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, 2003

 

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 - 231,032,604
shares outstanding at February 27, 2004

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 Arkansas Capital I

8-1/2% Cumulative Quarterly Income Preferred
Securities, Series A
(guaranteed by Entergy Arkansas, 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 Louisiana Capital I

9% Cumulative Quarterly Income Preferred
Securities, Series A
(guaranteed by Entergy Louisiana, Inc.)

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. [ ]

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 2003, was $12.0 billion based on the reported last sale price of $52.78 per share for such stock on the New York Stock Exchange on June 30, 2003. 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 14, 2004, 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

 

21

      Critical Accounting Estimates

 

33

    Selected Financial Data - Five-Year Comparison

Part II. Item 6.

41

    Independent Auditors' Report

 

42

    Consolidated Statements of Income For the Years Ended December 31,
     2003, 2002, and 2001

Part II. Item 8.

43

    Consolidated Statements of Cash Flows For the Years Ended 
     December 31, 2003, 2002, and 2001

Part II. Item 8.

44

    Consolidated Balance Sheets, December 31, 2003 and 2002

Part II. Item 8.

46

    Consolidated Statements of Retained Earnings, Comprehensive Income, and
     Paid in Capital for the Years Ended December 31, 2003, 2002, and 2001

Part II. Item 8.

48

    Notes to Consolidated Financial Statements

Part II. Item 8.

49

  U.S. Utility

Part I. Item 1.

104

    Customers

 

104

    Electric Energy Sales

 

104

    Retail Rate Regulation

 

106

    Property and Other Generation Resources

 

112

    Fuel Supply

 

115

    Wholesale Rate Matters

 

118

    Service Companies

 

126

    Earnings Ratios

 

126

  Non-Utility Nuclear

Part I. Item 1.

127

    Property

 

127

    Energy and Capacity Sales

 

128

    Fuel Supply

 

129

    Other Business Activities

 

129

    Other Matters

 

130

  Energy Commodity Services

Part I. Item 1.

130

    Entergy-Koch, L.P.

 

130

    Non-Nuclear Wholesale Assets Business

 

132

 Regulation of Entergy's Business

Part I. Item 1.

133

    PUHCA

 

133

    Federal Power Act

 

133

    State Regulation

 

133

    Regulation of the Nuclear Power Industry

 

134

    Environmental Regulation

 

137

  Other Environmental Matters

 

140

  Litigation

 

141

  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

 

151

    Significant Factors and Known Trends

 

154

    Critical Accounting Estimates

 

157

  Independent Auditors' Report

 

162

  Income Statements For the Years Ended December 31, 2003, 2002, and
   2001

Part II. Item 8.

163

  Statements of Cash Flows For the Years Ended December 31, 2003, 2002,
   and 2001

Part II. Item 8.

165

  Balance Sheets, December 31, 2003 and 2002

Part II. Item 8.

166

  Statements of Retained Earnings for the Years Ended December 31, 2003,
   2002, and 2001

Part II. Item 8.

168

  Selected Financial Data - Five-Year Comparison

Part II. Item 6.

169

Entergy Gulf States, Inc.

   

  Management's Financial Discussion and Analysis

Part II. Item 7.

 

    Results of Operations

 

170

    Liquidity and Capital Resources

 

173

    Significant Factors and Known Trends

 

176

    Critical Accounting Estimates

 

184

  Independent Auditors' Report

 

189

  Income Statements For the Years Ended December 31, 2003, 2002, and
   2001

Part II. Item 8.

190

  Statements of Cash Flows For the Years Ended December 31, 2003, 2002,
   and 2001

Part II. Item 8.

191

  Balance Sheets, December 31, 2003 and 2002

Part II. Item 8.

192

  Statements of Retained Earnings and Comprehensive Income for the Years
   Ended December 31, 2003, 2002, and 2001

Part II. Item 8.

194

  Selected Financial Data - Five-Year Comparison

Part II. Item 6.

195

Entergy Louisiana, Inc.

   

  Management's Financial Discussion and Analysis

Part II. Item 7.

 

    Results of Operations

 

196

    Liquidity and Capital Resources

 

199

    Significant Factors and Known Trends

 

202

    Critical Accounting Estimates

 

206

  Independent Auditors' Report

 

210

  Income Statements For the Years Ended December 31, 2003, 2002, and
   2001

Part II. Item 8.

211

  Statements of Cash Flows For the Years Ended December 31, 2003, 2002,
   and 2001

Part II. Item 8.

213

  Balance Sheets, December 31, 2003 and 2002

Part II. Item 8.

214

  Statements of Retained Earnings for the Years Ended December 31, 2003,
   2002, and 2001

Part II. Item 8.

216

  Selected Financial Data - Five-Year Comparison

Part II. Item 6.

217

Entergy Mississippi, Inc.

   

  Management's Financial Discussion and Analysis

Part II. Item 7.

 

    Results of Operations

 

218

    Liquidity and Capital Resources

 

220

    Significant Factors and Known Trends

 

223

    Critical Accounting Estimates

 

225

  Independent Auditors' Report

 

229

  Income Statements For the Years Ended December 31, 2003, 2002, and
   2001

Part II. Item 8.

230

  Statements of Cash Flows For the Years Ended December 31, 2003, 2002,
   and 2001

Part II. Item 8.

231

  Balance Sheets, December 31, 2003 and 2002

Part II. Item 8.

232

  Statements of Retained Earnings for the Years Ended December 31, 2003,
   2002, and 2001

Part II. Item 8.

234

  Selected Financial Data - Five-Year Comparison

Part II. Item 6.

235

Entergy New Orleans, Inc.

   

  Management's Financial Discussion and Analysis

Part II. Item 7.

 

    Results of Operations

 

236

    Liquidity and Capital Resources

 

238

    Significant Factors and Known Trends

 

241

    Critical Accounting Estimates

 

244

  Independent Auditors' Report

 

247

  Statements of Operations For the Years Ended December 31, 2003, 2002,
   and 2001

Part II. Item 8.

248

  Statements of Cash Flows For the Years Ended December 31, 2003, 2002,
   and 2001

Part II. Item 8.

249

  Balance Sheets, December 31, 2003 and 2002

Part II. Item 8.

250

  Statements of Retained Earnings for the Years Ended December 31, 2003,
   2002, and 2001

Part II. Item 8.

252

  Selected Financial Data - Five-Year Comparison

Part II. Item 6.

253

System Energy Resources, Inc.

   

  Management's Financial Discussion and Analysis

Part II. Item 7.

 

    Results of Operations

 

254

    Liquidity and Capital Resources

 

255

    Significant Factors and Known Trends

 

257

    Critical Accounting Estimates

 

258

  Independent Auditors' Report

 

262

  Income Statements For the Years Ended December 31, 2003, 2002, and
   2001

Part II. Item 8.

263

  Statements of Cash Flows For the Years Ended December 31, 2003, 2002,
   and 2001

Part II. Item 8.

265

  Balance Sheets, December 31, 2003 and 2002

Part II. Item 8.

266

  Statements of Retained Earnings for the Years Ended December 31, 2003,
   2002, and 2001

Part II. Item 8.

268

  Selected Financial Data - Five-Year Comparison

Part II. Item 6.

269

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

Part II. Item 8.

270

Properties

Part I. Item 2.

332

Legal Proceedings

Part I. Item 3.

332

Submission of Matters to a Vote of Security Holders

Part I. Item 4.

332

Directors and Executive Officers of Entergy Corporation

Part III. Item 10.

332

Market for Registrants' Common Equity and Related Stockholder Matters

Part II. Item 5.

334

Selected Financial Data

Part II. Item 6.

335

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

Part II. Item 7.

335

Quantitative and Qualitative Disclosures About Market Risk

Part II. Item 7A.

335

Financial Statements and Supplementary Data

Part II. Item 8.

336

Changes in and Disagreements with Accountants on Accounting and Financial
 Disclosure

Part II. Item 9.

336

Controls and Procedures

Part II. Item 9A.

336

Directors and Executive Officers of the Registrants

Part III. Item 10.

337

Executive Compensation

Part III. Item 11.

342

Security Ownership of Certain Beneficial Owners and Management

Part III. Item 12.

352

Certain Relationships and Related Transactions

Part III. Item 13.

355

Principal Accountant Fees and Services

Part IV. Item 14

356

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

Part IV. Item 15.

359

Signatures

 

360

Independent Auditors' Consents

 

367

Independent Auditors' Report on Financial Statement Schedules

 

368

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

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 decisions, including those related to Entergy's System Agreement and utility supply plan
    • Entergy's ability to reduce its operation and maintenance costs, particularly at its Non-Utility Nuclear generating facilities, including the uncertainty of negotiations with unions to agree to such reductions
    • 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
    • Entergy-Koch's profitability in trading physical and financial natural gas and power as well as other energy and weather-related contracts
    • changes in the number of participants in the energy trading market, and in their creditworthiness and risk profile
    • changes in the financial markets, particularly those affecting the availability of capital and Entergy's ability to refinance existing debt and to fund investments and acquisitions
    • actions of rating agencies, including changes in the ratings of debt and preferred stock
    • changes in inflation and interest rates
    • Entergy's ability to purchase and sell assets at attractive prices and on other attractive terms
    • changes in ownership of joint ventures
    • 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, and the establishment of a regional transmission organization that includes Entergy's utility service territory
    • changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown of Indian Point or other nuclear generating facilities
    • resolution of pending or future applications for license extensions 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, hurricanes, and other disasters
    • advances in technology
    • the potential impacts of threatened or actual terrorism and war
    • the success of Entergy's strategies to reduce current tax payments
    • the effects of litigation
    • 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

BCF

One billion cubic feet of natural gas

BCF/D

One billion cubic feet of natural gas per day

Board

Board of Directors of Entergy Corporation

BPS

British pounds sterling

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

Damhead Creek 800 MW (gas) combined cycle electric generating facility located in the United Kingdom that entered commercial operations in the first quarter of 2001 and was sold by Entergy in 2002

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

electricity marketed

Total physical volume marketed by Entergy-Koch in the U.S. and Europe during the period

electricity volatility

Measure of price fluctuation over time using standard deviation of daily price differences for into-Entergy and into-Cinergy power prices for the upcoming month

Energy Commodity Services

Entergy's business segment that is focused almost exclusively on providing energy commodity trading and gas transportation and storage services through Entergy-Koch, LP and also includes 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

FitzPatrick

James A. FitzPatrick nuclear power plant, 825 MW facility located near Oswego, New York, purchased in November 2000 from New York Power Authority (NYPA) by Entergy's Non-Utility Nuclear business

DEFINITIONS (Continued)

Abbreviation or Acronym

Term

   

gain/loss days

Ratio of the number of days when Entergy-Koch recognized a net gain from commodity trading activities to the number of days when Entergy-Koch recognized a net loss from commodity trading activities

gas marketed

Total physical volume marketed by Entergy-Koch in the U.S. and Europe during the period

gas volatility

Measure of price fluctuation over time using standard deviation of daily price differences for Henry Hub natural gas prices for the upcoming month

Grand Gulf 1

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

Indian Point 1

Indian Point Energy Center Unit 1 nuclear power plant that has been shut-down and in safe storage since the 1970s, located in Westchester County, New York, purchased in September 2001 together with Indian Point 2 from Consolidated Edison by Entergy's Non-Utility Nuclear business

Indian Point 2

Indian Point Energy Center Unit 2 nuclear power plant, 984 MW facility located in Westchester County, New York, purchased in September 2001 from Consolidated Edison by Entergy's Non-Utility Nuclear business

Indian Point 3

Indian Point Energy Center Unit 3 nuclear power plant, 994 MW facility located in Westchester County, New York, purchased in November 2000 from NYPA by Entergy's Non-Utility Nuclear business

IRS

Internal Revenue Service

kV

Kilovolt

kW

Kilowatt

kWh

Kilowatt-hour(s)

LDEQ

Louisiana Department of Environmental Quality

LPSC

Louisiana Public Service Commission

Mcf

1,000 cubic feet of gas

miles of pipeline

Total miles of transmission and gathering pipeline

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; other regulatory credits; and amortization of rate deferrals

DEFINITIONS (Concluded)

Abbreviation or Acronym

Term

   

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

Pilgrim

Pilgrim Nuclear Station, 688 MW facility located in Plymouth, Massachusetts, purchased in July 1999 from Boston Edison by Entergy's Non-Utility Nuclear business

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 1

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

storage capacity

Working gas storage capacity

System Energy

System Energy Resources, Inc.

throughput

Gas in BCF/D transported through a pipeline during the period

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

Vermont Yankee

Vermont Yankee nuclear power plant, 510 MW facility located in Vernon, Vermont, purchased in July 2002 from Vermont Yankee Nuclear Power Corporation (VYNPC) by Entergy's Non-Utility Nuclear business

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, retail electric distribution operations, energy marketing and trading, and gas transportation. 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 2.6 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Through Entergy-Koch, Entergy is a leading provider of wholesale energy marketing and trading services, as well as an operator of natural gas pipeline and storage facilities. Entergy generated annual revenues of over $9 billion in 2003 and had approximately 14,800 employees as of December 31, 2003.

Entergy Corporation is an integrated energy company engaged primarily in electric power production, retail electric distribution operations, energy marketing and trading, and gas transportation. 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 2.6 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Through Entergy-Koch, Entergy is a leading provider of wholesale energy marketing and trading services, as well as an operator of natural gas pipeline and storage facilities. Entergy generated annual revenues of over $9 billion in 2003 and had approximately 14,800 employees as of December 31, 2003.

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, with a small amount of natural gas distribution.
    • Non-Utility Nuclear owns and operates five nuclear power plants 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 provides energy commodity trading and gas transportation and storage services through Entergy-Koch, LP. Energy Commodity Services also includes Entergy's non-nuclear wholesale assets business, which sells electric power produced by those assets to wholesale customers while it focuses on selling the majority of those assets.

Entergy's business operates primarily through its regulated utility subsidiaries in a four-state service territory that includes portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans. Entergy has reshaped its non-utility business through the sale in 1998 of its international electric distribution businesses located in the UK and Australia; the growth of its Non-Utility Nuclear business in the northeastern United States beginning in 1999; and the termination of new greenfield power development activity in 2002. With the start of the Entergy-Koch joint venture in early 2001, Entergy expanded its business opportunities into new areas. The trading activities of Entergy-Koch extend to various parts of the United States, as well as the United Kingdom, Western Europe, and Canada. Entergy-Koch's Gulf South Pipeline system covers the Gulf Coast region of the United States. Entergy's financial interest in the Entergy-Koch venture allows it to appoint fou r of the eight members of the general partner's board of directors. Operating decisions for Entergy-Koch are made by Entergy-Koch management.

 

OPERATING INFORMATION

For the Years Ended December 31, 2003, 2002, and 2001


U.S. Utility


Non-Utility Nuclear

Energy Commodity Services

Entergy Consolidated (a)

(In Thousands)

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

2001

Operating revenues

$7,432,920

$789,244

$1,370,485

$9,620,899

Operating expenses

6,050,534

576,510

1,361,153

8,072,954

Other income

69,157

50,916

222,571

349,353

Interest and other charges

576,705

55,717

74,953

714,580

Income taxes

300,284

80,053

74,493

455,693

Cumulative effect of accounting change

-

-

23,482

23,482

Net income

574,554

127,880

105,939

750,507

CASH FLOW INFORMATION

For the Years Ended December 31, 2003, 2002, and 2001


U.S. Utility


Non-Utility Nuclear

Energy Commodity Services

Entergy Consolidated (a)

(In Thousands)

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)

2001

Net cash flow provided by (used in) operating activities

$1,647,969

$263,476

($127,938)

$2,215,548

Net cash flow provided by (used in) investing activities

(1,243,715)

(1,061,820)

138,351

(2,224,720)

Net cash flow provided by (used in) financing activities

(303,520)

292,872

(148,501)

(622,004)

FINANCIAL POSITION INFORMATION

December 31, 2003 and 2002


U.S. Utility


Non-Utility Nuclear

Energy Commodity Services

Entergy Consolidated (a)

(In Thousands)

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

2,917,563

745,568

10,317

3,589,243

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

2002

Current assets

$2,517,001

$706,056

$504,836

$3,205,583

Other property and investments

1,089,871

1,437,896

1,175,842

3,468,240

Property, plant and equipment - net

15,594,128

1,613,369

429,677

17,665,003

Deferred debits and other assets

2,429,523

724,987

57,117

3,165,540

Current liabilities

2,479,783

947,731

348,200

3,172,189

Non-current liabilities

13,755,569

2,175,467

182,750

16,493,940

Shareholders' equity

5,395,171

1,359,110

1,636,522

7,838,237

(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 Mississippi, Inc.

   

Entergy Nuclear FitzPatrick LLC

   

Gulf South Pipeline

   

Entergy Power Development Corp.

 

Entergy New Orleans, Inc.

   

Entergy Nuclear Indian Point 2, LLC

   

Entergy-Koch Trading

   

Entergy Asset Management, 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 60,000 customers. This business is also preparing to operate as Entergy's affiliated competitive retailer when retail open access commences in Entergy Gulf States' service territory in Texas. Competitive Retail Services does not currently have material levels of revenue, net income, or total assets; and Entergy reports this business as part of All Other in its segment disclosures.

Strategy

Entergy's strategy is to create value by focusing on asset management and strong operational execution, with a particular emphasis on service reliability and excellence in nuclear operations.  Entergy continually evaluates its business position, with a view toward enhancing the company's scale, scope, and skill advantages. It applies a well-developed point of view of the marketplace and strong risk management to manage its asset portfolio and customer relationships. Entergy benchmarks its operational performance against industry and competitor standards on measures such as safety, reliability, customer service, and cost efficiency.

___________________________________________________________________________________________

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.

Part I, Item 1 is continued on page 104.

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 herein. The financial statements are based on accounting principles generally accepted in the United States of America. Financial information included elsewhere in this report is consistent with the financial statements.

To meet their responsibilities with respect to financial information, management maintains and enforces a system of internal accounting controls designed to provide reasonable assurance, on a cost-effective basis, as to the integrity, objectivity, and reliability of the financial records, and as to the protection of assets. 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.

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 accounting 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 Audit Committee also meets periodically with the independent auditors and the chief internal auditor without management, providing free access to the Committee.

Independent public accountants regularly evaluate the system of internal accounting controls and perform such tests and other procedures as they deem necessary to reach and express an opinion on the fairness of the financial statements. They also provide the Audit Committee their judgments about the quality of accounting policies and disclosures.

Management believes that these policies and procedures provide reasonable assurance that its operations are carried out with a high standard of business conduct.

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, with a small amount of natural gas distribution.
    • Non-Utility Nuclear owns and operates five nuclear power plants 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 provides energy commodity trading and gas transportation and storage services through Entergy-Koch, LP. Energy Commodity Services also includes Entergy's non-nuclear wholesale assets business, which sells electric power produced by those assets to wholesale customers while it focuses on selling the majority of those assets.

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

 

2003

 

2002

 

2001

 

2003

 

2002

 

2001

 

2003

 

2002

 

2001

                                     

U.S. Utility

 

82

 

82

 

77

 

52 

 

97 

 

77 

 

79 

 

79 

 

78

Non-Utility Nuclear

 

14

 

14

 

8

 

32 

 

32 

 

17 

 

15 

 

16 

 

13

Energy Commodity Services

 

2

 

4

 

14

 

19 

 

(23)

 

14 

 

 

 

9

Parent & Other

 

2

 

-

 

1

 

(3)

 

(6)

 

(8)

 

(1)

 

(3)

 

-

Results of Operations

Earnings applicable to common stock for the years ended December 31, 2003, 2002, and 2001 by operating segment are as follows:

Operating Segment

2003

2002

2001

(In Thousands)

U.S. Utility

$469,050  

$583,251 

$550,243 

Non-Utility Nuclear

300,799  

200,505 

127,880 

Energy Commodity Services

180,454  

(145,830)

105,939 

Parent & Other

(23,360)

(38,566)

(57,866)

  Total

$926,943 

$599,360 

$726,196 

 

Entergy's income before taxes is discussed according to the business segments listed above. 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 after-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 12 to the consolidated financial statements for further discussion of Entergy's business segments and their financial results in 2003, 2002, and 2001.

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 decrease in earnings for the U.S. Utility for 2003 from $583 million to $469 million was primarily due to a $107.7 million ($65.6 million net-of-tax) accrual 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 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 were decreased interest charges and increased net revenue.

The increase in earnings for the U.S. Utility for 2002 from $550 million to $583 million was primarily due to an increase in net revenue and a decrease in interest charges, partially offset by increases in depreciation and amortization expenses and other operation and maintenance expenses.

Net Revenue

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)

Fuel price

 

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 has 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 fuel price variance is due to a revised estimate made in December 2002 of the fuel cost component of the price applied to unbilled sales and further revision of that estimate in the first quarter of 2003.

The asset retirement obligation variance is due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations," adopted in January 2003. See "Critical Accounting Estimates" for more details on SFAS 143. The increase is offset by increased depreciation and decommissioning expenses and has no effect on net income.

The increase in net wholesale revenue is primarily due 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 is offset by a corresponding decrease in other operation and maintenance expenses and has 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 is offset by increased fuel and purchased power expenses.

Other regulatory credits decreased primarily due to the 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.

2002 Compared to 2001

Following is an analysis of the change in net revenue comparing 2002 to 2001.

   

(In Millions)

     

2001 net revenue

 

$3,873.1 

March 2002 Ark. settlement agreement

 

180.7 

Volume/weather

 

155.7 

Fuel price

 

94.3 

System Energy refund in 2001

 

(128.9)

Other

 

34.7 

2002 net revenue

 

$4,209.6 

The March 2002 settlement agreement is discussed above and is offset by an increase in other operation and maintenance expenses. The effect on net income in 2002 is a decrease of $2.2 million.

The volume/weather variance is due to increased electricity usage in the service territories. Billed usage increased a total of 2,149 GWh in the residential and commercial sectors.

The fuel price variance is due to an increase in the price applied to unbilled sales partially offset by a revised estimate made in December 2002 to the fuel cost component of that price.

The effect of the System Energy refund resulted from System Energy's application to FERC in May 1995 for a rate increase, which it implemented in December 1995, subject to refund. The request sought changes to System Energy's rate schedule, including increases in the revenue requirement associated with decommissioning costs, the depreciation rate, and the rate of return on common equity. In July 2000, FERC approved a lower rate of return than the rate sought by System Energy. Upon receipt of a final FERC order in July 2001, Entergy Arkansas and Entergy Louisiana recorded entries to spread the impacts of FERC's order to the various revenue, expense, asset, and liability accounts affected, as if the order had been in place since commencement of the case in 1995. The accounting entries necessary to record the effects of the order reduced purchased power expenses in 2001, which resulted in a corresponding increase in net revenue in 2001. The System Energy refund proceeding is discusse d in Note 2 to the consolidated financial statements.

Gross operating revenues

Gross operating revenues include a decrease in fuel cost recovery revenue of $897.4 million and $60.5 million related to electric sales and gas sales, respectively, primarily due to lower fuel recovery factors resulting from decreases in the market prices of natural gas and purchased power in 2002. As such, this revenue decrease is offset by decreased fuel and purchased power expenses.

Other Income Statement Variances

2003 Compared to 2002

Other operation and maintenance expenses decreased 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 primarily due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations." The increase in decommissioning expense is offset by increases in other regulatory credits and interest and dividend income and has an insignificant effect on net income.

Depreciation and amortization expenses increased 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 is offset by increases in other regulatory credits and interest and dividend income and has an insignificant effect on net income.

Other income decreased primarily due to a decrease in "miscellaneous - - net" as a result of a $107.7 million accrual in the second quarter 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 charges decreased primarily due to a decrease of $28.5 million in interest on long-term debt due to the redemption and refinancing of long-term debt. Refer to Note 5 to the consolidated financial statements for detail of long-term debt outstanding as of December 31, 2003 and 2002.

2002 Compared to 2001

In addition to the effect of the March 2002 settlement agreement at Entergy Arkansas, the increase in other operation and maintenance expenses was primarily due to:

    • an increase of $51.2 million in benefit costs;
    • increased expenses of $24.5 million at Entergy Arkansas due to the reversal in 2001 of ice storm costs previously charged to expense in December 2000;
    • an increase of $14.6 million in fossil plant expenses due to maintenance outages and turbine inspection costs at various plants;
    • an increase of $10.9 million to reflect the current estimate of the liability for the future disposal of low-level radioactive waste materials; and
    • lower nuclear insurance refunds of $6.7 million.

Depreciation and amortization expenses increased primarily due to the effects in 2001 of the final FERC order addressing System Energy's 1995 rate filing.

Other income decreased primarily due to:

    • interest recognized in 2001 on Grand Gulf 1's decommissioning trust funds resulting from the final order addressing System Energy's rate proceeding;
    • interest recognized in 2001 at Entergy Mississippi and Entergy New Orleans on the deferred System Energy costs related to its 1995 rate filing that were not being recovered through rates; and
    • lower interest earned on declining deferred fuel balances.

The decrease was partially offset by an increase in "miscellaneous - - net" of $26.7 million due to the cessation of amortization of goodwill in January 2002 upon implementation of SFAS 142 and settlement of liability insurance coverage at Entergy Gulf States.

Interest and other charges decreased primarily due to:

    • a decrease of $31.9 million in interest on long-term debt primarily due to the retirement of long-term debt in late 2001 and early 2002; and
    • a decrease of $76.0 million in other interest expense primarily due to interest recorded on System Energy's provision for rate refund in 2001 resulting from the effects of the final FERC order addressing System Energy's 1995 rate filing. The refund was made in December 2001.

Non-Utility Nuclear

Following are key performance measures for Non-Utility Nuclear:

  

2003

  

2002

  

2001

  

  

  

  

  

  

Net MW in operation at December 31

4,001

  

3,955

  

3,445

Average realized price per MWh

$38.54

  

$40.49

  

$34.90

Generation in GWh for the year

32,379

  

29,953

  

22,614

Capacity factor for the year

92.4%

  

92.8%

  

92.7%

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.

2002 Compared to 2001

The increase in earnings for Non-Utility Nuclear from $127.9 million to $200.5 million was primarily due to the acquisitions of Indian Point 2, which was purchased in September 2001, and Vermont Yankee, which was purchased in July 2002. Also contributing to the increase in earnings was higher pricing under certain purchase power contracts.

Energy Commodity Services

Earnings for Energy Commodity Services in 2003 were primarily driven by Entergy's investment in Entergy-Koch. Following are key performance measures for Entergy-Koch's operations for 2003, 2002, and 2001:

  

  

2003

  

2002

  

2001

Entergy-Koch Trading

  

  

  

  

  

  

  Gas volatility

  

62%

  

61%

  

72%

  Electricity volatility

  

59%

  

48%

  

78%

  Gas marketed (BCF/D) (1)

  

6.5

  

5.8

  

4.5

  Electricity marketed (GWh)

  

445,979

  

408,038

  

180,893

  Gain/loss days

  

1.5

  

1.8

  

2.8

Gulf South Pipeline

  

  

  

  

  

  

  Throughput (BCF/D)

  

1.99

  

2.40

  

2.45

  Production cost ($/MMBtu)

  

$0.146

  

$0.094

 

$0.093

(1)

Previously reported volumes, which included only U.S. trading, have been adjusted to reflect both U.S. and Europe volumes traded.

