ETR-12.31.2013-10K
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, 2013
 
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)
446 North Boulevard
Baton Rouge, Louisiana 70802
Telephone (800) 368-3749
74-0662730
 
1-34360
ENTERGY TEXAS, INC.
(a Texas corporation)
350 Pine Street
Beaumont, Texas 77701
Telephone (409) 981-2000
61-1435798
 
 
 
 
 
 
 
 
 
 
1-32718
ENTERGY LOUISIANA, LLC
(a Texas limited liability company)
446 North Boulevard
Baton Rouge, Louisiana 70802
Telephone (800) 368-3749
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


Table of Contents




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 – 178,563,836
  shares outstanding at January 31, 2014
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, 7.875% Series due June 2039
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


Table of Contents


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.  [ ]

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.


Table of Contents

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 2013, was $12.4 billion based on the reported last sale price of $69.68 per share for such stock on the New York Stock Exchange on June 28, 2013.  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 2, 2014, are incorporated by reference into Part III hereof.


Table of Contents




























(Page left blank intentionally)



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

Table of Contents

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

Table of Contents

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 recently proposed 60-month notice period or such other period as approved by the FERC;
regulatory and operating challenges and uncertainties associated with the Utility operating companies’ move to the MISO RTO, which occurred in December 2013;
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 regulation of 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 the Entergy Wholesale Commodities business, 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 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, and other energy-related commodities;
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;

iv

Table of Contents

FORWARD-LOOKING INFORMATION (Concluded)

changes in environmental, tax, and other laws, including requirements for reduced emissions of sulfur, nitrogen, carbon, 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;
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 that could influence economic conditions in those areas;
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 by the end of 2014 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
DOE
United States Department of Energy
D. C. Circuit
U.S. Court of Appeals for the District of Columbia Circuit
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 and operation of six nuclear power plants, the ownership of interests in non-nuclear power plants, and the sale of the electric power produced by those 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
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
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
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

Table of Contents

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 and operation of six nuclear power plants located in the northern United States and the sale of the electric power produced by those plants to wholesale customers.  In August 2013, Entergy announced plans to close and decommission Vermont Yankee. The plant is expected to cease power production in the fourth quarter 2014 after its current fuel cycle. This business also provides services to other nuclear power plant owners. Entergy Wholesale Commodities also owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.

On December 5, 2011, Entergy announced that it would spin off its transmission business and merge it with a newly formed subsidiary of ITC Holdings Corp. (ITC). 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. Entergy and ITC have withdrawn transaction-related filings submitted to Entergy's retail regulators and the FERC.

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
2013
2012
2011
 
2013
2012
2011
 
2013
2012
2011
Utility
80

78

79

 
116

110

82

 
82

82

80

Entergy Wholesale Commodities
20

22

21

 
6

5

36

 
22

22

24

Parent & Other



 
(22
)
(15
)
(18
)
 
(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

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 impairment 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 $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 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 Initiative" below for further discussion.


2

Table of Contents
Entergy Corporation and Subsidiaries
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

Decommissioning trusts
(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 no 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 agreed to share with customers the savings from an IRS settlement related to the uncertain tax position regarding the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing. See Note 3 to the financial statements for additional discussion of the tax settlement.    

3

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


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 since March 2010 related to the transition and implementation of joining the MISO RTO.

The decommissioning trusts variance is primarily due to lower regulatory credits resulting from higher realized income on decommissioning trust fund investments. There is no effect on net income as the credits are offset by interest and investment income.

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. It is expected that the underlying transactions will result in earnings in first quarter 2014 as these positions settle. 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

4

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


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.

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 five of the six Entergy Wholesale Commodities nuclear power plants are located. Entergy Wholesale Commodities’s nuclear business experienced a decrease in realized price per MWh to $50.15 in 2013 from $50.29 in 2012 and $54.73 in 2011. The annual realized price per MWh for Entergy Wholesale Commodities reached 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 74% of its planned nuclear energy output for 2014 for an expected average contracted energy price of $50 per MWh based on market prices at December 31, 2013. In addition, Entergy Wholesale Commodities has sold forward 74% of its planned nuclear energy output for 2015 for an expected average contracted energy price of $49 per MWh based on market prices at December 31, 2013. These price trends present 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 investment required to maintain the safety and integrity of the plants. If, in the future, economic conditions or regulatory activity no longer support the continued operation 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. Vermont Yankee is expected to cease power production in the fourth quarter 2014 after its current fuel cycle. 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

5

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


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. 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 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 $2,080 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 no effect on net income;
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 and Outage” 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.


6

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

Interest expense increased primarily due to net debt issuances in 2013 of $520 million by the Utility operating companies and System Energy and lower AFUDC due to the completion of several major projects in 2012. See Note 5 to the financial statements for more details of long-term debt.

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 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 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.

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

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.

7

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



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 ITC transaction, 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.

2012 Compared to 2011

Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2012 to 2011 showing how much the line item increased or (decreased) in comparison to the prior period.
 
 
Utility
 
Entergy
Wholesale
Commodities
 
Parent &
Other
 
 
Entergy
 
(In Thousands)
2011 Consolidated Net Income (Loss)

$1,123,866

 

$491,846

 

($248,340
)
 

$1,367,372

 
 
 
 
 
 
 
 
Net revenue (operating revenue less fuel expense,
  purchased power, and other regulatory
  charges/credits)
64,531

 
(191,311
)
 
(4,313
)
 
(131,093
)
Other operation and maintenance expenses
128,955

 
52,253

 
(3,574
)
 
177,634

Asset impairment

 
355,524

 

 
355,524

Taxes other than income taxes
803

 
20,675

 
(206
)
 
21,272

Depreciation and amortization
45,728

 
(3,145
)
 
(200
)
 
42,383

Other income
(458
)
 
9,866

 
3,885

 
13,293

Interest expense
20,746

 
(15,167
)
 
50,078

 
55,657

Other expenses
9,356

 
(25,209
)
 

 
(15,853
)
Income taxes
22,029

 
(114,957
)
 
(162,480
)
 
(255,408
)
2012 Consolidated Net Income (Loss)

$960,322



$40,427



($132,386
)


$868,363

 
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.

In the fourth quarter 2012, Entergy moved two subsidiaries from Parent & Other to the Entergy Wholesale Commodities segment to improve the alignment of certain intercompany items and income tax activity. The prior period financial information in this Form 10-K has been restated to reflect this change.


8

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

As discussed in more detail in Note 1 to the financial statements, results of operations for 2012 include a $355.5 million ($223.5 million after-tax) impairment charge to write down the carrying values of Vermont Yankee and related assets to their fair values. Also, net income in 2012 was significantly affected by two settlements with the IRS; one of which related to the income tax treatment of the Louisiana Act 55 financing of the Hurricane Katrina and Hurricane Rita storm costs, and the other of which related to nuclear power plant decommissioning liabilities, both of 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 settlements. Net income for Utility for 2011 was significantly affected by a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts, 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 2011, because Entergy Louisiana is sharing the benefits with customers. See Notes 3 and 8 to the financial statements for additional discussion of the tax settlement and benefit sharing.

