10-K 1 a10-k.htm a10-k.htm


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, 2012
 
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



 
 

 

 
 
 
 

 

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 – 178,092,521
  shares outstanding at January 31, 2013
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.
     
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.
     
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
Ö
   
Entergy Arkansas, Inc.
   
Ö
Entergy Gulf States Louisiana, L.L.C.
   
Ö
Entergy Louisiana, LLC
Ö
   
Entergy Mississippi, Inc.
   
Ö
Entergy New Orleans, Inc.
   
Ö
Entergy Texas, Inc.
   
Ö
System Energy Resources, Inc.
   
Ö



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
   
Ö
Entergy Arkansas, Inc.
   
Ö
Entergy Gulf States Louisiana, L.L.C.
   
Ö
Entergy Louisiana, LLC
   
Ö
Entergy Mississippi, Inc.
   
Ö
Entergy New Orleans, Inc.
   
Ö
Entergy Texas, Inc.
   
Ö
System Energy Resources, Inc.
   
Ö

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.  [Ö]

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
Ö
           
Entergy Arkansas, Inc.
       
Ö
   
Entergy Gulf States Louisiana, L.L.C.
       
Ö
   
Entergy Louisiana, LLC
       
Ö
   
Entergy Mississippi, Inc.
       
Ö
   
Entergy New Orleans, Inc.
       
Ö
   
Entergy Texas, Inc.
       
Ö
   
System Energy Resources, Inc.
       
Ö
   

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.



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 2012, was $12.0 billion based on the reported last sale price of $67.89 per share for such stock on the New York Stock Exchange on June 29, 2012.  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 3, 2013, are incorporated by reference into Part III hereof.




























(Page left blank intentionally)









 
SEC Form 10-K
Reference Number
Page
Number
     
 
iv
 
vii
   
Part II. Item 7.
1
Part II. Item 6.
48
 
49
Part II. Item 8.
50
Part II. Item 8.
51
Part II. Item 8.
52
Part II. Item 8.
54
Part II. Item 8.
56
Part II. Item 8.
57
Part I. Item 1.
205
Part I. Item 1.
205
Part I. Item 1.
224
Part I. Item 1.
229
 
244
 
246
 
246
Part I. Item 1A.
247
Unresolved Staff Comments
Part I. Item 1B.
None
Entergy Arkansas, Inc. and Subsidiaries
   
Part II. Item 7.
269
 
283
Part II. Item 8.
284
Part II. Item 8.
285
Part II. Item 8.
286
Part II. Item 8.
288
Part II. Item 6.
289
Entergy Gulf States Louisiana, L.L.C.
   
Part II. Item 7.
290
 
308
Part II. Item 8.
309
Part II. Item 8.
310
Part II. Item 8.
311
Part II. Item 8.
312



Part II. Item 8.
314
Part II. Item 6.
315
Entergy Louisiana, LLC and Subsidiaries
   
Part II. Item 7.
316
 
334
Part II. Item 8.
335
Part II. Item 8.
336
Part II. Item 8.
337
Part II. Item 8.
338
Part II. Item 8.
340
Part II. Item 6.
341
Entergy Mississippi, Inc.
   
Part II. Item 7.
342
 
353
Part II. Item 8.
354
Part II. Item 8.
355
Part II. Item 8.
356
Part II. Item 8.
358
Part II. Item 6.
359
Entergy New Orleans, Inc.
   
Part II. Item 7.
360
 
371
Part II. Item 8.
372
Part II. Item 8.
373
Part II. Item 8.
374
Part II. Item 8.
376
Part II. Item 6.
377
Entergy Texas, Inc. and Subsidiaries
   
Part II. Item 7.
378
 
389
Part II. Item 8.
390
Part II. Item 8.
391
Part II. Item 8.
392
Part II. Item 8.
394
Part II. Item 6.
395
System Energy Resources, Inc.
   
Part II. Item 7.
396
 
403
 
 
Part II. Item 8.
404
Part II. Item 8.
405
Part II. Item 8.
406
Part II. Item 8.
408
Part II. Item 6.
409
Part I. Item 2.
410
Part I. Item 3.
410
Part I. Item 4.
410
Part I. and Part III.
Item 10.
410
Part II. Item 5.
412
Part II. Item 6.
414
Part II. Item 7.
414
Part II. Item 7A.
414
Part II. Item 8.
414
Part II. Item 9.
414
Part II. Item 9A.
414
Part II. Item 9A.
416
Part III. Item 10.
424
Part III. Item 11.
429
Part III. Item 12.
494
Part III. Item 13.
497
Part III. Item 14.
499
Part IV. Item 15.
502
 
503
 
511
 
513
 
S-1
 
E-1

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.



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 those factors discussed or incorporated by reference in (a) Item 1A. Risk Factors, (b) 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 and Entergy Mississippi’s participation in the System Agreement in December 2013 and November 2015, respectively;
·  
regulatory and operating challenges and uncertainties associated with the Utility operating companies’ proposal to move to the MISO RTO;
·  
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 possible shutdown of nuclear generating facilities, particularly those 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;


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 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;
·  
risks associated with the proposed spin-off and subsequent merger of Entergy’s electric transmission business into a subsidiary of ITC Holdings Corp., including the risk that Entergy and the Utility operating companies may not be able to timely satisfy the conditions or obtain the approvals required to complete such transaction or such approvals may contain material restrictions or conditions, and the risk that if completed, the transaction may not achieve its anticipated results;
·  
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;
·  
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;
·  
advances in technology;
·  
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 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.



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-Koch
A joint venture equally owned by subsidiaries of Entergy and Koch Industries, Inc.  Entergy-Koch’s pipeline and trading businesses were sold in 2004.
 
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
 
firm LD
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, the defaulting party must compensate the other party as specified in the contract
 
FitzPatrick
James A. FitzPatrick Nuclear Power Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
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
 


DEFINITIONS (Continued)

Abbreviation or Acronym
Term
   
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
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
Midwest Independent Transmission 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.


DEFINITIONS (Concluded)

Abbreviation or Acronym
Term
   
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
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



 


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.  As discussed in more detail in “Plan to Spin Off the Utility’s Transmission Business,” in December 2011, Entergy entered into an agreement to spin off its transmission business and merge it with a newly-formed subsidiary of ITC Holdings Corp.
·  
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.  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.

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
 
2012
 
2011
 
2010
 
2012
 
2011
 
2010
 
2012
 
2011
 
2010
                                     
Utility
 
78
 
79
 
78
 
110 
 
82 
 
65 
 
82 
 
80 
 
80 
Entergy Wholesale Commodities
 
22
 
21
 
22
 
 
36 
 
36 
 
22 
 
24 
 
26 
Parent & Other
 
-
 
  -
 
-
 
(15)
 
(18)
 
(1)
 
(4)
 
(4)
 
(6)

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.  Total restoration costs for the repair and/or replacement of Entergy's electric facilities in areas with damage from Hurricane Isaac are currently estimated to be approximately $370 million, including approximate amounts of $7 million at Entergy Arkansas, $70 million at Entergy Gulf States Louisiana, $220 million at Entergy Louisiana, $22 million at Entergy Mississippi, and $48 million at Entergy New Orleans.

The Utility operating companies are considering all reasonable avenues to recover storm-related costs from Hurricane Isaac, including, but not limited to, accessing funded storm reserves; securitization or other alternative financing; and traditional retail recovery on an interim and permanent basis.  Each Utility operating company is responsible for its restoration cost obligations and for recovering or financing its storm-related costs.  In November 2012, Entergy New Orleans drew $10 million from its funded storm reserves.  In January 2013, Entergy Gulf States Louisiana and Entergy Louisiana drew $65 million and $187 million, respectively, from their funded storm reserves.  Storm cost recovery or financing may be subject to review by applicable regulatory authorities.

Entergy recorded accruals for the estimated costs incurred that were necessary to return customers to service.  Entergy recorded corresponding regulatory assets of approximately $120 million and construction work in progress of approximately $250 million.  Entergy recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service areas because management believes that recovery through some form of regulatory mechanism is probable.  Because Entergy has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.

 
1

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


Results of Operations

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.

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.


 
2

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


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
·  
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.
 
 
3

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


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 are sharing 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 and savings obligation.

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.

Following are key performance measures for Entergy Wholesale Commodities for 2012 and 2011.

   
2012
 
2011
         
Owned capacity
 
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
 
 
4

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis



Realized Revenue per MWh for Entergy Wholesale Commodities Nuclear Plants

The recent economic downturn and negative trends in the energy commodity markets have resulted in lower natural gas prices and 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’ nuclear business experienced a decrease in realized price per MWh to $50.29 in 2012 from $54.73 in 2011 and $59.16 in 2010, and is likely to experience a decrease again in 2013 because, as shown in the contracted sale of energy table in “Market and Credit Risk Sensitive Instruments,” Entergy Wholesale Commodities has sold forward 85% of its planned nuclear energy output for 2013 for an expected average contracted energy price of $46 per MWh based on market prices at December 31, 2012.  In addition, Entergy Wholesale Commodities has sold forward 73% of its planned nuclear energy output for 2014 for an expected average contracted energy price of $45 per MWh based on market prices at December 31, 2012.  Near-term prices 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 impairment charges, increased depreciation rates, transitional costs, or accelerated decommissioning costs.  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 $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 planned spin-off and merger of 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.
 
 
5

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


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;
·  
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 planned spin-off and merger of 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 expense 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 is challenging 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 November 2012, Entergy appealed the District Court’s decision to the Second Circuit Court of Appeals, where the suit remains pending.
 
 
 
6

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

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 is related to (1) an IRS settlement of the tax treatment of the Louisiana Act 55 financing of the Hurricane Katrina and Hurricane Rita storm costs and the reversal of the provision for the uncertain tax position related to that item as discussed further in Note 3 to the financial statements; (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; and (3) an IRS Settlement on nuclear power plant decommissioning liabilities resulting in an earnings benefit of approximately $155 million, as discussed further in Note 3 to the financial statements.

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.

See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rates, and for additional discussion regarding income taxes.
 
 
7

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


2011 Compared to 2010

Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2011 to 2010 showing how much the line item increased or (decreased) in comparison to the prior period.

