_______________________________________________________________________________________________

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, 2002

 

OR

 

TRANSITION REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

   
 

For the transition period from ____________ to ____________

Commission

Registrant, State of Incorporation,

IRS Employer

File Number

Address of Principal Executive Offices and Telephone Number

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, 40th Floor
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 - 223,869,216
shares outstanding at February 28, 2003

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

     

Entergy Arkansas Capital I

8-1/2% Cumulative Quarterly Income Preferred
Securities, Series A

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

New York Stock Exchange, Inc.

     

Entergy Louisiana Capital I

9% Cumulative Quarterly Income Preferred
Securities, Series A

New York Stock Exchange, Inc.

     

Securities registered pursuant to Section 12(g) of the Act:

Registrant

Title of Class

   

Entergy Arkansas, Inc.

Preferred Stock, Cumulative, $100 Par Value
Preferred Stock, Cumulative, $0.01 Par Value

   

Entergy Gulf States, Inc.

Preferred Stock, Cumulative, $100 Par Value

   

Entergy Louisiana, Inc.

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

   

Entergy Mississippi, Inc.

Preferred Stock, Cumulative, $100 Par Value

   

Entergy New Orleans, Inc.

Preferred Stock, Cumulative, $100 Par Value

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes Ö No ____

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [Ö ]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

 

Yes

No

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

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The aggregate market value of Entergy Corporation Common Stock, $0.01 Par Value, held by non-affiliates as of the end of the second quarter of 2002, was $9.4 billion based on the reported last sale price of $42.44 per share for such stock on the New York Stock Exchange on June 28, 2002. Entergy Corporation is directly or indirectly 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 9, 2003, are incorporated by reference into Parts I and III hereof.

 

TABLE OF CONTENTS

 

SEC Form 10-K
Reference Number

Page
Number

     

Definitions

 

i

Entergy Corporation

   

      Business

Part I. Item 1.

1

         Strategy and Performance

 

3

         Significant Business Issues

 

5

         Employees

 

7

      Report of Management

 

8

      Management's Financial Discussion and Analysis

Part II. Item 7.

9

         Results of Operations

 

9

         Liquidity and Capital Resources

 

16

         Significant Factors and Known Trends

 

23

         Critical Accounting Estimates

 

31

      Selected Financial Data - Five-Year Comparison

Part II. Item 6.

38

      Independent Auditors' Report

 

39

      Consolidated Statements of Income For the Years Ended December 31,
        2002, 2001, and 2000

Part II. Item 8.

41

      Consolidated Statements of Cash Flows For the Years Ended December
        31, 2002, 2001, and 2000

Part II. Item 8.

42

      Consolidated Balance Sheets, December 31, 2002 and 2001

Part II. Item 8.

44

      Consolidated Statements of Retained Earnings, Comprehensive Income,
        and Paid in Capital for the Years Ended December 31, 2002, 2001,
        and 2000

Part II. Item 8.

46

      Notes to Consolidated Financial Statements

Part II. Item 8.

47

   U.S. Utility

   

      Business

Part I. Item 1.

97

         Customers

 

97

         Electric Energy Sales

 

98

         Property

 

99

         Fuel Supply

 

100

         Regulation of the Nuclear Power Industry

 

103

         Rate Matters

 

105

         State Regulation

 

116

         Environmental Regulation

 

117

         Litigation

 

121

         Research

 

125

         Earnings Ratios

 

126

      Financial Information

 

127

   Non-Utility Nuclear

   

      Business

Part I. Item 1.

128

         Property

 

128

         Power Purchase Agreements

 

128

         Fuel Supply

 

129

         Other

 

129

         Regulation of the Nuclear Power Industry

 

129

         Environmental Regulation

 

132

      Financial Information

 

133

   Energy Commodity Services

   

      Business

Part I. Item 1.

134

         Entergy-Koch, LP

 

134

         Non-Nuclear Wholesale Asset Business

 

135

      Financial Information

 

137

   Entergy Arkansas, Inc.

   

      Management's Financial Discussion and Analysis

Part II. Item 7.

