
 
 
 
 
 
 
 
 
13,900(6)
 
$1,215,972
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,000(7)
 
$349,920
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,334(8)

$116,698
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Haley R.
 
—

 
5,800(1)

 
 
 
$63.17

1/30/2024
 
 
 
 
 
 
 
 
Fisackerly
 
—

 
4,000(2)

 
 
 
$64.60

1/31/2023
 
 
 
 
 
 
 
 
 
 
—

 
1,534(3)

 
 
 
$71.30

1/26/2022
 
 
 
 
 
 
 
 
 
 
2,900

 
—

 
 
 
$72.79

1/27/2021
 
 
 
 
 
 
 
 
 
 
9,000

 
—

 
 
 
$77.10

1/28/2020
 
 
 
 
 
 
 
 
 
 
3,800

 
—

 
 
 
$77.53

1/29/2019
 
 
 
 
 
 
 
 
 
 
5,000

 
—

 
 
 
$108.20

1/24/2018
 
 
 
 
 
 
 
 
 
 
2,500

 
—

 
 
 
$91.82

1/25/2017
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



 
 
 
 
 
4,400(4)
 
$384,912
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,800(5)
 
$332,424
 
 
 
 
 
 
 
 
 
 
 
 
1,400(6)
 
$122,472
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
934(7)
 
$81,706
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
400(8)
 
$34,992
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

491
Table of Contents

 
 
Option Awards
 
Stock Awards
(a)
 
(b)
 
(c)
 
(d)
 
(e)
 
(f)
 
(g)
 
(h)
 
(i)
 
(j)
Name
 
Number
 of
Securities
Underlying
Unexercised
Options
Exercisable
 
Number
 of
Securities
Underlying
Unexercised
Options
Unexercisable
 
Equity
Incentive
Plan
Awards:
Number
of
Securities
Underlying
Unexercised
Unearned
Options
 
Option
Exercise
Price
 
Option
Expiration
Date
 
Number
of Shares
or Units
of Stock
That Have
Not
Vested
 
Market
Value of
Shares or
Units of
Stock
That Have
Not Vested
 
Equity
Incentive
Plan
Awards:
Number of
Unearned
Shares,
Units or
Other
 Rights
That Have
Not Vested
 
Equity
Incentive
Plan Awards:
Market or Payout Value of
Unearned
Shares,
Units or
Other
Rights
That Have
Not Vested
 
 
(#)
 
(#)
 
(#)
 
($)
 
 
 
(#)
 
($)
 
(#)
 
($)
Andrew S.
 
—

 
35,000(1)

 
 
 
$63.17
 
1/30/2024
 
 
 
 
 
 
 
 
Marsh
 
10,666

 
21,334(2)

 
 
 
$64.60
 
1/31/2023
 
 
 
 
 
 
 
 
 
 
6,666

 
3,334(3)

 
 
 
$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
 
 
 
 
 
 
 
 
 
 
5,000

 
—

 
 
 
$91.82
 
1/25/2017
 
 
 
 
 
 
 
 
 
 
5,500

 
—

 
 
 
$68.89
 
1/26/2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
18,800(4)
 
$1,644,624
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
14,884(5)
 
$1,302,052
 
 
 
 
 
 
 
 
 
 
 
 
4,900(6)
 
$428,652
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,667(7)
 
$223,309
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
467(8)
 
$40,853
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Phillip R.
 
—

 
8,000(1)

 
 
 
$63.17
 
1/30/2024
 
 
 
 
 
 
 
 
May, Jr.
 
2,000

 
4,000(2)

 
 
 
$64.60
 
1/31/2023
 
 
 
 
 
 
 
 
 
 
3,066

 
1,534(3)

 
 
 
$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
 
 
 
 
 
 
 
 
 
 
5,000

 
—

 
 
 
$91.82
 
1/25/2017
 
 
 
 
 
 
 
 
 
 
4,500

 
—

 
 
 
$68.89
 
1/26/2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6,200(4)
 
$542,376
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5,938(5)
 
$519,456
 
 
 
 
 
 
 
 
 
 
 
 
1,800(6)
 
$157,464
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
934(7)
 
$81,706
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
400(8)
 
$34,992
 
 
 
 

492
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
 
 
(#)
 
(#)
 
(#)
 
($)
 
 
 
(#)
 
($)
 
(#)
 
($)
Hugh T.
 
—

 
5,500(1)

 
 
 
$63.17
 
1/30/2024
 
 
 
 
 
 
 
 
McDonald
 
2,000

 
4,000(2)

 
 
 
$64.60
 
1/31/2023
 
 
 
 
 
 
 
 
 
 
3,066

 
1,534(3)

 
 
 
$71.30
 
1/26/2022
 
 
 
 
 
 
 
 
 
 
2,900

 
—

 
 
 
$72.79
 
1/27/2021
 
 
 
 
 
 
 
 
 
 
4,600

 
—

 
 
 
$77.10
 
1/28/2020
 
 
 
 
 
 
 
 
 
 
4,500

 
—

 
 
 
$77.53
 
1/29/2019
 
 
 
 
 
 
 
 
 
 
7,000

 
—

 
 
 
$108.20
 
1/24/2018
 
 
 
 
 
 
 
 
 
 
12,000

 
—

 
 
 
$91.82
 
1/25/2017
 
 
 
 
 
 
 
 
 
 
7,500

 
—

 
 
 
$68.89
 
1/26/2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,400(4)
 
$384,912
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,800(5)
 
$332,424
 
 
 
 
 
 
 
 
 
 
 
 
1,300(6)
 
$113,724
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
934(7)
 
$81,706
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
434(8)
 
$37,966
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alyson M.
 
—

 
8,500(1)

 
 
 
$63.17
 
1/30/2024
 
 
 
 
 
 
 
 
Mount
 
—

 
5,934(2)

 
 
 
$64.60
 
1/31/2023
 
 
 
 
 
 
 
 
 
 
4,500

 
—

 
 
 
$108.20
 
1/24/2018
 
 
 
 
 
 
 
 
 
 
5,400

 
—

 
 
 
$91.82
 
1/25/2017
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6,200(4)
 
$542,376
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6,000(5)
 
$524,880
 
 
 
 
 
 
 
 
 
 
 
 
1,800(6)
 
$157,464
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,200(7)
 
$104,976
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
500(8)
 
$43,740
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sallie T.
 
—

 
5,800(1)

 
 
 
$63.17
 
1/30/2024
 
 
 
 
 
 
 
 
Rainer
 
1,933

 
3,867(2)

 
 
 
$64.60
 
1/31/2023
 
 
 
 
 
 
 
 
 
 
2,500

 
—

 
 
 
$77.10
 
1/28/2020
 
 
 
 
 
 
 
 
 
 
1,200

 
—

 
 
 
$77.53
 
1/29/2019
 
 
 
 
 
 
 
 
 
 
2,300

 
—

 
 
 
$108.20
 
1/24/2018
 
 
 
 
 
 
 
 
 
 
2,000

 
—

 
 
 
$91.82
 
1/25/2017
 
 
 
 
 
 
 
 
 
 
2,500

 
—

 
 
 
$68.89
 
1/26/2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,400(4)
 
$384,912
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,800(5)
 
$332,424
 
 
 
 
 
 
 
 
 
 
 
 
1,400(6)
 
$122,472
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
934(7)
 
$81,706
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
434(8)
 
$37,966
 
 
 
 


493
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
 
 
(#)
 
(#)
 
(#)
 
($)
 
 
 
(#)
 
($)
 
(#)
 
($)
Charles L.
 
—

 
5,200(1)

 
 
 
$63.17
 
1/30/2024
 
 
 
 
 
 
 
 
Rice, Jr.
 
1,666

 
3,334(2)

 
 
 
$64.60
 
1/31/2023
 
 
 
 
 
 
 
 
 
 
3,066

 
1,534(3)

 
 
 
$71.30
 
1/26/2022
 
 
 
 
 
 
 
 
 
 
2,900

 
—

 
 
 
$72.79
 
1/27/2021
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,400(4)
 
$384,912
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,800(5)
 
$332,424
 
 
 
 
 
 
 
 
 
 
 
 
1,150(6)
 
$100,602
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
800(7)
 
$69,984
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
350(8)
 
$30,618
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mark T.
 
—

 
27,500(1)

 
 
 
$63.17
 
1/30/2024
 
 
 
 
 
 
 
 
Savoff
 
8,333

 
16,667(2)

 
 
 
$64.60
 
1/31/2023
 
 
 
 
 
 
 
 
 
 
12,000

 
6,000(3)

 
 
 
$71.30
 
1/26/2022
 
 
 
 
 
 
 
 
 
 
17,000

 
—

 
 
 
$72.79
 
1/27/2021
 
 
 
 
 
 
 
 
 
 
30,000

 
—

 
 
 
$77.10
 
1/28/2020
 
 
 
 
 
 
 
 
 
 
30,000

 
—

 
 
 
$77.53
 
1/29/2019
 
 
 
 
 
 
 
 
 
 
27,000

 
—

 
 
 
$108.20
 
1/24/2018
 
 
 
 
 
 
 
 
 
 
35,000

 
—

 
 
 
$91.82
 
1/25/2017
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
18,800(4)
 
$1,644,624
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15,200(5)
 
$1,329,696
 
 
 
 
 
 
 
 
 
 
 
 
4,200(6)
 
$367,416
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,867(7)
 
$163,325
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
834(8)
 
$72,958
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Roderick
 
—

 
36,000(1)

 
 
 
$63.17
 
1/30/2024
 
 
 
 
 
 
 
 
K. West
 
13,333

 
26,667(2)

 
 
 
$64.60
 
1/31/2023
 
 
 
 
 
 
 
 
 
 
20,000

 
10,000(3)

 
 
 
$71.30
 
1/26/2022
 
 
 
 
 
 
 
 
 
 
17,000

 
—

 
 
 
$72.79
 
1/27/2021
 
 
 
 
 
 
 
 
 
 
7,000

 
—

 
 
 
$77.10
 
1/28/2020
 
 
 
 
 
 
 
 
 
 
5,000

 
—

 
 
 
$77.53
 
1/29/2019
 
 
 
 
 
 
 
 
 
 
8,000

 
—

 
 
 
$108.20
 
1/24/2018
 
 
 
 
 
 
 
 
 
 
12,000

 
—

 
 
 
$91.82
 
1/25/2017
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
18,800(4)
 
$1,644,624
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15,200(5)
 
$1,329,696
 
 
 
 
 
 
 
 
 
 
 
 
6,000(6)
 
$524,880
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,334(7)
 
$291,658
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,334(8)
 
$116,698
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
21,000(9)
 
$1,837,080
 
 
 
 


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Table of Contents

(1)
Consists of options that vested or will vest as follows: 1/3 of the options granted vest on each of 1/30/2015, 1/30/2016 and 1/30/2017.
(2)
Consists of options that vested or will vest as follows: 1/2 of the remaining unexercisable options vest on each of 1/31/2015 and 1/31/2016.
(3)
The remaining unexercisable options vested on 1/26/2015.
(4)
Consists of performance units that will vest on December 31, 2016 based on Entergy Corporation’s total shareholder return performance over the 2014-2016 performance period, as described under “What We Pay and Why- Executive Compensation Elements - Long-Term Incentive Compensation - Performance Unit Program” in Compensation Discussion and Analysis.
(5)
Consists of performance units that will vest on December 31, 2015 based on Entergy Corporation’s total shareholder return performance over the 2013-2015 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 1/30/2015, 1/30/2016 and 1/30/2017.
(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 1/31/2015 and 1/31/2016.
(8)
Consists of shares of restricted stock that vested on 1/26/2015.
(9)
Consists of restricted units granted under the 2011 Equity Ownership Plan which will vest on May 1, 2018.

2014 Option Exercises and Stock Vested

The following table provides information concerning each exercise of stock options and each vesting of stock during 2014 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
 
 
(#)
 
($)
 
(#)
 
($)
Leo P. Denault
 
35,000

 

$477,575

 
17,370(1)
 

$1,423,990

 
 
 
 
 
 
 
 
 
Haley R. Fisackerly
 
6,066

 

$61,983

 
2,136(1)
 

$164,281

 
 
 
 
 
 
 
 
 
Andrew S. Marsh
 
7,000

 

$78,385

 
4,715(1)
 

$369,715

 
 
 
 
 
 
 
 
 
Phillip R. May, Jr.
 
7,000

 

$75,732

 
2,458(1)
 

$193,263

 
 
 
 
 
 
 
 
 
Hugh T. McDonald
 
10,000

 

$53,055

 
2,169(1)
 

$166,520

 
 
 
 
 
 
 
 
 
Alyson M. Mount
 
24,466

 

$67,906

 
2,670(1)
 

$202,276

 
 
 
 
 
 
 
 
 
Sallie T. Rainer
 
2,500

 

$31,434

 
1,901(1)
 

$145,240

 
 
 
 
 
 
 
 
 
Charles L. Rice, Jr.
 
—

 

$—

 
1,937(1)
 

$150,599

 
 
 
 
 
 
 
 
 
Mark T. Savoff
 
50,000

 

$534,219

 
6,257(1)
 

$495,030

 
 
 
 
 
 
 
 
 
Roderick K. West
 
2,001

 

$28,988

 
7,490(1)
 

$577,597


(1)
Represents the value of performance units for the 2012-2014 performance period (payable solely in shares based on the closing stock price of the Company on the dates of vesting) under the Performance Unit Program and the vesting of shares of restricted stock in 2014.

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Table of Contents

2014 Pension Benefits

The following table shows the present value as of December 31, 2014, 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 is included in Compensation Discussion & Analysis under the heading, “Benefits, Perquisites, Agreements, and Post-Retirement Plans" and following this table.  In addition, this section includes information regarding early retirement options under the plans.
 
 
 
Name
 
 
 
Plan
Name
 
Number
of Years
Credited
Service
 
Present
Value of
Accumulated
Benefit
 
 
Payments
During
 2014
Leo P. Denault (1)
 
Non-qualified System
   Executive Retirement Plan
 
30.83

 

$9,539,500

 

$—

 
 
Qualified defined
   benefit plan
 
15.83

 

$546,100

 

$—

 
 
 
 
 
 
 
 
 
Haley R. Fisackerly
 
Non-qualified System
   Executive Retirement Plan
 
19.08

 

$843,300

 

$—

 
 
Qualified defined
   benefit plan
 
19.08

 

$538,700

 

$—

 
 
 
 
 
 
 
 
 
Andrew S. Marsh
 
Non-qualified System
   Executive Retirement Plan
 
16.37

 

$1,621,700

 

$—

 
 
Qualified defined
   benefit plan
 
16.37

 

$354,600

 

$—

 
 
 
 
 
 
 
 
 
Phillip R. May, Jr.
 
Non-qualified System
   Executive Retirement Plan
 
28.56

 

$1,346,100

 

$—

 
 
Qualified defined
   benefit plan
 
28.56

 

$888,600

 

$—

 
 
 
 
 
 
 
 
 
Hugh T. McDonald (2)
 
Non-qualified System
   Executive Retirement Plan
 
32.93

 

$1,615,100

 

$—

 
 
Qualified defined
   benefit plan
 
31.44

 

$1,142,200

 

$—

 
 
 
 
 
 
 
 
 
Alyson M. Mount
 
Non-qualified System
   Executive Retirement Plan
 
12.35

 

$696,600

 

$—

 
 
Qualified defined
   benefit plan
 
12.35

 

$294,100

 

$—

 
 
 
 
 
 
 
 
 
Sallie T. Rainer (2)
 
Non-qualified System
   Executive Retirement Plan
 
30.38

 

$818,800

 

$—

 
 
Qualified defined
   benefit plan
 
28.52

 

$981,100

 

$—

 
 
 
 
 
 
 
 
 
Charles L. Rice, Jr.
 
Non-qualified System
   Executive Retirement Plan
 
5.47

 

$256,200

 

$—

 
 
Qualified defined
   benefit plan
 
5.47

 

$157,400

 

$—


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Table of Contents

 
 
 
Name
 
 
 
Plan
Name
 
Number
of Years
Credited
Service
 
Present
Value of
Accumulated
Benefit
 
 
Payments
During
 2014
Mark T. Savoff
 
Non-qualified System
   Executive Retirement Plan
 
11.06

 

$3,329,000

 

$—

 
 
Qualified defined
   benefit plan
 
11.06

 

$437,600

 

$—

 
 
 
 
 
 
 
 
 
Roderick K. West
 
Non-qualified System
   Executive Retirement Plan
 
15.75

 

$2,830,500

 

$—

 
 
Qualified defined
   benefit plan
 
15.75

 

$387,700

 

$—


(1)
During 2006, Mr. Denault entered into an agreement granting an additional 15 years of service under the non-qualified System Executive Retirement Plan if he continues to work for an Entergy System company employer and, after age 55, retires with the permission of his employer or his employment is terminated due to death or disability. The additional 15 years increases the present value of his benefit by $2,246,700.
(2)
Service under the non-qualified System Executive Retirement Plan is granted from date of hire.  Qualified plan benefit service is granted from the later of date of hire or plan participation date.

Qualified Retirement Benefits

The qualified retirement plan in which the Named Executive Officers participate is a funded, tax-qualified, noncontributory defined benefit pension plan that provides benefits to most of the non-bargaining unit employees of Entergy System Companies.  All Named Executive Officers are participants in this plan.  Benefits under the tax-qualified pension plan are calculated as an annuity payable at age 65 and generally equal to 1.5% of a participant’s Final Average Monthly Earnings (FAME) multiplied by years of service (not to exceed 40).  “Earnings” for purposes of calculating FAME generally includes the employee’s base salary and eligible annual incentive award and excludes all other bonuses. 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 annual bonuses paid during the 60 month period.  Benefits under the tax-qualified plan are payable monthly after attainment of at least age 55 and after separation from an Entergy System company.  The amount of annual earnings that may be considered in calculating benefits under the tax-qualified pension plan is limited by federal law.  Participants are 100% vested in their benefit upon completing 5 years of vesting service or upon attainment of age 65 while an active employee participant in the plan.  Contributions to the pension plan are made entirely by the Entergy System employer and are paid into a trust fund from which the benefits of participants will be paid.

Normal retirement under the plan is age 65.  Employees who terminate employment prior to age 55 may receive a reduced deferred vested retirement benefit commencing as early as age 55 that is based on the normal retirement benefit (reduced by 7% per year for the first 5 years commencement precedes age 65, and reduced by 6% for each additional year commencement precedes age 65). Employees who are at least age 55 with 10 years of vesting service upon termination of employment are entitled to a subsidized early retirement benefit beginning as early as age 55.  The subsidized early retirement benefit is equal to the normal retirement benefit reduced by 2% per year for each year that early retirement precedes age 65.

Mr. Denault, Mr. McDonald, and Mr. Savoff are eligible for subsidized early retirement benefits.


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Table of Contents

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 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 plans but 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.

All of the Named Executive Officers participate in both the Pension Equalization Plan and the System Executive Retirement Plan.