   
 
Utility
   
Entergy
Wholesale
Commodities
   
Parent &
Other
   
 
Entergy
 
   
(In Thousands)
 
                         
2010 Consolidated Net Income (Loss)
  $ 829,719     $ 450,104     $ (9,518 )   $ 1,270,305  
                                 
Net revenue (operating revenue less fuel expense,
purchased power, and other regulatory
charges/credits)
    (146,947 )     (155,898 )       3,620       (299,225 )
Other operation and maintenance expenses
    1,674       (141,672 )     38,354       (101,644 )
Taxes other than income taxes
    248       1,079       400       1,727  
Depreciation and amortization
    16,326       16,008       (26 )     32,308  
Gain on sale of business
    -       (44,173 )     -       (44,173 )
Other income
    (3,388 )     (47,257 )     9,339       (41,306 )
Interest expense
    (37,502 )     (69,661 )     45,623       (61,540 )
Other expenses
    1,688       (23,335 )     1       (21,646 )
Income taxes
    (426,916 )     (71,489 )     167,429       (330,976 )
                                 
2011 Consolidated Net Income (Loss)
  $ 1,123,866     $ 491,846     $ (248,340 )   $ 1,367,372  
 
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.

Net income for Utility in 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 a portion of the benefits will be shared 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 2011 to 2010.

  
 
Amount
 
  
 
(In Millions)
 
       
2010 net revenue
  $ 5,051  
Mark-to-market tax settlement sharing
    (196 )
Purchased power capacity
    (21 )
Net wholesale revenue
    (14 )
Volume/weather
    13  
ANO decommissioning trust
    24  
Retail electric price
    49  
Other
    (2 )
2011 net revenue
  $ 4,904  
 
 
8

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis



The mark-to-market tax settlement sharing variance results from a regulatory charge because a portion of the benefits of a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts will be shared with customers, slightly offset by the amortization of a portion of that charge beginning in October 2011.  See Notes 3 and 8 to the financial statements for additional discussion of the tax settlement and benefit sharing.

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

The net wholesale revenue variance is primarily due to lower margins on co-owner contracts and higher wholesale energy costs.

The volume/weather variance is primarily due to an increase of 2,061 GWh in weather-adjusted usage across all sectors.  Weather-adjusted residential retail sales growth reflected an increase in the number of customers.  Industrial sales growth has continued since the beginning of 2010.  Entergy’s service territory has benefited from the national manufacturing economy and exports, as well as industrial facility expansions.  Increases have been offset to some extent by declines in the paper, wood products, and pipeline segments.  The increase was also partially offset by the effect of less favorable weather on residential sales.

The ANO decommissioning trust variance is primarily related to the deferral of investment gains from the ANO 1 and 2 decommissioning trust in 2010 in accordance with regulatory treatment.  The gains resulted in an increase in interest and investment income in 2010 and a corresponding increase in regulatory charges with no effect on net income.
 
The retail electric price variance is primarily due to:

·  
rate actions at Entergy Texas, including a base rate increase effective August 2010 and an additional increase beginning May 2011;
·  
a formula rate plan increase at Entergy Louisiana effective May 2011; and
·  
a base rate increase at Entergy Arkansas effective July 2010.

These were partially offset by formula rate plan decreases at Entergy New Orleans effective October 2010 and October 2011.  See Note 2 to the financial statements for further discussion of these proceedings.

Entergy Wholesale Commodities

Following is an analysis of the change in net revenue comparing 2011 to 2010.

  
 
Amount
 
  
 
(In Millions)
 
       
2010 net revenue
  $ 2,200  
Nuclear realized price changes
    (159 )
Fuel expenses
    (30 )
Harrison County
    (27 )
Nuclear volume
    61  
2011 net revenue
  $ 2,045  

As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by $155 million, or 7%, in 2011 compared to 2010 primarily due to:

·  
lower pricing in its contracts to sell power;
·  
higher fuel expenses, primarily at the nuclear plants; and
·  
the absence of the Harrison County plant, which was sold in December 2010.
 
 
 
9

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


These factors were partially offset by higher volume resulting from fewer planned and unplanned outage days in 2011 compared to the same period in 2010.

Following are key performance measures for Entergy Wholesale Commodities for 2011 and 2010:

   
2011
 
2010
         
Owned capacity
 
6,599
 
6,351
GWh billed
 
43,497
 
42,934
Average realized price per MWh
 
$54.50
 
$58.69
         
Entergy Wholesale Commodities Nuclear Fleet
Capacity factor
 
93%
 
90%
GWh billed
 
40,918
 
39,655
Average realized revenue per MWh
 
$54.73
 
$59.16
Refueling Outage Days:
       
FitzPatrick
 
-
 
35
Indian Point 2
 
-
 
33
Indian Point 3
 
30
 
-
Palisades
 
-
 
26
Pilgrim
 
25
 
-
Vermont Yankee
 
25
 
29
 
Other Income Statement Items

Utility

Other operation and maintenance expenses increased from $1,949 million for 2010 to $1,951 million for 2011 primarily due to:

·  
an increase of $17 million in nuclear expenses primarily due to higher labor costs, including higher contract labor;
·  
an increase of $15 million in contract costs due to the transition and implementation of joining the MISO RTO;
·  
an increase of $9 million in legal expenses primarily resulting from an increase in legal and regulatory activity increasing the use of outside legal services;
·  
an increase of $8 million in fossil-fueled generation expenses primarily due to the addition of Acadia Unit 2 in April 2011; and
·  
several individually insignificant items.

These increases were substantially offset by:

·  
a decrease of $29 million in compensation and benefits costs primarily resulting from an increase in the accrual for incentive-based compensation in 2010 and a decrease in stock option expense.  The decrease in stock option expense is offset by credits recorded by the parent company, Entergy Corporation;
·  
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 2010 test year formula rate plan filing and settlement;
·  
the amortization of $11 million of Entergy Texas rate case expenses in 2010.  See Note 2 to the financial statements for further discussion of the Entergy Texas rate case settlement; and
·  
a decrease of $10 million in operating expenses due to the sale of surplus oil inventory in 2011.
 
 
 
10

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


Depreciation and amortization expense increased primarily due to an increase in plant in service, partially offset by a decrease in depreciation rates at Entergy Arkansas as a result of the rate case settlement agreement approved by the APSC in June 2010.

Interest expense decreased primarily due to:

·  
the refinancing of long-term debt at lower interest rates by certain of the Utility operating companies;
·  
a revision caused by FERC’s acceptance of a change in the treatment of funds received from independent power producers for transmission interconnection projects; and
·  
interest expense accrued in 2010 related to the expected result of the LPSC Staff audit of Entergy Gulf States Louisiana’s fuel adjustment clause for the period 1995 through 2004.

Entergy Wholesale Commodities

Other operation and maintenance expenses decreased from $1,047 million for 2010 to $906 million for 2011 primarily due to:

·  
the write-off of $64 million of capital costs in 2010, primarily for software that would not be utilized, and $16 million of additional costs incurred in 2010 in connection with Entergy’s decision to unwind the infrastructure created for the planned spin-off of its non-utility nuclear business;
·  
a decrease of $30 million due to the absence of expenses from the Harrison County plant, which was sold in December 2010;
·  
a decrease in compensation and benefits costs resulting from an increase of $19 million in the accrual for incentive-based compensation in 2010;
·  
a decrease of $12 million in spending on tritium remediation work; and
·  
the write-off of $10 million of capitalized engineering costs in 2010 associated with a potential uprate project.

The gain on sale resulted from the sale in 2010 of Entergy’s ownership interest in the Harrison County Power Project 550 MW combined-cycle plant to two Texas electric cooperatives that owned a minority share of the plant.  Entergy sold its 61 percent share of the plant for $219 million and realized a pre-tax gain of $44.2 million on the sale.

Depreciation and amortization expense increased primarily due to an increase in plant in service and declining useful life of nuclear assets.

Other income decreased primarily due to a decrease in interest income earned on loans to the parent company, Entergy Corporation, and a decrease of $13 million in realized earnings on decommissioning trust fund investments.

Interest expense decreased primarily due to the write-off of $39 million of debt financing costs in 2010, primarily incurred for a $1.2 billion credit facility that will not be used, in connection with Entergy’s decision to unwind the infrastructure created for the planned spin-off of its non-utility nuclear business.

Other expenses decreased primarily due to a credit to decommissioning expense of $34 million in 2011 resulting from a reduction in the decommissioning liability for a plant as a result of a revised decommissioning cost study obtained to comply with a state regulatory requirement.  See “Critical Accounting Estimates – Nuclear Decommissioning Costs” below for further discussion of accounting for asset retirement obligations.
 
 
 
11

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


Parent & Other

Other operation and maintenance expenses increased primarily due to lower intercompany stock option credits recorded by the parent company, Entergy Corporation, and an increase of $13 million related to the planned spin-off and merger of Entergy’s transmission business.  See “Plan to Spin Off  the Utility’s Transmission Business” below for further discussion.

Interest expense increased primarily due to $1 billion of Entergy Corporation senior notes issued in September 2010, with the proceeds used to pay down borrowings outstanding on Entergy Corporation’s revolving credit facility that were at a lower interest rate.

Income Taxes

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.

The effective income tax rate for 2010 was 32.7%.  The difference in the effective income tax rate versus the statutory rate of 35% in 2010 was primarily due to:

·  
a favorable U.S. Tax Court decision holding that the U.K. Windfall Tax may be used as a credit for purposes of computing the U.S. foreign tax credit, which allowed Entergy to reverse a provision for uncertain tax positions of $43 million, included in Parent and Other, on the issue.  See Note 3 to the financial statements for further discussion of this tax litigation;
·  
a $19 million tax benefit recorded in connection with Entergy’s decision to unwind the infrastructure created for the planned spin-off of its non-utility nuclear business; and
·  
the recognition of a $14 million Louisiana state income tax benefit related to storm cost financing.

Partially offsetting the decreased effective income tax rate was a charge of $16 million resulting from a change in tax law associated with the recently enacted federal healthcare legislation, as discussed below in “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” and state income taxes and certain book and tax differences for Utility plant items.

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.