138

         Results of Operations

 

138

         Liquidity and Capital Resources

 

140

         Significant Factors and Known Trends

 

143

         Critical Accounting Estimates

 

145

      Independent Auditors' Report

 

150

      Income Statements For the Years Ended December 31, 2002, 2001,
        and 2000

Part II. Item 8.

151

      Statements of Cash Flows For the Years Ended December 31, 2002,
        2001, and 2000

Part II. Item 8.

153

      Balance Sheets, December 31, 2002 and 2001

Part II. Item 8.

154

      Statements of Retained Earnings for the Years Ended December 31,
        2002, 2001, and 2000

Part II. Item 8.

156

      Selected Financial Data - Five-Year Comparison

Part II. Item 6.

157

   Entergy Gulf States, Inc.

   

      Management's Financial Discussion and Analysis

Part II. Item 7.

158

         Results of Operations

 

158

         Liquidity and Capital Resources

 

160

         Significant Factors and Known Trends

 

163

         Critical Accounting Estimates

 

170

      Independent Auditors' Report

 

175

      Income Statements For the Years Ended December 31, 2002, 2001,
        and 2000

Part II. Item 8.

176

      Statements of Cash Flows For the Years Ended December 31, 2002,
        2001, and 2000

Part II. Item 8.

177

      Balance Sheets, December 31, 2002 and 2001

Part II. Item 8.

178

      Statements of Retained Earnings and Comprehensive Income for the
        Years Ended December 31, 2002, 2001, and 2000

Part II. Item 8.

180

      Selected Financial Data - Five-Year Comparison

Part II. Item 6.

181

   Entergy Louisiana, Inc.

   

      Management's Financial Discussion and Analysis

Part II. Item 7.

182

         Results of Operations

 

182

         Liquidity and Capital Resources

 

184

         Significant Factors and Known Trends

 

187

         Critical Accounting Estimates

 

190

      Independent Auditors' Report

 

194

      Income Statements For the Years Ended December 31, 2002, 2001,
        and 2000

Part II. Item 8.

195

      Statements of Cash Flows For the Years Ended December 31, 2002,
        2001, and 2000

Part II. Item 8.

197

      Balance Sheets, December 31, 2002 and 2001

Part II. Item 8.

198

      Statements of Retained Earnings for the Years Ended December 31,
        2002, 2001, and 2000

Part II. Item 8.

200

      Selected Financial Data - Five-Year Comparison

Part II. Item 6.

201

   Entergy Mississippi, Inc.

   

      Management's Financial Discussion and Analysis

Part II. Item 7.

202

         Results of Operations

 

202

         Liquidity and Capital Resources

 

204

         Significant Factors and Known Trends

 

206

         Critical Accounting Estimates

 

208

      Independent Auditors' Report

 

211

      Income Statements For the Years Ended December 31, 2002, 2001,
        and 2000

Part II. Item 8.

212

      Statements of Cash Flows For the Years Ended December 31, 2002,
        2001, and 2000

Part II. Item 8.

213

      Balance Sheets, December 31, 2002 and 2001

Part II. Item 8.

214

      Statements of Retained Earnings for the Years Ended December 31,
        2002, 2001, and 2000

Part II. Item 8.

216

      Selected Financial Data - Five-Year Comparison

Part II. Item 6.

217

   Entergy New Orleans, Inc.

   

      Management's Financial Discussion and Analysis

Part II. Item 7.

218

         Results of Operations

 

218

         Liquidity and Capital Resources

 

220

         Significant Factors and Known Trends

 

223

         Critical Accounting Estimates

 

224

      Independent Auditors' Report

 

227

      Statements of Operations For the Years Ended December 31, 2002,
        2001, and 2000

Part II. Item 8.

228

      Statements of Cash Flows For the Years Ended December 31, 2002,
        2001, and 2000

Part II. Item 8.

229

      Balance Sheets, December 31, 2002 and 2001

Part II. Item 8.

230

      Statements of Retained Earnings for the Years Ended December 31,
        2002, 2001, and 2000

Part II. Item 8.

232

      Selected Financial Data - Five-Year Comparison

Part II. Item 6.

233

   System Energy Resources, Inc.