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 $428.5 million ($238.3 million net-of-tax) of charges recorded in 2002, as discussed in the 2002 to 2001 comparison 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 at Entergy-Koch Trading (EKT). Volatility was slightly up and trading earnings reflected solid point-of-view trading results. In addition, EKT's physical optimization business continued to contribute earnings, and its European business earnings increased as trading activities continued to expand beyond the United Kingdom. Earnings at Gulf South Pipeline were lower due to lower throughput and higher production costs. The decreased throughput was due to shifting gas flow patterns in a sustained high gas price environment that led to higher fuel costs. Production costs were higher as the result of incremental legal and consultant expenses incurred primarily in connection with Gulf South's defense of a lawsuit which it believes has no merit.

Entergy accounts for its 50% share in Entergy-Koch under the equity method of accounting. Earnings from Entergy-Koch are reported as equity in earnings of unconsolidated equity affiliates in the financial statements. Certain terms of the partnership arrangement allocated income from various sources, and the taxes on that income, on a significantly disproportionate basis through 2003. Losses and distributions from operations are allocated to the partners equally. Substantially all of Entergy-Koch's profits were allocated to Entergy in 2003, 2002, and 2001. Effective January 1, 2004, a revaluation of Entergy-Koch's assets for legal capital account purposes occurred, and future profit allocations changed after the revaluation. The profit allocations other than for weather trading and international trading became equal. Profit allocations for weather trading and international trading remain disproportionate to the ownership interests. The weather trading and international trading alloca tions are unequal only within a specified range, such that the overall earnings allocation should not materially differ from 50/50. Earnings allocated under the terms of the partnership agreement constitute equity, not subject to reallocation, for the partners.

2002 Compared to 2001

The decrease in earnings for Energy Commodity Services in 2002 from $105.9 million to a $145.8 million loss was primarily due to the 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. Entergy recorded net charges of $428.5 million ($238.3 million net-of-tax) to operating expenses. The net charges consist 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, is 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 results 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 reflects 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 relates to the restructuring of the non-nuclear wholesale assets business, which is 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 results from the write-off of capitalized project development costs for projects that will 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.

Also, in the first quarter of 2002, Energy Commodity Services sold its interests in projects in Argentina, Chile, and Peru for net proceeds of $135.5 million. After impairment provisions recorded for these Latin American interests in 2001, the net loss realized on the sale in 2002 was insignificant.

Revenues and fuel and purchased power expenses decreased for Energy Commodity Services by $1,075.8 million and $876.9 million, respectively, in 2002 primarily due to:

    • a decrease of $542.9 million in revenues and $539.6 million in fuel and purchased power expenses resulting from the sale of Highland Energy in the fourth quarter of 2001;
    • a decrease of $161.7 million in revenues resulting from the sale of the Saltend plant in August 2001; and
    • a decrease of $139.1 million in revenues and $133.5 million in purchased power expenses due to the contribution of substantially all of Entergy's power marketing and trading business to Entergy-Koch in February 2001. Earnings from Entergy-Koch are reported as equity in earnings of unconsolidated equity affiliates in the financial statements. The net income effect of the lower revenues was more than offset by the income from Entergy's investment in Entergy-Koch. The income from Entergy's investment in Entergy-Koch was $31.9 million higher in 2002 primarily as a result of earnings at Entergy-Koch Trading (EKT) and higher earnings at Gulf South Pipeline due to more favorable transportation contract pricing. Although the gain/loss days ratio reported above declined in 2002, EKT made relatively more money on the gain days than the loss days, and thus had an increase in earnings for the year.

Parent & Other

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

The loss from Parent & Other decreased in 2002 from $57.9 million to $38.6 million primarily due to:

    • a decrease in income tax expense of $12.1 million resulting from the allocation of intercompany tax benefits; and
    • a decrease in interest charges of $6.0 million.

Income Taxes

The effective income tax rates for 2003, 2002, and 2001 were 37.9%, 32.1%, and 38.3%, 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.

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 percentage for 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. The reduction in the percentage for 2002 is primarily the result of the sale of Damhead Creek in December 2002. Debt outstanding on the Damhead Creek facility was $458 million as of December 31, 2001.

2003

2002

2001

Net debt to net capital at the end of the year

45.3%

47.7%

51.1%

Effect of subtracting cash from gross debt

2.2%

4.1%

2.2%

Debt to capital at the end of the year

47.5%

51.8%

53.3%

Net debt consists of gross debt less cash and cash equivalents. Gross debt consists of notes payable, capital lease obligations, preferred stock with sinking fund, and long-term debt, including the currently maturing portion. Net capital consists of net debt, common shareholders' equity, and preferred stock without sinking fund. The preferred stock with sinking fund is included in gross debt pursuant to SFAS 150, which Entergy implemented in the third quarter of 2003. The 2002 and 2001 ratios do not reflect that type of security as debt, but do 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 2002 by operating segment. A significant factor in the change from 2002 to 2003 is over $2 billion of debt refinancing or retirement activity in the U.S. Utility business in 2003. 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

 

2003

 

2004

 

2005

 

2006

 

2007-2008

 

after 2008

  

 

(In Millions)

  

 

  

 

  

 

  

 

  

 

  

 

  

As of December 31, 2002

 

  

 

  

 

  

 

  

 

  

 

  

U.S. Utility

 

$1,111

 

$855

 

$470

 

$68

 

$654

 

$3,718

Non-Utility Nuclear

 

$87

 

$91

 

$95

 

$98

 

$119

 

$193

Energy Commodity Services

 

$79

 

-

 

-

 

-

 

-

 

-

Parent and Other

 

-

 

$595

 

-

 

-

 

-

 

$267

  

 

  

 

  

 

  

 

  

 

  

 

  

As of December 31, 2003

 

  

 

  

 

  

 

  

 

  

 

  

U.S. Utility

 

-

 

$450

 

$355

 

$28

 

$1,254

 

$4,345

Non-Utility Nuclear

 

-

 

$74

 

$72

 

$76

 

$100

 

$193

Energy Commodity Services

 

-

 

-

 

-

 

-

 

-

 

-

Parent and Other

 

-

 

-

 

$60

 

-

 

$272

 

$568

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

 

Capital lease obligations, including nuclear fuel leases, are a minimal part of Entergy's overall capital structure, and are discussed further in Note 10 to the consolidated financial statements. Following are Entergy's payment obligations under those leases:

  

2004

 

2005

 

2006

 

2007-2008

 

after 2008

  

(In Millions)

Capital lease payments, including nuclear fuel leases

$165

 

$142

 

$6

 

$5

 

$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, 2003. Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and Entergy Mississippi each have 364-day credit facilities available as follows:


Company

 


Expiration Date

 

Amount of Facility

 

Amount Drawn as of Dec. 31, 2003

 

 

 

 

  

 

 

Entergy Corporation

 

May 2004

 

$1.450 billion

 

-

Entergy Arkansas

 

April 2004

 

$63 million

 

-

Entergy Louisiana

 

May 2004

 

$15 million

 

-

Entergy Mississippi

 

May 2004

 

$25 million

 

-

Although the Entergy Corporation credit line expires in May 2004, Entergy has the discretionary option to extend the period to repay the amount then outstanding for an additional 364-day term. Because of this option, which Entergy intends to exercise if it does not renew the credit line or obtain an alternative source of financing, any debt outstanding on the credit line is reflected in long-term debt on the balance sheet. Entergy Corporation's facility requires 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 facility's maturity date may occur.

Operating Lease Obligations and Guarantees of Unconsolidated Obligations

In addition to the obligations listed above that are reflected on the balance sheet, Entergy has a minimal amount of operating leases and guarantees in support of unconsolidated obligations that are not reflected as liabilities on the balance sheet. These items are not on the balance sheet in accordance with generally accepted accounting principles.

Following are Entergy's payment obligations as of December 31, 2003 on non-cancelable operating leases with a term over one year:

 

2004

 

2005

 

2006

 

2007-2008

 

after 2008

 

(In Millions)

 

 

 

 

 

 

 

 

 

 

Operating lease payments

$99

 

$89

 

$70

 

$93

 

$245

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

Entergy's guarantees of unconsolidated obligations outstanding as of December 31, 2003 total a maximum amount of $249 million, detailed as follows:

    • In August 2001, EntergyShaw entered into a turnkey construction agreement with an Entergy subsidiary, Entergy Power Ventures, L.P. (EPV), and with Northeast Texas Electric Cooperative, Inc. (NTEC), providing for the construction by EntergyShaw of a 550 MW electric generating station to be located in Harrison County, Texas. Entergy has guaranteed the obligations of EntergyShaw to construct the plant, which is 70% owned by EPV. Entergy's maximum liability on the guarantee is $232.5 million, and the guarantee is expected to remain outstanding through June 2004.
    • RS Cogen has an interest rate swap agreement that hedges the interest rate on a portion of its debt. Entergy guaranteed RS Cogen's obligations under the interest rate swap agreement. The guarantee is for $16.5 million and terminates in October 2017.

Summary of Contractual Obligations of Consolidated Entities

Contractual Obligations

 

2004

 

2005-2006

 

2007-2008

 

after 2008

 

Total

     

(In Millions)

  

 

 

 

 

 

 

 

 

 

 

Long-term debt (1)

 

$524

 

$591

 

$1,626

 

$5,106

 

$7,847

Capital lease obligations (2)

 

$165

 

$148

 

$5

 

$3

 

$321

Operating leases (2)

 

$99

 

$159

 

$93

 

$245

 

$596

Purchase obligations (3)

 

$925

 

$1,007

 

$907

 

$1,446

 

$4,285

(1)

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

(2)

Capital lease obligations include nuclear fuel leases. Lease obligations are discussed in Note 10 to the consolidated financial statements.

(3)

As defined by SEC rule. For Entergy, it includes unconditional fuel and purchased power obligations and other purchase obligations. Approximately 97% 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.

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 1;
    • 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 2004 through 2006:

 

Planned construction and capital investments

2004

2005

2006

   

(In Millions)

Maintenance Capital:

U.S. Utility

$767

$767

$759

Non-Utility Nuclear

73

68

76

Energy Commodity Services

7

2

2

Parent and Other

7

10

14

854

847

851

Capital Commitments:

U.S. Utility 

569

295

112

Non-Utility Nuclear

123

-

-

Energy Commodity Services

73

-

-

Parent and Other

32

-

-

797

295

112

Total

$1,651

$1,142

$963

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 that Entergy is either contractually obligated or otherwise required to make pursuant to a regulatory agreement or existing rule or law. Amounts reflected in this category include the following:

    • Replacement of the ANO 1 steam generators and reactor vessel closure head. Entergy estimates the cost of the ANO 1 project to be approximately $235 million, of which approximately $135 million will be incurred through 2004. Entergy expects the replacement to occur during a planned refueling outage in 2005. Entergy Arkansas filed in January 2003 a request for a declaratory order by the APSC that the investment in the replacement is in the public interest analogous to the order received in 1998 prior to the replacement of the ANO 2 steam generators. The APSC found that the replacement is in the public interest in a declaratory order issued in May 2003.
    • Purchase of the Perryville power plant in Louisiana. In January 2004, Entergy Louisiana signed an agreement to acquire the 718 MW Perryville power plant for $170 million. The plant is owned by a subsidiary of Cleco Corporation, which subsidiary submitted a bid in response to Entergy's Fall 2002 request for proposals for supply-side resources. The signing of the agreement followed a voluntary Chapter 11 bankruptcy filing by the plant's owner. Entergy expects that Entergy Louisiana will own 100 percent of the Perryville plant, and that Entergy Louisiana will sell 75 percent of the output to Entergy Gulf States under a long-term cost-of-service purchased power agreement. The purchase of the plant, expected to be completed by December 2004, is contingent upon obtaining necessary approvals from the bankruptcy court and from state and federal regulators, including approval of full cost recovery, giving consideration to the need for the power and the prudence of Entergy Louisiana and Ente rgy Gulf States for engaging in the transaction. In addition, Entergy Louisiana and Entergy Gulf States executed a purchased power agreement with the plant's owner through the date of the acquisition's closing (as long as that occurs by September 2005) for 100 percent of the output of the Perryville plant.
    • Nuclear power plant uprates.
    • Entergy's obligation in the Energy Commodity Services business to make a $72.7 million cash contribution to Entergy-Koch in January 2004. Entergy made the contribution on January 2, 2004.

 

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 or commitment 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, because Entergy's contracts with the generators require the generators to fund the upgrades, which Entergy then repays through credits against billings to the generators.

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 July 2003 meeting, the Board increased Entergy's quarterly dividend per share by 29%, to $0.45. Entergy expects the next review of a potential dividend increase will occur in October 2004. Given the current number of Entergy common shares outstanding, Entergy expects the July 2003 dividend increase to result in an incremental annual increase in cash used of approximately $90 million. In 2003, Entergy paid $363 million in cash dividends on its common stock.

In accordance with Entergy's stock option plans, Entergy periodically grants stock options to its employees, which may be exercised to obtain shares of Entergy's common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy's management has been authorized to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans. In 2003, Entergy repurchased 155,000 shares of common stock for a total purchase price of $8.1 million.

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, 2003, Entergy's investments subject to this rule totaled $2.59 billion constituting 58.3% 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. Entergy currently has sufficient capacity under this order for its foreseeable needs.

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, 2003 was approximately $1.6 billion.

 

Sources of Capital

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

    • internally generated funds;
    • cash on hand ($692 million as of December 31, 2003);
    • securities issuances;
    • bank financing under new or existing facilities; and
    • sales of assets.

The majority of Entergy's internally generated funds come from the domestic utility companies and System Energy. Circumstances such as weather patterns, price fluctuations, and unanticipated expenses, including unscheduled plant outages, 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, 2003, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $309.4 million and $41.9 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, other agreements. The domestic utility companies and System Energy have sufficient capacity under these tests to meet foreseeable capital needs.

Short-term borrowings by the domestic utility companies and System Energy, including borrowings under the intra-company money pool, are limited to amounts authorized by the SEC. Under the SEC order authorizing the short-term borrowing limits, the domestic utility companies and System Energy cannot incur new short-term indebtedness if the issuer's common equity would comprise less than 30% of its capital. See Note 4 to the consolidated financial statements for further discussion of Entergy's short-term borrowing limits.

Cash Flow Activity

As shown in Entergy's Statements of Cash Flows, cash flows for the years ended December 31, 2003, 2002, and 2001 were as follows:

2003

2002

2001

(In Millions)

Cash and cash equivalents at beginning of period

$1,335 

$752 

$1,382 

Cash flow provided by (used in):

   Operating activities

2,006 

2,181 

2,216 

   Investing activities

(1,783)

(1,388)

(2,224)

   Financing activities

(869)

(213)

(622)

Effect of exchange rates on cash and cash equivalents

Net increase (decrease) in cash and cash equivalents

(643)

583 

(630)

Cash and cash equivalents at end of period

$692 

$1,335 

$752 

 

Operating Cash Flow Activity

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. Management expects that the deferred fuel costs will be recovered through regulatory recovery mechanisms currently in place.
    • 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 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 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 that is discussed below.

2002 Compared to 2001

Entergy's cash flow provided by operating activities decreased in 2002 primarily due to:

    • The U.S. Utility provided $2,341 million in operating cash flow, an increase of $693 million compared to 2001. The increase primarily resulted from the tax accounting election made by Entergy Louisiana that is discussed below.
    • The parent company used $439 million in operating cash flow compared to providing $407 million in 2001. The decrease primarily resulted from the payment that Entergy Corporation made to Entergy Louisiana pursuant to the tax accounting election made by Entergy Louisiana that is discussed below.
    • The Non-Utility Nuclear business provided $282 million in operating cash flow, an increase of $18 million compared to 2001.
    • Entergy's investment in Entergy-Koch used $47 million in operating cash flow in 2002, a decrease of $8 million compared to 2001. The use of cash primarily relates to tax payments on Entergy's share of the partnership income. Entergy did not receive a dividend from Entergy-Koch in 2002 or in 2001 because the joint venture was retaining capital for business opportunities.
    • The non-nuclear wholesale assets business provided $43 million in operating cash flow in 2002, compared to using $73 million in 2001.

Tax Election

In 2001, Entergy Louisiana changed its method of accounting for tax purposes related to the contract to purchase power from the Vidalia project (the contract is discussed in Note 9 to the consolidated financial statements). The new tax accounting method has provided a cumulative cash flow benefit of approximately $805 million through 2003, 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

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 has $77 million and Entergy Mississippi has $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. There is approximately $60 million of cash collateral remaining that Entergy expects to be released in March 2004 as a result of the regularly scheduled payment on the note payable to NYPA.

2002 Compared to 2001

Net cash used in investing activities decreased in 2002 primarily due to the following:

    • Entergy used $420 million less cash in its 2002 nuclear power plant purchase than it used in its 2001 purchase. In July 2002, Entergy's Non-Utility Nuclear business purchased the Vermont Yankee nuclear power plant for $180 million in cash. In September 2001, Entergy's Non-Utility Nuclear business purchased the Indian Point 2 nuclear power plant for $600 million in cash. The liabilities to decommission both plants, as well as related decommissioning trust funds, were also transferred to Entergy. These decommissioning trust transfers are reflected in the non-cash activity section of the cash flow statements.
    • Entergy made cash contributions of approximately $414 million in 2001 in connection with the formation of Entergy-Koch.
    • Entergy made a $272 million cash investment in 2001 to provide the collateral, discussed above, for the letter of credit that secures the installment obligations owed to NYPA. Approximately $40 million of this collateral was released to Entergy in 2002.
    • Entergy used $150 million to invest in temporary investments with a maturity of greater than 90 days in 2001 and those investments matured in 2002. This resulted in a net decrease of $300 million in cash used in 2002.

Partially offsetting the decrease in net cash used in investing activities were the following:

    • Entergy received less cash from sales of businesses in 2002 than it received in 2001. The sale of the Saltend plant in August 2001 provided approximately $810 million in cash, while the sale of various projects in 2002 provided approximately $215 million in cash.

    • Entergy spent approximately $150 million more on construction in 2002 than in 2001, primarily for construction of the Harrison County project.

Financing Activities

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.

2002 Compared to 2001

Net cash used in financing activities decreased in 2002 primarily due to:

    • Entergy increased the net borrowings under Entergy Corporation's credit facilities by $295 million in 2002.
    • Entergy Corporation issued $267 million of long-term notes in 2002.
    • The non-nuclear wholesale assets business used $196 million less cash in 2002 to retire debt than it did in 2001. This primarily resulted from two transactions. The non-nuclear wholesale assets business retired $268 million of long-term debt in April 2002 related to the acquisition of the rights to purchase turbines from a special-purpose financing entity. In 2001 the non-nuclear wholesale assets business retired the $555 million outstanding on the Saltend credit facility when the plant was sold.
    • Issuances of long-term debt net of retirements by the U.S. Utility segment provided $113 million less cash in 2002 than in 2001. Net issuances were $76 million in 2002 compared to $189 million in 2001.
    • Entergy repurchased $81.6 million more of its common stock in 2002 than in 2001.

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

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 FERC, are primarily responsible for approval of the rates charged to customers. The status of material retail rate proceedings are 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 cases are pending. Transition cost account mechanism expired on December 31, 2001. It is likely that a rate filing will be made in mid-2005 in connection with the steam generator replacement at ANO.

Entergy Gulf States-Texas

 

10.95%

 

Base rates have been frozen since settlement order issued in June 1999. Freeze will likely extend to the start of retail open access, given management's current expectations as to the start date of retail open access.

Entergy Gulf States-Louisiana

 

11.1%

 

The LPSC approved a settlement resolving the 4th - 8th post-merger earning reviews resulting in a $22.1 million prospective rate reduction effective January 2003 and a refund of $16.3 million. 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 9th earnings analysis (2002). Hearings are set for April 2004. With the LPSC staff, Entergy Gulf States continues to pursue the development of a performance-based rate structure.

Entergy Louisiana

 

9.7%-
11.3%(1)

 

In January 2004, Entergy Louisiana filed with the LPSC for a $167 million base rate increase and an ROE of 11.4%. The current ROE midpoint is 10.5%.  Hearings are currently set for September 2004. With the LPSC staff, Entergy Louisiana continues to pursue the development of a performance-based rate structure.

Entergy Mississippi

 

10.64%-
12.86%(2)

 

An annual formula rate plan is in place. The MPSC approved a $48.2 million rate increase effective January 2003 and an ROE midpoint of 11.75%. Entergy Mississippi will make a formula rate plan filing in March 2004.

Entergy New Orleans

 

10.25%-12.25%(3)

 

The City Council approved an agreement in May 2003 allowing for a $30.2 million increase in base rates effective June 1, 2003 and approved the implementation of formula rate plans for the electric and gas service that will be evaluated annually until 2005. An appeal of the approval by intervenors is pending, but the rates remain in effect. The midpoint ROE of both plans is 11.25%, with a target equity component of 42%. Entergy New Orleans will make a formula rate plan filing in May 2004.

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 overage, and if below, increased by 60 percent of the 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. The benchmark ROE set out in the March 15, 2004, formula rate plan filing likely will differ from the last approved ROE. Entergy Mississippi anticipates the March 15, 2004, filing will show an allowed regulatory earnings range of 9.3% to 12.2%. Entergy Mississippi does not anticipate a reduction in revenues going forward.

(3)

If Entergy New Orleans earns outside of 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, and if the ROE falls between 10.25% and 11%, rates are increased by 40 percent of the differential. 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 discussed below.

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.

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 pre-empted 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 pre-empted by federal law from reviewing and interpreting FERC 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. 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 the proceeding at FERC, the LPSC alleges that the domestic utility companies' annual production costs over the period 2002 to 2007 will be over or (under) the average for the domestic utility companies by the following amounts:

Entergy Arkansas

($130) to ($278) million

Entergy Gulf States - Louisiana

$11 to $87 million

Entergy Louisiana

$139 to $132 million

Entergy Mississippi

($27) to $13 million

Entergy New Orleans

$7 to $46 million

This range of results is a function of assumptions regarding such things as future natural gas prices, the future market price of electricity, and other factors. If FERC grants the relief requested by the LPSC, the relief may result in a material increase in production costs allocated to companies whose costs currently are projected to be less than the average and a material decrease in production costs allocated to companies whose costs currently are projected to exceed the average. Management believes that any changes in the allocation of production costs resulting from a FERC decision should result in similar rate changes for retail customers. Therefore, management does not believe that this proceeding will have a material effect on the financial condition of any of the domestic utility companies, although the outcome of the proceeding at FERC cannot be predicted at this time.

In February 2004 a FERC ALJ issued an Initial Decision in the proceeding. 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. Entergy continues to assess the potential effects of the ALJ's Initial Decision, and how it will respond to the decision. It appears that the shift in total production costs under the terms of the ALJ's Initial Decision would not be as great as that sought in the LPSC's complaint, but would still be substantial. As an Initial Decision, it is not a FERC order, and Entergy and the other parties in the proceeding will have additional opportunities to explain their positions in the proceeding prior to the issuance of a FERC decision. FERC does not have a deadline by which it has to decide the proceeding and management does not expect a FERC decision before the fourth quarter 2004.

On February 10, 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 includes a preliminary estimate that the FERC ALJ's Initial Decision would shift approximately $125 million of costs for the year 2003 to Entergy Arkansas' retail customers, and would shift an average of approximately $113 million per year for the years 2004-2011 to Entergy Arkansas' retail 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' initial testimony in the proceeding is due in Ap ril 2004.

In addition to the APSC's Order of Investigation, Entergy's retail regulators have and may continue to question the prudence and other aspects of Entergy System or domestic utility company contracts or assets that may not be subject to their respective jurisdictions. For instance, in its Order of Investigation, the APSC discusses aspects of Entergy Louisiana's power purchases from the Vidalia project, and the APSC has publicly announced its intention to initiate an inquiry into the Vidalia purchase power contract. Entergy believes that any such inquiry would have to occur at the FERC.

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 power purchase agreements (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:

   

2004

 

2005

 

2006

 

2007

 

2008

Non-Utility Nuclear:

                   

% of planned generation sold forward

 

100%

 

52%

 

32%

 

16%

 

4%

Planned generation (GWh)

 

32,787

 

34,164

 

34,853

 

34,517

 

34,513

Average price per MWh

 

$38

 

$37

 

$35

 

$34

 

$38

The Vermont Yankee acquisition included a 10-year PPA, which is through the expiration of the current operating license for the plant, under which the former owners will buy the power produced by the plant. The PPA includes an adjustment clause under which the prices specified in the PPA will be adjusted downward annually, 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 October 2005. Approximately 2% of Non-Utility Nuclear's planned generation in 2005, 13% in 2006, 12% in 2007, and 13% in 2008 is under contract from Vermont Yankee after October 2005.

Under the PPAs with NYPA for the output of power from Indian Point 3 and FitzPatrick, the Non-Utility Nuclear business is obligated to produce at an average capacity factor of 85% with a financial true-up payment to NYPA should NYPA's cost to purchase power due to an output shortfall be higher than the PPAs' price.  The calculation of any true-up payments is based on two two-year periods.  For the first period, which ran through November 20, 2002, Indian Point 3 and FitzPatrick operated at 95% and 97%, respectively, under the true-up formula.  Credits of up to 5% reflecting period one generation above 85% can be used to offset any output shortfalls in the second period, which runs through the end of the PPAs on December 31, 2004.

Included in the planned generation sold forward percentages are contracts entered into in 2003 that are not unit contingent but are firm contracts containing liquidated damages provisions. These firm contracts are for 1% of Non-Utility Nuclear's planned generation in 2005, 4% in 2006, 2% in 2007, and 0% in 2008.

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 Independent System Operators 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:

   

2004

 

2005

 

2006

 

2007

 

2008

Non-Utility Nuclear:

                   

Percent of capacity sold forward:

                   

  Bundled capacity and energy contracts

 

55%

 

15%

 

12%

 

13%

 

13%

  Capacity contracts

 

28%

 

15%

 

6%

 

3%

 

0%

  Total

 

83%

 

30%

 

18%

 

16%

 

13%

Planned MW in operation

 

4,111

 

4,203

 

4,203

 

4,203

 

4,203

Average capacity contract price per kW per month

 

$2.4

 

$1.3

 

$0.6

 

$0.7

 

N/A

Blended Capacity and Energy (based on revenues)

                   

% of planned generation and capacity sold forward

 

99%

 

49%

 

28%

 

13%

 

4%

Average contract revenue per MWh

 

$39

 

$37

 

$35

 

$34

 

$38

As of December 31, 2003, 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:

 

2004

 

2005

 

2006

 

2007

 

2008

Energy Commodity Services:

                 

Capacity

                 

Planned MW in operation

1,911

 

1,911

 

1,911

 

1,911

 

1,911

% of capacity sold forward

43%

 

43%

 

34%

 

31%

 

26%

Energy

                 

Planned generation (GWh)

3,321

 

3,348

 

3,337

 

3,545

 

4,015

% of planned generation sold forward

64%

 

67%

 

52%

 

42%

 

39%

Blended Capacity and Energy (based on revenues)

                 

% of planned energy and capacity sold forward

62%

 

66%

 

50%

 

41%

 

35%

Average contract revenue per MWh

$26

 

$25

 

$27

 

$31

 

$28

The increase in the planned generation sold forward percentages from the percentages reported in the 2002 Form 10-K is attributable to Entergy Louisiana and Entergy New Orleans contracts involving RS Cogen and Independence 2 entered into in 2003. These contracts are still subject to a FERC review proceeding scheduled for hearing later in 2004.

