_______________________________________________________________________________________________

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, 2004

 

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,
Address of Principal Executive Offices and Telephone Number

IRS Employer
Identification No.

1-11299

ENTERGY CORPORATION
(a Delaware corporation)
639 Loyola Avenue
New Orleans, Louisiana 70113
Telephone (504) 576-4000

72-1229752

     

1-10764

ENTERGY ARKANSAS, INC.
(an Arkansas corporation)
425 West Capitol Avenue
Little Rock, Arkansas 72201
Telephone (501) 377-4000

71-0005900

     

1-27031

ENTERGY GULF STATES, INC.
(a Texas corporation)
350 Pine Street
Beaumont, Texas 77701
Telephone (409) 838-6631

74-0662730

     

1-8474

ENTERGY LOUISIANA, INC.
(a Louisiana corporation)
4809 Jefferson Highway
Jefferson, Louisiana 70121
Telephone (504) 840-2734

72-0245590

     

1-31508

ENTERGY MISSISSIPPI, INC.
(a Mississippi corporation)
308 East Pearl Street
Jackson, Mississippi 39201
Telephone (601) 368-5000

64-0205830

     

0-5807

ENTERGY NEW ORLEANS, INC.
(a Louisiana corporation)
1600 Perdido Street, Building 505
New Orleans, Louisiana 70112
Telephone (504) 670-3674

72-0273040

     

1-9067

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 - 213,145,161
shares outstanding at February 28, 2005

New York Stock Exchange, Inc.
Chicago Stock Exchange Inc.
Pacific Exchange Inc.

     

Entergy Arkansas, Inc.

Mortgage Bonds, 6.7% Series due April 2032
Mortgage Bonds, 6.0% Series due November 2032

New York Stock Exchange, Inc.
New York Stock Exchange, Inc.

     

Entergy Gulf States, Inc.

Preferred Stock, Cumulative, $100 Par Value:
$4.40 Dividend Series
$4.52 Dividend Series
$5.08 Dividend Series
Adjustable Rate Series B (Depository Receipts)


New York Stock Exchange, Inc.
New York Stock Exchange, Inc.
New York Stock Exchange, Inc.
New York Stock Exchange, Inc.

     

Entergy Gulf States Capital I

8.75% Cumulative Quarterly Income Preferred
Securities, Series A
(guaranteed by Entergy Gulf States, Inc.)

New York Stock Exchange, Inc.

     

Entergy Louisiana, Inc.

Mortgage Bonds, 7.6% Series due April 2032

New York Stock Exchange, Inc.

     

Entergy Mississippi, Inc.

Mortgage Bonds, 6.0% Series due November 2032
Mortgage Bonds, 7.25% Series due December 2032

New York Stock Exchange, Inc.
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, Inc.

Preferred Stock, Cumulative, $100 Par Value

   

Entergy Louisiana, Inc.

Preferred Stock, Cumulative, $100 Par Value
Preferred Stock, Cumulative, $25 Par Value

   

Entergy Mississippi, Inc.

Preferred Stock, Cumulative, $100 Par Value

   

Entergy New Orleans, Inc.

Preferred Stock, Cumulative, $100 Par Value

            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 Ö No ____

            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 an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

 

Yes

No

Entergy Corporation
Entergy Arkansas, Inc.
Entergy Gulf States, Inc.
Entergy Louisiana, Inc.
Entergy Mississippi, Inc.
Entergy New Orleans, Inc.
System Energy Resources, Inc.

Ö


Ö

Ö
Ö
Ö
Ö
Ö

            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 2004, was $12.7 billion based on the reported last sale price of $56.01 per share for such stock on the New York Stock Exchange on June 30, 2004. Entergy Corporation is the sole holder of the common stock of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc., and System Energy Resources, Inc.

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 13, 2005, are incorporated by reference into Parts I and III hereof.

TABLE OF CONTENTS

 

SEC Form 10-K
Reference Number

Page
Number

     

Definitions

 

i

Entergy's Business

Part I. Item 1.

1

      Financial Information for U.S. Utility, Non-Utility Nuclear, and Energy
       Commodity Services

 

2

      Strategy

 

3

Report of Management

 

4

      Entergy Corporation and Subsidiaries

   

      Management's Financial Discussion and Analysis

Part II. Item 7.

 

           Results of Operations

 

5

           Liquidity and Capital Resources

 

12

           Significant Factors and Known Trends

 

22

           Critical Accounting Estimates

 

33

      Selected Financial Data - Five-Year Comparison

Part II. Item 6.

41

      Report of Independent Registered Public Accounting Firm

 

42

     Consolidated Statements of Income For the Years Ended December 31,
          2004, 2003, and 2002

Part II. Item 8.

43

     Consolidated Statements of Cash Flows For the Years Ended December
          31, 2004, 2003, and 2002

Part II. Item 8.

44

     Consolidated Balance Sheets, December 31, 2004 and 2003

Part II. Item 8.

46

     Consolidated Statements of Retained Earnings, Comprehensive Income,
          and Paid in Capital for the Years Ended December 31, 2004, 2003,
          and 2002

Part II. Item 8.

48

      Notes to Consolidated Financial Statements

Part II. Item 8.

49

U.S. Utility

Part I. Item 1.

105

      Customers

 

105

      Electric Energy Sales

 

105

      Retail Rate Regulation

 

107

      Property and Other Generation Resources

 

113

      Fuel Supply

 

116

      Federal Regulation

 

119

      Service Companies

 

128

      Earnings Ratios

 

128

Non-Utility Nuclear

Part I. Item 1.

129

      Property

 

129

      Energy and Capacity Sales

 

129

      Fuel Supply

 

130

      Other Business Activities

 

131

Energy Commodity Services

Part I. Item 1.

131

      Non-Nuclear Wholesale Assets Business

 

132

      Entergy-Koch, L.P.

 

132

Regulation of Entergy's Business

Part I. Item 1.

133

      PUHCA

 

133

      Federal Power Act

 

133

      State Regulation

 

134

      Regulation of the Nuclear Power Industry

 

135

      Environmental Regulation

 

137

Litigation

 

142

Research Spending

 

146

Employees

 

146

Entergy Arkansas, Inc.

   

      Management's Financial Discussion and Analysis

Part II. Item 7.

 

            Results of Operations

 

147

            Liquidity and Capital Resources

 

147

            Significant Factors and Known Trends

 

150

            Critical Accounting Estimates

 

154

      Report of Independent Registered Public Accounting Firm

 

164

      Income Statements For the Years Ended December 31, 2004, 2003,
         and 2002

Part II. Item 8.

165

      Statements of Cash Flows For the Years Ended December 31, 2004,
         2003, and 2002

Part II. Item 8.

167

      Balance Sheets, December 31, 2004 and 2003

Part II. Item 8.

168

      Statements of Retained Earnings for the Years Ended December 31, 2004,
         2003, and 2002

Part II. Item 8.

170

      Selected Financial Data - Five-Year Comparison

Part II. Item 6.

171

Entergy Gulf States, Inc.

   

      Management's Financial Discussion and Analysis

Part II. Item 7.

 

           Results of Operations

 

172

           Liquidity and Capital Resources

 

176

           Significant Factors and Known Trends

 

179

           Critical Accounting Estimates

 

188

      Report of Independent Registered Public Accounting Firm

 

193

      Income Statements For the Years Ended December 31, 2004, 2003,
           and 2002

Part II. Item 8.

194

      Statements of Cash Flows For the Years Ended December 31, 2004,
           2003, and 2002

Part II. Item 8.

195

     Balance Sheets, December 31, 2004 and 2003

Part II. Item 8.

196

     Statements of Retained Earnings and Comprehensive Income for the
           Years Ended December 31, 2004, 2003, and 2002

Part II. Item 8.

198

     Selected Financial Data - Five-Year Comparison

Part II. Item 6.

199

Entergy Louisiana, Inc.

   

     Management's Financial Discussion and Analysis

Part II. Item 7.

 

           Results of Operations

 

200

           Liquidity and Capital Resources

 

203

           Significant Factors and Known Trends

 

207

           Critical Accounting Estimates

 

213

     Report of Independent Registered Public Accounting Firm

 

218

     Income Statements For the Years Ended December 31, 2004, 2003,
           and 2002

Part II. Item 8.

219

     Statements of Cash Flows For the Years Ended December 31, 2004,
           2003, and 2002

Part II. Item 8.

221

     Balance Sheets, December 31, 2004 and 2003

Part II. Item 8.

222

     Statements of Retained Earnings for the Years Ended December 31, 2004,
           2003, and 2002

Part II. Item 8.

224

     Selected Financial Data - Five-Year Comparison

Part II. Item 6.

225

Entergy Mississippi, Inc.

   

      Management's Financial Discussion and Analysis

Part II. Item 7.

 

           Results of Operations

 

226

           Liquidity and Capital Resources

 

228

           Significant Factors and Known Trends

 

231

           Critical Accounting Estimates

 

236

      Report of Independent Registered Public Accounting Firm

 

239

      Income Statements For the Years Ended December 31, 2004, 2003,
           and 2002

Part II. Item 8.

240

      Statements of Cash Flows For the Years Ended December 31, 2004,
           2003, and 2002

Part II. Item 8.

241

      Balance Sheets, December 31, 2004 and 2003

Part II. Item 8.

242

      Statements of Retained Earnings for the Years Ended December 31,
           2004, 2003, and 2002

Part II. Item 8.

244

      Selected Financial Data - Five-Year Comparison

Part II. Item 6.

245

Entergy New Orleans, Inc.

   

      Management's Financial Discussion and Analysis

Part II. Item 7.

 

           Results of Operations

 

246

           Liquidity and Capital Resources

 

248

           Significant Factors and Known Trends

 

251

           Critical Accounting Estimates

 

257

      Report of Independent Registered Public Accounting Firm

 

260

      Statements of Operations For the Years Ended December 31, 2004,
           2003, and 2002

Part II. Item 8.

261

      Statements of Cash Flows For the Years Ended December 31, 2004,
           2003, and 2002

Part II. Item 8.

263

      Balance Sheets, December 31, 2004 and 2003

Part II. Item 8.

264

      Statements of Retained Earnings for the Years Ended December 31,
           2004, 2003, and 2002

Part II. Item 8.

266

      Selected Financial Data - Five-Year Comparison

Part II. Item 6.

267

System Energy Resources, Inc.

   

      Management's Financial Discussion and Analysis

Part II. Item 7.

 

           Results of Operations

 

268

           Liquidity and Capital Resources

 

268

           Significant Factors and Known Trends

 

271

           Critical Accounting Estimates

 

272

      Report of Independent Registered Public Accounting Firm

 

276

      Income Statements For the Years Ended December 31, 2004, 2003,
           and 2002

Part II. Item 8.

277

      Statements of Cash Flows For the Years Ended December 31, 2004,
           2003, and 2002

Part II. Item 8.

279

      Balance Sheets, December 31, 2004 and 2003

Part II. Item 8.

280

      Statements of Retained Earnings for the Years Ended December 31,
           2004, 2003, and 2002

Part II. Item 8.

282

      Selected Financial Data - Five-Year Comparison

Part II. Item 6.

283

Notes to Respective Financial Statements for the Domestic Utility Companies
    and System Energy

Part II. Item 8.

284

Properties

Part I. Item 2.

349

Legal Proceedings

Part I. Item 3.

349

Submission of Matters to a Vote of Security Holders

Part I. Item 4.

349

Directors and Executive Officers of Entergy Corporation

Part III. Item 10.

349

Market for Registrants' Common Equity and Related Stockholder Matters

Part II. Item 5.

351

Selected Financial Data

Part II. Item 6.

352

Management's Discussion and Analysis of Financial Condition and Results of
   Operations

Part II. Item 7.

352

Quantitative and Qualitative Disclosures About Market Risk

Part II. Item 7A.

352

Financial Statements and Supplementary Data

Part II. Item 8.

353

Changes in and Disagreements with Accountants on Accounting and Financial
   Disclosure

Part II. Item 9.

353

Controls and Procedures

Part II. Item 9A.

353

Attestation Report of Registered Public Accounting Firm

Part II. Item 9A.

354

Other Information

Part II. Item 9B.

368

Directors and Executive Officers of the Registrants

Part III. Item 10.

369

Executive Compensation

Part III. Item 11.

373

Security Ownership of Certain Beneficial Owners and Management

Part III. Item 12.

383

Certain Relationships and Related Transactions

Part III. Item 13.

386

Principal Accountant Fees and Services

Part IV. Item 14

387

Exhibits, Financial Statement Schedules, and Reports on Form 8-K

Part IV. Item 15.

390

Signatures

 

391

Consent of Independent Registered Public Accounting Firm

 

398

Report of Independent Registered Public Accounting Firm

 

400

Index to Financial Statement Schedules

 

S-1

Exhibit Index

 

E-1

     

            This combined Form 10-K is separately filed by Entergy Corporation, Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., Entergy New Orleans, 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 registrant. 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 registrant, except for the Notes to the financial statements. The Entergy Corporation Notes to the financial statements are separately presented, but the Notes to the financial statements for the other registrants are combined. These two sets of Notes are marked by headers. All other Items are combined for the registrants.

 

FORWARD-LOOKING INFORMATION

            In this filing and from time to time, Entergy makes statements 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. Although Entergy believes that these forward-looking statements and the underlying assumptions are reasonable, it cannot provide assurance that they will prove correct. Except to the extent required by the federal securities laws, Entergy undertakes 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, and there are factors that could cause actual results to differ materially from those expressed or implied in the statements. Some of those factors (in addition to others described elsewhere in this report and in subsequent securities filings) include:

  • resolution of pending and future rate cases and negotiations, including various performance-based rate discussions, and other regulatory proceedings, including those related to Entergy's System Agreement and Entergy's utility supply plan
  • Entergy's ability to manage its operation and maintenance costs, particularly at its Non-Utility Nuclear generating facilities
  • the performance of Entergy's generating plants, and particularly the capacity factors at its nuclear generating facilities
  • prices for power generated by Entergy's unregulated generating facilities, the ability to extend or replace the existing purchased power agreements for those facilities, including the Non-Utility Nuclear plants, and the prices and availability of power Entergy must purchase for its utility customers
  • Entergy's ability to develop and execute on a point of view regarding prices of electricity, natural gas, and other energy-related commodities
  • changes in the financial markets, particularly those affecting the availability of capital and Entergy's ability to refinance existing debt, execute its share repurchase program, and fund investments and acquisitions
  • actions of rating agencies, including changes in the ratings of debt and preferred stock, and changes in the rating agencies' ratings criteria
  • changes in inflation and interest rates
  • Entergy's ability to purchase and sell assets at attractive prices and on other attractive terms
  • volatility and changes in markets for electricity, natural gas, uranium, and other energy-related commodities
  • 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, the establishment of a regional transmission organization that includes Entergy's utility service territory, and the application of market power criteria by the FERC
  • changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown of Indian Point or other nuclear generating facilities
  • uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel storage and disposal
  • resolution of pending or future applications for license extensions or modifications of nuclear generating facilities
  • changes in law resulting from proposed energy legislation
  • changes in environmental, tax, and other laws, including requirements for reduced emissions of sulfur, nitrogen, carbon, mercury, and other substances
  • the economic climate, and particularly growth in Entergy's service territory
  • variations in weather and the occurrence of hurricanes and other storms and disasters
  • advances in technology
  • the potential effects of threatened or actual terrorism and war
  • the effects of Entergy's strategies to reduce current tax payments
  • the effects of litigation and government investigations
  • changes in accounting standards, corporate governance, and securities law requirements
  • Entergy's ability to attract and retain talented management and directors

DEFINITIONS

            Certain abbreviations or acronyms used in the text and notes are defined below:

Abbreviation or Acronym

Term

   

AFUDC

Allowance for Funds Used During Construction

ALJ

Administrative Law Judge

ANO 1 and 2

Units 1 and 2 of Arkansas Nuclear One Steam Electric Generating Station (nuclear), owned by Entergy Arkansas

APSC

Arkansas Public Service Commission

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

CPI-U

Consumer Price Index - Urban

DOE

United States Department of Energy

domestic utility companies

Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, collectively

EITF

FASB's Emerging Issues Task Force

Energy Commodity Services

Entergy's business segment that includes Entergy-Koch, LP and Entergy's non-nuclear wholesale assets business

Entergy

Entergy Corporation and its direct and indirect subsidiaries

Entergy Corporation

Entergy Corporation, a Delaware corporation

Entergy-Koch

Entergy-Koch, LP, a joint venture equally owned by subsidiaries of Entergy and Koch Industries, Inc.

EPA

United States Environmental Protection Agency

EPDC

Entergy Power Development Corporation, a wholly-owned subsidiary of Entergy Corporation

FASB

Financial Accounting Standards Board

FEMA

Federal Emergency Management Agency

FERC

Federal Energy Regulatory Commission

firm liquidated damages

Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset); if a party fails to deliver or receive energy, the defaulting party must compensate the other party as specified in the contract

FSP

FASB Staff Position

Grand Gulf

Unit No. 1 of Grand Gulf Steam Electric Generating Station (nuclear), 90% owned or leased by System Energy

GWh

Gigawatt-hour(s), which equals one million kilowatt-hours

Independence

Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi, and 7% by Entergy Power

IRS

Internal Revenue Service

ISO

Independent System Operator

kV

Kilovolt

kW

Kilowatt

kWh

Kilowatt-hour(s)

   

DEFINITIONS (Continued)

Abbreviation or Acronym

Term

   

LDEQ

Louisiana Department of Environmental Quality

LPSC

Louisiana Public Service Commission

Mcf

1,000 cubic feet of gas

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, owned 70% by Entergy Gulf States

Net debt ratio

Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents

Net MW in operation

Installed capacity owned or operated

Net revenue

Operating revenue net of fuel, fuel-related, and purchased power expenses; and other regulatory credits

Non-Utility Nuclear

Entergy's business segment that owns and operates five nuclear power plants and sells electric power produced by those plants to wholesale customers

NRC

Nuclear Regulatory Commission

NYPA

New York Power Authority

PPA

Purchased power agreement

production cost

Cost in $/MMBtu associated with delivering gas, excluding the cost of the gas

PRP

Potentially responsible party (a person or entity that may be responsible for remediation of environmental contamination)

PUCT

Public Utility Commission of Texas

PUHCA

Public Utility Holding Company Act of 1935, as amended

PURPA

Public Utility Regulatory Policies Act of 1978

Ritchie Unit 2

Unit 2 of the R.E. Ritchie Steam Electric Generating Station (gas/oil)

River Bend

River Bend Steam Electric Generating Station (nuclear), owned by Entergy Gulf States

SEC

Securities and Exchange Commission

SFAS

Statement of Financial Accounting Standards as promulgated by the FASB

SMEPA

South Mississippi Electric Power Agency, which owns a 10% interest in Grand Gulf

spark spread

Dollar difference between electricity prices per unit and natural gas prices after assuming a conversion ratio for the number of natural gas units necessary to generate one unit of electricity

System Agreement

Agreement, effective January 1, 1983, as modified, among the domestic utility companies relating to the sharing of generating capacity and other power resources

System Energy

System Energy Resources, Inc.

System Fuels

System Fuels, Inc.

   

DEFINITIONS (Concluded)

Abbreviation or Acronym

Term

   

TWh

Terawatt-hour(s), which equals one billion kilowatt-hours

unit-contingent

Transaction under which power is supplied from a specific generation asset; if the specified generation asset is unavailable as a result of forced outage or unanticipated event or circumstance, the seller is not liable to the buyer for any damages resulting from the seller's failure to deliver power

unit-contingent with
availability guarantees

Transaction under which power is supplied from a specific generation asset; if the specified generation asset is unavailable as a result of forced outage or unanticipated event or circumstance, the seller is not liable to the buyer for any damages resulting from the seller's failure to deliver power unless the actual availability over a specified period of time is below an availability threshold specified in the contract

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

UK

The United Kingdom of Great Britain and Northern Ireland

U.S. Utility

Entergy's business segment that generates, transmits, distributes, and sells electric power, with a small amount of natural gas distribution

Waterford 3

Unit No. 3 (nuclear) of the Waterford Steam Electric Generating 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'S BUSINESS

Entergy Corporation is an integrated energy company engaged primarily in electric power production and retail electric distribution operations. Entergy owns and operates power plants with approximately 30,000 MW of electric generating capacity, and it is the second-largest nuclear power generator in the United States. Entergy delivers electricity to 2.7 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy generated annual revenues of over $10 billion in 2004 and had approximately 14,400 employees as of December 31, 2004.

Entergy operates primarily through three business segments: U.S. Utility, Non-Utility Nuclear, and Energy Commodity Services.

  • U.S. Utility generates, transmits, distributes, and sells electric power in a four-state service territory that includes portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operates a small natural gas distribution business.
  • Non-Utility Nuclear owns and operates five nuclear power plants located in the northeastern United States and sells the electric power produced by those plants to wholesale customers. This business also provides services to other nuclear power plant owners.
  • Energy Commodity Services includes Entergy-Koch and Entergy's non-nuclear wholesale assets business. Entergy-Koch engaged in two major businesses: energy commodity marketing and trading through Entergy-Koch Trading, and gas transportation and storage through Gulf South Pipeline. Entergy-Koch sold both of these businesses in the fourth quarter of 2004, and Entergy-Koch is no longer an operating entity. The non-nuclear wholesale assets business sells to wholesale customers the electric power produced by power plants that it owns while it focuses on improving performance and exploring sales or restructuring opportunities for its power plants. Such opportunities are evaluated consistent with Entergy's market-based point-of-view. The non-nuclear wholesale assets business terminated new greenfield power development activity in 2002.

 

OPERATING INFORMATION
For the Years Ended December 31, 2004, 2003, and 2002
                 
    U.S. Utility   Non-Utility Nuclear   Energy Commodity Services   Entergy Consolidated (a)
    (In Thousands)
2004                
Operating revenues   $8,142,808    $1,341,852    $216,450    $10,123,724 
Operating expenses   $6,795,146    $978,688    $308,226    $8,470,160 
Other income   $108,925    $78,141    ($44,727)   $124,416 
Interest and other charges   $383,032    $53,657    $15,560    $479,023 
Income taxes   $406,864    $142,620    ($155,840)   $365,908 
Net income   $666,691    $245,029    $3,778    $933,049 
                  
2003                
Operating revenues   $7,584,857    $1,274,983    $184,888    $9,194,920 
Operating expenses   $6,274,830    $1,039,614    $224,567    $7,710,365 
Other income   ($35,965)   $33,997    $337,334    $325,238 
Interest and other charges   $419,111    $34,460    $15,193    $506,326 
Income taxes   $341,044    $88,619    $105,903    $490,074 
Cumulative effect of accounting change   ($21,333)   $154,512    $3,895    $137,074 
Net income   $492,574    $300,799    $180,454    $950,467 
                  
2002                
Operating revenues   $6,773,509    $1,200,238    $294,670    $8,305,035 
Operating expenses   $5,434,694    $868,288    $769,834    $7,163,314 
Other income   $47,603    $48,572    $249,678    $347,753 
Interest and other charges   $465,703    $47,291    $61,632    $572,464 
Income taxes   $313,752    $132,726    ($141,288)   $293,938 
Net income (loss)   $606,963    $200,505    ($145,830)   $623,072 
                 
                 
CASH FLOW INFORMATION
For the Years Ended December 31, 2004, 2003, and 2002
                 
    U.S. Utility   Non-Utility Nuclear   Energy Commodity Services   Entergy Consolidated (a)
    (In Thousands)
2004        
Net cash flow provided by operating activities   $2,207,876    $414,518    $479,919    $2,929,319 
Net cash flow provided by (used in) investing activities   ($1,198,009)   ($386,023)   $248,612    ($1,140,075)
Net cash flow used in financing activities   ($824,579)   ($37,894)   ($724,534)   ($1,671,859)
                 
2003                
Net cash flow provided by (used in) operating activities   $1,675,069    $182,524    ($111,291)   $2,005,820 
Net cash flow used in investing activities   ($1,441,992)   ($184,913)   ($78,120)   ($1,783,130)
Net cash flow provided by (used in) financing activities   ($919,983)   ($6,672)   $166,165    ($869,130)
                 
2002                
Net cash flow provided by (used in) operating activities   $2,341,161    $281,589    ($3,714)   $2,181,703 
Net cash flow used in investing activities   ($1,020,087)   ($438,664)   ($760)   ($1,388,463)
Net cash flow provided by (used in) financing activities   ($688,201)   $176,162    ($66,151)   ($212,610)
                 
                 
FINANCIAL POSITION INFORMATION
As of December 31, 2004 and 2003
                 
    U.S. Utility   Non-Utility Nuclear   Energy Commodity Services   Entergy Consolidated (a)
     (In Thousands)
2004                 
Current assets   $2,323,801    $590,580    $1,282,578    $3,108,118 
Other property and investments   $1,200,246    $1,403,222    $569,975    $2,995,894 
Property, plant and equipment - net   $16,502,155    $1,850,481    $310,793    $18,695,631 
Deferred debits and other assets   $2,911,035    $687,321    $60,632    $3,511,134 
Current liabilities   $1,756,011    $787,668    $205,348    $2,470,770 
Non-current liabilities   $15,214,095    $1,694,090    $279,730    $17,543,320 
Shareholders' equity   $5,967,131    $2,049,847    $1,738,900    $8,296,687 
                 
2003                
Current assets   $2,117,260    $542,837    $466,132    $2,919,244 
Other property and investments   $1,151,538    $1,326,347    $1,137,069    $3,746,926 
Property, plant and equipment - net   $16,242,775    $1,557,025    $463,403    $18,298,797 
Deferred debits and other assets   $2,890,741    $745,568    $10,317    $3,562,421 
Current liabilities   $1,671,607    $330,684    $478,693    $2,282,223 
Non-current liabilities   $15,309,482    $1,891,805    $41,450    $17,568,329 
Shareholders' equity   $5,448,047    $1,949,288    $1,614,620    $8,703,658 
                 
(a) In addition to the 3 operating segments presented here, Entergy Consolidated also includes Entergy Corporation (parent company),
     
other business activity, and intercompany eliminations.