   

      Management's Financial Discussion and Analysis

Part II. Item 7.

234

         Results of Operations

 

234

         Liquidity and Capital Resources

 

235

         Significant Factors and Known Trends

 

237

         Critical Accounting Estimates

 

238

      Independent Auditors' Report

 

242

      Income Statements For the Years Ended December 31, 2002, 2001,
        and 2000

Part II. Item 8.

243

      Statements of Cash Flows For the Years Ended December 31, 2002,
        2001, and 2000

Part II. Item 8.

245

      Balance Sheets, December 31, 2002 and 2001

Part II. Item 8.

246

      Statements of Retained Earnings for the Years Ended December 31,
        2002, 2001, and 2000

Part II. Item 8.

248

      Selected Financial Data - Five-Year Comparison

Part II. Item 6.

249

Notes to Respective Financial Statements

Part II. Item 8.

250

Properties

Part I. Item 2.

304

Legal Proceedings

Part I. Item 3.

304

Submission of Matters to a Vote of Security Holders

Part I. Item 4.

304

Directors and Executive Officers of Entergy Corporation

Part III. Item 10.

304

Market for Registrants' Common Equity and Related Stockholder Matters

Part II. Item 5.

307

Selected Financial Data

Part II. Item 6.

308

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

Part II. Item 7.

308

Quantitative and Qualitative Disclosures About Market Risk

Part II. Item 7A.

309

Financial Statements and Supplementary Data

Part II. Item 8.

309

Changes in and Disagreements with Accountants on Accounting and Financial
   Disclosure

Part II. Item 9.

309

Directors and Executive Officers of the Domestic Utility Companies and
   System Energy

Part III. Item 10.

310

Executive Compensation

Part III. Item 11.

313

Security Ownership of Certain Beneficial Owners and Management

Part III. Item 12.

325

Certain Relationships and Related Transactions

Part III. Item 13.

328

Controls and Procedures

Part IV. Item 14

329

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

Part IV. Item 15.

329

Signatures

 

330

Certifications

 

337

Independent Auditors' Consents

 

346

Independent Auditors' Report on Financial Statement Schedules

 

347

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. Item 1 is marked by a header to indicate where it applies only to Entergy Corporation and where it applies to one or more of 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.

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 the Entergy New Orleans rate case and various performance-based rate discussions, and other regulatory decisions, including those related to Entergy's 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 factor at its nuclear generating facilities
    • prices for power generated by Entergy's unregulated generating facilities - particularly the ability to extend or replace the existing power purchase agreements for 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 electricity, natural gas, and other energy-related commodities
    • 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
    • volatility and changes in markets for electricity, natural gas, 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 SeTrans or another regional transmission organization
    • changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown of Indian Point or other nuclear generating facilities
    • changes in environmental, tax, and other laws, including requirements for reduced emissions of sulfur, nitrogen, carbon, 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 taxes
    • the effects of litigation
    • changes in accounting standards
    • changes in corporate governance and securities law requirements and
    • 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

ADEQ

Arkansas Department of Environmental Quality

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

APB

Accounting Principles Board

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

CitiPower

CitiPower Pty., an electric distribution company serving Melbourne, Australia and surrounding suburbs, which was sold by Entergy effective December 31, 1998

City Council or Council

Council of the City of New Orleans, Louisiana

DOE

United States Department of Energy

domestic utility companies

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

EITF

Emerging Issues Task Force

electricity marketed

Total physical GWh volumes marketed in the U.S. 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

Entergy

Entergy Corporation and its various direct and indirect subsidiaries

Entergy Corporation

Entergy Corporation, a Delaware corporation

Entergy Gulf States

Entergy Gulf States, Inc., including its wholly owned subsidiaries - Varibus Corporation, GSG&T, Inc., Prudential Oil & Gas, Inc., and Southern Gulf Railway Company

Entergy-Koch

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

EPA

United States Environmental Protection Agency

EWO

Entergy Wholesale Operations, which primarily consists of Entergy's power development business

FASB

Financial Accounting Standards Board

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

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 volume of physical gas purchased plus volume of physical gas sold by Entergy-Koch in the U.S. denominated in billions of cubic feet per day