Net Revenue

Utility

Following is an analysis of the change in net revenue comparing 2012 to 2011.
  
Amount
  
(In Millions)
 
 
2011 net revenue

$4,904

Mark-to-market tax settlement sharing
200

Retail electric price
81

Grand Gulf recovery
71

Net wholesale revenue
(28
)
Purchased power capacity
(29
)
Volume/weather
(80
)
Louisiana Act 55 financing savings obligation
(161
)
Other
11

2012 net revenue

$4,969


The mark-to-market tax settlement sharing variance results from a regulatory charge recorded in September 2011 because Entergy Louisiana is sharing the benefits of a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts with customers. See Notes 3 and 8 to the financial statements for additional discussion of the tax settlement and benefit sharing.

The retail electric price variance is primarily due to:

an increase in the storm cost recovery rider at Entergy Mississippi, as approved by the MPSC for a five-month period effective August 2012. This increase is offset by costs included in other operation and maintenance expenses and has no effect on net income;
an increase in the energy efficiency rider at Entergy Arkansas, as approved by the APSC, effective July 2012. This increase is offset by costs included in other operation and maintenance expenses and has no effect on net income;
a special formula rate plan rate increase at Entergy Louisiana effective May 2011 in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center. See Note 2 to the financial statements for a discussion of the formula rate plan increase; and

9

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



base rate increases at Entergy Texas beginning May 2011 as a result of the settlement of the December 2009 rate case and effective July 2012 as a result of the PUCT’s order in the December 2011 rate case. See Note 2 to the financial statements for further discussion of the rate cases.

These increases were partially offset by formula rate plan decreases at Entergy New Orleans effective October 2011 and at Entergy Gulf States Louisiana effective September 2012. See Note 2 to the financial statements for further discussion of the formula rate plan decreases.

The Grand Gulf recovery variance is primarily due to increased recovery of higher costs resulting from the Grand Gulf uprate.
    
The net wholesale revenue variance is primarily due to decreased sales volume to municipal and co-op customers and lower prices.

The purchased power capacity variance is primarily due to price increases for ongoing purchased power capacity and additional capacity purchases.

The volume/weather variance is primarily due to decreased electricity usage, including the effect of milder weather as compared to the prior period on residential and commercial sales. Hurricane Isaac, which hit the Utility’s service area in August 2012, also contributed to the decrease in electricity usage. Billed electricity usage decreased a total of 1,684 GWh, or 2%, across all customer classes.

The Louisiana Act 55 financing savings obligation variance results from a regulatory charge recorded in 2012 because Entergy Gulf States Louisiana and Entergy Louisiana agreed to share the savings from an IRS settlement related to the uncertain tax position regarding the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing with customers. See Note 3 to the financial statements for additional discussion of the tax settlement.

Entergy Wholesale Commodities

Following is an analysis of the change in net revenue comparing 2012 to 2011.
  
Amount
  
(In Millions)
 
 
2011 net revenue

$2,045

Nuclear realized price changes
(194
)
Nuclear volume
(33
)
Other
36

2012 net revenue

$1,854


As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by $191 million, or 9%, in 2012 compared to 2011 primarily due to lower pricing in its contracts to sell power and lower volume in its nuclear fleet resulting from more unplanned and refueling outage days in 2012 as compared to 2011 which was partially offset by the exercise of resupply options provided for in purchase power agreements whereby 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. Partially offsetting the lower net revenue from the nuclear fleet was higher net revenue from the Rhode Island State Energy Center, which was acquired in December 2011.


10

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

Following are key performance measures for Entergy Wholesale Commodities for 2012 and 2011:
 
2012
 
2011
Owned capacity (MW)
6,612
 
6,599
GWh billed
46,178
 
43,497
Average realized price per MWh
$50.02
 
$54.50
 
 
 
 
Entergy Wholesale Commodities Nuclear Fleet
Capacity factor
89%
 
93%
GWh billed
41,042
 
40,918
Average realized revenue per MWh
$50.29
 
$54.73
Refueling Outage Days:
 
 
 
FitzPatrick
34
 
Indian Point 2
28
 
Indian Point 3
 
30
Palisades
34
 
Pilgrim
 
25
Vermont Yankee
 
25

Other Income Statement Items

Utility

Other operation and maintenance expenses increased from $1,951 million for 2011 to $2,080 million for 2012 primarily due to:

an increase of $47 million in compensation and benefits costs primarily due to decreasing discount rates and changes in certain actuarial assumptions resulting from an experience study. See "Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits" below and Note 11 to the financial statements for further discussion of benefits costs;
$38 million of costs incurred in 2012 related to the now terminated plan to spin off and merge the Utility’s transmission business;
an increase of $29 million in nuclear expenses primarily due to higher labor costs, including higher contract labor;
an increase of $21 million resulting from a temporary increase in the Entergy Mississippi storm damage reserve authorized by the MPSC effective August 2012. These costs included are recovered through the storm cost recovery rider and have no effect on net income;
an increase of $14 million in energy efficiency costs at Entergy Arkansas. These costs are recovered through the energy efficiency rider and have no effect on net income;
the deferral in 2011 of $13.4 million of 2010 Michoud plant maintenance costs pursuant to the settlement of Entergy New Orleans’ 2010 test year formula rate plan filing approved by the City Council in September 2011. See Note 2 to the financial statements for further discussion of the Entergy New Orleans 2010 test year formula rate plan filing and settlement; and
an increase of $10 million in operating expenses due to the sale of surplus oil inventory in 2011.

These increases were partially offset by:

a decrease of approximately $7 million as a result of the deferral or capitalization of storm restoration costs for Hurricane Isaac, which hit the Utility’s service area in August 2012;

11

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


the effect of the deferral, as approved by the FERC, and the LPSC for the Louisiana jurisdictions, of costs related to the transition and implementation of joining the MISO RTO, which reduced expenses by $10 million; and
a decrease of $9 million in legal expenses, not including legal costs related to the transition and implementation of joining the MISO RTO and the now terminated plan to spin off and merge the Utility’s transmission business which are included in other bullets, primarily resulting from a decrease in legal and regulatory activity decreasing the use of outside legal services.

Depreciation and amortization expenses increased primarily due to additions to plant in service.

Interest expense increased primarily due to a revision in 2011 caused by FERC’s acceptance of a change in the treatment of funds received from independent power producers for transmission interconnection projects. Also contributing to the increase were net debt issuances by certain of the Utility operating companies.