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.

Marketing and Trading

The earnings of Entergy's Energy Commodity Services segment are exposed to commodity price market risks primarily through Entergy's 50%-owned, unconsolidated investment in Entergy-Koch. Entergy-Koch Trading (EKT) uses value-at-risk models as one measure of the market risk of a loss in fair value for EKT's natural gas and power trading portfolio. Actual future gains and losses in portfolios will differ from those estimated based upon actual fluctuations in market rates, operating exposures, and the timing thereof, and changes in the portfolio of derivative financial instruments during the year.

To manage its portfolio, EKT enters into various derivative and contractual transactions in accordance with the policy approved by the trading committee of the governing board of Entergy-Koch. The trading portfolio consists of physical and financial natural gas and power as well as other energy and weather-related contracts. These contracts take many forms, including futures, forwards, swaps, and options.

 

Characteristics of EKT's value-at-risk method and the use of that method are as follows:

    • Value-at-risk is used in conjunction with stress testing, position reporting, and profit and loss reporting in order to measure and control the risk inherent in the trading and mark-to-market portfolios.
    • EKT estimates its value-at-risk using a model based on J.P. Morgan's Risk Metrics methodology combined with a Monte Carlo simulation approach.
    • EKT estimates its daily value-at-risk for natural gas and power using a 97.5% confidence level. EKT's daily value-at-risk is a measure that indicates that, if prices moved against the positions, the loss in neutralizing the portfolio would not be expected to exceed the calculated value-at-risk.
    • EKT seeks to limit the daily value-at-risk on any given day to a certain dollar amount approved by the trading committee.

EKT's value-at-risk measures, which it calls Daily Earnings at Risk (DE@R), for its trading portfolio were as follows:

   

2003

 

2002

 

2001

       

(in millions)

   

DE@R at end of the year

 

$9.6

 

$15.2

 

$5.5

Average DE@R for the year

 

13.6

 

10.8

 

6.4

Low DE@R for the year

 

5.9

 

6.6

 

3.6

High DE@R for the year

 

35.2

 

16.9

 

8.0

EKT's DE@R at the end of the year was lower in 2003 compared to 2002 as a result of reduced strength of point-of-view during the second half of 2003. EKT's average DE@R increased in 2003 compared to 2002 as a result of an increase in the size of the position held, particularly during the first quarter of 2003. EKT's average DE@R increased in 2002 compared to 2001 as a result of an increase in the size of the position held and an increase in the volatility of natural gas prices in the latter part of the year.

For all derivative and contractual transactions, EKT is exposed to losses in the event of nonperformance by counterparties to these transactions. Relevant considerations when assessing EKT's credit risk exposure include:

    • EKT's operations are primarily concentrated in the energy industry.
    • EKT's trade receivables and other financial instruments are predominantly with energy, utility, and financial services related companies, as well as other trading companies in the U.S., UK, and Western Europe.
    • EKT maintains credit policies, which its management believes minimize overall credit risk.
    • Prospective and existing customers are reviewed for creditworthiness based upon pre-established standards, with customers not meeting minimum standards providing various secured payment terms, including the posting of cash collateral.
    • EKT also has master netting agreements in place. These agreements allow EKT to offset cash and non-cash gains and losses arising from derivative instruments with the same counterparty. EKT's policy is to have such master netting agreements in place with significant counterparties.

Based on EKT's policies, risk exposures, and valuation adjustments related to credit, EKT does not anticipate a material adverse effect on its financial position as a result of counterparty nonperformance. As of December 31, 2003 approximately 91% of EKT's counterparty credit exposure is associated with companies that have at least investment grade credit ratings.

 

Following are EKT's mark-to-market assets (liabilities) and the period within which the assets (liabilities) would be realized (paid) in cash if they are held to maturity and market prices are unchanged:

Maturities and Sources for Fair Value of Trading Contracts at December 31, 2003



0-12 months



13-24 months



25+ months



Total

   

(In Millions)

Prices actively quoted

 

$126.3 

 

($87.1)

 

($14.6)

 

$24.6 

Prices provided by other sources

4.8 

(10.1)

5.6 

0.3 

Prices based on models

 

(28.0)

 

14.2 

 

4.9 

 

(8.9)

Total

 

$103.1 

 

($83.0)

 

($4.1)

 

$16.0 

Following is a roll-forward of the change in the fair value of EKT's mark-to-market contracts during 2003:

   

2003

   

(In Millions)

Fair value of contracts outstanding at December 31, 2002 after implementation of EITF 02-03

 

$90.9 

     

(Gain)/loss from contracts realized/settled during the year

 

(580.0)

Net option premiums received during the year

 

275.7 

Change in fair value of contracts attributable to market movements during the year

 

229.4 

Net change in contracts outstanding during the year

 

(74.9)

Fair value of contracts outstanding at December 31, 2003

$16.0 

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 142.8 million Euro and the forward currency rates range from .8641 to 1.085. The maturities of these forward contracts depend on the purchase contract payment dates and range in time from January 2004 to January 2007. The mark-to-market valuation of the forward contracts at December 31, 2003 was a net asset of $50 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, 2003.

Interest Rate and Equity Price Risk - Decommissioning Trust Funds

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 1, 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 1, 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 $895 million of fixed-rate, fixed-income securities as of De cember 31, 2003. These securities have an average coupon rate of approximately 5.6%, 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, 2003. 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 and 9 to the consolidated financial statements.

Utility Restructuring

In Entergy's U.S. Utility service territory, movement to retail competition either has not occurred or has been abandoned, with the exception of Texas, where it has been significantly delayed. At FERC, the pace of restructuring at the wholesale level has begun but has also been delayed. It is too early to predict the ultimate effects of changes in U.S. energy markets. Restructuring issues are complex and are continually affected by events at the national, regional, state, and local levels. These changes may result, in the long-term, in fundamental changes in the way traditional integrated utilities and holding company systems, like the Entergy system, conduct their business. Some of these changes may be positive for Entergy, while others may not be.

In the long-term, these changes may result in increased costs associated with utility unbundling of services or functions and transitioning in new organizational structures and ways of conducting business. It is possible that the new organizational structures that may be required will result in lost economies of scale, less beneficial cost sharing arrangements within utility holding company systems, and, in some cases, greater difficulty and cost in accessing capital. Furthermore, these changes could result in early refinancing of debt, the reorganization of debt, or other obligations between newly formed companies and Entergy. As a result of federal and state "codes of conduct" and affiliate transaction rules, adopted as part of restructuring, new non-utility affiliates in Entergy's system may be precluded from, or limited in, doing business with affiliated electric market participants, or have prices set at the lower of cost or market. In addition, regulators may impose limits on (pr ice caps), rather than have the market set, wholesale energy prices. There are a number of other changes that may result from electric business competition and unbundling, including, but not limited to, changes to labor relations, management and staffing, structure of operations, environmental compliance responsibility, and other aspects of the utility business.

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. Entergy's domestic utility companies were participating with other transmission owners within the southeastern United States to establish an RTO, the proposed SeTrans RTO, but the sponsors determined that the regulatory approvals necessary for the development of the SeTrans RTO were unlikely to be obtained at the present time and in December 2003 suspended further development activity. Although SeTrans development is suspended, Entergy continues to focus its efforts on reforms that can further the core objectives of FERC's 2000 ord er: achieving greater independence in the provision of transmission service and a more efficient method of pricing that service. Entergy intends to work with FERC and Entergy's retail regulators on certain voluntary steps to further those objectives.

As currently contemplated, and assuming applicable regulatory support and approvals can be obtained, Entergy plans to contract with an independent transmission entity to oversee the granting of transmission service on the Entergy system as well as the implementation of the weekly procurement process that Entergy has proposed. Entergy will submit to the FERC for its approval the proposed contract setting forth the independent entity's duties and obligations as well as other documents necessary to implement this proposed structure. The proposed structure does not transfer control of Entergy's transmission system to the independent entity, but rather will vest with the independent entity broad oversight authority over transmission planning and operations.

Entergy also intends that the independent transmission entity will administer a transition to participant funding that should increase the efficiency of transmission pricing on the Entergy system. Entergy intends for the independent transmission entity 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. 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.

On February 13, 2004 a group of ten market participants filed with the FERC a response to the announcement that the SeTrans sponsors had suspended further development efforts. In their response, the participants allege that absent the SeTrans RTO the dominant utilities in the southeastern United States (Entergy and Southern Company) will continue to maintain control over the transmission system and will continue to have the ability to exercise market power in the wholesale market. The market participants urge the FERC to: (1) order Entergy and Southern to immediately turn over control of their OASIS system to an independent entity; (2) initiate a formal investigation into competitive conditions in the southeastern United States; (3) issue a show cause order regarding revocation of Entergy's and Southern's market-based rate authority; and (4) either order Entergy and Southern into an RTO or initiate proceedings to appoint a market monitor and conduct various audits of Entergy's and South ern's practices and procedures related to the granting of transmission service and the planning of the transmission system. Entergy believes that the allegations contained in the response are without merit and plans to vigorously defend itself. See additional discussion related to this issue in the FERC's Supply Margin Assessment section below.

In September 2001, the LPSC ordered Entergy Gulf States and Entergy Louisiana to show cause as to why these companies should not be enjoined from transferring their transmission assets, or control of those transmission assets, to an ITC (independent transmission company), RTO, or any similar organization, asserting that FERC does not have jurisdiction to mandate an ITC or RTO. This proceeding is pending.

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 is buying or selling in the hourly wholesale market within its control area. Entergy requested rehearing of the order, and FERC has delayed the implementation of certain mitigation measures until such time as it has had the opportunity to consider the rehearing request. In June 2003, the FERC proposed and ultimately ado pted 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 has requested rehearing of FERC's order. Additionally, during December 2003 the FERC announced it was holding additional technical conferences on proposed modifications to its Supply Margin Assessment screen. Two technical conferences were held during January 2004. Entergy has filed comments in this proceeding urging the FERC to rely on an "uncommitted capacity" version of any market screen in order to reflect a utility's native load obligations. It is Entergy's belief that cost-based regulation effectively mitigates both the ability and the incentive to exercise market power to the extent of the native load obligations. A FERC rule on Supply Margin Assessment could be issued by the end of March 2004.

Separately, Entergy-Koch Trading filed its triennial market power update on January 26, 2004. Three market participants intervened and urged the FERC to reject Entergy-Koch Trading's triennial update and terminate Entergy-Koch Trading's, the domestic utility companies', and their affiliates' market-based rate authority for sales within the Entergy control area unless and until adequate mitigation measures have been implemented. If the FERC were to revoke Entergy-Koch Trading's, the domestic utility companies', and their affiliates' 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. Entergy's wholesale sales within its control area could be cost-justified and the wholesale electricity sales of Entergy-Koch Trading within Entergy's control area are of a limited amount; therefore management does not believe that the revocation of market-based rate authority would have a material effect on the financial results of Entergy. In spite of this, Entergy intends to vigorously defend its market-based rate authority.

In a separate, but related proceeding, in December 2003, the FERC determined that the acquisition by Oklahoma Gas & Electric (OG&E) of a generating facility within its control area from a non-affiliated entity would undermine competition and was, accordingly, not consistent with the public interest. Based on this conclusion, the FERC then set the matter for hearing to determine what mitigation remedies would be necessary to address the market power issues. The FERC's determination that the acquisition would raise market power concerns was premised on an analysis that relied on OG&E's total capacity, not its uncommitted capacity. This proceeding, and the FERC's ultimate ruling, could significantly affect a utility's ability to acquire needed non-affiliated generation resources in its service territory, such as the pending purchase of the Perryville power plant by Entergy Louisiana.

Interconnection Orders

In January 2003, the FERC issued two orders in proceedings involving Interconnection Agreements between each of the domestic utility companies (except Entergy New Orleans) and certain generators interconnecting to the domestic utility companies' transmission system. In the orders, the FERC authorized the generators to abrogate certain provisions of the interconnection agreements in order to avail themselves of new FERC policies developed after the generators' execution of the agreements. Under the FERC's orders, capital costs that the generators had agreed to bear will now be shifted to Entergy's native load and other transmission customers. Other generators that previously had executed interconnection agreements agreeing to bear similar costs have also filed complaints to obtain the same or similar relief against the domestic utility companies. In the event that the generators that have interconnected to the Entergy transmission system are successful in obtaining such relief, it i s estimated that approximately $280 million of costs will be shifted from the interconnecting generators to the domestic utility companies' other transmission customers, including the domestic utility companies' bundled-rate retail customers. Entergy intends to pursue all regulatory and legal avenues available to it in order to have these orders reversed, and the affected interconnection agreements reinstated as agreed to by the generators. The domestic utility companies had appealed previously to the Court of Appeals for the D.C. Circuit the FERC orders initially establishing the new FERC policy that was applied retroactively in the January orders. In the orders currently pending before the D.C. Circuit, the FERC had applied the new policy on a prospective basis. In an opinion issued in February 2003, the D.C. Circuit denied Entergy's petition for review in one proceeding, concluding that the FERC had not acted in an arbitrary and capricious manner when it changed its policy from that of directly assign ing certain interconnection costs to the generator to a policy in which those costs are borne by all customers on the domestic utility companies' transmission system. A related proceeding concerning a similar change in policy for another segment of interconnection costs is still pending before the D.C. Circuit.

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Among other things, Order 2003 incorporates pricing policies that require the transmission provider's other customers to bear the vast majority of costs required when a new generator interconnects to its transmission system or requests transmission upgrades necessary for the generator to be considered a network resource for load serving entities within the transmission provider's control area. Order 2003 also requires that generators that fund upgrades receive their money back, with interest, in no more than five years. Order 2003, which the FERC has indicated is to be applied only to prospective interconnection agreements, became effective on January 20, 2004. Consistent with their past practices, the generators that had previously executed interconnection agreements with Entergy and that have transmission credits outstanding have filed complaints at the FERC seeking to avail themselves of the more beneficial crediting aspects of the FERC's final rule. Entergy has opposed such relief and the proceedings are pending. On March 5, 2004, the FERC issued an order on rehearing responding to certain issues raised with respect to Order 2003. While management is still analyzing the order on rehearing, it appears that the FERC has modified Order 2003 to, among other things, eliminate the requirement that the generators receive their money back in no more than five years and include a requirement that the generators receive credits only when transmission service is taken from the specific generating facility served by the interconnection or upgrade. Because the order on rehearing was just issued, however, management's analysis of the effects of the order is ongoing.

Retail

Only in the Texas portion of Entergy Gulf States' service territory has there been significant movement toward retail open access, but implementation has been delayed in that territory. Entergy does not expect that retail open access is likely to begin for Entergy Gulf States before the first quarter of 2005. Entergy Gulf States' Texas-jurisdictional base rates remain unchanged as a result of a base rate freeze implemented in connection with the delay in implementation of retail open access in its Texas service territory. While the PUCT has approved, on an interim basis, a business separation plan for Entergy Gulf States in Texas, and has approved market protocols to implement an interim solution (retail open access without a FERC-approved RTO), several other proceedings necessary to implement retail open access are still pending in Texas. In addition, the LPSC has not approved certain matters needed for retail open access to begin in Texas. Delay in the start of retail open access may delay or jeopardize the regulatory approvals required for retail open access. Retail open access legislation has not been enacted in the other jurisdictions in Entergy's service territory, except for in Arkansas, where it was repealed in February 2003. The status of electric industry restructuring in Entergy's U.S. Utility service territory is more thoroughly discussed in Note 2 to the consolidated financial statements.

Federal Legislation

Federal legislation intended to facilitate wholesale competition in the electric power industry has been seriously considered by the United States Congress, in both the House of Representatives and the Senate. In 2003, both the House and Senate passed separate versions of comprehensive energy legislation. The bills contain electricity provisions that would, among other things, repeal PUHCA, repeal or modify PURPA, enact a mechanism for establishing enforceable reliability standards, provide FERC with new authority over utility mergers and acquisitions, and codify FERC's authority over market-based rates. Late in 2003, a conference committee approved a bill reconciling the differences between the two bills, but that bill has not been brought up for a vote in the Senate.

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 shutdown 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 area where Entergy's Indian Point units are located, which are discussed in more detail below. These concerns have led 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 intends to vigorously respond to these concerns and proposals.

Groups of concerned citizens and local public officials have raised concerns about safety issues associated with Entergy's Indian Point power plants located in New York. They argue that Indian Point's security measures and emergency plans do not provide reasonable assurance to protect the public health and safety. The NRC has original jurisdiction over these matters. In a decision that became final on December 13, 2002, the NRC denied a petition filed by Riverkeeper, Inc. asking the NRC to order Entergy to suspend operations, revoke the operating license, or adopt other measures, including a temporary shutdown of Indian Point 2 and Indian Point 3. The NRC noted that after September 11, 2001, it ordered enhanced security measures at all nuclear facilities and found that as a result of the collective measures taken since September 11, 2001, the security at Indian Point provides adequate protection of public health and saf ety. The NRC further found that the existing emergency response plans are flexible enough to respond to a wide variety of adverse conditions, including a terrorist attack, and that the current spent fuel storage system adequately protects the public health and safety. Riverkeeper petitioned the United States Court of Appeals for the Second Circuit for review of this final action of the NRC, and in February 2004 the Second Circuit affirmed the NRC and dismissed the petition for review.

In addition, certain concerns are being raised regarding the adequacy of the emergency evacuation plans for Indian Point. These matters initially must be reviewed by the Federal Emergency Management Agency (FEMA). Jurisdiction as to the overall adequacy of emergency planning and preparedness for Indian Point lies with the NRC. Entergy believes that the emergency evacuation plans for Indian Point are adequate to ensure the public health and safety in compliance with NRC requirements. Entergy is working with New York state and county officials, FEMA, the NRC, and other federal agencies to make additional improvements to the plans that may be warranted and to assure them as to the adequacy of the plans.

In July 2003, FEMA issued its notice of certification of the Indian Point Emergency Plan. The NRC followed soon thereafter with its endorsement. In August 2003, Westchester County filed an administrative appeal of the FEMA ruling that the emergency plans are adequate to protect the public health and safety. FEMA regulations on emergency plans provide for appeals in only two situations: (1) FEMA's approval or disapproval of a radiological emergency response plan (RERP) for a nuclear power facility; and (2) FEMA's determination to withdraw approval for a state or local RERP. In both cases, the appeal process is the same.

Litigation

Entergy and its subsidiaries are involved in the ordinary course of business in a substantial amount of employment, 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 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 estimates as critical accounting estimates because they are based on assumptions and measurements that involve an unusual degree of uncertainty, and there is the potential that different assumptions and measurements could produce estimates that are significantly different than those recorded in Entergy's financial statements.

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 that these facilities be decommissioned after the facility is taken out of service, and funds are 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. Note 9 to the consolidated financial statements contains details regarding Entergy's most recent studies and the obligations recorded by Entergy related to decommissioning. 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 impact of these assumptions cannot be determined with precision, assuming either license extension or use of a "safestore" status can significantly decrease the present value of these obligations.

    • Spent Fuel Disposal - Federal regulations require the Department of Energy to provide a permanent repository for the storage of spent nuclear fuel, and recent legislation has been passed by Congress to develop this repository at Yucca Mountain, Nevada. However, until this site is available, 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 impact (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 U.S. 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 impact on cost estimates. The impact of these potential changes is not presently determinable. Entergy's decommissioning cost studies assume current technologies and regulations.

The implications of these estimates vary significantly between Entergy's U.S. Utility and Non-Utility Nuclear businesses. Separate discussions of these implications by business segment follow.

U.S. Utility

Entergy collects substantially all of the projected costs of decommissioning the nuclear facilities in its U.S. Utility business segment through rates charged to customers, except for portions of River Bend, which is discussed in more detail below. The amounts collected through rates, which are based upon decommissioning cost studies, are deposited in decommissioning trust funds. These collections plus earnings on the trust fund investments are generally estimated to be sufficient to fund the future decommissioning costs. For the U.S. Utility segment, if decommissioning cost study estimates were changed and approved by regulators, collections from customers would also change.

Approximately half of River Bend is not currently subject to cost-based ratemaking. When Entergy Gulf States obtained the 30% share of River Bend formerly owned by Cajun, Entergy Gulf States obtained decommissioning trust funds of $132 million, which have since grown to almost $150 million. Entergy Gulf States believes that these funds will be sufficient to cover the costs of decommissioning this portion of River Bend, and no further collections or deposits are being made for these costs. Additionally, under the Deregulated Asset Plan in the Louisiana jurisdiction of Entergy Gulf States, a portion of River Bend (approximately 16% of its total capacity) is excluded from rate base, and no amounts have been or are being collected for decommissioning for this portion of the plant.

Non-Utility Nuclear

In conjunction with the purchase of Entergy's Non-Utility Nuclear facilities, Entergy assumed the decommissioning obligations and received the related decommissioning trust funds (except for the NYPA acquisition, in which NYPA retained the decommissioning obligations for the Indian Point 3 and FitzPatrick units). Based on decommissioning cost studies and expected plant operation lives, Entergy believes that the amounts in the trust funds will be sufficient to fund future decommissioning costs without additional deposits from Entergy.

As Entergy has assumed these decommissioning obligations without any further external source of funding, changes in estimates of decommissioning costs for these units will have a direct impact on Entergy's financial position and results of operations.

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 to date have been based on Entergy performing the work, and have not included any such margins or premiums. Inclusion of these items increased cost estimates.
    • Discount rate - SFAS 143 requires that these obligations be discounted using a credit-adjusted, risk-free rate. This resulted in significant decreases in Entergy's decommissioning obligations in the Non-Utility Nuclear business, as this discount rate is higher than the implicit rates utilized by Entergy in accounting for these obligations through December 31, 2002.

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 a regulatory asset, with no resulting impact 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. Assets and liabilities increased by approximately $1.1 billion in 2003 for the domestic utility companies and System Energy 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 mill ion and recording the related 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 approximately $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 resulted in a decrease in liabilities in 2003 of approximately $595 million due to reductions in decommissioning liabilities, a decrease in assets of approximately $340 million, including a decrease in electric plant in service of $315 million, and an increase in earnings of approximately $155 million net-of-tax ($0.67 per share) as a result of the one-time cumulative effect of accounting change.

Also Entergy's 2003 earnings for the Non-Utility Nuclear business increased by approximately $18 million after-tax over 2002 because of the change in accretion of the liability and depreciation of the adjusted plant costs. 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.

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 for some time. 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., 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 12 to the consolidated financial statements.

Mark-to-market Accounting

The EITF reached a consensus to rescind Issue No. 98-10 effective January 1, 2003. Rescinding Issue No. 98-10 resulted in some energy-related contracts being accounted for on an accrual basis that were previously accounted for on a mark-to-market basis. Contracts that meet the provisions of SFAS 133 to qualify as derivatives are marked-to-market in accordance with the guidance in SFAS 133. Contracts such as capacity, transportation, storage, tolling, and full requirements contracts that are based on physical assets and do not meet the provisions of SFAS 133 to qualify as derivatives are accounted for using accrual accounting. Energy commodity inventories held by trading companies such as physical natural gas are accounted for at the lower of cost or market. The adoption of the consensus had minimal cumulative and ongoing earnings effects for Entergy's Energy Commodity Services business.

As required by generally accepted accounting principles, Entergy and Entergy-Koch mark-to-market commodity instruments held by them for trading and risk management purposes that are considered derivatives under SFAS 133. Because of the significant estimates and uncertainties inherent in mark-to-market accounting, this method is considered a critical accounting estimate for the Energy Commodity Services segment. Examples of commodity instruments that are marked to market include:

    • commodity futures, options, swaps, and forwards that are expected to be net settled; and
    • power sales agreements that do not involve delivery of power from Entergy's power plants.

Conversely, commodity contracts that are not considered derivatives, generally because they involve physical delivery of a commodity to the purchaser, are not marked to market. Examples of commodity contracts that are not marked to market include:

    • the PPAs for Entergy's Non-Utility Nuclear plants;
    • capacity purchases and sales by the U.S. Utility companies; and
    • forward contracts that will result in physical delivery.

Fair value estimates of the commodity instruments that are marked to market are made at discrete points in time based on relevant market information. Market quotes are used in determining fair value whenever they are available. When market quotes are not available (e.g., long-dated commodity contract), other information is used, including transactional data and internally developed models. Fair value estimates based on these other methodologies are necessarily subjective in nature and involve uncertainties and matters of significant judgment. These uncertainties include projections of macroeconomic trends and future commodity prices, including supply and demand levels and future price volatility. The impact of these uncertainties, however, is lessened by the relatively short-term nature of the mark-to-market positions held by Entergy and EKT.

Pension and Other Postretirement Benefits

Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy 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 11 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 poor 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, Entergy reviews market yields on high-quality corporate debt. Based on recent market trends, Entergy reduced its discount rate from 7.5% in 2001 and 6.75% in 2002 to 6.25% in 2003. 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 2003 accumulated postretirement benefit obligation. The assumed health care cost trend rate is a 10% increase in health care costs in 2004 gradually decreasing each successive year until it reaches a 4.5% annual increase in health care costs in 2010 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 66% equity securities, 30% fixed income securities, and 4% other investments. The target allocation for Entergy's other postretirement benefit assets is 45% equity securities and 55% fixed income securities. Based on recent market trends, Entergy decreased its expected long-term rate of return on plan assets from 9% in 2001 to 8.75% for 2002 and 2003. The trend of reduced inflation caused Entergy to reduce its assumed rate of increase in future compensation levels from 4.6% in 2001 to 3.25% in 2002 and 2003.

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 2003
Pension Cost

 

Impact on Projected
Benefit Obligation

   

Increase/(Decrease)

Discount rate

 

(0.25%)

 

$4,882

 

$83,651

Rate of return on plan assets

 

(0.25%)

 

$4,346

 

-

Rate of increase in compensation

 

0.25%

 

$4,039

 

$28,101

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 2003
Postretirement Benefit
Cost

 

Impact on Accumulated
Postretirement Benefit
Obligation

   

Increase/(Decrease)

Health care cost trend

 

0.25%

 

$5,206

 

$25,979

Discount rate

 

(0.25%)

 

$3,278

 

$29,500

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 smoothes the impact 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 2003, Entergy's total pension cost was $108 million, including a $47 million charge related to the voluntary severance program. Entergy anticipates 2004 pension cost to increase to $87 million due to a decrease in the discount rate from 6.75% to 6.25% and the phased-in effect of poor asset performance. Pension funding was $35 million for 2003 and in 2004 is projected to be $110 million due to the poor performance of the financial equity markets.