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

GGART

Grand Gulf Accelerated Recovery Tariff

DEFINITIONS (Continued)

Abbreviation or Acronym Term

Grand Gulf 1

Unit 1 of Grand Gulf Steam Electric Generating Station (nuclear), 90% owned or leased by System Energy

GWh

Gigawatt hours, 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, 970 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, 980 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-hours

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-hours

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

NRC

Nuclear Regulatory Commission

Pilgrim

Pilgrim Nuclear Station, 670 MW facility located in Plymouth, Massachusetts, purchased in July 1999 from Boston Edison by Entergy's Non-Utility Nuclear business

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

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)

RTO

Regional transmission organization

SEC

Securities and Exchange Commission

DEFINITIONS (Concluded)

Abbreviation or Acronym Term

SFAS

Statement of Financial Accounting Standards, 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

throughput

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

UK

The United Kingdom of Great Britain and Northern Ireland

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 weather deviations from normal

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 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 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 had annual revenues of over $8 billion in 2002 and more than 15,000 employees as of December 31, 2002.

                    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 is primarily focused on selling electric power produced by those plants to wholesale customers.
    • Energy Commodity Services is focused almost exclusively on providing energy commodity trading and gas transportation and storage services through Entergy-Koch, L.P. Energy Commodity Services also includes Entergy's non-nuclear wholesale asset business.

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

2002

2001

2000

2002

2001

2000

2002

2001

2000

                   

U.S. Utility

82

77

74

97 

77 

87 

78 

78

81

Non-Utility Nuclear

14

8

3

32 

17 

17 

13

9

Energy Commodity Services

4

14

23

(23)

14 

9

10

Parent & Other

-

1

-

(6)

(8)

(2)

(3)

-

-

The net income figures in 2002 include a $238 million net of tax charge in the Energy Commodity Services segment. If this charge were excluded, the percentages would be 70% for U.S. Utility, 23% for Non-Utility Nuclear, 11% for Energy Commodity Services, and (4%) for Parent & Other.

                Entergy's business has traditionally operated primarily through its regulated utility subsidiaries in its four-state service territory. Entergy has reshaped its non-utility business through the sale of its international electric distribution businesses in 1998, the growth of its non-utility nuclear business in the northeastern United States beginning in 1999, and the termination of its greenfield power development business in 2002. With the start of the Entergy-Koch 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 four of the eight members of the general partner's board of directors. Operating decisions for Entergy-Koch are made by Entergy-Koch management.

                The following shows the principal subsidiaries 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.

                The following is a brief summary of Entergy's business segments. More detailed information on each of Entergy's businesses can be found in the U.S. Utility, Non-Utility Nuclear, and Energy Commodity Services sections, including certain business segment financial information.

                The U.S. Utility is Entergy's predominant business segment, with five wholly-owned 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 primarily 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 that owns or leases 90 percent of Grand Gulf 1. System Energy sells all the power and capacity from Grand Gulf 1 at wholesale to four of the domestic utility companies. As a registered public utility holding company under the Public Utility Holding Company Act of 1935, Entergy and its subsidiaries are subject to the broad regulatory provisions of PUHCA. Rates and other activities of the domestic utility companies are each regulated by state utility commissions, or in the case of Entergy New Orleans, the City Council. System Energy is regulated by the FERC as all of its transactions are at the wholesale level. Entergy's U.S. Utility continues to operate as a regulated monopoly as efforts toward deregulation in the jurisdictions it serves have either been delayed, abandoned, or not yet initiated.

                The primary objective of the U.S. Utility is to provide reliable and cost-effective electricity and gas service while creating a work 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. The overall generation portfolio of the U.S. Utility, which is primarily made up of natural gas and nuclear generation, is consistent with Entergy's strong support for environmental stewardship.

                The Non-Utility Nuclear business and Energy Commodity Services are referred to as Entergy's competitive businesses. These businesses, unlike the U.S. Utility, are not subject to cost-based rate regulation by state or local utility commissions. Primary oversight for these operations comes from the NRC and the FERC.