Plan to Spin Off the Utility’s Transmission Business

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).  In order to effect the spin-off and merger, Entergy entered into (i) a Merger Agreement with Mid South TransCo LLC, a newly formed, wholly-owned subsidiary of Entergy (TransCo); ITC; and ITC Midsouth LLC (formerly known as Ibis Transaction Subsidiary LLC) (Merger Sub), a newly formed, wholly-owned subsidiary of ITC; and (ii) a Separation Agreement with TransCo, ITC, each of the Utility operating companies, and Entergy Services, Inc.  These agreements, which have been approved by the Boards of Directors of Entergy and ITC, provide for the separation of Entergy’s transmission business (the Transmission Business), the distribution to Entergy’s stockholders of all of the common units, excluding any common units to be contributed to an exchange trust in the event Entergy makes the exchange trust election described below, of TransCo, a holding company subsidiary formed to hold the Transmission Business, and the merger of Merger Sub with and into TransCo, with TransCo continuing as the surviving entity in the Merger (the Merger), following which each common unit of TransCo will be converted into the right to receive one fully paid and nonassessable share of ITC common stock.  Both the Distribution (as defined below) and the Merger are expected to qualify as tax-free transactions.
 
 
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Management's Financial Discussion and Analysis



Pursuant to the Merger Agreement, and subject to the terms and conditions set forth therein, Entergy will distribute the TransCo common units to its shareholders, excluding any TransCo common units to be contributed to an exchange trust in the event Entergy makes the exchange trust election described below.  At Entergy’s election, it may distribute the TransCo common units by means of a pro rata dividend in a spin-off or pursuant to an exchange offer in a split-off, or a combination of a spin-off and a split-off (the Distribution).  In connection with the Merger, ITC will effectuate a $700 million recapitalization, which will take the form of a one-time special dividend to its shareholders of record as of a record date prior to the Merger (the Special Dividend), a share repurchase or a combination thereof.  The decision regarding the form of the recapitalization will be determined by the board of directors of ITC at a later date closer to the Merger.  Entergy’s shareholders who become shareholders of ITC as a result of the Merger will not receive the Special Dividend.  Pursuant to the Merger Agreement, and subject to the terms and conditions set forth therein, immediately after the consummation of the Separation (as defined below), the consummation of the Financings (as defined below), the payment of the Special Dividend and the consummation of the Distribution, Merger Sub will merge with and into TransCo, with TransCo continuing as the surviving entity, and Entergy shareholders who hold common units of TransCo will have those units exchanged for ITC common stock on a one-for-one basis.  Consummation of the transactions contemplated by the Separation Agreement and the Merger Agreement is expected to result in Entergy’s shareholders, together with the exchange trust described below if it is utilized, holding at least 50.1% of ITC’s common stock and existing ITC shareholders holding no more than 49.9% of ITC’s common stock immediately after the Merger.

Pursuant to the Merger Agreement, Entergy may elect to retain up to the number of TransCo common units that would convert in the Merger into up to 4.9999% of the total number of shares of ITC common stock outstanding on a fully diluted basis immediately following the consummation of the Merger that otherwise would have been distributed in the Distribution (the Exchange Trust Election).  If Entergy makes the Exchange Trust Election, Entergy will transfer the retained TransCo common units to an irrevocable trust (the Exchange Trust).  The TransCo common units transferred to the Exchange Trust will not be distributed to the distribution agent on behalf of Entergy shareholders in the Distribution.  At the closing of the Merger, the TransCo common units transferred to the Exchange Trust will convert to ITC common stock.  The trustee of the Exchange Trust will own and hold legal title to the TransCo common units and, following consummation of the Merger, ITC common stock for the benefit of Entergy and Entergy shareholders; provided, however, in no event will the ITC common stock held by the Exchange Trust be transferred to Entergy.  Upon delivery of notice by Entergy, the trustee of the Exchange Trust will conduct an exchange offer (the Exchange Trust Exchange Offer) pursuant to which Entergy shareholders may exchange Entergy common stock for the ITC common stock held by the Exchange Trust.  Any ITC common stock remaining in the Exchange Trust after six months following the completion of the Merger will be distributed to Entergy shareholders pro rata.  The purpose of the Exchange Trust is to permit an exchange offer with Entergy shareholders to occur during a period after the closing, when the trading market for the ITC common stock has settled following the Merger.  The Exchange Trust Exchange Offer, if elected by Entergy, is an option to help Entergy efficiently manage its post-transaction capital structure and improve cash flow and credit metrics.  Upon the consummation of a successful exchange offer by the Exchange Trust, there would be fewer outstanding shares of Entergy common stock, as those shares would have been exchanged for the shares of ITC common stock held by the Exchange Trust.  Consequently, a successful delayed exchange offer would permit Entergy to reduce its common shares outstanding and aggregate cash dividends paid and as a result could improve Entergy’s available cash flow and credit metrics.

The Merger Agreement contains certain customary representations and warranties.  The Merger Agreement may be terminated: (i) by mutual consent of Entergy and ITC, (ii) by either Entergy or ITC if the Merger has not been completed by June 30, 2013, subject to an up to six month extension by either Entergy or ITC in certain circumstances, (iii) by either Entergy or ITC if the transactions are enjoined or otherwise prohibited by applicable law, (iv) by Entergy, on the one hand, or ITC, on the other hand, upon a material breach of the Merger Agreement by the other party that has not been cured by the cure period specified in the Merger Agreement, (v) by either Entergy or ITC if ITC’s shareholders fail to approve the ITC shareholder proposals, (vi) by Entergy if the ITC Board of Directors withdraws or changes its recommendation of the ITC shareholder proposals in a manner adverse to Entergy, (vii) by Entergy if ITC willfully breaches in any material respect its non-solicitation covenant and the breach has not been cured by the cure period specified in the Merger Agreement, (viii) by Entergy if there is a law or order that enjoins the transactions or imposes a burdensome condition on Entergy, (ix) by either Entergy or ITC if there is a law or order that enjoins the transactions or imposes a
 
 
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Management's Financial Discussion and Analysis

 
burdensome condition on ITC, (x) by ITC, prior to ITC shareholder approval, to enter into a transaction for a superior proposal, provided that ITC complies with its notice and other obligations in the non-solicitation provision and pays Entergy the termination fee concurrently with termination or (xi) by ITC if Entergy takes certain actions with respect to the migration of the Transmission Business to a regional transmission organization if such actions could reasonably be expected to have certain adverse effects on TransCo or ITC after the Merger. In the event that (i) ITC terminates the Merger Agreement to accept a superior acquisition proposal, (ii) Entergy terminates the Merger Agreement because the ITC Board of Directors has withdrawn its recommendation of the ITC shareholder proposals, approves or recommends another acquisition proposal, fails to reaffirm its recommendation or materially breaches the non-solicitation provisions, (iii) either of the parties terminates the Merger Agreement because the approval of ITC’s shareholders is not obtained or (iv) Entergy terminates because of ITC’s uncured willful breach of the Merger Agreement, and in the case of clauses (iii) and (iv) an ITC takeover transaction was publicly announced and not withdrawn prior to termination and within 12 months of termination ITC agrees to or consummates a takeover transaction, then ITC must pay Entergy a $113,570,800 termination fee.

Consummation of the Merger is subject to the satisfaction of customary closing conditions for a transaction such as the Merger, including, among others, (i) consummation of the Separation, the Distribution, the Financings and the Special Dividend, (ii) the approval of the ITC shareholder proposals by the shareholders of ITC, (iii) the authorization for listing on the New York Stock Exchange of ITC common stock to be issued in the Merger, (iv) the receipt by Entergy of regulatory approvals necessary to become a member of an acceptable regional transmission organization, (v) the receipt of regulatory approvals necessary to consummate the transaction and no such regulatory approvals impose a burdensome condition on ITC or Entergy, (vi) the expiration of the applicable waiting period under the Hart-Scott-Rodino Act (which has occurred), (vii) the absence of a material adverse effect on the Transmission Business or ITC, (viii) the receipt by Entergy of a solvency opinion and (ix) the receipt of a private letter ruling from the IRS substantially to the effect that certain requirements for the tax-free treatment of the distribution of TransCo are met and an opinion that the Distribution and the Merger will be treated as tax-free reorganizations for U.S. federal income tax purposes. The Merger and the other transactions contemplated by the Merger Agreement and the Separation Agreement are planned for completion in 2013.

Pursuant to the Separation Agreement, and subject to the terms and conditions set forth therein, Entergy will engage in a series of preliminary restructuring transactions that result in the transfer to TransCo’s subsidiaries of the assets relating to the Transmission Business (the Separation).  TransCo and its subsidiaries will consummate certain financing transactions (the TransCo Financing) totaling approximately $1.775 billion (as may be adjusted pursuant to the Merger Agreement and the Separation Agreement) pursuant to which (i) TransCo’s subsidiaries will borrow through a funded bridge facility with a term of 366 days and (ii) TransCo will issue senior securities of TransCo to Entergy (the TransCo Securities).  Neither Entergy nor the Utility operating companies will guarantee or otherwise be liable for the payment of the TransCo Securities after the Separation occurs.  Entergy will issue new debt or enter into agreements under which certain unrelated creditors will agree to purchase existing corporate debt of Entergy, which will be exchangeable into the TransCo Securities at closing (the Exchangeable Debt Financing).  Entergy intends to contribute some or all of the proceeds from the new debt to the Utility operating companies.  In addition, prior to the closing TransCo and/or the TransCo subsidiaries may obtain a working capital revolving credit facility in a principal amount agreed to by Entergy and ITC (such financing, together with the TransCo Financing and the Exchangeable Debt Financing, the Financings).