Entergy Wholesale Commodities

Other operation and maintenance expenses increased from $906 million for 2011 to $958 million for 2012 primarily due to:

an increase of $23 million in compensation and benefits costs primarily due to decreasing discount rates and changes in certain actuarial assumptions resulting from an experience study. See "Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits " below and Note 11 to the financial statements for further discussion of benefits costs;
an increase of $23 million primarily due to higher contract labor costs and higher material and supply costs; and
an increase of $20 million due to the operations of the Rhode Island State Energy Center, which was acquired in December 2011.

These increases were partially offset by the effects of recording 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. The damages awarded include the reimbursement of approximately $25 million of spent nuclear fuel storage costs previously recorded as operation and maintenance expenses.

The asset impairment variance is due to a $355.5 million ($223.5 million after-tax) impairment charge recorded in the first quarter 2012 to write down the carrying values of Vermont Yankee and related assets to their fair values. See Note 1 to the financial statements for further discussion of this charge.

Taxes other than income taxes increased primarily due to increased property taxes at FitzPatrick, increased electric generating excises at Vermont Yankee, and property taxes from the Rhode Island State Energy Center acquired in December 2011. Previously, FitzPatrick was granted an exemption from property taxation and paid taxes according to a payment in lieu of property tax agreement. This agreement expired on June 30, 2011 and FitzPatrick is now being taxed under the regular property tax system. FitzPatrick has pending litigation in the Fifth Judicial District of New York State Supreme Court challenging each annual property tax assessment placed on FitzPatrick since the expiration of the payment in lieu of tax agreement.  The State of Vermont enacted legislation, which became effective on July 1, 2012, increasing the electric generating excise on Vermont Yankee. Vermont Yankee challenged the constitutionality of this legislation.  In October 2012 the federal judge for the U.S. District Court for the District of Vermont dismissed the suit on jurisdictional grounds.  In December 2013 the U.S. Court of Appeals for the Second Circuit affirmed that decision. As part of the settlement agreement regarding the operation and decommissioning of Vermont Yankee, Entergy agreed not to pursue further appeals or other challenges to this legislation. See "Impairment of Long-Lived Assets" in Note 1 to the financial statements for further discussion of the settlement agreement.


12

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

Depreciation and amortization expenses decreased primarily due to adjustments resulting from final court decisions in the Entergy Nuclear Indian Point 2 and Vermont Yankee lawsuits against the U.S. Department of Energy related to spent nuclear fuel disposal. The effects of recording the proceeds from the judgments reduced the plant in service balances with a corresponding $25 million reduction to previously-recorded depreciation expense. Partially offsetting the adjustment was an increase due to additions to plant in service, including the acquisition of the Rhode Island State Energy Center in December 2011.

Other expenses decreased primarily due to a credit to decommissioning expense of $49 million in the second quarter 2012 compared to a credit to decommissioning expense of $34 million in the fourth quarter 2011 resulting from reductions in the decommissioning cost liabilities for certain nuclear plants as a result of revised decommissioning cost studies. See “Critical Accounting Estimates - Nuclear Decommissioning Costs” below for further discussion of these credits.

Parent & Other

Interest expense increased primarily due to the issuance of $500 million of 4.7% senior notes by Entergy Corporation in January 2012 and a higher interest rate on outstanding borrowings under the Entergy Corporation credit facility.

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 2012 was 3.4%. The difference in the effective income tax rate versus the statutory rate of 35% for 2012 was related to (1) IRS settlements 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.

The effective income tax rate for 2011 was 17.3%. The difference in the effective income tax rate versus the statutory rate of 35% in 2011 was primarily due to a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts, which resulted in a reduction in income tax expense of $422 million. See Note 3 to the financial statements for further discussion of the settlement.

Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants

In March 2011 and May 2012 the NRC renewed the operating licenses of Vermont Yankee and Pilgrim, respectively, for an additional 20 years, as a result of which each license now expires in 2032. For additional discussion regarding the planned shutdown of the Vermont Yankee plant by the end of 2014, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements. The NRC operating license for Palisades expires in 2031 and for FitzPatrick expires in 2034.
 
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. In April 2007, Entergy submitted the applications to the NRC to renew the operating licenses for Indian Point 2 and 3 for an additional 20 years. Indian Point Unit 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.

13

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


Various parties have expressed opposition to renewal of the licenses. The ASLB has admitted 21 contentions raised by the State of New York or other parties, which were combined into 16 discrete issues.

Three of the 16 discrete issues have been resolved by the ASLB without hearing, two by means of ASLB-approved settlements, and a third by summary disposition. 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, stating that the appeal could be renewed at the conclusion of the ASLB proceedings. 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. There is no deadline for the NRC staff filing on Entergy's updated SAMA cost analysis.

Of the remaining 13 discrete issues, nine that were designated by the ASLB as “Track 1” 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. One Track 1 contention based on a dispute over the characterization of certain electrical equipment as “active” or “passive” was resolved in favor of the State of New York despite precedent supporting the characterization advocated by Entergy and NRC staff. Appeals to the NRC of issues raised by the ASLB's Track 1 decision were due in February 2014. The State of New York and Clearwater each appealed the decision on a single contention (SAMA decontamination times 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. The ASLB's decision on issues not appealed is now final. NRC rules provide for two further rounds of filings after submission of appeals. There is no deadline for the NRC to resolve appeals from the ASLB. The remaining four discrete issues have been designated by the ASLB as “Track 2.” Testimony on Track 2 contentions has not been completed, and Track 2 hearings have not been scheduled.

The NRC staff is also continuing to perform its technical and environmental reviews of the Indian Point 2 and 3 license renewal applications. The NRC staff issued a Final Safety Evaluation Report (FSER) in August 2009, a supplement to the FSER in August 2011, a FSEIS in December 2010, and a supplement to the FSEIS in June 2013. In addition, the NRC staff has stated its intent to issue a further supplement to the FSER by mid-2014. The NRC staff is considering whether a second supplement to the FSEIS is necessary. The second supplement to the FSER and the already-issued supplement to the FSEIS are expected to affect testimony yet to be filed on Track 2 contentions.

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 applications. See “Nuclear Matters” below for discussion of spent nuclear fuel storage issues and its 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 the NYSDEC in April 2009,

14

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


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 the 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, which is continuing into 2014. After the full hearing on the merits and post-hearing briefing, the ALJs will issue a recommended decision to the Commissioner who will then issue the final agency decision. A party to the proceeding can appeal the decision of the Commissioner to state court.

In addition, the consistency of Indian Point’s operations with New York State’s coastal management policies must be resolved to the extent required by the Coastal Zone Management Act (CZMA). Entergy has undertaken three independent initiatives to resolve CZMA issues. First, on July 24, 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. On July 30, 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. On April 5, 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 the New York State Department of State (NYSDOS) could conduct a CZMA review for NRC license renewal purposes. On April 15, 2013, the NRC Staff filed answers recommending the ASLB deny both Entergy’s and the State of New York’s motions for declaratory order. On June 12, 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. On December 6, 2013, NRC staff initiated consultation under federal CZMA regulations by serving on NYSDOS written questions related to whether Indian Point had been previously reviewed. NRC staff did not state a deadline for NYSDOS to respond. It is uncertain what further steps may be entailed in the consultation process.