The Pension Equalization Plan
The Pension Equalization Plan is a non-qualified unfunded restoration retirement plan that provides for the payment to participants from Entergy Corporation's general assets of a single lump sum cash distribution upon separation from service generally equal to the actuarial present value of the difference between the amount that would have been payable as an annuity under the tax-qualified pension plan, but for Internal Revenue Code limitations on pension benefits and earnings that may be considered in calculating tax-qualified pension benefits, and the amount actually payable as an annuity under the tax-qualified pension plan. The Pension Equalization Plan also takes into account as eligible earnings certain incentive awards paid under the Annual Incentive Plan and includes supplemental credited service granted to a participant in calculating his or her benefit. Participants receive their Pension Equalization Plan benefit in the form of a single sum cash distribution. The benefits under this plan are offset by benefits payable from the qualified retirement plan and may be offset by prior employer benefits. The Pension Equalization Plan benefit attributable to supplemental credited service is not vested until age 65. Subject to the prior written consent of the Entergy System Company employer (which consent is deemed given if the participant’s employment is terminated within twenty-four months following a change in control by the employer without “Cause” or by the participant for “Good Reason,” as each is defined in the plan), an employee with supplemental credited service who terminates employment prior to age 65 may be vested in his or her benefit, with payment of the lump sum benefit generally at separation from service unless delayed six months under Internal Revenue Code Section 409A. Benefits payable prior to age 65 are subject to the same reductions as qualified plan benefits.
Effective July 1, 2014, participants in the Pension Equalization Plan will not be provided with supplemental credited service unless the grant of supplemental credited service was approved and accepted in writing by the plan administrator prior to July 1, 2014. In addition, the Pension Equalization Plan was amended effective July 1, 2014 to provide that employees who participate in the Entergy Corporation’s cash balance pension plan adopted June 30, 2014 are not eligible to participate in the Pension Equalization Plan and instead are eligible to participate in a new cash balance restoration plan.

The System Executive Retirement Plan

The System Executive Retirement Plan is a non-qualified supplemental retirement plan that provides for a single sum payment at age 65.  Like the Pension Equalization Plan, the System Executive Retirement Plan is designed to provide for the payment to participants from Entergy Corporation’s general assets of a single-sum cash distribution upon the participant’s separation from service.  The single-sum benefit is generally equal to the actuarial present value of a specified percentage of the participant’s “Final Average Monthly Compensation” (which is generally 1/36th of the sum of the participant’s annual rate of base salary and Annual Incentive Plan award for the 3 highest years during the last 10 years preceding termination of employment), after first being reduced by the value of the participant’s tax-qualified retirement plan benefit and typically any prior employer pension benefit available to the participant.


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Table of Contents

While the System Executive Retirement Plan has a replacement ratio schedule from one year of service to the maximum of 30 years of service, the table below offers a sample ratio at 20 and 30 years of service.

Years of
Service
 
Executives at
Management
Level 1
 
Executives at Management Levels 2 and 3
 
Executives at
Management
Level 4
20 Years
 
55.0%
 
50.0%
 
45.0%
30 years
 
65.0%
 
60.0%
 
55.0%
The System Executive Retirement Plan benefit is not vested until age 65. Subject to the prior written consent of the Entergy System company employer, an employee who terminates his or her employment prior to age 65 may be vested in the System Executive Retirement Plan benefit, with payment of the lump sum benefit generally at separation from service unless delayed six months under Code Section 409A.  Benefits payable prior to age 65 are subject to the same reductions as qualified plan benefits.  Further, in the event of a change in control, participants whose employment is terminated without “Cause” or by the employee for “Good Reason,” as each is defined in the plan are also eligible for a subsidized lump sum benefit payment, even if they do not currently meet the age or service requirements for early retirement under that plan or have company permission to separate from employment. Such lump sum benefit is payable generally at separation from service unless delayed 6 months under Code Section 409A.

2014 Non-qualified Deferred Compensation

The Executive Deferred Compensation Plan, the 2007 Equity Ownership Plan and Long-Term Cash Incentive Plan, and the 2011 Equity Ownership Plan allow for the deferral of compensation for the Named Executive Officers.  As of December 31, 2014, none of the Named Executive Officers had deferred compensation balances under the equity ownership plans or the Executive Deferred Compensation Plan.

As of December 31, 2014, Mr. Savoff and Mr. May had deferred account balances under a frozen Defined Contribution Restoration Plan.  These amounts are deemed invested, as chosen by the participant, in certain T. Rowe Price investment funds that are also available to participants under the Savings Plan.  Mr. Savoff and Mr. May have elected to receive the deferred account balances after they retire. The Defined Contribution Restoration Plan, until it was frozen in 2005, credited eligible employees’ deferral accounts with employer contributions to the extent contributions under the qualified savings plan in which the employee participated were subject to limitations imposed by the Internal Revenue Code.

Defined Contribution Restoration Plan
Name
 
Executive
Contributions in
 2014
 
Registrant
Contributions in
2014
 
Aggregate
Earnings in
2014 (1)
 
Aggregate
Withdrawals/
Distributions
 
Aggregate
Balance at
December 31,
2014
(a)
 
(b)
 
(c)
 
(d)
 
(e)
 
(f)
 
 
 
 
 
 
 
 
 
 
 
Phillip R. May, Jr.
 

$—

 

$—

 

$359

 

$—

 

$1,721

 
 
 
 
 
 
 
 
 
 
 
Mark T. Savoff
 

$—

 

$—

 

$8,224

 

$—

 

$26,685


(1)
Amounts in this column are not included in the Summary Compensation Table.


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Table of Contents

2014 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. In addition, Entergy Corporation has entered into a retention agreement with Mr. Denault that provides for payments upon certain employment termination events. There are no plans or agreements that would provide for payments to any of the Named Executive Officers solely upon a change in control.
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 System company had been terminated under various scenarios as of December 31, 2014. For purposes of these tables, Entergy Corporation assumed that its stock price was $87.48, the closing market price on that date.

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Table of Contents

Benefits and Payments Upon Termination
Voluntary Resignation
For Cause
Termination for Good Reason or Not for Cause
Retirement
Disability
Death
Change in Control
Termination Related to a Change in Control
Leo P. Denault (1)(2)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Severance Payment(5)
—
—

$8,613,353

—
—
—
—

$8,613,353

Performance Units:(7)
 
 
 
 
 
 
 
 
2013-2015 Performance Unit Program
—
—

$2,112,642


$2,166,880


$2,112,642


$2,112,642

—

$2,112,642

2014-2016 Performance Unit Program
—
—

$2,112,642


$1,166,371


$2,112,642


$2,112,642

—

$2,112,642

Unvested Stock Options(9)
—
—

$3,501,327


$3,501,327


$3,501,327


$3,501,327

—

$3,501,327

Unvested Restricted Stock(11)
—
—

$1,791,514

—

$1,791,514


$1,791,514

—

$1,791,514

Welfare Benefits(13)
—
—
—
—
—
—
—
 
 
 
 
 
 
 
 
 
 
Haley Fisackerly (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Severance Payment(6)
—
—
—
—
—
—
—

$424,107

Performance Units:(8)
 
 
 
 
 
 
 
 
2013-2015 Performance Unit Program
—
—
—
—

$110,837


$110,837

—

$96,228

2014-2016 Performance Unit Program
—
—
—
—

$64,123


$64,123

—

$96,228

Unvested Stock Options(10)
—
—
—
—

$257,327


$257,327

—

$257,327

Unvested Restricted Stock(12)
—
—
—
—

$117,836


$117,836

—

$258,479

Welfare Benefits(14)
—
—
—
—
—
—
—

$18,324

 
 
 
 
 
 
 
 
 
Andrew S. Marsh (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Severance Payment(6)
—
—
—
—
—
—
—

$2,398,354

Performance Units:(8)
 
 
 
 
 
 
 
 
2013-2015 Performance Unit Program
—
—
—
—

$433,988


$433,988

—

$489,888

2014-2016 Performance Unit Program
—
—
—
—

$274,075


$274,075

—

$489,888

Unvested Stock Options(10)
—
—
—
—

$1,392,890


$1,392,890

—

$1,392,890

Unvested Restricted Stock(12)
—
—
—
—

$298,482


$298,482

—

$752,247

Welfare Benefits(14)
—
—
—
—
—
—
—

$27,486

 
 
 
 
 
 
 
 
 
Phillip R. May, Jr. (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Severance Payment(6)
—
—
—
—
—
—
—

$1,014,750

Performance Units:(8)
 
 
 
 
 
 
 
 
2013-2015 Performance Unit Program
—
—
—
—

$173,210


$173,210

—

$205,578

2014-2016 Performance Unit Program
—
—
—
—

$90,367


$90,367

—

$205,578

Unvested Stock Options(10)
—
—
—
—

$310,809


$310,809

—

$310,809

Unvested Restricted Stock(12)
—
—
—
—

$129,120


$129,120

—

$295,063

Welfare Benefits(14)
—
—
—
—
 
 
—

$27,486


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Table of Contents

Benefits and Payments Upon Termination
Voluntary Resignation
For Cause
Termination for Good Reason or Not for Cause
Retirement
Disability
Death
Change in Control
Termination Related to a Change in Control
Hugh T. McDonald (1)(3)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Severance Payment(6)
—
—
—
—
—
—
—

$528,181

Performance Units:(8)
 
 
 
 
 
 
 
 
2013-2015 Performance Unit Program
—
—
—

$110,837


$110,837


$110,837

—

$96,228

2014-2016 Performance Unit Program
—
—
—

$64,123


$64,123


$64,123

—

$96,228

Unvested Stock Options(10)
—
—
—

$250,034


$250,034


$250,034

—

$250,034

Unvested Restricted Stock(12)
—
—
—
—

$118,273


$118,273

—

$252,776

Welfare Benefits(13)
—
—
—
—
—
—
—
 
 
 
 
 
 
 
 
 
 
Alyson M. Mount (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Severance Payment(6)
—
—
—
—
—
—
—

$963,520

Performance Units:(8)
 
 
 
 
 
 
 
 
2013-2015 Performance Unit Program
—
—
—
—

$174,960


$174,960

—

$205,578

2014-2016 Performance Unit Program
—
—
—
—

$90,367


$90,367

—

$205,578

Unvested Stock Options(10)
—
—
—
—

$342,390


$342,390

—

$342,390

Unvested Restricted Stock(12)
—
—
—
—

$150,203


$150,203

—

$330,801

Welfare Benefits(14)
—
—
—
—
—
—
—

$9,148

 
 
 
 
 
 
 
 
 
Sallie T. Rainer (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Severance Payment(6)
—
—
—
—
—
—
—

$417,585

Performance Units:(8)
 
 
 
 
 
 
 
 
2013-2015 Performance Unit Program
—
—
—
—

$110,837


$110,837

—

$96,228

2014-2016 Performance Unit Program
—
—
—
—

$64,123


$64,123

—

$96,228

Unvested Stock Options(10)
—
—
—
—

$229,467


$229,467

—

$229,467

Unvested Restricted Stock(12)
—
—
—
—

$121,072


$121,072

—

$261,921

Welfare Benefits(14)
—
—
—
—
—
—
—

$18,234

 
 
 
 
 
 
 
 
 
Charles R. Rice, Jr (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Severance Payment(6)
—
—
—
—
—
—
—

$367,201

Performance Units:(8)
 
 
 
 
 
 
 
 
2013-2015 Performance Unit Program
—
—
—
—

$110,837


$110,837

—

$96,228

2014-2016 Performance Unit Program
—
—
—
—

$64,123


$64,123

—

$96,228

Unvested Stock Options(10)
—
—
—
—

$227,488


$227,488

—

$227,488

Unvested Restricted Stock(12)
—
—
—
—

$100,340


$100,340

—

$217,649

Welfare Benefits(14)
—
—
—
—
—
—
—

$18,324



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Benefits and Payments Upon Termination
Voluntary Resignation
For Cause
Termination for Good Reason or Not for Cause
Retirement
Disability
Death
Change in Control
Termination Related to a Change in Control
Mark T. Savoff (1)(3)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Severance Payment(6)
—
—
—
—
—
—
—

$3,278,006

Performance Units:(8)
 
 
 
 
 
 
 
 
2013-2015 Performance Unit Program
—
—
—

$443,261


$443,261


$443,261

—

$489,888

2014-2016 Performance Unit Program
—
—
—

$274,075


$274,075


$274,075

—

$489,888

Unvested Stock Options(10)
 
 
 

$1,146,938


$1,146,938


$1,146,938

—

$1,146,938

Unvested Restricted Stock(12)
—
—
—


$278,099


$278,099

—

$648,346

Welfare Benefits(13)
—
—
—
—
—
—
—
—
 
 
 
 
 
 
 
 
 
Roderick K. West (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Severance Payment(6)
—
—
—
—
—
—
—

$3,192,348

Performance Units:(8)
 
 
 
 
 
 
 
 
2013-2015 Performance Unit Program
—
—
—
—

$443,261


$443,261

—

$489,888

2014-2016 Performance Unit Program
—
—
—
—

$274,075


$274,075

—

$489,888

Unvested Stock Options(10)
 
 
 
 

$1,647,093


$1,647,093

—

$1,647,093

Unvested Restricted Stock(12)
—
—
—
—

$440,199


$440,199

—

$1,004,859

Welfare Benefits(14)
—
—
—
—
—

 
—

$27,486

Unvested Restricted Units(15)
—
—

$1,837,080

—
—
—
—

$1,837,080

(1)
As of December 31, 2014, Mr. Denault, Mr. McDonald, and Mr. Savoff are retirement eligible and would retire rather than voluntarily resign.
Pension Benefits
(2)
In addition to the payments and benefits in the table, Mr. Denault also would have been entitled to receive his vested pension benefits. If Mr. Denault’s employment were terminated under certain conditions relating to a change in control, he would also be eligible for early retirement benefits. For a description of these benefits, see “2014 Pension Benefits.” In addition, Mr. Denault is subject to the following provisions:
•
Mr. Denault’s retention agreement provides that, unless his employment is terminated for cause, he will be granted an additional 15 years of service under the System Executive Retirement Plan if he continues to work for an Entergy System company employer and after age 55, retires with the permission of his employer or his employment is terminated due to death or disability. If Mr. Denault’s employment is terminated for cause, he will forfeit his benefit under the System Executive Retirement Plan.
•
Under his retention agreement, if Mr. Denault’s employment is terminated by Mr. Denault for good reason or by Entergy Corporation not for cause (regardless of whether there is a change in control) or on account of disability, Mr. Denault would be eligible for subsidized retirement and the additional 15 years of service upon his separation of service even if he does not have permission to separate from employment.
(3)
In addition to the payments and benefits in the table, Mr. McDonald and Mr. Savoff each would have been eligible to retire and entitled to receive his vested pension benefits. For a description of the pension benefits available see, “2014 Pension Benefits.” In the event of a termination by Entergy Corporation without cause or by the executive for good reason in connection with a change in control, Mr. McDonald and Mr. Savoff each would be eligible for subsidized early retirement benefits under the System Executive Retirement Plan even if he does not have permission to separate from employment. If Mr. McDonald’s and Mr. Savoff’s

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employment were terminated for cause, he would not receive a benefit under the System Executive Retirement Plan.
(4)
In addition to the payments and benefits in the table, if a Named Executive Officer's, other than Messrs. Denault, McDonald, and Savoff, employment was terminated under certain conditions relating to a change in control, he or she also would have been entitled to receive his or her vested pension benefits upon attainment of age 55 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 “2014 Pension Benefits.” If the Named Executive Officers’, other than Messrs. Denault, McDonald, and Savoff, employment were terminated for cause, he or she would forfeit his or her benefit under the System Executive Retirement Plan.
Severance Payments
(5)
In the event of a termination (not due to death or disability) by Mr. Denault for good reason or by Entergy Corporation not for cause (regardless of whether there is a change in control), Mr. Denault would be entitled to receive, pursuant to his retention agreement, a lump sum severance payment equal to the product of 2.99 times the sum of (a) his annual base salary as in effect at any time within one year prior to the effective date of the retention agreement or, if higher, immediately prior to a circumstance constituting good reason plus (b) the greater of (i) his actual annual incentive award under the Annual Incentive Plan for the calendar year immediately preceding the calendar year in which Mr. Denault’s termination date occurs or (ii) Mr. Denault’s Annual Incentive Plan target award for the calendar year in which the effective date of the retention agreement occurred. For purposes of this table, we have calculated the award using a base salary of $1,110,000 and his preceding year’s actual annual incentive award, $1,770,720.
(6)
In the event of a termination (not due to death or disability) by the executive for good reason or by Entergy Corporation 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, other than Mr. Denault, would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to the product of for Mr. Marsh, Mr. Savoff, and Mr. West 2.99 times, for Mr. May and Ms. Mount 2 times and Mr. Fisackerly, Mr. McDonald, Ms. Rainer, and Mr. Rice 1 time 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) his or her annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in his or her termination occurs. For purposes of this table, it assumes the following target opportunity and base salary:
Named Executive Officer
Target Opportunity
Base Salary
Haley R. Fisackerly
40%
$302,934
Andrew S. Marsh
55%
$517,500
Phillip R. May
50%
$338,250
Hugh T. McDonald
50%
$352,121
Alyson M. Mount
60%
$301,100
Sallie T. Rainer
40%
$298,275
Charles L. Rice, Jr.
40%
$262,287
Mark T. Savoff
70%
644,896
Roderick K. West
70%
628,044
Performance Units
(7)
In the event of a termination due to death or disability, by Mr. Denault for good reason, or by Entergy Corporation not for cause (in all cases, regardless of whether there is a change in control), Mr. Denault would have forfeited his performance units for all open performance periods and would have been entitled to receive a single-lump sum severance payment pursuant to his retention agreement that would not be based on any outstanding performance periods. The payment would be calculated using the average annual number of performance

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units he would have been entitled to receive under the Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which his termination occurs, assuming all performance goals were achieved at target. For purposes of the table, the value of Mr. Denault’s severance payment was calculated by taking an average of the target performance units from the 2010-2012 Performance Unit Program (22,300 units) and the 2011-2013 Performance Unit Program (26,000 units). This average number of units (24,150 units) multiplied by the closing price of Entergy stock on December 31, 2014 ($87.48) would equal a severance payment of $2,112,642 for the forfeited performance units.
In the event of Mr. Denault’s retirement not related to a change in control, Mr. Denault would not have forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on his number of months of participation in each open Performance Unit Program performance cycle. 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 value of Mr. Denault’s awards were calculated as follows:
2013 - 2015 Plan - 24,770 (24/36*37,156) performance units at target, assuming a stock price of $87.48
2014 - 2016 Plan - 13,333 (12/36*40,000) performance units at target, assuming a stock price of $87.48
(8)
In the event of a qualifying termination related to a change in control, each Named Executive Officer, other than Mr. Denault, would have forfeited his or her performance units for the 2013-2015 and 2014-2016 performance periods and would have been entitled to receive, pursuant to the 2011 Equity Ownership Plan, a single-lump sum severance payment that would not be based on any outstanding performance periods. For both the 2013-2015 and the 2014-2016 performance periods, the payment would have been calculated using the average annual number of performance units he or she would have been entitled to receive under each Performance Unit Program with respect to the two most recent performance periods preceding (but not including) the calendar year in which his or her termination occurs, assuming all performance goals were achieved at target multiplied by the closing price of Entergy stock on December 31, 2014.
For purposes of the table, the value of the severance payment for Mr. Fisackerly, Mr. McDonald, Ms. Rainer and Mr. Rice was calculated by taking an average of the target performance units from the 2010-2012 Performance Unit Program (1,000 units) and the 2011-2013 Performance Unit Program (1,200 units). This average number of units (1,100) multiplied by the closing price of Entergy stock on December 31, 2014 ($87.48) would equal a severance payment of for the forfeited performance units equal to $96,228.
The value of severance payment for Mr. May and Ms. Mount was calculated by taking an average of the target performance units from the 2010-2012 Performance Unit Program (2,200 units) and the 2011-2013 Performance Unit Program (2,500 units). This average number of units (2,350) multiplied by the closing price of Entergy stock on December 31, 2014 ($87.48) would equal a severance payment of for the forfeited performance units equal to $205,578.
The value of severance payment for Mr. Marsh, Mr. Savoff, and Mr. West was calculated by taking an average of the target performance units from the 2010-2012 Performance Unit Program (5,300 units) and the 2011-2013 Performance Unit Program (5,900 units). This average number of units (5,600) multiplied by the closing price of Entergy stock on December 31, 2014 ($87.48) would equal a severance payment of for the forfeited performance units equal to $489,888.
In the event of death or disability, or retirement in the case of Mr. McDonald or Mr. Savoff, each Named Executive Officer, other than Mr. Denault, would not have forfeited his 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 cycle, in accordance with his or her 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 value of the awards were calculated as follows:


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Mr. Fisackerly’s, Mr. McDonald’s, Ms. Rainer’s and Mr. Rice’s awards:
2013 - 2015 Plan - 1,267 (24/36*1,900) performance units at target, assuming a stock price of $87.48
2014 - 2016 Plan - 733 (12/36*2,200) performance units at target, assuming a stock price of $87.48
Mr. Marsh’s awards:
2013 - 2015 Plan - 4,961 (24/36*7,442) performance units at target, assuming a stock price of $87.48
2014 - 2016 Plan - 3,133 (12/36*9,400) performance units at target, assuming a stock price of $87.48
Mr. May’s awards:
2013 - 2015 Plan - 1,980 (24/36*2,969) performance units at target, assuming a stock price of $87.48
2014 - 2016 Plan - 1,033 (12/36*3,100) performance units at target, assuming a stock price of $87.48
Ms. Mount’s awards:
2013 - 2015 Plan - 2,000 (24/36*3,000) performance units at target, assuming a stock price of $87.48
2014 - 2016 Plan - 1,033 (12/36*3,100) performance units at target, assuming a stock price of $87.48
Mr. Savoff’s and Mr. West’s awards:
2013 - 2015 Plan - 5,067 (24/36*7,600) performance units at target, assuming a stock price of $87.48
2014 - 2016 Plan - 3,133 (12/36*9,400) performance units at target, assuming a stock price of $87.48
Unvested Stock Options
(9)
In the event of Mr. Denault’s retirement, death or disability (pursuant to the 2011 Equity Ownership Plan) or upon termination by Mr. Denault for good reason or by Entergy Corporation not for cause (regardless of whether there is a change in control), pursuant to his retention agreement, all of Mr. Denault’s unvested stock options would immediately vest. In addition, he would be entitled to exercise any unexercised options during a ten-year term extending from the grant date of the options. For purposes of this table, it is assumed that Mr. Denault exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2014, and the exercise price of each option share.
(10)
In the event of death or disability or qualifying termination related to a change in control or retirement in the case of Mr. McDonald or Mr. Savoff, all of the unvested stock options of each Named Executive Officer, other than Mr. Denault, would immediately vest pursuant to the 2011 Equity Ownership Plan. In addition, each 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. For purposes of this table, it is assumed that the Named Executive Officers, other than Mr. Denault, exercised their options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2014, and the applicable exercise price of each option share.
Unvested Restricted Stock
 (11)
Pursuant to his retention agreement, in the event of Mr. Denault's death or disability or upon termination by Mr. Denault for good reason or by Entergy Corporation not for cause (regardless of whether there is a change in control), all of Mr. Denault’s unvested restricted stock would immediately vest.
(12)
In the event of death or disability (pursuant to the 2011 Equity Ownership Plan), each Named Executive Officer, other than Mr. Denault, 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 twelve (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 twelve (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, the Named Executive Officers, other than Mr. Denault, would immediately vest in all of their unvested restricted stock.
Welfare Benefits
(13)
Upon retirement, Mr. Denault, Mr. McDonald, and Mr. Savoff would be eligible for retiree medical and dental benefits, the same as all other retirees. Pursuant to the System Executive Continuity Plan, in the event of a

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termination related to a change in control, Messrs. Denault, McDonald, and Savoff would not be eligible to receive Entergy Corporation subsidized COBRA benefits.
(14)
Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Marsh, Mr. May, Ms. Mount and Mr. West would be eligible to receive Entergy Corporation subsidized COBRA benefits for 18 months and Mr. Fisackerly, Ms. Rainer, and Mr. Rice would be eligible to receive Entergy Corporation subsidized COBRA benefits for 12 months.
Restricted Stock Units

(15)
Mr. West’s 21,000 restricted units vest 100% in 2018. Pursuant to his restricted unit agreement, any unvested restricted units will vest immediately in the event of a termination for a reason other than cause, total disability, or death. The units will vest upon termination within 24 months of a change in control without cause or by Mr. West with good reason. If Mr. West voluntarily resigns or is terminated for cause, he would forfeit these units.

Mr. Denault’s Retention Agreement

Under the terms of Mr. Denault’s retention agreement, Entergy Corporation may terminate his employment 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 or her under any of Entergy Corporation’s pension, savings, life insurance, medical, health and accident, disability, or vacation plans 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.


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System Executive Continuity Plan
Termination Related to a Change in Control
The 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 an Entergy System company 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 common stock or the combined voting power of its 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 the Board at the end of the period.
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 Board adopts resolutions determining that, for purposes of the System Executive Continuity Plan, a potential change in control has occurred;
•
an Entergy 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 common stock of Entergy Corporation constituting 20% 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 the 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 confidential information without authorization.
A Named Executive Officer may terminate his or her employment with an Entergy System Company 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;

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•
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 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 Supplemental Retirement 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. In 2010, Entergy Corporation eliminated tax gross up payments for any severance benefits paid under the System Executive Continuity Plan.
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-competition provision, which generally runs for two years but extends to three years if permissible under applicable law.
Furthermore, if the executive discloses non-public data or information concerning Entergy Corporation or any of its subsidiaries or violates his or her non-competition provision, he or she will be required to repay any benefits previously received under the System Executive Continuity Plan.
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 below under “Voluntary Resignation,” except that all options are no longer exercisable.
Voluntary Resignation
If a Named Executive Officer voluntarily resigns from his or her Entergy System company employer, he or she is entitled to all 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. In the case of voluntary resignation, the officer would forfeit all unvested stock options, shares of restricted stock, and restricted units as well as any perquisites to which he or she is entitled as an officer. In addition, the officer would forfeit, except as described below, his or her right to receive incentive payments under any outstanding performance periods under the Long-Term Performance Unit Program or the Annual Incentive Plan. If the 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

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performance cycle and could, at the 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.
Retirement
Under Entergy Corporation’s retirement plans, a Named Executive Officer’s eligibility for retirement benefits is based on a combination of age and years of service. Normal retirement is defined as age 65. Early retirement is defined under the qualified retirement plan as minimum age 55 with 10 years of service and in the case of the System Executive Retirement Plan and the supplemental credited service under the Pension Equalization Plan, the consent of the Entergy System company employer.
Upon a Named Executive Officer’s retirement, he or she is generally entitled to all 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. The annual incentive payment under the Annual Incentive Plan is pro-rated based on the actual number of days employed during the performance year in which the retirement date occurs. Similarly, payments under the Performance Unit Program for those retiring with a minimum 12 months of participation are pro-rated based on the actual full months of participation, in each outstanding performance cycle, in which the retirement date occurs. In each case, payments are delivered at the conclusion of each annual or performance cycle, consistent with the timing of payments to active participants in the Annual Incentive Plan and the Performance Unit Program, respectively. Unvested stock options issued under Entergy Corporation’s equity ownership plans vest on the retirement date and expire ten years from the grant date of the options. Any restricted stock and restricted stock units (other than those issued under the Performance Unit Program) held by the executive upon his or her retirement are forfeited, and perquisites are not available following the separation date.
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 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 System company employer, he or she generally is entitled to the same compensation and separation benefits described above under “Retirement,” including:
•
all unvested stock options will vest immediately;
•
vested stock options will expire ten years from the grant date; and
•
restricted units may be subject to specific death benefits depending on the restricted unit agreement (as noted, where applicable, in the tables above).

Compensation of Directors

For information regarding compensation of the directors of Entergy Corporation, see the Proxy Statement under the heading “Director Compensation,” which information is incorporated herein by reference.  The Boards of Directors of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas are comprised solely of employee directors who receive no compensation for service as directors.




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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 Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas.  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 “Stockholders Who Own at Least 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.


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The following table sets forth the beneficial ownership of Common Stock of Entergy Corporation and stock-based units as of January 31, 2015 for all directors and Named Executive Officers.  Unless otherwise noted, each person had sole voting and investment power over the number of shares of Common Stock and stock-based units of Entergy Corporation set forth across from his or her name.

 
Name
 
 
Shares (1)
 
Options Exercisable
Within 60 Days
 
 
Stock Units (2)
Entergy Corporation
 
 
 
 
 
 
Maureen S. Bateman*
 
6,258

 
—

 
11,263

Leo P. Denault***
 
64,450

 
378,666

 
—

Kirkland H. Donald*
 
965

 
—

 
753

Gary W. Edwards*
 
1,791

 
—

 
10,852

Alexis Herman*
 
556

 
—

 
8,863

Donald C. Hintz*
 
3,650

 
—

 
10,471

Stuart L. Levenick*
 
5,758

 
—

 
7,094

Blanche L. Lincoln*
 
2,618

 
—

 
2,663

Andrew S. Marsh**
 
18,620

 
84,599

 
—

William M. Mohl**
 
18,946

 
80,799

 
—

Stewart C. Myers*
 
3,682

 
—

 
3,846

Mark T. Savoff**
 
26,546

 
182,832

 
305

W. J. Tauzin*
 
5,658

 
—

 
6,956

Roderick K. West**
 
26,191

 
117,666

 
—

Steven V. Wilkinson*
 
6,813

 
—

 
8,490

All directors and executive
 
 
 
 
 
 
officers as a group (20 persons)
 
271,309

 
1,153,759

 
71,617

 
 
 
 
 
 
 
Entergy Arkansas
 
 

 
 

 
 

Theodore H. Bunting, Jr.*
 
21,009

 
111,466

 
—

Leo P. Denault**
 
64,450

 
378,666

 
—

Andrew S. Marsh***
 
18,620

 
84,599

 
—

Hugh T. McDonald***
 
15,653

 
48,933

 
—

Alyson M. Mount**
 
9,653

 
15,700

 
—

Mark T. Savoff***
 
26,546

 
182,832

 
305

Roderick K. West**
 
26,191

 
117,666

 
—

All directors and executive
 
 
 
 
 
 
officers as a group (10 persons)
 
230,267

 
1,121,893

 
366

 
 
 
 
 
 
 
Entergy Gulf States Louisiana
 
 
 
 
 
 
Theodore H. Bunting, Jr.*
 
21,009

 
111,466

 
—

Leo P. Denault**
 
64,450

 
378,666

 
—

Andrew S. Marsh***
 
18,620

 
84,599

 
—

Phillip R. May, Jr.***
 
12,886

 
40,866

 
11

Alyson M. Mount**
 
9,653

 
15,700

 
—

Mark T. Savoff***
 
26,546

 
182,832

 
305

Roderick K. West**
 
26,191

 
117,666

 
—

All directors and executive
 
 
 
 
 
 
officers as a group (10 persons)
 
227,500

 
1,113,826

 
377


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Table of Contents

 
Name
 
 
Shares (1)
 
Options Exercisable
Within 60 Days
 
 
Stock Units (2)
Entergy Louisiana
 
 
 
 
 
 
Theodore H. Bunting, Jr.*
 
21,009

 
111,466

 
—

Leo P. Denault**
 
64,450

 
378,666

 
—

Andrew S. Marsh***
 
18,620

 
84,599

 
—

Phillip R. May, Jr.***
 
12,886

 
40,866

 
11

Alyson M. Mount**
 
9,653

 
15,700

 
—

Mark T. Savoff***
 
26,546

 
182,832

 
305

Roderick K. West**
 
26,191

 
117,666

 
—

All directors and executive
 
 
 
 
 
 
officers as a group (10 persons)
 
227,500

 
1,113,826

 
377

 
 
 
 
 
 
 
Entergy Mississippi
 
 
 
 
 
 
Theodore H. Bunting, Jr.*
 
21,009

 
111,466

 
—

Leo P. Denault**
 
64,450

 
378,666

 
—

Haley R. Fisackerly***
 
7,269

 
28,667

 
—

Andrew S. Marsh***
 
18,620

 
84,599

 
—

Alyson M. Mount**
 
9,653

 
15,700

 
—

Mark T. Savoff***
 
26,546

 
182,832

 
305

Roderick K. West**
 
26,191

 
117,666

 
—

All directors and executive
 
 
 
 
 
 
officers as a group (9 persons)
 
203,967

 
1,002,461

 
305

 
 
 
 
 
 
 
Entergy New Orleans
 
 
 
 
 
 
Theodore H. Bunting, Jr.*
 
21,009

 
111,466

 
—

Leo P. Denault**
 
64,450

 
378,666

 
—

Andrew S. Marsh***
 
18,620

 
84,599

 
—

Alyson M. Mount**
 
9,653

 
15,700

 
—

Charles L. Rice, Jr.***
 
4,831

 
12,566

 
—

Mark T. Savoff***
 
26,546

 
182,832

 
305

Roderick K. West**
 
26,191

 
117,666

 
—

All directors and executive
 
 
 
 
 
 
officers as a group (9 persons)
 
201,529

 
986,360

 
305

 
 
 
 
 
 
 
Entergy Texas
 
 
 
 
 
 
Theodore H. Bunting, Jr.*
 
21,009

 
111,466

 
—

Leo P. Denault**
 
64,450

 
378,666

 
—

Andrew S. Marsh***
 
18,620

 
84,599

 
—

Alyson M. Mount**
 
9,653

 
15,700

 
—

Sallie T. Rainer***
 
8,586

 
16,299

 
—

Mark T. Savoff***
 
26,546

 
182,832

 
305

Roderick K. West**
 
26,191

 
117,666

 
—

All directors and executive
 
 
 
 
 
 
officers as a group (9 persons)
 
205,284

 
990,093

 
305




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*
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 directors and executive officers as a group does not exceed one percent of the outstanding Entergy Corporation common stock.
(2)
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.  For directors of Entergy Corporation the phantom units are issued under the Service Recognition Program for Outside Directors.  All non-employee directors are credited with units for each year of service on the Board.  In addition, Messrs. Edwards and Hintz 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.

Equity Compensation Plan Information

The following table summarizes the equity compensation plan information as of December 31, 2014. 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)
 
7,281,396

 
$83.25
 
3,569,309

Equity compensation plans not
  approved by security holders(2)
 
—

 
—

 
—

Total
 
7,281,396

 
$83.25
 
3,569,309


(1)
Includes the Equity Ownership Plan, which was approved by the shareholders on May 15, 1998, the 2007 Equity Ownership Plan and the 2011 Equity Ownership Plan.  The 2007 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 12, 2006, and 7,000,000 shares of Entergy Corporation common stock can be issued, with no more than 2,000,000 shares available for non-option grants.  The 2011 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 6, 2011, and 5,500,000 shares of Entergy Corporation common stock can be issued from the 2011 Equity Ownership Plan, with no more than 2,000,000 shares available for incentive stock option grants.  The Equity Ownership Plan, the 2007 Equity Ownership Plan and the 2011 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 System 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 shares, 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) and other stock-based awards.

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Table of Contents

(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, 2014, all options outstanding under the plan were either exercised or expired.

Item 13.  Certain Relationships and Related Transactions and Director Independence

For information regarding certain relationships, related transactions and director independence of Entergy Corporation, see the Proxy Statement under the headings “Corporate Governance - Director Independence” and “Transactions with Related Persons,” which information is incorporated herein by reference.

Since December 31, 2011, none of the Subsidiaries or any of their affiliates has participated in any transaction involving an amount in excess of $120,000 in which any director or executive officer of any of the Subsidiaries, any nominee for director, or any immediate family member of the foregoing had a material interest as contemplated by Item 404(a) of Regulation S-K (“Related Party Transactions”).

Entergy Corporation’s Board of Directors has adopted written policies and procedures for the review, approval or ratification of Related Party Transactions.  Under these policies and procedures, the Corporate Governance Committee, or a subcommittee of the Board of Directors of Entergy Corporation composed 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 at least as favorable to Entergy Corporation or the subsidiary as those achievable with an unaffiliated third party;
•
Size of 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 Party Transactions involving a director or an executive officer solely resulting from that person’s service as a director or employment with the Company so long as the compensation is approved by Entergy’s Board of Directors, (b) transactions involving the rendering of services as a public utility 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 SK.

None of the Subsidiaries are listed issuers.  As previously noted, the Boards of Directors of the Subsidiaries are composed solely of employee directors.  None of the Boards of Directors of any of the Subsidiaries has any committees.


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Item 14.  Principal Accountant Fees and Services (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Aggregate fees billed to Entergy Corporation (consolidated), Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy for the years ended December 31, 2014 and 2013 by Deloitte & Touche LLP were as follows:

 
2014
 
2013
Entergy Corporation (consolidated)
 
 
 
Audit Fees

$8,097,000

 

$9,832,698

Audit-Related Fees (a)
1,135,000

 
545,000

Total audit and audit-related fees
9,232,000

 
10,377,698

Tax Fees (b)
—

 
—

All Other Fees
—

 
—

Total Fees (c)

$9,232,000

 

$10,377,698

Entergy Arkansas
 
 
 
Audit Fees

$984,813

 

$985,484

Audit-Related Fees (a)
19,000

 
—

Total audit and audit-related fees
1,003,813

 
985,484

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (c)

$1,003,813

 

$985,484

Entergy Gulf States Louisiana
 
 
 
Audit Fees

$874,813

 

$840,484

Audit-Related Fees (a)
375,000

 
100,000

Total audit and audit-related fees
1,249,813

 
940,484

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (c)

$1,249,813

 

$940,484

Entergy Louisiana
 
 
 
Audit Fees

$1,134,813

 

$985,484

Audit-Related Fees (a)
375,000

 
100,000

Total audit and audit-related fees
1,509,813

 
1,085,484

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (c)

$1,509,813

 

$1,085,484


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Table of Contents

 
2014
 
2013
Entergy Mississippi
 
 
 
Audit Fees

$869,813

 

$840,484

Audit-Related Fees (a)
—

 
—

Total audit and audit-related fees
869,813

 
840,484

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (c)

$869,813

 

$840,484

Entergy New Orleans
 
 
 
Audit Fees

$824,813

 

$885,484

Audit-Related Fees (a)
—

 
—

Total audit and audit-related fees
824,813

 
885,484

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (c)

$824,813

 

$885,484

Entergy Texas
 
 
 
Audit Fees

$1,004,813

 

$1,886,280

Audit-Related Fees (a)
—

 
—

Total audit and audit-related fees
1,004,813

 
1,886,280

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (c)

$1,004,813

 

$1,886,280

System Energy
 
 
 
Audit Fees

$824,813

 

$840,484

Audit-Related Fees (a)
—

 
—

Total audit and audit-related fees
824,813

 
840,484

Tax Fees
—

 
—

All Other Fees
—

 
—

Total Fees (c)

$824,813

 

$840,484


(a)
Includes fees for employee benefit plan audits, consultation on financial accounting and reporting, and other attestation services.
(b)
Includes fees for tax advisory services.
(c)
100% of fees paid in 2014 and 2013 were pre-approved by the Entergy Corporation Audit Committee.