Under the terms of the Separation Agreement, immediately prior to the closing, each Utility operating company will contribute its respective transmission assets to a subsidiary that will become a TransCo subsidiary in the Separation in exchange for the equity interest in that subsidiary and the net proceeds received by that subsidiary from the funded bridge facility described above.  Each Utility operating company will distribute the equity interests in the subsidiaries holding the transmission assets to Entergy, which will then contribute such interests to TransCo.  The Utility operating companies intend to apply all of the amounts received by them from the subsidiaries and from Entergy to the prepayment or redemption of outstanding preferred and debt securities, with
 
 
14

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


 
the goal, following completion of the Separation, of maintaining their capitalization generally consistent with their capitalization prior to the Separation.  Although the aggregate amount and particular series of preferred and debt securities of each Utility operating company to be redeemed as well as the redemption dates are uncertain at this time and are expected to remain subject to change, each Utility operating company currently anticipates that all of its outstanding preferred securities, if any are outstanding, will be redeemed or otherwise retired prior to the Separation and that debt securities in the following approximate aggregate amounts will be redeemed prior to or following the Separation: $.45 billion for Entergy Arkansas, $.25 billion for Entergy Gulf States Louisiana, $.33 billion for Entergy Louisiana, $.24 billion for Entergy Mississippi, $2.5 million for Entergy New Orleans, and $.28 billion for Entergy Texas.  Entergy and the Utility operating companies may, subject to certain conditions, modify or supplement the manner in which the Separation is consummated.  As of December 31, 2012, net transmission plant in service, which does not include transmission-related construction work in progress or general or intangible plant, for the Utility operating companies was $1.03 billion for Entergy Arkansas, $.57 billion for Entergy Gulf States Louisiana, $.73 billion for Entergy Louisiana, $.58 billion for Entergy Mississippi, $.03 billion for Entergy New Orleans, and $.64 billion for Entergy Texas.  Consummation of the Separation is subject to the satisfaction of the conditions applicable to Entergy and ITC contained in the Separation Agreement and the Merger Agreement, including that the sum of the principal amount of TransCo Securities issued to Entergy and the principal amount of the bridge facility entered into by TransCo’s subsidiaries is approximately $1.775 billion, subject to adjustment pursuant to the Merger Agreement and the Separation Agreement.

Filings with Retail Regulators

In conjunction with ITC, each of the Utility operating companies has filed applications with their respective retail regulators seeking approval for the proposal to spin off and merge the Transmission Business with ITC, including approval for change of control of the transmission assets and transaction-related steps in the spin-off and merger.  An application was filed with the LPSC on September 5, 2012, with the City Council on September 12, 2012, with the APSC on September 28, 2012, with the MPSC on October 5, 2012, and with the PUCT on February 19, 2013.  Also, on February 22, 2013, Entergy Texas filed with the PUCT its transmission cost recovery rider application seeking to recover its 2014 ITC transmission charges and MISO administrative costs.   Entergy Arkansas and ITC also filed a joint application with the Missouri Public Service Commission on February 14, 2013 to obtain approval for the transfer of limited transmission facilities located in Missouri.

The ALJ in the LPSC proceeding has established a procedural schedule with staff testimony due March 14, 2013 and a hearing set to commence on June 24, 2013.  LPSC consideration is anticipated in September 2013.  The City Council has established a procedural schedule with a hearing scheduled to commence on July 23, 2013, with certification of the record to the City Council no later than August 6, 2013.  The APSC established a procedural schedule with staff testimony due in April 2013 and a hearing commencing in July 2013.  The MPSC has established a procedural schedule with staff testimony due in June 2013, a hearing commencing in August 2013, and a final order issued on or before September 15, 2013.  The PUCT is required to issue an order within 180 days of Entergy Texas’s filing.

Filings with the FERC

On September 24, 2012, Entergy, ITC, and certain of their subsidiaries submitted a series of filings with the FERC to obtain regulatory approvals related to the proposed transfer to ITC subsidiaries of the transmission assets owned by the Utility operating companies.  These filings include a joint application for authorization of the acquisition and disposition of jurisdictional transmission facilities, approval of transmission service formula rates and certain jurisdictional agreements, and a petition for declaratory order on the application of Federal Power Act section 305(a).  The application seeks approval under Federal Power Act section 205 of formula rates under Attachment O of the MISO Tariff for each of the new ITC Operating Companies (which will become Transmission Owner members of MISO) and of related jurisdictional pro forma agreements.  In a separate filing, MISO sought approval of an amendment to the MISO Tariff pursuant to Federal Power Act section 205 to enable the integration of the new ITC Operating Companies’ transmission facilities into MISO prior to the Utility operating companies becoming market participants in MISO.  On September 26, 2012, Entergy Services submitted an application under Federal Power Act section 205 requesting FERC authorization to cancel System Agreement Service Schedule MSS-2 (Transmission Equalization) effective upon closing of the transaction.  In October 2012, Entergy, ITC, and certain subsidiaries submitted filings with the FERC to obtain regulatory approvals under Federal Power Act section 204 for the various financings being undertaken as part of the transaction.

 
 
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Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


Various parties have submitted comments and protests to the FERC regarding these filings.  The comments filed at the FERC include various matters related to the proposed transaction itself, including concerns about hold harmless commitments, whether the benefits of the transaction outweigh rate effects, and whether the transaction is consistent with the public interest, as well as issues related to the Utility operating companies’ proposal to join MISO.  Commenters have also challenged, among other things, aspects of the transmission rates proposed by the ITC applicants, including for example the proposed return on common equity, debt/equity ratio, and the number of transmission pricing zones.  Entergy and ITC are in the process of responding to the comments and protests filed as of a January 22, 2013 comment deadline established by the FERC.  FERC rules call for a decision 180 days from the date of a completed application provided that the matter is not set for hearing or is not otherwise extended for up to an additional 180 days.  If a matter is set for hearing, a procedural schedule will be established.

Other Filings

In July 2012, Entergy Corporation submitted a request to the Internal Revenue Service seeking a private letter ruling substantially to the effect that certain requirements for the tax-free treatment of the distribution of the transmission business are met.  In September 2012, Entergy submitted an application to the NRC for approval of certain nuclear plant license transfers and amendments as part of the steps to complete the spin-off and merger.  In December 2012, Entergy submitted a pre-merger notification under the Hart-Scott-Rodino Act (HSR Act) with the Federal Trade Commission and the Department of Justice and the applicable waiting period under the HSR Act has expired.

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 continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements.  In the Vermont Yankee license renewal case, the Vermont Department of Public Service and the New England Coalition appealed the NRC’s renewal of Vermont Yankee’s license to the D.C. Circuit.  In June 2012 the D.C. Circuit denied that appeal.  The time for seeking further judicial review of the NRC’s issuance of Vermont Yankee’s renewed operating license has expired.  In the Pilgrim license renewal case, three contentions remained pending before the ASLB at the time the license was issued.  Two of those contentions were subsequently denied by the ASLB and not appealed within the applicable time.  A third remaining contention (alleging failure of the Pilgrim Environmental Impact Statement to address adequately an endangered species) was denied by the ASLB and then appealed to the NRC, which denied the appeal on December 6, 2012.  No appeal of the NRC’s decision was filed within the time allowed for such appeals.  The NRC has indicated that should the appeal of a contention result in voiding of the renewed license, Pilgrim could operate under the “timely renewal” doctrine in reliance on the prior, and now superseded, license until proceedings concerning the renewed license are final.  Massachusetts appealed the NRC’s renewal of Pilgrim’s license to the United States Court of Appeals for the First Circuit.  Entergy intervened in that appeal.  Briefing was completed and oral argument was held December 5, 2012.  On February 25, 2013, the United States Court of Appeals for the First Circuit denied Massachusetts’s appeal.

The NRC operating licenses for Indian Point 2 and Indian Point 3 expire in September 2013 and December 2015, respectively, and NRC license renewal applications are in process for these plants.  Under federal law, nuclear power plants may continue to operate beyond their license expiration dates while their renewal applications are pending NRC approval.  Various parties have expressed opposition to renewal of the licenses.  In April 2007, Entergy submitted the application to the NRC to renew the operating licenses for Indian Point 2 and 3 for an additional 20 years.  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 issues have been resolved, and 13 issues remain
 
 
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Management's Financial Discussion and Analysis



subject to ASLB resolution.  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.

Pursuant to ASLB scheduling orders in the Indian Point 2 and 3 license renewal proceeding, hearings on the nine contentions remaining in “Track 1” were held over 12 days in October, November, and December 2012.  Testimony on the four contentions currently in “Track 2” has not been completed.  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 application.  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 2012.  The NRC staff issued a draft supplemental FSEIS in June 2012 and has stated its intent to issue, following an opportunity for comment, another supplement to the FSEIS by April 30, 2013.  In addition, the NRC staff has stated its intent to issue a further supplement to the FSER by July 31, 2013.  These reports 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 process as permitted by the NRC’s hearing rules.  As noted in Entergy’s responses to the various intervenor filings, 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 the timing of license renewals.

The New York State Department of Environmental Conservation 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, 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, has taken longer than one year to take final action on Entergy’s application for a water quality certification and, therefore, has 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 judge 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 2013.  After the full hearing on the merits, 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.
 
 
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Management's Financial Discussion and Analysis


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).  On July 24, 2012, Entergy filed a supplement to the Indian Point license renewal application 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.  Responses to Entergy’s motion for declaratory order are due March 22, 2013.  In addition, Entergy filed with the New York State Department of State (NYSDOS) on November 7, 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.   The NYSDOS denied the motion by order dated January 9, 2013.  An appeal may be taken to state court within four months.  Finally, 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.  On January 16, 2013, NYSDOS notified Entergy that it deemed the consistency determination incomplete because it does not include the further supplement to the FSEIS that, as indicated above, is targeted for issuance by April 30, 2013.  The six-month federal deadline for state decision on a consistency determination does not begin to run until the submission is complete.

The NRC operating license for Palisades expires in 2031 and for FitzPatrick expires in 2034.

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.

   
2012
 
2011
         
Debt to capital
 
58.7% 
 
57.3% 
Effect of excluding securitization bonds
 
(1.8%)
 
(2.3%)
Debt to capital, excluding securitization bonds (1)
 
56.9% 
 
55.0% 
Effect of subtracting cash
 
(1.1%)
 
(1.5%)
Net debt to net capital, excluding securitization bonds (1)
 
55.8% 
 
53.5% 

(1)
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, 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 net debt to net capital ratio and the 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.

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, 2012.  To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2012.  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.
 
 
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Management's Financial Discussion and Analysis



Long-term debt maturities and
estimated interest payments
 
 
2013
 
 
2014
 
 
2015
 
 
2016-2017
 
 
after 2017
   
(In Millions)
                     
Utility
 
$1,194
 
$904
 
$816
 
$1,540
 
$12,186
Entergy Wholesale Commodities
 
15
 
15
 
18
 
4
 
57
Parent and Other
 
83
 
83
 
627
 
1,385
 
512
Total
 
$1,292
 
$1,002
 
$1,461
 
$2,929
 
$12,755

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 2017.  Entergy Corporation also has the ability to issue letters of credit against 50% of the total borrowing capacity of the credit facility.  The commitment fee is currently 0.275% of the 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, 2012 was 2.04% on the drawn portion of the facility.