Second, Entergy filed with the 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 on December 13, 2013. Entergy initiated an appeal to the Appellate Division of the New York State Supreme Court on January 22, 2014. Briefing and oral argument have not yet been scheduled.
    
Third, on December 17, 2012, Entergy filed with NYSDOS a consistency determination explaining why Indian Point satisfies all applicable NYCMP policies. Entergy included in the consistency determination a “reservation of rights” clarifying that Entergy does not concede NYSDOS’s right to conduct a new CZMA review for Indian Point. The six-month federal deadline for state decision on a consistency determination runs from the date the submission is complete. On January 16, 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

15

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


issuance by NRC staff. On June 28, 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 on June 20, 2013. In October 2013, Entergy and NYSDOS executed a stay agreement that extended the deadline for NYSDOS to decide Indian Point’s CZMA consistency certification to March 22, 2014. In January 2014, Entergy and NYSDOS executed another stay agreement that further extends YSDOS's deadline for decision to December 31, 2014. A basis for the further extension is a request by NYSDOS for supplemental information, to which Entergy will be responding in stages during 2014.

In August 2013, Riverkeeper filed with the ASLB a proposed amended Endangered Species Act contention alleging that NRC Staff’s supplemental FSEIS issued in June 2013 did not adequately consider Riverkeeper comments or explain the effect of certain new information used to develop the supplemental FSEIS. Entergy and NRC Staff have filed answers in opposition. Riverkeeper’s proposed amended contention and Entergy’s motion to dismiss Riverkeeper’s original admitted contention on endangered species are pending before the ASLB.

ANO Damage and Outage

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 $94 million as of December 31, 2013.  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.  Each of the Utility operating companies has recovery mechanisms in place designed to recover its prudently-incurred fuel and purchased power costs.

Entergy Arkansas is assessing 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. 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 general contractor, and certain individuals asserting claims of breach of contract, negligence, and gross negligence in connection with their responsibility for the stator drop.

In the second quarter 2013, Entergy Arkansas recorded an insurance receivable of $50 million based on the minimum amount that it expects to receive from NEIL. This $50 million receivable offset approximately $35 million of capital spending, $13 million of operation and maintenance expense, and $2 million of incremental deferred refueling outage costs incurred for the recovery through December 31, 2013. As of December 31, 2013, Entergy Arkansas has incurred approximately $34 million in capital spending, $9 million in operation and maintenance expense, and $1 million in incremental deferred refueling outage costs in excess of its recorded insurance receivable. In January 2014, Entergy Arkansas collected $20 million of the $50 million receivable that it expects to receive from NEIL.


16

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


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 in costs in 2013 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.
 
2013
 
2012
Debt to capital
57.9
%
 
58.7
%
Effect of excluding securitization bonds
(1.6
%)
 
(1.8
%)
Debt to capital, excluding securitization bonds (a)
56.3
%

56.9
%
Effect of subtracting cash
(1.5
%)
 
(1.1
%)
Net debt to net capital, excluding securitization bonds (a)
54.8
%

55.8
%

(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 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, 2013. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2013. 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.


17

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


Long-term debt maturities and
estimated interest payments
 
 
2014
 
 
2015
 
 
2016
 
 
2017-2018
 
 
after 2018
 
 
(In Millions)
Utility
 

$942

 

$1,095

 

$754

 

$2,328

 

$12,240

Entergy Wholesale Commodities
 
15

 
19

 
2

 
4

 
55

Parent and Other
 
72

 
616

 
51

 
808

 
489

Total
 

$1,029

 

$1,730

 

$807

 

$3,140

 

$12,784


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 2018. 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 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, 2013 was 1.96% on the drawn portion of the facility.

As of December 31, 2013, 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
 
$255
 
$8
 
$3,237

(a)The capacity decreases to $3,490 in March 2017.

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.

In September 2012, Entergy implemented a commercial paper program, and in July 2013 the Board increased the commercial paper program limit to $1.5 billion. As of December 31, 2013, Entergy Corporation had approximately $1,045 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2013 was 0.84%.

Capital lease obligations are a minimal part of Entergy’s overall capital structure. Following are Entergy’s payment obligations under those leases.
 
2014
 
2015
 
2016
 
2017-2018
 
after 2018
 
(In Millions)
Capital lease payments
$5
 
$5
 
$4
 
$8
 
$30

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


18

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

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, 2013 as follows:
 
Company
 
 
Expiration Date
 
Amount of
Facility
 
 
Interest Rate (a)
 
Amount Drawn as
of December 31, 2013
Entergy Arkansas
 
April 2014
 
$20 million (b)
 
1.75%
 
Entergy Arkansas
 
March 2018
 
$150 million (c)
 
1.67%
 
Entergy Gulf States Louisiana
 
March 2018
 
$150 million (d)
 
1.67%
 
Entergy Louisiana
 
March 2018
 
$200 million (e)
 
1.67%
 
Entergy Mississippi
 
May 2014
 
$35 million (f)
 
1.92%
 
Entergy Mississippi
 
May 2014
 
$20 million (f)
 
1.92%
 
Entergy Mississippi
 
May 2014
 
$37.5 million (f)
 
1.92%
 
Entergy New Orleans
 
November 2014
 
$25 million (g)
 
1.64%
 
Entergy Texas
 
March 2018
 
$150 million (h)
 
1.92%
 

(a)
The interest rate is the rate as of December 31, 2013 that would be applied to outstanding borrowings under the facility.
(b)
The credit facility requires Entergy Arkansas to maintain a debt ratio of 65% or less of its total capitalization.  Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable.
(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, 2013, $0.2 million in letters of credit were outstanding.  The credit facility requires Entergy Arkansas to maintain a consolidated debt ratio of 65% or less of its total capitalization.
(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, 2013, $15.2 million in letters of credit were outstanding.  The credit facility requires Entergy Gulf States Louisiana to maintain a consolidated debt ratio of 65% or less of its total capitalization.
(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, 2013, $7.0 million in letters of credit were outstanding.  The credit facility requires Entergy Louisiana to maintain a consolidated debt ratio of 65% or less of its total capitalization.
(f)
The credit facilities require Entergy Mississippi to maintain a debt ratio of 65% or less of its total capitalization. Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable. 
(g)
The credit facility requires Entergy New Orleans to maintain a debt ratio of 65% or less of its total capitalization.
(h)
The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2013, $25 million in letters of credit were outstanding.  The credit facility requires Entergy Texas to maintain a consolidated debt ratio of 65% or less of its total capitalization.