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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 the only qualified provider of that service or if the Audit Committee specifically requests the service.
3.
The Audit Committee will be informed quarterly as to the status of pre-approved services actually provided by the independent auditor.
4.
To ensure prompt handling of unexpected matters, the Audit Committee delegates to the Audit Committee Chair or its designee the authority to approve permissible services and fees.  The Audit Committee Chair or designee will report action taken to the Audit Committee at the next scheduled Audit Committee meeting.
5.
The Vice President and General Auditor will be responsible for tracking all independent auditor fees and will report quarterly to the Audit Committee.


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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 Gulf States Louisiana, 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 529)
 
 
 
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 Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are listed in the Exhibit Index (see page E-1).  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.


519
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, 2015

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, 2015

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, Kirkland H. Donald, Gary W. Edwards, Alexis M. Herman, Donald C. Hintz, Stuart L. Levenick, Blanche L. Lincoln, Stewart C. Myers, W. J. Tauzin, and Steven V. Wilkinson (Directors).

By: /s/ Alyson M. Mount
February 26, 2015
(Alyson M. Mount, Attorney-in-fact)
 


520
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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, 2015

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, 2015

Hugh T. McDonald (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); Theodore H. Bunting, Jr. and Mark T. Savoff (Directors).

By: /s/ Alyson M. Mount
February 26, 2015
(Alyson M. Mount, Attorney-in-fact)
 

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Table of Contents

ENTERGY GULF STATES LOUISIANA, L.L.C.

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 GULF STATES LOUISIANA, L.L.C.
 
 
 
By  /s/ Alyson M. Mount
 
Alyson M. Mount
 
Senior Vice President and Chief Accounting Officer
 
 
 
Date: February 26, 2015

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, 2015

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); Theodore H. Bunting, Jr. and Mark T. Savoff (Directors).

By:  /s/ Alyson M. Mount
February 26, 2015
(Alyson M. Mount, Attorney-in-fact)
 

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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, 2015

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, 2015

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); Theodore H. Bunting, Jr. and Mark T. Savoff (Directors).

By: /s/ Alyson M. Mount
February 26, 2015
(Alyson M. Mount, Attorney-in-fact)
 

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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, 2015

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, 2015

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); Theodore H. Bunting, Jr. and Mark T. Savoff (Directors).

By: /s/ Alyson M. Mount
February 26, 2015
(Alyson M. Mount, Attorney-in-fact)
 

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Table of Contents

ENTERGY NEW ORLEANS, 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 NEW ORLEANS, INC.
 
 
 
By  /s/ Alyson M. Mount
 
Alyson M. Mount
 
Senior Vice President and Chief Accounting Officer
 
 
 
Date: February 26, 2015

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, 2015

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); Theodore H. Bunting, Jr. and Mark T. Savoff (Directors).

By: /s/ Alyson M. Mount
February 26, 2015
(Alyson M. Mount, Attorney-in-fact)
 

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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, 2015

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, 2015

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); Theodore H. Bunting, Jr. and Mark T. Savoff (Directors).

By:  /s/ Alyson M. Mount
February 26, 2015
(Alyson M. Mount, Attorney-in-fact)
 

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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, 2015

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, 2015

Theodore H. Bunting, 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); Jeffrey S. Forbes and Steven C. McNeal (Directors).

By: /s/ Alyson M. Mount
February 26, 2015
(Alyson M. Mount, Attorney-in-fact)
 


527
Table of Contents

EXHIBIT 23(a)

CONSENTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-190911 on Form S-3 and in Registration Statements Nos. 333-55692, 333-68950, 333-75097, 333-90914, 333-98179, 333-140183, 333-142055, 333-168664, 333-174148, and 333-183090 on Form S-8 of our reports dated February 26, 2015, 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, 2014.

We consent to the incorporation by reference in Registration Statement No. 333-190911-02 on Form S-3 of our reports dated February 26, 2015, 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, 2014.

We consent to the incorporation by reference in Registration Statement No. 333-190911-07 on Form S-3 of our reports dated February 26, 2015, 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, 2014.

We consent to the incorporation by reference in Registration Statement No. 333-190911-06 on Form S-3 of our reports dated February 26, 2015, relating to the financial statements and financial statement schedule of Entergy Mississippi, Inc. appearing in this Annual Report on Form 10-K of Entergy Mississippi, Inc. for the year ended December 31, 2014.

We consent to the incorporation by reference in Registration Statement No. 333-190911-05 on Form S-3 of our reports dated February 26, 2015, relating to the financial statements and financial statement schedule of Entergy New Orleans, Inc. appearing in this Annual Report on Form 10-K of Entergy New Orleans, Inc. for the year ended December 31, 2014.

We consent to the incorporation by reference in Registration Statement No. 333-190911-04 on Form S-3 of our reports dated February 26, 2015, 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, 2014.

We consent to the incorporation by reference in Registration Statement No. 333-190911-03 on Form S-3 of our reports dated February 26, 2015, 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, 2014.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana
February 26, 2015

528
Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Board of Directors and Shareholders of
Entergy Corporation and Subsidiaries


We have audited the consolidated financial statements of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2014 and 2013, and for each of the three years in the period ended December 31, 2014, and the Corporation’s internal control over financial reporting as of December 31, 2014, and have issued our reports thereon dated February 26, 2015; such consolidated financial statements and reports are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedules of the Corporation listed in Item 15. These consolidated financial statement schedules are the responsibility of the Corporation’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated 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, 2015



529
Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Board of Directors and Shareholders of
Entergy Arkansas, Inc. and Subsidiaries
Entergy Mississippi, Inc.
Entergy New Orleans, Inc.
Entergy Texas, Inc. and Subsidiaries

To the Board of Directors and Members of
Entergy Gulf States Louisiana, L.L.C.
Entergy Louisiana, LLC and Subsidiaries


We have audited the consolidated financial statements of Entergy Arkansas, Inc. and Subsidiaries, Entergy Louisiana, LLC and Subsidiaries, and Entergy Texas, Inc. and Subsidiaries, and we have also audited the financial statements of Entergy Gulf States Louisiana, L.L.C., Entergy Mississippi, Inc., and Entergy New Orleans, Inc. (collectively the “Companies”) as of December 31, 2014 and 2013, and for each of the three years in the period ended December 31, 2014, and have issued our reports thereon dated February 26, 2015; such financial statements and reports are included elsewhere in this Form 10-K. 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’ managements. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic 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, 2015



530
Table of Contents

INDEX TO FINANCIAL STATEMENT SCHEDULES



Schedule
 
Page
 
 
 
II
Valuation and Qualifying Accounts 2014, 2013, and 2012:
 
 
Entergy Corporation and Subsidiaries
 
Entergy Arkansas, Inc. and Subsidiaries
 
Entergy Gulf States Louisiana, L.L.C.
 
Entergy Louisiana, LLC and Subsidiaries
 
Entergy Mississippi, Inc.
 
Entergy New Orleans, Inc.
 
Entergy Texas, Inc. and Subsidiaries

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, 2014, 2013, and 2012
(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
 
 
 
 
 
 
 
 
2014
 

$34,311

 

$4,573

 

$3,221

 

$35,663

2013
 

$31,956

 

$2,355

 

$—

 

$34,311

2012
 

$31,159

 

$2,448

 

$1,651

 

$31,956

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, 2014, 2013, and 2012
(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
 
 
 
 
 
 
 
 
2014
 

$30,113

 

$2,881

 

$747

 

$32,247

2013
 

$28,343

 

$1,770

 

$—

 

$30,113

2012
 

$26,155

 

$2,188

 

$—

 

$28,343

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 GULF STATES LOUISIANA, L.L.C.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2014, 2013, and 2012
(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
 
 
 
 
 
 
 
 
2014
 

$909

 

$326

 

$610

 

$625

2013
 

$711

 

$198

 

$—

 

$909

2012
 

$843

 

$123

 

$255

 

$711

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 LOUISIANA, LLC AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2014, 2013, and 2012
(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
 
 
 
 
 
 
 
 
2014
 

$965

 

$516

 

$497

 

$984

2013
 

$867

 

$98

 

$—

 

$965

2012
 

$1,147

 

$121

 

$401

 

$867

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 MISSISSIPPI, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2014, 2013, and 2012
(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
 
 
 
 
 
 
 
 
2014
 

$906

 

$269

 

$302

 

$873

2013
 

$910

 

($4
)
 

$—

 

$906

2012
 

$756

 

$154

 

$—

 

$910

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 NEW ORLEANS, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2014, 2013, and 2012
(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
 
 
 
 
 
 
 
 
2014
 

$974

 

$99

 

$811

 

$262

2013
 

$446

 

$528

 

$—

 

$974

2012
 

$465

 

$12

 

$31

 

$446

Notes:
 
 

 
 

 
 

 
 

(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.


S-7
Table of Contents

ENTERGY TEXAS, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2014, 2013, and 2012
(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
 
 
 
 
 
 
 
 
2014
 

$443

 

$483

 

$254

 

$672

2013
 

$680

 

($237
)
 

$—

 

$443

2012
 

$1,461

 

($21
)
 

$760

 

$680

Notes:
 
 

 
 

 
 

 
 

(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.



S-8
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 Gulf States Louisiana
(b) 1 --
Plan of Merger of Entergy Gulf States, Inc. effective December 31, 2007 (2(ii) to Form 8-K15D5 filed January 7, 2008 in 333-148557).

(3) Articles of Incorporation and By-laws

Entergy Corporation
(a) 1 --
Restated Certificate of Incorporation of Entergy Corporation dated October 10, 2006 (3(a) to Form 10-Q for the quarter ended September 30, 2006).
 
 
(a) 2 --
By-Laws of Entergy Corporation as amended February 12, 2007, and as presently in effect (3(ii) to Form 8-K filed February 16, 2007 in 1-11299).

System Energy
(b) 1 --
Amended and Restated Articles of Incorporation of System Energy and amendments thereto through April 28, 1989 (A-1(a) to Form U-1 in 70-5399).
 
 
(b) 2 --
By-Laws of System Energy effective July 6, 1998, and as presently in effect (3(f) to Form 10-Q for the quarter ended June 30, 1998 in 1-9067).

Entergy Arkansas
(c) 1 --
Articles of Amendment and Restatement for the Second Amended and Restated Articles of Incorporation of Entergy Arkansas, effective August 19, 2009 (3 to Form 8-K filed August 24, 2009 in 1-10764).
 
 
(c) 2 --
By-Laws of Entergy Arkansas effective November 26, 1999, and as presently in effect (3(ii)(c) to Form 10-K for the year ended December 31, 1999 in 1-10764).


E-1
Table of Contents

Entergy Gulf States Louisiana
(d) 1 --
Articles of Organization of Entergy Gulf States Louisiana effective December 31, 2007 (3(i) to Form 8-K15D5 filed January 7, 2008 in 333-148557).
 
 
(d) 2 --
Operating Agreement of Entergy Gulf States Louisiana, effective as of December 31, 2007 (3(ii) to Form 8-K15D5 filed January 7, 2008 in 333-148557).

Entergy Louisiana
(e) 1 --
Articles of Organization of Entergy Louisiana effective December 31, 2005 (3(c) to Form 8-K filed January 6, 2006 in 1-32718).
 
 
(e) 2 --
Regulations of Entergy Louisiana effective December 31, 2005, and as presently in effect (3(d) to Form 8-K filed January 6, 2006 in 1-32718).

Entergy Mississippi
(f) 1 --
Second Amended and Restated Articles of Incorporation of Entergy Mississippi, effective July 21, 2009 (99.1 to Form 8-K filed July 27, 2009 in 1-31508).
 
 
(f) 2 --
By-Laws of Entergy Mississippi effective November 26, 1999, and as presently in effect (3(ii)(f) to Form 10-K for the year ended December 31, 1999 in 0-320).

Entergy New Orleans
(g) 1 --
Amended and Restated Articles of Incorporation of Entergy New Orleans, effective May 8, 2007 (3(a) to Form 10-Q for the quarter ended March 31, 2007 in 0-5807).
 
 
(g) 2 --
Amended By-Laws of Entergy New Orleans effective May 8, 2007, and as presently in effect (3(b) to Form 10-Q for the quarter ended March 31, 2007 in 0-5807).

Entergy Texas
(h) 1 --
Certificate of Formation of Entergy Texas, effective December 31, 2007 (3(i) to Form 10 filed March 14, 2008 in 000-53134).
 
 
(h) 2 --
Bylaws of Entergy Texas effective December 31, 2007 (3(ii) to Form 10 filed March 14, 2008 in 000-53134).


E-2
Table of Contents

(4)Instruments Defining Rights of Security Holders, Including Indentures

Entergy Corporation
(a) 1 --
See (4)(b) through (4)(h) below for instruments defining the rights of holders of long-term debt of System Energy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas.
 
 
(a) 2 --
Credit Agreement ($3,500,000,000), dated as of March 9, 2012, among Entergy Corporation, as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, Bank of the West, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, National Cooperative Services Corporation, and The Northern Trust Company), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.1 to Form 8-K filed March 14, 2012 in 1-11299).
 
 
*(a) 3 --
Extension Agreement, dated as of March 1, 2013, to Credit Agreement.
 
 
*(a) 4 --
Extension Agreement, dated as of March 14, 2014, to Credit Agreement.
 
 
(a) 5 --
Indenture (For Unsecured Debt Securities), dated as of September 1, 2010, between Entergy Corporation and Wells Fargo Bank, National Association (4.01 to Form 8-K filed September 16, 2010 in 1-11299).
 
 
(a) 6 --
Officer’s Certificate for Entergy Corporation relating to 3.625% Senior Notes due September 15, 2015 (4.02(a) to Form 8-K filed September 16, 2010 in 1-11299).
 
 
(a) 7 --
Officer’s Certificate for Entergy Corporation relating to 5.125% Senior Notes due September 15, 2020 (4.02(b) to Form 8-K filed September 16, 2010 in 1-11299).
 
 
(a) 8 --
Officer’s Certificate for Entergy Corporation relating to 4.70% Senior Notes due January 15, 2017 (4.02 to Form 8-K filed January 13, 2012 in 1-11299).
 
 
(a) 9 --
Officer’s Certificate for Entergy Corporation relating to 4.50% Senior Note due December 16, 2028 (4(a)7 to Form 10-K for the year ended December 31, 2013 in 1-11299).


E-3
Table of Contents

System Energy
(b) 1 --
Mortgage and Deed of Trust, dated as of June 15, 1977, as amended by twenty-four Supplemental Indentures (A-1 in 70-5890 (Mortgage); B and C to Rule 24 Certificate in 70-5890 (First); B to Rule 24 Certificate in 70-6259 (Second); 20(a)-5 to Form 10-Q for the quarter ended June 30, 1981 in 1-3517 (Third); A-1(e)-1 to Rule 24 Certificate in 70-6985 (Fourth); B to Rule 24 Certificate in 70-7021 (Fifth); B to Rule 24 Certificate in 70-7021 (Sixth); A-3(b) to Rule 24 Certificate in 70-7026 (Seventh); A-3(b) to Rule 24 Certificate in 70-7158 (Eighth); B to Rule 24 Certificate in 70-7123 (Ninth); B-1 to Rule 24 Certificate in 70-7272 (Tenth); B-2 to Rule 24 Certificate in 70-7272 (Eleventh); B-3 to Rule 24 Certificate in 70-7272 (Twelfth); B-1 to Rule 24 Certificate in 70-7382 (Thirteenth); B-2 to Rule 24 Certificate in 70-7382 (Fourteenth); A-2(c) to Rule 24 Certificate in 70-7946 (Fifteenth); A-2(c) to Rule 24 Certificate in 70-7946 (Sixteenth); A-2(d) to Rule 24 Certificate in 70-7946 (Seventeenth); A-2(e) to Rule 24 Certificate dated May 4, 1993 in 70-7946 (Eighteenth); A-2(g) to Rule 24 Certificate dated May 6, 1994 in 70-7946 (Nineteenth); A-2(a)(1) to Rule 24 Certificate dated August 8, 1996 in 70-8511 (Twentieth); A-2(a)(2) to Rule 24 Certificate dated August 8, 1996 in 70-8511 (Twenty-first); A-2(a) to Rule 24 Certificate filed October 4, 2002 in 70-9753 (Twenty-second); 4(b) to Form 10-Q for the quarter ended September 30, 2007 in 1-9067 (Twenty-third); and 4.42 to Form 8-K dated September 25, 2012 in 1-9067 (Twenty-fourth)).
 
 
(b) 2 --
Facility Lease No. 1, dated as of December 1, 1988, between Meridian Trust Company and Stephen M. Carta (Steven Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (1) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-3(d) to Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-3(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182).
 
 
(b) 3 --
Facility Lease No. 2, dated as of December 1, 1988 between Meridian Trust Company and Stephen M. Carta (Steven Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (2) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-4(d) Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-4(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182).