As of December 31, 2012, amounts outstanding and capacity available under the $3.5 billion credit facility are:

 
Capacity
 
 
Borrowings
 
Letters
of Credit
 
Capacity
Available
(In Millions)
             
$3,500
 
$795
 
$8
 
$2,697

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 Corporation implemented a commercial paper program with a program limit of up to $500 million.  In November 2012, Entergy Corporation increased the limit for the commercial paper program to $1 billion.  At December 31, 2012, Entergy Corporation had $665 million of commercial paper outstanding.  The weighted-average interest rate for the year ended December 31, 2012 was 0.88%.

Capital lease obligations are a minimal part of Entergy’s overall capital structure.  Following are Entergy’s payment obligations under those leases.

 
2013
 
2014
 
2015
 
2016-2017
 
after 2017
 
 
(In Millions)
                     
Capital lease payments
$6
 
$5
 
$5
 
$9
 
$34
 

The capital leases are discussed in Note 10 to the financial statements.
 
 
19

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, 2012 as follows.

 
Company
 
 
Expiration Date
 
Amount of
Facility
 
 
Interest Rate (a)
 
Amount Drawn as
of Dec. 31, 2012
                 
Entergy Arkansas
 
April 2013
 
$20 million (b)
 
1.81%
 
-
Entergy Arkansas
 
March 2017
 
$150 million (c)
 
1.71%
 
-
Entergy Gulf States Louisiana
 
March 2017
 
$150 million (d)
 
1.71%
 
-
Entergy Louisiana
 
March 2017
 
$200 million (e)
 
1.71%
 
-
Entergy Mississippi
 
May 2013
 
$35 million (f)
 
1.96%
 
-
Entergy Mississippi
 
May 2013
 
$25 million (f)
 
1.96%
 
-
Entergy Mississippi
 
May 2013
 
$10 million (f)
 
1.96%
 
-
Entergy New Orleans
 
November 2013
 
$25 million (g)
 
1.69%
 
-
Entergy Texas
 
March 2017
 
$150 million (f)
 
1.96%
 
-

(a)
The interest rate is the weighted average interest rate as of December 31, 2012 applied, or 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, 2012, no 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, 2012, no 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, 2012, no 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)
Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable.  Entergy Mississippi is required to maintain a consolidated debt ratio of 65% or less of its total capitalization.
(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, 2012, no 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.  Pursuant to the terms of the credit agreement, securitization bonds are excluded from debt and capitalization in calculating the debt ratio.
 
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, 2012 on non-cancelable operating leases with a term over one year.

 
2013
 
2014
 
2015
 
2016-2017
 
after 2017
 
 
(In Millions)
                     
Operating lease payments
$94
 
$97
 
$80
 
$94
 
$140
 

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

 
20

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis



Summary of Contractual Obligations of Consolidated Entities

Contractual Obligations
 
2013
 
2014-2015
 
2016-2017
 
after 2017
 
Total
   
(In Millions)
                     
Long-term debt (1)
 
$1,292
 
$2,463
 
$2,929
 
$12,755
 
$19,439
Capital lease payments (2)
 
$6
 
$10
 
$9
 
$34
 
$59
Operating leases (2)
 
$94
 
$177
 
$94
 
$140
 
$505
Purchase obligations (3)
 
$1,939
 
$3,512
 
$2,609
 
$11,195
 
$19,255

(1)
Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.
(2)
Lease obligations are discussed in Note 10 to the financial statements.
(3)
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 $163.3 million to its pension plans and approximately $82.5 million to other postretirement plans in 2013, although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013.  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 $148 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.


 
21

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 2013 through 2015.

Planned construction and capital investments
 
2013
 
2014
 
2015
     
(In Millions)
               
Maintenance Capital:
           
 
Utility:
           
 
Generation
 
$133
 
$127
 
$135
 
Transmission
 
253
 
229
 
202
 
Distribution
 
504
 
494
 
489
 
Other
 
97
 
107
 
105
 
Total
 
987
 
957
 
931
 
Entergy Wholesale Commodities
 
108
 
131
 
176
     
$1,095
 
$1,088
 
$1,107
Capital Commitments:
           
 
Utility:
           
 
Generation
 
$716
 
$415
 
$392
 
Transmission
 
162
 
240
 
303
 
Distribution
 
45
 
21
 
16
 
Other
 
92
 
88
 
92
 
Total
 
1,015
 
764
 
803
 
Entergy Wholesale Commodities
 
257
 
242
 
281
     
1,272
 
1,006
 
1,084
Total
 
$2,367
 
$2,094 
 
$2,191

The planned amounts do not reflect the expected reduction in capital expenditures that would occur if the planned spin-off and merger of the transmission business with ITC Holdings occurs, and do not include material costs for capital projects that might result from the NRC post-Fukushima requirements that remain under development.

Maintenance Capital refers 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.

Capital Commitments refers to 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 reflected in this category 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 and final spending from the Waterford 3 steam generator replacement project, both of which are discussed below.
·  
Spending to support the Utility’s plan to join the MISO RTO by December 2013 along with other transmission projects.
·  
Entergy Wholesale Commodities investments associated with specific investments such as dry cask storage, nuclear license renewal, component replacement and identified repairs, and potential wedgewire screens at Indian Point.
·  
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.
 
 
22

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


The Utility’s owned generating capacity remains short of customer demand, 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 35% of the capacity and energy generated by Ninemile 6.  The 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, if one is in effect when the project is placed in service; alternatively, Entergy Gulf States Louisiana and Entergy Louisiana must file rate cases approximately 12 months prior to the expected in-service date.  Entergy New Orleans is expected to file a full rate case 12 months prior to the expected in-service date.

Waterford 3 Steam Generator Replacement Project

Entergy Louisiana planned to replace the Waterford 3 steam generators, along with the reactor vessel closure head and control element drive mechanisms, in the spring 2011.  Replacement of these components is common to pressurized water reactors throughout the nuclear industry.  In December 2010, Entergy Louisiana advised the LPSC that the replacement generators would not be completed and delivered by the manufacturer in time to install them during the spring 2011 refueling outage.  During the final steps in the manufacturing process, the manufacturer discovered separation of stainless steel cladding from the carbon steel base metal in the channel head of both replacement steam generators (RSGs), in areas beneath and adjacent to the divider plate.  As a result of this damage, the manufacturer was unable to meet the contractual delivery deadlines, and the RSGs were not installed in the spring 2011.  Waterford 3 resumed operations with the original steam generators upon completion of the spring 2011 refueling outage, which included inspection and maintenance of the original steam generators.

Entergy Louisiana worked with the RSG manufacturer to fully develop, evaluate, and implement repair options, and the RSGs were delivered in time for Waterford 3’s fall 2012 refueling outage, which began in October 2012.  During the fall 2012 refueling outage Entergy Louisiana replaced the RSGs, reactor vessel head, and control element drive mechanisms.  Those components, which together comprised the replacement project, were placed in-service in December 2012.

In June 2008, Entergy Louisiana filed with the LPSC for approval of the replacement project, including full cost recovery.  Following discovery and the filing of testimony by the LPSC staff and an intervenor, the parties entered into a stipulated settlement of the proceeding.  The LPSC unanimously approved the settlement in November 2008.  The settlement resolved the following issues: 1) the accelerated degradation of the steam generators is not the result of any imprudence on the part of Entergy Louisiana; 2)
 
 
23

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


the decision to undertake the replacement project at the then-estimated cost is in the public interest, is prudent, and would serve the public convenience and necessity; 3) the scope of the replacement project is in the public interest; 4) undertaking the replacement project at the target installation date during the 2011 refueling outage is in the public interest; and 5) the jurisdictional costs determined to be prudent in a future prudence review are eligible for cost recovery, either in an extension or renewal of the formula rate plan or in a full base rate case including necessary pro forma adjustments.

In November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s formula rate plan and provided a mechanism to begin recovering the costs of the replacement project in the first billing cycle after it is placed in service.  On December 21, 2012, Entergy Louisiana provided notice of the first year revenue requirement associated with the replacement project that would be placed into rates in the January 2013 billing cycle.  The estimated revenue requirement included the LPSC-jurisdictional share of the replacement project costs, less (i) a credit for earnings above a 10.25% return on common equity (based on the 2011 test year) for the period following the in-service date, and (ii) a credit for operation and maintenance savings expected from the RSGs.  These rates are anticipated to remain in effect until Entergy Louisiana’s rate case filed in February 2013 is resolved.  See Note 2 to the financial statements for additional discussion of the formula rate plan and rate case filings.  With completion of the replacement project, the LPSC will undertake a prudence review in connection with a filing to be made by Entergy Louisiana on or before April 30, 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs.

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 2013 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.  The prior quarterly dividend per share was $0.75.  Entergy paid $589 million in 2012, $590 million in 2011, and $604 million in 2010 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 2009 the Board granted authority for a $750 million share repurchase program which was completed in the fourth quarter 2010.  In October 2010 the Board granted authority for an additional $500 million share repurchase program.  As of December 31, 2012, $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 ($533 million as of December 31, 2012);
·  
securities issuances;
·  
bank financing under new or existing facilities or commercial paper; and
·  
sales of assets.
 
 
24

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


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, 2012, under provisions in their mortgage indentures, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively.  All debt and common and preferred equity issuances by the Registrant Subsidiaries require prior regulatory approval and their preferred equity and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements.  Entergy believes that the Registrant Subsidiaries have sufficient capacity under these tests to meet foreseeable capital needs.

The FERC has jurisdiction over securities issuances by the Utility operating companies and System Energy (except securities with maturities longer than one year issued by Entergy Arkansas and Entergy New Orleans, which are subject to the jurisdiction of the APSC and the City Council, respectively).  No regulatory approvals are necessary for Entergy Corporation to issue securities.  The current FERC-authorized short-term borrowing limits are effective through October 31, 2013.  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 July 2013.  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.