                Entergy's Non-Utility Nuclear business is focused on acquiring, owning, operating, and selling power from nuclear power plants and providing operations and management services to nuclear power plants owned by other utilities in the United States. Non-Utility Nuclear sells all of its power to wholesale customers. Operations and management services, including decommissioning services, are provided through Entergy's wholly-owned subsidiary, Entergy Nuclear, Inc.

                Entergy's Non-Utility Nuclear business currently owns assets located in the northeastern portion of the United States as shown on the map below:

 

 

 

 

 

 

                The Energy Commodity Services segment includes the operations of Entergy-Koch (50% owned by Entergy) and Entergy's non-nuclear wholesale asset business. Entergy-Koch is engaged in two major businesses: energy commodity marketing and trading that includes power, gas, weather derivatives, emissions, and cross-commodities through Entergy-Koch Trading and gas transportation and storage through Gulf South Pipeline. Entergy's non-nuclear wholesale asset business owns and operates power plants capable of generating about 1,400 MW of electricity for sale in the wholesale market.

Strategy and Performance

                Entergy's strategy is to create value by focusing on asset management and strong operational execution, with a particular emphasis on service reliability and nuclear excellence.  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.

                The following graph compares the performance of Entergy common stock to the S&P 500 Index and Philadelphia Utility Index (each of which includes Entergy) for the last five years:

 

 

 

Years ended December 31,

1997

1998

1999

2000

2001

2002

Entergy

$100

$109.62

$94.45

$161.91

$154.58

$185.90

S&P 500 (2)

$100

$128.58

$155.63

$141.46

$124.66

$97.12

Philadelphia Utility Index (2)

$100

$117.63

$96.96

$145.91

$126.89

$103.61

  1. Assumes $100 invested at the closing price on December 31, 1997, in Entergy common stock, the S&P 500, and the Philadelphia Utility Index, and reinvestment of all dividends.
  2. Cumulative total returns calculated from the S&P 500 Index and Philadelphia Utility Index maintained by Standard & Poor's Corporation.

                Selected Entergy financial data obtained from Entergy's consolidated financial statements for the past three years is reflected on the charts below.

                A more detailed discussion of Entergy's operations is set forth below in "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS."

 

Significant Business Issues

Rate Regulation and Fuel-Cost Recovery

               
The rates that the domestic utility companies and System Energy charge for their services are a very important item influencing Entergy's financial position, results of operations, and liquidity. See Rate Regulation and Fuel-Cost Recovery in "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS" and "Rate Matters" in Part I, Item 1 for discussion of this issue.

 

Utility Restructuring

 

                Utility restructuring in Entergy's retail service territories has either been delayed, abandoned, or not pursued; however, major changes are occurring in the wholesale and retail electric utility business, including in the transmission business. See Utility Restructuring in "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS" for discussion of these issues.

 

Nuclear Matters

 

                The domestic utility companies, System Energy, and the Non-Utility Nuclear subsidiaries own and operate, through affiliates, ten nuclear power plants. See Nuclear Matters in "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS" for discussion of the risks inherent in owning and operating nuclear power plants.

 

Price of Power Sales

 

                The sale of capacity and energy from the power generation plants owned by the Non-Utility Nuclear business and the non-nuclear wholesale asset business is subject to fluctuations in the market price for power. See Market and Credit Risks in "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS" for a discussion of the market risk associated with these businesses.

 

Energy Trading

 

                Entergy owns a 50% interest in Entergy-Koch. Entergy-Koch, through its Entergy-Koch Trading subsidiary, buys and sells natural gas, power, and other energy-related services and commodities, including weather derivatives. Prices of these commodities may fluctuate over relatively short periods of time and expose Entergy-Koch to commodity price risk. See Market and Credit Risks in "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS" for a discussion of the market risk associated with the energy trading business.

 

Financing

 

                Entergy relies on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements and refinancing not satisfied by the cash flow from its operations. See Liquidity and Capital Resources in "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS" for a discussion of these matters.

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, a significant portion of which originates in Louisiana, Mississippi, and Texas. Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment in these states poses a significant business risk. See "Litigation" below in Part I, Item 1 for additional discussion of significant litigation involving Entergy.