In addition, Entergy Mississippi and Entergy New Orleans each entered into an uncommitted letter of credit facility as a means to post collateral to support its obligations related to MISO.  As of December 31, 2013, a $21 million letter of credit was outstanding under Entergy Mississippi’s letter of credit facility and a $8.5 million letter of credit was outstanding under Entergy New Orleans’s letter of credit facility. As of December 31, 2013, the letter of credit fee on outstanding letters of credit under the Entergy Mississippi and Entergy New Orleans letter of credit facilities was 1.50%.

19

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


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, 2013 on non-cancelable operating leases with a term over one year:
 
2014
 
2015
 
2016
 
2017-2018
 
after 2018
 
(In Millions)
Operating lease payments
$106
 
$90
 
$65
 
$84
 
$111

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

Summary of Contractual Obligations of Consolidated Entities
Contractual Obligations
 
2014
 
2015-2016
 
2017-2018
 
after 2018
 
Total
 
 
(In Millions)
Long-term debt (a)
 

$1,029

 

$2,537

 

$3,140

 

$12,784

 

$19,490

Capital lease payments (b)
 

$5

 

$9

 

$8

 

$30

 

$52

Operating leases (b)
 

$106

 

$155

 

$84

 

$111

 

$456

Purchase obligations (c)
 

$1,738

 

$2,877

 

$2,379

 

$9,526

 

$16,520


(a)
Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.
(b)
Lease obligations are discussed in Note 10 to the financial statements.
(c)
Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services.  Almost all of the total are fuel and purchased power obligations.

In addition to the contractual obligations, Entergy currently expects to contribute approximately $400 million to its pension plans and approximately $74.1 million to other postretirement plans in 2014, although the required pension contributions will not be known with more certainty until the January 1, 2014 valuations are completed by April 1, 2014. 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 $193 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.


20

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

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 2014 through 2016.
Planned construction and capital investments
 
2014
 
2015
 
2016
 
 
(In Millions)
Utility:
 
 
 
 
 
 
Generation
 

$650

 

$640

 

$590

Transmission
 
515

 
635

 
570

Distribution
 
575

 
545

 
565

Other
 
155

 
180

 
150

Total
 
1,895

 
2,000

 
1,875

Entergy Wholesale Commodities
 
420

 
380

 
230

Total
 

$2,315

 

$2,380

 

$2,105


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:

The currently planned construction or purchase of additional generation supply sources within the Utility’s service territory through the Utility’s portfolio transformation strategy, including a self-build option at Entergy Louisiana’s Ninemile site identified in the Summer 2009 Request for Proposal, discussed below.
Entergy Wholesale Commodities investments associated with specific investments such as dry cask storage, nuclear license renewal, NYPA value sharing, component replacements, software, and security.
Environmental compliance spending. 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 support economic development projects.

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.

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 will be a nominally-sized 550 MW unit that is estimated to cost approximately $721 million to construct, 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

21

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


Ninemile 6 capacity and energy is proposed to be 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. All major permits and approvals required to begin construction have been obtained and construction is in progress.

Under the terms approved by the LPSC, 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 November 2013, Entergy Louisiana and Entergy Gulf States Louisiana filed a joint application with the LPSC to certify the estimated first year revenue requirement associated with Ninemile 6 that will be placed into rates. Entergy New Orleans expects to initiate a rate proceeding prior to the expected in-service date.

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 2014 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 $593 million in 2013, $589 million in 2012, and $590 million in 2011 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, 2013, $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 ($739 million as of December 31, 2013);
securities issuances;
bank financing under new or existing facilities or commercial paper; and
sales of assets.

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

Provisions within the Articles of Incorporation 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, 2013, under provisions

22

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

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 2014. 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 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 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, Entergy Gulf States Louisiana is seeking an LPSC determination that $73.8 million in system restoration costs were prudently incurred and Entergy Louisiana is seeking an LPSC determination that $247.7 million in system restoration costs were prudently incurred.  Entergy Gulf States Louisiana and Entergy Louisiana intend to replenish their storm escrow accounts to $90 million and $200 million, respectively, primarily through traditional debt markets and have requested special rate treatment of any borrowings for that purpose.  In May 2013, Entergy Gulf States Louisiana and Entergy Louisiana filed a supplemental application proposing a specific means to finance system restoration costs and related requests. Entergy Gulf States Louisiana and Entergy Louisiana are proposing to finance Hurricane Isaac restoration costs through Louisiana Act 55 financing, which was the same method they used for Hurricanes Katrina, Rita, Gustav, and Ike.

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. The LPSC Staff also supported the requests to re-establish storm reserves of $90 million for Entergy Gulf States Louisiana and $200 million for Entergy Louisiana. One intervenor filed testimony recommending storm reserve levels of $70 million for Entergy Gulf States Louisiana and $100 million for Entergy Louisiana, but takes no position on the prudence of the Hurricane Isaac system restoration costs. An evidentiary hearing took place in December 2013, and an LPSC decision is expected in 2014.

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

23

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


account to partially offset these costs. Entergy New Orleans plans to make a filing with the City Council in the first quarter of 2014 seeking certification of these costs.

Entergy Louisiana Securitization Bonds – Little Gypsy

In August 2011 the LPSC issued a financing order authorizing the issuance of bonds to recover Entergy Louisiana’s investment recovery costs associated with the canceled Little Gypsy repowering project.  In September 2011, Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, issued $207.2 million of senior secured investment recovery bonds.  The bonds have an interest rate of 2.04% and an expected maturity date of June 2021.  There is no recourse to Entergy or Entergy Louisiana in the event of a bond default. See Note 5 to the financial statements for additional discussion of the issuance of the investment recovery bonds.

Cash Flow Activity

As shown in Entergy’s Statements of Cash Flows, cash flows for the years ended December 31, 2013, 2012, and 2011 were as follows.
 
2013
 
2012
 
2011
 
(In Millions)
Cash and cash equivalents at beginning of period

$533

 

$694

 

$1,295

 


 
 
 
 
Net cash provided by (used in):
 

 
 

 
 

Operating activities
3,189

 
2,940

 
3,128

Investing activities
(2,602
)
 
(3,639
)
 
(3,447
)
Financing activities
(381
)
 
538

 
(282
)
Net increase (decrease) in cash and cash equivalents
206

 
(161
)
 
(601
)
 
 
 
 
 
 
Cash and cash equivalents at end of period

$739

 

$533

 

$694


Operating Activities

2013 Compared to 2012

Net cash provided by operating activities increased by $249 million in 2013 compared to 2012 primarily due to:

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


24

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

These increases in cash flow were partially offset by:

an increase of $79 million in income tax payments primarily due to 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.

2012 Compared to 2011

Entergy's net cash provided by operating activities decreased by $188 million in 2012 compared to 2011 primarily due to:

the decrease in Entergy Wholesale Commodities net revenue that is discussed previously;
Hurricane Isaac storm restoration spending of $98 million in 2012;
income tax payments of $49.2 million in 2012 compared to income tax refunds of $2 million in 2011. The income tax payments in 2012 were primarily due to state income tax effects of the settlement of the 2006-2007 IRS audit; and
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.