In January 2013, Entergy Arkansas arranged for the issuance by (i) Independence County, Arkansas of $45 million of 2.375% Pollution Control Revenue Refunding Bonds (Entergy Arkansas, Inc. Project) Series 2013 due January 2021, and (ii) Jefferson County, Arkansas of $54.7 million of 1.55% Pollution Control Revenue Refunding Bonds (Entergy Arkansas, Inc. Project) Series 2013 due October 2017, each of which series is secured by a separate series of non-interest bearing first mortgage bonds of Entergy Arkansas.  The proceeds of these issuances were applied to the refunding of outstanding series of pollution control revenue bonds previously issued by the respective issuers.

In February 2013 the Entergy Gulf States Louisiana nuclear fuel company variable interest entity issued $70 million of 3.38% Series R notes due August 2020.  The Entergy Gulf States nuclear fuel company variable interest entity used the proceeds principally to purchase additional nuclear fuel.
 
Hurricane Gustav and Hurricane Ike

In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to portions of Entergy's service territories in Louisiana and Texas, and to a lesser extent in Arkansas and Mississippi.  The storms resulted in widespread power outages, significant damage to distribution, transmission, and generation infrastructure, and the loss of sales during the power outages.  In September 2009, Entergy Gulf States Louisiana and Entergy Louisiana and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Act 55 financings).  In July 2010 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $468.9 million in bonds under Act 55.  From the $462.4
 
 
25

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $200 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $262.4 million directly to Entergy Louisiana.  In July 2010, the LCDA issued another $244.1 million in bonds under Act 55.  From the $240.3 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $90 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $150.3 million directly to Entergy Gulf States Louisiana.  Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy, Entergy Gulf States Louisiana or Entergy Louisiana in the event of a bond default.  See Notes 2 and 3 to the financial statements for additional discussion of the Act 55 financings.

Entergy Arkansas January 2009 Ice Storm

In January 2009 a severe ice storm caused significant damage to Entergy Arkansas’s transmission and distribution lines, equipment, poles, and other facilities.  A law was enacted in April 2009 in Arkansas that authorizes securitization of storm damage restoration costs.  In June 2010 the APSC issued a financing order authorizing the issuance of storm cost recovery bonds, including carrying costs of $11.5 million and $4.6 million of up-front financing costs.  In August 2010, Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, issued $124.1 million of storm cost recovery bonds.  There is no recourse to Entergy or Entergy Arkansas in the event of a bond default.  See Note 5 to the financial statements for additional discussion of the issuance of the storm cost recovery bonds.

Entergy Louisiana Securitization Bonds – Little Gypsy

In August 2011 the LPSC issued a financing order authorizing the issuance of bonds to recover Entergy Louisiana’s investment recovery costs associated with the cancelled Little Gypsy repowering project.  In September 2011, Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, issued $207.2 million of senior secured investment recovery bonds.  The bonds have an interest rate of 2.04% and an expected maturity date of June 2021.  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, 2012, 2011, and 2010 were as follows.

   
2012
   
2011
   
2010
 
   
(In Millions)
 
                   
Cash and cash equivalents at beginning of period
  $ 694     $ 1,295     $ 1,710  
                         
Net cash provided by (used in):
                       
Operating activities
    2,940       3,128       3,926  
Investing activities
    (3,639 )     (3,447 )     (2,574 )
Financing activities
    538       (282 )     (1,767 )
Net decrease in cash and cash equivalents
    (161 )     (601 )     (415 )
                         
Cash and cash equivalents at end of period
  $ 533     $ 694     $ 1,295  
 
 
26

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


Operating Activities

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 in 2012;
·  
income tax payments of $49.2 million in 2012 compared to income tax refunds of $2 million in 2011; 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.

2011 Compared to 2010

Entergy's net cash provided by operating activities decreased by $798 million in 2011 compared to 2010 primarily due to the receipt in July 2010 of $703 million from the Louisiana Utilities Restoration Corporation as a result of the Louisiana Act 55 storm cost financings for Hurricane Gustav and Hurricane Ike.  The Act 55 storm cost financings are discussed in Note 2 to the financial statements.  The decrease in Entergy Wholesale Commodities net revenue that is discussed above also contributed to the decrease in operating cash flow.

Investing Activities

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.  Entergy’s construction spending plans for 2013 through 2015 are discussed further in the “ Capital Expenditure Plans and Other Uses of Capital” above.
 
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.
 
 
27

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis



2011 Compared to 2010

Net cash used in investing activities increased $873 million in 2011 compared to 2010 primarily due to:

·  
the purchase of the Acadia Power Plant by Entergy Louisiana for approximately $300 million in April 2011, the purchase of the Rhode Island State Energy Center for approximately $346 million by an Entergy Wholesale Commodities subsidiary in December 2011, and the sale of an Entergy Wholesale Commodities subsidiary’s ownership interest in the Harrison County Power Project for proceeds of $219 million in 2010.  These transactions are described in more detail in Note 15 to the financial statements;
·  
an increase 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; and
·  
a slight increase in construction expenditures, including spending resulting from April 2011 storms that caused damage to transmission and distribution lines, equipment, poles, and other facilities, primarily in Arkansas.  The capital cost of repairing that damage was approximately $55 million.

These increases were offset by the investment in 2010 of a total of $290 million in Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm reserve escrow accounts as a result of their Act 55 storm cost financings, which are discussed in Note 2 to the financial statements.

Financing Activities

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

2011 Compared to 2010

Net cash used in financing activities decreased $1,485 million in 2011 compared to 2010 primarily because long-term debt activity provided approximately $554 million of cash in 2011 and used approximately $307 million of cash in 2010.  The most significant long-term debt activity in 2011 included the issuance of $207 million of securitization bonds by a subsidiary of Entergy Louisiana, the issuance of $200 million of first mortgage bonds by Entergy Louisiana, and Entergy Corporation increasing the borrowings outstanding on its 5-year credit facility by $288 million.  For the details of Entergy’s long-term debt outstanding on December 31, 2011 and 2010 see Note 5 to the financial statements.  In addition to the long-term debt activity, Entergy Corporation repurchased $235 million of its common stock in 2011 and repurchased $879 million of its common stock in 2010.  Entergy’s stock repurchases are discussed further in the “Capital Expenditure Plans and Other Uses of Capital - Dividends and Stock Repurchases” section above.
 
 
28

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


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
 
10.2%
     
Entergy Gulf States Louisiana
 
9.9%-11.4% Electric; 10.0%-11.0% Gas
     
Entergy Louisiana
 
9.45% - 11.05%
     
Entergy Mississippi
 
9.88% - 12.01%
     
Entergy New Orleans
 
10.7% - 11.5% Electric; 10.25% - 11.25% Gas
     
Entergy Texas
 
9.8%

The Utility operating companies’ base rate, fuel and purchased power cost recovery, and storm cost recovery proceedings are discussed in Note 2 to the financial statements.

Federal Regulation

Independent Coordinator of Transmission

In 2000 the FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations).  Delays in implementing the FERC RTO order occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators have had to work to resolve various issues related to the establishment of such RTOs.  In November 2006, the Utility operating companies installed the Southwest Power Pool (SPP), an RTO, as their Independent Coordinator of Transmission (ICT).  The ICT structure approved by FERC is not an RTO under FERC Order No. 2000 and installation of the ICT did not transfer control of the Entergy transmission system to the ICT.  Instead, the ICT performs some, but not all, of the functions performed by a typical RTO, as well as certain functions unique to the Entergy transmission system. In particular, the ICT was vested with responsibility for:

·  
granting or denying transmission service on the Utility operating companies’ transmission system.
·  
administering the Utility operating companies’ OASIS node for purposes of processing and evaluating transmission service requests.
·  
developing a base plan for the Utility operating companies’ transmission system and deciding whether costs of transmission upgrades should be rolled into the Utility operating companies’ transmission rates or directly assigned to the customer requesting or causing an upgrade to be constructed.
·  
serving as the reliability coordinator for the Entergy transmission system.
 
 
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·  
overseeing the operation of the weekly procurement process (WPP).
·  
evaluating interconnection-related investments already made on the Entergy System for purposes of determining the future allocation of the uncredited portion of these investments, pursuant to a detailed methodology.  The ICT agreement also clarifies the rights that customers receive when they fund a supplemental upgrade.

The FERC, in conjunction with the APSC, the LPSC, the MPSC, the PUCT, and the City Council, hosted a conference on June 24, 2009, to discuss the ICT arrangement and transmission access on the Entergy transmission system.  During the conference, several issues were raised by regulators and market participants, including the adequacy of the Utility operating companies’ capital investment in the transmission system, the Utility operating companies’ compliance with the existing North American Electric Reliability Corporation (NERC) reliability planning standards, the availability of transmission service across the system, and whether the Utility operating companies could have purchased lower cost power from merchant generators located on the transmission system rather than running their older generating facilities.  On July 20, 2009, the Utility operating companies filed comments with the FERC responding to the issues raised during the conference.  The comments explained that: 1) the Utility operating companies believe that the ICT arrangement has fulfilled its objectives; 2) the Utility operating companies’ transmission planning practices comply with laws and regulations regarding the planning and operation of the transmission system; and 3) these planning practices have resulted in a system that meets applicable reliability standards and is sufficiently robust to allow the Utility operating companies both to substantially increase the amount of transmission service available to third parties and to make significant amounts of economic purchases from the wholesale market for the benefit of the Utility operating companies’ retail customers.   The Utility operating companies also explained that, as with other transmission systems, there are certain times during which congestion occurs on the Utility operating companies’ transmission system that limits the ability of the Utility operating companies as well as other parties to fully utilize the generating resources that have been granted transmission service.  Additionally, the Utility operating companies committed in their response to exploring and working on potential reforms or alternatives for the ICT arrangement.  The Utility operating companies’ comments also recognized that NERC was in the process of amending certain of its transmission reliability planning standards and that the amended standards, if approved by the FERC, will result in more stringent transmission planning criteria being applicable in the future.  The FERC may also make other changes to transmission reliability standards.  Changes to the reliability standards could result in increased capital expenditures by the Utility operating companies.
 
In 2009 the Entergy Regional State Committee (E-RSC), which is comprised of representatives from all of the Utility operating companies' retail regulators, was formed to consider issues related to the ICT and Entergy's transmission system.  Among other things, the E-RSC in concert with the FERC conducted a cost/benefit analysis comparing the ICT arrangement to other transmission proposals, including participation in an RTO.