Due to negative pension plan asset returns from 2000 to 2002, Entergy's accumulated benefit obligation at December 31, 2003 and 2002 exceeded plan assets. As a result, Entergy was required to recognize an additional minimum liability as prescribed by SFAS 87. At December 31, 2003 Entergy reduced its additional minimum liability to $180.2 million ($149.4 million net of related pension assets) from $208.1 million ($175 million net of related pension assets) at December 31, 2002. This reduced the charge to other comprehensive income to $9.3 million at December 31, 2003 from $11 million at December 31, 2002, after reductions for the unrecognized prior service cost, amounts recoverable in rates, and taxes. Net income for 2003 and 2002 were not affected.

Total postretirement health care and life insurance benefit costs for Entergy in 2003 were $165 million, including a $64 million charge related to the voluntary severance program. In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 became law. The Act introduces a prescription drug benefit under Medicare (Part D) as well as a federal subsidy to employers who provide a retiree prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Currently, specific authoritative guidance on the accounting for the federal subsidy is pending. Entergy expects 2004 postretirement health care and life insurance benefit costs to approximate $102 million.

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 9 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. Entergy does not expect a material adverse effect from these matters.

ENTERGY CORPORATION AND SUBSIDIARIES

SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON

 

 

2003

 

2002

 

2001

 

2000

 

1999

 

(In Thousands, Except Percentages and Per Share Amounts)

                   

Operating revenues

$9,194,920

 

$8,305,035

 

$9,620,899

 

$10,022,129

 

$8,765,635

Income before cumulative
effect of accounting change


$813,393

 


$623,072

 


$727,025

 


$710,915

 


$595,026

Earnings per share before
cumulative effect of accounting
change
Basic
Diluted




$3.48
$3.42

 




$2.69
$2.64

 




$3.18
$3.13

 




$3.00
$2.97

 




$2.25
$2.25

Dividends declared per share

$1.60

 

$1.34

 

$1.28

 

$1.22

 

$1.20

Return on average common equity

11.21%

 

7.85%

 

10.04%

 

9.62%

 

7.77%

Book value per share, year-end

$38.02

 

$35.24

 

$33.78

 

$31.89

 

$29.78

Total assets

$28,554,210

 

$27,504,366

 

$25,910,311

 

$25,451,896

 

$22,969,940

Long-term obligations (1)

$7,497,690

 

$7,488,919

 

$7,743,298

 

$8,214,724

 

$7,252,697

(1)

Includes long-term debt (excluding currently maturing debt), preferred stock with sinking fund, preferred securities of subsidiary trusts and partnership, and noncurrent capital lease obligations.

 

2003

2002

2001

2000

1999

(Dollars In Thousands)

Domestic Electric Operating Revenues:

 Residential

$2,682,802

$2,439,590

$2,612,889

$2,524,529

$2,231,091

 Commercial

1,882,060

1,672,964

1,860,040

1,699,699

1,502,267

 Industrial

2,081,781

1,850,476

2,298,825

2,177,236

1,878,363

 Governmental

194,998

179,508

205,054

185,286

163,403

   Total retail

6,841,641

6,142,538

6,976,808

6,586,750

5,775,124

 Sales for resale

371,646

330,010

395,353

423,519

397,844

 Other (1)

183,888

173,866

(127,334)

209,417

98,446

   Total

$7,397,175

$6,646,414

$7,244,827

$7,219,686

$6,271,414

Billed Electric Energy

Sales (GWh):

  Residential

32,817

32,581

31,080

31,998

30,631

  Commercial

25,863

25,354

24,706

24,657

23,775

  Industrial

38,637

41,018

41,577

43,956

43,549

  Governmental

2,651

2,678

2,593

2,605

2,564

    Total retail

99,968

101,631

99,956

103,216

100,519

  Sales for resale

9,248

9,828

8,896

9,794

9,714

  Total

109,216

111,459

108,852

113,010

110,233

(1)

2001 includes the effect of a reserve for rate refund at System Energy.

INDEPENDENT AUDITORS' REPORT

 

To the Board of Directors and Shareholders of
Entergy Corporation:

 

We have audited the accompanying consolidated balance sheets of Entergy Corporation and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income; of retained earnings, comprehensive income, and paid-in capital; and of cash flows for each of the three years in the period ended December 31, 2003. 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 for the year ended December 31, 2003, 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 has been furnished to us, and our opinion, 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 auditing standards generally accepted in the United States of America. 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, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 1 and 9 to the consolidated financial statements, Entergy Corporation adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, and Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, in 2003, SFAS No. 142, Goodwill and Other Intangible Assets, in 2002 and SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, in 2001.




DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 9, 2004



                  ENTERGY CORPORATION AND SUBSIDIARIES
                    CONSOLIDATED STATEMENTS OF INCOME

                                                                 For the Years Ended December 31,
                                                                 2003          2002          2001
                                                                 (In Thousands, Except Share Data)

                   OPERATING REVENUES
Domestic electric                                              $7,397,175    $6,646,414    $7,244,827
Natural gas                                                       186,176       125,353       185,902
Competitive businesses                                          1,611,569     1,533,268     2,190,170
                                                               ----------    ----------    ----------
TOTAL                                                           9,194,920     8,305,035     9,620,899
                                                               ----------    ----------    ----------

                   OPERATING EXPENSES
Operating and Maintenance:
   Fuel, fuel-related expenses, and
     gas purchased for resale                                   1,987,217     2,154,596     3,681,677
   Purchased power                                              1,697,959       832,334     1,021,432
   Nuclear refueling outage expenses                              159,995       105,592        89,145
     Provision for turbine commitments, asset impairments
     and restructuring charges                                     (7,743)      428,456             -
   Other operation and maintenance                              2,484,436     2,488,112     2,151,742
Decommissioning                                                   146,100        76,417        28,586
Taxes other than income taxes                                     405,659       380,462       399,849
Depreciation and amortization                                     850,503       839,181       721,033
Other regulatory credits - net                                    (13,761)     (141,836)      (20,510)
                                                               ----------    ----------    ----------
TOTAL                                                           7,710,365     7,163,314     8,072,954
                                                               ----------    ----------    ----------

OPERATING INCOME                                                1,484,555     1,141,721     1,547,945
                                                               ----------    ----------    ----------

                      OTHER INCOME
Allowance for equity funds used during construction                42,710        31,658        26,209
Interest and dividend income                                       87,386       118,325       159,805
Equity in earnings of unconsolidated equity affiliates            271,647       183,878       162,882
Miscellaneous - net                                               (76,505)       13,892           457
                                                               ----------    ----------    ----------
TOTAL                                                             325,238       347,753       349,353
                                                               ----------    ----------    ----------

               INTEREST AND OTHER CHARGES
Interest on long-term debt                                        485,964       526,442       563,758
Other interest - net                                               53,553        70,560       172,241
Allowance for borrowed funds used during construction             (33,191)      (24,538)      (21,419)
                                                               ----------    ----------    ----------
TOTAL                                                             506,326       572,464       714,580
                                                               ----------    ----------    ----------

INCOME BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGES                         1,303,467       917,010     1,182,718

Income taxes                                                      490,074       293,938       455,693
                                                               ----------    ----------    ----------

INCOME BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGES                                             813,393       623,072       727,025

CUMULATIVE EFFECT OF ACCOUNTING
CHANGES (net of income taxes of $89,925 in 2003
 and $10,064 in 2001)                                             137,074             -        23,482
                                                               ----------    ----------    ----------

CONSOLIDATED NET INCOME                                           950,467       623,072       750,507

Preferred dividend requirements and other                          23,524        23,712        24,311
                                                               ----------    ----------    ----------

EARNINGS APPLICABLE TO
COMMON STOCK                                                     $926,943      $599,360      $726,196
                                                               ==========    ==========    ==========

Earnings per average common share before cumulative
effect of accounting changes:
    Basic                                                           $3.48         $2.69         $3.18
    Diluted                                                         $3.42         $2.64         $3.13
Earnings per average common share:
    Basic                                                           $4.09         $2.69         $3.29
    Diluted                                                         $4.01         $2.64         $3.23
Dividends declared per common share                                 $1.60         $1.34         $1.28
Average number of common shares outstanding:
    Basic                                                     226,804,370   223,047,431   220,944,270
    Diluted                                                   231,146,040   227,303,103   224,733,662

See Notes to Consolidated Financial Statements.




                  ENTERGY CORPORATION AND SUBSIDIARIES
                  CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                                            For the Years Ended December 31,
                                                                             2003         2002         2001
                                                                                      (In Thousands)

                          OPERATING ACTIVITIES
Consolidated net income                                                      $950,467     $623,072     $750,507
Noncash items included in net income:
  Reserve for regulatory adjustments                                           13,090       18,848     (359,199)
  Other regulatory credits - net                                              (13,761)    (141,836)     (20,510)
  Depreciation, amortization, and decommissioning                             996,603      915,597      749,619
  Deferred income taxes and investment tax credits                          1,189,531     (256,664)      87,752
  Allowance for equity funds used during construction                         (42,710)     (31,658)     (26,209)
  Cumulative effect of accounting changes                                    (137,074)           -      (23,482)
  Equity in undistributed earnings of unconsolidated equity affiliates       (176,036)    (181,878)    (150,799)
  Provision for turbine commitments, asset impairments, and restructuring
  charges                                                                      (7,743)     428,456            -
Changes in working capital:
  Receivables                                                                (140,612)     (43,957)     302,230
  Fuel inventory                                                              (14,015)       1,030       (3,419)
  Accounts payable                                                            (60,164)     286,230     (415,160)
  Taxes accrued                                                              (828,539)     462,956      486,676
  Interest accrued                                                            (35,837)       7,209       17,287
  Deferred fuel                                                               (33,874)     156,181      495,007
  Other working capital accounts                                               16,809     (286,232)     (39,978)
Provision for estimated losses and reserves                                   196,619       10,533       19,093
Changes in other regulatory assets                                             22,671       71,132      119,215
Other                                                                         110,395      142,684      226,918
                                                                           ----------   ----------   ----------
Net cash flow provided by operating activities                              2,005,820    2,181,703    2,215,548
                                                                           ----------   ----------   ----------

                           INVESTING ACTIVITIES
Construction/capital expenditures                                          (1,568,943)  (1,530,301)  (1,380,417)
Allowance for equity funds used during construction                            42,710       31,658       26,209
Nuclear fuel purchases                                                       (224,308)    (250,309)    (130,670)
Proceeds from sale/leaseback of nuclear fuel                                  150,135      183,664       71,964
Proceeds from sale of assets and businesses                                    25,987      215,088      784,282
Investment in nonutilty properties                                            (71,438)    (216,956)    (647,015)
Decrease (increase) in other investments                                      172,187       38,964     (631,975)
Changes in other temporary investments                                        (50,000)     150,000     (150,000)
Decommissioning trust contributions and realized change in trust assets       (91,518)     (84,914)     (95,571)
Other regulatory investments                                                 (156,446)     (39,390)      (3,460)
Other                                                                         (11,496)     114,033      (68,067)
                                                                           ----------   ----------   ----------
Net cash flow used in investing activities                                 (1,783,130)  (1,388,463)  (2,224,720)
                                                                           ----------   ----------   ----------

See Notes to Consolidated Financial Statements.















                     ENTERGY CORPORATION AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                                                  For the Years Ended December 31,
                                                                                  2003          2002          2001
                                                                                            (In Thousands)

                            FINANCING ACTIVITIES
Proceeds from the issuance of:
  Long-term debt                                                                 2,221,164     1,197,330       682,402
  Common stock and treasury stock                                                  217,521       130,061        64,345
Retirement of long-term debt                                                    (2,409,917)   (1,341,274)     (962,112)
Repurchase of common stock                                                          (8,135)     (118,499)      (36,895)
Redemption of preferred stock                                                       (3,450)       (1,858)      (39,574)
Changes in short-term borrowings - net                                            (499,975)      244,333       (37,004)
Dividends paid:
  Common stock                                                                    (362,814)     (298,991)     (269,122)
  Preferred stock                                                                  (23,524)      (23,712)      (24,044)
                                                                                ----------    ----------    ----------
Net cash flow used in financing activities                                        (869,130)     (212,610)     (622,004)
                                                                                ----------    ----------    ----------

Effect of exchange rates on cash and cash equivalents                                3,345         3,125           325
                                                                                ----------    ----------    ----------

Net increase (decrease) in cash and cash equivalents                              (643,095)      583,755      (630,851)

Cash and cash equivalents at beginning of period                                 1,335,328       751,573     1,382,424
                                                                                ----------    ----------    ----------

Cash and cash equivalents at end of period                                        $692,233    $1,335,328      $751,573
                                                                                ==========    ==========    ==========


SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
  Cash paid (received) during the period for:
    Interest - net of amount capitalized                                          $552,017      $633,931      $708,748
    Income taxes                                                                  $188,709       $57,856     ($113,466)
  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      $430,000
    Long-term debt refunded with proceeds from
       long-term debt issued in prior period                                             -      ($47,000)            -
    Proceeds from long-term debt issued for the purpose
       of refunding prior long-term debt                                                 -             -       $47,000

 See Notes to Consolidated Financial Statements.




                  ENTERGY CORPORATION AND SUBSIDIARIES
                       CONSOLIDATED BALANCE SHEETS
                                 ASSETS

                                                                            December 31,
                                                                       2003           2002
                                                                           (In Thousands)

                        CURRENT ASSETS
Cash and cash equivalents:
  Cash                                                                 $115,112       $169,788
  Temporary cash investments - at cost,
   which approximates market                                            576,813      1,165,260
  Special deposits                                                          308            280
                                                                    -----------    -----------
     Total cash and cash equivalents                                    692,233      1,335,328
                                                                    -----------    -----------
Other temporary investments                                              50,000              -
Notes receivable                                                          1,730          2,078
Accounts receivable:
  Customer                                                              398,091        323,215
  Allowance for doubtful accounts                                       (25,976)       (27,285)
  Other                                                                 246,824        244,621
  Accrued unbilled revenues                                             384,860        319,133
                                                                    -----------    -----------
     Total receivables                                                1,003,799        859,684
                                                                    -----------    -----------
Deferred fuel costs                                                     245,973         55,653
Fuel inventory - at average cost                                        110,482         96,467
Materials and supplies - at average cost                                548,921        525,900
Deferred nuclear refueling outage costs                                 138,836        163,646
Prepayments and other                                                   127,270        166,827
                                                                    -----------    -----------
TOTAL                                                                 2,919,244      3,205,583
                                                                    -----------    -----------

                OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity                                  1,053,328        824,209
Decommissioning trust funds                                           2,278,533      2,069,198
Non-utility property - at cost (less accumulated depreciation)          262,384        297,294
Other                                                                   152,681        277,539
                                                                    -----------    -----------
TOTAL                                                                 3,746,926      3,468,240
                                                                    -----------    -----------

                PROPERTY, PLANT AND EQUIPMENT
Electric                                                             28,035,899     26,789,538
Property under capital lease                                            751,815        746,624
Natural gas                                                             236,622        209,969
Construction work in progress                                         1,380,982      1,232,891
Nuclear fuel under capital lease                                        278,683        259,433
Nuclear fuel                                                            234,421        263,609
                                                                    -----------    -----------
TOTAL PROPERTY, PLANT AND EQUIPMENT                                  30,918,422     29,502,064
Less - accumulated depreciation and amortization                     12,619,625     11,837,061
                                                                    -----------    -----------
PROPERTY, PLANT AND EQUIPMENT - NET                                  18,298,797     17,665,003
                                                                    -----------    -----------

               DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
  SFAS 109 regulatory asset - net                                       830,539        844,105
  Other regulatory assets                                             1,425,145        973,185
Long-term receivables                                                    20,886         24,703
Goodwill                                                                377,172        377,172
Other                                                                   935,501        946,375
                                                                    -----------    -----------
TOTAL                                                                 3,589,243      3,165,540
                                                                    -----------    -----------

TOTAL ASSETS                                                        $28,554,210    $27,504,366
                                                                    ===========    ===========
See Notes to Consolidated Financial Statements.


                   ENTERGY CORPORATION AND SUBSIDIARIES
                       CONSOLIDATED BALANCE SHEETS
                  LIABILITIES AND SHAREHOLDERS' EQUITY

                                                                             December 31,
                                                                         2003           2002
                                                                            (In Thousands)

                      CURRENT LIABILITIES
Currently maturing long-term debt                                        $524,372     $1,191,320
Notes payable                                                                 351            351
Accounts payable                                                          796,572        855,446
Customer deposits                                                         199,620        198,442
Taxes accrued                                                             224,926        385,315
Accumulated deferred income taxes                                          22,963         26,468
Nuclear refueling outage costs                                              8,238         14,244
Interest accrued                                                          139,603        175,440
Obligations under capital leases                                          159,978        153,822
Other                                                                     205,600        171,341
                                                                      -----------    -----------
TOTAL                                                                   2,282,223      3,172,189
                                                                      -----------    -----------

                    NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued                     4,779,513      4,250,800
Accumulated deferred investment tax credits                               420,248        447,925
Obligations under capital leases                                          153,898        155,943
Other regulatory liabilities                                              291,239        185,579
Decommissioning and retirement cost liabilities                         2,242,312      2,115,744
Transition to competition                                                  79,098         79,098
Regulatory reserves                                                        69,528         56,438
Accumulated provisions                                                    506,960        389,868
Long-term debt                                                          7,322,940      7,308,649
Preferred stock with sinking fund                                          20,852              -
Other                                                                   1,347,404      1,145,232
                                                                      -----------    -----------
TOTAL                                                                  17,233,992     16,135,276
                                                                      -----------    -----------

Preferred stock with sinking fund                                               -         24,327
Preferred stock without sinking fund                                      334,337        334,337

                      SHAREHOLDERS' EQUITY
Common stock, $.01 par value, authorized 500,000,000
  shares; issued 248,174,087 shares in 2003 and in 2002                     2,482          2,482
Paid-in capital                                                         4,767,615      4,666,753
Retained earnings                                                       4,502,508      3,938,693
Accumulated other comprehensive loss                                       (7,795)       (22,360)
Less - treasury stock, at cost (19,276,445 shares in 2003 and
  25,752,410 shares in 2002)                                              561,152        747,331
                                                                      -----------    -----------
TOTAL                                                                   8,703,658      7,838,237
                                                                      -----------    -----------

Commitments and Contingencies

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                            $28,554,210    $27,504,366
                                                                      ===========    ===========
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,
                                                               2003                      2002                    2001
                                                                                     (In Thousands)

               RETAINED EARNINGS
Retained Earnings - Beginning of period               $3,938,693                $3,638,448               $3,190,639

     Add: Earnings applicable to common stock            926,943    $926,943       599,360    $599,360      726,196      $726,196

     Deduct:
        Dividends declared on common stock               362,941                   299,031                  278,342
        Capital stock and other expenses                     187                        84                       45
                                                      ----------                ----------               ----------
              Total                                      363,128                   299,115                  278,387
                                                      ----------                ----------               ----------

Retained Earnings - End of period                     $4,502,508                $3,938,693               $3,638,448
                                                      ==========                ==========               ==========





   ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
                    (Net of taxes):
Balance at beginning of period:
  Accumulated derivative instrument fair value changes   $17,313                  $(17,973)                      $-
  Other accumulated comprehensive (loss) items           (39,673)                  (70,821)                 (75,033)
                                                      ----------                ----------               ----------
     Total                                               (22,360)                  (88,794)                 (75,033)
                                                      ----------                ----------               ----------

  Cumulative effect to January 1, 2001 of accounting
    change regarding fair value of derivative instruments      -                         -                  (18,021)

Net derivative instrument fair value changes
  arising during the period                              (43,124)    (43,124)       35,286      35,286           48            48

Foreign currency translation adjustments                   4,169       4,169        65,948     (15,487)       4,615         4,615

Minimum pension liability adjustment                       1,153       1,153       (10,489)    (10,489)           -             -

Net unrealized investment gains (losses)                  52,367      52,367       (24,311)    (24,311)        (403)         (403)
                                                         -------    --------      --------    --------     --------      --------
Balance at end 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)     --------
Comprehensive Income                                     =======    $941,508      ========    $584,359     ========      $730,456
                                                                    ========                  ========                   ========




                PAID-IN CAPITAL
Paid-in Capital - Beginning of period                 $4,666,753                $4,662,704               $4,660,483

     Add:
      Common stock issuances related to stock plans      100,862                     4,049                    2,221
                                                      ----------                ----------               ----------
Paid-in Capital - End of period                       $4,767,615                $4,666,753               $4,662,704
                                                      ==========                ==========               ==========


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, both of 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. Entergy Mississippi has 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 plus carrying charges will be collected over twelve months beginning January 2004. 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 1. The capital costs are computed by allowing a return on System Energy's common equity funds allocable to its net investment in Grand Gulf 1, plus System Energy's effective interest cost for its debt allocable to its investment in Grand Gulf 1.

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 1 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, 2003 and 2002, is shown below:

Energy

U.S.

Non-Utility

Commodity

Parent and

2003

Entergy

Utility

Nuclear

Services

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 (1)

156

155

-

1

-

Property, plant, and equipment - net

$18,299

$16,245

$1,557

$458

$39

Energy

U.S.

Non-Utility

Commodity

Parent and

2002

Entergy

Utility

Nuclear

Services

Other

(In Millions)

Production

  Nuclear

$7,472 

$6,314 

$1,158

$-

$-

  Other

1,616 

1,382 

-

234

-

Transmission

1,851 

1,851 

-

-

-

Distribution

4,037 

4,037 

-

-

-

Other

933 

929 

-

-

4

Construction work in progress

1,233 

797 

216

192

28

Nuclear fuel

 

  (leased and owned)

523 

284 

239

-

-

Property, plant, and equipment - net

$17,665 

$15,594 

$1,613

$426

$32

 

(1)

This is reflected in electric property, plant, and equipment and accumulated depreciation and amortization on the balance sheet.

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 2003 and 2.9% in 2002 and 2001. Included in these rates are the depreciation rates on average depreciable utility property of 2.8% in 2003, 2002 and 2001 and the depreciation rates on average depreciable non-utility property of 3.3% in 2003, 4.0% in 2002, and 4.8% in 2001.

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, 2003, 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)

                         

Grand Gulf

Unit 1

 

Nuclear

 

1,207

 

90.00% (2)

 

$3,672

 

$1,673

Independence

Units 1 and 2

 

Coal

 

1,630

 

47.90%

 

459

 

240

White Bluff

Units 1 and 2

 

Coal

 

1,635

 

57.00%

 

423

 

256

Roy S. Nelson

Unit 6

 

Coal

 

550

 

70.00%

 

404

 

234

Big Cajun 2

Unit 3

 

Coal

 

575

 

42.00%

 

233

 

123

Harrison County

   

Gas

 

550

 

70.00%

 

230

 

3

(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 1 lease obligations are discussed in Note 10 to the consolidated financial statements.

Goodwill

Entergy implemented SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002. The adoption of SFAS 142 required an initial impairment assessment involving a comparison of the fair value of goodwill and other intangible assets to the current carrying value. Goodwill and other intangible assets determined to have indefinite useful lives are not amortized, whereas goodwill and other intangible assets determined to have definite useful lives are amortized over their useful lives. Goodwill and other intangible assets are subject to annual impairment testing.

The implementation of SFAS 142 resulted in the cessation of Entergy's amortization of the remaining plant acquisition adjustment recorded in conjunction with its acquisition of Entergy Gulf States. The following table is a reconciliation of reported earnings applicable to common stock to earnings applicable to common stock without goodwill amortization for the years ended December 31, 2003, 2002, and 2001:

 

For the Years Ended December 31,

2003

2002

2001

(In Thousands, Except Share Data)

Reported earnings applicable to common stock

$926,943

$599,360

$726,196

Add back: Goodwill amortization

-

-

16,265

Adjusted earnings applicable to common stock without

  goodwill amortization

$926,943

$599,360

$742,461

Basic earnings per average common share:

Reported earnings applicable to common stock

$4.09

$2.69

$3.29

Goodwill amortization

-

-

0.07

Adjusted earnings applicable to common stock without

  goodwill amortization

$4.09

$2.69

$3.36

Diluted earnings per average common share:

Reported earnings applicable to common stock

$4.01

$2.64

$3.23

Goodwill amortization

-

-

0.07

Adjusted earnings applicable to common stock without

  goodwill amortization

$4.01

$2.64

$3.30

 

During 2001, Entergy acquired certain intangible assets in connection with the formation of Entergy-Koch, LP, an unconsolidated 50/50 limited partnership between subsidiaries of Entergy and Koch Industries, Inc. Because the intangible assets were assigned definite useful lives, which correspond to the useful lives of Entergy-Koch's fixed assets, Entergy is amortizing them on a straight-line basis over a period of 30 years. Entergy's consolidated balance sheet at December 31, 2003 includes $53 million of unamortized intangible assets acquired in forming Entergy-Koch.

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 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 its subsidiaries file a U.S. 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,

2003

2002

2001

(In Millions, Except Per Share Data)

$/share

$/share

$/share

Income before cumulative effect of accounting change

$ 789.9

$599.4

$ 702.7

Average number of common shares outstanding - basic

226.8

$ 3.48 

223.0

$ 2.69 

220.9

$ 3.18 

Average dilutive effect of:

Stock Options (1)

4.1

(0.062)

3.9

(0.046)

3.6

(0.052)

Equity Awards

0.2

(0.004)

0.4

(0.005)

0.2

(0.002)

Average number of common shares outstanding - diluted

231.1

$ 3.42 

227.3

$ 2.64 

224.7

$ 3.13 

Earnings applicable to common stock

$ 926.9

$599.4

$ 726.2

Average number of common shares outstanding - basic

226.8

$ 4.09 

223.0

$ 2.69 

220.9

$ 3.29 

Average dilutive effect of:

Stock Options (1)

4.1

(0.073)

3.9

(0.046)

3.6

(0.054)

Equity Awards

0.2

(0.004)

0.4

(0.005)

0.2

(0.002)

Average number of common shares outstanding - diluted

231.1

$ 4.01 

227.3

$ 2.64 

224.7

$ 3.23 

(1)

Options to purchase approximately 15,231 shares in 2003, 109,897 shares in 2002, and 148,500 shares in 2001 of common stock 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 average market price of the common shares at the end of each of the years presented.

Stock-based Compensation Plans

Entergy has two plans that grant stock options, which are described more fully in Note 8 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 and 2001 net income as all options granted under those 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 2003 is less than that which would have been recognized if the fair value based me thod 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.

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. As of December 31, 2003 and 2002, the fair value of the securities held in such funds differs from the amounts deposited plus the earnings on the deposits by $94 million and ($24) million, respectively. 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. Prior to the implementation of SFAS 143, the offsetting amount of unrealized gains/(losses) on investment securities was recor ded in accumulated depreciation for Entergy Arkansas, Entergy Gulf States (for the regulated portion of River Bend), and for Entergy Louisiana. 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 assets in these trust funds are recognized in the accumulated other income component of shareholders' equity because these assets are classified as available for sale.