 

Other Regulation

                In addition to the regulation of rates that the domestic utility companies and System Energy charge for sales of electric power, there are three additional primary areas of regulation: federal regulation of the utility business, regulation of nuclear power, and environmental regulation. The regulation of nuclear power and environmental regulation are discussed in detail in the description of the U.S. Utility Business and Non-Utility Nuclear Business sections of Part I, Item 1.

PUHCA

                The Public Utility Holding Company Act of 1935, as amended, regulates companies like Entergy Corporation that serve as holding companies to domestic operating utilities. Some of the more significant impacts of PUHCA are that it:

    • limits the operations of a registered holding company system to a single, integrated public utility system, plus related systems and businesses;
    • regulates transactions among affiliates within a holding company system;
    • governs the issuance, acquisition, and disposition of securities and assets by registered holding companies and their subsidiaries;
    • limits the entry by registered holding companies and their subsidiaries into businesses other than electric and/or gas utility businesses; and
    • requires SEC approval for certain utility mergers and acquisitions.

                Entergy continues to support the broad industry effort to pass legislation in the United States Congress to repeal PUHCA and transfer certain aspects of the oversight of public utility holding companies from the SEC to FERC. Entergy believes that PUHCA inhibits its ability to compete in the evolving electric energy marketplace and largely duplicates the oversight activities otherwise performed by FERC, other federal regulators, and state and local regulators. In June 1995, the SEC adopted a report proposing options for the repeal or significant modification of PUHCA, which it continues to support.

Federal Power Act

                The Federal Power Act regulates:

    • the transmission and wholesale sale of electric energy in interstate commerce;
    • the licensing of certain hydroelectric projects; and
    • certain other activities, including accounting policies and practices of electric and gas utilities.

                The Federal Power Act gives FERC jurisdiction over the rates charged by System Energy for Grand Gulf 1 capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over some of the rates charged by Entergy Arkansas and Entergy Gulf States. FERC also regulates the rates charged for intrasystem sales pursuant to the System Agreement.

                Entergy Arkansas holds a FERC license for two hydroelectric projects totaling 70 MW of capacity that was to expire on February 28, 2003. In December 2002, FERC issued an order approving Entergy Arkansas' application to renew the license for these two facilities. The license gives Entergy Arkansas permission to operate the projects for another 50 years.

 

Employees

                Employees are an integral part of Entergy's commitment to serving its customers. As of December 31, 2002, Entergy employed 15,601 people.

                Approximately 5,100 employees are represented by the International Brotherhood of Electrical Workers Union, the Utility Workers Union of America, and the International Brotherhood of Teamsters Union.

___________________________________________________________________________________________

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

                Entergy's internet address is www.entergy.com. Entergy's annual report on Form 10-K for the year ended December 31, 2002, 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 web site, 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 shareholder that requests it.

Part I, Item 1 is continued on page 97.

 

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 Directors who are not employees of Entergy, meets with the independent 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 Committee also meets periodically with the independent auditors and the chief internal auditor without management, providing free access to the Committee.

                Independent public accountants provide an objective assessment of the degree to which management meets its responsibility for fairness of financial reporting. They 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.

                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

C. JOHN WILDER
Executive Vice President and Chief Financial Officer of Entergy Corporation and System Energy Resources, Inc.

   
   

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.

JERRY W. YELVERTON
Chairman, President, and Chief Executive Officer of System Energy Resources, Inc.

   
   
 

THEODORE H. BUNTING, JR.
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 is primarily focused on selling electric power produced by those plants to wholesale customers.
    • Energy Commodity Services is focused almost exclusively on providing energy commodity trading and gas transportation and storage services through Entergy-Koch, L.P. Energy Commodity Services also includes Entergy's non-nuclear wholesale assets business.