E-4
Table of Contents

Entergy Arkansas
(c) 1 --
Mortgage and Deed of Trust, dated as of October 1, 1944, as amended by seventy-seven Supplemental Indentures (7(d) in 2-5463 (Mortgage); 7(b) in 2-7121 (First); 7(c) in 2-7605 (Second); 7(d) in 2-8100 (Third); 7(a)-4 in 2-8482 (Fourth); 7(a)-5 in 2-9149 (Fifth); 4(a)-6 in 2-9789 (Sixth); 4(a)-7 in 2-10261 (Seventh); 4(a)-8 in 2-11043 (Eighth); 2(b)-9 in 2-11468 (Ninth); 2(b)-10 in 2-15767 (Tenth); D in 70-3952 (Eleventh); D in 70-4099 (Twelfth); 4(d) in 2-23185 (Thirteenth); 2(c) in 2-24414 (Fourteenth); 2(c) in 2-25913 (Fifteenth); 2(c) in 2-28869 (Sixteenth); 2(d) in 2-28869 (Seventeenth); 2(c) in 2-35107 (Eighteenth); 2(d) in 2-36646 (Nineteenth); 2(c) in 2-39253 (Twentieth); 2(c) in 2-41080 (Twenty-first); C-1 to Rule 24 Certificate in 70-5151 (Twenty-second); C-1 to Rule 24 Certificate in 70-5257 (Twenty-third); C to Rule 24 Certificate in 70-5343 (Twenty-fourth); C-1 to Rule 24 Certificate in 70-5404 (Twenty-fifth); C to Rule 24 Certificate in 70-5502 (Twenty-sixth); C-1 to Rule 24 Certificate in 70-5556 (Twenty-seventh); C-1 to Rule 24 Certificate in 70-5693 (Twenty-eighth); C-1 to Rule 24 Certificate in 70-6078 (Twenty-ninth); C-1 to Rule 24 Certificate in 70-6174 (Thirtieth); C-1 to Rule 24 Certificate in 70-6246 (Thirty-first); C-1 to Rule 24 Certificate in 70-6498 (Thirty-second); A-4b-2 to Rule 24 Certificate in 70-6326 (Thirty-third); C-1 to Rule 24 Certificate in 70-6607 (Thirty-fourth); C-1 to Rule 24 Certificate in 70-6650 (Thirty-fifth); C-1 to Rule 24 Certificate dated December 1, 1982 in 70-6774 (Thirty-sixth); C-1 to Rule 24 Certificate dated February 17, 1983 in 70-6774 (Thirty-seventh); A-2(a) to Rule 24 Certificate dated December 5, 1984 in 70-6858 (Thirty-eighth); A-3(a) to Rule 24 Certificate in 70-7127 (Thirty-ninth); A-7 to Rule 24 Certificate in 70-7068 (Fortieth); A-8(b) to Rule 24 Certificate dated July 6, 1989 in 70-7346 (Forty-first); A-8(c) to Rule 24 Certificate dated February 1, 1990 in 70-7346 (Forty-second); 4 to Form 10-Q for the quarter ended September 30, 1990 in 1-10764 (Forty-third); A-2(a) to Rule 24 Certificate dated November 30, 1990 in 70-7802 (Forty-fourth); A-2(b) to Rule 24 Certificate dated January 24, 1991 in 70-7802 (Forty-fifth); 4(d)(2) in 33-54298 (Forty-sixth); 4(c)(2) to Form 10-K for the year ended December 31, 1992 in 1-10764 (Forty-seventh); 4(b) to Form 10-Q for the quarter ended June 30, 1993 in 1-10764 (Forty-eighth); 4(c) to Form 10-Q for the quarter ended June 30, 1993 in 1-10764 (Forty-ninth); 4(b) to Form 10-Q for the quarter ended September 30, 1993 in 1-10764 (Fiftieth); 4(c) to Form 10-Q for the quarter ended September 30, 1993 in 1-10764 (Fifty-first); 4(a) to Form 10-Q for the quarter ended June 30, 1994 in 1-10764 (Fifty-second); C-2 to Form U5S for the year ended December 31, 1995 (Fifty-third); C-2(a) to Form U5S for the year ended December 31, 1996 (Fifty-fourth); 4(a) to Form 10-Q for the quarter ended March 31, 2000 in 1-10764 (Fifty-fifth); 4(a) to Form 10-Q for the quarter ended September 30, 2001 in 1-10764 (Fifty-sixth); C-2(a) to Form U5S for the year ended December 31, 2001 (Fifty-seventh); 4(c)1 to Form 10-K for the year December 31, 2002 in 1-10764 (Fifty-eighth); 4(a) to Form 10-Q for the quarter ended June 30, 2003 in 1-10764 (Fifty-ninth); 4(f) to Form 10-Q for the quarter ended June 30, 2003 in 1-10764 (Sixtieth); 4(h) to Form 10-Q for the quarter ended June 30, 2003 in 1-10764 (Sixty-first); 4(e) to Form 10-Q for the quarter ended September 30, 2004 in 1-10764 (Sixty-second); 4(c)1 to Form 10-K for the year December 31, 2004 in 1-10764 (Sixty-third); C-2(a) to Form U5S for the year ended December 31, 2004 (Sixty-fourth); 4(c) to Form 10-Q for the quarter ended June 30, 2005 in 1-10764 (Sixty-fifth);  4(a) to Form 10-Q for the quarter ended June 30, 2006 in 1-10764 (Sixty-sixth); 4(b) to Form 10-Q for the quarter ended June 30, 2008 in 1-10764 (Sixty-seventh); 4(c)1 to Form 10-K for the year ended December 31, 2008 in 1-10764 (Sixty-eighth); 4.06 to Form 8-K dated October 8, 2010 in 1-10764 (Sixty-ninth); 4.06 to Form 8-K dated November 12, 2010 in 1-10764 (Seventieth); 4.06 to Form 8-K dated December 13, 2012 in 1-10764 (Seventy-first); 4(e) to Form 8-K dated January 9, 2013 in 1-10764 (Seventy-second); 4.06 to Form 8-K dated May 30, 2013 in 1-10764 (Seventy-third); 4.06 to Form 8-K dated June 4, 2013 in 1-10764 (Seventy-fourth); 4.02 to Form 8-K dated July 26, 2013 in 1-10764 (Seventy-fifth); 4.05 to Form 8-K dated March 14, 2014 in 1-10764 (Seventy-sixth); and 4.05 to Form 8-K dated December 9, 2014 in 1-10764 (Seventy-Seventh)).
 
 
(c) 2 --
Credit Agreement ($150,000,000), dated as of March 9, 2012, among Entergy Arkansas, Inc., as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, and National Cooperative Services Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.2 to Form 8-K filed March 14, 2012 in 1-10764).
 
 
*(c) 3 --
Extension Agreement, dated as of March 1, 2013, to Credit Agreement.
 
 
*(c) 4 --
Extension Agreement, dated as of March 14, 2014, to Credit Agreement.

E-5
Table of Contents

Entergy Gulf States Louisiana
(d) 1 --
Indenture of Mortgage, dated September 1, 1926, as amended by certain Supplemental Indentures (B-a-I-1 in Registration No. 2-2449 (Mortgage); 7-A-9 in Registration No. 2-6893 (Seventh); B to Form 8-K dated September 1, 1959 (Eighteenth); B to Form 8-K dated February 1, 1966 (Twenty-second); B to Form 8-K dated March 1, 1967 (Twenty-third); C to Form 8-K dated March 1, 1968 (Twenty-fourth); B to Form 8-K dated November 1, 1968 (Twenty-fifth); B to Form 8-K dated April 1, 1969 (Twenty-sixth); 2-A-8 in Registration No. 2-66612 (Thirty-eighth); 4-2 to Form 10-K for the year ended December 31, 1984 in 1-27031 (Forty-eighth); 4-2 to Form 10-K for the year ended December 31, 1988 in 1-27031 (Fifty-second); 4 to Form 10-K for the year ended December 31, 1991 in 1-27031 (Fifty-third); 4 to Form 8-K dated July 29, 1992 in 1-27031 (Fifth-fourth); 4 to Form 10-K dated  December 31, 1992 in 1-27031 (Fifty-fifth); 4 to Form 10-Q for the quarter ended March 31, 1993 in 1-27031 (Fifty-sixth); 4-2 to Amendment No. 9 to Registration No. 2-76551 (Fifty-seventh); 4(b) to Form 10-Q for the quarter ended March 31,1999 in 1-27031 (Fifty-eighth); A-2(a) to Rule 24 Certificate dated June 23, 2000 in 70-8721 (Fifty-ninth); A-2(a) to Rule 24 Certificate dated September 10, 2001 in 70-9751 (Sixtieth); A-2(b) to Rule 24 Certificate dated November 18, 2002 in 70-9751 (Sixty-first); A-2(c) to Rule 24 Certificate dated December 6, 2002 in 70-9751 (Sixty-second); A-2(d) to Rule 24 Certificate dated June 16, 2003 in 70-9751 (Sixty-third); A-2(e) to Rule 24 Certificate dated June 27, 2003 in 70-9751 (Sixty-fourth); A-2(f) to Rule 24 Certificate dated July 11, 2003 in 70-9751 (Sixty-fifth); A-2(g) to Rule 24 Certificate dated July 28, 2003 in 70-9751 (Sixty-sixth); A-3(i) to Rule 24 Certificate dated November 4, 2004 in 70-10158 (Sixty-seventh); A-3(ii) to Rule 24 Certificate dated November 23, 2004 in 70-10158 (Sixty-eighth); A-3(iii) to Rule 24 Certificate dated February 16, 2005 in 70-10158 (Sixty-ninth); A-3(iv) to Rule 24 Certificate dated June 2, 2005 in 70-10158 (Seventieth); A-3(v) to Rule 24 Certificate dated July 21, 2005 in 70-10158 (Seventy-first); A-3(vi) to Rule 24 Certificate dated October 7, 2005 in 70-10158 (Seventy-second); A-3(vii) to Rule 24 Certificate dated December 19, 2005 in 70-10158 (Seventy-third); 4(a) to Form 10-Q for the quarter ended March 31, 2006 in 1-27031 (Seventy-fourth); 4(iv) to Form 8-K15D5 dated January 7, 2008 in 333-148557 (Seventy-fifth); 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 dated October 1, 2010 in 0-20371 (Seventy-eighth); 4(c) to Form 8-K filed October 12, 2010 in 0-20371 (Seventy-ninth); 4(f) to Form 8-K filed October 12, 2010 in 0-20371 (Eightieth); and 4.07 to Form 8-K dated July 1, 2014 in 0-20371 (Eighty-first)).
 
 
(d) 2 --
Indenture, dated March 21, 1939, accepting resignation of The Chase National Bank of the City of New York as trustee and appointing Central Hanover Bank and Trust Company as successor trustee (B-a-1-6 in Registration No. 2-4076).
 
 
(d) 3 --
Agreement of Resignation, Appointment and Acceptance, dated as of October 3, 2007, among Entergy Gulf States, Inc., JPMorgan Chase Bank, National Association, as resigning trustee, and The Bank of New York, as successor trustee (4(a) to Form 10-Q for the quarter ended September 30, 2007 in 1-27031).
 
 
(d) 4 --
Assumption Agreement, dated as of May 30, 2008, among Entergy Texas, Inc., Entergy Gulf States Louisiana, L.L.C. and Citibank, N.A., as administrative agent (10(a) to Form 10-Q for the quarter ended March 31, 2008 in 0-53134).
 
 
(d) 5 --
Credit Agreement ($150,000,000), dated as of March 9, 2012, among Entergy Gulf States Louisiana, L.L.C., as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, and National Cooperative Services Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.3 to Form 8-K filed March 14, 2012 in 0-20371).
 
 
*(d) 6 --
Extension Agreement, dated as of March 1, 2013, to Credit Agreement.
 
 
*(d) 7 --
Extension Agreement, dated as of March 14, 2014, to Credit Agreement.

E-6
Table of Contents

Entergy Louisiana
(e) 1 --
Mortgage and Deed of Trust, dated as of April 1, 1944, as amended by seventy-eight Supplemental Indentures (7(d) in 2-5317 (Mortgage); 7(b) in 2-7408 (First); 7(c) in 2-8636 (Second); 4(b)-3 in 2-10412 (Third); 4(b)-4 in 2-12264 (Fourth); 2(b)-5 in 2-12936 (Fifth); D in 70-3862 (Sixth); 2(b)-7 in 2-22340 (Seventh); 2(c) in 2-24429 (Eighth); 4(c)-9 in 2-25801 (Ninth); 4(c)-10 in 2-26911 (Tenth); 2(c) in 2-28123 (Eleventh); 2(c) in 2-34659 (Twelfth); C to Rule 24 Certificate in 70-4793 (Thirteenth); 2(b)-2 in 2-38378 (Fourteenth); 2(b)-2 in 2-39437 (Fifteenth); 2(b)-2 in 2-42523 (Sixteenth); C to Rule 24 Certificate in 70-5242 (Seventeenth); C to Rule 24 Certificate in 70-5330 (Eighteenth); C-1 to Rule 24 Certificate in 70-5449 (Nineteenth); C-1 to Rule 24 Certificate in 70-5550 (Twentieth); A-6(a) to Rule 24 Certificate in 70-5598 (Twenty-first); C-1 to Rule 24 Certificate in 70-5711 (Twenty-second); C-1 to Rule 24 Certificate in 70-5919 (Twenty-third); C-1 to Rule 24 Certificate in 70-6102 (Twenty-fourth); C-1 to Rule 24 Certificate in 70-6169 (Twenty-fifth); C-1 to Rule 24 Certificate in 70-6278 (Twenty-sixth); C-1 to Rule 24 Certificate in 70-6355 (Twenty-seventh); C-1 to Rule 24 Certificate in 70-6508 (Twenty-eighth); C-1 to Rule 24 Certificate in 70-6556 (Twenty-ninth); C-1 to Rule 24 Certificate in 70-6635 (Thirtieth); C-1 to Rule 24 Certificate in 70-6834 (Thirty-first); C-1 to Rule 24 Certificate in 70-6886 (Thirty-second); C-1 to Rule 24 Certificate in 70-6993 (Thirty-third); C-2 to Rule 24 Certificate in 70-6993 (Thirty-fourth); C-3 to Rule 24 Certificate in 70-6993 (Thirty-fifth); A-2(a) to Rule 24 Certificate in 70-7166 (Thirty-sixth); A-2(a) in 70-7226 (Thirty-seventh); C-1 to Rule 24 Certificate in 70-7270 (Thirty-eighth); 4(a) to Quarterly Report on Form 10-Q for the quarter ended June 30, 1988 in 1-8474 (Thirty-ninth); A-2(b) to Rule 24 Certificate in 70-7553 (Fortieth); A-2(d) to Rule 24 Certificate in 70-7553 (Forty-first); A-3(a) to Rule 24 Certificate in 70-7822 (Forty-second); A-3(b) to Rule 24 Certificate in 70-7822 (Forty-third); A-2(b) to Rule 24 Certificate in 70-7822 (Forty-fourth); A-3(c) to Rule 24 Certificate in 70-7822 (Forty-fifth); A-2(c) to Rule 24 Certificate dated April 7, 1993 in 70-7822 (Forty-sixth); A-3(d) to Rule 24 Certificate dated June 4, 1993 in 70-7822 (Forth-seventh); A-3(e) to Rule 24 Certificate dated December 21, 1993 in 70-7822 (Forty-eighth); A-3(f) to Rule 24 Certificate dated August 1, 1994 in 70-7822 (Forty-ninth); A-4(c) to Rule 24 Certificate dated September 28, 1994 in 70-7653 (Fiftieth); A-2(a) to Rule 24 Certificate dated April 4, 1996 in 70-8487 (Fifty-first); A-2(a) to Rule 24 Certificate dated April 3, 1998 in 70-9141 (Fifty-second); A-2(b) to Rule 24 Certificate dated April 9, 1999 in 70-9141 (Fifty-third); A-3(a) to Rule 24 Certificate dated July 6, 1999 in 70-9141 (Fifty-fourth); A-2(c) to Rule 24 Certificate dated June 2, 2000 in 70-9141 (Fifty-fifth); A-2(d) to Rule 24 Certificate dated April 4, 2002 in 70-9141 (Fifty-sixth); A-3(a) to Rule 24 Certificate dated March 30, 2004 in 70-10086 (Fifty-seventh); A-3(b) to Rule 24 Certificate dated October 15, 2004 in 70-10086 (Fifty-eighth); A-3(c) to Rule 24 Certificate dated October 26, 2004 in 70-10086 (Fifty-ninth); A-3(d) to Rule 24 Certificate dated May 18, 2005 in 70-10086 (Sixtieth); A-3(e) to Rule 24 Certificate dated August 25, 2005 in 70-10086 (Sixty-first); A-3(f) to Rule 24 Certificate dated October 31, 2005 in 70-10086 (Sixty-second); B-4(i) to Rule 24 Certificate dated January 10, 2006 in 70-10324 (Sixty-third); B-4(ii) to Rule 24 Certificate dated 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(a) to Form 10-Q for the quarter ended March 31, 2010 in 1-32718 (Sixty-seventh); 4.08 to Form 8-K dated September 24, 2010 in 1-32718 (Sixty-eighth); 4(c) to Form 8-K filed October 12, 2010 in 1-32718 (Sixty-ninth); 4.08 to Form 8-K dated November 23, 2010 in 1-32718 (Seventieth); 4.08 to Form 8-K dated 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 dated December 15, 2011 in 1-32718 (Seventy-third); 4.08 to Form 8-K dated January 12, 2012 in 1-32718 (Seventy-fourth); 4.08 to Form 8-K dated July 3, 2012 in 1-32718 (Seventy-fifth); 4.08 to Form 8-K dated December 4, 2012 in 1-32718 (Seventy-sixth); 4.08 to Form 8-K dated May 21, 2013 in 1-32718 (Seventy-seventh); 4.08 to Form 8-K dated August 23, 2013 in 1-32718 (Seventy-eighth); 4.08 to Form 8-K dated June 24, 2014 in 1-32718 (Seventy-ninth); 4.08 to Form 8-K dated July 1, 2014 in 1-32718 (Eightieth); and 4.08 to Form 8-K dated November 21, 2014 (Eighty-first)).
 
 
(e) 2 --
Facility Lease No. 1, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-1 in Registration No. 33-30660), as supplemented by Lease Supplement No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 1, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 2 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474).
 
 
(e) 3 --
Facility Lease No. 2, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-2 in Registration No. 33-30660), as supplemented by Lease Supplemental No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 2, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 3 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474).
 
 

E-7
Table of Contents

(e) 4 --
Facility Lease No. 3, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-3 in Registration No. 33-30660), as supplemented by Lease Supplemental No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 3, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 4 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474).
 
 
(e) 5 --
Credit Agreement ($200,000,000), dated as of March 9, 2012, among Entergy Louisiana, LLC, as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, and National Cooperative Services Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.4 to Form 8-K filed March 14, 2012 in 1-32718).
 
 
*(e) 6 --
Extension Agreement, dated as of March 1, 2013, to Credit Agreement.
 
 
*(e) 7 --
Extension Agreement, dated as of March 14, 2014, to Credit Agreement.

Entergy Mississippi
(f) 1 --
Mortgage and Deed of Trust, dated as of February 1, 1988, as amended by thirty-one Supplemental Indentures (A-2(a)-2 to Rule 24 Certificate in 70-7461 (Mortgage); A-2(b)-2 in 70-7461 (First); A-5(b) to Rule 24 Certificate in 70-7419 (Second); A-4(b) to Rule 24 Certificate in 70-7554 (Third); A-1(b)-1 to Rule 24 Certificate in 70-7737 (Fourth); A-2(b) to Rule 24 Certificate dated November 24, 1992 in 70-7914 (Fifth); A-2(e) to Rule 24 Certificate dated January 22, 1993 in 70-7914 (Sixth); A-2(g) to Form U-1 in 70-7914 (Seventh); A-2(i) to Rule 24 Certificate dated November 10, 1993 in 70-7914 (Eighth); A-2(j) to Rule 24 Certificate dated July 22, 1994 in 70-7914 (Ninth); (A-2(l) to Rule 24 Certificate dated April 21, 1995 in 70-7914 (Tenth); A-2(a) to Rule 24 Certificate dated June 27, 1997 in 70-8719 (Eleventh); A-2(b) to Rule 24 Certificate dated April 16, 1998 in 70-8719 (Twelfth); A-2(c) to Rule 24 Certificate dated May 12, 1999 in 70-8719 (Thirteenth); A-3(a) to Rule 24 Certificate dated June 8, 1999 in 70-8719 (Fourteenth); A-2(d) to Rule 24 Certificate dated February 24, 2000 in 70-8719 (Fifteenth); A-2(a) to Rule 24 Certificate dated February 9, 2001 in 70-9757 (Sixteenth); A-2(b) to Rule 24 Certificate dated October 31, 2002 in 70-9757 (Seventeenth); A-2(c) to Rule 24 Certificate dated December 2, 2002 in 70-9757 (Eighteenth); A-2(d) to Rule 24 Certificate dated February 6, 2003 in 70-9757 (Nineteenth); A-2(e) to Rule 24 Certificate dated April 4, 2003 in 70-9757 (Twentieth); A-2(f) to Rule 24 Certificate dated June 6, 2003 in 70-9757 (Twenty-first); A-3(a) to Rule 24 Certificate dated April 8, 2004 in 70-10157 (Twenty-second); A-3(b) to Rule 24 Certificate dated April 29, 2004 in 70-10157 (Twenty-third); A-3(c) to Rule 24 Certificate dated October 4, 2004 in 70-10157 (Twenty-fourth); A-3(d) to Rule 24 Certificate dated January 27, 2006 in 70-10157 (Twenty-fifth); 4(b) to Form 10-Q for the quarter ended June 30, 2009 in 1-31508 (Twenty-sixth); 4(b) to Form 10-Q for the quarter ended March 31, 2010 in 1-31508 (Twenty-seventh); 4.38 to Form 8-K dated April 15, 2011 in 1-31508 (Twenty-eighth); 4.38 to Form 8-K dated May 13, 2011 in 1-31508 (Twenty-ninth); 4.38 to Form 8-K dated December 11, 2012 in 1-31508 (Thirtieth); and 4.05 to Form 8-K dated March 21, 2014 in 1-31508 (Thirty-first)).