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 equit y investments 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 13 to the consolidated financial statements for additional information regarding Entergy's equity method investments.

Derivative Financial Instruments and Commodity Derivatives

Entergy implemented SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" on January 1, 2001. The statement 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. 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.

Other contracts for commodities in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transaction 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 a 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.

Effective January 1, 2001, Entergy recorded a net-of-tax cumulative-effect-type adjustment of approximately $18.0 million reducing accumulated other comprehensive income to recognize, at fair value, all derivative instruments that are designated as cash-flow hedging instruments, primarily interest rate swaps and foreign currency forward contracts related to Entergy's competitive businesses. Effective October 1, 2001, Entergy recorded an additional net-of-tax cumulative-effect-type adjustment that increased net income by approximately $23.5 million. This adjustment resulted from the implementation of an interpretation of SFAS 133 that requires fuel supply agreements with volumetric optionality to be classified as derivative instruments. The agreement that resulted in the adjustment is in the Energy Commodity Services segment and was disposed of in the Damhead Creek sale in December 2002.

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 12 to the consolidated financial statements for discussion of asset impairments recognized in 2002 in the Energy Commodity Services segment.

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.

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 2003, Entergy adopted the provisions of the following accounting standards: SFAS 143, "Accounting for Asset Retirement Obligations," which is discussed further in Note 9; FIN 46, Consolidation of Variable Interest Entities," which is discussed further in Note 6; 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 this standard.

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
2003 Revenues Derived
from Retail Electric
Utility Operations
in the Jurisdiction

 

 

 

 

 

Arkansas

 

Retail open access was repealed in February 2003.

 

15.4%

 

 

 

 

 

Texas

 

Implementation delayed in Entergy Gulf States' service area in a settlement approved by PUCT. In light of regulatory proceedings and approvals required, retail open access not likely before the first quarter of 2005.

 

14.4%

 

 

 

 

 

Louisiana

 

The LPSC has deferred pursuing retail open access, pending developments at the federal level and in other states.

 

43.9%

 

 

 

 

 

Mississippi

 

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

 

13.0%

 

 

 

 

 

New Orleans

 

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

 

5.9%

Retail open access commenced in portions of Texas on January 1, 2002. The staff of the PUCT filed a petition to delay retail open access in Entergy Gulf States' service area, and Entergy Gulf States reached a settlement agreement approved by the PUCT to delay retail open access until at least September 15, 2002. In September 2002, the PUCT ordered Entergy Gulf States to file on January 24, 2003 a proposal for an interim solution (retail open access without a FERC-approved RTO) if it appeared by January 15, 2003 that a FERC-approved RTO would not be functional by January 1, 2004. On January 24, 2003, Entergy Gulf States filed its proposal, 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 seeks 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.

The PUCT considered the proposal at a March 2003 hearing, and issued an order in April 2003. The order set forth a sequence of proceedings and activities designed to initiate an interim solution. These proceedings and activities include ruling on market protocols; initiating a proceeding to certify an independent organization to administer the market protocols and ensure nondiscriminatory access to transmission and distribution systems; resuming business separation proceedings; re-invigorating the pilot project; and initiating a market-readiness proceeding. The PUCT issued an order on rehearing in late-July 2003 in which it identified December 2004 as the target date for the beginning of the interim solution. Consistent with the order, and after negotiations with other parties and following a series of contested hearings and the PUCT approval of a settlement agreement on the market protocols, Entergy Services made a filing at the FERC and has received approval on an expedited basis of the market protocols subject to FERC jurisdiction. This ruling, when final and appealable, will allow for the reinvigorated pilot to begin upon the PUCT approval of Entergy Gulf States' independent organization request. The PUCT is currently scheduled to conduct a hearing on this request in June 2004.

In September 2003, the PUCT issued a written order that approved the Price to Beat (PTB) fuel factor for Entergy Gulf States, which is to be implemented upon the commencement of retail open access in its Texas service territory. This PTB fuel factor is subject to revision based on PUCT rules. The PUCT declined consideration of a request for rehearing sought by certain cities in Texas served by Entergy Gulf States and the Office of Public Utility Counsel. The Office of Public Utility Counsel has appealed this decision to the Texas courts. Management cannot predict the ultimate outcome of the proceeding at this time.

In November 2003, Entergy Gulf States initiated a proceeding to certify the Entergy Transmission Organization as the independent organization. The PUCT is scheduled to conduct a hearing on the certification application in June 2004.

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, 2003 and 2002.

 

2003

2002

(In Millions)

DOE Decommissioning and Decontamination Fees - recovered through fuel rates until
  December 2006 (Note 9)

$32.9

$40.3

Asset Retirement Obligation - recovery dependent upon timing of decommissioning
  (Note 9)

464.9

-

Removal costs - recovered through depreciation rates

72.4

79.6

Provisions for storm damages - recovered through cost of service

123.3

93.9

Postretirement benefits - recovered through 2013 (Note 11)

21.5

23.9

Pension costs (Note 11)

134.0

157.8

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

79.1

79.1

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

39.4

41.3

Spindletop gas storage lease - recovered through December 2032

38.0

35.0

Low-level radwaste - recovery timing dependent upon pending lawsuit

19.4

19.4

1994 FERC Settlement - recovered through June 2004 (Note 2)

4.0

12.1

Sale-leaseback deferral - recovered through June 2014 (Note 10)

131.7

123.9

Deferred fuel - non-current - recovered through rate riders redetermined annually

28.2

17.3

Unamortized loss on reaquired debt - recovered over term of debt

164.4

155.2

Other - various

71.9

94.4

Total

$1,425.1

$973.2

 

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, 2003 and 2002 that has been or will be recovered or (refunded) through the fuel mechanisms of the domestic utility companies.

 

2003

 

2002

 

(In Millions)

       

Entergy Arkansas

$10.6 

 

$(42.6)

Entergy Gulf States

$118.4 

 

$100.6 

Entergy Louisiana

$30.6 

 

$(25.6)

Entergy Mississippi

$89.1 

 

$38.2 

Entergy New Orleans

$(2.7)

 

$(14.9)

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 2003, Entergy Arkansas filed with the APSC its energy cost recovery rider for the period April 2003 through March 2004. The energy cost rate filed was approximately the same as the interim energy cost rate that was in effect since October 2002. The current energy cost rate is designed to eliminate the over-recovery during the annual rider period.

Entergy Gulf States

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 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. 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 $116.6 million as of December 31, 2003, which includes the following:

 

Interim surcharge

 

$87.0 million

Items to be addressed as part of unbundling

 

$29.0 million

Imputed capacity charges

 

$9.3 million

Other (includes over-recovery for the period 9/03 - 12/03)

 

$(8.7) million

The PUCT has ordered that the imputed capacity charges be excluded from fuel rates and therefore recovered through base rates. It is uncertain, however, as to when and if Entergy Gulf States will initiate a base rate proceeding before the PUCT. The current PUCT-approved settlement agreement delaying retail open access in Texas requires a rate freeze during the delay period. If Entergy Gulf States implements retail open access 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.

In January 2001, Entergy Gulf States filed 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. The PUCT decided in August 2002 to reduce 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 this 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-regulated sha re 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.

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 will be 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. The reconciliation includes $8.6 million of under-recovered costs that Entergy Gulf States is asking to roll into its fuel over/under-recovery balance to be addressed in the next appropriate fuel proceeding. Hearings are expected to occur in the third quarter 2004 with a final PUCT decision expected in early 2005.

Entergy Gulf States (Louisiana) and Entergy Louisiana

The Louisiana jurisdiction of 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. Entergy Gulf States' gas rate schedules include estimates for the billing month adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations.

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. The LPSC staff has quantified the possible disallowance as between $7.6 and $14 million. Entergy Louisiana is currently evaluating the LPSC staff report and expects to contest the recommendation. A procedural schedule has been adopted and hearings, which also will address issues relating to the reasonableness of transmission planning and purchases of power from affiliates, the potential value of which issues cannot yet be quantified, are scheduled to begin in September 2004, but the LPSC staff has requested a delay until April 2005.

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 collected by Entergy Gulf States through its fuel adjustment clause in Louisiana for the period January 1, 1995 through December 1, 2002. The discovery process 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 has 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 will be collected through the energy cost recovery rider over a twelve-month period beginning January 2004.

Entergy New Orleans

Effective June 2003, 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.

Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

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 June 1999 PUCT-approved settlement agreement. The settlement provided for a base rate freeze that has remained in effect during the delay in implementation of retail open access in Entergy Gulf States' Texas service territory.

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. A 1999 settlement agreement limits potential recovery of the remaining plant asset to $115 million as of January 1, 2002, less depreciation after that date. Entergy Gulf States accordingly reduced the value of the plant asset in 1999. Entergy Gulf States has also agreed that it will not seek recovery of the abeyed plant costs through any additional charge to Texas ratepayers. In an interim order approving this agreement, however, the PUCT recognized that any additional River Bend investment found prudent, subject to the $115 million cap, could be used as an offset against stranded benefits, should legislation be passed requiring Entergy Gulf States to return stranded benefits to retail customers.

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, management has concluded that it is prudent to accrue 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 as of June 30, 2003, and after this accrual Entergy Gulf States provided for all potential loss related to current or past contested costs of construction of the River Bend plant. Accrual of the loss was recorded in the second quarter 2003 and reduced net income by $65. 6 million. In January 2004, the Texas Supreme Court asked for full briefing on the merits of the case in response to Entergy Gulf States' petition for review.

Filings with the LPSC

Annual Earnings Reviews (Entergy Gulf States)

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. Entergy Gulf States made the refund in February 2003. In addition to resolving and discharging all liability associated with the fourth through eighth earnings reviews, the settlement provides that Entergy Gulf States shall be authorized to continue to reflect in rates a ROE of 11.1% until a different ROE is authorized by a final resolution disposing of all issues in the proceeding that was commenced with Entergy Gulf States' May 2002 filing.

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 April 2003, the LPSC staff filed testimony in which it recommended that the LPSC require a rate refund of $30.3 million and a prospective rate reduction of $75.9 million, before taking into account the $11.5 million rate reduction that Entergy Gulf States implemented effective June 2002. In July 2003, Entergy Gulf States filed testimony rebutting the LPSC staff's testimony and supporting the filing. During discovery, the LPSC staff requested that Entergy Gulf States provide updated cost of service data to reflect changes in costs, revenues, and rate base through December 31, 2002. In September 2003, Entergy Gulf States supplied the updated data. In December 2003, the LPSC staff recommended a rate refund of $30.6 mil lion and a prospective rate reduction of approximately $50 million. Hearings are scheduled to begin in April 2004. Entergy Gulf States cannot predict the ultimate outcome of this proceeding.

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 certain power purchase agreements, the implementation of which would, based on current natural gas prices, produce fuel 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 midpoint currently in effect is 10.5%. Hearings are currently set for September 2004.

 

Filings with the MPSC (Entergy Mississippi)

Formula Rate Plan Filings

In December 2002, the MPSC issued a final order approving a joint stipulation entered into by Entergy Mississippi and the Mississippi Public Utilities Staff in October 2002. The final order results in a $48.2 million rate increase, or about a 5.3% increase in overall retail revenues, which is based on an ROE of 11.75%. The rate increase began in January 2003. 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 the provisions of the order, Entergy Mississippi will make its next formula rate plan filing during March 2004. The "benchmark ROE" set out in Entergy Mississippi's March 2004 annual formula rate plan filing likely will differ from the last approved ROE. 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.

Grand Gulf Accelerated Recovery Tariff (GGART)

In September 1998, FERC approved the GGART for Entergy Mississippi's allocable portion of Grand Gulf, which was filed with FERC in August 1998. The GGART provided for the acceleration of Entergy Mississippi's Grand Gulf purchased power over the period October 1, 1998 through June 30, 2004. In May 2003, the MPSC authorized the cessation of the GGART effective July 1, 2003. Entergy Mississippi filed notice of the change with FERC and the FERC approved the filing on July 30, 2003. Entergy Mississippi accelerated a total of $168.4 million of Grand Gulf purchased power obligation under the GGART over the period October 1, 1998 through June 30, 2003.

Filings with the Council (Entergy New Orleans)

Rate Proceedings

In May 2002, Entergy New Orleans filed a cost of service study and revenue requirement filing with the City Council for the 2001 test year. The filing indicated that a revenue deficiency existed and that a $28.9 million electric rate increase and a $15.3 million gas rate increase were appropriate. Additionally, Entergy New Orleans proposed a $6 million public benefit fund. In March 2003, Entergy New Orleans and the Advisors to the City Council presented to the City Council an agreement in principle and the City Council approved that agreement in May 2003 allowing for a total increase of $30.2 million in electric and gas base rates effective June 1, 2003. Certain intervenors have appealed the City Council's approval to Civil District Court for the Parish of Orleans. Entergy New Orleans and the City Council will oppose the appeal, but the outcome cannot be predicted.

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 seek 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. 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 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 results in a refund to customers of $11.3 million, including interest during the months of June through September 2004. Entergy New Orleans has accrued for this liability as of December 31, 2003. The resolution concludes, among o ther things, that the record does not support an allegation that 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.  The plaintiffs have appealed the City Council resolution to the state court in Orleans Parish.

System Energy's 1995 Rate Proceeding

System Energy applied to FERC in May 1995 for a rate increase, and implemented the increase in December 1995. The request sought changes to System Energy's rate schedule, including increases in the revenue requirement associated with decommissioning costs, the depreciation rate, and the rate of return on common equity. The request proposed a 13% return on common equity. In July 2000, FERC approved a rate of return of 10.58% for the period December 1995 to the date of FERC's decision, and prospectively adjusted the rate of return to 10.94% from the date of FERC's decision. FERC's decision also changed other aspects of System Energy's proposed rate schedule, including the depreciation rate and decommissioning costs and their methodology. FERC accepted System Energy's compliance tariff in November 2001. System Energy made refunds to the domestic utility companies in December 2001.

In accordance with regulatory accounting principles, during the pendency of the case, System Energy recorded reserves for potential refunds against its revenues. Upon the order becoming final, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy recorded entries to spread the impacts of FERC's order to the various revenue, expense, asset, and liability accounts affected, as if the order had been in place since commencement of the case in 1995. System Energy also recorded an additional reserve amount against its revenue, to adjust its estimate of the impact of the order, and recorded additional interest expense on that reserve. System Energy also recorded reductions in its depreciation and its decommissioning expenses to reflect the lower levels in FERC's order, and reduced tax expense affected by the order.

FERC Settlement

In November 1994, FERC approved an agreement settling a long-standing dispute involving income tax allocation procedures of System Energy. In accordance with the agreement, System Energy has been refunding a total of approximately $62 million, plus interest, to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans through June 2004. System Energy also reclassified from utility plant to other deferred debits approximately $81 million of other Grand Gulf 1 costs. Although such costs are excluded from rate base, System Energy is amortizing and recovering these costs over a 10-year period. Interest on the $62 million refund and the loss of the return on the $81 million of other Grand Gulf 1 costs is reducing Entergy's and System Energy's net income by approximately $10 million annually.

 

 

NOTE 3. INCOME TAXES

Income tax expenses for 2003, 2002, and 2001 consist of the following:

(a)

The actual cash taxes paid/(received) were $188,709 in 2003, $57,856 in 2002, and ($113,466) in 2001. Entergy Louisiana's mark-to-market tax accounting election significantly reduced taxes paid in 2001 and 2002. In 2001, Entergy Louisiana changed its method of accounting for tax purposes related to the contract to purchase power from the Vidalia project (the contract is discussed in Note 9 to the consolidated financial statements). The new tax accounting method has provided a cumulative cash flow benefit of approximately $805 million through 2003, 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.

Total income taxes differ from the amounts computed by applying the statutory income tax rate to income before taxes. The reasons for the differences for the years 2003, 2002, and 2001 are:

 

Significant components of net deferred and noncurrent accrued tax liabilities as of December 31, 2003 and 2002 are as follows:

At December 31, 2003, Entergy had $192 million in net realized federal capital loss carryforwards that will expire as follows: $12 million in 2006, $163 million in 2007, and $17 million in 2008.

At December 31, 2003, Entergy had state net operating loss carryforwards of $1.9 billion, primarily resulting from Entergy Louisiana's mark-to-market tax election. If the state net operating loss carryforwards are not utilized, they will expire in the years 2010 through 2016.

The 2003 and 2002 valuation allowances are provided against UK capital loss and UK net operating loss carryforwards, which can be utilized against future UK taxable income. For UK tax purposes, these carryforwards do not expire.

At December 31, 2003, Entergy had $9.8 million of indefinitely reinvested undistributed earnings from subsidiary companies outside the U.S. Upon distribution of these earnings in the form of dividends or otherwise, Entergy could be subject to U.S. income taxes (subject to foreign tax credits) and withholding taxes payable to various foreign countries.

 

 

NOTE 4. LINES OF CREDIT AND RELATED SHORT-TERM BORROWINGS

Entergy Corporation has in place a 364-day bank credit facility with a borrowing capacity of $1.45 billion, none of which was outstanding as of December 31, 2003. The commitment fee for this facility is currently 0.20% of the line amount. Commitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior debt ratings of the domestic utility companies.

Although the Entergy Corporation credit facility expires in May 2004, Entergy has the discretionary option to extend the period to repay the amount then outstanding for an additional 364-day term. Because of this option, which Entergy intends to exercise if it does not renew the credit line or obtain an alternative source of financing, the credit line is reflected in long-term debt on the balance sheet. Entergy Corporation's facility requires 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 facility's maturity date may occur.

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, 2004. Also, under the SEC order authorizing the short-term borrowing limits, the domestic utility companies and System Energy cannot incur new short-term indebtedness if the issuer's common equity would comprise less than 30% of its capital. In addition to borrowing from commercial banks, Entergy's subsidiaries are authorized to borrow from the Entergy System Money Pool (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, 2003, Entergy's subsidiaries' authorized limit was $1.6 billion and the outstanding borrowing from the money pool was $147.1 million. There were no borrowings outstanding from external sources. There is further discussion of commitments for long-term financing arrangements in Note 5 to the consolidated financial statements.

Entergy Arkansas, Entergy Louisiana, and Entergy Mississippi each have 364-day credit facilities available as follows:


Company

 


Expiration Date

 

Amount of
Facility

 

Amount Drawn as
of Dec. 31, 2003

             

Entergy Arkansas

 

April 2004

 

$63 million

 

-

Entergy Louisiana

 

May 2004

 

$15 million

 

-

Entergy Mississippi

 

May 2004

 

$25 million

 

-

The facilities have variable interest rates and the average commitment fee is 0.14%.

 

 

NOTE 5. LONG - TERM DEBT

Long-term debt as of December 31, 2003 and 2002 consisted of:

 

2003

2002

(In Thousands)

Mortgage Bonds:

6.25% Series due February 2003 - Entergy Mississippi

$-

$70,000

7.75% Series due February 2003 - Entergy Mississippi

-

120,000

6.75% Series due March 2003 - Entergy Gulf States

-

33,000

7.72% Series due March 2003 - Entergy Arkansas

-

100,000

8.5% Series due June 2003 - Entergy Louisiana

-

150,000

Libor + 1.2% Series due June 2003 - Entergy Gulf States

-

260,000

6.0% Series due October 2003 - Entergy Arkansas

-

155,000

6.625% Series due November 2003 - Entergy Mississippi

-

65,000

6.65% Series due March 2004 - Entergy New Orleans

-

30,000

8.25% Series due April 2004 - Entergy Gulf States

292,000

292,000

6.2% Series due May 2004 - Entergy Mississippi

75,000

75,000

Libor + 0.65% Series due May 2004 - Entergy Mississippi

-

50,000

8.25% Series due July 2004 - Entergy Mississippi

-

25,000

Libor + 1.3% Series due September 2004 - Entergy Gulf States

-

300,000

6.125% Series due July 2005 - Entergy Arkansas

100,000

100,000

8.125% Series due July 2005 - Entergy New Orleans

30,000

30,000

6.65% Series due August 2005 - Entergy Arkansas

-

115,000

6.77% Series due August 2005 - Entergy Gulf States

98,000

98,000

8.0% Series due March 2006 - Entergy New Orleans

-

40,000

Libor + 0.90% Series due June 2007 - Entergy Gulf States

275,000

-

7.5% Series due August 2007 - Entergy Arkansas

-

100,000

4.875% Series due October 2007 - System Energy

70,000

70,000

5.2% Series due December 2007 - Entergy Gulf States

200,000

200,000

6.5% Series due March 2008 - Entergy Louisiana

115,000

115,000

4.35% Series due April 2008 - Entergy Mississippi

100,000

-

6.45% Series due April 2008 - Entergy Mississippi

80,000

80,000

3.6% Series due June 2008 - Entergy Gulf States

325,000

-

7.0% Series due July 2008 - Entergy New Orleans

-

30,000

3.875% Series due August 2008 - Entergy New Orleans

30,000

-

6.0% Series due December 2012 - Entergy Gulf States

140,000

140,000

5.15% Series due February 2013 - Entergy Mississippi

100,000

-

5.25% Series due August 2013 - Entergy New Orleans

70,000

-

5.25% Series due August 2015 - Entergy Gulf States

200,000

-

6.75% Series due October 2017 - Entergy New Orleans

25,000

25,000

5.4% Series due May 2018 - Entergy Arkansas

150,000

-

4.95% Series due June 2018 - Entergy Mississippi

95,000

-

 

 

2003

2002

(In Thousands)

Mortgage Bonds (continued):

5.0% Series due July 2018 - Entergy Arkansas

$115,000

$-

8.94% Series due January 2022 - Entergy Gulf States

-

150,000

8.0% Series due March 2023 - Entergy New Orleans

45,000

45,000

7.7% Series due July 2023 - Entergy Mississippi

60,000

60,000

7.55% Series due September 2023 - Entergy New Orleans

30,000

30,000

7.0% Series due October 2023 - Entergy Arkansas

175,000

175,000

8.7% Series due April 2024 - Entergy Gulf States

-

294,950

6.7% Series due April 2032 - Entergy Arkansas

100,000

100,000

7.6% Series due April 2032 - Entergy Louisiana

150,000

150,000

6.0% Series due November 2032 - Entergy Arkansas

100,000

100,000

6.0% Series due November 2032 - Entergy Mississippi

75,000

75,000

7.25% Series due December 2032 - Entergy Mississippi

100,000

100,000

5.9% Series due June 2033 - Entergy Arkansas

100,000

-

6.20% Series due July 2033 - Entergy Gulf States

240,000

-

Total mortgage bonds

3,860,000

4,147,950

Governmental Bonds (a):

5.45% Series due 2010, Calcasieu Parish - Louisiana

$22,095

 

$22,100

6.75% Series due 2012, Calcasieu Parish - Louisiana

48,285

 

48,280

6.7% Series due 2013, Pointe Coupee Parish - Louisiana

17,450

 

17,450

5.7% Series due 2014, Iberville Parish - Louisiana

21,600

 

21,600

7.7% Series due 2014, West Feliciana Parish - Louisiana

94,000

 

94,000

5.8% Series due 2015, West Feliciana Parish - Louisiana

28,400

 

28,400

7.0% Series due 2015, West Feliciana Parish - Louisiana

39,000

 

39,000

7.5% Series due 2015, West Feliciana Parish - Louisiana

41,600

 

41,600

9.0% Series due 2015, West Feliciana Parish - Louisiana

45,000

 

45,000

5.8% Series due 2016, West Feliciana Parish - Louisiana

20,000

 

20,000

6.3% Series due 2016, Pope County - Arkansas

19,500

19,500

5.6% Series due 2017, Jefferson County - Arkansas

45,500

45,500

6.3% Series due 2018, Jefferson County - Arkansas

9,200

9,200

6.3% Series due 2020, Pope County - Arkansas

120,000

120,000

6.25% Series due 2021, Independence County - Arkansas

45,000

45,000

7.5% Series due 2021, St. Charles Parish - Louisiana

50,000

50,000

5.875% Series due 2022, Mississippi Business Finance Corp.

216,000

216,000

5.9% Series due 2022, Mississippi Business Finance Corp.

102,975

102,975

7.0% Series due 2022, Warren County - Mississippi

8,095

8,095

7.0% Series due 2022, Washington County - Mississippi

7,935

7,935

7.0% Series due 2022, St. Charles Parish - Louisiana

24,000

24,000

2003

2002

(In Thousands)

Governmental Bonds (continued):

7.05% Series due 2022, St. Charles Parish - Louisiana

$20,000

$20,000

Auction Rate due 2022, Independence City - Mississippi

30,000

30,000

5.95% Series due 2023, St. Charles Parish - Louisiana

25,000

25,000

6.2% Series due 2023, St. Charles Parish - Louisiana

33,000

33,000

6.875% Series due 2024, St. Charles Parish - Louisiana

20,400

20,400

6.375% Series due 2025, St. Charles Parish - Louisiana

16,770

16,770

7.3% Series due 2025, Claiborne County - Mississippi

7,625

7,625

6.2% Series due 2026, Claiborne County - Mississippi

90,000

90,000

5.05% Series due 2028, Pope County - Arkansas (b)

47,000

47,000

5.65% Series due 2028, West Feliciana Parish - Louisiana (c)

62,000

62,000

6.6% Series due 2028, West Feliciana Parish - Louisiana

40,000

40,000

5.35% Series due 2029, St. Charles Parish - Louisiana (d)

-

110,950

Auction Rate due 2030, St. Charles Parish - Louisiana

60,000

60,000

4.9% Series due 2030, St. Charles Parish - Louisiana (e) (f)

55,000

55,000

Total governmental bonds

1,532,430

1,643,380

Other Long-Term Debt:

Note Payable to NYPA, non-interest bearing, 4.8% implicit rate

$514,708

$683,640

Bank Credit Facility (Entergy Corporation and Subsidiaries, Note 4)

-

535,000

Bank term loan, Entergy Corporation, avg rate 2.98%, due 2005

60,000

60,000

Bank term loan, Entergy Corporation, avg rate 3.08%, due 2008

35,000

-

6.17% Notes due March 2008, Entergy Corporation

72,000

-

6.23% Notes due March 2008, Entergy Corporation

15,000

-

6.13% Notes due September 2008, Entergy Corporation

150,000

-

7.75% Notes due December 2009, Entergy Corporation

267,000

267,000

6.58% Notes due May 2010, Entergy Corporation

75,000

-

6.9% Notes due November 2010, Entergy Corporation

140,000

-

7.06% Notes due March 2011, Entergy Corporation

86,000

-

Long-term DOE Obligation (g)

154,409

152,804

Waterford 3 Lease Obligation

7.45% (Entergy Corporation and Subsidiaries, Note 10)

262,534

297,950

Grand Gulf Lease Obligation

7.02% (Entergy Corporation and Subsidiaries, Note 10)

403,468

414,843

Unamortized Premium and Discount - Net

(11,853)

(13,741)

Top of Iowa wind project debt, avg rate 3.15% due 2003

-

79,029

8.5% Junior Subordinated Deferrable Interest Debentures

Due 2045 - Entergy Arkansas

61,856

61,856

8.75% Junior Subordinated Deferrable Interest Debentures

Due 2046 - Entergy Gulf States

87,629

87,629

9.0% Junior Subordinated Deferrable Interest Debentures

Due 2045 - Entergy Louisiana

72,165

72,165

Other

9,966

10,464

Total Long-Term Debt

7,847,312

8,499,969

Less Amount Due Within One Year

524,372

1,191,320

Long-Term Debt Excluding Amount Due Within One Year

$7,322,940

$7,308,649

Fair Value of Long-Term Debt (h)

$7,113,740

$7,546,996

 

(a)

Consists of pollution control revenue bonds and environmental revenue bonds, certain series of which are secured by non-interest bearing first mortgage bonds.