 

The following shows the principal subsidiaries and affiliates within Entergy's business segments. Companies that file reports and other information with the SEC under the Securities Exchange Act of 1934 are identified in bold-faced type.

       


Entergy Corporation

   
                   
                   
                   
                 

U. S. Utility

 

Non-Utility Nuclear

 

Energy Commodity Services

                     
 

Entergy Arkansas, Inc.

   

Entergy Nuclear Operations, Inc.

 

Entergy-Koch, LP

 

Non-Nuclear Wholesale Assets

 

Entergy Gulf States, Inc.

   

Entergy Nuclear Finance, Inc.

 

(50% ownership)

     
 

Entergy Louisiana, Inc.

   

Entergy Nuclear Generation Co. (Pilgrim)

         

Entergy Power Development Corp.

 

Entergy Mississippi, Inc.

   

Entergy Nuclear FitzPatrick LLC

         

Entergy Asset Management, Inc.

 

Entergy New Orleans, Inc.

   

Entergy Nuclear Indian Point 2, LLC

         

Entergy Power, Inc.

 

System Energy Resources, Inc.

   

Entergy Nuclear Indian Point 3, LLC

           
 

Entergy Operations, Inc.

   

Entergy Nuclear Vermont Yankee, LLC

           
 

Entergy Services, Inc.

   

Entergy Nuclear, Inc.

           
 

System Fuels, Inc.

   

Entergy Nuclear Fuels Company

           
       

Entergy Nuclear Nebraska LLC

           

In addition to its three primary operating segments, Entergy's Competitive Retail Services business markets and sells electricity, thermal energy, and related services in competitive markets, primarily the ERCOT region in Texas, where it has over 105,000 customers. Competitive Retail Services contributed approximately 5% of Entergy's revenue in 2004, but does not currently have significant levels of net income or loss, or total assets, and Entergy reports this business as part of All Other in its segment disclosures.

Strategy

Entergy aspires to achieve industry leading total shareholder returns by leveraging the scale and expertise inherent in its core nuclear and utility operations. Entergy's scope includes electricity generation, transmission and distribution as well as natural gas transportation and distribution. Entergy focuses on operational excellence with an emphasis on safety, reliability, customer service, sustainability, cost efficiency and risk management. Entergy also focuses on portfolio management to make periodic buy, build, hold, or sell decisions based upon its analytically-derived points of view which are continuously updated as market conditions evolve.

___________________________________________________________________________________________

Availability of SEC filings and other information on Entergy's website

Entergy's internet address is www.entergy.com. Entergy's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to any of these reports, are available free of charge through Entergy's website as soon as reasonably practicable after filing with the SEC. Financial presentations and news releases are also available through Entergy's website. Additionally, Entergy's Corporate Governance Guidelines, Board Committee Charters for the Corporate Governance, Audit, and Personnel Committees, and Entergy's Codes of Conduct are posted on Entergy's website. This information is also available in print to any investor that requests it. In June 2004, Entergy's chief executive officer certified to the New York Stock Exchange that he was not aware of any violation by Entergy of the New York Stock Exchange corporate governance listing standards.

Part I, Item 1 is continued on page 105.

 

ENTERGY CORPORATION AND SUBSIDIARIES

REPORT OF MANAGEMENT

Management of Entergy Corporation and its subsidiaries has prepared and is responsible for the financial statements and related financial information included in this document. To meet this responsibility, management establishes and maintains a system of internal control designed to provide reasonable assurance regarding the preparation and fair presentation of financial statements in accordance with generally accepted accounting principles. This system includes communication through written policies and procedures, an employee Code of Entegrity, and an organizational structure that provides for appropriate division of responsibility and the training of personnel. This system is also tested by a comprehensive internal audit program.

Entergy management assesses the effectiveness of its internal control over financial reporting on an annual basis. In making this assessment, management uses the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Management acknowledges, however, that all internal control systems, no matter how well designed, have inherent limitations and can provide only reasonable assurance with respect to financial statement preparation and presentation.

As a supplement to management's assessment, Entergy's independent auditors conduct an objective assessment of the degree to which management meets its responsibility for fairness of financial reporting and issue an attestation report on the adequacy of management's assessment. They evaluate Entergy's internal control over financial reporting and perform such tests and other procedures as they deem necessary to reach and express an opinion on the fairness of the financial statements.

In addition, the Audit Committee of the Board of Directors, composed solely of independent Directors, meets with the independent auditors, internal auditors, management, and internal accountants periodically to discuss internal controls, and auditing and financial reporting matters. The Audit Committee appoints the independent auditors annually, and reviews with the independent auditors the scope and results of the audit effort. The Committee also meets periodically with the independent auditors and the chief internal auditor without management, providing free access to the Committee.

Based on management's assessment of internal controls using the COSO criteria, management believes that Entergy maintained effective internal control over financial reporting as of December 31, 2004. Management further believes that this assessment, combined with the policies and procedures noted above provide reasonable assurance that Entergy's financial statements are fairly and accurately presented in accordance with generally accepted accounting principles.

J. WAYNE LEONARD
Chief Executive Officer of Entergy Corporation

LEO P. DENAULT
Executive Vice President and Chief Financial Officer of Entergy Corporation

HUGH T. MCDONALD
Chairman, President, and Chief Executive Officer of Entergy Arkansas, Inc.

JOSEPH F. DOMINO
Chairman of Entergy Gulf States, Inc., President and Chief Executive Officer - Texas of Entergy Gulf States, Inc.

E. RENAE CONLEY
Chairman, President, and Chief Executive Officer of Entergy Louisiana, Inc.; President and Chief Executive Officer- Louisiana of Entergy Gulf States, Inc.

CAROLYN C. SHANKS
Chairman, President, and Chief Executive Officer of Entergy Mississippi, Inc.

DANIEL F. PACKER
Chairman, President, and Chief Executive Officer of Entergy New Orleans, Inc.

GARY J. TAYLOR
Chairman, President, and Chief Executive Officer of System Energy Resources, Inc.

THEODORE H. BUNTING, JR.
Vice President and Chief Financial Officer of System Energy Resources, Inc.

JAY A. LEWIS
Vice President and Chief Financial Officer of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc.

ENTERGY CORPORATION AND SUBSIDIARIES

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

Entergy Corporation is an investor-owned public utility holding company that operates primarily through three business segments.

  • U.S. Utility generates, transmits, distributes, and sells electric power in a four-state service territory that includes portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operates a small natural gas distribution business.
  • Non-Utility Nuclear owns and operates five nuclear power plants located in the northeastern United States and sells the electric power produced by those plants to wholesale customers. This business also provides services to other nuclear power plant owners.
  • Energy Commodity Services includes Entergy-Koch and Entergy's non-nuclear wholesale assets business. Entergy-Koch engaged in two major businesses: energy commodity marketing and trading through Entergy-Koch Trading, and gas transportation and storage through Gulf South Pipeline. Entergy-Koch sold both of these businesses in the fourth quarter of 2004, and Entergy-Koch is no longer an operating entity. The non-nuclear wholesale assets business sells to wholesale customers the electric power produced by power plants that it owns while it focuses on improving performance and exploring sales or restructuring opportunities for its power plants. Such opportunities are evaluated consistent with Entergy's market-based point-of-view. The non-nuclear wholesale assets business terminated new greenfield power development activity in 2002.

Following are the percentages of Entergy's consolidated revenues and net income generated by these segments and the percentage of total assets held by them:

   

% of Revenue

 

% of Net Income

 

% of Total Assets

Segment

 

2004

 

2003

 

2002

 

2004

 

2003

 

2002

 

2004

 

2003

 

2002

                                     

U.S. Utility

 

81

 

82

 

82

 

72 

 

52 

 

97 

 

80 

 

79 

 

79 

Non-Utility Nuclear

 

13

 

14

 

14

 

26 

 

32 

 

32 

 

16 

 

15 

 

16 

Energy Commodity Services

 

2

 

2

 

4

 

 

19 

 

(23)

 

 

 

Parent & Other

 

4

 

2

 

-

 

 

(3)

 

(6)

 

 

(1)

 

(3)

Results of Operations

Earnings applicable to common stock for the years ended December 31, 2004, 2003, and 2002 by operating segment are as follows:

Operating Segment

 

2004

 

2003

 

2002

 

 

(In Thousands)

 

 

 

 

 

 

 

U.S. Utility

 

$643,408 

 

$469,050 

 

$583,251 

Non-Utility Nuclear

 

245,029 

 

300,799 

 

200,505 

Energy Commodity Services

 

3,481 

 

180,454 

 

(145,830)

Parent & Other

 

17,606 

 

(23,360)

 

(38,566)

Total

 

$909,524 

 

$926,943 

 

$599,360 

Following is a discussion of Entergy's income before taxes according to the business segments listed above. Earnings for 2004 include a $97 million tax benefit that resulted from the sale of preferred stock and less than 1% of the common stock in a subsidiary in the non-nuclear wholesale assets business; and a $36 million net-of-tax impairment charge in the non-nuclear wholesale assets business, both of which are discussed below.

Earnings for 2003 include the $137.1 million net-of-tax cumulative effect of changes in accounting principle that increased earnings in the first quarter of 2003, almost entirely resulting from the implementation of SFAS 143. Earnings were negatively affected in the fourth quarter of 2003 by voluntary severance program expenses of $122.8 million net-of-tax. As part of an initiative to achieve productivity improvements with a goal of reducing costs, primarily in the Non-Utility Nuclear and U.S. Utility businesses, in the second half of 2003 Entergy offered a voluntary severance program to employees in various departments. Approximately 1,100 employees, including 650 employees in nuclear operations from the Non-Utility Nuclear and U.S. Utility businesses, accepted the offers.

Earnings for 2002 were negatively affected by net charges ($238.3 million net-of-tax) reflecting the effect of Entergy's decision to discontinue additional greenfield power plant development and asset impairments resulting from the deteriorating economics of wholesale power markets principally in the United States and the United Kingdom. The net charges are discussed more fully below in the Energy Commodity Services discussion. See Note 11 to the consolidated financial statements for further discussion of Entergy's business segments and their financial results in 2004, 2003, and 2002.

Refer to "SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES" which accompanies Entergy Corporation's consolidated financial statements in this report for further information with respect to operating statistics.

U.S. UTILITY

The increase in earnings for the U.S. Utility for 2004 from $469 million to $643 million was primarily due to the following:

  • the $107.7 million ($65.6 million net-of-tax) accrual in 2003 of the loss that would be associated with a final, non-appealable decision disallowing abeyed River Bend plant costs. Refer to Note 2 to the consolidated financial statements for more details regarding the River Bend abeyed plant costs;
  • lower other operation and maintenance expenses primarily due to $99.8 million ($70.1 million net-of-tax) of charges recorded in 2003 in connection with the voluntary severance program;
  • the $21.3 million net-of-tax cumulative effect of a change in accounting principle that reduced earnings at Entergy Gulf States in the first quarter of 2003 upon implementation of SFAS 143. See "Critical Accounting Estimates - SFAS 143" below for discussion of the implementation of SFAS 143;
  • miscellaneous other income of $27.7 million (pre-tax) in 2004 resulting from a revision of the decommissioning liability for River Bend, as discussed in Note 8 to the consolidated financial statements;
  • higher net revenue; and
  • lower interest charges.

The decrease in earnings for the U.S. Utility for 2003 from $583 million to $469 million was primarily due to:

  • the $107.7 million ($65.6 million net-of-tax) accrual in 2003 of the loss that would be associated with a final, non-appealable decision disallowing abeyed River Bend plant costs;
  • $99.8 million ($70.1 million net-of-tax) of charges recorded in 2003 in connection with the voluntary severance program; and
  • the $21.3 million net-of-tax cumulative effect of a change in accounting principle that reduced earnings at Entergy Gulf States in the first quarter of 2003 upon implementation of SFAS 143. See "Critical Accounting Estimates - SFAS 143" below for discussion of the implementation of SFAS 143.

Partially offsetting the decrease in earnings in 2003 were higher net revenue and lower interest charges.

Net Revenue

2004 Compared to 2003

Net revenue, which is Entergy's measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2004 to 2003.

   

(In Millions)

     

2003 net revenue

 

$4,214.5  

Volume/weather

 

68.3  

Summer capacity charges

 

17.4  

Base rates

 

10.6  

Deferred fuel cost revisions

 

(46.3)

Price applied to unbilled sales

 

(19.3)

Other

 

(1.2)

2004 net revenue

 

$4,244.0 

The volume/weather variance resulted primarily from increased usage, partially offset by the effect of milder weather on sales during 2004 compared to 2003. Billed usage increased a total of 2,261 GWh in the industrial and commercial sectors.

The summer capacity charges variance was due to the amortization in 2003 at Entergy Gulf States and Entergy Louisiana of deferred capacity charges for the summer of 2001. Entergy Gulf States' amortization began in June 2002 and ended in May 2003. Entergy Louisiana's amortization began in August 2002 and ended in July 2003.

Base rates increased net revenue due to a base rate increase at Entergy New Orleans that became effective in June 2003.

The deferred fuel cost revisions variance resulted primarily from a revision in 2003 to an unbilled sales pricing estimate to more closely align the fuel component of that pricing with expected recoverable fuel costs at Entergy Louisiana. Deferred fuel cost revisions also decreased net revenue due to a revision in 2004 to the estimate of fuel costs filed for recovery at Entergy Arkansas in the March 2004 energy cost recovery rider.

The price applied to unbilled sales variance resulted from a decrease in fuel price in 2004 caused primarily by the effect of nuclear plant outages in 2003 on average fuel costs.

Gross operating revenues and regulatory credits

Gross operating revenues include an increase in fuel cost recovery revenues of $475 million and $18 million in electric and gas sales, respectively, primarily due to higher fuel rates in 2004 resulting from increases in the market prices of purchased power and natural gas. As such, this revenue increase is offset by increased fuel and purchased power expenses.

Other regulatory credits increased primarily due to the following:

  • cessation of the Grand Gulf Accelerated Recovery Tariff that was suspended in July 2003;
  • the amortization in 2003 of deferred capacity charges for summer 2001 power purchases at Entergy Gulf States and Entergy Louisiana;
  • the deferral in 2004 of $14.3 million of capacity charges related to generation resource planning as allowed by the LPSC;
  • the deferral in 2004 by Entergy Louisiana of $11.4 million related to the voluntary severance program, in accordance with a proposed stipulation entered into with the LPSC staff; and
  • the deferral in August 2004 of $7.5 million of fossil plant maintenance and voluntary severance program costs at Entergy New Orleans as a result of a stipulation approved by the City Council.

2003 Compared to 2002

Net revenue, which is Entergy's measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2003 to 2002.

   

(In Millions)

     

2002 net revenue

 

$4,209.6  

Base rate increases

 

66.2  

Base rate decreases

 

(23.3)

Deferred fuel cost revisions

 

56.2  

Asset retirement obligation

 

42.9  

Net wholesale revenue

 

23.2  

March 2002 Ark. settlement agreement

 

(154.0)

Other

 

(6.3)

2003 net revenue

 

$4,214.5 

Base rates increased net revenue due to base rate increases at Entergy Mississippi and Entergy New Orleans that became effective in January 2003 and June 2003, respectively. Entergy Gulf States implemented base rate decreases in its Louisiana jurisdiction effective June 2002 and January 2003. The January 2003 base rate decrease of $22.1 million had a minimal impact on net income due to a corresponding reduction in nuclear depreciation and decommissioning expenses associated with the change in accounting estimate to reflect an assumed extension of River Bend's useful life.

The deferred fuel cost revisions variance was due to a revised unbilled sales pricing estimate made in December 2002 and further revision of that estimate in the first quarter of 2003 to more closely align the fuel component of that pricing with expected recoverable fuel costs at Entergy Louisiana.

The asset retirement obligation variance was due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations," adopted in January 2003. See "Critical Accounting Estimates - - Nuclear Decommissioning Costs" for more details on SFAS 143. The increase was offset by increased depreciation and decommissioning expenses and had an insignificant effect on net income.

The increase in net wholesale revenue was primarily due to an increase in sales volume to municipal and cooperative customers.

The March 2002 settlement agreement variance reflects the absence in 2003 of the effect of recording the ice storm settlement approved by the APSC in 2002. This settlement resulted in previously deferred revenues at Entergy Arkansas per the transition cost account mechanism being recorded in net revenue in the second quarter of 2002. The decrease was offset by a corresponding decrease in other operation and maintenance expenses and had a minimal effect on net income.

Gross operating revenues and regulatory credits

Gross operating revenues include an increase in fuel cost recovery revenues of $682 million and $53 million in electric and gas sales, respectively, primarily due to higher fuel rates in 2003 resulting from increases in the market prices of purchased power and natural gas. As such, this revenue increase was offset by increased fuel and purchased power expenses.

Other regulatory credits decreased primarily due to the APSC-approved March 2002 settlement agreement mentioned above, which increased other regulatory credits in 2002 to offset other operation and maintenance expenses of $159.9 million related to the December 2000 ice storms. The decrease was partially offset by the asset retirement obligation mentioned above, which increased other regulatory credits in 2003 to offset the increases in depreciation and decommissioning expenses.

Other Income Statement Variances

2004 Compared to 2003

Other operation and maintenance expenses decreased from $1.613 billion in 2003 to $1.569 billion in 2004 primarily due to voluntary severance program accruals of $99.8 million in 2003 partially offset by an increase of $30.5 million as a result of higher customer service support costs in 2004 and an increase of approximately $33 million as a result of higher benefits costs in 2004. Entergy expects benefit costs to continue to increase in 2005. See "Critical Accounting Estimates - - Pension and Other Retirement Benefits" and Note 10 to the consolidated financial statements for further discussion of benefit costs.

Depreciation and amortization expenses increased from $797.6 million in 2003 to $823.7 million in 2004 primarily due to higher depreciation of Grand Gulf due to a higher scheduled sale-leaseback principal payment in addition to an increase in plant in service.

Other income (deductions) changed from ($36.0 million) in 2003 to $108.9 million in 2004 primarily due to the following:

  • the $107.7 million accrual in the second quarter of 2003 for the loss that would be associated with a final, non-appealable decision disallowing abeyed River Bend plant costs. See Note 2 to the consolidated financial statements for more details regarding the River Bend abeyed plant costs;
  • a reduction in the decommissioning liability for River Bend in 2004, as discussed in Note 8 to the consolidated financial statements; and
  • a $10 million reduction in the loss provision for an environmental clean-up site.

Interest on long-term debt decreased from $433.5 million in 2003 to $390.7 million in 2004 primarily due to the net retirement and refinancing of long-term debt in 2003 and the first six months of 2004. See Note 5 to the consolidated financial statements for details on long-term debt.

2003 Compared to 2002

Other operation and maintenance expenses decreased from $1.679 billion in 2002 to $1.613 billion in 2003 primarily due to decreased expenses at Entergy Arkansas. The March 2002 settlement agreement that became final in the second quarter of 2002, allowing Entergy Arkansas to recover a large majority of 2000 and 2001 ice storm repair expenses through the previously-collected transition cost account amounts, increased Entergy Arkansas' expenses by $159.9 million in 2002. This increase in expenses in 2002 was offset by a regulatory credit resulting in no effect on net income. The decrease was partially offset by an increase of $99.8 million in benefit costs as a result of voluntary severance program accruals in 2003.

Decommissioning expense increased from $30.5 million in 2002 to $92.5 million in 2003 primarily due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations." The increase in decommissioning expense was offset by increases in other regulatory credits and interest and dividend income and had an insignificant effect on net income.

Depreciation and amortization expenses increased from $769.8 million in 2002 to $797.6 million in 2003 primarily due to an increase in plant in service. The increase was also due to the implementation of SFAS 143. The increase in depreciation and amortization expense due to SFAS 143 implementation was offset by increases in other regulatory credits and interest and dividend income and has an insignificant effect on net income.

Other income (deductions) changed from $47.6 million in 2002 to ($36.0 million) in 2003 primarily due to a decrease in "miscellaneous - net" as a result of a $107.7 million accrual in the second quarter of 2003 for the loss that would be associated with a final, non-appealable decision disallowing abeyed River Bend plant costs. See Note 2 to the consolidated financial statements for more details regarding the River Bend abeyed plant costs. The decrease was partially offset by an increase in interest and dividend income as a result of the implementation of SFAS 143.

Interest on long-term debt decreased from $462.0 million in 2002 to $433.5 million in 2003 primarily due to the redemption and refinancing of long-term debt.

NON-UTILITY NUCLEAR

Following are key performance measures for Non-Utility Nuclear:

 

2004

 

2003

 

2002

 

 

 

 

 

 

Net MW in operation at December 31

4,058

 

4,001

 

3,955

Average realized price per MWh

$41.26

 

$39.38

 

$40.07

Generation in GWh for the year

32,524

 

32,379

 

29,953

Capacity factor for the year

92%

 

92%

 

93%

2004 Compared to 2003

The decrease in earnings for Non-Utility Nuclear from $300.8 million to $245.0 million was primarily due to the $154.5 million net-of-tax cumulative effect of a change in accounting principle that increased earnings in the first quarter of 2003 upon implementation of SFAS 143. See "Critical Accounting Estimates - SFAS 143" below for discussion of the implementation of SFAS 143. Earnings before the cumulative effect of accounting change increased by $98.7 million primarily due to the following:

  • lower operation and maintenance expenses, which decreased from $681.8 million in 2003 to $595.7 million in 2004, primarily resulting from charges recorded in 2003 in connection with the voluntary severance program;
  • higher revenues, which increased from $1.275 billion in 2003 to $1.342 billion in 2004, primarily resulting from higher contract pricing. The addition of a support services contract for the Cooper Nuclear Station and increased generation in 2004 due to power uprates completed in 2003 and fewer planned and unplanned outages in 2004 also contributed to the higher revenues; and
  • miscellaneous income resulting from a reduction in the decommissioning liability for a plant, as discussed in Note 8 to the consolidated financial statements.