E-8
Table of Contents

Entergy New Orleans
(g) 1 --
Mortgage and Deed of Trust, dated as of May 1, 1987, as amended by seventeen Supplemental Indentures (A-2(c) to Rule 24 Certificate in 70-7350 (Mortgage); A-5(b) to Rule 24 Certificate in 70-7350 (First); A-4(b) to Rule 24 Certificate in 70-7448 (Second); 4(f)4 to Form 10-K for the year ended December 31, 1992 in 0-5807 (Third); 4(a) to Form 10-Q for the quarter ended September 30, 1993 in 0-5807 (Fourth); 4(a) to Form 8-K dated April 26, 1995 in 0-5807 (Fifth); 4(a) to Form 8-K dated March 22, 1996 in 0-5807 (Sixth); 4(b) to Form 10-Q for the quarter ended June 30, 1998 in 0-5807 (Seventh); 4(d) to Form 10-Q for the quarter ended June 30, 2000 in 0-5807 (Eighth); C-5(a) to Form U5S for the year ended December 31, 2000 (Ninth); 4(b) to Form 10-Q for the quarter ended September 30, 2002 in 0-5807 (Tenth); 4(k) to Form 10-Q for the quarter ended June 30, 2003 in 0-5807 (Eleventh); 4(a) to Form 10-Q for the quarter ended September 30, 2004 in 0-5807 (Twelfth); 4(b) to Form 10-Q for the quarter ended September 30, 2004 in 0-5807 (Thirteenth); 4(e) to Form 10-Q for the quarter ended June 30, 2005 in 0-5807 (Fourteenth); 4.02 to Form 8-K dated November 23, 2010 in 0-5807 (Fifteenth); 4.02 to Form 8-K dated November 29, 2012 in 0-5807 (Sixteenth); and 4.02 to Form 8-K dated June 21, 2013 in 0-5807 (Seventeenth)).


E-9
Table of Contents

Entergy Texas
(h) 1 --
Credit Agreement ($150,000,000), dated as of March 9, 2012, among Entergy Texas, Inc., as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, and National Cooperative Services Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.5 to Form 8-K filed March 14, 2012 in 1-34360).
 
 
*(h) 2 --
Extension Agreement, dated as of March 1, 2013, to Credit Agreement.
 
 
*(h) 3 --
Extension Agreement, dated as of March 14, 2014, to Credit Agreement.
 
 
(h) 4 --
Assumption Agreement, dated as of May 30, 2008, among Entergy Texas, Inc., Entergy Gulf States Louisiana, L.L.C. and Citibank, N.A., as administrative agent (10(a) to Form 10-Q for the quarter ended March 31, 2008 in 0-53134).
 
 
(h) 5 --
Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(h)2 to Form 10-K for the year ended December 31, 2008 in 0-53134).
 
 
(h) 6 --
Officer’s Certificate No. 1-B-1 dated January 27, 2009, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(h)3 to Form 10-K for the year ended December 31, 2008 in 0-53134).
 
 
(h) 7 --
Officer’s Certificate No. 2-B-2 dated May 14, 2009, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(a) to Form 10-Q for the quarter ended June 30, 2009 in 1-34360).
 
 
(h) 8 --
Officer’s Certificate No. 3-B-3 dated May 18, 2010, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(a) to Form 10-Q for the quarter ended June 30, 2010 in 1-34360).
 
 
(h) 9 --
Officer’s Certificate No. 5-B-4 dated September 7, 2011, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4.40 to Form 8-K dated September 13, 2011 in 1-34360).
 
 
(h) 10 --
Officer’s Certificate No. 7-B-5 dated May 13, 2014, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(d) to Form 10-Q for the quarter ended June 30, 2014 in 1-34360).
  
(10)  Material Contracts

Entergy Corporation
(a) 1 --
Agreement, dated April 23, 1982, among certain System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517).
 
 
(a) 2 --
Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 1-11299).
 
 

E-10
Table of Contents

(a) 3 --
Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080).
 
 
(a) 4 --
Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)5 in 2-41080).
 
 
(a) 5 --
Amendment, dated April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517).
 
 
(a) 6 --
Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(a)12 to Form 10-K for the year ended December 31, 2001 in 1-11299).
 
 
(a) 7 --
Amendment, dated December 19, 2013, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 2013 in 1-11299).
 
 
(a) 8 --
Availability Agreement, dated June 21, 1974, among System Energy and certain other System companies (B to Rule 24 Certificate dated June 24, 1974 in 70-5399).
 
 
(a) 9 --
First Amendment to Availability Agreement, dated as of June 30, 1977 (B to Rule 24 Certificate dated June 24, 1977 in 70-5399).
 
 
(a) 10 --
Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate dated July 1, 1981 in 70-6592).
 
 
(a) 11 --
Third Amendment to Availability Agreement, dated as of June 28, 1984 (B-13(a) to Rule 24 Certificate dated July 6, 1984 in 70-6985).
 
 
(a) 12 --
Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate dated June 8, 1989 in 70-5399).
 
 
(a) 13 --
Thirty-fifth Assignment of Availability Agreement, Consent and Agreement, dated as of December 22, 2003, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, and Union Bank of California, N.A (10(a)25 to Form 10-K for the year ended December 31, 2003 in 1-11299).
 
 
(a) 14 --
First Amendment to Thirty-fifth Assignment of Availability Agreement, Consent and Agreement, dated as of December 17, 2004 (10(a)24 to Form 10-K for the year ended December 31, 2004 in 1-11299).
 
 
(a) 15 --
Thirty-seventh Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 2012, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and The Bank of New York Mellon, as successor trustee (10(a)15 to Form 10-K for the year ended December 31, 2012 in 1-11299).
 
 
(a) 16 --
Capital Funds Agreement, dated June 21, 1974, between Entergy Corporation and System Energy (C to Rule 24 Certificate dated June 24, 1974 in 70-5399).
 
 
(a) 17 --
First Amendment to Capital Funds Agreement, dated as of June 1, 1989 (B to Rule 24 Certificate dated June 8, 1989 in 70-5399).
 
 
(a) 18 --
Thirty-fifth Supplementary Capital Funds Agreement and Assignment, dated as of December 22, 2003, among Entergy Corporation, System Energy, and Union Bank of California, N.A (10(a)38 to Form 10-K for the year ended December 31, 2003 in 1-11299).
 
 
(a) 19 --
Thirty-seventh Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 2012, among Entergy Corporation, System Energy, and The Bank of New York Mellon, as successor trustee (10(a)19 to Form 10-K for the year ended December 31, 2012 in 1-11299).
 
 

E-11
Table of Contents

(a) 20 --
First Amendment to Supplementary Capital Funds Agreements and Assignments, dated as of June 1, 1989, by and between Entergy Corporation, System Energy, Deposit Guaranty National Bank, United States Trust Company of New York and Gerard F. Ganey (C to Rule 24 Certificate dated June 8, 1989 in 70-7026).
 
 
(a) 21 --
First Amendment to Supplementary Capital Funds Agreements and Assignments, dated as of June 1, 1989, by and between Entergy Corporation, System Energy, United States Trust Company of New York and Gerard F. Ganey (C to Rule 24 Certificate dated June 8, 1989 in 70-7123).
 
 
(a) 22 --
First Amendment to Supplementary Capital Funds Agreement and Assignment, dated as of June 1, 1989, by and between Entergy Corporation, System Energy and Chemical Bank (C to Rule 24 Certificate dated June 8, 1989 in 70-7561).
 
 
(a) 23 --
Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
 
 
(a) 24 --
Joint Construction, Acquisition and Ownership Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B-1(a) in 70-6337), as amended by Amendment No. 1, dated as of May 1, 1980 (B-1(c) in 70-6337) and Amendment No. 2, dated as of October 31, 1980 (1 to Rule 24 Certificate dated October 30, 1981 in 70-6337).
 
 
(a) 25 --
Operating Agreement dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337).
 
 
(a) 26 --
Assignment, Assumption and Further Agreement No. 1, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561).
 
 
(a) 27 --
Assignment, Assumption and Further Agreement No. 2, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561).
 
 
(a) 28 --
Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B(3)(a) in 70-6337).
 
 
(a) 29 --
Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033).
 
 
(a) 30 --
Compromise and Settlement Agreement, dated June 4, 1982, between Texaco, Inc. and Entergy Louisiana (28(a) to Form 8-K dated June 4, 1982 in 1-3517).
 
 
(a) 31 --
Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
 
 
(a) 32 --
First Amendment to Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
 
 
(a) 33 --
Revised Unit Power Sales Agreement (10(ss) in 33-4033).
 
 
(a) 34 --
Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
 
 
(a) 35 --
First Amendment, dated January 1, 1990, to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).
 
 

E-12
Table of Contents

(a) 36 --
Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
 
 
(a) 37 --
Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
 
 
(a) 38 --
Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
 
 
(a) 39 --
Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-11299).
 
 
(a) 40 --
Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-11299).
 
 
(a) 41 --
Guaranty Agreement between Entergy Corporation and Entergy Arkansas, dated as of September 20, 1990 (B-1(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).
 
 
(a) 42 --
Guarantee Agreement between Entergy Corporation and Entergy Louisiana, dated as of September 20, 1990 (B-2(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).
 
 
(a) 43 --
Guarantee Agreement between Entergy Corporation and System Energy, dated as of September 20, 1990 (B-3(a) to Rule 24 Certificate dated September 27, 1990 in 70- 7757).
 
 
(a) 44 --
Loan Agreement between Entergy Operations and Entergy Corporation, dated as of September 20, 1990 (B-12(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679).
 
 
(a) 45 --
Loan Agreement between Entergy Corporation and Entergy Systems and Service, Inc., dated as of December 29, 1992 (A-4(b) to Rule 24 Certificate in 70-7947).
 
 
+(a) 46 --
2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (Effective for Grants and Elections On or After January 1, 2007) (Appendix B to Entergy Corporation’s Definitive Proxy Statement filed on March 24, 2006 in 1-11299).
 
 
+(a) 47 --
First Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective October 26, 2006 (10(a)50 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 48 --
Second Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective January 1, 2009 (10(a)51 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 49 --
Third Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective December 30, 2010 (10(a)52 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 50 --
Amended and Restated 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries (Effective for Grants and Elections After February 13, 2003) (10(a) to Form 10-Q for the quarter ended March 31, 2003 in 1-11299).
 
 
+(a) 51 --
First Amendment of the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries, effective January 1, 2005 (10(a)54 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 

E-13
Table of Contents

+(a) 52 --
Second Amendment of the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries, effective October 26, 2006 (10(a)55 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 53 --
Third Amendment of the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries, effective January 1, 2009 (10(a)56 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 54 --
2011 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (Annex A to Entergy Corporation’s Definitive Proxy Statement filed on March 24, 2011 in 1-11299).
 
 
+(a) 55 --
Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)57 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 56 --
First Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)58 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 57 --
Second Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)57 to Form 10-K for the year ended December 31, 2011 in 1-11299).
 
 
+(a) 58 --
Third Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(b) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299).
 
 
+(a) 59 --
Fourth Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(c) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299).
 
 
+(a) 60 --
Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)59 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 61 --
First Amendment of the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)60 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 62 --
Second Amendment of the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)60 to Form 10-K for the year ended December 31, 2011 in 1-11299).
 
 
+(a) 63 --
Executive Disability Plan of Entergy Corporation and Subsidiaries (10(a)74 to Form 10-K for the year ended December 31, 2001 in 1-11299).
 
 
+(a) 64 --
Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)62 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 65 --
First Amendment of the Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)63 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 66 --
Second Amendment of the Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)64 to Form 10-K for the year ended December 31, 2011 in 1-11299).
 
 
+(a) 67 --
System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective as of January 1, 2009 (10(a)77 to Form 10-K for the year ended December 31, 2009 in 1-11299).
 
 
+(a) 68--
First Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective January 1, 2010 (10(a)78 to Form 10-K for the year ended December 31, 2009 in 1-11299).
 
 
+(a) 69 --
Second Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)69 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 

E-14
Table of Contents

+(a) 70 --
Third Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)71 to Form 10-K for the year ended December 31, 2011 in 1-11299).
 
 
+(a) 71 --
Post-Retirement Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)80 to Form 10-K for the year ended December 31, 2001 in 1-11299).
 
 
+(a) 72 --
Amendment, effective December 28, 2001, to the Post-Retirement Plan of Entergy Corporation and Subsidiaries (10(a)81 to Form 10-K for the year ended December 31, 2001 in 1-11299).
 
 
+(a) 73 --
Pension Equalization Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)74 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 74 --
First Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)75 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 75 --
Second Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)76 to Form 10-K for the year ended December 31, 2011 in 1-11299).
 
 
+(a) 76 --
Third Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective June 19, 2013 (10(b) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299).
 
 
+(a) 77 --
Fourth Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(c) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299).
 
 
+(a) 78 --
Fifth Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(a) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299).
 
 
+(a) 79 --
Service Recognition Program for Non-Employee Outside Directors of Entergy Corporation and Subsidiaries, as amended and restated effective June 1, 2012 (10(a) to Form 10-Q for the quarter ended September 30, 2012 in 1-11299).
 
 
+(a) 80 --
Executive Income Security Plan of Gulf States Utilities Company, as amended effective March 1, 1991 (10(a)86 to Form 10-K for the year ended December 31, 2001 in 1-11299).
 
 
+(a) 81 --
System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 1, 2009 (10(a)78 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 82 --
First Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)79 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 83 --
Second Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)81 to Form 10-K for the year ended December 31, 2011 in 1-11299).
 
 
+(a) 84--
Third Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 26, 2012 (10(a)81 to Form 10-K for the year ended December 31, 2013 in 1-11299).
 
 
+(a) 85 --
Fourth Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(d) to Form 10-Q for the year ended June 30, 2013 in 1-11299).
 
 
+(a) 86 --
Fifth Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(d) to Form 10-Q for the year ended September 30, 2014 in 1-11299).
 
 
(a) 87 --
Agreement of Limited Partnership of Entergy-Koch, LP among EKLP, LLC, EK Holding I, LLC, EK Holding II, LLC and Koch Energy, Inc. dated January 31, 2001 (10(a)94 to Form 10-K/A for the year ended December 31, 2000 in 1-11299).
 
 

E-15
Table of Contents

+(a) 88 --
Employment Agreement effective November 24, 2003 between Mark T. Savoff and Entergy Services (10(a)99 to Form 10-K for the year ended December 31, 2003 in 1-11299).
 
 
+(a) 89 --
Employment Agreement effective February 9, 1999 between Leo P. Denault and Entergy Services (10(a) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).
 
 
+(a) 90 --
Amendment to Employment Agreement effective March 5, 2004 between Leo P. Denault and Entergy Corporation (10(b) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).
 
 
+(a) 91 --
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) 92 --
Amendment to Retention Agreement effective January 1, 2009 between Leo P. Denault and Entergy Corporation (10(a)93 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 93 --
Amendment to Retention Agreement effective January 1, 2010 between Leo P. Denault and Entergy Corporation (10(a)101 to Form 10-K for the year ended December 31, 2009 in 1-11299).
 
 
+(a) 94 --
Amendment to Retention Agreement effective December 30, 2010 between Leo P. Denault and Entergy Corporation (10(a)95 to Form 10-K for the year ended December 31, 2010 in 1-11299).
 
 
+(a) 95 --
Shareholder Approval of Future Severance Agreements Policy, effective March 8, 2004 (10(f) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).
 
 
+(a) 96 --
Entergy Corporation Outside Director Stock Program Established under the 2011 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (10(b) to Form 10-Q for the quarter ended June 30, 2011 in 1-11299).
 
 
+(a) 97 --
First Amendment to Entergy Corporation Outside Director Stock Program Established under the 2011 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation Subsidiaries (10(b) to Form 10-Q for the quarter ended September 30, 2012 in 1-11299).
 
 
+(a) 98 --
Entergy Nuclear Retention Plan, as amended and restated January 1, 2007 (10(a)107 to Form 10-K for the year ended December 31, 2007 in 1-11299).
 
 
+(a) 99 --
Executive Annual Incentive Plan of Entergy Corporation and Subsidiaries as amended and restated effective January 1, 2010 (Annex A to Entergy Corporation’s Definitive Proxy Statement filed on  March 17, 2010 in 1-11299).
 
 
+(a) 100 --
First Amendment of the Executive Annual Incentive Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)106 to Form 10-K for the year ended December 31, 2011 in 1-11299).
 
 
*+(a)101-
Form of Stock Option Grant Letter.
 
 
*+(a)102-
Form of Long Term Incentive Program Performance Unit Grant Letter.
 
 
*+(a)103-
Form of Restricted Stock Grant Letter.
 
 
(a) 104 --
Employee Matters Agreement, dated as of December 4, 2011, among Entergy Corporation, Mid South TransCo LLC and ITC Holdings Corp. (10.1 to Form 8-K filed December 6, 2011 in 1-11299).
 
 
*+(a)105-
Retention Agreement effective February 1, 2013 between William M. Mohl and Entergy Corporation.
 
 
+(a)106 --
Restricted Units Agreement between Roderick K. West and Entergy Corporation (10(a) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299).
 
 

E-16
Table of Contents

+(a)107 --
Restricted Unit Agreement between Jeffrey S. Forbes and Entergy Corporation (10(a)109 to Form 10-K for the year ended December 31, 2013 in 1-11299).
System Energy
(b) 1 through
(b) 8 -- See 10(a)8 through 10(a)15 above.
 
(b) 9 through
(b) 15 -- See 10(a)16 through 10(a)22 above.
 
(b) 16 --
Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
 
 
(b) 17 --
Joint Construction, Acquisition and Ownership Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B-1(a) in 70-6337), as amended by Amendment No. 1, dated as of May 1, 1980 (B-1(c) in 70-6337) and Amendment No. 2, dated as of October 31, 1980 (1 to Rule 24 Certificate dated October 30, 1981 in 70-6337).
 
 
(b) 18 --
Operating Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337).
 
 
(b) 19 --
Amended and Restated Installment Sale Agreement, dated as of February 15, 1996, between System Energy and Claiborne County, Mississippi (B-6(a) to Rule 24 Certificate dated March 4, 1996 in 70-8511).
 
 
(b) 20 --
Loan Agreement, dated as of October 15, 1998, between System Energy and Mississippi Business Finance Corporation (B-6(b) to Rule 24 Certificate dated November 12, 1998 in 70-8511).
 
 
(b) 21 --
Facility Lease No. 1, dated as of December 1, 1988, between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (1) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-3(d) to Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-3(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182).
 
 
(b) 22 --
Facility Lease No. 2, dated as of December 1, 1988 between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (2) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-4(d) Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-4(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182).
 
 
(b) 23 --
Assignment, Assumption and Further Agreement No. 1, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561).
 
 
(b) 24 --
Assignment, Assumption and Further Agreement No. 2, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561).
 
 
(b) 25 --
Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B(3)(a) in 70-6337).
 
 

E-17
Table of Contents

(b) 26 --
Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033).
 
 
(b) 27 --
Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
 
 
(b) 28 --
First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
 
 
(b) 29 --
Revised Unit Power Sales Agreement (10(ss) in 33-4033).
 