(b)

The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on September 1, 2005 and can then be remarketed.

(c)

The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on September 1, 2004 and can then be remarketed.

(d)

The bonds had a mandatory tender date of October 1, 2003. Entergy Louisiana purchased the bonds from the holders, pursuant to the mandatory tender provision, and has not remarketed the bonds at this time. Entergy Louisiana used a combination of cash on hand and short-term borrowing to buy-in the bonds.

(e)

On June 1, 2002, Entergy Louisiana remarketed $55 million St. Charles Parish Pollution Control Revenue Refunding Bonds due 2030, resetting the interest rate to 4.9% through May 2005.

(f)

The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on June 1, 2005 and can then be remarketed.

(g)

Pursuant to the Nuclear Waste Policy Act of 1982, Entergy's nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service. The contracts include a one-time fee for generation prior to April 7, 1983. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt.

(h)

The fair value excludes lease obligations, long-term DOE obligations, and other long-term debt and includes debt due within one year. It is determined using bid prices reported by dealer markets and by nationally recognized investment banking firms.

The annual long-term debt maturities (excluding lease obligations) for debt outstanding as of December 31, 2003, for the next five years are as follows:

 

(In Thousands)

   

2004

$503,215

2005

$462,420

2006

$75,896

2007

$624,539

2008

$941,625

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

Covenants in the Entergy Corporation notes require it to maintain a consolidated debt ratio of 65% or less of its total capitalization. If Entergy's  debt ratio exceeds this limit, or if Entergy or certain of the domestic utility companies default on other indebtedness or are in bankruptcy or insolvency proceedings, an acceleration of the notes' maturity dates may occur.

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 1;
    • 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.

 

NOTE 6. COMPANY-OBLIGATED REDEEMABLE PREFERRED SECURITIES

Entergy implemented FASB Interpretation No. 46, "Consolidation of Variable Interest Entities" effective December 31, 2003. FIN 46 requires existing unconsolidated variable interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among their investors. Variable interest entities (VIEs), generally, are entities that do not have sufficient equity to permit the entity to finance its operations without additional financial support from its equity interest holders and/or the group of equity interest holders are collectively not able to exercise control over the entity. The primary beneficiary is the party that absorbs a majority of the entity's expected losses, receives a majority of its expected residual returns, or both as a result of holding the variable interest. A company may have an interest in a VIE through ownership or other contractual rights or obligations.

Entergy Louisiana Capital I, Entergy Arkansas Capital I, and Entergy Gulf States Capital I (Trusts) were established as financing subsidiaries of Entergy Louisiana, Entergy Arkansas, and Entergy Gulf States, respectively,  (the parent company or companies, collectively) for the purposes of issuing common and preferred securities. The Trusts issued Cumulative Quarterly Income Preferred Securities (Preferred Securities) to the public and issued common securities to their parent companies. Proceeds from such issues were used to purchase junior subordinated deferrable interest debentures (Debentures) from the parent company. The Debentures held by each Trust are its only assets. Each Trust uses interest payments received on the Debentures owned by it to make cash distributions on the Preferred Securities and common securities. The parent companies fully and unconditionally guaranteed payment of distributions on the Preferred Securities issued by the respective Trusts. Prior to the application of FIN 46, each parent company consolidated its interest in its Trust. Because each parent company's share of expected losses of its Trust is limited to its investment in its Trust, the parent companies are not considered the primary beneficiaries and therefore de-consolidated their interest in the Trusts upon application of FIN 46 with no significant impacts to the financial statements. The parent companies' investment in the Trusts and the Debentures issued by each parent company are included in Other Property and Investments and Long-Term Debt, respectively. The financial statements as of December 31, 2002 have been reclassified to reflect the application of FIN 46 as of that date.

 

NOTE 7. PREFERRED STOCK

The number of shares authorized and outstanding and dollar value of preferred stock for Entergy Corporation subsidiaries as of December 31, 2003 and 2002 are presented below. Only the Entergy Gulf States series "with sinking fund" contain mandatory redemption requirements. All other series are redeemable at Entergy's option.

 

Shares

Authorized

and Outstanding

2003

2002

2003

2002

(Dollars in Thousands)

Entergy Corporation

U.S. Utility Preferred Stock:

Without sinking fund:

Entergy Arkansas, 4.32% - 7.88% Series

1,613,500

1,613,500

$116,350

$116,350

Entergy Gulf States, 4.20% - 7.56% Series

473,268

473,268

47,327

47,327

Entergy Louisiana, 4.16% - 8.00% Series

2,115,000

2,115,000

100,500

100,500

Entergy Mississippi, 4.36% - 8.36% Series

503,807

503,807

50,381

50,381

Entergy New Orleans, 4.36% - 5.56% Series

197,798

197,798

19,780

9,780

Total without sinking fund

4,903,373

4,903,373

$334,337

$334,337

 

 

With sinking fund:

 

 

Entergy Gulf States, Adjustable Rate 7.0% (a)

208,519

243,269

$20,852

$24,327

Total with sinking fund

208,519

243,269

$20,852

$24,327

Fair Value of Preferred Stock

with sinking fund (b)

$15,354

$20,792

(a)

Represents weighted-average annualized rate for 2003.

(b)

Fair values were determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. There is additional disclosure of fair value of financial instruments in Note 15 to the consolidated financial statements.

All outstanding preferred stock is cumulative.

Changes in the preferred stock of Entergy during the last three years were:

    

Number of Shares

    

2003

 

2002

 

2001

Preferred stock retirements

           

Entergy Gulf States

           

$100 par value

 

(34,500)

 

(18,579)

 

(49,237)

Entergy Louisiana

           

$100 par value

 

 

 

(350,000)

Entergy Gulf States has annual sinking fund requirements of $3.45 million through 2008 for its preferred stock outstanding.

NOTE 8. COMMON EQUITY

Common Stock

Treasury Stock

Treasury stock activity for Entergy for 2003 and 2002:

2003

2002

Treasury Shares

Cost

Treasury Shares

Cost

(In Thousands)

(In Thousands)

Beginning Balance, January 1

25,752,410 

$747,331 

27,441,384 

$758,820 

  Repurchases

155,000 

8,135 

2,885,000 

118,499 

  Issuances:

  Equity Ownership/Equity Awards Plans

(6,622,095)

(194,057)

(4,567,054)

(129,748)

  Directors' Plan

(8,870)

(257)

(6,920)

(240)

Ending Balance, December 31

19,276,445 

$561,152 

25,752,410 

$747,331 

 

Entergy Corporation reissues treasury shares to meet the requirements of the Stock Plan for Outside Directors (Directors' Plan), the Equity Ownership Plan of Entergy Corporation and Subsidiaries (Equity Ownership Plan), the Equity Awards Plan, and certain other stock benefit plans. The Directors' Plan awards to non-employee directors a portion of their compensation in the form of a fixed number of shares of Entergy Corporation common stock.

Equity Compensation Plan Information

Entergy has two plans that grant stock options, equity awards, and incentive awards to key employees of the Entergy subsidiaries. The Equity Ownership Plan is a shareholder-approved stock-based compensation plan. The Equity Awards Plan is a Board-approved stock-based compensation plan. Stock options are granted at exercise prices not less than market value on the date of grant. The majority of options granted in 2003, 2002, and 2001 will become exercisable in equal amounts on each of the first three anniversaries of the date of grant. Options expire ten years after the date of the grant if they are not exercised.

Beginning in 2001, Entergy began granting most of the equity awards and incentive awards earned under its stock benefit plans in the form of performance units, which are equal to the cash value of shares of Entergy Corporation common stock at the time of payment. In addition to the potential for equivalent share appreciation or depreciation, performance units will earn the cash equivalent of the dividends paid during the performance period applicable to each plan. The amount of performance units awarded will not reduce the amount of securities remaining under the current authorizations. The costs of equity and incentive awards, given either as company stock or performance units, are charged to income over the period of the grant or restricted period, as appropriate. In 2003, 2002, and 2001, $45 million, $28 million, and $14 million, respectively, was charged to compensation expense.

 

Entergy was assisted by external valuation firms to determine the fair value of the stock option grants made in 2003. The fair value applied to the 2003 grants was an average of two firms' option valuations, which included adjustments for factors such as lack of marketability, stock retention requirements, and regulatory restrictions on exercisability. In 2002 and 2001, the fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model, without any such adjustments. The stock option weighted-average assumptions used in determining the fair values were as follows:

 

2003

 

2002

 

2001

 

 

 

 

 

 

Stock price volatility

26.3%

 

27.2%

 

26.3%

Expected term in years

6.2

 

5.0

 

5.0

Risk-free interest rate

3.3%

 

4.2%

 

4.9%

Dividend yield

3.3%

 

3.2%

 

3.4%

Dividend payment

$1.40

 

$1.32

 

$1.26

Stock option transactions are summarized as follows:

2003

2002

2001

Average

Average

Average

Number

Exercise

Number

Exercise

Number

Exercise

of Options

Price

of Options

Price

of Options

Price

Beginning-of-year balance

19,943,114

$ 35.85

17,316,816

$ 31.06

11,468,316

$ 25.52

Options granted

2,936,236

44.98

8,168,025

41.72

8,602,300

36.96

Options exercised

(6,927,000)

33.12

(4,877,688)

28.62

(2,407,783)

25.85

Options forfeited

(522,967)

40.98

(664,039)

36.36

(346,017)

30.35

End-of-year balance

15,429,383

$ 38.64

19,943,114

$ 35.85

17,316,816

$ 31.06

Options exercisable at year-end

6,153,043

$ 34.82

4,837,511

$ 31.39

2,923,452

$ 27.35

Weighted-average fair value of

options at time of grant

$ 6.86

$ 9.22

$ 8.14

The following table summarizes information about stock options outstanding as of December 31, 2003:

Retained Earnings and Dividend Restrictions

Provisions within the Articles of Incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of certain of Entergy Corporation's subsidiaries restrict the payment of cash dividends or other distributions on their common and preferred stock. As of December 31, 2003, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $309.4 million and $41.9 million, respectively. Additionally, PUHCA prohibits Entergy Corporation's subsidiaries from making loans or advances to Entergy Corporation. In 2003, Entergy Corporation received dividend payments totaling $425 million from subsidiaries.

Investments in affiliates that are not controlled by Entergy Corporation, but over which it has significant influence, are accounted for using the equity method. Entergy's retained earnings include undistributed earnings of equity method investees of $472.0 million in 2003 and $304.1 million in 2002. Equity method investments are discussed in Note 13 to the consolidated financial statements.

 

NOTE 9. COMMITMENTS AND CONTINGENCIES

Entergy is involved in a number of legal, tax, and regulatory proceedings before various courts, regulatory commissions, and governmental agencies in the ordinary course of its business. While management is unable to predict the outcome of such proceedings, management does not believe that the ultimate resolution of these matters will have a material adverse effect on Entergy's results of operations, cash flows, or financial condition.

Sales Warranties and Indemnities

In the Saltend sales transaction discussed further in Note 14 to the consolidated financial statements, Entergy or its subsidiaries made certain warranties to the purchasers relating primarily to the performance of certain remedial work on the facility and the assumption of responsibility for certain contingent liabilities. Entergy believes that it has provided adequately for the warranties as of December 31, 2003.

Vidalia Purchased Power Agreement

Entergy Louisiana has an agreement extending through the year 2031 to purchase energy generated by a hydroelectric facility known as the Vidalia project. Entergy Louisiana made payments under the contract of approximately $112.6 million in 2003, $104.2 million in 2002, and $86.0 million in 2001. If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $116.5 million in 2004, and a total of $3.6 billion for the years 2005 through 2031. Entergy Louisiana currently recovers the costs of the purchased energy through its fuel adjustment clause. In an LPSC-approved settlement related to tax benefits from the tax treatment of the Vidalia contract, Entergy Louisiana agreed to credit rates by $11 million each year for up to ten years, beginning in October 2002.

Nuclear Insurance

Third Party Liability Insurance

The Price-Anderson Act provides insurance for the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Originally passed by Congress in 1957 and most recently amended in 1988, the Price-Anderson Act requires nuclear power plants to show evidence of financial protection in the event of a nuclear accident. This protection must consist of two levels:

  1. The primary level is private insurance underwritten by American Nuclear Insurers and provides liability insurance coverage of $300 million. If this amount is not sufficient to cover claims arising from the accident, the second level, Secondary Financial Protection, applies. An industry-wide aggregate limitation of $300 million exists for domestically-sponsored terrorist acts. There is no limitation for foreign-sponsored terrorist acts.
  2. Within the Secondary Financial Protection level, each nuclear plant must pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary level, up to a maximum of $100.6 million per reactor per incident. This consists of a $95.8 million maximum retrospective premium plus a five percent surcharge that may be applied, if needed, at a rate that is presently set at $10 million per year per nuclear power reactor. There are no domestically- or foreign-sponsored terrorism limitations.

Currently, 105 nuclear reactors are participating in the Secondary Financial Protection program - 103 operating reactors and two closed units that still store used nuclear fuel on site. The product of the maximum retrospective premium assessment to the nuclear power industry and the number of nuclear power reactors provides over $10 billion in insurance coverage to compensate the public in the event of a nuclear power reactor accident.

Entergy owns and operates ten of the nuclear power reactors, and owns the shutdown Indian Point 1 reactor (10% of Grand Gulf 1 is owned by a non-affiliated company which would share on a pro-rata basis in any retrospective premium assessment under the Price-Anderson Act).

An additional but temporary contingent liability exists for all nuclear power reactor owners because of a previous Nuclear Worker Tort (long-term bodily injury caused by exposure to nuclear radiation while employed at a nuclear power plant) insurance program that was in place from 1988 to 1998. The maximum premium assessment exposure to each reactor is $3 million and will only be applied if such claims exceed the program's accumulated reserve funds. This contingent premium assessment feature will expire with the Nuclear Worker Tort program's expiration, which is scheduled for 2008.

Property Insurance

Entergy's nuclear owner/licensee subsidiaries are members of certain mutual insurance companies that provide property damage coverage, including decontamination and premature decommissioning expense, to the members' nuclear generating plants. These programs are underwritten by Nuclear Electric Insurance Limited (NEIL). As of December 31, 2003, Entergy was insured against such losses per the following structures:

U.S. Utility Plants (ANO 1 and 2, Grand Gulf 1, River Bend, and Waterford 3)

    • Primary Layer (per plant) - $500 million per occurrence
    • Excess Layer (per plant) - $100 million per occurrence
    • Blanket Layer (shared among all plants) - $1.0 billion per occurrence
    • Total limit - $1.6 billion per occurrence
    • Deductibles:
    • $1.0 million per occurrence - Equipment breakdown/failure
    • $2.5 million per occurrence - Other than equipment breakdown/failure

Note: ANO 1 and 2 share in the Primary Layer with one policy in common.

Non-Utility Nuclear Plants (Indian Point 2 and 3, FitzPatrick, Pilgrim, and Vermont Yankee)

    • Primary Layer (per plant) - $500 million per occurrence
    • Blanket Layer (shared among all plants) - $615 million per occurrence
    • Total limit - $1.115 billion per occurrence
    • Deductibles:
    • $1.0 million per occurrence - Equipment breakdown/failure
    • $1.0 million per occurrence (all plants except Vermont Yankee which is $500,000) - Other than equipment breakdown/failure

Note: Indian Point 2 and 3 share in the Primary Layer with one policy in common.

In addition, the Non-Utility Nuclear plants are also covered under NEIL's Accidental Outage Coverage program. This coverage provides certain fixed indemnities in the event of an unplanned outage that results from a covered NEIL property damage loss, subject to a deductible. The following summarizes this coverage as of December 31, 2003:

    • Indian Point 2 and 3, FitzPatrick, and Pilgrim (each plant has an individual policy with the noted parameters):
    • $4.5 million weekly indemnity
    • $490 million maximum indemnity
    • Deductible: 12 week waiting period

    • Vermont Yankee
    • $4.0 million weekly indemnity
    • $435 million maximum indemnity
    • Deductible: 12 week waiting period

Entergy's U.S. Utility nuclear plants have significantly less or no accidental outage coverage. Under the property damage and accidental outage insurance programs, Entergy nuclear plants could be subject to assessments should losses exceed the accumulated funds available from NEIL. As of December 31, 2003, the maximum amounts of such possible assessments per occurrence were $77 million for the Non-Utility Nuclear plants and $79.3 million for the U.S. Utility plants.

Entergy maintains property insurance for its nuclear units in excess of the NRC's minimum requirement of $1.06 billion per site for nuclear power plant licensees. NRC regulations provide that the proceeds of this insurance must be used, first, to render the reactor safe and stable, and second, to complete decontamination operations. Only after proceeds are dedicated for such use and regulatory approval is secured would any remaining proceeds be made available for the benefit of plant owners or their creditors.

In the event that one or more acts of domestically-sponsored terrorism causes property damage under one or more or all nuclear insurance policies issued by NEIL (including, but not limited to, those described above) within 12 months from the date the first property damage occurs, the maximum recovery under all such nuclear insurance policies shall be an aggregate of $3.24 billion plus the additional amounts recovered for such losses from reinsurance, indemnity, and any other sources applicable to such losses. There is no aggregate limit involving one or more acts of foreign-sponsored terrorism.

Nuclear Decommissioning and Other Retirement Costs

SFAS 143, "Accounting for Asset Retirement Obligations," which was implemented effective January 1, 2003, requires the recording of liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of those assets. For Entergy, these asset retirement obligations consist of its liability for decommissioning its nuclear power plants.

These liabilities are recorded at their fair values (which is the present values of the estimated future cash outflows) in the period in which they are incurred, with an accompanying addition to the recorded cost of the long-lived asset. The asset retirement obligation is accreted each year through a charge to expense, to reflect the time value of money for this present value obligation. The amounts added to the carrying amounts of the long-lived assets will be depreciated over the useful lives of the assets. The net effect of implementing this standard for the rate-regulated business of the domestic utility companies and System Energy was recorded as a regulatory asset, with no resulting impact on Entergy's net income. Entergy recorded these regulatory assets because existing rate mechanisms in each jurisdiction are based on the principle that Entergy will recover all ultimate costs of decommissioning from customers.

Assets and liabilities increased approximately $1.1 billion for the domestic utility companies and System Energy 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 $287 million, reducing accumulated depreciation by $361 million and recording the related 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 approximately $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 the domestic utility companies and System Energy include a component for removal costs that are not asset retirement obligations under SFAS 143. In accordance with regulatory accounting principles, Entergy has recorded a regulatory asset for certain of its domestic utility companies and System Energy of approximately $72.4 million as of December 31, 2003 and approximately $79.6 million as of December 31, 2002 to reflect an estimate of incurred but uncollected removal costs previously recorded as a component of accumulated depreciation. The decommissioning and retirement cost liability for certain of the domestic utility companies and System Energy includes a regulatory liability of approximately $26.8 million as of December 31, 2003 and approximately $25.5 million as of December 31, 2002 representing an estimate of collected but not yet incurred removal costs. For the Non-Utility Nuclear business, the implementation of SFAS 143 resulted in a decrease in liabilities of approximately $595 million due to reductions in decommissioning liabilities, a decrease in assets of approximately $340 million, including a decrease in electric plant in service of $315 million, and an increase in earnings in the first quarter of 2003 of approximately $155 million net-of-tax ($0.67 per share) as a result of a one-time cumulative effect of accounting change.

The cumulative decommissioning liabilities and expenses recorded in 2003 by Entergy were as follows:

Liabilities as of

SFAS 143

Liabilities as of

December 31, 2002

Adoption

Accretion

Spending

December 31, 2003

(In Millions)

ANO 1 & ANO 2

$310.7

$221.0

$35.8

$ -

$567.5

River Bend

237.0

41.2

20.6

-

298.8

Waterford 3

125.3

179.4

20.6

-

325.3

Grand Gulf 1

153.5

137.2

21.8

-

312.5

Pilgrim

490.2

(292.6)

15.8

-

213.4

Indian Point 1 & 2

456.9

(207.3)

19.9

11.8

257.7

Vermont Yankee

316.7

(95.1)

17.7

-

239.3

$2,090.3

($16.2)

$152.2

$ 11.8

$2,214.5

 

In addition, an insignificant amount of removal costs associated with non-nuclear power plants are also included in the decommissioning line item on the balance sheet. Entergy periodically reviews and updates estimated decommissioning costs. The actual decommissioning costs may vary from the estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment.

 

If Entergy had applied SFAS 143 during prior periods, the following impacts would have resulted:

   

Year Ended
December 31,
2002

 

Year Ended
December 31,
2001

         

Asset retirement obligations actually recorded

 

$2,090,269 

 

$1,679,738 

Pro forma effect of SFAS 143

 

$(46,041)

 

$28,512 

Asset retirement obligations - pro forma

 

$2,044,228 

 

$1,708,250 

         

Earnings applicable to common stock - as reported

 

$599,360 

 

$726,196 

Pro forma effect of SFAS 143

 

$14,119 

 

$9,613 

Earnings applicable to common stock - pro forma

 

$613,479 

 

$735,809 

         

Basic earnings per average common share - as reported

 

$2.69 

 

$3.29 

Pro forma effect of SFAS 143

 

$0.06 

 

$0.04 

Basic earnings per average common share - pro forma

 

$2.75 

 

$3.33 

         

Diluted earnings per average common share - as reported

 

$2.64 

 

$3.23 

Pro forma effect of SFAS 143

 

$0.06 

 

$0.04 

Diluted earnings per average common share - pro forma

 

$2.70 

 

$3.27 

For the Indian Point 3 and FitzPatrick plants purchased in 2000, NYPA retained the decommissioning trusts and the decommissioning liability. NYPA and Entergy executed decommissioning agreements, which specify their decommissioning obligations. NYPA has the right to require Entergy to assume the decommissioning liability provided that it assigns the corresponding decommissioning trust, up to a specified level, to Entergy. If the decommissioning liability is retained by NYPA, Entergy will perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. Entergy believes that the amounts available to it under either scenario are sufficient to cover the future decommissioning costs without any additional contributions to the trusts.

Entergy maintains decommissioning trust funds that are committed to meeting the costs of decommissioning the nuclear power plants. The fair values of the decommissioning trust funds and asset retirement obligation-related regulatory assets of Entergy as of December 31, 2003 are as follows:

Decommissioning

Trust

Regulatory

Fair Values

Assets

(In Millions)

ANO 1 & ANO 2

$360.5

$203.7

River Bend

267.9

36.2

Waterford 3

152.0

132.3

Grand Gulf 1

172.9

92.7

Pilgrim

491.9

-

Indian Point 1 & 2

485.9

-

Vermont Yankee

347.4

-

$2,278.5

$464.9

 

The Energy Policy Act of 1992 contains a provision that assesses domestic nuclear utilities with fees for the decontamination and decommissioning (D&D) of the DOE's past uranium enrichment operations. Annual assessments (in 2003 dollars), which will be adjusted annually for inflation, are for 15 years and were $4.3 million for Entergy Arkansas, $1.1 million for Entergy Gulf States, $1.6 million for Entergy Louisiana, and $1.8 million for System Energy in 2003. The Energy Policy Act calls for cessation of annual D&D assessments not later than October 24, 2007. At December 31, 2003, three years of assessments were remaining. D&D fees are included in other current liabilities and other non-current liabilities and, as of December 31, 2003, recorded liabilities were $12.8 million for Entergy Arkansas, $3.0 million for Entergy Gulf States, $4.9 million for Entergy Louisiana, and $4.8 million for System Energy. Regulatory assets in the financial statements offset these liabilitie s, with the exception of Entergy Gulf States' 30% non-regulated portion. These assessments are recovered through rates in the same manner as fuel costs.

Employment Litigation

Entergy Corporation and certain subsidiaries are defendants in numerous lawsuits filed by former employees asserting that they were wrongfully terminated and/or discriminated against on the basis of age, race, and/or sex. Entergy Corporation and these subsidiaries are vigorously defending these suits and deny any liability to the plaintiffs. Nevertheless, no assurance can be given as to the outcome of these cases.

 

 

NOTE 10. LEASES

General

As of December 31, 2003, Entergy had non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities (excluding nuclear fuel leases and the Grand Gulf 1 and Waterford 3 sale and leaseback transactions) with minimum lease payments as follows:

Total rental expenses for all leases (excluding nuclear fuel leases and the Grand Gulf 1 and Waterford 3 sale and leaseback transactions) amounted to $58.9 million in 2003, $60.1 million in 2002, and $65.1 million in 2001.

Nuclear Fuel Leases

As of December 31, 2003, arrangements to lease nuclear fuel existed in an aggregate amount up to $150 million for Entergy Arkansas, $80 million for each of System Energy and Entergy Louisiana, and $105 million for Entergy Gulf States. As of December 31, 2003, the unrecovered cost base of nuclear fuel leases amounted to approximately $102.7 million for Entergy Arkansas, $63.7 million for Entergy Gulf States, $65.0 million for Entergy Louisiana, and $47.2 million for System Energy. The lessors finance the acquisition and ownership of nuclear fuel through loans made under revolving credit agreements, the issuance of commercial paper, and the issuance of intermediate-term notes. The credit agreements for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy each have a termination date of October 30, 2006. The termination dates may be extended from time to time with the consent of the lenders. The intermediate-term notes issued pursuant to these fuel lease arrang ements have varying maturities through December 15, 2008. It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. However, if such additional financing cannot be arranged, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations in accordance with the Fuel Lease.

Lease payments are based on nuclear fuel use. The total nuclear fuel lease payments (principal and interest) as well as the separate interest component charged to operations by the domestic utility companies and System Energy were $142.0 million (including interest of $11.8 million) in 2003, $137.8 million (including interest of $11.3 million) in 2002, and $149.3 million (including interest of $17.2 million) in 2001.

Sale and Leaseback Transactions

Waterford 3 Lease Obligations

In 1989, Entergy Louisiana sold and leased back 9.3% of its interest in Waterford 3 for the aggregate sum of $353.6 million. The lease has an approximate term of 28 years. The lessors financed the sale-leaseback through the issuance of Waterford 3 Secured Lease Obligation Bonds. The lease payments made by Entergy Louisiana are sufficient to service the debt.

In 1994, Entergy Louisiana did not exercise its option to repurchase the 9.3% interest in Waterford 3. As a result, Entergy Louisiana issued $208.2 million of non-interest bearing first mortgage bonds as collateral for the equity portion of certain amounts payable under the lease.

In 1997, the lessors refinanced the outstanding bonds used to finance the purchase of Waterford 3 at lower interest rates, which reduced the annual lease payments.