Partially offsetting this increase were the following:

  • higher income taxes, which increased from $88.6 million in 2003 to $142.6 million in 2004; and
  • higher depreciation expense, which increased from $34.3 million in 2003 to $48.9 million in 2004, due to additions to plant in service.

2003 Compared to 2002

The increase in earnings for Non-Utility Nuclear from $200.5 million to $300.8 million was primarily due to the $154.5 million net-of-tax cumulative effect of a change in accounting principle recognized in the first quarter of 2003 upon implementation of SFAS 143. See "Critical Accounting Estimates - SFAS 143" below for discussion of the implementation of SFAS 143. Income before the cumulative effect of accounting change decreased by $54.2 million. The decrease was primarily due to $83.0 million ($50.6 million net-of-tax) of charges recorded in connection with the voluntary severance program. Except for the effect of the voluntary severance program, operation and maintenance expenses in 2003 per MWh of generation were in line with 2002 operation and maintenance expenses.

ENERGY COMMODITY SERVICES

Sales of Entergy-Koch Businesses

In the fourth quarter of 2004, Entergy-Koch sold its energy trading and pipeline businesses to third parties. The sales came after a review of strategic alternatives for enhancing the value of Entergy-Koch, LP. Entergy received $862 million of cash distributions in 2004 from Entergy-Koch after the business sales, and Entergy ultimately expects to receive total net cash distributions exceeding $1 billion, comprised of the after-tax cash from the distributions of the sales proceeds and the eventual liquidation of Entergy-Koch. Entergy currently expects that it will receive the remaining cash distributions in 2006, and expects that the net cash distributions will exceed its equity investment in Entergy-Koch. Entergy expects to record a $60 million net-of-tax gain when the remainder of the proceeds are received in 2006.

In the purchase agreements for the energy trading and the pipeline business sales, Entergy-Koch has agreed to indemnify the respective purchasers for certain potential losses relating to any breaches of the sellers' representations, warranties, and obligations under each of the purchase agreements. Entergy Corporation has guaranteed up to 50% of Entergy-Koch's indemnification obligations to the purchasers. Entergy does not expect any material claims under these indemnification obligations, but to the extent that any are asserted and paid, the gain that Entergy expects to record in 2006 may be reduced.

Results of Operations

2004 Compared to 2003

The decrease in earnings for Energy Commodity Services from $180.5 million to $3.5 million was primarily due to:

  • earnings from Entergy's investment in Entergy-Koch were $254 million lower in 2004, primarily as a result of Entergy-Koch's trading business reporting a loss from its operations in 2004; and
  • Entergy recorded a charge in 2004 of approximately $55 million ($36 million net-of-tax) as a result of an impairment of the value of the Warren Power plant, which is owned in the non-nuclear wholesale assets business. Entergy concluded that the plant is impaired based on valuation studies prepared in connection with the Entergy Asset Management stock sale discussed below.

Partially offsetting the decrease in earnings is a tax benefit resulting from the sale of preferred stock and less than 1% of the common stock of Entergy Asset Management, an Entergy subsidiary. In December 2004, an Entergy subsidiary sold the stock to a third party for $29.75 million. The sale resulted in a capital loss for tax purposes of $370 million, producing a net tax benefit of $97 million that Entergy recorded in the fourth quarter of 2004.

2003 Compared to 2002

The increase in earnings for Energy Commodity Services in 2003 from a $145.8 million loss to $180.5 million in earnings was primarily due to net charges recorded to operating expenses in 2002, as discussed below. Higher earnings from Entergy's investment in Entergy-Koch also contributed to the increase in earnings. The income from Entergy's investment in Entergy-Koch was $73 million higher in 2003 primarily as a result of higher earnings in its trading business.

In 2002, Entergy recorded charges to reflect the effect of Entergy's decision to discontinue additional greenfield power plant development and to reflect asset impairments resulting from the deteriorating economics of wholesale power markets principally in the United States and the United Kingdom. The net charges of $428.5 million ($238.3 million net-of-tax) consisted of the following:

  • The power development business obtained contracts in October 1999 to acquire 36 turbines from General Electric. Entergy's rights and obligations under the contracts for 22 of the turbines were sold to an independent special-purpose entity in May 2001. $178.0 million of the charges, including an offsetting net-of-tax benefit of $18.5 million related to the subsequent sale of four turbines to a third party, was a provision for the net costs resulting from cancellation or sale of the turbines subject to purchase commitments with the special-purpose entity;
  • $204.4 million of the charges resulted from the write-off of Entergy Power Development Corporation's equity investment in the Damhead Creek project and the impairment of the values of its Warren Power power plant and its Crete and RS Cogen projects. This portion of the charges reflected Entergy's estimate of the effects of reduced spark spreads in the United States and the United Kingdom. Damhead Creek was sold in December 2002, resulting in net income of $31.4 million;
  • $39.1 million of the charges related to the restructuring of the non-nuclear wholesale assets business, which was comprised of $22.5 million of impairments of administrative fixed assets, $10.7 million of estimated sublease losses, and $5.9 million of employee-related costs;
  • $32.7 million of the charges resulted from the write-off of capitalized project development costs for projects that would not be completed; and
  • a gain of $25.7 million ($15.9 million net-of-tax) realized on the sale in August 2002 of an interest in projects under development in Spain.

PARENT & OTHER

2004 Compared to 2003

The increase in earnings for Parent & Other from a $23.4 million loss to $17.6 million in earnings was primarily due to the following:

  • realization of $16.7 million of tax benefits related to the Entergy-Koch investment; and
  • Entergy's competitive retail business earned a very small profit in 2004 compared to reporting a $14.4 million loss in 2003.

2003 Compared to 2002

The loss from Parent & Other decreased in 2003 from $38.6 million to $23.4 million primarily due to lower income tax expense.

Income Taxes

The effective income tax rates for 2004, 2003, and 2002 were 28.2%, 37.9%, and 32.1%, respectively. See Note 3 to the consolidated financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rates. The lower effective income tax rate in 2004 is primarily due to the tax benefits resulting from the Entergy Asset Management stock sale discussed above.

Liquidity and Capital Resources

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

Capital Structure

Entergy's capitalization is balanced between equity and debt, as shown in the following table. The reduction in the debt to capital percentage from 2002 to 2003 is the result of reduced debt outstanding in the U.S. Utility and Non-Utility Nuclear businesses, and an increase in shareholders' equity, primarily due to increased retained earnings.

 

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

Net debt to net capital at the end of the year

 

44.7%

 

45.3%

 

47.7%

Effect of subtracting cash from debt

 

2.7%

 

2.2%

 

4.1%

Debt to capital at the end of the year

 

47.4%

 

47.5%

 

51.8%

Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable, capital lease obligations, preferred stock with sinking fund, and long-term debt, including the currently maturing portion. Capital consists of debt, common shareholders' equity, and preferred stock without sinking fund. Net capital consists of capital less cash and cash equivalents. The preferred stock with sinking fund is included in debt pursuant to SFAS 150, which Entergy implemented in the third quarter of 2003. The 2002 ratio does not reflect that type of security as debt, but does include it in net capital, which is how Entergy presented those securities prior to implementation of SFAS 150. Entergy uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy's financial condition.

Long-term debt, including the currently maturing portion, makes up over 90% of Entergy's total debt outstanding. Following are Entergy's long-term debt principal maturities as of December 31, 2003 and 2004 by operating segment. The figures below include principal payments on the Entergy Louisiana and System Energy sale-leaseback transactions, which are included in long-term debt on the balance sheet.

Long-term debt maturities

 

2004

 

2005

 

2006

 

2007

 

2008-2009

 

after 2009

 

 

(In Millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2003

 

 

 

 

 

 

 

 

 

 

 

 

U.S. Utility

 

$450

 

$355

 

$28

 

$573

 

$721

 

$4,305

Non-Utility Nuclear

 

74

 

72

 

76

 

80

 

40

 

173

Energy Commodity Services

 

-

 

-

 

-

 

-

 

-

 

-

Parent and Other

 

-

 

60

 

-

 

-

 

539

 

301

Total

$524

$487

$104

$653

$1,300

$4,779

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2004

 

 

 

 

 

 

 

 

 

 

 

 

U.S. Utility

 

-

 

$359

 

$27

 

$98

 

$749

 

$4,880

Non-Utility Nuclear

 

-

 

77

 

76

 

80

 

40

 

173

Energy Commodity Services

 

-

 

-

 

-

 

-

 

-

 

-

Parent and Other

 

-

 

60

 

-

 

50

 

539

 

301

Total

-

$496

$103

$228

$1,328

$5,354

Note 5 to the consolidated financial statements provides more detail concerning long-term debt.

In May 2004, Entergy Corporation replaced its 364-day bank credit facility with two separate facilities, a new 364-day credit facility and a three-year credit facility. The three-year credit facility, which expires in May 2007, has a borrowing capacity of $965 million, of which $50 million was outstanding at December 31, 2004.

In December 2004, Entergy Corporation refinanced the 364-day bank credit facility by entering into a five-year credit facility. The five-year credit facility, which expires in December 2009, has a borrowing capacity of $500 million, none of which was outstanding at December 31, 2004.

Entergy also has the ability to issue letters of credit against the total borrowing capacity of both credit facilities, and $50 million of letters of credit had been issued against the three-year facility at December 31, 2004.

Entergy Corporation's credit facilities require it to maintain a consolidated debt ratio of 65% or less of its total capitalization, and maintain an interest coverage ratio of 2 to 1. If Entergy fails to meet these limits, or if Entergy or the domestic utility companies default on other indebtedness or are in bankruptcy or insolvency proceedings, an acceleration of the credit facilities' maturity dates may occur.

Capital lease obligations, including nuclear fuel leases, are a minimal part of Entergy's overall capital structure, and are discussed further in Note 9 to the consolidated financial statements. Following are Entergy's payment obligations under those leases:

 

2005

 

2006

 

2007

 

2008-2009

 

after 2009

 

(In Millions)

Capital lease payments, including nuclear fuel leases


$136

 


$143

 


$3

 


$2

 


$3

Notes payable, which include borrowings outstanding on credit facilities with original maturities of less than one year, were less than $1 million as of December 31, 2004. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans each have 364-day credit facilities available as follows:


Company

 


Expiration Date

 

Amount of
Facility

 

Amount Drawn as of
Dec. 31, 2004

 

 

 

 

 

 

 

Entergy Arkansas

 

April 2005

 

$85 million

 

-

Entergy Louisiana

 

April 2005

 

$15 million (a)

 

-

Entergy Mississippi

 

May 2005

 

$25 million

 

-

Entergy New Orleans

 

April 2005

 

$14 million (a)

 

-

(a) The combined amount borrowed by Entergy Louisiana and Entergy New Orleans under these facilities at any one time cannot exceed $15 million.

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 or results of operations. Following are Entergy's payment obligations as of December 31, 2004 on non-cancelable operating leases with a term over one year:

 

2005

 

2006

 

2007

 

2008-2009

 

after 2009

 

(In Millions)

 

 

 

 

 

 

 

 

 

 

Operating lease payments

$99

 

$86

 

$69

 

$100

 

$210

The operating leases are discussed more thoroughly in Note 9 to the consolidated financial statements.

Summary of Contractual Obligations of Consolidated Entities

Contractual Obligations

 

2005

 

2006-2007

 

2008-2009

 

after 2009

 

Total

 

 

(In Millions)

 

 

 

 

 

 

 

 

 

 

 

Long-term debt (1)

 

$496

 

$331

 

$1,328

 

$5,354

 

$7,509

Capital lease payments (2)

 

$136

 

$146

 

$2

 

$3

 

$287

Operating leases (2)

 

$99

 

$155

 

$100

 

$210

 

$564

Purchase obligations (3)

 

$1,160

 

$1,402

 

$962

 

$1,156

 

$4,680

(1)

Long-term debt is discussed in Note 5 to the consolidated financial statements.

(2)

Capital lease payments include nuclear fuel leases. Lease obligations are discussed in Note 9 to the consolidated financial statements.

(3)

Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. Approximately 99% of the total pertains to fuel and purchased power obligations that are recovered in the normal course of business through various fuel cost recovery mechanisms in the U.S. Utility business.

In addition to these contractual obligations, Entergy expects to contribute $185.9 million to its pension plans and $63.3 million to other postretirement plans in 2005.

Capital Funds Agreement

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

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

Capital Expenditure Plans and Other Uses of Capital

Following are the amounts of Entergy's planned construction and other capital investments by operating segment for 2005 through 2007:

Planned construction and capital investments

 

2005

 

2006

 

2007

 

 

 

(In Millions)

 

 

  

 

  

 

  

 

Maintenance Capital:

 

 

 

 

 

 

 

U.S. Utility

 

$734

 

$699

 

$763

 

Non-Utility Nuclear

 

72

 

72

 

60

 

Energy Commodity Services

 

3

 

4

 

6

 

Parent and Other

 

11

 

19

 

11

 

 

 

820

 

794

 

840

Capital Commitments:

 

 

 

 

 

 

 

U.S. Utility

 

571

 

349

 

201

 

Non-Utility Nuclear

 

90

 

67

 

43

 

Energy Commodity Services

 

-

 

-

 

-

 

Parent and Other

 

-

 

-

 

-

 

 

 

661

 

416

 

244

Total

 

$1,481

 

$1,210

 

$1,084

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.

Capital Commitments refers to non-routine capital investments for which Entergy is either contractually obligated, has Board-approval, or is otherwise required to make pursuant to a regulatory agreement or existing rule or law. Amounts reflected in this category include the following:

From time to time, Entergy considers other capital investments as potentially being necessary or desirable in the future, including additional nuclear plant power uprates, generation supply assets, various transmission upgrades, environmental compliance expenditures, or investments in new businesses or assets. Because no contractual obligation, commitment, or Board-approval exists to pursue these investments, they are not included in Entergy's planned construction and capital investments. These potential investments are also subject to evaluation and approval in accordance with Entergy's policies before amounts may be spent. In addition, Entergy's capital spending plans do not include spending for transmission upgrades requested by merchant generators, other than projects currently underway.

Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of business restructuring, regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, and the ability to access capital.

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 October 2004 meeting, the Board increased Entergy's quarterly dividend per share by 20%, to $0.54. In 2004, Entergy paid approximately $428 million in cash dividends on its common stock.

In accordance with Entergy's stock-based compensation plan, Entergy periodically grants stock options to its employees, which may be exercised to obtain shares of Entergy's common stock. According to the plan, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy's management has been authorized to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans. In addition to this authority, the Board has approved a program under which Entergy will repurchase up to $1.5 billion of its common stock through 2006. The amount of repurchases under the program may vary as a result of material changes in business results or capital spending, or as a result of material new investment opportunities. In 2004, Entergy repurchased 16,631,800 shares of common stock under both programs for a total purchase price of $1.018 billion.

PUHCA Restrictions on Uses of Capital

Entergy's ability to invest in electric wholesale generators and foreign utility companies is subject to the SEC's regulations under PUHCA. As authorized by the SEC, Entergy is allowed to invest earnings in electric wholesale generators and foreign utility companies in an amount equal to 100% of its average consolidated retained earnings. As of December 31, 2004, Entergy's investments subject to this rule totaled $2.7 billion constituting 55.9% of Entergy's average consolidated retained earnings.

Entergy's ability to guarantee obligations of Entergy's non-utility subsidiaries is also limited by SEC regulations under PUHCA. In August 2000, the SEC issued an order, effective through December 31, 2005, that allows Entergy to issue up to $2 billion of guarantees for the benefit of its non-utility companies. In February 2005, Entergy requested that the SEC increase this limit to $4 billion.

Under PUHCA, the SEC imposes a limit equal to 15% of consolidated capitalization on the amount that may be invested in "energy-related" businesses without specific SEC approval. Entergy has made investments in energy-related businesses, including power marketing and trading. Entergy's available capacity to make additional investments at December 31, 2004 was approximately $1.9 billion.

Sources of Capital

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

  • internally generated funds;
  • cash on hand ($808 million as of December 31, 2004);
  • securities issuances;
  • bank financing under new or existing facilities; and
  • sales of assets.

The majority of Entergy's internally generated funds come from the U.S. Utility. Circumstances such as weather patterns, price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the level of internally generated funds in the future. In the following section, Entergy's cash flow activity for the previous three years is discussed.

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 restrict the payment of cash dividends or other distributions on their common and preferred stock. As of December 31, 2004, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively. Additionally, PUHCA prohibits Entergy Corporation's subsidiaries from making loans or advances to Entergy Corporation. All debt and common and preferred stock issuances by the domestic utility companies and System Energy require prior regulatory approval and their preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. The domestic utility companies and System Energy have sufficient capacity under these tests to meet foreseeable capital needs.

The short-term borrowings of Entergy's subsidiaries are limited to amounts authorized by the SEC. The current limits authorized are effective through November 30, 2007. In addition to borrowing from commercial banks, Entergy's subsidiaries are authorized under the SEC order to borrow from Entergy's money pool. The money pool is an inter-company borrowing arrangement designed to reduce Entergy's subsidiaries' dependence on external short-term borrowings. Borrowings from the money pool and external borrowings combined may not exceed the SEC authorized limits. As of December 31, 2004, Entergy's subsidiaries' aggregate authorized limit was $1.6 billion and the aggregate outstanding borrowing from the money pool was $151.6 million. There were no borrowings outstanding from external sources. Under the SEC order and without further SEC authorization, the domestic utility companies and System Energy cannot issue new short-term indebtedness unless (a) Entergy Corporation and the issuer each maintain common equity of at least 30% of its capital and (b) with the exception of money pool borrowings, the debt security to be issued (if rated) and all outstanding securities of the issuer and Entergy Corporation that are rated must be rated investment grade. See Note 4 to the consolidated financial statements for further discussion of Entergy's short-term borrowing limits.

The short and long-term securities issuances of Entergy Corporation also are limited to amounts authorized by the SEC. Under its current SEC order, and without further SEC authorization, Entergy Corporation cannot incur additional indebtedness or issue other securities unless (a) Entergy Corporation and each of its public utility subsidiaries maintain common equity ratios of at least 30% and (b) the security to be issued (if rated) and all outstanding securities of Entergy Corporation that are rated, are rated investment grade.

The long-term securities issuances of Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and System Energy also are limited to amounts authorized by the SEC. Under the current SEC orders of Entergy Gulf States, Entergy Louisiana, and Entergy Mississippi, and without further SEC authorization, the issuer cannot incur additional indebtedness or issue other securities unless (a) it and Entergy Corporation maintain a common equity ratio of at least 30% and (b) the security to be issued (if rated) and all outstanding securities of the issuer (other than preferred stock of Entergy Gulf States), as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade.

Cash Flow Activity

As shown in Entergy's Statements of Cash Flows, cash flows for the years ended December 31, 2004, 2003, and 2002 were as follows:

     

2004

 

2003

 

2002

     

(In Millions)

               

Cash and cash equivalents at beginning of period

 

$692 

 

$1,335 

 

$752 

               

Cash flow provided by (used in):

           
 

Operating activities

 

2,929 

 

2,006 

 

2,181 

 

Investing activities

 

(1,140)

 

(1,783)

 

(1,388)

 

Financing activities

 

(1,672)

 

(869)

 

(213)

Effect of exchange rates on cash and cash equivalents

 

(1)

 

 

 

Net increase (decrease) in cash and cash equivalents

 

116 

 

(643)

 

583 

               

Cash and cash equivalents at end of period

 

$808 

 

$692 

 

$1,335 

Operating Cash Flow Activity

2004 Compared to 2003

Entergy's cash flow provided by operating activities increased in 2004 primarily due to the following:

  • The U.S. Utility provided $2,208 million in cash from operating activities compared to providing $1,675 million in 2003. The increase resulted primarily from the receipt of intercompany income tax refunds from the parent company, Entergy Corporation. Income tax refunds/payments contributed approximately $400 million of the increase in cash from operating activities in 2004. Improved recovery of fuel costs and a reduction in interest paid also contributed to the increase in 2004.
  • The Non-Utility Nuclear business provided $415 million in cash from operating activities compared to providing $183 million in 2003. The increase resulted primarily from lower intercompany income tax payments and increases in generation and contract pricing that led to an increase in revenues.
  • Entergy's investment in Entergy-Koch, LP provided $526 million in cash from operating activities compared to using $41 million in 2003. Entergy received dividends from Entergy-Koch of $529 million in 2004 compared to $100 million in 2003. In addition, tax payments related to the investment were higher in 2003 because the investment had higher net income in 2003.
  • The non-nuclear wholesale asset business used $46 million in cash from operating activities compared to using $70 million in 2003. The decrease in cash used resulted primarily from a one-time $33 million payment in 2003 related to a generation contract in the non-nuclear wholesale assets business.
  • The parent company, Entergy Corporation, used $146 million in cash from operating activities in 2004 compared to providing $209 million in 2003 primarily due to higher intercompany income tax payments.

As discussed in Note 3 to the consolidated financial statements, in 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The cash benefit from the method change was $74 million on a consolidated basis in 2004. This accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit. As of December 31, 2004, Entergy has a consolidated net operating loss (NOL) carryforward for tax purposes of $2.9 billion, principally resulting from the change in tax accounting method related to cost of goods sold. If the tax accounting method change is sustained, Entergy expects to fully utilize the NOL carryforward through 2006.

2003 Compared to 2002

Entergy's cash flow provided by operating activities decreased in 2003 primarily due to the following:

  • The U.S. Utility provided $1,675 million in operating cash flow in 2003 compared to providing $2,341 million in 2002. The decrease primarily resulted from the tax accounting election made by Entergy Louisiana, as discussed below. Also contributing to the decrease were higher payments for fuel during the period, which also significantly increased the amount of deferred fuel costs.
  • The non-nuclear wholesale assets business used $70 million in operating cash flow in 2003 compared to providing $43 million in 2002 primarily due to a decrease of $64 million in the income tax refund received in 2003 compared to 2002. Also contributing to the increase in cash used was a one-time $33 million payment in 2003 related to a generation contract in the non-nuclear wholesale assets business.
  • The Non-Utility Nuclear segment provided $183 million in operating cash flow in 2003 compared to providing $282 million in 2002 primarily due to higher tax payments and unplanned outages.
  • Operating cash flow used by the investment in Entergy-Koch, LP decreased by $6 million in 2003. This decrease in cash flow used was due to the receipt of $100 million in dividends from Entergy-Koch in 2003. Almost entirely offsetting the dividends received was an increase in tax payments related to Entergy's investment in Entergy-Koch due to increased income from the investment.

Partially offsetting the decrease in cash flow in 2003 was an increase due to the parent company providing $209 million in operating cash flow in 2003 compared to using $439 million in 2002 primarily due to the payment that Entergy Corporation made to Entergy Louisiana in 2002 pursuant to the tax accounting election made by Entergy Louisiana.

In 2001, Entergy Louisiana changed its method of accounting for tax purposes related to its wholesale electric power contracts.  The most significant of these is the contract to purchase power from the Vidalia project (the contract is discussed in Note 8 to the consolidated financial statements). The new tax accounting method has provided a cumulative cash flow benefit of approximately $790 million through 2004, which is expected to reverse in the years 2005 through 2031. The election did not reduce book income tax expense. The timing of the reversal of this benefit depends on several variables, including the price of power. Approximately half of the consolidated cash flow benefit of the election occurred in 2001 and the remainder occurred in 2002. In accordance with Entergy's intercompany tax allocation agreement, the cash flow benefit for Entergy Louisiana occurred in the fourth quarter of 2002.