 
(b) 30 --
Fuel Lease, dated as of February 24, 1989, between River Fuel Funding Company #3, Inc. and System Energy (B-1(b) to Rule 24 Certificate dated March 3, 1989 in 70-7604).
 
 
(b) 31 --
System Energy’s Consent, dated January 31, 1995, pursuant to Fuel Lease, dated as of February 24, 1989, between River Fuel Funding Company #3, Inc. and System Energy (B-1(c) to Rule 24 Certificate dated February 13, 1995 in 70-7604).
 
 
(b) 32 --
Sales Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (D to Rule 24 Certificate dated June 26, 1974 in 70-5399).
 
 
(b) 33 --
Service Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (E to Rule 24 Certificate dated June 26, 1974 in 70-5399).
 
 
(b) 34 --
Partial Termination Agreement, dated as of December 1, 1986, between System Energy and Entergy Mississippi (A-2 to Rule 24 Certificate dated January 8, 1987 in 70-5399).
 
 
(b) 35 --
Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
 
 
(b) 36 --
First Amendment, dated January 1, 1990 to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).
 
 
(b) 37 --
Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
 
 
(b) 38 --
Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
 
 
(b) 39 --
Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
 
 
(b) 40 --
Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-9067).
 
 
(b) 41 --
Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-9067).
 
 
(b) 42 --
Service Agreement with Entergy Services, dated as of July 16, 1974, as amended (10(b)43 to Form 10-K for the year ended December 31, 1988 in 1-9067).
 
 

E-18
Table of Contents

(b) 43 --
Amendment, dated January 1, 2004, to Service Agreement with Entergy Services (10(b)57 to Form 10-K for the year ended December 31, 2004 in 1-9067).
 
 
(b) 44 --
Amendment, dated December 19, 2013, to Service Agreement with Entergy Services (10(b)44 to Form 10-K for the year ended December 31, 2013 in 1-9067).
 
 
(b) 45 --
Operating Agreement between Entergy Operations and System Energy, dated as of June 6, 1990 (B-3(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679).
 
 
(b) 46 --
Guarantee Agreement between Entergy Corporation and System Energy, dated as of September 20, 1990 (B-3(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).
 
 
(b) 47 --
Letter of Credit and Reimbursement Agreement, dated as of December 22, 2003, among System Energy Resources, Inc., Union Bank of California, N.A., as administrating bank and funding bank, Keybank National Association, as syndication agent, Banc One Capital Markets, Inc., as documentation agent, and the Banks named therein, as Participating Banks (10(b)63 to Form 10-K for the year ended December 31, 2003 in 1-9067).
 
 
(b) 48 --
Amendment to Letter of Credit and Reimbursement Agreement, dated as of December 22, 2003 (10(b)62 to Form 10-K for the year ended December 31, 2004 in 1-9067).
 
 
(b) 49 --
First Amendment and Consent, dated as of May 3, 2004, to Letter of Credit and Reimbursement Agreement (10(b)63 to Form 10-K for the year ended December 31, 2004 in 1-9067).
 
 
(b) 50 --
Second Amendment and Consent, dated as of December 17, 2004, to Letter of Credit and Reimbursement Agreement (99 to Form 8-K dated December 22, 2004 in 1-9067).
 
 
(b) 51 --
Third Amendment and Consent, dated as of May 14, 2009, to Letter of Credit and Reimbursement Agreement (10(b)69 to Form 10-K for the year ended December 31, 2009 in 1-9067).
 
 
(b) 52 --
Fourth Amendment and Consent, dated as of April 15, 2010, to Letter of Credit and Reimbursement Agreement (10(a) to Form 10-Q for the quarter ended March 31, 2010 in 1-9067).
 
 
(b) 53 --
Fifth Amendment and Consent, dated as of November 15, 2012, to Letter of Credit and Reimbursement Agreement (10(b)55 to Form 10-K for the year ended December 31, 2012 in 1-9067).
 
Entergy Arkansas
(c) 1 --
Agreement, dated April 23, 1982, among Entergy Arkansas and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a) 1 to Form 10-K for the year ended December 31, 1982 in 1-3517).
 
 
(c) 2 --
Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 1-10764).
 
 
(c) 3 --
Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080).
 
 
(c) 4 --
Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)5 in 2-41080).
 
 
(c) 5 --
Amendment, dated December 19, 2013, to Service Agreement, with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services, Service Agreement for Generation Planning and Operational Support Services, and Service Agreement for Transmission Planning and Reliability Support Services (10(c)5 to Form 10-K for the year ended December 31, 2013 in 1-10764).
 
 
(c) 6 through
(c) 13 -- See 10(a)8 through 10(a)15 above.
 

E-19
Table of Contents

(c) 14 --
Agreement, dated August 20, 1954, between Entergy Arkansas and the United States of America (SPA)(13(h) in 2-11467).
 
 
(c) 15 --
Amendment, dated April 19, 1955, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)2 in 2-41080).
 
 
(c) 16 --
Amendment, dated January 3, 1964, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)3 in 2-41080).
 
 
(c) 17 --
Amendment, dated September 5, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)4 in 2-41080).
 
 
(c) 18 --
Amendment, dated November 19, 1970, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)5 in 2-41080).
 
 
(c) 19 --
Amendment, dated July 18, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)6 in 2-41080).
 
 
(c) 20 --
Amendment, dated December 27, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)7 in 2-41080).
 
 
(c) 21 --
Amendment, dated January 25, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)8 in 2-41080).
 
 
(c) 22 --
Amendment, dated October 14, 1971, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)9 in 2-43175).
 
 
(c) 23 --
Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)10 in 2-60233).
 
 
(c) 24 --
Agreement, dated May 14, 1971, between Entergy Arkansas and the United States of America (SPA) (5(e) in 2-41080).
 
 
(c) 25 --
Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated May 14, 1971 (5(e)1 in 2-60233).
 
 
(c) 26 --
Contract, dated May 28, 1943, Amendment to Contract, dated July 21, 1949, and Supplement to Amendment to Contract, dated December 30, 1949, between Entergy Arkansas and McKamie Gas Cleaning Company; Agreements, dated as of September 30, 1965, between Entergy Arkansas and former stockholders of McKamie Gas Cleaning Company; and Letter Agreement, dated June 22, 1966, by Humble Oil & Refining Company accepted by Entergy Arkansas on June 24, 1966 (5(k)7 in 2-41080).
 
 
(c) 27 --
Fuel Lease, dated as of December 22, 1988, between River Fuel Trust #1 and Entergy Arkansas (B-1(b) to Rule 24 Certificate in 70-7571).
 
 
(c) 28 --
White Bluff Operating Agreement, dated June 27, 1977, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas (B-2(a) to Rule 24 Certificate dated June 30, 1977 in 70-6009).
 
 
(c) 29 --
White Bluff Ownership Agreement, dated June 27, 1977, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas (B-1(a) to Rule 24 Certificate dated June 30, 1977 in 70-6009).
 
 
(c) 30 --
Agreement, dated June 29, 1979, between Entergy Arkansas and City of Conway, Arkansas (5(r)3 in 2-66235).
 
 
(c) 31 --
Transmission Agreement, dated August 2, 1977, between Entergy Arkansas and City Water and Light Plant of the City of Jonesboro, Arkansas (5(r)3 in 2-60233).
 
 

E-20
Table of Contents

(c) 32 --
Power Coordination, Interchange and Transmission Service Agreement, dated as of June 27, 1977, between Arkansas Electric Cooperative Corporation and Entergy Arkansas (5(r)4 in 2-60233).
 
 
(c) 33 --
Independence Steam Electric Station Operating Agreement, dated July 31, 1979, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas and City of Conway, Arkansas (5(r)6 in 2-66235).
 
 
(c) 34 --
Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c)51 to Form 10-K for the year ended December 31, 1984 in 1-10764).
 
 
(c) 35 --
Independence Steam Electric Station Ownership Agreement, dated July 31, 1979, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas and City of Conway, Arkansas (5(r)7 in 2-66235).
 
 
(c) 36 --
Amendment, dated December 28, 1979, to the Independence Steam Electric Station Ownership Agreement (5(r)7(a) in 2-66235).
 
 
(c) 37 --
Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c)54 to Form 10-K for the year ended December 31, 1984 in 1-10764).
 
 
(c) 38 --
Owner’s Agreement, dated November 28, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station (10(c)55 to Form 10-K for the year ended December 31, 1984 in 1-10764).
 
 
(c) 39 --
Consent, Agreement and Assumption, dated December 4, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station and United States Trust Company of New York, as Trustee (10(c)56 to Form 10-K for the year ended December 31, 1984 in 1-10764).
 
 
(c) 40 --
Power Coordination, Interchange and Transmission Service Agreement, dated as of July 31, 1979, between Entergy Arkansas and City Water and Light Plant of the City of Jonesboro, Arkansas (5(r)8 in 2-66235).
 
 
(c) 41 --
Power Coordination, Interchange and Transmission Agreement, dated as of June 29, 1979, between City of Conway, Arkansas and Entergy Arkansas (5(r)9 in 2-66235).
 
 
(c) 42 --
Agreement, dated June 21, 1979, between Entergy Arkansas and Reeves E. Ritchie (10(b)90 to Form 10-K for the year ended December 31, 1980 in 1-10764).
 
 
(c) 43 --
Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
 
 
(c) 44 --
Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
 
 
(c) 45 --
First Amendment to Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
 
 
(c) 46 --
Revised Unit Power Sales Agreement (10(ss) in 33-4033).
 
 
(c) 47 --
Contract For Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste, dated June 30, 1983, among the DOE, System Fuels and Entergy Arkansas (10(b)57 to Form 10-K for the year ended December 31, 1983 in 1-10764).
 
 
(c) 48 --
Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
 
 

E-21
Table of Contents

(c) 49 --
First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).
 
 
(c) 50 --
Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
 
 
(c) 51 --
Third Amendment dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
 
 
(c) 52 --
Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
 
 
(c) 53 --
Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-10764).
 
 
(c) 54 --
Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-10764).
 
 
(c) 55 --
Assignment of Coal Supply Agreement, dated December 1, 1987, between System Fuels and Entergy Arkansas (B to Rule 24 letter filing dated November 10, 1987 in 70-5964).
 
 
(c) 56 --
Coal Supply Agreement, dated December 22, 1976, between System Fuels and Antelope Coal Company (B-1 in 70-5964), as amended by First Amendment (A to Rule 24 Certificate in 70-5964); Second Amendment (A to Rule 24 letter filing dated December 16, 1983 in 70-5964); and Third Amendment (A to Rule 24 letter filing dated November 10, 1987 in 70-5964).
 
 
(c) 57 --
Operating Agreement between Entergy Operations and Entergy Arkansas, dated as of June 6, 1990 (B-1(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679).
 
 
(c) 58 --
Guaranty Agreement between Entergy Corporation and Entergy Arkansas, dated as of September 20, 1990 (B-1(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).
 
 
(c) 59 --
Agreement for Purchase and Sale of Independence Unit 2 between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-3(c) to Rule 24 Certificate dated September 6, 1990 in 70-7684).
 
 
(c) 60 --
Agreement for Purchase and Sale of Ritchie Unit 2 between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-4(d) to Rule 24 Certificate dated September 6, 1990 in 70-7684).
 
 
(c) 61 --
Ritchie Steam Electric Station Unit No. 2 Operating Agreement between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-5(a) to Rule 24 Certificate dated September 6, 1990 in 70-7684).
 
 
(c) 62 --
Ritchie Steam Electric Station Unit No. 2 Ownership Agreement between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-6(a) to Rule 24 Certificate dated September 6, 1990 in 70-7684).
 
 
(c) 63 --
Power Coordination, Interchange and Transmission Service Agreement between Entergy Power and Entergy Arkansas, dated as of August 28, 1990 (10(c)71 to Form 10-K for the year ended December 31, 1990 in 1-10764).
 
 
(c) 64 --
Loan Agreement, dated as of January 1, 2013, between Jefferson County, Arkansas and Entergy Arkansas relating to Revenue Bonds (Entergy Arkansas, Inc. Project) Series 2013 (4(b) to Form 8-K filed January 9, 2013 in 1-10764).
 
 

E-22
Table of Contents

(c) 65 --
Loan Agreement, dated as of January 1, 2013, between Independence County, Arkansas and Entergy Arkansas relating to Revenue Bonds (Entergy Arkansas, Inc. Project) Series 2013 (4(d) to Form 8-K filed January 9, 2013 in 1-10764).

Entergy Gulf States Louisiana
(d) 1 --
Agreement effective February 1, 1964, between Sabine River Authority, State of Louisiana, and Sabine River Authority of Texas, and Entergy Gulf States, Inc., Central Louisiana Electric Company, Inc., and Louisiana Power & Light Company, as supplemented (B to Form 8-K dated May 6, 1964, A to Form 8-K dated October 5, 1967, A to Form 8-K dated May 5, 1969, and A to Form 8-K dated December 1, 1969 in 1-27031).
 
 
(d) 2 --
Joint Ownership Participation and Operating Agreement regarding River Bend Unit 1 Nuclear Plant, dated August 20, 1979, between Entergy Gulf States, Inc., Cajun, and SRG&T; Power Interconnection Agreement with Cajun, dated June 26, 1978, and approved by the REA on August 16, 1979, between Entergy Gulf States, Inc. and Cajun; and Letter Agreement regarding CEPCO buybacks, dated August 28, 1979, between Entergy Gulf States, Inc. and Cajun (2, 3, and 4, respectively, to Form 8-K dated September 7, 1979 in 1-27031).
 
 
(d) 3 --
Lease Agreement, dated September 18, 1980, between BLC Corporation and Entergy Gulf States, Inc. (1 to Form 8-K dated October 6, 1980 in 1-27031).
 
 
(d) 4 --
Joint Ownership Participation and Operating Agreement for Big Cajun, between Entergy Gulf States, Inc., Cajun Electric Power Cooperative, Inc., and Sam Rayburn G&T, Inc, dated November 14, 1980 (6 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 1, dated December 12, 1980 (7 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 2, dated December 29, 1980 (8 to Form 8-K dated January 29, 1981 in 1-27031).
 
 
(d) 5 --
Agreement of Joint Ownership Participation between SRMPA, SRG&T and Entergy Gulf States, Inc., dated June 6, 1980, for Nelson Station, Coal Unit #6, as amended (8 to Form 8-K dated June 11, 1980, A-2-b to Form 10-Q for the quarter ended June 30, 1982; and 10-1 to Form 8-K dated February 19, 1988 in 1-27031).
 
 
(d) 6 --
Agreements between Southern Company and Entergy Gulf States, Inc., dated February 25, 1982, which cover the construction of a 140-mile transmission line to connect the two systems, purchase of power and use of transmission facilities (10-31 to Form 10-K for the year ended December 31, 1981 in 1-27031).
 
 
(d) 7 --
Transmission Facilities Agreement between Entergy Gulf States, Inc. and Mississippi Power Company, dated February 28, 1982, and Amendment, dated May 12, 1982 (A-2-c to Form 10-Q for the quarter ended March 31, 1982 in 1-27031) and Amendment, dated December 6, 1983 (10-43 to Form 10-K for the year ended December 31, 1983 in 1-27031).
 
 
(d) 8 --
First Amended Power Sales Agreement, dated December 1, 1985 between Sabine River Authority, State of Louisiana, and Sabine River Authority, State of Texas, and Entergy Gulf States, Inc., Central Louisiana Electric Co., Inc., and Louisiana Power and Light Company (10-72 to Form 10-K for the year ended December 31, 1985 in 1-27031).
 
 
+(d) 9 --
Deferred Compensation Plan for Directors of Entergy Gulf States, Inc. and Varibus Corporation, as amended January 8, 1987, and effective January 1, 1987 (10-77 to Form 10-K for the year ended December 31, 1986 in 1-27031). Amendment dated December 4, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551).
 
 
+(d) 10 --
Trust Agreement for Deferred Payments to be made by Entergy Gulf States, Inc. pursuant to the Executive Income Security Plan, by and between Entergy Gulf States, Inc. and Bankers Trust Company, effective November 1, 1986 (10-78 to Form 10-K for the year ended December 31, 1986 in 1-27031).
 
 

E-23
Table of Contents

+(d) 11 --
Trust Agreement for Deferred Installments under Entergy Gulf States, Inc. Management Incentive Compensation Plan and Administrative Guidelines by and between Entergy Gulf States, Inc. and Bankers Trust Company, effective June 1, 1986 (10-79 to Form 10-K for the year ended December 31, 1986 in 1-27031).
 
 
+(d) 12 --
Nonqualified Deferred Compensation Plan for Officers, Nonemployee Directors and Designated Key Employees, effective December 1, 1985, as amended, continued and completely restated effective as of March 1, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551).
 
 
+(d) 13 --
Trust Agreement for Entergy Gulf States, Inc. Nonqualified Directors and Designated Key Employees by and between Entergy Gulf States, Inc. and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective July 1, 1991 (10-4 to Form 10-K for the year ended December 31, 1992 in 1-27031).
 
 
(d) 14 --
Nuclear Fuel Lease Agreement between Entergy Gulf States, Inc. and River Bend Fuel Services, Inc. to lease the fuel for River Bend Unit 1, dated February 7, 1989 (10-64 to Form 10-K for the year ended December 31, 1988 in 1-27031).
 
 
(d) 15 --
Trust and Investment Management Agreement between Entergy Gulf States, Inc. and Morgan Guaranty and Trust Company of New York (the “Decommissioning Trust Agreement”) with respect to decommissioning funds authorized to be collected by Entergy Gulf States, Inc., dated March 15, 1989 (10-66 to Form 10-K for the year ended December 31, 1988 in 1-27031).
 
 
(d) 16 --
Amendment No. 2 dated November 1, 1995 between Entergy Gulf States, Inc. and Mellon Bank to Decommissioning Trust Agreement (10(d)31 to Form 10-K for the year ended December 31, 1995 in 1-27031).
 
 
(d) 17 --
Amendment No. 3 dated March 5, 1998 between Entergy Gulf States, Inc. and Mellon Bank to Decommissioning Trust Agreement (10(d)23 to Form 10-K for the year ended December 31, 2004 in 1-27031).
 
 
(d) 18 --
Amendment No. 4 dated December 17, 2003 between Entergy Gulf States, Inc. and Mellon Bank to Decommissioning Trust Agreement (10(d)24 to Form 10-K for the year ended December 31, 2004 in 1-27031).
 
 
(d) 19 --
Amendment No. 5 dated December 31, 2007 between Entergy Gulf States Louisiana, L.L.C. and Mellon Bank. N.A. to Decommissioning Trust Agreement (10(d)21 to Form 10-K for the year ended December 31, 2007 in 333-148557).
 
 
(d) 20 --
Partnership Agreement by and among Conoco Inc., and Entergy Gulf States, Inc., CITGO Petroleum Corporation and Vista Chemical Company, dated April 28, 1988 (10-67 to Form 10-K for the year ended December 31, 1988 in 1-27031).
 
 
+(d) 21 --
Gulf States Utilities Company Executive Continuity Plan, dated January 18, 1991 (10-6 to Form 10-K for the year ended December 31, 1990 in 1-27031).
 
 
+(d) 22 --
Trust Agreement for Entergy Gulf States, Inc. Executive Continuity Plan, by and between Entergy Gulf States, Inc. and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective May 20, 1991 (10-5 to Form 10-K for the year ended December 31, 1992 in 1-27031).
 