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:

Segment

% of Revenue

% of Net Income

% of Total Assets

 

2002

2001

2000

2002 (1)

2001

2000

2002

2001

2000

U.S. Utility

82

77

74

97 

77 

87 

78 

78

81

Non-Utility Nuclear

14

8

3

32 

17 

17 

13

9

Energy Commodity Services

4

14

23

(23)

14 

9

10

Parent & Other

-

1

-

(6)

(8)

(2)

(3)

-

-

(1) The net income figures in 2002 include a $238 million net of tax charge in the Energy Commodity Services segment. If this charge were excluded, the percentages would be 70% for U.S. Utility, 23% for Non-Utility Nuclear, 11% for Energy Commodity Services, and (4%) for Parent & Other.

Results of Operations

                Earnings applicable to common stock for the years ended December 31, 2002, 2001, and 2000 by operating segment are as follows:

                

                Results 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.

                Entergy's income before taxes is discussed according to the business segments listed above. See Note 12 to the consolidated financial statements for further discussion of Entergy's business segments and their financial results in 2002, 2001, and 2000.

                Refer to "SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC., ENTERGY GULF STATES, INC. AND SUBSIDIARIES, ENTERGY LOUISIANA, INC., ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., AND SYSTEM ENERGY RESOURCES, INC." which accompany each company's financial statements in this report for further information with respect to operating statistics.

U.S. Utility

                The increase in earnings for the U.S. Utility in 2002 from $550 million to $583 million was primarily due to a decrease in interest charges combined with an increase in other income, partially offset by decreases in operating income and interest income.

                The decrease in earnings for the U.S. Utility in 2001 from $587 million to $550 million was primarily due to a decrease in operating income and increased interest charges, partially offset by an increase in interest income.

Operating Income

2002 Compared to 2001

                Operating income decreased by $43.6 million in 2002 primarily due to:

    • an increase in other operation and maintenance expenses of $273.2 million. $159.9 million of this increase is offset in other regulatory credits and relates to a March 2002 settlement agreement and 2001 earnings review 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 previously-collected transition cost account (TCA) amounts. The remaining increase in other operation and maintenance expenses is explained below; and
    • an increase in depreciation and amortization expenses of $105.7 million primarily due to the effects in 2001 of the final FERC order addressing System Energy's 1995 rate filing.

Partially offsetting these decreases in operating income were the following:

    • increased revenues of $155.7 million due to increased electricity usage in the service territories;
    • an increase in revenue of $94.3 million due to an increase in the price applied to unbilled sales; and
    • an increase in other regulatory credits of $121.3 million primarily due to a March 2002 settlement agreement allowing Entergy Arkansas to recover a large majority of 2000 and 2001 ice storm repair expenses through the previously-collected TCA amounts. This increase is offset in other operation and maintenance expenses.

                In addition to the effect of the March 2002 settlement agreement, 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.

                Fuel recovery mechanisms at the domestic utility companies generally provide for the deferral of fuel and purchased power costs above the amounts included in existing rates. 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. Also contributing to the decrease in fuel cost recovery revenue was a lower fuel recovery surcharge in 2002 in the Texas jurisdiction of Entergy Gulf States.

2001 Compared to 2000

                Operating income decreased $125.6 million in 2001 primarily due to:

    • decreased revenues of $161.9 million due to decreased electricity usage in the service territories;
    • a decrease in revenue of $161.7 million due to a decrease in the price applied to unbilled sales; and
    • the accrual of $26.8 million in the transition cost account at Entergy Arkansas.

Partially offsetting these decreases in operating income were the following:

    • a decrease in other operation and maintenance expenses of $95.6 million, which is explained below;
    • a decrease in depreciation and amortization expense at System Energy of $74.5 million primarily resulting from the final resolution of its 1995 rate filing; and
    • a decrease in decommissioning expense at System Energy of $32.4 million resulting from the final resolution of the FERC order addressing the 1995 rate increase filing.

                The decrease in other operation and maintenance expenses in 2001 was primarily due to:

    • a decrease in property damage expenses of $49.7 million primarily due to a reversal of $24.5 million in June 2001, upon recommendation from the APSC, of ice storm costs previously charged to expense in December 2000. The effect of the reversal of the ice storm costs on net income was largely offset by the adjustment to the transition cost account as a result of the 2000 earnings review in 2001;
    • decreases in expenses of $9.3 million at Entergy Arkansas due to decreased transition to competition support costs and $11.0 million at Entergy Louisiana due to decreased legal fees; and
    • decreases of $10.7 million and $14.6 million at Entergy Louisiana and Entergy Mississippi, respectively, because of maintenance and planned maintenance outages at certain fossil plants in 2000.