In November 2010 the FERC issued an order accepting the Utility operating companies’ proposal to extend the ICT arrangement with SPP until November 2012.  In addition, in December 2010 the FERC issued an order that granted the E-RSC additional authority over transmission upgrades and cost allocation.  In July 2012 the LPSC approved, subject to conditions, Entergy Gulf States Louisiana’s and Entergy Louisiana’s request to extend the ICT arrangement and to transition to MISO as the provider of ICT services effective as of November 2012 and continuing until the Utility operating companies join the MISO RTO, or December 31, 2013, whichever occurs first.  In January 2013 the LPSC approved the use of a market monitor as part of the ICT services to be provided by MISO.

In October 2012 the FERC accepted the Utility operating companies’ proposal for (a) an interim extension of the ICT arrangement through and until the earlier of December 31, 2014 or the date the proposed transfer of functional control of the Utility operating companies’ transmission assets to the MISO RTO is completed and (b) the transfer from SPP to MISO as the provider of ICT services, effective December 1, 2012.  In December 2012 the FERC issued an order accepting further revisions to the Utility operating companies’ OATT, including a Monitoring Plan and Retention Agreement, to establish Potomac Economics Ltd., MISO’s current market monitor, as an independent Transmission Service Monitor for the Entergy transmission system, effective as of December 1, 2012.  Potomac will monitor actions of Entergy and transmission customers within the Entergy region as related to systems operations, reliability coordination, transmission planning, and transmission reservations and scheduling.
 
 
30

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System Agreement

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

Utility Operating Company Notices of Termination of System Agreement Participation

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.

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.  While the FERC had indicated previously that the notices should be filed 18 months prior to Entergy Arkansas’s termination (approximately mid-2012), the filing explains that resolving this issue now, rather than later, is important to ensure that informed long-term resource planning decisions can be made during the years leading up to Entergy Arkansas’s withdrawal and that all of the Utility operating companies are properly positioned to continue to operate reliably following Entergy Arkansas’s and, eventually, Entergy Mississippi’s, departure from the System Agreement.

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 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’ plan to integrate 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
 
 
31

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis

from the System Agreement.  Additional aspects of the Utility operating companies’ future operating arrangements will be addressed in other FERC dockets related to the allocation of the Ouachita plant transmission upgrade costs and the upcoming filings at the FERC related to the rates, terms, and conditions under which the Utility operating companies will join MISO.   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.

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 Proposal to Join MISO” section below.

Entergy’s Proposal to Join MISO

On April 25, 2011, Entergy announced that each of the Utility operating companies propose joining MISO, which is expected to provide long-term benefits for the customers of each of the Utility operating companies.  MISO is an RTO that operates in eleven U.S. states (Illinois, Indiana, Iowa, Kentucky, Michigan, Minnesota, Missouri, Montana, North Dakota, South Dakota, and Wisconsin) and also in Canada.  Each of the Utility operating companies filed an application with its retail regulator concerning the proposal to join MISO and transfer 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. Becoming a member of MISO will not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities. Once the Utility operating companies are fully integrated as members, however, MISO will assume control of transmission planning and congestion management and, through its Day 2 market, MISO will provide 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.

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.

On October 26, 2012, the APSC authorized Entergy Arkansas to sign the MISO Transmission Owners Agreement, which Entergy Arkansas has now done, 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.  On October 31, 2012, MISO filed with the APSC proof of approval of the governance enhancements and requested a finding of compliance and approval of Entergy Arkansas's application.  On November 21, 2012, the APSC issued an order requiring that MISO file a “higher level of proof” that the MISO Transmission Owners have “officially approved and adopted” one of the proposed governance enhancements in the form of sworn compliance testimony, or a sworn affidavit, from the chairman of the MISO Transmission Owners Committee.  On January 7, 2013, MISO filed its Motion for Finding of Compliance with the APSC’s order, with supporting testimony, including a copy of the testimony of the Chairman of the MISO Transmission Owners Committee in support of a filing at the FERC made January 4, 2013, on behalf of MISO and a majority of its transmission owners, jointly submitting changes to Appendix K of the MISO Transmission Owner Agreement to implement the governance enhancements.  MISO stated that the evidence submitted to the APSC showed that a majority of the MISO Transmission Owners have adopted and approved the MISO governance enhancements and the joint filing submitted to FERC on January 4, 2013, and asked that the APSC find MISO in compliance with the conditions of the APSC’s October 26, 2012 order, and that the APSC expeditiously enter an order approving Entergy Arkansas’s application to join MISO.

On January 23, 2013, Entergy Arkansas filed a Motion to Discontinue Activities Necessary to Operate as a True Stand-Alone Electric Utility, with supporting testimony, in which Entergy Arkansas requested an order from the APSC authorizing it to drop the stand-alone option by March 1, 2013.  Consistent with the conditions enumerated in a previous APSC order, Entergy Arkansas’s testimony stated that there is a low risk that MISO’s integration of Entergy Arkansas will not be successfully completed on time.

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 that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities is in the public interest, subject to certain conditions.
 
 
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Entergy Corporation and Subsidiaries
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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 Southwest Power Pool, 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 require 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 the applications, the Utility operating companies have 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 power purchase agreements 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 power purchase agreements 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 impact from termination of the power purchase agreements.  In January 2013, Entergy Texas filed an updated analysis of the effect of termination of the power purchase agreements indicating that termination would have little or no effect on Entergy Texas’s costs.  An independent consultant has been retained to assist the PUCT Staff in its assessment of the analysis.

The FERC filings related to the terms and conditions of integrating the Utility operating companies into MISO are planned to be made by mid-2013.  The target implementation date for joining MISO is December 2013.  Entergy believes that the decision to join MISO should be evaluated separately from and independent of the decision regarding the proposed transaction with ITC, and Entergy plans to continue to pursue the MISO proposal and the planned spin-off or split-off exchange offer and merger of Entergy’s Transmission Business with ITC on parallel regulatory paths.

In addition to the FERC filings planned to be made by mid-2013, there are a number of proceedings pending at FERC related to the Utility operating companies’ proposal to join MISO.  In April 2012 the FERC conditionally accepted MISO’s proposal related to the allocation of transmission upgrade costs in connection with the transition and integration of the Utility operating companies into MISO.  In November 2012 the FERC issued an order denying the requests for rehearing of the April 2012 order, and conditionally accepting MISO’s May 2012 compliance filing, subject to a further compliance filing due within 30 days of the date of the November 2012 Order.  In December 2012, MISO and the MISO Transmission Owners submitted to FERC a request for rehearing and proposed revisions to the MISO Tariff in compliance with FERC’s November 2012 order.   The request for rehearing and compliance filing are pending at FERC.
 
 
33

Entergy Corporation and Subsidiaries
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In addition, the Utility operating companies have proposed giving authority to the E-RSC, upon unanimous vote and within the first five years after the Utility operating companies join the MISO RTO, (i) to require the Utility operating companies to file with the FERC a proposed allocation of certain transmission upgrade costs among the Utility operating companies’ transmission pricing zones that would differ from the allocation that would occur under the MISO OATT and (ii) to direct the Utility operating companies as transmission owners to add projects to MISO’s transmission expansion plan.  On January 4, 2013, MISO submitted a filing with the FERC to give the Organization of MISO States, Inc. enhanced authority for determining transmission cost allocation methodologies to be filed pursuant to section 205 of the Federal Power Act.

On January 17, 2013, Occidental Chemical Corporation filed a complaint against MISO and a petition for declaratory judgment, both with the FERC, 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.  On February 14, 2013, Entergy sought to intervene and filed an answer to these pleadings.  On January 22, 2013, the MPSC, APSC, and City Council filed a petition for declaratory order with the FERC requesting that the FERC determine whether the avoided cost calculation methodology proposed in an LPSC proceeding by Entergy Services, on behalf of Entergy Gulf States Louisiana and Entergy Louisiana, complies with PURPA and the FERC’s implementing regulations.  On February 21, 2013, Entergy Services intervened and filed an answer to the petition for declaratory order.

Entergy’s initial filings with its retail regulators estimated that the transition and implementation costs of joining the MISO RTO could be up to $105 million if all of the Utility operating companies join the MISO RTO, most of which will be spent in late 2012 and 2013.  Maintaining the viability of the alternatives of Entergy Arkansas joining the MISO RTO alone or standing alone within an ICT arrangement is expected to result in an additional cost of approximately $35 million, for a total estimated cost of up to $140 million.  This amount could increase with extended litigation in various regulatory proceedings.  It is expected that costs will be incurred to obtain regulatory approvals, to revise or implement commercial and legal agreements, to integrate transmission and generation facilities, to develop back-office accounting and settlement systems, and to build out communications infrastructure.

FERC Reliability Standards Investigation

FERC’s Division of Investigations is conducting an investigation of certain issues relating to the Utility operating companies compliance with certain reliability standards related to protective system maintenance, facility ratings and modeling, training, and communications.  In November 2012 the FERC issued a
“Staff Notice of Alleged Violations” stating that the Division of Investigations’ staff has preliminarily determined that Entergy Services violated thirty-three requirements of sixteen reliability standards by failing to adequately perform certain functions.  Entergy Services is in the process of responding to the staff’s concerns.  The Energy Policy Act of 2005 provides authority to impose civil penalties for violations of the Federal Power Act and FERC regulations.

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
 
 
34

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis


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.

Market and Credit Risk Sensitive Instruments

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

·  
The commodity price risk associated with the sale of electricity by the Entergy Wholesale Commodities business.
·  
The interest rate and equity price risk associated with Entergy’s investments in pension and other postretirement benefit trust funds.  See Note 11 to the financial statements for details regarding Entergy’s pension and other postretirement benefit trust funds.
·  
The interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds, particularly in the Entergy Wholesale Commodities business.  See Note 17 to the financial statements for details regarding Entergy’s decommissioning trust funds.
·  
The interest rate risk associated with changes in interest rates as a result of Entergy’s 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 business 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 rate regulators, the Utility operating companies hedge the exposure to natural gas price volatility of their fuel and gas purchased for resale costs, which 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 core business is selling energy, measured in MWh, to its customers.  Entergy Wholesale Commodities enters into forward contracts with its customers and sells energy in the day ahead or spot markets.  In addition to selling the energy produced by its plants, Entergy Wholesale Commodities sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas.  Entergy Wholesale Commodities’ forward 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,
 
 
35

Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis



and sensitivity are provided to show potential variations.  While the sensitivity reflects the minimum, it does 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’ current forward capacity and generation contracts as well as total revenue projections based on market prices as of December 31, 2012.