In a September 2002 settlement of an LPSC proceeding that concerned the Vidalia contract, the LPSC approved Entergy Louisiana's proposed treatment of the regulatory impact of the tax accounting election. In general, the settlement permits Entergy Louisiana to keep a portion of the tax benefit in exchange for bearing the risk associated with sustaining the tax treatment. The LPSC settlement divided the term of the Vidalia contract into two segments: 2002-2012 and 2013-2031. During the first eight years of the 2002-2012 segment, Entergy Louisiana agreed to credit rates by flowing through its fuel adjustment calculation $11 million each year, beginning monthly in October 2002. Entergy Louisiana must credit rates in this way and by this amount even if Entergy Louisiana is unable to sustain the tax deduction. Entergy Louisiana also must credit rates by $11 million each year for an additional two years unless either the tax accounting method elected is retroactively repealed or the Inter nal Revenue Service denies the entire deduction related to the tax accounting method. Entergy Louisiana agreed to credit ratepayers additional amounts unless the tax accounting election is not sustained if it is challenged. During 2013-2031, Entergy Louisiana and its ratepayers would share the remaining benefits of this tax accounting election.

Investing Activities

2004 Compared to 2003

Net cash used in investing activities decreased in 2004 primarily due to the following:

  • Construction expenditures were $158 million lower in 2004 than in 2003, including decreases of $81 million in the U.S. Utility business, $39 million in the Non-Utility Nuclear business, and $42 million in the non-nuclear wholesale assets business.
  • Entergy received net returns of invested capital from Entergy-Koch of $284 million in 2004 after the sale by Entergy-Koch of its trading and pipeline businesses. This activity is reported in the "Decrease in other investments" line in the cash flow statement.
  • Approximately $60 million of the cash collateral for a letter of credit that secures the installment obligations owed to NYPA for the acquisition of the FitzPatrick and Indian Point 3 nuclear power plants was released to Entergy in 2004. Approximately $172 million of this cash collateral was released to Entergy in 2003, and the letter of credit is no longer secured by cash collateral. This activity is reported in the "Decrease in other investments" line in the cash flow statement.
  • The non-nuclear wholesale assets business realized $75 million in net proceeds from sales of portions of three of its power plants in 2004.
  • Entergy made temporary investments of $50 million in 2003, and these investments matured in the first quarter of 2004.
  • Entergy Arkansas used $7 million, Entergy Gulf States used $77 million, and Entergy Mississippi used $73 million for other regulatory investments in 2003 as a result of fuel cost under-recovery. In 2004, Entergy Arkansas used $4 million and Entergy Gulf States used $50 million for other regulatory investments related to fuel cost under-recovery. See Note 1 to the consolidated financial statements for discussion of the accounting treatment of these fuel cost under-recoveries.

2003 Compared to 2002

Net cash used in investing activities increased in 2003 primarily due to the following:

  • The non-nuclear wholesale assets business realized $215 million in net proceeds from sales of businesses in 2002.
  • Temporary investments of $150 million matured in 2002, which provided cash flow in 2002.
  • Temporary investments of $50 million were made in 2003, which used cash flow in 2003.
  • Entergy Gulf States had $77 million and Entergy Mississippi had $73 million of other regulatory investments in 2003 as a result of fuel cost under-recoveries. See Note 1 to the consolidated financial statements for discussion of the accounting treatment of these fuel cost under-recoveries. See Note 2 to the consolidated financial statements for discussion of the change in Entergy Mississippi's energy cost recovery rider.

Partially offsetting these uses of cash, approximately $172 million of the cash collateral for a letter of credit that secures the installment obligations owed to NYPA for the acquisition of the FitzPatrick and Indian Point 3 nuclear power plants was released to Entergy during 2003.

Financing Activities

2004 Compared to 2003

Net cash used in financing activities increased in 2004 primarily due to the following:

  • Entergy Corporation issued $538 million of long-term notes in 2003.
  • Entergy Corporation repurchased $1.018 billion of its common stock in 2004, as discussed above in the "Uses of Capital" section.
  • Entergy Corporation paid $65 million more in common stock dividends in 2004 than in 2003.

Offsetting the factors that caused an increase in cash used in financing activities in 2004 were the following:

  • Retirements of long-term debt net of issuances by the U.S. Utility segment used $345 million in 2004 and used $359 million in 2003. See Note 5 to the consolidated financial statements for the details of the long-term debt activity in 2004.
  • In 2003, Entergy Corporation decreased the net borrowings on its credit facility by $500 million, while in 2004, net borrowings on its credit facilities increased by $50 million.
  • The non-nuclear wholesale assets business retired the $79 million Top of Iowa wind project debt at its maturity in January 2003.

2003 Compared to 2002

Net cash used in financing activities increased in 2003 primarily due to the following:

  • Net long-term debt retirements by the U.S. Utility segment were approximately $470 million in 2003 compared to net issuances of approximately $76 million in 2002. See Note 5 to the consolidated financial statements for the details of Entergy's long-term debt outstanding.
  • The net borrowings under Entergy Corporation's credit facilities decreased $500 million in 2003 compared to an increase of $244 million in 2002.

The items causing cash used to increase in 2003 were partially offset by the following:

  • Entergy Corporation issued $538 million of long-term notes in 2003 compared to $267 million in 2002.
  • The non-nuclear wholesale assets business retired $268 million of long-term debt in 2002 related to the repurchase of the rights to acquire turbines discussed in "Results of Operations" above. Partially offsetting this was the retirement of the $79 million Top of Iowa wind project debt at its maturity in January 2003.
  • Entergy repurchased $8 million of its common stock in 2003 compared to $118 million in 2002.

In a non-cash transaction in 2002, long-term debt was reduced by $488 million in the sale of the Damhead Creek plant when the purchaser assumed the Damhead Creek debt along with the acquisition of the plant.

Significant Factors and Known Trends

Following are discussions of significant factors and known trends affecting Entergy's business, including rate regulation and fuel-cost recovery, federal regulation, market and credit risks, and nuclear matters.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that the domestic utility companies and System Energy charge for their services are an important item influencing Entergy's financial position, results of operations, and liquidity. These companies are closely regulated and the rates charged to their customers are determined in regulatory proceedings, except for a portion of Entergy Gulf States' operations. 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. The status of material retail rate proceedings is summarized below and described in more detail in Note 2 to the consolidated financial statements.

Company

 

Authorized
ROE

 

Pending Proceedings/Events

 

 

 

 

 

Entergy Arkansas

 

11.0%

 

No base rate cases are pending. Transition cost recovery rider approved to collect $8.5 million effective October 2004 with recovery expected over subsequent 16 months. It is likely that a rate filing will be made in 2005 in connection with the ANO 1 steam generator and reactor vessel head replacement.

 

 

 

 

 

Entergy Gulf States-Texas

 

10.95%

 

Base rates are currently set at rates approved by the PUCT in June 1999. Entergy Gulf States filed a retail electric rate case with the PUCT in August 2004. In October 2004, the PUCT issued a written order in which it dismissed the rate case indicating that Entergy Gulf States is still subject to a rate freeze based on an agreement, approved by PUCT order in 2001, stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory, unless lifted by the PUCT prior thereto. Entergy Gulf States has appealed this decision and intends to pursue other available remedies, including legislation that would clarify that it is no longer operating under a rate freeze. In February 2005, bills were filed in the Texas legislature that would clarify that Entergy Gulf States is no longer operating under a rate freeze and specify that retail open access will not commence in Entergy Gulf States' territory until the PUCT certifies a power region.

 

 

 

 

 

Entergy Gulf States-Louisiana

 

11.1%

 

In December 2003, the LPSC staff recommended a $30.6 million rate refund and a prospective rate reduction of approximately $50 million as a result of the ninth post-merger earnings analysis (2002). Hearings concluded in May 2004. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement that would resolve, among other dockets, Entergy Gulf States' ninth post-merger review, and dockets established to consider issues concerning the companies' power purchases for the summers of 2001, 2002, 2003, and 2004. The proposed settlement currently includes an offer to refund $76 million to Entergy Gulf States' Louisiana customers through a credit on bills rendered in March 2005, with no immediate change in the current base rates. The settlement also proposes a formula rate plan with an ROE mid-point of 10.65%. The LPSC has solicited comments on the proposed settlement from the parties to the various proceedings at issue in the settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005.

 

 

 

 

 

Entergy Louisiana

 

9.7%-
11.3%(1)

 

In January 2004, Entergy Louisiana filed with the LPSC an application for a $167 million base rate increase and an ROE of 11.4%. The currently authorized ROE midpoint is 10.5%. Hearings in this matter concluded in December 2004. Based on the evidence submitted at the hearing, the LPSC staff is recommending approximately a $7 million base rate increase. The LPSC staff proposed the implementation of a formula rate plan that includes a provision for the recovery of incremental capacity costs, including those related to the proposed Perryville acquisition. A decision by the LPSC is expected in mid- to late-March 2005 on these issues.

In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement with the LPSC that would resolve, among other dockets, dockets established to consider issues concerning the companies' power purchases for the summers of 2001, 2002, 2003, and 2004. The proposed settlement currently includes an offer to refund $14 million to Entergy Louisiana's customers. The LPSC has solicited comments on the proposed settlement from the parties to the various proceedings at issue in the proposed settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005.

 

 

 

 

 

Entergy Mississippi

 

9.3%-
12.2%(2)

 

An annual formula rate plan is in place. Entergy Mississippi made its annual formula rate plan filing in March 2004 based on a 2003 test year. There was no change in rates based on an adjusted ROE midpoint of 10.77%.

 

 

 

 

 

Entergy New Orleans

 

10.25%-
12.25%(3)

 

The midpoint ROE of the electric and gas plans is 11.25%, with a target equity component of the capital structure of 42%. Entergy New Orleans made a formula rate plan filing in April 2004. The City Council ordered that electric and gas rates remain unchanged from levels set in 2003. Entergy New Orleans will file its formula rate plan for the year ended December 31, 2004 by May 1, 2005 and also intends to file for an extension of the formula rate plan by September 1, 2005. If the formula rate plan is not extended by the City Council, the rate adjustments in effect based on the December 31, 2004 test year shall continue.

 

 

 

 

 

System Energy

 

10.94%

 

ROE approved by July 2001 FERC order. No cases pending before FERC.

(1)

Entergy Louisiana's formula rate plan expired with the 2001 test year. Under the expired formula, if Entergy Louisiana earned outside of the bandwidth range, rates would be adjusted on a prospective basis. If earnings were above the bandwidth range, rates would be reduced by 60 percent of the amount necessary to bring earnings down to the top of the bandwidth, and if earnings were below the bandwidth range, rates would be increased by 60 percent of the corresponding shortfall.

(2)

Under Mississippi law and Entergy Mississippi's formula rate plan, if Entergy Mississippi's earned ROE is above the top of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's rates are reduced by 50 percent of the difference between the earned ROE and the top of the bandwidth. In such circumstance, Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the point halfway between such earned ROE and the top of the bandwidth - - Entergy Mississippi's retail rates are set at that halfway-point ROE level. (Before the comparison is made of the earned ROE to the bandwidth, the bandwidth can be adjusted for performance measures by as much as 1%. Rates are adjusted pursuant to Entergy Mississippi's formula rate plan on a prospective basis only.) In the situation where Entergy Mississippi's earned ROE is not above the top of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the top of the range-of-no-change at the top of the bandwidth. If earnings are below the bandwidth range, rates are increased by 50 percent of the difference between the earned ROE and the bottom of the bandwidth. Under the provisions of Entergy Mississippi's formula rate plan, each annual formula rate plan filing incorporates a revised calculation of the benchmark ROE.

 

(3)

If Entergy New Orleans earns outside the bandwidth range, rates will be adjusted on a prospective basis. Under the gas formula rate plan, if earnings are above the bandwidth range, rates are reduced by 100 percent of the overage, and if below, increased by 100 percent of the shortfall. In addition, if the ROE falls between 11.5% and 12.25%, rates are reduced by 60 percent of the difference (between 11.5% and 12.25%), and if the ROE falls between 10.25% and 11%, rates are increased by 40 percent of the difference (between 10.25% and 11%). Under the electric formula rate plan, rates are adjusted accordingly by 100 percent of the amount of any overage or shortfall. Entergy New Orleans may earn up to 13.25% under the electric formula rate plan provided that the increase is caused by its share of energy cost savings under the generation performance-based recovery plan.

In addition to the regulatory scrutiny connected with base rate proceedings, the domestic utility companies' fuel and purchased power costs recovered from customers are subject to regulatory scrutiny. The domestic utility companies' significant fuel and purchased power cost proceedings are described in Note 2 to the consolidated financial statements.

Federal Regulation

The FERC regulates wholesale rates (including Entergy intrasystem sales 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 1 to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement.

System Agreement Litigation

The domestic utility companies historically have engaged in the coordinated planning, construction, and operation of generating and transmission facilities under the terms of an agreement called the System Agreement that has been approved by the FERC. Litigation involving the System Agreement is being pursued by the LPSC at both the FERC and before itself. These proceedings include challenges to the allocation of costs as defined by the System Agreement, raise questions of imprudence by the domestic utility companies in their execution of the System Agreement, and seek support for local regulatory authority over System Agreement issues. Regarding the proceeding at the LPSC, Entergy believes that state and local regulators are preempted by federal law from reviewing and deciding System Agreement issues for themselves. An unrelated case between the LPSC and Entergy Louisiana raised the question of whether a state regulator is preempted by federal law from reviewing and interpreting F ERC rate schedules that are part of the System Agreement, and from subsequently enforcing that interpretation. The LPSC interpreted a System Agreement rate schedule in the unrelated case, and then sought to enforce its interpretation. The Louisiana Supreme Court affirmed the LPSC's decision. In 2003, the U.S. Supreme Court ruled in Entergy Louisiana's favor and reversed the decisions of the LPSC and the Louisiana Supreme Court.

In February 2004, a FERC ALJ issued an Initial Decision in the LPSC-initiated proceeding at the FERC. The Initial Decision decided some issues in favor of the relief sought by the LPSC, and decided some issues against the relief sought by the LPSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the ALJ's Initial Decision. Entergy's exceptions to the ALJ's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they would be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method.

If the FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to companies whose costs currently are projected to exceed that average.   If the FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALJ's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility compan ies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost.

An assessment of the potential effects of the ALJ's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power.  Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation.  Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies.  Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004 period, and averaging $3.43/mmBtu duri ng the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004.  Recent market conditions have resulted in gas prices that have averaged $5.85/mmBtu for the twelve months ended December 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009:

 


Range of Annual Payments
or (Receipts)

 

Average Annual
Payments or (Receipts)
for 2005-2009 Period

 

(In Millions)

 

(In Millions)

       

Entergy Arkansas

$154 to $281 

 

$215                 

Entergy Gulf States

($130) to ($15)

 

($63)                

Entergy Louisiana

($199) to ($98)

 

($141)

Entergy Mississippi

($16) to $8 

 

$1                 

Entergy New Orleans

($17) to ($5)

 

($12)               

Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers. The timing of recovery of these costs in rates could be the subject of additional proceedings at the APSC and elsewhere, however, and a delay in full recovery of any increased allocation of production costs could result in additional financing requirements. Although the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy does not believe that the ultimate resolution of these proceedings will have a material effect on its financial condition or results of operation.

In February 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC ALJ's Initial Decision would have on Entergy Arkansas' customers. The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement is in the best interest of its customers, and whether there are steps that Entergy Arkansas or the APSC can take "to protect [Entergy Arkansas' customers] from future attempts by Louisiana, or any other Entergy retail regulator, to shift its high costs to Arkansas." Entergy Arkansas filed testimony in response to the APSC's Order of Investigation. The testimony emphasizes that the ALJ's Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with the FERC; emphasizes that Entergy will seek to reverse the production cost-related portions of the Initial Decision; an d states that Entergy Arkansas believes that it is premature, before the FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate.

In April 2004, the APSC commenced the investigation into Entergy Louisiana's Vidalia purchased power contract and requested historical documents, records, and information from Entergy Arkansas, which Entergy Arkansas has provided to the APSC. Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, or show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Entergy Arkansas filed a response in May 2004 stating that Entergy will seek to reverse the production cost-related portions of the ALJ's Initial Decision in the System Agreement proceeding at the FERC, that the Perryville acquisition is part of Entergy's request for proposal generation planning process, that Entergy Arkansas is not in a position to indemnify its retail customers from actions taken by the FERC, and that the Perryville acquisition is expected to reduce the domestic utility companies' overall production costs. Procedural schedules have not been established in these APSC investigations.

In April 2004, the City Council issued a resolution directing Entergy New Orleans and Entergy Louisiana to notify the City Council and obtain prior approval for any action that would materially modify, amend, or terminate the System Agreement for one or more of the domestic utility companies. Entergy New Orleans and Entergy Louisiana appealed to state court the City Council's resolution on the basis that the imposition of this requirement with respect to the System Agreement, a FERC-approved tariff, exceeds the City Council's jurisdiction and authority. In July 2004, the City Council answered the appeal and filed a third party demand and counterclaim against Entergy, the domestic utility companies, Entergy Services, and System Energy, seeking a declaratory judgment that Entergy and its subsidiaries cannot terminate the System Agreement until obligations owed under a March 2003 rate case settlement are satisfied. In August 2004, Entergy New Orleans and Entergy Lou isiana, as well as the named third party defendants, filed pleadings objecting to the City Council's third party demand and counterclaim on various grounds, including federal preemption. In February 2005, the state court issued an oral decision dismissing the City Council's claims for lack of subject matter jurisdiction and prematurity.

Transmission

In 2000, FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays in implementing the FERC order have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to work to resolve various issues related to the establishment of such RTOs.

In April 2004, Entergy filed a proposal with the FERC to commit voluntarily to retain an independent entity (Independent Coordinator of Transmission or ICT) to oversee the granting of transmission or interconnection service on Entergy's transmission system, to implement a transmission pricing structure that ensures that Entergy's retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs, and to have the ICT serve as the security coordinator for the Entergy region. Assuming applicable regulatory support and approvals can be obtained, Entergy proposed to contract with the ICT to oversee the granting of transmission service on the Entergy system as well as the implementation of the proposed weekly procurement process (WPP). The proposal was structured to not transfer control of Entergy's transmission system to the ICT, but rather to vest with the ICT broad oversight authority over transmission planning and operations.

Entergy also proposed to have the ICT administer a transmission expansion pricing protocol that will increase the efficiency of transmission pricing on the Entergy system and that will be designed to protect Entergy's native load customers from bearing the cost of transmission upgrades not required to reliably serve these customers' needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC, and any party contesting such determination, including Entergy, would be required to seek review at the FERC. Several technical conferences regarding the ICT proposal, or various components thereof, were held in 2004. Entergy has also responded to discovery requests that resulted from these conferences.

In January 2005, Entergy filed a petition for declaratory order with the FERC requesting that the FERC provide guidance on two important issues: (1) whether the functions performed by the ICT will cause it to become a "public utility" under the Federal Power Act or the "transmission provider" under Entergy's open access transmission tariff; and (2) whether Entergy's transmission pricing proposal, as administered by the ICT, satisfies the FERC's transmission pricing policy. The petition also indicates that, subject to the outcome of the petition and obtaining support of Entergy's retail regulators, Entergy would be willing to have the ICT perform the following additional functions: (a) grant or deny requests for transmission service; (b) calculate available flowgate capacity; (c) administer Entergy's OASIS; and (d) perform an enhanced planning function (integrating the plans of Entergy and other potential transmission owners to identify regional synergies.) Comments and interventions on the petition were filed by market participants and retail regulators on February 4, 2005. In their individual comments, the APSC, LPSC, and City Council supported Entergy's position that the ICT would not become a "public utility" or "transmission provider" and that the transmission pricing proposal satisfies the FERC's transmission pricing policy. Certain other parties urged the FERC to reject the petition for declaratory order or, in the alternative, that the FERC assert jurisdiction over the ICT and determine that Entergy's proposed pricing policy is inconsistent with FERC's current pricing policy. FERC action on the petition is expected during the first half of 2005.

In March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC sought comments from all interested parties on this issue. Various parties, including the APSC General Staff, filed comments opposing the ICT proposal. A public hearing has not been scheduled by the APSC at this time, although Entergy Arkansas has responded to various APSC data requests. In May 2004, Entergy Mississippi filed a petition for review with the MPSC requesting MPSC support for the ICT proposal. A hearing in that proceeding was held in August 2004. Additionally, Entergy Louisiana and Entergy Gulf States have filed an application with the LPSC requesting that the LPSC find that the ICT proposal is a prudent and appropriate course of action. A hearing on the transmission pricing aspects of the ICT proposal is scheduled for May 2005, with a separate hearing on the WPP portion of th e proposal currently scheduled for August 2005.

FERC's Supply Margin Assessment

In November 2001, FERC issued an order that established a new generation market power screen (called Supply Margin Assessment) for purposes of evaluating a utility's request for market-based rate authority, applied that new screen to the Entergy System (among others), determined that Entergy and the others failed the screen within their respective control areas, and ordered these utilities to implement certain mitigation measures as a condition to their continued ability to buy and sell at market-based rates. Among other things, the mitigation measures would require that Entergy transact at cost-based rates when it sells in the hourly wholesale market within its control area. Entergy requested rehearing of the order, and FERC delayed the implementation of certain mitigation measures until such time as it had the opportunity to consider the rehearing request. In June 2003, the FERC proposed and ultimately adopted new market behavior rules and tariff provisions that would be applied to any market-based sale. Entergy modified its market-based rate tariffs to reflect the new provisions but requested rehearing of FERC's order.

In April 2004, the FERC issued its Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy. In its April 2004 order, the FERC established a new interim generation market power analysis that will consider two indicative market power screens: (1) the pivotal supplier screen that is designed to measure an applicant's market power based on the applicant's share of uncommitted capacity at the time of the control area market's annual peak demand; and (2) the market share screen that is designed to evaluate an applicant's market share of uncommitted capacity on a seasonal basis. An integrated utility's native load obligation will be reflected in both screens; however, the proxy for native load obligation differs between the screens. For the uncommitted pivotal supplier screen, the proxy for native load is the average of the daily native load peaks during the month in which the annual peak load day occurs; for the uncommitted market share screen the prox y for native load is the minimum peak load day for each season. In the event an applicant fails either of these screens, there will be a rebuttable presumption that market power exists. The applicant will then have the opportunity to either: (1) submit a more detailed market power analysis that reflects market prices and measures an applicant's "economic capacity" and "available economic capacity" under the "delivered price test;" or (2) propose case-specific mitigation tailored to the applicant's specific circumstances or adopt cost-based rates for sales within the applicant's control area.

In its April 2004 order, the FERC also: (1) determined that transmission market power and the need to employ an independent entity to operate and administer an applicant's OASIS site is more properly considered in other proceedings, to the extent appropriate, and would not be considered in evaluating an applicant's generation market power for purposes of granting market-based rate authority; and (2) eliminated the exemption from the generation market power analysis for sales within an RTO/ISO that had approved market monitoring. Several parties, including Entergy, filed for rehearing of the April 2004 order. Among other things, Entergy argued that the market share screen is overly conservative and overstates vertically integrated utilities' ability to exercise market power.

In July 2004, the FERC issued an order on rehearing reaffirming the use of the pivotal supplier and market share screens and clarified certain instructions for performing such analysis. With regard to the delivered price test analysis, the FERC declined to make a determination on whether an applicant's native load obligations will be reflected when evaluating an applicant's generation market power, but instead indicated that it would evaluate the arguments of both the applicant and intervenors as to which measure (one with or without native load obligations) more accurately reflects market conditions. Entergy appealed the April 2004 and July 2004 orders to the United States Court of Appeals for the District of Columbia Circuit. In February 2005, the D.C. Circuit granted the FERC's motion to dismiss Entergy's appeal on the grounds that Entergy's claims were premature. The D.C. Circuit found that Entergy's petition was premature because the D.C. Circuit was not yet in a position to evalu ate the manner in which the FERC will apply its new market power tests or whether the tests will have adverse consequences for Entergy. Thus, the D.C. Circuit did not rule on the merits of Entergy's appeal.