These decreases were partially offset by a decrease of $230 million in pension contributions. See "Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits" below for a discussion of qualified pension and other postretirement benefits funding.

Investing Activities

2013 Compared to 2012

Net cash used in investing activities decreased by $1,038 million in 2013 compared to 2012 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. Entergy’s construction spending plans for 2014 through 2016 are discussed further in “Capital Expenditure Plans and Other Uses of Capital” above; 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.


25

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


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’s 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.

2012 Compared to 2011

Net cash used in investing activities increased by $192 million in 2012 compared to 2011 primarily due to an increase in construction expenditures, primarily in the Utility business resulting from Hurricane Isaac restoration spending, the uprate project at Grand Gulf, the Ninemile Unit 6 self-build project, and the Waterford 3 steam generator replacement project in 2012.

This increase was partially offset by:

a decrease of $190 million in payments for the purchase of plants resulting from the purchase of the Hot Spring Energy Facility by Entergy Arkansas for approximately $253 million in November 2012, the purchase of the Hinds Energy Facility by Entergy Mississippi for approximately $206 million in November 2012, the purchase of the Acadia Power Plant by Entergy Louisiana for approximately $300 million in April 2011, and the purchase of the Rhode Island State Energy Center for approximately $346 million by an Entergy Wholesale Commodities subsidiary in December 2011. These transactions are described in more detail in Note 15 to the financial statements;
proceeds received from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel; and
a decrease in nuclear fuel purchases because of variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle.

Financing Activities

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 $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 and Entergy's commercial paper program.

26

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


2012 Compared to 2011

Entergy’s financing activities provided $538 million of cash in 2012 compared to using $282 million of cash in 2011 primarily due to the following activity:

long-term debt activity provided approximately $348 million of cash in 2012 compared to $554 million of cash in 2011. The most significant long-term debt activity in 2012 included the net issuance of $1.1 billion of long-term debt at the Utility operating companies and System Energy, the issuance of $500 million of senior notes by Entergy Corporation, and Entergy Corporation decreasing borrowings outstanding on its long-term credit facility by $1.1 billion. Entergy Corporation issued $665 million of commercial paper in 2012 to repay borrowings on its long-term credit facility;
Entergy repurchasing $235 million of its common stock in 2011, as discussed below;
a net increase in 2012 of $51 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 long-term debt outstanding, see Note 5 to the financial statements.

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
 
9.3%
Entergy Gulf States Louisiana
 
9.15%-10.75% Electric; 9.45%-10.45% Gas
Entergy Louisiana
 
9.15% - 10.75%
Entergy Mississippi
 
9.76% - 11.83%
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. The Entergy Arkansas authorized return on common equity is subject to pending rehearing.


27

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


Federal Regulation

Entergy’s Integration Into the MISO Regional Transmission Organization

On December 19, 2013, the Utility operating companies successfully completed their planned integration into the MISO RTO. Integration into the MISO RTO was the culmination of efforts undertaken by the Utility operating companies consistent with FERC’s order, issued in 2000, encouraging utilities to voluntarily place their transmission facilities under the control of an independent regional transmission organization (RTO). Initially, these efforts led to the establishment of Southwest Power Pool (SPP), an RTO, in November 2006, as the Independent Coordinator of Transmission (ICT) for the Utility operating companies, with responsibility for certain transmission tariff functions, including granting or denying transmission service, administering OASIS, evaluating all transmission requests, and serving as the reliability coordinator. Also as part of these initial efforts, an Entergy Regional State Committee (E-RSC), comprised of one representative from each of the Utility operating companies’ retail regulators, was formed. In concert with the FERC, the E-RSC retained an independent entity to conduct a cost-benefit analysis comparing the option of continuing the ICT arrangement to proposals under which Entergy would join the SPP RTO or the MISO RTO. This analysis, completed in 2011, showed that joining the MISO RTO would be expected to provide the most benefits to the Utility operating companies’ customers of these options.

On April 25, 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 integrated 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.

After the April 2011 announcement, each of the Utility operating companies filed an application with its retail regulator concerning the proposal to join MISO and transfer functional control of each company’s transmission assets to MISO. The applications to join MISO sought a finding that membership in MISO is in the public interest.

The LPSC voted to grant Entergy Gulf States Louisiana’s and Entergy Louisiana’s application for transfer of control to MISO, subject to conditions, in May 2012 and issued its order in June 2012.

In October 2012 the APSC authorized Entergy Arkansas to sign the MISO Transmission Owners Agreement and move forward with the MISO integration process. The APSC stated in its order that it would give conditional approval of Entergy Arkansas’s application upon MISO’s filing with the APSC proof of approval by the appropriate MISO entities of certain governance enhancements. In April 2013 the APSC issued an order resolving the outstanding issues in Entergy Arkansas’s change of control docket and granted Entergy Arkansas’s application subject to the conditions set forth in the APSC’s October 2012 order. In September 2013 the APSC issued an order directing Entergy Arkansas and MISO to show cause why the APSC should not find that Entergy Arkansas and MISO were in violation of certain conditions. In October 2013, Entergy Arkansas and MISO submitted testimony in compliance with the show cause order. In November 2013 the APSC issued an order in which it found that Entergy Arkansas and MISO are not currently in violation of the conditions addressed in the show cause order, but directed that Entergy Arkansas and MISO demonstrate, through monthly testimony, that Entergy Arkansas and MISO are moving forward with full compliance with those conditions, and that Entergy Arkansas and MISO advise the APSC of FERC filings or FERC orders related to compliance with those conditions.

In September 2012, Entergy Mississippi and the Mississippi Public Utilities Staff filed a joint stipulation indicating that they agree that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities to MISO is in the public interest, subject to certain contingencies and conditions. In November 2012 the MPSC issued an order approving a joint stipulation filed by Entergy Mississippi and the Mississippi Public Utilities Staff, concluding

28

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

that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities to MISO is in the public interest, subject to certain conditions.

In November 2012 the City Council issued a resolution concerning the application of Entergy New Orleans. In its resolution, the City Council approved a settlement agreement agreed to by Entergy New Orleans, Entergy Louisiana, MISO, and the advisors to the City Council related to joining MISO and found that it is in the public interest for Entergy New Orleans and Entergy Louisiana to join MISO, subject to certain conditions.

Entergy Texas submitted its change of control filing in April 2012. In August 2012 parties in the PUCT proceeding, with the exception of SPP, filed a non-unanimous settlement. The substance of the settlement is that it is in the public interest for Entergy Texas to transfer operational control of its transmission facilities to MISO under certain conditions. In October 2012 the PUCT issued an order approving the transfer as in the public interest, subject to the terms and conditions in the settlement, 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.

With these actions on their applications, the Utility operating companies obtained from all of the 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.

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 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

29

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


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.