Entergy Wholesale Commodities Nuclear Portfolio

   
2013
 
2014
 
2015
 
2016
 
2017
                     
Energy
                   
Percent of planned generation under contract (a):
                   
Unit-contingent (b)
 
42%
 
22%
 
12%
 
12%
 
13%
Unit-contingent with availability guarantees (c)
 
19%
 
15%
 
13%
 
13%
 
13%
Firm LD (d)
 
24%
 
55%
 
14%
 
   -%
 
   -%
Offsetting positions (e)
 
   -%
 
(19%)
 
   -%
 
   -%
 
   -%
Total
 
85%
 
73%
 
39%
 
25%
 
26%
Planned generation (TWh) (f) (g)
 
40
 
41
 
41
 
40
 
41
Average revenue per MWh on contracted volumes:
                   
Minimum
 
$45
 
$44
 
$45
 
$50
 
$51
Expected based on market prices as of Dec. 31, 2012
 
$46
 
$45
 
$47
 
$51
 
$52
Sensitivity: -/+ $10 per MWh market price change
 
$45-$48
 
$44-$48
 
$45-$52
 
$50-$53
 
$51-$54
                     
Capacity
                   
Percent of capacity sold forward (h):
                   
Bundled capacity and energy contracts (i)
 
16%
 
16%
 
16%
 
16%
 
16%
Capacity contracts (j)
 
33%
 
13%
 
12%
 
  5%
 
   -%
Total
 
49%
 
29%
 
28%
 
21%
 
16%
Planned net MW in operation (g) (k)
 
5,011
 
5,011
 
5,011
 
5,011
 
5,011
Average revenue under contract per kW per month
(applies to Capacity contracts only)
 
$2.3
 
$2.9
 
$3.3
 
$3.4
 
$-
                     
Total Nuclear Energy and Capacity Revenues
                   
Expected sold and market total revenue per MWh
 
$48
 
$45
 
$45
 
$47
 
$48
Sensitivity: -/+ $10 per MWh market price change
 
$47-$51
 
$42-$50
 
$38-$52
 
$40-$55
 
$41-$56

Entergy Wholesale Commodities Non-Nuclear Portfolio

   
2013
 
2014
 
2015
 
2016
 
2017
                     
Energy
                   
Percent of planned generation under contract (a):
                   
Cost-based contracts (l)
 
39%
 
32%
 
35%
 
32%
 
32%
Firm LD (d)
 
  6%
 
  6%
 
  6%
 
  6%
 
  6%
Total
 
45%
 
38%
 
41%
 
38%
 
38%
Planned generation (TWh) (f) (m)
 
6
 
6
 
6
 
6
 
6
       
 
           
Capacity
                   
Percent of capacity sold forward (h):
                   
Cost-based contracts (l)
 
29%
 
24%
 
24%
 
24%
 
26%
Bundled capacity and energy contracts (i)
 
  8%
 
  8%
 
  8%
 
  8%
 
  9%
Capacity contracts (j)
 
48%
 
47%
 
48%
 
20%
 
   -%
Total
 
85%
 
79%
 
80%
 
52%
 
35%
Planned net MW in operation (k) (m)
 
1,052
 
1,052
 
1,052
 
1,052
 
977
 
 
36

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 effect dispatch.
(g)
Assumes NRC license renewal for plants whose current licenses expire within five years and uninterrupted normal operation at all 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 Indian Point 3 (December 2015).  For a discussion regarding the continued operation 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)
Amount of capacity to be available to generate power and/or sell capacity considering uprates planned to be completed during the year.
(l)
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, which do not operate under market-based rate authority.  The percentage sold assumes approval of long-term transmission rights.  Includes sales to the Utility through 2013 of 121 MW of capacity and energy from Entergy Power sourced from Independence Steam Electric Station Unit 2.
(m)
Non-nuclear planned generation and net MW in operation include purchases from affiliated and non-affiliated counterparties under long-term contracts and exclude energy and capacity from Entergy Wholesale Commodities’ wind investment and from the 544 MW Ritchie plant that is not planned to operate.
 
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 net income of $125 million in 2013 and would have had a corresponding effect on pre-tax net income of $48 million in 2012.

Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA.  In October 2007, NYPA and the subsidiaries that own the FitzPatrick and Indian Point 3 plants amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms.  Under the amended value sharing agreements, the Entergy subsidiaries agreed to make annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014.  Entergy subsidiaries 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
 
 
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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 2012, 2011, and 2010, 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, 2012, based on power prices at that time, Entergy had liquidity exposure of $203 million under the guarantees in place supporting Entergy Wholesale Commodities transactions, $20 million of guarantees that support letters of credit, and $7 million of posted cash collateral to the ISOs.  As of December 31, 2012, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $106 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, 2012, Entergy would have been required to provide approximately $48 million of additional cash or letters of credit under some of the agreements.

As of December 31, 2012, substantially all of the counterparties or their guarantors for 100% of the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 2016 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, including Entergy, to undertake plant modifications or perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating Entergy’s nuclear plants.  The NRC, with input from the industry, is in the process of determining the specific actions required by the orders and an estimate 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.

On June 8, 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
 
 
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National Environmental Policy Act (NEPA) when it considered environmental effects in reaching these conclusions. The Waste Confidence Decision has been relied upon by NRC license renewal applicants to address some of the issues that 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. On August 7, 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. On September 6, 2012 the NRC directed its staff to develop a revised Waste Confidence Decision within 24 months.

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 policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in 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 business units.  Regulations require Entergy subsidiaries to decommission the nuclear power plants after each facility is taken out of service, and money is collected and 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.

·  
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 2.0% to 3.25%.  A 50 basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 10% to 18%.  To the extent that a high probability of license renewal is assumed, a change in the estimated inflation or cost escalation rate has a larger effect on the undiscounted cash flows because the rate of inflation is factored into the calculation for a longer period of time.
·  
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 currently been assumed for purposes of calculating the decommissioning liability for a number of Entergy’s nuclear units.  Second, an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in SAFSTOR status for later decommissioning, as permitted by applicable regulations.  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.  While the effect of these assumptions cannot be determined with precision, a change of assumption of either the probability of license renewal, continued operation,  or use of a SAFSTOR period can possibly change the present value of these obligations.  Future revisions to appropriately reflect changes needed to the estimate of decommissioning costs will immediately affect net income for non-rate-regulated portions of Entergy’s business, and then only to the extent that the estimate of any reduction in the liability exceeds the amount of the undepreciated asset retirement cost at the date of the revision.  Any increases in the liability recorded due to such changes are capitalized as asset retirement costs and depreciated over the asset’s remaining economic life.

 
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·  
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. However, hearings on the repository’s NRC license have been suspended indefinitely. 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 is 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 may include cost estimates for spent fuel storage.  However, these estimates could change in the future based on the timing of the opening of an appropriate facility designated by the federal government to receive spent nuclear fuel.
·  
Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of facilities has been gained and that experience has been incorporated into Entergy’s current decommissioning cost estimates.  However, given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could occur and affect current cost estimates.  If regulations regarding nuclear decommissioning were to change, this could have a potentially significant effect on cost estimates.  The effect of these potential changes is not presently determinable.
·  
Interest Rates - The estimated decommissioning costs that form the basis for the decommissioning liability recorded on the balance sheet are discounted to present values using a credit-adjusted risk-free rate. When the decommissioning cost estimate is significantly changed requiring a revision to the decommissioning liability and the change results in an increase in cash flows, that increase is discounted using a current credit-adjusted risk-free rate.  Under accounting rules, if the revision in estimate results in a decrease in estimated cash flows, that decrease is discounted using the previous credit-adjusted risk-free rate.  Therefore, to the extent that one of the factors noted above changes resulting in a significant increase in estimated cash flows, current interest rates will affect the calculation of the present value of the additional decommissioning liability.

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 first quarter 2011, 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 $38.9 million reduction in its decommissioning liability, along with a corresponding reduction in the related regulatory asset.

           In the fourth quarter 2011, Entergy Wholesale Commodities recorded a reduction of $34.1 million in its 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.


 
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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 all of its segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment whenever 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 nuclear 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 units if their operating licenses are not renewed.  Entergy’s investments in merchant non-nuclear generation assets are subject to impairment if adverse market conditions arise or if a unit plans to cease, or ceases, operation sooner than expected.

In order to determine if Entergy should recognize an impairment of a long-lived asset that is to be held and used, accounting standards require that the sum of the expected undiscounted future cash flows from the asset be compared to the asset’s carrying value.  The carrying value of the asset includes any capitalized asset retirement cost associated with the recording of an additional 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 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 have been very volatile in recent years, and this volatility is expected to continue.  This volatility necessarily 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, 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 impact on operations could cause a significant change in these assumptions.
·  
Timing - Entergy currently assumes, for a number 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 continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements.


 
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Entergy evaluates unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred.  The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs.  Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary-impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss).  Entergy did not have any material other than temporary impairments relating to credit losses on debt securities in 2012, 2011, or 2010.  The assessment of whether an investment in an equity security has suffered an other than temporary impairment continues to be based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time.  Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments.  As discussed in Note 1 to the financial statements, unrealized losses that are not considered temporarily impaired are recorded in earnings for Entergy Wholesale Commodities.  Entergy Wholesale Commodities did not record material charges to other income in 2012, 2011, and 2010, respectively, resulting from the recognition of the other-than-temporary impairment of certain equity securities held in its decommissioning trust funds.  Additional impairments could be recorded in 2013 to the extent that then current market conditions change the evaluation of recoverability of unrealized losses.  

Qualified Pension and Other Postretirement Benefits

Entergy sponsors qualified, defined benefit pension plans which 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.  Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms.  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 and volatility in the financial equity markets have impacted 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, 2012 and December 31, 2011 financial disclosures.