Entergy filed with the FERC its generation market power analysis pursuant to the two indicative screens in August 2004. Entergy's analysis indicated that it passed the pivotal supplier screen for all relevant geographical regions, but failed the market share screen within its control area. At the same time, Entergy submitted the results of the delivered price test for Entergy, which indicate that Entergy does not have market power in any wholesale market when Entergy's native load obligations are reflected.

In December 2004, the FERC issued an order pursuant to Section 206 of the Federal Power Act: (1) finding that Entergy failed the market share screen; (2) indicating that the FERC is continuing to review the delivered price test analysis submitted by Entergy; (3) establishing a refund effective date for Entergy's market-based wholesale sales within its control area; and (4) indicating that the FERC believes that it can reach a decision concerning Entergy's market-based rate authority by the second quarter of 2005.

If the FERC were to revoke Entergy's or the domestic utility companies' market-based rate authority for wholesale sales within the Entergy control area, these entities would be limited to making wholesale sales pursuant to cost-based rate schedules approved by the FERC. The wholesale sales of the domestic utility companies and their affiliates, including Entergy's non-nuclear wholesale assets business, within the Entergy control area could either be cost-justified or are of such a limited amount that management does not believe that the revocation of their market-based rate authority would have a material effect on the financial results of Entergy. Because Entergy believes that it does not possess market power and that the FERC's tests are flawed, Entergy intends to vigorously defend its market-based rate authority.

The FERC has also initiated a rulemaking proceeding to address, among other things, whether the FERC should retain or modify its existing four-prong test for evaluating market-based rate applications (i.e., whether the applicant has generation or transmission market power, whether the applicant can erect barriers to entry, and whether there are affiliate abuse or reciprocal dealing concerns), and whether the FERC should adopt different approaches for affiliate transactions. The FERC has held a series of technical conferences to discuss these issues. Additionally, in February 2005 the FERC adopted revised reporting obligations for changes in status that apply to public utilities authorized to make wholesale sales of power at market-based rates. The FERC determined to replace the current triennial reporting requirement with more detailed guidelines concerning the types of events that will trigger a reporting obligation and the timing and format for such reports. The new rules will become part of all existing market-based rate tariffs during March 2005.

Interconnection Orders

The domestic utility companies (except Entergy New Orleans) are currently defendants to several complaints and rehearing requests before the FERC in which independent generation entities (GenCos) are seeking a refund of monies that the GenCos had previously paid to the Entergy companies for facilities necessary to connect their generation facilities to Entergy's transmission system. The FERC has issued initial orders in response to two of the complaints and in certain other dockets ordering Entergy to refund approximately $100 million in expenses and tax obligations previously paid by the GenCos. The refunds will be in the form of transmission credits that will be utilized over time as the GenCos take transmission service from Entergy.

In addition, Entergy Louisiana was recently directed, effective as of March 2001, to provide transmission credits, with interest, associated with a specific generator that asserted to the FERC that it retained in its contract for interconnection a right to execute the latest form of Entergy's standard interconnection agreement in lieu of its existing contract, which thereby would apply FERC's most recent interconnection cost allocation policies to that generator. Following an ALJ's Initial Decision and an order affirming such decision by FERC, approximately $15 million in expenses and tax obligations previously paid by the generator have been ordered refunded in the form of transmission credits, to be utilized over time and applied to Entergy transmission service bills incurred after March 2001. Entergy has sought rehearing of the FERC's order.

To the extent the Entergy companies are ordered to provide such refunds, these costs will qualify for inclusion in the Entergy companies' rates. The recovery of these costs is not automatic, however, especially at the retail level, where the majority of the cost recovery would occur. Entergy intends to pursue all regulatory and legal avenues available to it in order to have these orders reversed and have the affected interconnection agreements reinstated as agreed to originally by the generators.

Available Flowgate Capacity Proceeding

On December 17, 2004, the FERC issued an order initiating a hearing and investigation concerning the justness and reasonableness of the Available Flowgate Capacity (AFC) methodology, the methodology used to evaluate short-term transmission service requests under the domestic utility companies' open access transmission tariff, and establishing a refund effective date. In its order, the FERC indicated that although it "appreciates that Entergy is attempting to explore ways to improve transmission access on its system," it believed that an investigation was warranted to gather more evidence in light of the concerns raised by certain transmission customers and certain issues raised in a FERC audit report finding errors and problems with the predecessor methodology used by Entergy for evaluating short-term transmission requests, the Generator Operating Limits methodology. The FERC order indicates that the investigation will include an examination of (i) Entergy's implementation of the AFC pro gram, (ii) whether Entergy's implementation has complied with prior FERC orders and open access transmission tariff provisions addressing the AFC program, and (iii) whether Entergy's provision of access to short-term transmission on its transmission system was just, reasonable, and not unduly discriminatory.

Entergy has submitted an Emergency Interim Request for Rehearing requesting the FERC to defer the hearing process and instead proceed initially with an independent audit of the AFC program and the expansion of the current process involving other market participants to address a broader range of issues. Entergy believes that this type of approach is a more efficient and effective mechanism for evaluating the AFC program. Following the completion of the independent audit and process involving other market participants, the FERC could determine whether other procedural steps are necessary. The FERC has not yet ruled on the Emergency Interim Request for Rehearing submitted by Entergy.

Entergy believes that it has complied with the provisions of its open access transmission tariff, including the provisions addressing the implementation of the AFC methodology; however, the ultimate scope of this proceeding cannot be predicted at this time. A hearing in the AFC proceeding is currently scheduled to commence in August 2005.

Federal Legislation

Federal legislation intended to facilitate wholesale competition in the electric power industry has been seriously considered by the United States Congress for the past several years.  In the last Congress, both the House and Senate passed separate versions of comprehensive energy legislation, negotiated a conference package, and fell two votes short of bringing the conferenced bill up for a vote in the Senate. The bill contained electricity provisions that would, among other things, allow for participant funding of transmission interconnections and upgrades, repeal PUHCA, repeal or modify PURPA, enact a mechanism for establishing enforceable reliability standards, provide the FERC with new authority over utility mergers and acquisitions, and codify the FERC's authority over market-based rates.  It is expected that the United States House and Senate will again craft and consider energy legislation in the 109th Congr ess.

Market and Credit Risks

Market risk is the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Entergy is exposed to the following significant market risks:

  • The commodity price risk associated with Entergy's Non-Utility Nuclear and Energy Commodity Services segments.
  • The foreign currency exchange rate risk associated with certain of Entergy's contractual obligations.
  • The interest rate and equity price risk associated with Entergy's investments in decommissioning trust funds.

Entergy is also exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Where it is a significant consideration, counterparty credit risk is addressed in the discussions that follow.

Commodity Price Risk

Power Generation

The sale of electricity from the power generation plants owned by Entergy's Non-Utility Nuclear business and Energy Commodity Services, unless otherwise contracted, is subject to the fluctuation of market power prices. Entergy's Non-Utility Nuclear business has entered into PPAs and other contracts to sell the power produced by its power plants at prices established in the PPAs. Entergy continues to pursue opportunities to extend the existing PPAs and to enter into new PPAs with other parties. Following is a summary of the amount of the Non-Utility Nuclear business' output that is currently sold forward under physical or financial contracts at fixed prices:

   

2005

 

2006

 

2007

 

2008

 

2009

Non-Utility Nuclear:

                   

Percent of planned generation sold forward:

                   
 

Unit-contingent

 

36%

 

20%

 

17%

 

1%

 

0%

 

Unit-contingent with availability guarantees

 

54%

 

52%

 

38%

 

25%

 

0%

 

Firm liquidated damages

 

4%

 

4%

 

2%

 

0%

 

0%

 

Total

 

94%

 

76%

 

57%

 

26%

 

0%

Planned generation (TWh)

 

34

 

35

 

34

 

34

 

35

Average contracted price per MWh

 

$39

 

$41

 

$42

 

$44

 

N/A

The Vermont Yankee acquisition included a 10-year PPA under which the former owners will buy the power produced by the plant, which is through the expiration in 2012 of the current operating license for the plant. The PPA includes an adjustment clause under which the prices specified in the PPA will be adjusted downward monthly, beginning in November 2005, if power market prices drop below PPA prices. Accordingly, because the price is not fixed, the table above does not report power from that plant as sold forward after November 2005.

A sale of power on a unit contingent basis coupled with an availability guarantee 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. To date, Entergy has not incurred any payment obligation to any power purchaser pursuant to an availability guarantee. All of Entergy's outstanding availability guarantees provide for dollar limits on Entergy's maximum liability under such guarantees.

Some of the agreements to sell the power produced by Entergy's Non-Utility Nuclear power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements. The Entergy subsidiary may be required to provide collateral based upon the difference between the current market and contracted power prices in the regions where the Non-Utility Nuclear business sells its power.  The primary form of the collateral to satisfy these requirements would be an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of collateral. At December 31, 2004, based on power prices at that time, Entergy had in place as collateral $545.5 million of Entergy Corporation guarantees and $47.5 million of letters of credit. In the event of a decrease in Entergy Corporation's credit rating to specified levels below investment grade, Entergy may be required to replace Entergy Corporation guarantees with cash or letters of c redit under some of the agreements.

In addition to selling the power produced by its plants, the Non-Utility Nuclear business sells installed capacity to load-serving distribution companies in order for those companies to meet requirements placed on them by the ISO in their area. Following is a summary of the amount of the Non-Utility Nuclear business' installed capacity that is currently sold forward, and the blended amount of the Non-Utility Nuclear business' planned generation output and installed capacity that is currently sold forward:

   

2005

 

2006

 

2007

 

2008

 

2009

Non-Utility Nuclear:

                   

Percent of capacity sold forward:

                   
 

Bundled capacity and energy contracts

 

13%

 

13%

 

13%

 

13%

 

13%

 

Capacity contracts

 

58%

 

67%

 

36%

 

22%

 

10%

 

Total

 

71%

 

80%

 

49%

 

35%

 

23%

Planned net MW in operation

 

4,155

 

4,200

 

4,200

 

4,200

 

4,200

Average capacity contract price per kW per month

 

$1.2

 

$1.1

 

$1.1

 

$1.0

 

$0.9

Blended Capacity and Energy (based on revenues)

                   

% of planned generation and capacity sold forward

 

93%

 

87%

 

65%

 

36%

 

12%

Average contract revenue per MWh

 

$40

 

$42

 

$43

 

$44

 

$43

As of December 31, 2004, approximately 99% of Entergy's counterparties to Non-Utility Nuclear's energy and capacity contracts have investment grade credit ratings.

Following is a summary of the amount of Energy Commodity Services' output and installed capacity that is currently sold forward under physical or financial contracts at fixed prices:

   

2005

 

2006

 

2007

 

2008

 

2009

Energy Commodity Services:

                   

Capacity

                   

Planned MW in operation

 

1,578

 

1,578

 

1,578

 

1,578

 

1,578

% of capacity sold forward

 

44%

 

33%

 

29%

 

29%

 

19%

Energy

                   

Planned generation (TWh)

 

3

 

3

 

3

 

3

 

4

% of planned generation sold forward

 

69%

 

54%

 

45%

 

45%

 

35%

Blended Capacity and Energy (based on revenues)

                   

% of planned energy and capacity sold forward

 

63%

 

44%

 

38%

 

39%

 

22%

Average contract revenue per MWh

 

$24

 

$24

 

$28

 

$28

 

$21

Entergy continually monitors industry trends in order to determine whether asset impairments or other losses could result from a decline in value, or cancellation, of merchant power projects, and records provisions for impairments and losses accordingly. As discussed in "Results of Operations" above, in 2004 Entergy determined that the value of the Warren power plant owned by the non-nuclear wholesale assets business was impaired, and recorded the appropriate provision for the loss.

Foreign Currency Exchange Rate Risk

Entergy Gulf States, System Fuels, and Entergy's Non-Utility Nuclear business enter into foreign currency forward contracts to hedge the Euro-denominated payments due under certain purchase contracts. The notional amounts of the foreign currency forward contracts are 95.5 million Euro and the forward currency rates range from .8641 to 1.33020. The maturities of these forward contracts depend on the purchase contract payment dates and range in time from January 2005 to January 2007. The mark-to-market valuation of the forward contracts at December 31, 2004 was a net asset of $28.1 million. The counterparty banks obligated on these agreements are rated by Standard & Poor's Rating Services at AA on their senior debt obligations as of December 31, 2004.

Interest Rate and Equity Price Risk - Decommissioning Trust Funds

9; Entergy's nuclear decommissioning trust funds are exposed to fluctuations in equity prices and interest rates. The NRC requires Entergy to maintain trusts to fund the costs of decommissioning ANO 1, ANO 2, River Bend, Waterford 3, Grand Gulf, Pilgrim, Indian Point 1 and 2, and Vermont Yankee (NYPA currently retains the decommissioning trusts and liabilities for Indian Point 3 and FitzPatrick). The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that exposure of the various funds to market fluctuations will not affect Entergy's financial results of operations as it relates to the ANO 1 and 2, River Bend, Grand Gulf, and Waterford 3 trust funds because of the application of regulatory accounting principles. The Pilgrim, Indian Point 1 and 2, and Vermont Yankee trust funds collectively hold approximately $952 million of fixed-rate, fixed-income securities as of December 31, 2004. These securities have an average coup on rate of approximately 5.4%, an average duration of approximately 5.2 years, and an average maturity of approximately 7.9 years. The Pilgrim, Indian Point 1 and 2, and Vermont Yankee trust funds also collectively hold equity securities worth approximately $450 million as of December 31, 2004. These securities are generally held in funds that are designed to approximate or somewhat exceed the return of the Standard & Poor's 500 Index, and a relatively small percentage of the securities are held in a fund intended to replicate the return of the Wilshire 4500 Index. The decommissioning trust funds are discussed more thoroughly in Notes 1, 8, and 15 to the consolidated financial statements.

Nuclear Matters

The domestic utility companies, System Energy, and Non-Utility Nuclear subsidiaries own and operate ten nuclear power generating units and the shutdown Indian Point 1 nuclear reactor. Entergy is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks from the use, storage, handling, and disposal of high-level and low-level radioactive materials, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shut-down of any of Entergy's nuclear plants, Entergy may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.

Concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel, in particular in the northeastern United States, which is where the Non-Utility Nuclear units are located. These concerns have led to, and are expected to continue to lead to, various proposals to federal regulators as well as governing bodies in some localities where Entergy owns nuclear plants for legislative and regulatory changes that could lead to the shut-down of nuclear units, denial of license extension applications, municipalization of nuclear units, restrictions on nuclear units as a result of unavailability of sites for nuclear fuel disposal, or other adverse effects on owning and operating nuclear power plants. Entergy believes that its generating units are in compliance with NRC requirements and Entergy vigorously responds to these concerns and proposals.

Litigation

Entergy and its subsidiaries are involved in the ordinary course of business in a substantial amount of employment, commercial, asbestos, hazardous material, and other environmental and rate-related proceedings and litigation. Entergy uses legal and appropriate means to contest vigorously litigation threatened or filed against it, but litigation poses a significant business risk to Entergy.

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 the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy's financial position or results of operations.

Nuclear Decommissioning Costs

Entergy owns a significant number of nuclear generation facilities in both its U.S. Utility and Non-Utility Nuclear business units. Regulations require Entergy to decommission its 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 (typically updated every three to five years) 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 decommissioning revenue requirement studies include an assumption that decommissioning costs will escalate over present cost levels by annual factors ranging from approximately CPI-U to 5.5%. A 50 basis point change in this assumption could change the ultimate cost of decommissioning a facility by as much as 11.0%.
  • 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. The expiration of the plant's operating license is typically used for this purpose, or an assumption could be made that the plant will be relicensed and operate for some time beyond the original license term. Second, an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in "safestore" status for later decommissioning, as permitted by applicable regulations. While the effect of these assumptions cannot be determined with precision, assuming either license extension or use of a "safestore" status can possibly change the present value of these obligations. As discussed in Note 8 to the consolidated financial statements, Entergy recorded revisions in 2004 to its estimated decommissioning cost liability for four of its nuclear power plants to reflect changes in assumptions regarding license renewal. Increases in the probability of decommissioning the plants at a date later than the original license expiration lowered the estimate of the decommissioning cost liability. The changes in probability for the unregulated portion of Entergy Gulf States and Entergy's Non-Utility Nuclear business increased income by approximately $28.9 million net-of-tax for the excess of the reduction in the liability over the amount of undepreciated asset retirement cost at the time of adoption of SFAS 143. The changes in probability for ANO 1 and ANO 2 had no effect on net income because, as discussed further below, any amounts recorded related to SFAS 143 are offset by the recording of regulatory assets or regulatory liabilities when projected decommissioning costs are collected in rates. Future revisions to appropriately reflect changes needed to the estimate of decommissioning costs will affect net income, 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, for unregulated portions of Entergy's business. Any increases in the liability recorded due to such changes are capitalized and depreciated over the asset's remaining economic life in accordance with SFAS 143.
  • Spent Fuel Disposal - Federal regulations require the DOE to provide a permanent repository for the storage of spent nuclear fuel, and legislation has been passed by Congress to develop this repository at Yucca Mountain, Nevada. Until this 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 can have a significant effect (as much as 16% of estimated decommissioning costs). Entergy's decommissioning studies include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors.
  • Technology and Regulation - To date, there is limited practical experience in the United States with actual decommissioning of large nuclear facilities. As experience is gained and technology changes, cost estimates could also change. 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. Entergy's decommissioning cost studies assume current technologies and regulations.

SFAS 143

Entergy implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs comprise substantially all of Entergy's asset retirement obligations, and the measurement and recording of Entergy's decommissioning obligations changed significantly with the implementation of SFAS 143. The most significant differences in the measurement of these obligations are outlined below:

  • Recording of full obligation - SFAS 143 requires that the fair value of an asset retirement obligation be recorded when it is incurred. This caused the recorded decommissioning obligation in Entergy's U.S. Utility business to increase significantly, as Entergy had previously only recorded this obligation as the related costs were collected from customers, and as earnings were recorded on the related trust funds.
  • Fair value approach - SFAS 143 requires that these obligations be measured using a fair value approach. Among other things, this entails the assumption that the costs will be incurred by a third party and will therefore include appropriate profit margins and risk premiums. Entergy's decommissioning studies had been based on Entergy performing the work, and did not include any such margins or premiums.
  • Discount rate - SFAS 143 requires that these obligations be discounted using a credit-adjusted, risk-free rate.

The net effect on Entergy's financial statements of implementing SFAS 143 for the U.S. Utility and Non-Utility Nuclear businesses follows:

  • For the U.S. Utility business, the implementation of SFAS 143 for the rate-regulated business of the domestic utility companies and System Energy was recorded as regulatory assets, with no resulting effect on Entergy's net income. Entergy recorded these regulatory assets because existing rate mechanisms in each jurisdiction are based on the original or historical cost standard that allows Entergy to recover all ultimate costs of decommissioning existing assets from current and future customers. As a result of this treatment, SFAS 143 is expected to be earnings neutral to the rate-regulated business of the domestic utility companies and System Energy. Upon implementation of SFAS 143 in 2003, assets and liabilities increased by $1.1 billion for the U.S. Utility segment as a result of recording the asset retirement obligations at their fair values of $1.1 billion as determined under SFAS 143, increasing utility plant by $288 million, reducing accumulated depreciation by $361 million and recording the rel ated regulatory assets of $422 million. The implementation of SFAS 143 for the portion of River Bend not subject to cost-based ratemaking decreased earnings by $21 million net-of-tax ($0.09 per share) as a result of a one-time cumulative effect of accounting change. In accordance with ratemaking treatment and as required by SFAS 71, the depreciation provisions for Entergy's utility subsidiaries include a component for removal costs that are not asset retirement obligations under SFAS 143. Approximately 6% of the U.S. Utility's current depreciation rates, on a weighted-average basis, represents a component for the net of salvage value and removal costs.
  • For the Non-Utility Nuclear business, the implementation of SFAS 143 in 2003 resulted in a decrease in liabilities of $595 million due to reductions in decommissioning liabilities, a decrease in assets of $340 million, including a decrease in electric plant in service of $315 million, and an increase in earnings of $155 million net-of-tax as a result of the one-time cumulative effect of accounting change.

Also, beginning in 2003 Entergy's earnings for the Non-Utility Nuclear business have an increase of $18 million after-tax because of the change in accretion of the liability and depreciation of the adjusted plant costs from the 2002 levels. This effect will gradually decrease over future years as the accretion of the liability increases. Management expects that applying SFAS 143 post-implementation will have a minimal effect on ongoing earnings for the U.S. Utility business.

In the first quarter of 2004, Entergy Arkansas recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for ANO 1 and 2 as a result of revised decommissioning costs and changes in assumptions regarding the timing of when the decommissioning of the plants will begin. The revised estimate resulted in a $107.7 million reduction in its decommissioning liability, along with a $19.5 million reduction in utility plant and an $88.2 million reduction in the related regulatory asset.

In the third quarter of 2004, Entergy Gulf States recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for River Bend that reflected an expected life extension for the plant. The revised estimate resulted in a $116.8 million reduction in decommissioning liability, along with a $31.3 million reduction in utility plant, a $40.1 million reduction in the related regulatory asset, and a regulatory liability of $17.7 million. For the portion of River Bend not subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous income of $27.7 million.

In the third quarter of 2004, Entergy's Non-Utility Nuclear business recorded a reduction of $20.3 million in its decommissioning cost liability to reflect changes in assumptions regarding the timing of when the decommissioning of a plant will begin. Entergy considered the assumptions as part of recent studies evaluating the economic effect of the plant in its region. The revised estimate resulted in miscellaneous income of $20.3 million, reflecting the excess of the reduction in the liability over the amount of undepreciated asset retirement cost recorded at the time of adoption of SFAS 143.

Unbilled Revenue

As discussed in Note 1 to the consolidated 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, including fuel price. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period and fuel price fluctuations, in addition to changes in certain components of the calculation including changes to estimates such as line loss, which affects the estimate of unbilled customer usage, and assumptio ns regarding price such as the fuel cost recovery mechanism.

Impairment of Long-lived Assets

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, and these estimates are particularly important in Entergy's U.S. Utility and Energy Commodity Services segments. In the U.S. Utility segment, portions of River Bend and Grand Gulf are not included in rate base, which could reduce the revenue that would otherwise be recovered for the applicable portions of those units' generation. In the Energy Commodity Services segment, Entergy's investments in merchant generation assets are subject to impairment if adverse market conditions arise.

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. 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. There is currently an oversupply of electricity throughout the U.S., including much of Entergy's service territory, and it is necessary to project economic growth and other macroeconomic factors in order to project when this oversupply will cease and prices will rise. Similarly, gas prices have been volatile as a result of recent fluctuations in both supply and demand, and projecting future trends in these prices is difficult.
  • 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.

Due to the oversupply of power that existed throughout the U.S. and the UK in 2002, and the resulting decreases in spark spreads, consistent with Entergy's point of view, Entergy's impairment tests indicated that a number of impairments were required to be recognized in 2002 in the Energy Commodity Services segment. These impairments, which were also accompanied by other charges related to the restructuring of Entergy's independent power business, are further detailed in Note 11 to the consolidated financial statements.

In 2004, Entergy recorded a charge of approximately $55 million ($36 million net-of-tax) as a result of an impairment of the value of the Warren Power plant. Entergy concluded that the value of the plant, which is owned in the non-nuclear wholesale assets business, was impaired. Entergy reached this conclusion based on valuation studies prepared in connection with the Entergy Asset Management stock sale discussed above in "Results of Operations."

Pension and Other Postretirement Benefits

Entergy sponsors 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 while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 10 to the consolidated 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 U.S. Utility and Non-Utility Nuclear segments.

Assumptions

Key actuarial assumptions utilized in determining these costs include:

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

Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and worse-than-expected performance of the financial equity markets over the past several years 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.