Upon the occurrence of certain events, Entergy Louisiana may be obligated to assume the outstanding bonds used to finance the purchase of the unit and to pay an amount sufficient to withdraw from the lease transaction. Such events include lease events of default, events of loss, deemed loss events, or certain adverse "Financial Events." "Financial Events" include, among other things, failure by Entergy Louisiana, following the expiration of any applicable grace or cure period, to maintain (i) total equity capital (including preferred stock) at least equal to 30% of adjusted capitalization, or (ii) a fixed charge coverage ratio of at least 1.50 computed on a rolling 12 month basis.

As of December 31, 2003, Entergy Louisiana's total equity capital (including preferred stock) was 49.82% of adjusted capitalization and its fixed charge coverage ratio for 2003 was 4.06.

As of December 31, 2003, Entergy Louisiana had future minimum lease payments (reflecting an overall implicit rate of 7.45%) in connection with the Waterford 3 sale and leaseback transactions, which are recorded as long-term debt, as follows:

Grand Gulf 1 Lease Obligations

In December 1988, System Energy sold 11.5% of its undivided ownership interest in Grand Gulf 1 for the aggregate sum of $500 million. Subsequently, System Energy leased back its interest in the unit for a term of 26-1/2 years. System Energy has the option of terminating the lease and repurchasing the 11.5% interest in the unit at certain intervals during the lease. Furthermore, at the end of the lease term, System Energy has the option of renewing the lease or repurchasing the 11.5% interest in Grand Gulf 1.

System Energy is required to report the sale-leaseback as a financing transaction in its financial statements. For financial reporting purposes, System Energy expenses the interest portion of the lease obligation and the plant depreciation. However, operating revenues include the recovery of the lease payments because the transactions are accounted for as a sale and leaseback for ratemaking purposes. Consistent with a recommendation contained in a FERC audit report, System Energy recorded as a net regulatory asset the difference between the recovery of the lease payments and the amounts expensed for interest and depreciation and is recording this difference as a regulatory asset or liability on an ongoing basis, resulting in a zero net balance at the end of the lease term. The amount of this net regulatory asset was $83.2 million and $79.5 million as of December 31, 2003 and 2002, respectively.

As of December 31, 2003, System Energy had future minimum lease payments (reflecting an implicit rate of 7.02%), which are recorded as long-term debt as follows:

NOTE 11. RETIREMENT, OTHER POSTRETIREMENT BENEFITS, AND DEFINED CONTRIBUTION PLANS

Pension Plans

Entergy has seven pension plans covering substantially all of its employees: "Entergy Corporation Retirement Plan for Non-Bargaining Employees," "Entergy Corporation Retirement Plan for Bargaining Employees," "Entergy Corporation Retirement Plan II for Non-Bargaining Employees, " "Entergy Corporation Retirement Plan II for Bargaining Employees, " "Entergy Corporation Retirement Plan III, " "Entergy Corporation Retirement Plan IV for Non-Bargaining Employees, " and "Entergy Corporation Retirement Plan IV for Bargaining Employees. " Except for the Entergy Corporation Retirement Plan III, the pension plans are noncontributory and provide pension benefits that are based on employees' credited service and compensation during the final years before retirement. The Entergy Corporation Retirement Plan III includes a mandatory employee contribution of 3% of earnings during the first 10 years of plan participation, and allows voluntary contributions from 1% to 10% of earn ings for a limited group of employees. Entergy Corporation and its subsidiaries fund pension costs in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the plans include common and preferred stocks, fixed-income securities, interest in a money market fund, and insurance contracts. As of December 31, 2003 and December 31, 2002, Entergy recognized an additional minimum pension liability for the excess of the accumulated benefit obligation over the fair market value of plan assets. In accordance with FASB 87, an offsetting intangible asset, up to the amount of any unrecognized prior service cost, was also recorded, with the remaining offset to the liability recorded as a regulatory asset reflective of the recovery mechanism for pension costs in Entergy's jurisdictions. Entergy's domestic utility companies' and System Energy's pension costs are recovered from customers as a component of cost of service in each of its jurisdictions. Entergy uses a December 31 measurement date for its pension plans.

 

Components of Net Pension Cost

Total 2003, 2002, and 2001, pension costs of Entergy Corporation and its subsidiaries, including amounts capitalized, included the following components:

 

 

Pension Obligations, Plan Assets, Funded Status, Amounts Not Yet Recognized and Recognized in the Balance Sheet as of December 31, 2003 and 2002:

 

Other Postretirement Benefits

Entergy also provides health care and life insurance benefits for retired employees. Substantially all domestic employees may become eligible for these benefits if they reach retirement age while still working for Entergy. Entergy uses a December 31 measurement date for its postretirement benefit plans.

Effective January 1, 1993, Entergy adopted SFAS 106, which required a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. At January 1, 1993, the actuarially determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be approximately $241.4 million for Entergy (other than Entergy Gulf States) and $128 million for Entergy Gulf States. Such obligations are being amortized over a 20-year period that began in 1993. For the most part, the domestic utilities and System Energy recover SFAS 106 costs from customers and are required to fund postretirement benefits collected in rates to an external trust.

Components of Net Postretirement Benefit Cost

Total 2003, 2002, and 2001 other postretirement benefit costs of Entergy Corporation and its subsidiaries, including amounts capitalized and deferred, included the following components (in thousands):

2003

2002

2001

(In Thousands)

Service cost - benefits earned during the period

$37,799

$29,199

$24,225

Interest cost on APBO

52,746

44,819

38,811

Expected return on assets

(15,810)

(14,066)

(12,578)

Amortization of transition obligation

15,193

17,874

17,874

Amortization of prior service cost

(925)

992

992

Recognized net (gain)/loss

12,369

1,874

(1,506)

Curtailment loss

57,958

-

-

Special termination benefits

5,444

-

-

Net other postretirement benefit cost

$164,774

$80,692

$67,818

 

Other Postretirement Benefit Obligations, Plan Assets, Funded Status, and Amounts Not Yet Recognized and Recognized in the Balance Sheet as of December 31, 2003 and 2002:

December 31,

2003

2002

(In Thousands)

Change in APBO

Balance at beginning of year

$799,506 

$590,731 

Service cost

37,799 

29,199 

Interest cost

52,746 

44,819 

Actuarial loss

115,966 

159,143 

Benefits paid

(48,379)

(35,861)

Plan amendments (a)

(84,722)

Plan participant contributions

7,074 

Curtailment

56,369 

Special termination benefits

5,444 

Acquisition of subsidiary

11,475 

Balance at end of year

$941,803 

$799,506 

Change in Plan Assets

Fair value of assets at begininning of year

$182,692 

$158,190 

Actual return on plan assets

22,794 

(11,559)

Employer contributions

63,265 

59,542 

Plan participant contributions

7,074 

Benefits paid

(48,379)

(35,861)

Acquisition of subsidiary

12,380 

Fair value of assets at end of year

$227,446 

$182,692 

Funded status

($714,357)

($616,814)

Amounts not yet recognized in the balance sheet:

Unrecognized transition obligation

44,815 

114,724 

Unrecognized prior service cost

(20,746)

3,522 

Unrecognized net loss

336,005 

245,795 

Accrued other postretirement benefit cost recognized in the balance sheet

($354,283)

($252,773)

 

(a) Reflects plan design changes, including a change in the participation assumption for non-bargaining employees effective August 1, 2003.

Pension and Other Postretirement Plans' Assets

Entergy's pension and postretirement plans weighted-average asset allocations by asset category at December 31, 2003 and 2002 are as follows:

 

Pension

 

Postretirement

 

2003

 

2002

 

2003

 

2002

               

Domestic Equity Securities

56%

 

50%

 

37%

 

34%

International Equity Securities

14%

 

10%

 

0%

 

1%

Fixed Income Securities

28%

 

37%

 

60%

 

64%

Other

2%

 

3%

 

3%

 

1%

Entergy's trust asset investment strategy is to invest the assets in a manner whereby long-term earnings on the assets (plus cash contributions) provide adequate funding for retiree benefit payments. Adequate funding is described as a 90% confidence that assets equal or exceed liabilities due five years in the future, and a corresponding 75% confidence level ten years out. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk while minimizing the expected contributions and pension and postretirement expense.

To perform such an optimization study, Entergy first makes assumptions about certain market characteristics, such as expected asset class investment returns, volatility (risk) and correlation coefficients among the various asset classes. Entergy does so by examining (or hiring a consultant to provide such analysis) historical market characteristics of the various asset classes over all of the different economic conditions that have existed. Entergy then examines and projects the economic conditions expected to prevail over the study period. Finally, the historical characteristics to reflect the expected future conditions are adjusted to produce the market characteristics that will be assumed in the study.

The optimization analysis utilized in Entergy's latest study produced the following approved asset class target allocations.

 

Pension

 

Postretirement

       

Domestic Equity Securities

54%

 

37%

International Equity Securities

12%

 

8%

Fixed Income Securities

30%

 

55%

Other (Cash and GACs)

4%

 

0%

These allocation percentages combined with each asset class' expected investment return produced an aggregate return expectation of 9.59% for pension assets, 5.45% for taxable postretirement assets, and 7.19% for non-taxable postretirement assets. These returns are consistent with Entergy's disclosed expected return on assets of 8.75% (non-taxable assets) and 5.5% (taxable assets).

Since precise allocation targets are inefficient to manage security investments, the following ranges were established to produce an acceptable economically efficient plan to manage to targets:

 

Pension

 

Postretirement

       

Domestic Equity Securities

49 % to 59%

 

32 % to 42%

International Equity Securities

7% to 17%

 

3% to 12%

Fixed Income Securities

25% to 35%

 

50% to 60%

Other

0% to 10%

 

0% to 5%

Accumulated Pension Benefit Obligation

The accumulated benefit obligation for Entergy's pension plans was $2.1 billion and $1.7 billion at December 31, 2003 and 2002, respectively.

 

Estimated Future Benefit Payments

Based upon the assumptions used to measure the company's pension and postretirement benefit obligation at December 31, 2003, and including pension and postretirement benefits attributable to estimated future employee service, Entergy expects that pension benefits to be paid over the next ten years is as follows:

 

Estimated Future Benefits Payments

 

Pension

 

Postretirement

 

(In Thousands)

Year(s)

 

2004

$96,764

 

$53,666

2005

$98,378

 

$57,271

2006

$100,411

 

$58,389

2007

$103,225

 

$61,171

2008

$107,120

 

$63,393

2009 - 2013

$631,594

 

$358,648

Contributions

Entergy expects to contribute $110 million (which includes about $1 million in employee contributions) to its pension plans and $68.6 million to other postretirement plans in 2004.

Additional Information

The change in the minimum pension liability included in other comprehensive income and regulatory assets was as follows for 2003 and 2002:

 

2003

 

2002

 

(In Thousands)

Increase/(decrease) in the minimum pension liability included in:

     

     Other comprehensive income

($1,639)

 

$17,016

     Regulatory assets

($23,768)

 

$157,789

Actuarial Assumptions

The assumed health care cost trend rate used in measuring the APBO of Entergy was 10% for 2004, gradually decreasing each successive year until it reaches 4.5% in 2010 and beyond. The assumed health care cost trend rate used in measuring the Net Other Postretirement Benefit Cost of Entergy was 10% for 2004, gradually decreasing each successive year until it reaches 4.5% in 2009 and beyond. A one percentage point increase in the assumed health care cost trend rate for 2003 would have increased the APBO and the sum of the service cost and interest cost of Entergy as of December 31, 2003 as follows:

The significant actuarial assumptions used in determining the pension PBO and the SFAS 106 APBO for 2003, 2002, and 2001 were as follows:

 

2003

 

2002

 

2001

Weighted-average discount rate:

 

 

 

 

 

   Pension

6.25%

 

6.75%

 

7.50%

   Other postretirement

6.71%

 

6.75%

 

7.50%

Weighted-average rate of increase

 

  

 

  

 

   in future compensation levels

3.25%

 

3.25%

 

4.60%

Expected long-term rate of

 

 

 

 

 

   return on plan assets:

 

 

 

 

 

      Taxable assets

5.5%

 

5.50%

 

5.50%

      Non-taxable assets

8.75%

 

8.75%

 

9.00%

The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2003, 2002, and 2001 were as follows:

 

2003

 

2002

 

2001

 

 

 

 

 

 

Weighted-average discount rate

6.75%

 

7.5%

 

7.5%

Weighted-average rate of increase

 

 

 

 

 

   in future compensation levels

3.25%

 

4.6%

 

4.6%

Expected long-term rate of

 

 

 

 

 

   return on plan assets:

 

 

 

 

 

       Taxable assets

5.5%

 

5.5%

 

5.5%

       Non-taxable assets

8.75%

 

9.0%

 

9.0%

Entergy's remaining pension transition assets are being amortized over the greater of the remaining service period of active participants or 15 years, and its SFAS 106 transition obligations are being amortized over 20 years.

Voluntary Severance Program

During 2003, Entergy offered a voluntary severance program to certain groups of employees. As a result of this program, Entergy recorded additional pension and postretirement costs (including amounts capitalized) of $110.3 million for special termination benefits and plan curtailment charges. These amounts are included in the net pension cost and net postretirement benefit cost for the year ended December 31, 2003.

Medicare Prescription Drug, Improvement and Modernization Act of 2003

In December 2003, the President signed the Medicare Prescription Drug, Improvement and Modernization Act of 2003 into law. The Act introduces a prescription drug benefit under Medicare (Part D) as well as federal subsidy to employers who provide a retiree prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

Currently, specific authoritative guidance on the accounting for the federal subsidy is pending. As allowed by Financial Accounting Standards Board Staff Position No. FAS 106-1, Entergy has elected to record an estimate of the effects of the Act in accounting for its postretirement benefit plans under SFAS 106 and in providing disclosures required by SFAS No. 132 (revised 2003), Employers' Disclosures about Pensions and Other Postretirement Benefits.

Based on actuarial analysis of prescription drug benefits, estimated future Medicare subsidies are expected to reduce the December 31, 2003 Accumulated Postretirement Benefit Obligation by $56 million. For the year ended December 31, 2003 the impact of the Act on Net Postretirement Cost was immaterial, as it reflected only one month's impact of the Act. When specific guidance on accounting for federal subsidy is issued, these estimates could change.

Defined Contribution Plans

Entergy sponsors the Savings Plan of Entergy Corporation and Subsidiaries (Savings Plan). The Savings Plan is a defined contribution plan covering eligible employees of Entergy and its subsidiaries. Through January 31, 2004, the Savings Plan provided that the employing Entergy subsidiary:

    • make matching contributions to the Savings Plan in an amount equal to 75% of the participants' basic contributions, up to 6% of their eligible earnings, in shares of Entergy Corporation common stock if the employees direct their company-matching contribution to the purchase of Entergy Corporation's common stock; or
    • make matching contributions in the amount of 50% of the participants' basic contributions, up to 6% of their eligible earnings, if the employees direct their company-matching contribution to other investment funds.

Effective February 1, 2004, the employing Entergy subsidiary will make matching contributions to the Savings Plan in an amount equal to 70% of the participants' basic contributions, up to 6% of their eligible earnings. The 70% match will be allocated to investments as directed by the employee.

Entergy also sponsors the Savings Plan of Entergy Corporation and Subsidiaries II (began in 2001), the Savings Plan of Entergy Corporation and Subsidiaries III (began in 2002), and the Savings Plan of Entergy Corporation and Subsidiaries V (began in 2002). The plans are defined contribution plans that cover eligible employees, as defined by each plan, of Entergy and its subsidiaries. The employing Entergy subsidiary makes matching contributions equal to 50% of the participants' participating contributions for each of these plans.

Entergy's subsidiaries' contributions to the plans collectively were $31.5 million in 2003, $29.6 million in 2002, and $25.4 million in 2001 to these defined contribution plans. The majority of the contributions were to the Savings Plan.

 

NOTE 12. BUSINESS SEGMENT INFORMATION

Entergy's reportable segments as of December 31, 2003 are U.S. Utility, Non-Utility Nuclear, and Energy Commodity Services. U.S. Utility generates, transmits, distributes, and sells electric power in portions of Arkansas, Louisiana, Mississippi, and Texas, and provides natural gas utility service in portions of Louisiana. Non-Utility Nuclear owns and operates five nuclear power plants and is primarily focused on selling electric power produced by those plants to wholesale customers. Energy Commodity Services is focused primarily on providing energy commodity trading and gas transportation and storage services through Entergy-Koch, LP. Energy Commodity Services also includes non-nuclear wholesale assets, a participant in the wholesale power generation business in North America and Europe. Results from Entergy-Koch are reported as equity in earnings of unconsolidated equity affiliates in the financial statements. Entergy's operating segments are strategic business units managed separa tely due to their different operating and regulatory environments. Entergy's chief operating decision maker is its Office of the Chief Executive, which consists of its highest-ranking officers.

"All Other" includes the parent company, Entergy Corporation, and other business activity, including earnings on the proceeds of sales of previously owned businesses.

 

Entergy's segment financial information is as follows:

  



U.S. Utility

 


Non-Utility Nuclear*

Energy Commodity Services*



All Other*

 



Eliminations

 



Consolidated

  

(In Thousands)

2003

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

$7,584,857 

 

$1,274,983

 

$184,888

 

$188,228 

 

($38,036)

 

$9,194,920

Deprec., amort. & decomm.

890,092 

 

87,825

 

13,681

 

5,005 

 

 

996,603

Interest income

43,035 

 

36,874

 

18,128

 

27,575 

 

(38,226)

 

87,386

Equity in earnings (loss) of

 

 

 

 

 

 

 

 

 

 

 

unconsolidated equity affiliates

(3)

 

-

 

271,650

 

 

 

271,647

Interest charges

419,111 

 

34,460

 

15,193

 

75,787 

 

(38,225)

 

506,326

Income taxes (credits)

341,044 

 

88,619

 

105,903

 

(45,492)

 

 

490,074

Cumulative effect of accounting change

(21,333)

 

154,512

 

3,895

 

 

 

137,074

Net income (loss)

492,574 

 

300,799

 

180,454

 

(23,360)

 

 

950,467

Total assets

22,429,136 

 

4,171,777

 

2,076,921

 

1,495,903 

 

(1,619,527)

 

28,554,210

Investment in affiliates - at equity

211 

 

-

 

1,081,462

 

 

(28,345)

 

1,053,328

Cash paid for long-lived asset additions

1,233,208 

 

281,377

 

44,284

 

10,074 

 

 

1,568,943

 

  



U.S. Utility

 


Non-Utility Nuclear*

Energy Commodity Services*



All Other*

 



Eliminations

 



Consolidated

  

(In Thousands)

2002

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

$6,773,509 

 

$1,200,238

 

$294,670 

 

$40,729 

 

($4,111)

 

$8,305,035

Deprec., amort. & decomm.

800,257 

 

88,733

 

21,465 

 

5,143 

 

 

915,598

Interest income

23,231 

 

71,262

 

26,140 

 

35,433 

 

(37,741)

 

118,325

Equity in earnings of

 

 

 

 

 

 

 

 

 

 

 

unconsolidated equity affiliates

(2)

 

-

 

183,880 

 

 

 

183,878

Interest charges

465,703 

 

47,291

 

61,632 

 

35,579 

 

(37,741)

 

572,464

Income taxes (credits)

313,752 

 

132,726

 

(141,288)

 

(11,252)

 

 

293,938

Net income (loss)

606,963 

 

200,505

 

(145,830)

 

(38,566)

 

 

623,072

Total assets

21,630,523 

 

4,482,308

 

2,167,472 

 

1,327,354 

 

(2,103,291)

 

27,504,366

Investment in affiliates - at equity

214 

 

-

 

823,995 

 

 

 

824,209

Cash paid for long-lived asset additions

1,131,734 

 

169,756

 

210,297 

 

18,514 

 

 

1,530,301

 



U.S. Utility

 


Non-Utility Nuclear*

Energy Commodity Services*



All Other*

 



Eliminations

 



Consolidated

 

(In Thousands)

2001

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

$7,432,920

 

$789,244

 

$1,370,485

 

$34,603 

 

($6,353)

 

$9,620,899

Deprec., amort. & decomm.

667,333

 

43,103

 

34,667

 

4,516 

 

 

749,619

Interest income

79,702

 

54,053

 

23,169

 

37,235 

 

(34,354)

 

159,805

Equity in earnings of

 

 

 

 

 

 

 

 

 

 

 

unconsolidated equity affiliates

-

 

-

 

162,882

 

 

 

162,882

Interest charges

576,705

 

55,717

 

74,953

 

41,558 

 

(34,353)

 

714,580

Income taxes

300,284

 

80,053

 

74,493

 

863 

 

 

455,693

Cumulative effect of accounting change

-

 

-

 

23,482

 

 

 

23,482

Net income (loss)

574,554

 

127,880

 

105,939

 

(57,866)

 

 

750,507

Total assets

20,309,695

 

3,449,156

 

2,377,733

 

863,906 

 

(1,090,179)

 

25,910,311

Investment in affiliates - at equity

214

 

-

 

765,889

 

 

 

766,103

Cash paid for long-lived asset additions

1,110,484

 

126,880

 

199,387

 

599,886 

 

 

2,036,637

Businesses marked with * are referred to as the "competitive businesses," with the exception of the parent company, Entergy Corporation. Eliminations are primarily intersegment activity.

Energy Commodity Services' net loss for the year ended December 31, 2002 includes net charges of $428.5 million to operating expenses ($238.3 million net of tax). These charges reflect the effect of Entergy's decision to discontinue additional greenfield power plant development and the asset impairments resulting from the deteriorating economics of wholesale power markets in the United States and the United Kingdom. The net charges consist 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 benefit of $28.5 million ($18.5 million net of tax) related to the sale of four turbines to a third party, is 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 result from the write-off of Entergy Power Development Corporation's equity investment in the Damhead Creek project and the impairment of the values of the Warren Power power plant, the Crete project, and the RS Cogen project. This portion of the charges reflects Entergy's estimate of the effects of reduced spark spreads in the United States and the United Kingdom. These estimates are based on various sources of information, including discounted cash flow projections and current market prices.
  • $39.1 million of the charges relate to the restructuring of the non-nuclear wholesale assets business, including impairments of administrative fixed assets, estimated sublease losses, and employee-related costs for approximately 135 affected employees. These restructuring costs are included in the "Provision for turbine commitments, asset impairments and restructuring charges" in the accompanying consolidated statement of income were comprised of the following:

 

 

Restructuring Costs

Paid in Cash

Non-Cash Portion

Remaining
Accrual

 

(in millions)

Fixed asset impairments

$22.5

$ -

$22.5

$ -

Sublease losses

10.7

5.6

-

5.1

Severance and related costs

5.9

5.9

Total

$39.1

$11.5

$22.5

$5.1

  • $32.7 million of the charges result from the write-off of capitalized project development costs for projects that will not be completed.
  • The net charges include a gain of $25.7 million ($15.9 million net of tax) on the sale of projects under development in Spain in August 2002 and the after-tax gain of $31.4 million realized on the sale of Damhead Creek in December 2002.

 

Geographic Areas

The following table shows Entergy's domestic and foreign operating revenues for the years ended December 31:

 

2003

 

2002

 

2001

 

(In Thousands)

Domestic

$9,122,827

 

$8,051,992

 

$9,098,861

Foreign

72,093

 

253,043

 

522,038

Consolidated

$9,194,920

 

$8,305,035

 

$9,620,899

Long-lived assets as of December 31 were as follows:

 

2003

 

2002

 

2001

 

(In Thousands)

Domestic

$18,296,934

 

$17,664,230

 

$16,468,059

Foreign

1,863

 

773

 

421,870

Consolidated

$18,298,797

 

$17,665,003

 

$16,889,929

 

NOTE 13. EQUITY METHOD INVESTMENTS

As of December 31, 2003, Entergy owns material investments in the following companies that it accounts for under the equity method of accounting:

Company

 

Ownership

 

Description

         

Entergy-Koch, LP

 

50% partnership interest

 

Engaged in two major businesses: energy commodity trading, which includes power, gas, weather derivatives, emissions, and cross-commodities, and gas transportation and storage

         

RS Cogen LLC

 

50% member interest

 

Co-generation project that produces power and steam on an industrial and merchant basis in the Lake Charles, Louisiana area

         

EntergyShaw LLC

 

50% member interest

 

Provides management, engineering, procurement, construction, and commissioning services for electric power plants

         

Crete Energy Ventures, LLC Crete Turbine Holding, LLC

 

50% member interests

 

Own a merchant power plant located in Crete, Illinois

         

Entergy sold its interest in the Crete project in January 2004 and realized an insignificant gain on the sale.

Following is a reconciliation of Entergy's investments in equity affiliates:

   

2003

 

2002

 

2001

   

(In Thousands)

Beginning of year

 

$824,209 

 

$766,103 

 

$136,487 

Additional investments

 

4,668 

 

36,372 

 

471,102 

Income from the investments

 

271,647 

 

183,878 

 

162,882 

Other income

 

45,583 

 

21,462 

 

18,074 

Dividends received

 

(105,142)

 

(73,902)

 

(21,191)

Currency translation adjustments

 

 

 

138 

Dispositions and other adjustments

 

12,363 

 

(109,704)

 

(1,389)

End of year

 

$1,053,328 

 

$824,209 

 

$766,103 

In accordance with the partnership agreement, Entergy contributed $72.7 million to Entergy-Koch in January 2004.

The following is a summary of combined financial information reported by Entergy's equity method investees:

     

2003

 

2002

 

2001

     

(In Thousands)

               

Income Statement Items

           
 

Operating revenues

 

$585,404

 

$551,853

 

$693,400

 

Operating income

 

$207,301

 

$159,342

 

$309,752

 

Net income

 

$172,595

 

$68,095

 

$226,039

               

Balance Sheet Items

           
 

Current assets

 

$2,576,630

 

$2,334,133

   
 

Noncurrent assets

 

$1,675,334

 

$1,490,355

   
 

Current liabilities

 

$1,757,663

 

$1,782,385

   
 

Noncurrent liabilities

 

$1,166,540

 

$729,817

   

Two of the unconsolidated 50/50 joint ventures, Entergy-Koch and RS Cogen, have obtained debt financing for their operations. As of December 31, 2003, the debt financing outstanding for those two entities totals $773.8 million, which is included in the liability figures given above. This debt is nonrecourse to Entergy.

Related-party transactions and guarantees

During 2003, 2002, and 2001, Entergy procured various services from Entergy-Koch consisting primarily of pipeline transportation services for natural gas and risk management services for electricity and natural gas. The total cost of such services in 2003, 2002, and 2001 was approximately $15.9 million, $11.2 million, and $7.8 million, respectively. In 2003, Entergy Louisiana and Entergy New Orleans entered purchase power agreements with RS Cogen, and purchased a total of $26.0 million of capacity and energy from RS Cogen in 2003. Entergy's operating transactions with its other equity method investees were not material in 2003, 2002, or 2001.

EntergyShaw constructed the Harrison County project for Entergy that was completed in 2003. Entergy guaranteed EntergyShaw's obligation to construct the plant until approximately June 2004. Entergy's maximum liability on the guarantee is $232.5 million.