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. These filings included, but are not limited to, proposals to address the allocation of transmission upgrade costs, an extension of the E-RSC arrangement, enhanced authority for the Organization of MISO States, Inc., and other numerous other matters. The Utility operating companies and the MISO RTO received the FERC orders necessary for those companies to integrate into the MISO RTO on December 19, 2013 consistent with the approvals obtained from Entergy’s retail regulators, although some proceedings remain pending at 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 PURPA and the FERC’s implementing regulations. Occidental’s filing asks that the FERC declare that MISO’s QF integration plan is unlawful, find that the plan cannot be implemented because MISO did not file it pursuant to section 205 of the Federal Power Act, and direct that MISO modify certain aspects of the plan. Entergy sought to intervene and filed a protest to the pleadings.

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. On February 20, 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.

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

Citing its concerns that the benefits of its continued participation in the current form of the System Agreement have been seriously eroded, in December 2005, Entergy Arkansas submitted its notice that it will terminate its participation in the current System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC.


30

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

In October 2007 the MPSC issued a letter confirming its belief that Entergy Mississippi should exit the System Agreement in light of the recent developments involving the System Agreement. In November 2007, Entergy Mississippi provided its written notice to terminate its participation in the System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC.

In February 2009, Entergy Arkansas and Entergy Mississippi filed with the FERC 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 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.

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 19, 2013.

In keeping with the commitments made in its March 2013 answer to the protests and after a careful evaluation of the basis for and continued reasonableness of the ninety-six 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 ninety-six months to sixty months. The proposed amendment also clarifies that the revised notice period will apply to any written notice of termination 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.


31

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


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 ninety-six months to sixty months. The City Council argued that Entergy has not adequately supported its proposal to shorten the notice period from ninety-six months to sixty 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 sixty 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 thirty-six months). The LPSC argued that the sixty-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.

See also the discussion of the order of the PUCT concerning Entergy Texas’s proposal to join MISO discussed further in the “Federal Regulation - Entergy’s Integration Into the MISO Regional Transmission Organization” section above.

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 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.

32

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

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 issuances of debt.  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 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 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's 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’s 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, put and/or call 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 sensitivity are provided to show potential variations.  The sensitivities may not reflect the total maximum upside potential from higher market prices.  The information contained in the table below 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’s current forward capacity and generation contracts as well as total revenue projections based on market prices as of December 31, 2013.


33

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


Entergy Wholesale Commodities Nuclear Portfolio
 
 
2014
 
2015
 
2016
 
2017
 
2018
Energy
 
 
 
 
 
 
 
 
 
 
Percent of planned generation under contract (a):
 
 
 
 
 
 
 
 
 
 
Unit-contingent (b)
 
25%
 
15%
 
16%
 
14%
 
14%
Unit-contingent with availability guarantees (c)
 
16%
 
15%
 
14%
 
15%
 
3%
Firm LD (d)
 
59%
 
44%
 
10%
 
—%
 
—%
Offsetting positions (e)
 
(26%)
 
—%
 
—%
 
—%
 
—%
Total
 
74%
 
74%
 
40%
 
29%
 
17%
Planned generation (TWh) (f) (g)
 
39
 
35
 
36
 
35
 
35
Average revenue per MWh on contracted volumes:
 
 
 
 
 
 
 
 
 
 
Minimum
 
$47
 
$43
 
$47
 
$51
 
$56
Expected based on market prices as of Dec. 31, 2013
 
$50
 
$49
 
$49
 
$52
 
$56
Sensitivity: -/+ $10 per MWh market price change
 
$48-$52
 
$45-$54
 
$47-$51
 
$51-$54
 
$56
 
 
 
 
 
 
 
 
 
 
 
Capacity
 
 
 
 
 
 
 
 
 
 
Percent of capacity sold forward (h):
 
 
 
 
 
 
 
 
 
 
Bundled capacity and energy contracts (i)
 
16%
 
18%
 
18%
 
18%
 
18%
Capacity contracts (j)
 
28%
 
15%
 
15%
 
6%
 
—%
Total
 
44%
 
33%
 
33%
 
24%
 
18%
Planned net MW in operation (g)
 
5,011
 
4,406
 
4,406
 
4,406
 
4,406
Average revenue under contract per kW per month
    (applies to capacity contracts only)
 
$2.7
 
$3.2
 
$3.4
 
$3.6
 
$—
 
 
 
 
 
 
 
 
 
 
 
Total Nuclear Energy and Capacity Revenues (m)
 
 
 
 
 
 
 
 
 
 
Expected sold and market total revenue per MWh
 
$55
 
$50
 
$49
 
$50
 
$51
Sensitivity: -/+ $10 per MWh market price change
 
$51-$59
 
$45-$56
 
$42-$56
 
$43-$57
 
$43-$59

Entergy Wholesale Commodities Non-Nuclear Portfolio
 
 
2014
 
2015
 
2016
 
2017
 
2018
Energy
 
 
 
 
 
 
 
 
 
 
Percent of planned generation under contract (a):
 
 
 
 
 
 
 
 
 
 
Cost-based contracts (k)
 
33%
 
35%
 
34%
 
32%
 
33%
Firm LD (d)
 
6%
 
6%
 
6%
 
6%
 
6%
Total
 
39%
 
41%
 
40%
 
38%
 
39%
Planned generation (TWh) (f) (l)
 
6
 
6
 
6
 
6
 
6
 
 
 
 
 
 
 
 
 
 
 
Capacity
 
 
 
 
 
 
 
 
 
 
Percent of capacity sold forward (h):
 
 
 
 
 
 
 
 
 
 
Cost-based contracts (k)
 
24%
 
24%
 
24%
 
26%
 
26%
Bundled capacity and energy contracts (i)
 
8%
 
8%
 
8%
 
8%
 
8%
Capacity contracts (j)
 
53%
 
53%
 
53%
 
23%
 
—%
Total
 
85%
 
85%
 
85%
 
57%
 
34%
Planned net MW in operation (l)
 
1,052
 
1,052
 
1,052
 
977
 
977


34

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

(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.
(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.
(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 expire within five years. Assumes shutdown of Vermont Yankee in the fourth quarter 2014 and uninterrupted normal operation at remaining 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) and Indian Point 3 (December 2015). For a discussion regarding the shutdown of the Vermont Yankee plant, see Impairment of Long-Lived Assets in Note 1 to the financial statements. For a discussion regarding the license renewals 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 prior to receiving market-based authority under MISO. The percentage sold assumes approval of long-term 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’s wind investment and from the 544 MW Ritchie plant that Entergy retired in November 2013. The decrease in planned net MW in operation beginning in 2017 is due to the expiration of a non-affiliated 75 MW contract.
(m)
Includes expectations for the new New York ISO Lower Hudson Valley capacity zone starting in May 2014.