In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and matches these rates with Entergy's projected stream of benefit payments. Based on recent market trends, Entergy reduced its discount rate used to calculate benefit obligations from 6.75% in 2002 to 6.25% in 2003 and to 6% in 2004. Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy increased its health care cost trend rate assumption used in calculating the December 31, 2004 accumulated postretirement benefit obligation to a 10% increase in health care costs in 2005 gradually decreasing each successive year, until it reaches a 4.5% annual increase in health care costs in 2011 and beyond.

In determining its expected long-term rate of return on plan assets, Entergy reviews past long-term performance, asset allocations, and long-term inflation assumptions. Entergy targets an asset allocation for its pension plan assets of roughly 65% equity securities, 31% fixed income securities and 4% other investments. The target allocation for Entergy's other postretirement benefit assets is 51% equity securities and 49% fixed income securities. Based on recent market trends, Entergy reduced its expected long-term rate of return on plan assets used to calculate benefit obligations from 8.75% for 2002 and 2003 to 8.5% in 2004. The assumed rate of increase in future compensation levels used to calculate benefit obligations was 3.25% in 2002, 2003, and 2004.

Cost Sensitivity

The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions (in thousands):


Actuarial Assumption

 

Change in
Assumption

 

Impact on 2004
Pension Cost

 

Impact on Projected
Benefit Obligation

 

 

Increase/(Decrease)

 

 

 

 

 

 

 

Discount rate

 

(0.25%)

 

$10,268

 

$94,903

Rate of return on plan assets

 

(0.25%)

 

$4,388          

 

-              

Rate of increase in compensation

 

0.25%

 

$4,928          

 

$29,134

The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (in thousands):



Actuarial Assumption

 


Change in
Assumption

 


Impact on 2004
Postretirement Benefit Cost

 

Impact on Accumulated
Postretirement Benefit
Obligation

 

 

Increase/(Decrease)

 

 

 

 

 

 

 

Health care cost trend

 

0.25%

 

$4,150

 

$23,892

Discount rate

 

(0.25%)

 

$2,715

 

$28,719

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

Accounting Mechanisms

In accordance with SFAS No. 87, "Employers' Accounting for Pensions," Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into cost only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.

Additionally, Entergy accounts for the effect of asset performance on pension expense over a twenty-quarter phase-in period through a "market-related" value of assets calculation. Since the market-related value of assets recognizes investment gains or losses over a twenty-quarter period, the future value of assets will be impacted as previously deferred gains or losses are recognized. As a result, the losses that the pension plan assets experienced in 2002 may have an adverse impact on pension cost in future years depending on whether the actuarial losses at each measurement date exceed the 10% corridor in accordance with SFAS 87.

Costs and Funding

In 2004, Entergy's total pension cost was $98 million. Entergy anticipates 2005 pension cost to increase to $117 million due to decreases in the discount rate (from 6.25% to 6.00%) and the expected rate of return (from 8.75% to 8.5%) used to calculate benefit obligations. Pension funding was $73 million for 2004 and in 2005 is projected to be $186 million. The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, offset by the Pension Funding Equity Act relief passed in April 2004.

Entergy's accumulated benefit obligation at December 31, 2004, 2003, and 2002 exceeded plan assets. As a result, Entergy was required to recognize an additional minimum pension liability as prescribed by SFAS 87. At December 31, 2004, Entergy increased its additional minimum pension liability to $244 million ($218 million net of related pension assets) from $180 million ($149 million net of related pension assets) at December 31, 2003. Other comprehensive income decreased to $6.6 million at December 31, 2004 from $9.3 million at December 31, 2003, after reductions for the unrecognized prior service cost, amounts recoverable in rates, and taxes. Net income for 2004, 2003, and 2002 was not affected.

Total postretirement health care and life insurance benefit costs for Entergy in 2004 were $86 million, including $23 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy expects 2005 postretirement health care and life insurance benefit costs to approximate $96 million, including a projected $27 million in savings due to the estimated effect of future Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the decrease in the discount rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate used to calculate benefit obligations.

Other Contingencies

Entergy, as a company with multi-state domestic utility operations, and which also had investments in international projects, is subject to a number of federal, state, and international laws and regulations and other factors and conditions in the areas in which it operates, which potentially subject it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a reserve for those matters which are considered probable and estimable in accordance with generally accepted accounting principles.

Environmental

Entergy must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. Under these various laws and regulations, Entergy could incur substantial costs to restore properties consistent with the various standards. Entergy conducts studies to determine the extent of any required remediation and has recorded reserves based upon its evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites could be identified which require environmental remediation for which Entergy could be liable. The amounts of environmental reserves recorded can be significantly affected by the following external events or conditions:

  • Changes to existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters.
  • The identification of additional sites or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party.
  • The resolution or progression of existing matters through the court system or resolution by the EPA.

Litigation

Entergy has been named as defendant in a number of lawsuits involving employment, ratepayer, and injuries and damages issues, among other matters. Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably estimable, or remote and records reserves for cases which have a probable likelihood of loss and can be estimated. Notes 2 and 8 to the consolidated financial statements include more detail on ratepayer and other lawsuits and management's assessment of the adequacy of reserves recorded for these matters. Given the environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, however, the ultimate outcome of the litigation Entergy is exposed to has the potential to materially affect the results of operations of Entergy, or its operating company subsidiaries.

Sales Warranty and Tax Reserves

Entergy's operations, including acquisitions and divestitures, require Entergy to evaluate risks such as the potential tax effects of a transaction, or warranties made in connection with such a transaction. Entergy believes that it has adequately assessed and provided for these types of risks, where applicable. Any reserves recorded for these types of issues, however, could be significantly affected by events such as claims made by third parties under warranties, additional transactions contemplated by Entergy, or completion of reviews of the tax treatment of certain transactions or issues by taxing authorities. Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued in the financial statements. Entergy does not expect a material adverse effect on earnings from these matters.

(Page left blank intentionally)

ENTERGY CORPORATION AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
                     
    2004   2003   2002   2001   2000
    (In Thousands, Except Percentages and Per Share Amounts)
                     
Operating revenues   $10,123,724   $9,194,920   $8,305,035   $9,620,899   $10,022,129
Income before cumulative effect of accounting change   $933,049   $813,393   $623,072   $727,025   $710,915
Earnings per share before cumulative effect of accounting change                    
  Basic   $4.01   $3.48   $2.69   $3.18   $3.00
  Diluted   $3.93   $3.42   $2.64   $3.13   $2.97
Dividends declared per share   $1.89   $1.60   $1.34   $1.28   $1.22
Return on common equity   10.70%   11.21%   7.85%   10.04%   9.62%
Book value per share, year-end   $38.25   $38.02   $35.24   $33.78   $31.89
Total assets   $28,310,777   $28,527,388   $27,504,366   $25,910,311   $25,451,896
Long-term obligations (1)   $7,180,291   $7,497,690   $7,488,919   $7,743,298   $8,214,724
                     
                     
(1) Includes long-term debt (excluding currently maturing debt), preferred stock with sinking fund, and noncurrent capital lease obligations.
                     
    2004   2003   2002   2001   2000
    (Dollars In Millions)
Electric Operating Revenues:                    
  Residential   $2,842   $2,683   $2,440   $2,613    $2,525
  Commercial   2,045   1,882   1,673   1,860    1,700
  Industrial   2,311   2,082   1,850   2,299    2,177
  Governmental   200   195   179   205    185
    Total retail   7,398   6,842   6,142   6,977    6,587
  Sales for resale   390   371   330   395    424
  Other (1)   145   184   174   (127)   209
    Total   $7,933   $7,397   $6,646   $7,245    $7,220
Billed Electric Energy Sales (GWh):                    
  Residential   32,897   32,817   32,581   31,080    31,998
  Commercial   26,468   25,863   25,354   24,706    24,657
  Industrial   40,293   38,637   41,018   41,577    43,956
  Governmental   2,568   2,651   2,678   2,593    2,605
    Total retail   102,226   99,968   101,631   99,956    103,216
  Sales for resale   8,623   9,248   9,828   8,896    9,794
    Total   110,849   109,216   111,459   108,852    113,010
                     
                     
(1) 2001 includes the effect of a reserve for rate refund at System Energy.                    
                     

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Entergy Corporation:

We have audited the accompanying consolidated balance sheets of Entergy Corporation and subsidiaries (the "Corporation") as of December 31, 2004 and 2003, and the related consolidated statements of income; of retained earnings, comprehensive income, and paid-in capital; and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Entergy-Koch, LP, the Corporation's investment in which is accounted for by the use of the equity method. The Corporation's equity in earnings of unconsolidated equity affiliates for the year ended December 31, 2003 includes $180,110,000 for Entergy Koch, LP, which earnings were audited by other auditors whose report (which as to 2003 included an explanatory paragraph concerning a change in accounting for inventory held for trading purposes and energy trading contracts not qualifying as derivatives) has been furnished to us, and our opinion for the year ended December 31, 2003, insofar as it relates to the amount audited by other auditors included for such company, is based solely on the report of such other auditors.

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

In our opinion, based on our audits and the report of other auditors, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Corporation and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 1, 5 and 8 to the Form 10-K consolidated financial statements, Entergy Corporation adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, and Statement of Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, in 2003, and SFAS No. 142, Goodwill and Other Intangible Assets, in 2002.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Corporation's internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control - - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Corporation's internal control over financial reporting and an unqualified opinion on the effectiveness of the Corporation's internal control over financial reporting.

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 8, 2005

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
 
    For the Years Ended December 31,
    2004   2003   2002
    (In Thousands, Except Share Data)
             
OPERATING REVENUES            
Domestic electric   $7,932,577    $7,397,175    $6,646,414 
Natural gas   208,499    186,176    125,353 
Competitive businesses   1,982,648    1,611,569    1,533,268 
TOTAL   10,123,724    9,194,920    8,305,035 
             
OPERATING EXPENSES            
Operating and Maintenance:            
  Fuel, fuel-related expenses, and            
   gas purchased for resale   2,488,208    1,987,217    2,154,596 
  Purchased power   2,092,922    1,728,526    833,829 
  Nuclear refueling outage expenses   166,072    159,995    105,592 
  Provisions for turbine commitments, asset impairments            
   and restructuring charges   55,000    (7,743)   428,456 
  Other operation and maintenance   2,303,561    2,453,869    2,486,617 
Decommissioning   149,529    146,100    76,417 
Taxes other than income taxes   409,886    405,659    380,462 
Depreciation and amortization   895,593    850,503    839,181 
Other regulatory credits - net   (90,611)   (13,761)   (141,836)
TOTAL   8,470,160    7,710,365    7,163,314 
             
OPERATING INCOME   1,653,564    1,484,555    1,141,721 
             
OTHER INCOME            
Allowance for equity funds used during construction   39,582    42,710    31,658 
Interest and dividend income   109,809    87,386    118,325 
Equity in earnings (loss) of unconsolidated equity affiliates   (78,727)   271,647    183,878 
Miscellaneous - net   53,752    (76,505)   13,892 
TOTAL   124,416    325,238    347,753 
             
INTEREST AND OTHER CHARGES            
Interest on long-term debt   463,384    485,964    526,442 
Other interest - net   41,380    53,553    70,560 
Allowance for borrowed funds used during construction   (25,741)   (33,191)   (24,538)
TOTAL   479,023    506,326    572,464 
             
INCOME BEFORE INCOME TAXES AND            
CUMULATIVE EFFECT OF ACCOUNTING CHANGES   1,298,957    1,303,467    917,010 
             
Income taxes   365,908    490,074    293,938 
             
INCOME BEFORE CUMULATIVE EFFECT            
OF ACCOUNTING CHANGES   933,049    813,393    623,072 
             
CUMULATIVE EFFECT OF ACCOUNTING            
CHANGES (net of income taxes of $89,925)   - -    137,074    - - 
             
CONSOLIDATED NET INCOME   933,049    950,467    623,072 
             
Preferred dividend requirements and other   23,525    23,524    23,712 
             
EARNINGS APPLICABLE TO            
COMMON STOCK   $909,524    $926,943    $599,360 
             
             
Earnings per average common share before cumulative            
effect of accounting changes:            
  Basic   $4.01    $3.48    $2.69 
  Diluted   $3.93    $3.42    $2.64 
Earnings per average common share:            
  Basic   $4.01    $4.09    $2.69 
  Diluted   $3.93    $4.01    $2.64 
Dividends declared per common share   $1.89    $1.60    $1.34 
Average number of common shares outstanding:            
  Basic   226,863,758    226,804,370    223,047,431 
  Diluted   231,193,686    231,146,040    227,303,103 
             
See Notes to Consolidated Financial Statements.            
             

 

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
   
    For the Years Ended December 31,
    2004   2003   2002
    (In Thousands)
   
OPERATING ACTIVITIES            
Consolidated net income   $933,049    $950,467    $623,072 
Adjustments to reconcile consolidated net income to net cash flow            
provided by operating activities:            
  Reserve for regulatory adjustments   33,533    13,090    18,848 
  Other regulatory credits - net   (90,611)   (13,761)   (141,836)
  Depreciation, amortization, and decommissioning   1,045,122    996,603    915,597 
  Deferred income taxes and investment tax credits   275,458    1,189,531    (256,664)
  Cumulative effect of accounting changes     (137,074)  
  Equity in earnings (loss) of unconsolidated equity affiliates - net of dividends   608,141    (176,036)   (181,878)
  Provisions for turbine commitments, asset impairments, and restructuring charges   55,000    (7,743)   428,456 
  Changes in working capital:            
    Receivables   (210,419)   (140,612)   (43,957)
    Fuel inventory   (16,769)   (14,015)   1,030 
    Accounts payable   95,306    (60,164)   286,230 
    Taxes accrued   75,055    (882,446)   462,956 
    Interest accrued   5,269    (35,837)   7,209 
    Deferred fuel   213,627    (33,874)   156,181 
    Other working capital accounts   41,008    16,809    (286,232)
  Provision for estimated losses and reserves   (18,041)   196,619    10,533 
  Changes in other regulatory assets   48,626    22,671    71,132 
  Other   (164,035)   121,592    111,026 
Net cash flow provided by operating activities   2,929,319    2,005,820    2,181,703 
             
INVESTING ACTIVITIES            
Construction/capital expenditures   (1,410,610)   (1,568,943)   (1,530,301)
Allowance for equity funds used during construction   39,582    42,710    31,658 
Nuclear fuel purchases   (238,170)   (224,308)   (250,309)
Proceeds from sale/leaseback of nuclear fuel   109,988    150,135    183,664 
Proceeds from sale of assets and businesses   75,430    25,987    215,088 
Investment in nonutility properties   (6,420)   (71,438)   (216,956)
Decrease in other investments   383,498    172,187    38,964 
Changes in other temporary investments   50,000    (50,000)   150,000 
Decommissioning trust contributions and realized change in trust assets   (89,807)   (91,518)   (84,914)
Other regulatory investments   (53,566)   (156,446)   (39,390)
Other     (11,496)   114,033 
Net cash flow used in investing activities   (1,140,075)   (1,783,130)   (1,388,463)
             
See Notes to Consolidated Financial Statements.            
             
             
             
             
ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
    For the Years Ended December 31,
    2004   2003   2002
    (In Thousands)
     
FINANCING ACTIVITIES            
Proceeds from the issuance of:            
  Long-term debt   1,059,824    2,221,164    1,197,330 
  Common stock and treasury stock   170,237    217,521    130,061 
Retirement of long-term debt   (1,478,894)   (2,409,917)   (1,341,274)
Repurchase of common stock   (1,017,996)   (8,135)   (118,499)
Redemption of preferred stock   (3,450)   (3,450)   (1,858)
Changes in credit line borrowings - net   49,846    (499,975)   244,333 
Dividends paid:            
  Common stock   (427,901)   (362,814)   (298,991)
  Preferred stock   (23,525)   (23,524)   (23,712)
Net cash flow used in financing activities   (1,671,859)   (869,130)   (212,610)
             
Effect of exchange rates on cash and cash equivalents   (1,882)   3,345    3,125 
             
Net increase (decrease) in cash and cash equivalents   115,503    (643,095)   583,755 
             
Cash and cash equivalents at beginning of period   692,233    1,335,328    751,573 
             
Cash and cash equivalents at end of period   $807,736    $692,233    $1,335,328 
             
             
             
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:            
  Cash paid during the period for:            
    Interest - net of amount capitalized   $477,768    $552,017    $633,931 
    Income taxes   $28,241    $188,709    $57,856 
  Noncash investing and financing activities:            
    Debt assumed by the Damhead Creek purchaser       $488,432 
    Decommissioning trust funds acquired in nuclear power plant acquisitions       $310,000 
    Long-term debt refunded with proceeds from            
     long-term debt issued in prior period       ($47,000)
             
See Notes to Consolidated Financial Statements.            
             
             

 

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
         
    December 31,
    2004   2003
    (In Thousands)
         
CURRENT ASSETS        
Cash and cash equivalents:        
  Cash   $79,136    $115,112 
  Temporary cash investments - at cost,        
   which approximates market   728,600    576,813 
  Special deposits     308 
     Total cash and cash equivalents   807,736    692,233 
Other temporary investments     50,000 
Notes receivable   3,092    1,730 
Accounts receivable:        
  Customer   435,191    398,091 
  Allowance for doubtful accounts   (23,758)   (25,976)
  Other   342,289    246,824 
  Accrued unbilled revenues   460,039    384,860 
     Total receivables   1,213,761    1,003,799 
Deferred fuel costs   85,911    245,973 
Accumulated deferred income taxes   76,899   
Fuel inventory - at average cost   127,251    110,482 
Materials and supplies - at average cost   569,407    548,921 
Deferred nuclear refueling outage costs   107,782    138,836 
Prepayments and other   116,279    127,270 
TOTAL   3,108,118    2,919,244 
         
OTHER PROPERTY AND INVESTMENTS        
Investment in affiliates - at equity   231,779    1,053,328 
Decommissioning trust funds   2,453,406    2,278,533 
Non-utility property - at cost (less accumulated depreciation)   219,717    262,384 
Other   90,992    152,681 
TOTAL   2,995,894    3,746,926 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric   29,053,340    28,035,899 
Property under capital lease   738,554    751,815 
Natural gas   262,787    236,622 
Construction work in progress   1,197,551    1,380,982 
Nuclear fuel under capital lease   262,469    278,683 
Nuclear fuel   320,813    234,421 
TOTAL PROPERTY, PLANT AND EQUIPMENT   31,835,514    30,918,422 
Less - accumulated depreciation and amortization   13,139,883    12,619,625 
PROPERTY, PLANT AND EQUIPMENT - NET   18,695,631    18,298,797 
         
DEFERRED DEBITS AND OTHER ASSETS        
Regulatory assets:        
  SFAS 109 regulatory asset - net   746,413    830,539 
  Other regulatory assets   1,429,261    1,398,323 
Long-term receivables   39,417    20,886 
Goodwill   377,172    377,172 
Other   918,871    935,501 
TOTAL   3,511,134    3,562,421 
         
TOTAL ASSETS   $28,310,777    $28,527,388 
         
See Notes to Consolidated Financial Statements.        
 
 
ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
         
    December 31,
    2004   2003
    (In Thousands)
         
CURRENT LIABILITIES        
Currently maturing long-term debt   $492,564    $524,372 
Notes payable   193    351 
Accounts payable   896,528    796,572 
Customer deposits   222,320    199,620 
Taxes accrued   224,011    224,926 
Accumulated deferred income taxes     22,963 
Nuclear refueling outage costs   -    8,238 
Interest accrued   144,478    139,603 
Obligations under capital leases   133,847    159,978 
Other   218,442    145,453 
TOTAL   2,332,383    2,222,076 
         
NON-CURRENT LIABILITIES        
Accumulated deferred income taxes and taxes accrued   5,067,381    4,779,513 
Accumulated deferred investment tax credits   399,228    420,248 
Obligations under capital leases   146,060    153,898 
Other regulatory liabilities   329,767    291,239 
Decommissioning and retirement cost liabilities   2,066,277    2,215,490 
Transition to competition    79,101    79,098 
Regulatory reserves   103,061    69,528 
Accumulated provisions   549,914    506,960 
Long-term debt   7,016,831    7,322,940 
Preferred stock with sinking fund   17,400    20,852 
Other   1,541,331    1,407,551 
TOTAL   17,316,351    17,267,317 
         
Commitments and Contingencies        
         
Preferred stock without sinking fund   365,356    334,337 
         
SHAREHOLDERS' EQUITY        
Common stock, $.01 par value, authorized 500,000,000        
  shares; issued 248,174,087 shares in 2004 and in 2003   2,482    2,482 
Paid-in capital   4,835,375    4,767,615 
Retained earnings   4,984,302    4,502,508 
Accumulated other comprehensive loss   (93,453)   (7,795)
Less - treasury stock, at cost (31,345,028 shares in 2004 and        
  19,276,445 shares in 2003)   1,432,019    561,152 
TOTAL   8,296,687    8,703,658 
         
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY   $28,310,777    $28,527,388 
         
See Notes to Consolidated Financial Statements.        
         

 

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS, COMPREHENSIVE INCOME, AND PAID-IN CAPITAL
 
                             
        For the Years Ended December 31,
        2004   2003   2002
        (In Thousands)
                             
RETAINED EARNINGS                            
                             
Retained Earnings - Beginning of period       $4,502,508        $3,938,693        $3,638,448     
                             
  Add: Earnings applicable to common stock       909,524    $909,524    926,943    $926,943    599,360    $599,360 
                             
  Deduct:                            
    Dividends declared on common stock       427,740        362,941        299,031     
    Capital stock and other expenses       (10)       187        84     
     Total       427,730        363,128        299,115     
                             
Retained Earnings - End of period       $4,984,302        $4,502,508        $3,938,693     
                             
                             
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Net of taxes):                            
Balance at beginning of period:                            
  Accumulated derivative instrument fair value changes       ($25,811)       $17,313        ($17,973)    
  Other accumulated comprehensive income (loss) items       18,016        (39,673)       (70,821)    
     Total       (7,795)       (22,360)       (88,794)    
                             
                             
Net derivative instrument fair value changes                            
  arising during the period       (115,600)   (115,600)   (43,124)   (43,124)   35,286    35,286 
                             
Foreign currency translation       1,882    1,882    4,169    4,169    65,948    (15,487)
                             
Minimum pension liability       2,762    2,762    1,153    1,153    (10,489)   (10,489)
                             
Net unrealized investment gains (losses)       25,298    25,298    52,367    52,367    (24,311)   (24,311)
                             
Balance at end of period:                            
  Accumulated derivative instrument fair value changes       (141,411)       (25,811)       17,313     
  Other accumulated comprehensive income (loss) items       47,958        18,016        (39,673)    
     Total       ($93,453)       ($7,795)       ($22,360)    
Comprehensive Income          
$823,866 
      $941,508        $584,359 
                             
                             
                             
PAID-IN CAPITAL                            
                             
Paid-in Capital - Beginning of period       $4,767,615        $4,666,753        $4,662,704     
                             
  Add:                            
    Common stock issuances related to stock plans       67,760        100,862        4,049     
                             
Paid-in Capital - End of period      
$4,835,375 
     
$4,767,615 
     
$4,666,753 
   
                             
                             
                             
See Notes to Consolidated Financial Statements.                            

ENTERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The accompanying consolidated financial statements include the accounts of Entergy Corporation and its direct and indirect subsidiaries. As required by generally accepted accounting principles, all significant intercompany transactions have been eliminated in the consolidated financial statements. The domestic utility companies and System Energy maintain accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications, with no effect on net income or shareholders' equity.

Use of Estimates in the Preparation of Financial Statements

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

Revenues and Fuel Costs

The domestic utility companies generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, including the City of New Orleans, Mississippi, and Texas. Entergy Gulf States distributes gas to retail customers in and around Baton Rouge, Louisiana and Entergy New Orleans distributes gas to retail customers in the City of New Orleans. Entergy's Non-Utility Nuclear and Energy Commodity Services segments derive almost all of their revenue from sales of electric power generated by plants owned by them.