RS Cogen has an interest rate swap agreement that hedges the interest rate on a portion of its debt. Entergy guaranteed RS Cogen's obligations under the interest rate swap agreement. The guarantee is in the amount of $16.5 million and terminates in October 2017.

 

NOTE 14. ACQUISITIONS AND DISPOSITIONS

Asset Acquisitions

Vermont Yankee

In July 2002, Entergy's Non-Utility Nuclear business purchased the 510 MW Vermont Yankee nuclear power plant located in Vernon, Vermont, from Vermont Yankee Nuclear Power Corporation for $180 million. Entergy received the plant, nuclear fuel, inventories, and related real estate. The liability to decommission the plant, as well as related decommissioning trust funds of approximately $310 million, was also transferred to Entergy. The acquisition included a 10-year power purchase agreement (PPA) under which the former owners will buy the power produced by the plant, which is through the expiration of the current operating license for the plant. The PPA includes an adjustment clause which provides that the prices specified in the PPA will be adjusted downward annually, beginning in 2006, if power market prices drop below the PPA prices.

The acquisition was accounted for using the purchase method. The results of operations of Vermont Yankee subsequent to the purchase date have been included in Entergy's consolidated results of operations. The purchase price has been allocated to the assets acquired and liabilities assumed based on their estimated fair values on the purchase date.

Indian Point 2

In September 2001, Entergy's Non-Utility Nuclear business acquired the 970 MW Indian Point 2 nuclear power plant located in Westchester County, New York from Consolidated Edison. Entergy paid approximately $600 million in cash at the closing of the purchase and received the plant, nuclear fuel, materials and supplies, a purchase power agreement (PPA), and assumed certain liabilities. On the second anniversary of the Indian Point 2 acquisition, Entergy's nuclear business will also begin to pay NYPA $10 million per year for up to 10 years in accordance with the Indian Point 3 purchase agreement. Under the PPA, Consolidated Edison will purchase 100% of Indian Point 2's output through 2004. Consolidated Edison transferred a $430 million decommissioning trust fund, along with the liability to decommission Indian Point 2 and Indian Point 1, to Entergy. Entergy acquired Indian Point 1 in the transaction, a plant that has been shut down and in safe storage since the 1 970s.

The acquisition was accounted for using the purchase method. The results of operations of Indian Point 2 subsequent to the purchase date have been included in Entergy's consolidated results of operations. The purchase price has been allocated to the acquired assets, including identifiable intangible assets, and liabilities assumed based on their estimated fair values on the purchase date. Intangible assets are being amortized straight-line over the remaining life of the plant.

Asset Dispositions

In the first quarter of 2002, Entergy sold its interests in projects in Argentina, Chile, and Peru for net proceeds of $135.5 million. After impairment provisions recorded for these Latin American interests in 2001, the net loss realized on the sale in 2002 is insignificant.

In August 2002, Entergy sold its interest in projects under development in Spain for a realized gain on the sale of $25.7 million. In December 2002, Entergy sold its 800 MW Damhead Creek power plant in the UK resulting in an increase in net income of $31.4 million. The Damhead Creek buyer assumed all market and regulatory risks associated with the facility.

In August 2001, Entergy sold its Saltend power plant in the UK for a cash payment of approximately $800 million. Entergy's gain on the sale was approximately $88.1 million ($57.2 million after tax). In the sales transaction, Entergy or its subsidiaries made certain warranties to the purchasers relating primarily to the performance of certain remedial work on the facility and the assumption of responsibility for certain contingent liabilities. Entergy believes that it has provided adequate reserves for the warranties as of December 31, 2003.

 

NOTE 15. RISK MANAGEMENT AND FAIR VALUES

Market and Commodity Risks

In the normal course of business, Entergy is exposed to a number of market and commodity risks. Market risk is the potential loss that Entergy may incur as a result of changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Entergy is subject to a number of commodity and market risks, including:

Type of Risk

 

Primary Affected Segments

     

Power price risk

 

All reportable segments

Fuel price risk

 

All reportable segments

Foreign currency exchange rate risk

 

All reportable segments

Equity price and interest rate risk - investments

 

U.S. Utility, Non-Utility Nuclear

Entergy manages these risks through both contractual arrangements and derivatives. Contractual risk management tools include long-term power and fuel purchase agreements, capacity contracts, and tolling agreements. Entergy also uses a variety of commodity and financial derivatives, including natural gas and electricity futures, forwards, swaps, and options; foreign currency forwards; and interest rate swaps as a part of its overall risk management strategy. Except for the energy trading activities conducted by the Energy Commodity Services segment, Entergy enters into derivatives only to manage natural risks inherent in its physical or financial assets or liabilities.

Entergy's exposure to market risk is determined by a number of factors, including the size, term, composition, and diversification of positions held, as well as market volatility and liquidity. For instruments such as options, the time period during which the option may be exercised and the relationship between the current market price of the underlying instrument and the option's contractual strike or exercise price also affects the level of market risk. A significant factor influencing the overall level of market risk to which Entergy is exposed is its use of hedging techniques to mitigate such risk. Entergy manages market risk by actively monitoring compliance with stated risk management policies as well as monitoring the effectiveness of its hedging policies and strategies. Entergy's risk management policies limit the amount of total net exposure and rolling net exposure during the stated periods. These policies, including related risk limits, are regularly assessed to ensure thei r appropriateness given Entergy's objectives.

 

Hedging Derivatives

Entergy classifies substantially all of the following types of derivative instruments held by its consolidated businesses as cash flow hedges:

Instrument

 

Business Segment

     

Natural gas and electricity futures and forwards

 

Non-Utility Nuclear, Energy Commodity Services

Foreign currency forwards

 

U.S. Utility, Non-Utility Nuclear

Cash flow hedges with net unrealized gains of approximately $11 million at December 31, 2003 are scheduled to mature during 2004. Gains totaling approximately $27 million were realized during 2003 on the maturity of cash flow hedges. Unrealized gains or losses result from hedging power output at the Non-Utility Nuclear power stations and foreign currency hedges related to Euro-denominated nuclear fuel acquisitions. The related gains or losses from hedging power are included in revenues when realized. The realized gains or losses from foreign currency transactions are included in the cost of capitalized fuel. The maximum length of time over which Entergy is currently hedging the variability in future cash flows for forecasted transactions at December 31, 2003 is approximately five years. The ineffective portion of the change in the value of Entergy's cash flow hedges during 2003 was insignificant.

Fair Values

Commodity Instruments

Fair value estimates of Energy Commodity Services' commodity instruments are made at discrete points in time based on relevant market information. Market quotes are used in determining fair value whenever they are available. When market quotes are not available (e.g., in the case of a long-dated commodity contract), other information is used, including transactional data and internally developed models. Fair value estimates based on these other methodologies are necessarily subjective in nature and involve uncertainties and matters of significant judgment. Therefore, actual results may differ from these estimates. At December 31, 2003 and 2002, the recorded values of Energy Commodity Services' energy-related commodity contracts were as follows:

 

2003

 

2002

 

Assets

 

Liabilities

 

Assets

 

Liabilities

 

(In Thousands)

               

Consolidated subsidiaries

$-

 

$-

 

$4,071

 

$8,395

Equity method investees (1)

$872,959

 

$866,412

 

$754,678

 

$663,765

(1)

As required by equity method accounting principles, only Entergy's net investment in these investees is reflected in its balance sheet, and these assets and liabilities are not reflected in Entergy's balance sheet. See Note 13 to the consolidated financial statements for more information on Entergy's equity method investees.

 

Following are the cumulative periods in which Entergy-Koch Trading's net mark-to-market assets would be realized in cash if they are held to maturity and market prices are unchanged:

Maturities and Sources for Fair
Value of Trading Contracts at
December 31, 2003



0-12 months



13-24 months



25+ months



Total

   

(In Millions)

Prices actively quoted

 

$126.3 

 

($87.1)

 

($14.6)

 

$24.6 

Prices provided by other sources

4.8 

(10.1)

5.6 

0.3 

Prices based on models

 

(28.0)

 

14.2 

 

4.9 

 

(8.9)

Total

 

$103.1 

 

($83.0)

 

($4.1)

 

$16.0 

Financial Instruments

The estimated fair value of Entergy's financial instruments is determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. The estimated fair value of derivative financial instruments is based on market quotes. Considerable judgment is required in developing some of the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. In addition, gains or losses realized on financial instruments held by regulated businesses may be reflected in future rates and therefore do not necessarily accrue to the benefit or detriment of stockholders.

Entergy considers the carrying amounts of most of its financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. Additional information regarding financial instruments and their fair values is included in Notes 5 and 7 to the consolidated financial statements.

 

NOTE 16. QUARTERLY FINANCIAL DATA (UNAUDITED)

Operating results for the four quarters of 2003 and 2002 were:

 

Operating
Revenues

 

Operating
Income (Loss)

 

Net
Income (Loss)

 

(In Thousands)

2003:

 

   First Quarter

$2,037,723

 

$363,403 

 

$400,923(a)

   Second Quarter

2,353,909

 

461,576 

 

211,517   

   Third Quarter

2,700,125

 

619,005 

 

371,650   

   Fourth Quarter

2,103,163

 

40,571 

 

(33,623)  

 

 

 

 

 

 

2002:

         

   First Quarter

$1,860,834

 

$(55,670)

 

$(72,983)  

   Second Quarter

2,096,581

 

486,159 

 

247,585   

   Third Quarter

2,468,875

 

653,695 

 

366,800   

   Fourth Quarter

1,878,745

 

57,537 

 

81,670   

(a)

Net income before the cumulative effect of accounting change for the first quarter 2003 was $258,001.

 

 

Earnings per Average Common Share

 

 

2003

 

2002

 

Basic

 

Diluted

 

Basic

 

Diluted

               

First Quarter

$1.77(b)

 

$1.73(b)

 

$(0.36)

 

$(0.36)

Second Quarter

$0.91   

 

$0.89   

 

$1.08 

 

$1.06 

Third Quarter

$1.60   

 

$1.57   

 

$1.61 

 

$1.59 

Fourth Quarter

$(0.19)  

 

$(0.18)  

 

$0.36 

 

$0.35 

(b)

Basic and diluted earning per average common share before the cumulative effect of accounting change for the first quarter of 2003 were $1.13 and $1.10, respectively.

 

 

ENTERGY'S BUSINESS (continued)

U.S. Utility

The U.S. Utility is Entergy's largest business segment, with five wholly-owned domestic retail electric utility subsidiaries: Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. These companies generate, transmit, distribute and sell electric power to retail and wholesale customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy Gulf States and Entergy New Orleans also provide natural gas utility services to customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Also included in the U.S. Utility is System Energy, a wholly-owned subsidiary of Entergy Corporation that owns or leases 90 percent of Grand Gulf 1. System Energy sells its power and capacity from Grand Gulf 1 at wholesale to four of the domestic utility companies.

These utility subsidiaries are each regulated by state utility commissions, and in the case of Entergy New Orleans, the City Council. System Energy is regulated by FERC as all of its transactions are at the wholesale level. The U.S. Utility continues to operate as a monopoly as efforts toward deregulation have been delayed, abandoned, or not initiated in its service territories. The overall generation portfolio of the U.S. Utility, which relies heavily on natural gas and nuclear generation, is consistent with Entergy's strong support for the environment.

The U.S. Utility is focused on providing highly reliable and cost effective electricity and gas service while working in an environment that provides the highest level of safety for its employees. Since 1998, the U.S. Utility has significantly improved key customer service, reliability and safety metrics and continues to actively pursue additional improvements.

Customers

As of December 31, 2003, Entergy's domestic utility companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:

Electric Customers

Gas Customers

Area Served

(In Thousands)

(%)

(In Thousands)

(%)

Entergy Arkansas

Portions of Arkansas

660

25%

Entergy Gulf States

Portions of Texas and Louisiana

709

27%

90

38%

Entergy Louisiana

Portions of Louisiana

657

25%

Entergy Mississippi

Portions of Mississippi

416

16%

Entergy New Orleans

City of New Orleans*

189

7%

147

62%

Total customers

2,631

100%

237

100%

* Excludes Algiers, which is provided electric service by Entergy Louisiana.

 

Electric Energy Sales

The electric energy sales of Entergy's domestic utility companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On August 19, Entergy reached a 2003 peak demand of 20,162 MW, compared to the 2002 peak of 20,419 MW recorded on August 2 of that year. Selected electric energy sales data is shown in the table below:

Selected 2003 Electric Energy Sales Data

Entergy

Entergy

Entergy

Entergy

Entergy

System

Arkansas

Gulf States

Louisiana

Mississippi

New Orleans

Energy

Entergy (a)

(In GWh)

Electric Department:

  Sales to retail

   customers

19,650

33,805

27,778

12,891

5,844

-

99,968

Sales for resale:

  Affiliates

7,036

1,185

1,344

112

1,312

9,812

-

  Others

5,399

3,358

132

331

28

-

9,248

     Total

32,085

38,348

29,254

13,334

7,184

9,812

109,216

Average use per

 residential customer

 (KWh)

12,669

15,791

15,382

14,631

12,556

-

14,498

(a)

Includes the effect of intercompany eliminations.

The following table illustrates the domestic utility companies' 2003 combined electric sales volume as a percentage of total electric sales volume, and 2003 combined electric revenues as a percentage of total 2003 electric revenue, each by customer class.

Customer Class

 

% of Sales Volume

 

% of Revenue

         

Residential

 

30.0

 

36.3

Commercial

 

23.7

 

25.5

Industrial (a)

 

35.4

 

28.1

Wholesale

 

8.5

 

7.5

Governmental

 

2.4

 

2.6

(a)

Major industrial customers are in the chemical, petroleum refining, and paper industries.

See "Selected Financial Data" for each of the domestic utility companies for the detail of their sales by customer class for 2001, 2002, and 2003.

Selected 2003 Natural Gas Sales Data

Entergy New Orleans and Entergy Gulf States provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Gulf States sold 14,859,798 and 7,116,028 Mcf, respectively, of natural gas to retail customers in 2003. In 2003, 98% of Entergy Gulf States' operating revenue was derived from the electric utility business, and only 2% from the natural gas distribution business. For Entergy New Orleans, 81% of operating revenue was derived from the electric utility business and 19% from the natural gas distribution business in 2003. Following is data concerning Entergy New Orleans 2003 retail operating revenue sources and customer data.

   

Electric Operating

 

Natural Gas

Entergy New Orleans

 

Revenue

 

Revenue

          

Residential

 

41%

 

54%

Commercial

 

37%

 

21%

Industrial

 

6%

 

11%

Governmental/Municipal

 

16%

 

14%

Retail Rate Regulation

General (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans)

The retail regulatory philosophy has shifted in some jurisdictions from traditional, cost-of-service regulation to include performance-based rate elements. Performance-based rate plans are designed to encourage efficiencies and productivity while permitting utilities and their customers to share in the benefits. Entergy Mississippi, Entergy Louisiana, and Entergy New Orleans have implemented performance-based formula rate plans, but Entergy Louisiana's performance-based formula rate plan expired in 2001. The status of the introduction of competition in Entergy's retail service territories is summarized below.

Jurisdiction

 

Status of Retail Open Access

 

% of Entergy's
2003 Revenues Derived
from Retail Electric
Utility Operations
in the Jurisdiction

 

 

 

 

 

Arkansas

 

Retail open access was repealed in February 2003.

 

15.4%

 

 

 

 

 

Texas

 

Implementation delayed in Entergy Gulf States' service area in a settlement approved by PUCT. In light of regulatory proceedings and approvals required, retail open access not likely before the first quarter of 2005.

 

14.4%

 

 

 

 

 

Louisiana

 

The LPSC has deferred pursuing retail open access, pending developments at the federal level and in other states.

 

43.9%

 

 

 

 

 

Mississippi

 

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

 

13.0%

 

 

 

 

 

New Orleans

 

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

 

5.9%

Retail Rate Proceedings

Each domestic utility operating subsidiary participates in retail rate proceedings on a consistent basis. The status of material retail rate proceedings is described below and in Note 2 to the domestic utility companies and System Energy financial statements.

Company

 

Authorized
ROE

 

Pending Proceedings/Events

 

 

 

 

 

Entergy Arkansas

 

11.0%

 

No cases are pending. Transition cost account mechanism expired on December 31, 2001. It is likely a filing will be made in mid-2005 in connection with the steam generator replacement at ANO.

 

 

 

 

 

Entergy Gulf States-Texas

 

10.95%

 

Base rates have been frozen since settlement order issued in June 1999. Freeze will likely extend to the start of retail open access given management's current expectations as to the start of retail open access.

 

 

 

 

 

Entergy Gulf States-Louisiana

 

11.1%

 

The LPSC approved a settlement resolving the 4th - 8th post-merger earning reviews resulting in a $22.1 million prospective rate reduction effective January 2003 and a refund of $16.3 million. 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 9th earnings analysis (2002). Hearings are set for April 2004. With the LPSC staff, Entergy Gulf States continues to pursue the development of a performance-based rate structure.

 

 

 

 

 

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 are scheduled for September 2004. With the LPSC staff, Entergy Louisiana continues to pursue the development of a performance-based rate structure.

 

 

 

 

 

Entergy Mississippi

 

10.64%-
12.86%(2)

 

An annual formula rate plan is in place. The MPSC approved a $48.2 million rate increase effective January 2003 and an ROE midpoint of 11.75%. Entergy Mississippi will make a formula rate plan filing in March 2004.

 

 

 

 

 

Entergy New Orleans

 

10.25%-12.25%(3)

 

The City Council approved an agreement in May 2003 allowing for a $30.2 million increase in base rates effective June 1, 2003 and approved the implementation of formula rate plans for the electric and gas service that will be evaluated annually until 2005. An appeal of the approval by intervenors is pending, but the rates remain in effect. The midpoint ROE of both plans is 11.25%, with a target equity component of 42%. Entergy New Orleans will make a formula rate plan filing in May 2004.

 

 

 

 

 

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 the 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 Mississ ippi'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. The benchmark ROE set out in the March 15, 2004, formula rate plan filing likely will differ from the last approved ROE. Entergy Mississippi anticipates that the March 15, 2004, filing will show an allowed regulatory earnings range of 9.3% to 12.2%. Entergy Mississippi does not anticipate a reduction in revenues going forward.

(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, and if the ROE falls between 10.25% and 11%, rates are increased by 40 percent of the differential. 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 discussed below.

Entergy Arkansas

Fuel Recovery

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 energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year.

Entergy Gulf States

Performance-Based Rate Plan

With the LPSC staff, Entergy Gulf States continues to pursue the development of a performance-based rate structure for its Louisiana jurisdiction.

Texas Jurisdiction - River Bend Costs

In March 1998, the PUCT issued an order disallowing recovery of $1.4 billion of company-wide River Bend plant costs which have been held in abeyance since 1988. Entergy Gulf States appealed the PUCT's decision on this matter to a Texas District Court. A June 1999 settlement agreement addresses the treatment of abeyed plant costs, and, as a result, Entergy Gulf States removed the reserve for these costs and reduced the carrying value of the plant asset in 1999. In another settlement, Entergy Gulf States agreed not to prosecute its appeal before January 1, 2002 and agreed to cap the recovery of Entergy Gulf States' River Bend abeyed investment at $115 million net plant in service, less depreciation. The Texas District Court affirmed the PUCT decision disallowing recovery of the abeyed plant costs in April 2002, and Entergy Gulf States appealed that 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, management has concluded that it is prudent to accrue 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 as of June 30, 2003, and after this accrual Entergy Gulf States has provided for all potential loss related to current or past contested costs of construction of the River Bend plant. Accrual of the loss was recorded in the second quarter 2003 and reduced net income by $65.6 million. In January 2004, the Texas Supreme Court asked for full briefing on the merits of the case in response to Entergy Gulf States' petition for review. The abeyed plant costs are discussed in more detail in Note 2 to the domestic utility companies and System Energy financial statements.

Fuel Recovery

Entergy Gulf States' Texas rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including carrying charges, not recovered in base rates. Under 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 retail open access begins in Texas. To the extent actual costs vary from the fixed fuel factor, refunds or surcharges are required or permitted. The amounts collected under the fixed fuel factor through the start of retail open access are subject to fuel reconciliation proceedings before the PUCT. At the start of retail open access for Entergy Gulf States in Texas, which is not expected before the first quarter of 2005, fuel and purchased power cost recovery will be subject to the fuel component of the price-to-beat rates approved by the PUCT. The PUCT fuel cost reviews that were resolved during the past year or are currently pending are discussed in Note 2 to the domestic utility companies and System Energy financial statements.

Entergy Gulf States' Louisiana electric rates include a fuel adjustment designed to recover the cost of fuel and purchased power costs. The fuel adjustment contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers.

Entergy Gulf States' Louisiana gas rates include a purchased gas adjustment based on estimated gas costs for the billing month adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers.

Entergy Louisiana

Performance-Based Rate Plan

With the LPSC staff, Entergy Louisiana continues to pursue the development of a performance-based rate structure.

Fuel Recovery

Entergy Louisiana's rate schedules include a fuel adjustment clause designed to recover the cost of fuel. The fuel adjustment contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers.

In September 2002, Entergy Louisiana settled a proceeding that concerned a contract entered into by Entergy Louisiana to purchase through the year 2031 energy generated by a hydroelectric facility known as the Vidalia project. In the settlement, the LPSC approved Entergy Louisiana's proposed treatment of the regulatory impact of a tax accounting election related to that project. 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. E ntergy 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 Internal 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 the years 2013-2031, Entergy Louisiana and its ratepayers would share the remaining benefits of this tax accounting election. Note 9 to the domestic utility companies and System Energy financial statements contains further discussion of the obligations related to the Vidalia project.

Entergy Louisiana has reduced its indebtedness and preferred stock with a portion of the cash. In accordance with the terms of the settlement, Entergy Louisiana requested SEC approval to return up to $350 million of common equity capital to Entergy Corporation in order to maintain Entergy Louisiana's current capital structure. In December 2002, Entergy Louisiana repurchased $120 million of common stock from Entergy Corporation and paid a dividend of $122.6 million pursuant to the SEC approval. The provisions of the settlement provide that the LPSC shall not recognize or use Entergy Louisiana's use of this cash in setting any of Entergy Louisiana's rates. Therefore, to the extent Entergy Louisiana's use of the proceeds would ordinarily have reduced its rate base, no change in rate base shall be reflected for ratemaking purposes. The SEC approval for additional return of equity capital is now expired.

Entergy Mississippi

Performance-Based Formula Rate Plan

Entergy Mississippi files a performance-based formula rate plan every 12 months that compares the annual earned rate of return to, and adjusts it against, a benchmark rate of return. The benchmark is calculated under a separate formula within the formula rate plan. The formula rate plan allows for periodic small adjustments in rates, up to an amount that would produce a change in Entergy Mississippi's overall revenue of almost 2%, based on a comparison of actual earned returns to benchmark returns and upon certain performance factors. In accordance with the MPSC's December 2002 rate order, there was no formula rate plan filing in 2003 for the 2002 test year. The next formula rate plan filing will be submitted in March 2004 for the 2003 test year, and filings are due to continue annually thereafter.

Fuel Recovery

Entergy Mississippi's rate schedules include energy cost recovery riders to recover fuel and purchased energy costs. The rider utilizes projected energy costs filed quarterly by Entergy Mississippi to develop an energy cost rate. The energy cost rate is redetermined each calendar quarter and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy cost as of the second quarter preceding the redetermination.

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 has 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 will be collected through the energy cost recovery rider over a twelve-month period that began in January 2004.

Entergy New Orleans

Formula Rate Plans

In May 2003, the City Council approved the implementation of formula rate plans for electric and gas service that will be evaluated annually until 2005. Entergy New Orleans is required to make a filing with the Council in May 2004 based upon a 2003 test year. Under the formula rate plans, the midpoint ROE of both plans is 11.25%, with a target equity component of 42%. Any change in rates would be prospective, with the first billing cycle effective after September 1, 2004. Entergy New Orleans' can earn between 10.25% and 12.25% under the electric plan and between 11% and 11.5% under the gas plan, with earnings within those ranges not resulting in a change in rates. An appeal of the approval by intervenors is pending, but the rates remain in effect.

In May 2003, the City Council approved implementation of a generation performance-based rate calculation in the electric fuel adjustment clause under which Entergy New Orleans will receive 10% of calculated fuel and purchased power cost savings in excess of $20 million, based on a defined benchmark, subject to a 13.25% return on equity limitation for electric operations as provided for in the electric formula rate plan. Entergy New Orleans will bear 10% of any "negative" fuel and purchased power cost savings.

Fuel Recovery

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 the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges. The adjustment also includes the difference between non-fuel Grand Gulf 1 costs paid by Entergy New Orleans and the estimate of such costs, which are included in base rates, as provided in Entergy New Orleans' Grand Gulf 1 rate settlements. Entergy New Orleans' gas rate schedules include an adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges. In November 2003, the Council passed a resolution implementing a package of measur es developed by Entergy New Orleans and the Council Advisors to protect customers from potential gas price spikes during the 2003 - 2004 winter heating season. These measures include: expansion of Entergy New Orleans' financial hedging plan for its purchase of wholesale gas, and deferral of collection of up to $4 million of gas costs in the event that the average residential customer's gas bill were to exceed a threshold level, which management does not expect.

Franchises

Entergy Arkansas holds exclusive franchises to provide electric service in approximately 306 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are terminable upon breach of the terms of the franchise.

In Louisiana, Entergy Gulf States holds non-exclusive franchises, permits, or certificates of convenience and necessity to provide electric service in approximately 55 incorporated municipalities and the unincorporated areas of approximately 19 parishes, and to provide gas service in the City of Baton Rouge and the unincorporated areas of two parishes. In Texas, Entergy Gulf States holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 24 counties in eastern Texas, and holds non-exclusive franchises to provide electric service in approximately 65 incorporated municipalities. Entergy Gulf States typically is granted 50-year franchises in Texas and 60-year franchises in Louisiana. Entergy Gulf States' current electric franchises will expire during 2007 - 2045 in Texas and during 2015 - 2046 in Louisiana.

Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 116 incorporated Louisiana municipalities. Most of these franchises have 25-year terms, although six of these municipalities have granted 60-year franchises. Entergy Louisiana also supplies electric service in approximately 353 unincorporated communities, all of which are located in Louisiana parishes in which it holds non-exclusive franchises.

Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.

Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to city ordinances (except electric service in Algiers, which is provided by Entergy Louisiana). These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans' electric and gas utility properties. A resolution to study the advantages for ratepayers that might result from an acquisition of these properties was filed in a committee of the Council in January 2001. The committee has deferred consideration of and has taken no further action regarding that resolution. The full Council must approve the resolution to commence such a study before it can become effective.

The business of System Energy is limited to wholesale power sales. It has no distribution franchises.

Property and Other Generation Resources

Generating Stations

The total capability of the generating stations owned and leased by the domestic utility companies and System Energy as of December 31, 2003, is indicated below:

<

Owned and Leased Capability MW(1)

Gas

Turbine and

Internal