 
+(d) 23 --
Gulf States Utilities Board of Directors’ Retirement Plan, dated February 15, 1991 (10-8 to Form 10-K for the year ended December 31, 1990 in 1-27031).
 
 
(d) 24 --
Third Amendment, dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
 
 
(d) 25 --
Fourth Amendment, dated April 1, 1997, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).

E-24
Table of Contents

 
 
(d) 26 --
Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 0-20371).
 
 
(d) 27 --
Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 0-20371).
 
 
(d) 28 --
Operating Agreement dated as of January 1, 2008, between Entergy Operations, Inc. and Entergy Gulf States Louisiana (10(d)39 to Form 10-K for the year ended December 31, 2007 in 333-148557).
 
 
(d) 29 --
Service Agreement dated as of January 1, 2008, between Entergy Services, Inc. and Entergy Gulf States Louisiana (10(d)40 to Form 10-K for the year ended December 31, 2007 in 333-148557).
 
 
(d) 30 --
Amendment, dated December 19, 2013, to Service Agreement with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services and Service Agreement for Generation Planning and Operational Support Services) (10(d)30 to Form 10-K for the year ended December 31, 2013 in 0-20371).
 
 
(d) 31 --
Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 333-148557).
 
 
(d) 32 --
Decommissioning Trust Agreement, dated as of December 22, 1997, by and between Cajun Electric Power Cooperative, Inc. and Mellon Bank, N.A. with respect to decommissioning funds authorized to be collected by Cajun Electric Power Cooperative, Inc. and related Settlement Term Sheet (10(d)42 to Form 10-K for the year ended December 31, 2007 in 333-148557).
 
 
(d) 33 --
First Amendment to Decommissioning Trust Agreement, dated as of December 23, 2003, by and among Cajun Electric Power Cooperative, Inc., Mellon Bank, N.A., Entergy Gulf States, Inc., and the Rural Utilities Services of the United States Department of Agriculture (10(d)43 to Form 10-K for the year ended December 31, 2007 in 333-148557).
 
 
(d) 34 --
Second Amendment to Decommissioning Trust Agreement, dated December 31, 2007, by and among Cajun Electric Power Cooperative, Inc., Mellon Bank, N.A., Entergy Gulf States Louisiana, L.L.C., and the Rural Utilities Services of the United States Department of Agriculture (10(d)44 to Form 10-K for the year ended December 31, 2007 in 333-148557).
 
 
(d) 35 --
Second Amended and Restated Limited Liability Company Agreement of Entergy Holdings Company LLC dated as of July 22, 2010 (10(a) to Form 10-Q for the quarter ended June 30, 2010).
 
 
(d) 36 --
Loan Agreement, dated as of October 1, 2010, between the Louisiana Public Facilities Authority and Entergy Gulf States Louisiana, L.L.C. relating to Revenue Bonds (Entergy Gulf States Louisiana, L.L.C. Project) Series 2010A (4(b) to Form 8-K filed October 12, 2010 in 0-20371).
 
 
(d) 37 --
Loan Agreement, dated as of October 1, 2010, between the Louisiana Public Facilities Authority and Entergy Gulf States Louisiana, L.L.C. relating to Revenue Bonds (Entergy Gulf States Louisiana, L.L.C. Project) Series 2010B (4(e) to Form 8-K filed October 12, 2010 in 0-20371).
 
 
(d) 38 --
Asset Purchase Agreement, dated as of December 8, 2014, by and among Union Power Partners, L.P., Entegra TC LLC, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas (10.1 to Form 8-K filed December 12, 2014 in 0-20371).

Entergy Louisiana
(e) 1 --
Agreement, dated April 23, 1982, among Entergy Louisiana and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982, in 1-3517).
 
 

E-25
Table of Contents

(e) 2 --
Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 1-32718).
 
 
(e) 3 --
Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080).
 
 
(e) 4 --
Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)5 in 2-42523).
 
 
(e) 5 --
Amendment, dated December 19, 2013, to Service Agreement with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services and Service Agreement for Generation Planning and Operational Support Services) (10(e)5 to Form 10-K for the year ended December 31, 2013 in 1-32718).
 
 
(e) 6 through
(e) 13 -- See 10(a)8 through 10(a)15 above.
 
 
(e) 14 --
Fuel Lease, dated as of January 31, 1989, between River Fuel Company #2, Inc., and Entergy Louisiana (B-1(b) to Rule 24 Certificate in 70-7580).
 
 
(e) 15 --
Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
 
 
(e) 16 --
Compromise and Settlement Agreement, dated June 4, 1982, between Texaco, Inc. and Entergy Louisiana (28(a) to Form 8-K dated June 4, 1982 in 1-8474).
 
 
(e) 17 --
Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
 
 
(e) 18 --
First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
 
 
(e) 19 --
Revised Unit Power Sales Agreement (10(ss) in 33-4033).
 
 
(e) 20 --
Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste, dated February 2, 1984, among DOE, System Fuels and Entergy Louisiana (10(d)33 to Form 10-K for the year ended December 31, 1984 in 1-8474).
 
 
(e) 21--
Operating Agreement between Entergy Operations and Entergy Louisiana, dated as of June 6, 1990 (B-2(c) to Rule 24 Certificate dated June 15, 1990 in 70-7679).
 
 
(e) 22 --
Guarantee Agreement between Entergy Corporation and Entergy Louisiana, dated as of September 20, 1990 (B-2(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).
 
 
(e) 23 --
Second Amended and Restated Limited Liability Company Agreement of Entergy Holdings Company LLC dated as of July 22, 2010 (10(a) to Form 10-Q for the quarter ended June 30, 2010).
 
 
(e) 24 --
Third Amended and Restated Limited Liability Company Agreement of Entergy Holdings Company LLC dated as of August 6, 2014 (10(a) to Form 10-Q for the quarter ended June 30, 2014).
 
 
(e) 25 --
Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-32718).
 
 
(e) 26 --
Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-32718).
 
 

E-26
Table of Contents

(e) 27 --
Loan Agreement, dated as of October 1, 2010, between the Louisiana Public Facilities Authority and Entergy Louisiana, LLC relating to Revenue Bonds (Entergy Louisiana, LLC Project) Series 2010 (4(b) to Form 8-K filed October 12, 2010 in 1-32718).

Entergy Mississippi
(f) 1 --
Agreement dated April 23, 1982, among Entergy Mississippi and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517).
 
 
(f) 2 --
Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 1-31508).
 
 
(f) 3 --
Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080).
 
 
(f) 4 --
Service Agreement with Entergy Services, dated as of April 1, 1963 (D in 37-63).
 
 
(f) 5 --
Amendment, dated December 19, 2013, to Service Agreement with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services and Service Agreement for Generation Planning and Operational Support Services) (10(f)5 to Form 10-K for the year ended December 31, 2013 in 1-31508).
 
 
(f) 6 through
(f) 13 -- See 10(a)8 through 10(a)15 above.
 
 
(f) 14 --
Refunding Agreement, dated as of May 1, 1999, between Entergy Mississippi and Independence County, Arkansas (B-6(a) to Rule 24 Certificate dated June 8, 1999 in 70-8719).
 
 
(f) 15 --
Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B-3(a) in 70-6337).
 
 
(f) 16 --
Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c)51 to Form 10-K for the year ended December 31, 1984 in 0-375).
 
 
(f) 17 --
Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c)54 to Form 10-K for the year ended December 31, 1984 in 0-375).
 
 
(f) 18 --
Owners Agreement, dated November 28, 1984, among Entergy Arkansas, Entergy Mississippi and other co-owners of the Independence Station (10(c)55 to Form 10-K for the year ended December 31, 1984 in 0-375).
 
 
(f) 19 --
Consent, Agreement and Assumption, dated December 4, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station and United States Trust Company of New York, as Trustee (10(c)56 to Form 10-K for the year ended December 31, 1984 in 0-375).
 
 
(f) 20 --
Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
 
 
+(f) 21 --
Post-Retirement Plan (10(d)24 to Form 10-K for the year ended December 31, 1983 in 0-320).
 
 
(f) 22 --
Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
 
 
(f) 23 --
First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
 
 

E-27
Table of Contents

(f) 24 --
Revised Unit Power Sales Agreement (10(ss) in 33-4033).
 
 
(f) 25 --
Sales Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (D to Rule 24 Certificate dated June 26, 1974 in 70-5399).
 
 
(f) 26 --
Service Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (E to Rule 24 Certificate dated June 26, 1974 in 70-5399).
 
 
(f) 27 --
Partial Termination Agreement, dated as of December 1, 1986, between System Energy and Entergy Mississippi (A-2 to Rule 24 Certificate dated January 8, 1987 in 70-5399).
 
 
(f) 28 --
Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
 
 
(f) 29 --
First Amendment dated January 1, 1990 to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).
 
 
(f) 30 --
Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
 
 
(f) 31 --
Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
 
 
(f) 32 --
Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
 
 
(f) 33 --
Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-31508).
 
 
(f) 34 --
Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-31508).
 
 
(f) 35 --
Purchase and Sale Agreement by and between Central Mississippi Generating Company, LLC and Entergy Mississippi, Inc., dated as of March 16, 2005 (10(b) to Form 10-Q for the quarter ended March 31, 2005 in 1-31508).
Entergy New Orleans
(g) 1 --
Agreement, dated April 23, 1982, among Entergy New Orleans and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517).
 
 
(g) 2 --
Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 0-5807).
 
 
(g) 3 --
Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080).
 
 
(g) 4 --
Service Agreement with Entergy Services dated as of April 1, 1963 (5(a)5 in 2-42523).
 
 
(g) 5 --
Amendment, dated December 19, 2013, to Service Agreement with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services and Service Agreement for Generation Planning and Operational Support Services) (10(g)5 to Form 10-K for the year ended December 31, 2013 in 0-5807).
 
 
 
 

E-28
Table of Contents

(g) 6 through
(g) 13 -- See 10(a)8 through 10(a)15 above.
 
 
(g) 14 --
Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
 
 
(g) 15 --
Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
 
 
(g) 16 --
First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
 
 
(g) 17 --
Revised Unit Power Sales Agreement (10(ss) in 33-4033).
 
 
(g) 18 --
Transfer Agreement, dated as of June 28, 1983, among the City of New Orleans, Entergy New Orleans and Regional Transit Authority (2(a) to Form 8-K dated June 24, 1983 in 1-1319).
 
 
(g) 19 --
Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
 
 
(g) 20 --
First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).
 
 
(g) 21 --
Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
 
 
(g) 22 --
Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
 
 
(g) 23 --
Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
 
 
(g) 24 --
Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 0-5807).
 
 
(g) 25 --
Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 0-5807).
 
 
(g) 26 --
Chapter 11 Plan of Reorganization of Entergy New Orleans, Inc., as modified, dated May 2, 2007, confirmed by bankruptcy court order dated May 7, 2007 (2(a) to Form 10-Q for the quarter ended March 31, 2007 in 0-5807).

Entergy Texas
(h) 1 --
Agreement effective February 1, 1964, between Sabine River Authority, State of Louisiana, and Sabine River Authority of Texas, and Entergy Gulf States, Inc., Central Louisiana Electric Company, Inc., and Louisiana Power & Light Company, as supplemented (B to Form 8-K dated May 6, 1964, A to Form 8-K dated October 5, 1967, A to Form 8-K dated May 5, 1969, and A to Form 8-K dated December 1, 1969 in 1-27031).
 
 
(h) 2 --
Ground Lease, dated August 15, 1980, between Statmont Associates Limited Partnership (Statmont) and Entergy Gulf States, Inc., as amended (3 to Form 8-K dated August 19, 1980 and A-3-b to Form 10-Q for the quarter ended September 30, 1983 in 1-27031).

E-29
Table of Contents

 
 
(h) 3 --
Lease and Sublease Agreement, dated August 15, 1980, between Statmont and Entergy Gulf States, Inc., as amended (4 to Form 8-K dated August 19, 1980 and A-3-c to Form 10-Q for the quarter ended September 30, 1983 in 1-27031).
 
 
(h) 4 --
Lease Agreement, dated September 18, 1980, between BLC Corporation and Entergy Gulf States, Inc. (1 to Form 8-K dated October 6, 1980 in 1-27031).
 
 
(h) 5 --
Joint Ownership Participation and Operating Agreement for Big Cajun, between Entergy Gulf States, Inc., Cajun Electric Power Cooperative, Inc., and Sam Rayburn G&T, Inc, dated November 14, 1980 (6 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 1, dated December 12, 1980 (7 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 2, dated December 29, 1980 (8 to Form 8-K dated January 29, 1981 in 1-27031).
 
 
(h) 6 --
Agreement of Joint Ownership Participation between SRMPA, SRG&T and Entergy Gulf States, Inc., dated June 6, 1980, for Nelson Station, Coal Unit #6, as amended (8 to Form 8-K dated June 11, 1980, A-2-b to Form 10-Q for the quarter ended June 30, 1982; and 10-1 to Form 8-K dated February 19, 1988 in 1-27031).
 
 
(h) 7 --
First Amended Power Sales Agreement, dated December 1, 1985 between Sabine River Authority, State of Louisiana, and Sabine River Authority, State of Texas, and Entergy Gulf States, Inc., Central Louisiana Electric Co., Inc., and Louisiana Power and Light Company (10-72 to Form 10-K for the year ended December 31, 1985 in 1-27031).
 
 
+(h) 8 --
Deferred Compensation Plan for Directors of Entergy Gulf States, Inc. and Varibus Corporation, as amended January 8, 1987, and effective January 1, 1987 (10-77 to Form 10-K for the year ended December 31, 1986 in 1-27031). Amendment dated December 4, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551).
 
 
+(h) 9 --
Trust Agreement for Deferred Payments to be made by Entergy Gulf States, Inc. pursuant to the Executive Income Security Plan, by and between Entergy Gulf States, Inc. and Bankers Trust Company, effective November 1, 1986 (10-78 to Form 10-K for the year ended December 31, 1986 in 1-27031).
 
 
+(h) 10 --
Trust Agreement for Deferred Installments under Entergy Gulf States, Inc. Management Incentive Compensation Plan and Administrative Guidelines by and between Entergy Gulf States, Inc. and Bankers Trust Company, effective June 1, 1986 (10-79 to Form 10-K for the year ended December 31, 1986 in 1-27031).
 
 
+(h) 11 --
Nonqualified Deferred Compensation Plan for Officers, Nonemployee Directors and Designated Key Employees, effective December 1, 1985, as amended, continued and completely restated effective as of March 1, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551).
 
 
+(h) 12 --
Trust Agreement for Entergy Gulf States, Inc. Nonqualified Directors and Designated Key Employees by and between Entergy Gulf States, Inc. and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective July 1, 1991 (10-4 to Form 10-K for the year ended December 31, 1992 in 1-27031).
 
 
(h) 13 --
Lease Agreement, dated as of June 29, 1987, among GSG&T, Inc., and Entergy Gulf States, Inc. related to the leaseback of the Lewis Creek generating station (10-83 to Form 10-K for the year ended December 31, 1988 in 1-27031).
 
 
+(h) 14 --
Gulf States Utilities Company Executive Continuity Plan, dated January 18, 1991 (10-6 to Form 10-K for the year ended December 31, 1990 in 1-27031).
 
 
+(h) 15 --
Trust Agreement for Entergy Gulf States, Inc. Executive Continuity Plan, by and between Entergy Gulf States, Inc. and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective May 20, 1991 (10-5 to Form 10-K for the year ended December 31, 1992 in 1-27031).
 
 

E-30
Table of Contents

+(h) 16 --
Gulf States Utilities Board of Directors’ Retirement Plan, dated February 15, 1991 (10-8 to Form 10-K for the year ended December 31, 1990 in 1-27031).
 
 
(h) 17 --
Third Amendment, dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
 
 
(h) 18 --
Fourth Amendment, dated April 1, 1997, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
 
 
(h) 19 --
Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-34360).
 
 
(h) 20 --
Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-34360).
 
 
(h) 21 --
Service Agreement dated as of January 1, 2008, between Entergy Services, Inc. and Entergy Texas (10(h)25 to Form 10-K for the year ended December 31, 2008 in 3-53134).
 
 
(h) 22 --
Amendment, dated December 19, 2013, to Service Agreement with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services and Service Agreement for Generation Planning and Operational Support Services) (10(h)22 to Form 10-K for the year ended December 31, 2013 in 1-34360).

(12) Statement Re Computation of Ratios

*(a)
Entergy Arkansas’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.
 
 
*(b)
Entergy Gulf States Louisiana’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Distributions, as defined.
 
 
*(c)
Entergy Louisiana’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Distributions, as defined.
 
 
*(d)
Entergy Mississippi’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.
 
 
*(e)
Entergy New Orleans’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.
 
 
*(f)
Entergy Texas’s Computation of Ratios of Earnings to Fixed Charges, as defined.
 
 
*(g)
System Energy’s Computation of Ratios of Earnings to Fixed Charges, as defined.

*(21)  Subsidiaries of the Registrants

(23)  Consents of Experts and Counsel

*(a)
The consent of Deloitte & Touche LLP is contained herein at page 528.

*(24)  Powers of Attorney
 

E-31
Table of Contents

(31)  Rule 13a-14(a)/15d-14(a) Certifications

*(a)
Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation.
 
 
*(b)
Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation.
 
 
*(c)
Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas.
 
 
*(d)
Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas.
 
 
*(e)
Rule 13a-14(a)/15d-14(a) Certification for Entergy Gulf States Louisiana.
 
 
*(f)
Rule 13a-14(a)/15d-14(a) Certification for Entergy Gulf States Louisiana.
 
 
*(g)
Rule 13a-14(a)/15d-14(a) Certification for Entergy Louisiana.
 
 
*(h)
Rule 13a-14(a)/15d-14(a) Certification for Entergy Louisiana.
 
 
*(i)
Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi.
 
 
*(j)
Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi.
 
 
*(k)
Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans.
 
 
*(l)
Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans.
 
 
*(m)
Rule 13a-14(a)/15d-14(a) Certification for Entergy Texas.
 
 
*(n)
Rule 13a-14(a)/15d-14(a) Certification for Entergy Texas.
 
 
*(o)
Rule 13a-14(a)/15d-14(a) Certification for System Energy.
 
 
*(p)
Rule 13a-14(a)/15d-14(a) Certification for System Energy.


E-32
Table of Contents

(32)  Section 1350 Certifications

*(a)
Section 1350 Certification for Entergy Corporation.
 
 
*(b)
Section 1350 Certification for Entergy Corporation.
 
 
*(c)
Section 1350 Certification for Entergy Arkansas.
 
 
*(d)
Section 1350 Certification for Entergy Arkansas.
 
 
*(e)
Section 1350 Certification for Entergy Gulf States Louisiana.
 
 
*(f)
Section 1350 Certification for Entergy Gulf States Louisiana.
 
 
*(g)
Section 1350 Certification for Entergy Louisiana.
 
 
*(h)
Section 1350 Certification for Entergy Louisiana.
 
 
*(i)
Section 1350 Certification for Entergy Mississippi.
 
 
*(j)
Section 1350 Certification for Entergy Mississippi.
 
 
*(k)
Section 1350 Certification for Entergy New Orleans.
 
 
*(l)
Section 1350 Certification for Entergy New Orleans.
 
 
*(m)
Section 1350 Certification for Entergy Texas.
 
 
*(n)
Section 1350 Certification for Entergy Texas.
 
 
*(o)
Section 1350 Certification for System Energy.
 
 
*(p)
Section 1350 Certification for System Energy.
 
(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.


E-33