Entergy recognizes revenue from electric power and gas sales when it delivers power or gas to its customers. To the extent that deliveries have occurred but a bill has not been issued, the domestic utility companies accrue an estimate of the revenues for energy delivered since the latest billings. Entergy calculates the estimate based upon several factors including billings through the last billing cycle in a month, actual generation in the month, historical line loss factors, and prices in effect in the domestic utility companies' various jurisdictions. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. Therefore, changes in price and volume differences resulting from factors such as weather affect the calculation of unbilled revenues from one period to the next, and may result in variability in reported revenues from one period to the next as prior estimates are so recorded and reversed.

The domestic utility companies' rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Because the fuel adjustment clause mechanism allows monthly adjustments to recover fuel costs, Entergy Louisiana, Entergy New Orleans, and the Louisiana portion of Entergy Gulf States include a component of fuel cost recovery in their unbilled revenue calculations. Where the fuel component of revenues is billed based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing. Entergy Mississippi's fuel factor includes an energy cost rider that is adjusted quarterly. As discussed in Note 2 to the consolidated financial statements, the MPSC approved Entergy Mississippi's deferral of the refund of over-recoveries for the third quarte r of 2004 that would have been refunded in the first quarter of 2005. The deferred amount plus carrying charges will be refunded in the second and third quarters of 2005. In the case of Entergy Arkansas and the Texas portion of Entergy Gulf States, their fuel under-recoveries are treated as regulatory investments in the cash flow statements because those companies are allowed by their regulatory jurisdictions to recover the fuel cost regulatory asset over longer than a twelve-month period, and the companies earn a carrying charge on the under-recovered balances.

System Energy's operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are computed by allowing a return on System Energy's common equity funds allocable to its net investment in Grand Gulf, plus System Energy's effective interest cost for its debt allocable to its investment in Grand Gulf.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost. For the domestic utility companies and System Energy, the original cost of plant retired or removed, less salvage, is charged to accumulated depreciation. Normal maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the domestic utility companies' and System Energy's plant is subject to mortgage liens.

Electric plant includes the portions of Grand Gulf and Waterford 3 that have been sold and leased back. For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions.

Net property, plant, and equipment by business segment and functional category, as of December 31, 2004 and 2003, is shown below:



2004

 



Entergy

 


U.S.
Utility

 


Non-Utility
Nuclear

 

Energy
Commodity
Services

 


Parent and
Other

 

 

(In Millions)

Production

 

 

 

 

 

 

 

 

 

 

Nuclear

 

$7,308

 

$5,987

 

$1,321

 

$-

 

$-

Other

 

1,533

 

1,228

 

-

 

305

 

-

Transmission

 

2,182

 

2,182

 

-

 

-

 

-

Distribution

 

4,672

 

4,672

 

-

 

-

 

-

Other

 

1,123

 

1,115

 

-

 

-

 

8

Construction work in progress

 

1,198

 

924

 

244

 

2

 

28

Nuclear fuel (leased and owned)

 

583

 

297

 

286

 

-

 

-

Asset retirement obligation

 

97

 

97

 

-

 

-

 

-

Property, plant, and equipment - net

 

$18,696

 

$16,502

 

$1,851

 

$307

 

$36



2003

 



Entergy

 


U.S.
Utility

 


Non-Utility
Nuclear

 

Energy
Commodity
Services

 


Parent and
Other

 

 

(In Millions)

Production

 

 

 

 

 

 

 

 

 

 

Nuclear

 

$7,056

 

$6,112

 

$944

 

$-

 

$-

Other

 

1,816

 

1,359

 

-

 

457

 

-

Transmission

 

2,067

 

2,067

 

-

 

-

 

-

Distribution

 

4,231

 

4,231

 

-

 

-

 

-

Other

 

1,079

 

1,069

 

-

 

-

 

10

Construction work in progress

 

1,381

 

954

 

398

 

-

 

29

Nuclear fuel (leased and owned)

 

513

 

298

 

215

 

-

 

-

Asset retirement obligation

 

156

 

155

 

-

 

1

 

-

Property, plant, and equipment - net

 

$18,299

 

$16,245

 

$1,557

 

$458

 

$39

Depreciation is computed on the straight-line basis at rates based on the estimated service lives of the various classes of property. Depreciation rates on average depreciable property approximated 2.8% in 2004 and 2003, and 2.9% in 2002. Included in these rates are the depreciation rates on average depreciable utility property of 2.7% in 2004 and 2.8% in 2003 and 2002 and the depreciation rates on average depreciable non-utility property of 3.8% in 2004, 3.3% in 2003, and 4.0% in 2002.

Non-utility property - at cost (less accumulated depreciation) is reported net of accumulated depreciation of $152.8 million and $145.2 million as of December 31, 2004 and 2003, respectively.

Jointly-Owned Generating Stations

Certain Entergy subsidiaries jointly own electric generating facilities with third parties. The investments and expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, 2004, the subsidiaries' investment and accumulated depreciation in each of these generating stations were as follows:



Generating Stations

 



Fuel-Type

 

Total
Megawatt
Capability (1)

 



Ownership

 



Investment

 


Accumulated
Depreciation

 

 

 

 

 

 

 

 

 

(In Millions)

U.S. Utility:

 

 

 

 

 

 

 

 

 

 

 

Grand Gulf

Unit 1

 

Nuclear

 

1,270

 

90.00% (2)

 

$3,702

 

$1,780

Independence

Units 1 and 2

 

Coal

 

1,630

 

47.90%

 

$462

 

$249

White Bluff

Units 1 and 2

 

Coal

 

1,635

 

57.00%

 

$428

 

$264

Roy S. Nelson

Unit 6

 

Coal

 

550

 

60.90%

 

$403

 

$241

Big Cajun 2

Unit 3

 

Coal

 

575

 

42.00%

 

$233

 

$128

Energy Commodity Services:

                     

Harrison County

 

 

Gas

 

550

 

61.00%

 

$209

 

$7

Warren

   

Gas

 

300

 

75.00%

 

$24

 

$9

(1)

"Total Megawatt Capability" is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.

(2)

Includes an 11.5% leasehold interest held by System Energy. System Energy's Grand Gulf lease obligations are discussed in Note 9 to the consolidated financial statements.

Nuclear Refueling Outage Costs

Entergy records nuclear refueling outage costs in accordance with regulatory treatment and the matching principle. These refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line. Except for the River Bend plant, the costs are deferred during the outage and amortized over the period to the next outage. In accordance with the regulatory treatment of the River Bend plant, River Bend's costs are accrued in advance and included in the cost of service used to establish retail rates. Entergy Gulf States relieves the accrued liability when it incurs costs during the next River Bend outage.

Allowance for Funds Used During Construction (AFUDC)

AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction in the U.S. Utility segment. Although AFUDC increases both the plant balance and earnings, it is realized in cash through depreciation provisions included in rates.

Income Taxes

Entergy Corporation and the majority of its subsidiaries file a United States consolidated federal income tax return. Income taxes are allocated to the subsidiaries in proportion to their contribution to consolidated taxable income. SEC regulations require that no Entergy subsidiary pay more taxes than it would have paid if a separate income tax return had been filed. In accordance with SFAS 109, "Accounting for Income Taxes," deferred income taxes are recorded for all temporary differences between the book and tax basis of assets and liabilities, and for certain credits available for carryforward.

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

Investment tax credits are deferred and amortized based upon the average useful life of the related property, in accordance with ratemaking treatment.

Earnings per Share

The following table presents Entergy's basic and diluted earnings per share (EPS) calculation included on the consolidated income statement:

 

 

For the Years Ended December 31,

 

 

2004

 

2003

 

2002

 

 

(In Millions, Except Per Share Data)

 

 

 

 

$/share

 

 

 

$/share

 

 

 

$/share

Income before cumulative effect of accounting change

 


$909.5

 

 

 


$789.9

 

 

 


$599.4

 

 

 

 

 

 

 

   

 

 

 

 

 

 

 

Average number of common shares outstanding - basic

 


226.9

 


$4.01 

 


226.8

 


$3.48 

 


223.0

 


$2.69 

Average dilutive effect of:

 

 

 

 

 

 

 

 

 

 

 

 

  Stock Options (1)

 

4.3

 

(0.075)

 

4.1

 

(0.062)

 

3.9

 

(0.046)

  Equity Awards

 

 

- 

 

0.2

 

(0.004)

 

0.4

 

(0.005)

Average number of common shares outstanding - diluted

 


231.2

 


$3.93 

 


231.1

 


$3.42 

 


227.3

 


$2.64 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

 

 

 

 

 

Earnings applicable to common stock

 

$909.5

 

 

 

$926.9

 

 

 

$599.4

 

 

 

 

 

 

 

   

 

 

 

 

 

 

 

Average number of common shares outstanding - basic

 


226.9

 


$4.01 

 


226.8

 


$4.09 

 


223.0

 


$2.69 

Average dilutive effect of:

 

 

 

 

 

 

 

 

 

 

 

 

  Stock Options (1)

 

4.3

 

(0.075)

 

4.1

 

(0.073)

 

3.9

 

(0.046)

  Equity Awards

 

 

 

0.2

 

(0.004)

 

0.4

 

(0.005)

Average number of common shares outstanding - diluted

 


231.2

 


$3.93 

 


231.1

 


$4.01 

 


227.3

 


$2.64 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

Options to purchase approximately 3,319 common stock shares in 2004, 15,231 common stock shares in 2003, and 109,897 common stock shares in 2002 at various prices were outstanding at the end of those years that were not included in the computation of diluted earnings per share because the exercise prices were greater than the common share average market price at the end of each of the years presented.

Stock-based Compensation Plans

Entergy grants stock options to key employees of the Entergy subsidiaries, which is described more fully in Note 7 to the consolidated financial statements. Prior to 2003, Entergy applied the recognition and measurement principles of APB Opinion 25, "Accounting for Stock Issued to Employees," and related Interpretations in accounting for those plans. No stock-based employee compensation expense is reflected in 2002 net income as all options granted under the plans have an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2003, Entergy prospectively adopted the fair value based method of accounting for stock options prescribed by SFAS 123, "Accounting for Stock-Based Compensation." Awards under Entergy's plans vest over three years. Therefore, the cost related to stock-based employee compensation included in the determination of net income for 2004 and 2003 is less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of SFAS 123. The following table illustrates the effect on net income and earnings per share if Entergy would have historically applied the fair value based method of accounting to stock-based employee compensation.

 

 

For the Years Ended December 31,

 

 

2004

 

2003

 

2002

 

 

(In Thousands, Except Per Share Data)

 

 

 

 

 

 

 

Earnings applicable to common stock

 

$909,524

 

$926,943

 

$599,360

Add back: Stock-based compensation expense included in earnings applicable to common stock, net
  of related tax effects

  



5,141

 



2,818

 



- -

Deduct: Total stock-based employee compensation
  expense determined under fair value method for all
  awards, net of related tax effects

 



16,668

 



24,518

 



28,110

Pro forma earnings applicable to common stock

 

$897,997

 

$905,243

 

$571,250

 

 

 

 

 

 

 

Earnings per average common share:

 

 

 

 

 

 

  Basic

 

$4.01

 

$4.09

 

$2.69

  Basic - pro forma

 

$3.96

 

$3.99

 

$2.56

 

 

 

 

 

 

 

  Diluted

 

$3.93

 

$4.01

 

$2.64

  Diluted - pro forma

 

$3.88

 

$3.92

 

$2.51

Application of SFAS 71

The domestic utility companies and System Energy currently account for the effects of regulation pursuant to SFAS 71, "Accounting for the Effects of Certain Types of Regulation." This statement applies to the financial statements of a rate-regulated enterprise that meets three criteria. The enterprise must have rates that (i) are approved by a body empowered to set rates that bind customers (its regulator); (ii) are cost-based; and (iii) can be charged to and collected from customers. These criteria may also be applied to separable portions of a utility's business, such as the generation or transmission functions, or to specific classes of customers. If an enterprise meets these criteria, it capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. Such capitalized costs are reflected as regulatory assets in the accompanying financial statements. A significant majority o f Entergy's regulatory assets, net of related regulatory and deferred tax liabilities, earn a return on investment during their recovery periods. SFAS 71 requires that rate-regulated enterprises assess the probability of recovering their regulatory assets at each balance sheet date. When an enterprise concludes that recovery of a regulatory asset is no longer probable, the regulatory asset must be removed from the entity's balance sheet.

SFAS 101, "Accounting for the Discontinuation of Application of FASB Statement No. 71," specifies how an enterprise that ceases to meet the criteria for application of SFAS 71 for all or part of its operations should report that event in its financial statements. In general, SFAS 101 requires that the enterprise report the discontinuation of the application of SFAS 71 by eliminating from its balance sheet all regulatory assets and liabilities related to the applicable segment. Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs and therefore no longer qualifies for SFAS 71 accounting, it is possible that an impairment may exist that could require further write-offs of plant assets.

EITF 97-4: "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and 101" specifies that SFAS 71 should be discontinued at a date no later than when the effects of a transition to competition plan for all or a portion of the entity subject to such plan are reasonably determinable. Additionally, EITF 97-4 promulgates that regulatory assets to be recovered through cash flows derived from another portion of the entity that continues to apply SFAS 71 should not be written off; rather, they should be considered regulatory assets of the segment that will continue to apply SFAS 71.

See Note 2 to the consolidated financial statements for discussion of transition to competition activity in the retail regulatory jurisdictions served by the domestic utility companies. Only Texas has a currently enacted retail open access law, but Entergy believes that significant issues remain to be addressed by regulators, and the enacted law does not provide sufficient detail to reasonably determine the impact on Entergy Gulf States' regulated operations.

Cash and Cash Equivalents

Entergy considers all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at date of purchase to be cash equivalents. Investments with original maturities of more than three months are classified as other temporary investments on the balance sheet.

Investments

Entergy applies the provisions of SFAS 115, "Accounting for Investments for Certain Debt and Equity Securities," in accounting for investments in decommissioning trust funds. As a result, Entergy records the decommissioning trust funds at their fair value on the consolidated balance sheet. Because of the ability of the domestic utility companies and System Energy to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the domestic utility companies and System Energy have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets. For the nonregulated portion of River Bend, Entergy Gulf States has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. Decommissioning trust funds for Pilgrim, Indian Point 2, and Vermont Yankee do not receive regulatory treatment. Accordingly, unrealized gains and losses recorded on the asse ts in these trust funds are recognized in the accumulated other comprehensive income component of shareholders' equity because these assets are classified as available for sale. See Note 15 to the consolidated financial statements for details on the decommissioning trust funds.

Equity Method Investees

Entergy owns investments that are accounted for under the equity method of accounting because Entergy's ownership level results in significant influence, but not control, over the investee and its operations. Entergy records its share of earnings or losses of the investee based on the change during the period in the estimated liquidation value of the investment, assuming that the investee's assets were to be liquidated at book value. The equity earnings for Entergy-Koch, LP recorded by Entergy are dictated by the terms of the partnership agreement in accordance with the hypothetical liquidation at book value (HLBV) method. In accordance with the HLBV method, earnings are allocated to members based on what each partner would receive from their capital account if, hypothetically, liquidation were to occur at the balance sheet date and amounts distributed were based on recorded book values. Entergy discontinues the recognition of losses on equity inves tments when its share of losses equals or exceeds its carrying amount of investee plus any advances made or commitments to provide additional financial support. See Note 12 to the consolidated financial statements for additional information regarding Entergy's equity method investments.

Derivative Financial Instruments and Commodity Derivatives

SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," requires that all derivatives be recognized in the balance sheet, either as assets or liabilities, at fair value, unless they meet the normal purchase, normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.

Contracts for commodities that will be delivered in quantities expected to be used or sold in the ordinary course of business, including certain purchases and sales of power and fuel, are not classified as derivatives. These contracts are exempted under the normal purchase, normal sales criteria of SFAS 133. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.

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

Impairment of Long-Lived Assets

Entergy periodically reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from such operations and assets. Projected net cash flows depend on the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy over the remaining life of the assets. See Note 11 to the consolidated financial statements for a discussion of asset impairments recognized by Entergy in 2002 and 2004.

River Bend AFUDC

The River Bend AFUDC gross-up is a regulatory asset that represents the incremental difference imputed by the LPSC between the AFUDC actually recorded by Entergy Gulf States on a net-of-tax basis during the construction of River Bend and what the AFUDC would have been on a pre-tax basis. The imputed amount was only calculated on that portion of River Bend that the LPSC allowed in rate base and is being amortized over the estimated remaining economic life of River Bend.

Transition to Competition Liabilities

In conjunction with electric utility industry restructuring activity in Texas, regulatory mechanisms were established to mitigate potential stranded costs. Texas restructuring legislation allowed depreciation on transmission and distribution assets to be directed toward generation assets. The liability recorded as a result of this mechanism is classified as "transition to competition" deferred credits on the balance sheet.

Reacquired Debt

The premiums and costs associated with reacquired debt of the domestic utility companies and System Energy (except that portion allocable to the deregulated operations of Entergy Gulf States) are being amortized over the life of the related new issuances, in accordance with ratemaking treatment.

Foreign Currency Translation

All assets and liabilities of Entergy's foreign subsidiaries are translated into U.S. dollars at the exchange rate in effect at the end of the period. Revenues and expenses are translated at average exchange rates prevailing during the period. The resulting translation adjustments are reflected in a separate component of shareholders' equity. Current exchange rates are used for U.S. dollar disclosures of future obligations denominated in foreign currencies.

New Accounting Pronouncements

During 2004, Entergy adopted the provisions of FSP 106-2, "Accounting and Disclosure Requirements Related to Medicare Prescription Drug, Improvement and Modernization Act of 2003," which is discussed further in Note 10 to the consolidated financial statements. Entergy also adopted FSP 109-1, "Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004" and FSP 109-2, "Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision Within the American Jobs Creation Act of 2004" which are further discussed in Note 3 to the consolidated financial statements.

SFAS 123R, "Share-Based Payment" was issued in December of 2004 and is effective for Entergy at the beginning of the third quarter in 2005. SFAS 123R requires all employers to account for share-based payments at fair value and also provides guidance on determining the assumptions to estimate fair value. SFAS 123R also provides guidance on how to account for differences in the amounts of deferred taxes initially recorded when the options are recorded as expense and the amount of expense deducted on a company's tax return when the options are actually exercised. Entergy began voluntarily expensing its stock options effective January 1, 2003 in accordance with SFAS 148, "Stock-Based Compensation - Transition and Disclosure." Entergy is in the process of evaluating the reporting and disclosure issues resulting from the adoption of SFAS 123R but does not expect the effect of the adoption of this standard to be material to Entergy's financial position or results of operations.

SFAS 151, "Inventory Costs - an amendment of ARB No. 43, Chapter 4" and SFAS 153, "Exchanges of Nonmonetary Assets", were also issued during the fourth quarter of 2004 and are effective for Entergy in 2006 and 2005, respectively. Entergy does not expect the impact of the adoption of these standards to be material.

During 2003, Entergy adopted the provisions of the following accounting standards: SFAS 143, "Accounting for Asset Retirement Obligations," which is discussed further in Note 8 to the consolidated financial statements; FIN 46, Consolidation of Variable Interest Entities," which is discussed further in Note 5 to the consolidated financial statements; and SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." SFAS 150, which became effective July 1, 2003, requires mandatorily redeemable financial instruments to be classified and treated as liabilities in the presentation of financial position and results of operations. The only effect of implementing SFAS 150 for Entergy is the inclusion of long-term debt and preferred stock with sinking fund under the liabilities caption in Entergy's balance sheet. Entergy's results of operations and cash flows were not affected by SFAS 150.

During 2003, Entergy also adopted the provisions of the following accounting standards: EITF 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities"; SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" and related interpretations by the Derivatives Implementation Group, and FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees Including Indirect Guarantees of Indebtedness of Others". The adoption of these standards did not have a material effect on Entergy's financial statements.

NOTE 2. RATE AND REGULATORY MATTERS

Electric Industry Restructuring and the Continued Application of SFAS 71

Although Arkansas and Texas enacted retail open access laws, the retail open access law in Arkansas has now been repealed. Retail open access in Entergy Gulf States' service territory in Texas has been delayed. Entergy believes that significant issues remain to be addressed by regulators, and the enacted law in Texas does not provide sufficient detail to allow Entergy Gulf States to reasonably determine the impact on Entergy Gulf States' regulated operations. Entergy therefore continues to apply regulatory accounting principles to the retail operations of all of the domestic utility companies. Following is a summary of the status of retail open access in the domestic utility companies' retail service territories.

Jurisdiction

 

Status of Retail Open Access

 

% of Entergy's
2004 Revenues Derived
from Retail Electric
Utility Operations
in the Jurisdiction

  

 

 

 

 

Arkansas

 

Retail open access was repealed in February 2003.

 

11.6%

 

 

 

 

 

Texas

 

In July 2004, the PUCT effectively rejected Entergy Gulf States' proposal to implement retail open access in its service territory. In February 2005, bills were submitted in the Texas Legislature that would specify that retail open access will not commence in Entergy Gulf States' territory until the PUCT certifies a power region.

 

11.8%

 

 

 

 

 

Louisiana

 

The LPSC has deferred pursuing retail open access, pending developments at the federal level and in other states. In response to a study submitted to the LPSC that was funded by a group of large industrial customers, the LPSC recently has solicited comments regarding a limited retail access program. It is uncertain what action, if any, the LPSC might take in response to the information it received.

 

34.1%

 

 

 

 

 

Mississippi

 

The MPSC has recommended not pursuing open access at this time.

 

10.9%

 

 

 

 

 

New Orleans

 

The Council has taken no action on Entergy New Orleans' proposal filed in 1997.

 

4.5%

Texas

As ordered by the PUCT, in January 2003 Entergy Gulf States filed its proposal for an interim solution (retail open access without a FERC-approved RTO), which among other elements, included:

  • the recommendation that retail open access in Entergy Gulf States' Texas service territory, including corporate unbundling, occur by January 1, 2004, or else be delayed until at least January 1, 2007. If retail open access is delayed past January 1, 2004, Entergy Gulf States requested authorization to separate into two bundled utilities, one subject to the retail jurisdiction of the PUCT and one subject to the retail jurisdiction of the LPSC.
  • the recommendation that Entergy's transmission organization, possibly with the oversight of another entity, will continue to serve as the transmission authority for purposes of retail open access in Entergy Gulf States' service territory.
  • the recommendation that the decision points be identified that would require prior to January 1, 2004, the PUCT's determination, based upon objective criteria, whether to proceed with further efforts toward retail open access in Entergy Gulf States' Texas service territory.

After considering the proposal, in an April 2003 order the PUCT set forth a sequence of proceedings and activities designed to initiate an interim solution. These proceedings and activities included initiating a proceeding to certify an independent organization to administer market protocols and ensure nondiscriminatory access to transmission and distribution systems.

In July 2004 the PUCT denied Entergy's application to certify Entergy's transmission organization as an independent organization under Texas law. In its order, the PUCT also ordered: the cessation of efforts to develop an interim solution for retail open access in Entergy Gulf States' Texas service territory, termination of the pilot project in that territory, and a delay in retail open access in that territory until either a FERC-approved RTO is in place or some other independent transmission entity is certified under Texas law. Several parties have appealed the termination of the pilot program aspect of the order, claiming the issue was not properly a part of the proceeding.

In February 2005, bills were submitted in the Texas Legislature that would clarify that Entergy Gulf States is no longer subject to a rate freeze and specify that retail open access will not commence in Entergy Gulf States' Texas service territory until the PUCT certifies a power region.