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 $240 million in 2014 and would have had a corresponding effect on pre-tax income of $125 million in 2013. 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 ($91) million in 2014 and would have had a corresponding effect on pre-tax income of ($76) million in 2013.

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

35

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


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 will pay 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 will record the liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick.  In 2013, 2012, and 2011, 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, 2013, based on power prices at that time, Entergy had liquidity exposure of $274 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $104 million of posted cash collateral.  As of December 31, 2013, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $123 million for a $1 per MMBtu increase in gas prices in both the short-and long-term markets.  In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2013, Entergy would have been required to provide approximately $113 million of additional cash or letters of credit under some of the agreements.

As of December 31, 2013, substantially all of the counterparties or their guarantors for 100% of the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 2017 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 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 and an estimate of the full amount of the increased costs cannot be made at this time.

With the issuance of the three orders, the NRC also provided members of the public an opportunity to request a hearing.  Two established anti-nuclear groups, Pilgrim Watch and Beyond Nuclear, filed hearing requests, focused on Pilgrim, regarding two of the three orders.  These requests sought to have the NRC impose expanded remedial requirements to address the issues raised by the NRC’s orders.  Beyond Nuclear subsequently withdrew its hearing request and the NRC’s ASLB denied Pilgrim Watch’s hearing request.  Pilgrim Watch appealed the Board’s decision to the NRC, which affirmed the Board’s decision in January 2013.

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

36

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

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 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 2012 the NRC directed its staff to develop a revised Waste Confidence Decision within 24 months. In September 2013 the NRC published a draft of the revised Waste Confidence rule and supporting draft environmental impact statement for public comment. The NRC's current schedule calls for publication of a final rule and environmental impact statement no later than October 2014 with the effective date 30 days after publication.

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 which 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.

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 18%. The timing assumption influences the effect of a

37

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


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 damages 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 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 a current credit-adjusted risk-free rate. Decreases in estimated cash flows are discounted using the previously-used credit-adjusted risk-free rate. Therefore, to the extent that one of the factors noted above results in a significant increase in estimated cash flows, current interest rates will affect the calculation of the present value of the additional 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 increase net income 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 also result in an increase in the asset retirement cost asset, which is then depreciated over the asset’s remaining economic life. For 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 decrease net income.

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 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.


38

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

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, 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 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 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 $48.9 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.

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.

In the fourth quarter of 2011, Entergy Wholesale Commodities recorded a reduction of $34.1 million in the decommissioning cost liability for a plant as a result of a revised decommissioning cost study obtained to comply with a state regulatory requirement.  The revised cost study resulted in a change in the undiscounted cash flows and a credit to decommissioning expense of $34.1 million, reflecting the excess of the reduction in the liability over the amount of undepreciated assets.

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 impairments 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 conditions arise, if a unit plans to cease, or ceases, operation sooner than expected, or for certain nuclear units if their operating licenses are not renewed.


39

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


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 such cash flows are less than the carrying 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 impacted by factors unique to those assets.
Future operating costs - Entergy assumes relatively minor annual increases in operating costs.  Technological or regulatory changes that have a significant effect on operations could cause a significant change in these assumptions.
Timing - 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 planned 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 2013, 2012, or 2011.  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 2013, 2012, or 2011 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.  


40

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

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 employees hired or rehired after June 30, 2014 and setting a dollar limit cap on Entergy's contribution to retiree medical costs, effective 2019, for those employees who commence their Entergy retirement benefits on or after January 1, 2015. 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 will be 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.

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 2011 actuarial study reviewed plan experience from 2007 through 2010.  As a result of the 2011 actuarial study, changes were made to reflect the expectation that participants have longer life expectancies and different retirement patterns than previously assumed.  These changes are reflected in the December 31, 2013, December 31, 2012 and December 31, 2011 financial disclosures.

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 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 rates used to calculate its 2011 qualified pension benefit obligation and 2012 qualified pension cost ranged from 5.1% to 5.2% for its specific pension plans (5.1% combined rate for all pension plans).   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

41

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


4.36%.  The discount rate used to calculate its 2011 other postretirement benefit obligation and 2012 other postretirement benefit cost was 5.1%.

Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates.  Based on this review, 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 the December 31, 2012 accumulated postretirement benefit obligation and 2013 postretirement cost was 7.50% for pre-65 retirees and 7.25% 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 health care cost trend rate assumption used in measuring the December 31, 2011 accumulated postretirement benefit obligation and 2012 postretirement cost was 7.75% for pre-65 retirees and 7.5% for post-65 retirees for 2012, 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 2013 and 2012 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 2013, 2012 and 2011 qualified pension costs was 8.5% and will be 8.5% for 2014.  Entergy’s expected long term rate of return on non-taxable other postretirement assets used to calculate other postretirement costs was 8.5% for 2013, 2012, and 2011, and will be 8.3% for 2014.  For Entergy’s taxable postretirement assets, the expected long term rate of return was 6.5% for 2013 and 2012, 5.5% for 2011, and will be 6.5% in 2014.

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.


42

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

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 2013
Qualified Pension
Cost
 
Impact on 2013
Qualified Projected
Benefit Obligation
 
 
Increase/(Decrease)
Discount rate
 
(0.25%)
 
$22,778
 
$197,359
Rate of return on plan assets
 
(0.25%)
 
$9,614
 
$—
Rate of increase in compensation
 
0.25%
 
$9,499
 
$36,817

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 2013
Postretirement Benefit Cost
 
Impact on 2013 Accumulated
Postretirement Benefit Obligation
 
 
Increase/(Decrease)
Discount rate
 
(0.25%)
 
$4,711
 
$47,611
Health care cost trend
 
0.25%
 
$8,382
 
$41,553

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.  Refer to 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 2013, Entergy’s total qualified pension cost was $352 million, including a $16.3 million curtailment charge and a $13.1 million special termination charge related to workforce downsizing.  Entergy anticipates 2014 qualified pension cost to be $215.7 million.  Entergy's pension funding was approximately $163 million for 2013.  Entergy’s contributions to the pension trust are currently estimated to be approximately $400 million in 2014, although the required pension contributions will not be known with more certainty until the January 1, 2014 valuations are completed by April 1, 2014. The expected increase in pension contributions is primarily due to the phase out of pension funding relief under the Moving Ahead for Progress in the 21st Century Act (MAP-21).


43

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


Minimum required funding calculations as determined under Pension Protection Act guidance are performed annually as of January 1 of each year and are based on measurements of the assets and funding liabilities as measured at that date.  Any excess of the funding liability over the calculated fair market value of assets results in a funding shortfall that, under the Pension Protection Act, must be funded over a seven-year rolling period.  The Pension Protection Act also imposes certain plan limitations if the funded percentage, which is based on a 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.

MAP-21 became federal law on July 6, 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 requirements for single employer defined benefit plans in response to the historically low interest rates that existed when the law was enacted.  The law does not reduce contribution requirements over the long term, and it is likely that Entergy’s