Louisiana

In November 2001, the LPSC decided not to move forward with retail open access for any customers at this time. The LPSC instead directed its staff to hold collaborative group meetings concerning open access from time to time, and to have the LPSC staff monitor developments in neighboring states and to report to the LPSC regarding the progress of retail access developments in those states. In September 2004, in response to a study funded by certain industrial customers that evaluated a limited industrial-only retail choice program, the LPSC asked the LPSC staff to solicit comments and obtain information from utilities, customers, and other interested parties concerning the potential costs and benefits of a limited choice program, the impact of such a program on other customers, as well as issues such as stranded costs and transmission service.  Comments from interested parties were filed with the LPSC on January 14, 2005. The LPSC has not established a procedural framework for consi deration of the comments. At this time, it is not certain what further action, if any, the LPSC might take in response to the information it received.

Regulatory Assets

Other Regulatory Assets

The domestic utility companies and System Energy are subject to the provisions of SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. In addition to the regulatory assets that are specifically disclosed on the face of the balance sheets, the table below provides detail of "Other regulatory assets" that are included on the balance sheets as of December 31, 2004 and 2003:

   

2004

 

2003

   

(In Millions)

Asset Retirement Obligation - recovery dependent upon timing of decommissioning
(Note 8)

 


$380.1

 


$464.9

Deferred fuel - non-current - recovered through rate riders when rates are
redetermined annually

 


21.9

 


28.2

Depreciation re-direct - recovery begins at start of retail open access (Note 1)

 

79.1

 

79.1

DOE Decommissioning and Decontamination Fees - recovered through fuel rates until
December 2006 (Note 8)

 


25.3

 


32.9

Low-level radwaste - recovery timing dependent upon pending lawsuit

 

19.4

 

19.4

Pension costs (Note 10)

 

207.3

 

134.0

Postretirement benefits - recovered through 2013 (Note 10)

 

19.1

 

21.5

Provision for storm damages - recovered through cost of service

 

124.5

 

123.3

Removal costs - recovered through depreciation rates (Note 8)

 

53.2

 

45.6

Resource planning - recovery timing will be determined by the LPSC in a base rate
proceeding (Note 2)

 


25.4

 


5.8

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

 

37.5

 

39.4

Sale-leaseback deferral - recovered through June 2014 (Note 9)

 

127.3

 

131.7

Spindletop gas storage facility - recovered through December 2032

 

42.3

 

38.0

Unamortized loss on reaquired debt - recovered over term of debt

 

169.9

 

164.4

Other - various

 

97.0

 

70.1

Total

 

$1,429.3

 

$1,398.3

Deferred fuel costs

The domestic utility companies are allowed to recover certain fuel and purchased power costs through fuel mechanisms included in electric rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is recorded as "Deferred fuel costs" on the domestic utility companies' financial statements. The table below shows the amount of deferred fuel costs as of December 31, 2004 and 2003 that Entergy expects to recover or (refund) through the fuel mechanisms of the domestic utility companies, subject to subsequent regulatory review.

 

2004

 

2003

 

(In Millions)

 

 

 

 

Entergy Arkansas

$7.4 

 

$10.6 

Entergy Gulf States

$90.1 

 

$118.4 

Entergy Louisiana

$8.7 

 

$30.6 

Entergy Mississippi

($22.8)

 

$89.1 

Entergy New Orleans

$2.6 

 

($2.7)

Entergy Arkansas

Entergy Arkansas' rate schedules include an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an annual energy cost rate. The energy cost rate includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year.

In March 2004, Entergy Arkansas filed with the APSC its energy cost recovery rider for the period April 2004 through March 2005. The filed energy cost rate, which accounts for 12 percent of a typical residential customer's bill using 1,000 kWh per month, increased 16 percent due primarily to the elimination of a credit contained in the prior year's rate to refund previously over-recovered fuel costs. Also included in the current year's energy cost calculation is a decrease in rates of $3.9 million as a result of the operation of a revised energy allocation method between the retail and wholesale sectors resulting from the APSC's approval of a life-of-resources power purchase agreement with Entergy New Orleans.

Entergy Gulf States (Texas)

In the Texas jurisdiction, Entergy Gulf States' rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including carrying charges, not recovered in base rates. Under the current methodology, semi-annual revisions of the fixed fuel factor may be made in March and September based on the market price of natural gas. Entergy Gulf States will likely continue to use this methodology until the start of retail open access, which has been delayed. The amounts collected under Entergy Gulf States' fixed fuel factor and any interim surcharge implemented until the date retail open access commences are subject to fuel reconciliation proceedings before the PUCT. In the Texas jurisdiction, Entergy Gulf States' deferred electric fuel costs are $78.6 million as of December 31, 2004, which include the following:

   

Amount

   

(In Millions)

Under-recovered fuel costs for the period 9/03 - 7/04 to be recovered through an interim fuel surcharge over a six-month period beginning in January 2005

 



$27.8

Items to be addressed as part of unbundling

 

$29.0

Imputed capacity charges

 

$ 9.3      

Other

 

$12.5

The PUCT has ordered that the imputed capacity charges be excluded from fuel rates and therefore recovered through base rates. Entergy Gulf States filed a retail electric rate case and fuel proceeding with the PUCT in August 2004. As discussed below, the PUCT dismissed the rate case and fuel reconciliation proceeding in October 2004 indicating that Entergy Gulf States is still subject to a rate freeze based on the current PUCT-approved settlement agreement stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory, unless the rate freeze is lifted by the PUCT prior thereto. Without a Texas base rate proceeding, it is possible that Entergy Gulf States will not be allowed to recover imputed capacity charges in Texas retail rates in the future. Entergy Gulf States believes the PUCT has misinterpreted the settlement and has appealed the PUCT order to the Travis County District Court and also intends to pursue other available remedies as discussed above in "Electric Industry Restructuring and the Continued Application of SFAS 71." The dismissal of the rate case does not preclude Entergy Gulf States from seeking the reconciliation of fuel and purchased power costs of $288 million incurred from September 2003 through March 2004 when, at the appropriate time, similar costs are reconciled in the future.

In January 2001, Entergy Gulf States filed with the PUCT a fuel reconciliation case covering the period from March 1999 through August 2000. Entergy Gulf States was reconciling approximately $583 million of fuel and purchased power costs. As part of this filing, Entergy Gulf States requested authority to collect $28 million, plus interest, of under-recovered fuel and purchased power costs. In August 2002, the PUCT reduced Entergy Gulf States' request to approximately $6.3 million, including interest through July 31, 2002. Approximately $4.7 million of the total reduction to the requested surcharge relates to nuclear fuel costs that the PUCT deferred ruling on at that time. In October 2002, Entergy Gulf States appealed the PUCT's final order in Texas District Court. In its appeal, Entergy Gulf States is challenging the PUCT's disallowance of approximately $4.2 million related to imputed capacity costs and its disallowance related to costs for energy delivered from the 30% non-regulate d share of River Bend. The case was argued before the Travis County Texas District Court in August 2003 and the Travis County District Court judge affirmed the PUCT's order. In October 2003, Entergy Gulf States appealed this decision to the Court of Appeals. Oral argument before the appellate court occurred in September 2004 and the matter is still pending.

In September 2003, Entergy Gulf States filed an application with the PUCT to implement an $87.3 million interim fuel surcharge, including interest, to collect under-recovered fuel and purchased power expenses incurred from September 2002 through August 2003. Hearings were held in October 2003 and the PUCT issued an order in December 2003 allowing for the recovery of $87 million. The surcharge was collected over a twelve-month period that began in January 2004.

In March 2004, Entergy Gulf States filed with the PUCT a fuel reconciliation case covering the period September 2000 through August 2003. Entergy Gulf States is reconciling $1.43 billion of fuel and purchased power costs on a Texas retail basis. This amount includes $8.6 million of under-recovered costs that Entergy Gulf States is asking to reconcile and roll into its fuel over/under-recovery balance to be addressed in the next appropriate fuel proceeding. This case involves imputed capacity and River Bend payment issues similar to those decided adversely in the January 2001 proceeding, discussed above, which is now on appeal. On January 31, 2005, the ALJs issued a Proposal for Decision that recommends disallowing $10.7 million (excluding interest) related to these two issues. A final PUCT decision is expected in the first quarter of 2005.

In September 2004, Entergy Gulf States filed an application with the PUCT to implement a $27.8 million interim fuel surcharge, including interest, to collect under-recovered fuel and purchased power expenses incurred from September 2003 through July 2004. Entergy Gulf States proposed to collect the surcharge over a six-month period beginning January 2005. In December 2004, the PUCT approved the surcharge consistent with Entergy Gulf States' request. Amounts collected though the interim fuel surcharge, which will be implemented over the six-month period commencing January 2005, are subject to final reconciliation in a future fuel reconciliation proceeding.

Entergy Gulf States (Louisiana) and Entergy Louisiana

In Louisiana, Entergy Gulf States and Entergy Louisiana recover electric fuel and purchased power costs for the upcoming month based upon the level of such costs from the prior month. In Louisiana, Entergy Gulf States' purchased gas adjustments include estimates for the billing month adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations of actual fuel costs incurred with fuel cost revenues billed to customers.

In August 2000, the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Louisiana pursuant to a November 1997 LPSC general order. The time period that is the subject of the audit is January 1, 2000 through December 31, 2001. In September 2003, the LPSC staff issued its audit report and recommended a disallowance with regard to one item. The issue relates to the alleged failure to uprate Waterford 3 in a timely manner, a claim that also has been raised in the summer 2001, 2002, and 2003 purchased power proceedings. The LPSC staff has quantified the possible disallowance as between $7.6 and $14 million. Entergy Louisiana notified the LPSC that it will contest the recommendation. The procedural schedule in the case has been suspended. A status conference for the purpose of establishing a new procedural schedule will be set when the current hearings in the Power Purchase Agreement proceedings at the FERC are concluded. The FERC hear ings in that matter concluded in November 2004. If the LPSC approves the proposed settlement discussed below under "Retail Rate Proceedings", the issue of a proposed imprudence disallowance relating to the uprate will be resolved and will no longer be at issue in this proceeding.

In January 2003, the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States and its affiliates pursuant to a November 1997 LPSC general order. The audit will include a review of the reasonableness of charges flowed by Entergy Gulf States through its fuel adjustment clause in Louisiana for the period January 1, 1995 through December 31, 2002. Discovery is underway, but a detailed procedural schedule extending beyond the discovery stage has not yet been established, and the LPSC staff has not yet issued its audit report.

Entergy Mississippi

Entergy Mississippi's rate schedules include an energy cost recovery rider which is adjusted quarterly to reflect accumulated over- or under-recoveries from the second prior quarter. In May 2003, Entergy Mississippi filed and the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Under the MPSC's order, Entergy Mississippi deferred until 2004 the collection of fuel under-recoveries for the first and second quarters of 2003 that would have been collected in the third and fourth quarters of 2003, respectively. The deferred amount of $77.6 million plus carrying charges was collected through the energy cost recovery rider over a twelve-month period that began in January 2004.

In January 2005, the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Entergy Mississippi's fuel over-recoveries for the third quarter of 2004 of $21.3 million will be deferred from the first quarter 2005 energy cost recovery rider adjustment calculation. The deferred amount of $21.3 million plus carrying charges will be refunded through the energy cost recovery rider in the second and third quarters of 2005.

Entergy New Orleans

Entergy New Orleans' electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations, including carrying charges. Entergy New Orleans' gas rate schedules include estimates for the billing month adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations, including carrying charges. In June and November 2004, the City Council passed resolutions implementing a package of measures developed by Entergy New Orleans and the Council Advisors to protect customers from potential gas price spikes during the 2004 - 2005 winter heating season. These measures include: maintaining Entergy New Orleans' financial hedging plan for its purchase of wholesale gas, and deferral of collection of up to $6.2 million of gas costs associated with a cap on the purchased gas adjustment in November and December 200 4 and in the event that the average residential customer's gas bill were to exceed a threshold level. The deferrals resulting from these caps will receive accelerated recovery over a seven-month period beginning in April 2005.

In November 2004, the City Council directed Entergy New Orleans to confer with the Council Advisors regarding possible modification of the current gas cost collection mechanism in order to address concerns regarding its fluctuations particularly during the winter heating season.

Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

No significant retail rate proceedings are pending in Arkansas at this time.

Filings with the PUCT and Texas Cities (Entergy Gulf States)

Retail Rates

Entergy Gulf States is operating in Texas under the terms of a December 2001 settlement agreement approved by the PUCT. The settlement provided for base rates that have remained in effect during the delay in the implementation of retail open access in Entergy Gulf States' Texas service territory. In view of the PUCT order in July 2004 to further delay retail open access in the Texas service territory, Entergy Gulf States filed a retail electric rate case and fuel reconciliation proceeding with the PUCT in August 2004 seeking the following:

  • approval of a base rate increase of $42.6 million annually for the Texas retail jurisdiction;
  • approval to implement a $14.1 million per year rider to recover, over a 15-year period, $110.9 million of incurred costs related to its efforts to transition to a competitive retail market in accordance with the Texas restructuring law;
  • approval to implement a proposed $11.3 million franchise fee rider to recover payments to municipalities charging such fees; and
  • a requested return on equity of 11.5%.

In addition, Entergy Gulf States' fuel reconciliation filing made in conjunction with the base rate case sought to reconcile approximately $288 million in fuel and purchased power costs incurred during the period September 2003 through March 2004. In October 2004, the PUCT issued a written order in which it dismissed the rate case and fuel reconciliation proceeding indicating that Entergy Gulf States is still subject to a rate freeze based on a PUCT-approved agreement in 2001 stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory, unless the rate freeze is lifted by the PUCT prior thereto. Entergy Gulf States believes the PUCT has misinterpreted the settlement and has appealed the PUCT order to the Travis County District Court and intends to pursue other available remedies.

In February 2005, bills were submitted in the Texas Legislature that would clarify that Entergy Gulf States is no longer subject to a rate freeze and specify that retail open access will not commence in Entergy Gulf States' Texas service territory until the PUCT certifies a power region.

Recovery of River Bend Costs

In March 1998, the PUCT disallowed recovery of $1.4 billion of company-wide abeyed River Bend plant costs, which have been held in abeyance since 1988. Entergy Gulf States appealed the PUCT's decision on this matter to the Travis County District Court in Texas. In April 2002, the Travis County District Court issued an order affirming the PUCT's order on remand disallowing recovery of the abeyed plant costs. Entergy Gulf States appealed this ruling to the Third District Court of Appeals. In July 2003, the Third District Court of Appeals unanimously affirmed the judgment of the Travis County District Court. After considering the progress of the proceeding in light of the decision of the Court of Appeals, Entergy Gulf States accrued for the loss that would be associated with a final, non-appealable decision disallowing the abeyed plant costs. The net carrying value of the abeyed plant costs was $107.7 million at the time of the Court of Appeals decision. Accrual of the $107.7 million loss was recorded in the second quarter of 2003 as miscellaneous other income (deductions) and reduced net income by $65.6 million after-tax. In September 2004, the Texas Supreme Court denied Entergy Gulf States' petition for review, and Entergy Gulf States filed a motion for rehearing. In February 2005, the Texas Supreme Court denied the motion for rehearing, and the proceeding is now final.

Filings with the LPSC

Proposed Settlement

In September 2004, the LPSC consolidated various dockets that were the subject of settlement discussions between the LPSC staff and Entergy Gulf States and Entergy Louisiana. The LPSC directed its staff to continue the settlement discussions and submit any proposed settlement to the LPSC for its consideration. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement that currently includes an offer to refund $76 million to Entergy Gulf States' Louisiana customers, with no immediate change in current base rates and to refund $14 million to Entergy Louisiana's customers. If the LPSC approves the proposed settlement, Entergy Gulf States will be regulated under a three-year formula rate plan that, among other provisions, establishes an ROE mid-point of 10.65% and permits Entergy Gulf States to recover incremental capacity costs without filing a traditional base rate proceeding. The sett lement resolves all issues in, and will result in the dismissal of, Entergy Gulf States' fourth, fifth, sixth, seventh, and eighth annual earnings reviews, Entergy Gulf States' ninth post-merger earnings review and revenue requirement analysis, a fuel review for Entergy Gulf States, dockets established to consider issues concerning power purchases for both Entergy Gulf States and Entergy Louisiana for the summers of 2001, 2002, 2003, and 2004, and a docket concerning retail issues arising under the Entergy System Agreement. The settlement does not include the System Agreement case pending at FERC. The LPSC has solicited comments on the proposed settlement from the parties to the various proceedings at issue in the proposed settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005.

Annual Earnings Reviews (Entergy Gulf States)

In May 2002, Entergy Gulf States filed its ninth and last required post-merger analysis with the LPSC. The filing included an earnings review filing for the 2001 test year that resulted in a rate decrease of $11.5 million, which was implemented effective June 2002. In its latest testimony, in December 2003, the LPSC staff recommended a rate refund of $30.6 million and a prospective rate reduction of approximately $50 million. Hearings concluded in May 2004. Should the LPSC approve the proposed settlement discussed above, the ninth post-merger analysis would be resolved.

In December 2002, the LPSC approved a settlement between Entergy Gulf States and the LPSC staff pursuant to which Entergy Gulf States agreed to make a base rate refund of $16.3 million, including interest, and to implement a $22.1 million prospective base rate reduction effective January 2003. The settlement discharged any potential liability for claims that relate to Entergy Gulf States' fourth, fifth, sixth, seventh, and eighth post-merger earnings reviews, with the exception of certain issues related to the calculation of the River Bend Deregulated Asset Plan percentage. Entergy Gulf States made the refund in February 2003. Should the LPSC approve the proposed settlement discussed above, the outstanding issue in these proceedings would be resolved.

Retail Rates

(Entergy Louisiana)

In January 2004, Entergy Louisiana made a rate filing with the LPSC requesting a base rate increase of approximately $167 million. In that filing, Entergy Louisiana noted that approximately $73 million of the base rate increase was attributable to the acquisition of a generating station and certain power purchase agreements that, based on current natural gas prices, would produce fuel and purchased power savings for customers that substantially mitigate the impact of the requested base rate increase. The filing also requested an allowed ROE of 11.4%. Entergy Louisiana's previously authorized ROE mid-point currently in effect is 10.5%. Hearings concluded in December 2004. Based on the evidence submitted at the hearing, the LPSC staff is recommending approximately a $7 million base rate increase. The LPSC staff proposed the implementation of a formula rate plan that includes a provision for the recovery of incremental capacity costs, including those related to the proposed Perryvil le acquisition, without filing a traditional base rate proceeding. A decision by the LPSC is expected in mid- to late-March 2005 on these issues.

Filings with the MPSC (Entergy Mississippi)

Formula Rate Plan Filings

Entergy Mississippi is operating under a December 2002 order issued by the MPSC. The order endorsed a new power management rider schedule designed to more efficiently collect capacity portions of purchased power costs. Also, the order provides for improvements in the return on equity formula and more robust performance measures for Entergy Mississippi's formula rate plan. Under the provisions of Entergy Mississippi's formula rate plan, a bandwidth is placed around the benchmark ROE, and if Entergy Mississippi earns outside of the bandwidth (as well as outside of a range-of-no-change at each edge of the bandwidth), then Entergy Mississippi's rates will be adjusted, though on a prospective basis only. Under Mississippi law and Entergy Mississippi's formula rate plan, however, if Entergy Mississippi's earned ROE is above the top of the range-of-no-change at the top of the formula rate plan bandwidth, then Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the point halfway between such earned ROE and the top of the bandwidth; and Entergy Mississippi's retail rates are set at that halfway-point ROE level. In the situation where Entergy Mississippi's earned ROE is not above the top of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the top of the range-of-no-change at the top of the bandwidth.

Entergy Mississippi made its annual formula rate plan filing with the MPSC in March 2004 based on a 2003 test year. In April 2004, the MPSC approved a joint stipulation entered into between the Mississippi Public Utilities Staff and Entergy Mississippi that provides for no change in rates based on a performance adjusted return on common equity mid-point of 10.77%, establishing an allowed regulatory earnings range of 9.3% to 12.2%.

Filings with the Council (Entergy New Orleans)

Rate Proceedings

In May 2003, the City Council approved a resolution allowing for a total increase of $30.2 million in electric and gas base rates effective June 1, 2003.  In April 2004, Entergy New Orleans made filings with the City Council as required by the earnings review process prescribed by the Gas and Electric Formula Rate Plans approved by the City Council in 2003. In August 2004, the City Council approved an unopposed settlement among Entergy New Orleans, the Council Advisors, and the intervenors in connection with the Gas and Electric Formula Rate Plans. In accordance with the resolution approving the settlement agreement, Entergy New Orleans' gas and electric base rates remain unchanged from the levels set in May 2003. The resolution ordered Entergy New Orleans to defer $3.9 million relating to voluntary severance plan costs allocated to its electric operations and $1.0 million allocated to its gas operations, which amounts were accrued on its books in 2003, and to record on its books regulatory assets in those amounts to be amortized over five years effective January 2004. Entergy New Orleans also was ordered to defer $6.0 million of fossil plant maintenance e xpense incurred in 2003 and to record on its books a regulatory asset in that amount to be amortized over a five-year period effective January 2003.

Fuel Adjustment Clause Litigation

In April 1999, a group of ratepayers filed a complaint against Entergy New Orleans, Entergy Corporation, Entergy Services, and Entergy Power in state court in Orleans Parish purportedly on behalf of all Entergy New Orleans ratepayers. The plaintiffs seek treble damages for alleged injuries arising from the defendants' alleged violations of Louisiana's antitrust laws in connection with certain costs passed on to ratepayers in Entergy New Orleans' fuel adjustment filings with the City Council. In particular, plaintiffs allege that Entergy New Orleans improperly included certain costs in the calculation of fuel charges and that Entergy New Orleans imprudently purchased high-cost fuel from other Entergy affiliates. Plaintiffs allege that Entergy New Orleans and the other defendant Entergy companies conspired to make these purchases to the detriment of Entergy New Orleans' ratepayers and to the benefit of Entergy's shareholders, in violation of Louisiana's antitrust laws. Plaintiffs also se ek to recover interest and attorneys' fees. Entergy filed exceptions to the plaintiffs' allegations, asserting, among other things, that jurisdiction over these issues rests with the City Council and FERC. In March 2004, the plaintiffs supplemented and amended their petition. If necessary, at the appropriate time, Entergy will also raise its defenses to the antitrust claims. The suit in state court has been stayed by stipulation of the parties pending a decision by the City Council in the proceeding discussed in the next paragraph.

Plaintiffs also filed this complaint with the City Council in order to initiate a review by the City Council of the plaintiffs' allegations and to force restitution to ratepayers of all costs they allege were improperly and imprudently included in the fuel adjustment filings. Testimony was filed on behalf of the plaintiffs in this proceeding asserting, among other things, that Entergy New Orleans and other defendants have engaged in fuel procurement and power purchasing practices and included costs in Entergy New Orleans' fuel adjustment that could have resulted in Entergy New Orleans customers being overcharged by more than $100 million over a period of years. Hearings were held in February and March 2002. In February 2004, the City Council approved a resolution that resulted in a refund to customers of $11.3 million, including interest, during the months of June through September 2004. The resolution concludes, among other things, that the record does not support an allegation tha t Entergy New Orleans' actions or inactions, either alone or in concert with Entergy or any of its affiliates, constituted a misrepresentation or a suppression of the truth made in order to obtain an unjust advantage of Entergy New Orleans, or to cause loss, inconvenience, or harm to its ratepayers. Management believes that it has adequately provided for the liability associated with this proceeding. The plaintiffs have appealed the City Council resolution to the state court in Orleans Parish. Oral argument on the plaintiffs' appeal was conducted in February 2005.

NOTE 3. INCOME TAXES

Income tax expenses for 2004, 2003, and 2002 consist of the following:

2004

2003

2002

(In Thousands)

Current:

  Federal (a)(b)

$54,380 

 

($731,129)

$510,109 

  Foreign

(2,231)

 

8,284