                Operating revenues include an increase in fuel cost recovery revenue of $462.7 million related to electric sales primarily due to increased fuel recovery factors at Entergy Arkansas, Entergy Gulf States in the Texas jurisdiction, and Entergy Mississippi, combined with higher fuel and purchased power costs recovered through fuel recovery mechanisms at Entergy Gulf States in the Louisiana jurisdiction and Entergy New Orleans due to the increased market prices of natural gas and purchased power early in 2001. As such, this revenue increase is offset by increased fuel and purchased power expenses.

Other Impacts on Results of Operations

2002 Compared to 2001

                Results for the year ended December 31, 2002 for U.S. Utility were also affected by the following:

    • a decrease in interest income of $56.5 million, which is explained below;
    • an increase in "miscellaneous - net" in other income 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; and
    • a decrease in interest charges of $111.0 million, which is explained below.

                The decrease in interest income in 2002 was 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 that were not being recovered through rates; and
    • lower interest earned on declining deferred fuel balances.

                The decrease in interest charges in 2002 is 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 reserve for rate refund in 2001. The refund was made in December 2001.

2001 Compared to 2000

                Results for the year ended December 31, 2001 for U.S. Utility were also affected by an increase in interest charges of $61.5 million primarily due to:

    • the final FERC order addressing the 1995 System Energy rate filing;
    • debt issued at Entergy Arkansas in July 2001, at Entergy Gulf States in June 2000 and August 2001, at Entergy Mississippi in January 2001, and at Entergy New Orleans in July 2000 and February 2001; and
    • borrowings under credit facilities during 2001, primarily at Entergy Arkansas.

Non-Utility Nuclear

                The increase in earnings in 2002 for Non-Utility Nuclear from $128 million to $201 million was primarily due to the operation of Indian Point 2 and Vermont Yankee, which were purchased in September 2001 and July 2002, respectively.

                The increase in earnings in 2001 for Non-Utility Nuclear from $49 million to $128 million was primarily due to the operation of FitzPatrick and Indian Point 3 for a full year, as each was purchased in November 2000, and the operation of Indian Point 2, which was purchased in September 2001.

                Following are key performance measures for Non-Utility Nuclear:

 2002 

 2001 

 2000 

Net MW in operation at December 31

3,955

3,445

2,475

Generation in GWh for the year

29,953

22,614

7,171

Capacity factor for the year

93%

93%

94%

2002 Compared to 2001

                The following fluctuations in the results of operations for Non-Utility Nuclear in 2002 were primarily caused by the acquisitions of Indian Point 2 and Vermont Yankee (except as otherwise noted):

    • operating revenues increased $411.0 million to $1.2 billion;
    • other operation and maintenance expenses increased $201.8 million to $596.3 million;
    • depreciation and amortization expenses increased $25.1 million to $42.8 million;
    • fuel expenses increased $29.4 million to $105.2 million;
    • nuclear refueling outage expenses increased $23.9 million to $46.8 million, which was due primarily to a full year of amortization of Pilgrim and Indian Point 3 expenses;
    • interest income increased $17.2 million to $71.3 million; and
    • interest expense increased $12.1 million to $93.3 million.

2001 Compared to 2000

                The following fluctuations in the results of operations for Non-Utility Nuclear in 2001 were primarily caused by the acquisition of FitzPatrick, Indian Point 3, and Indian Point 2:

    • operating revenues increased $491.1 million to $789.2 million;
    • other operation and maintenance expenses increased $217.6 million to $394.5 million;
    • interest expense, primarily related to debt incurred to purchase the plants, increased $47.9 million to $81.1 million;
    • fuel expenses increased $51.0 million to $75.8 million; and
    • taxes other than income taxes increased $30.9 million to $40.1 million.

Energy Commodity Services

                The decrease in earnings for Energy Commodity Services in 2002 from $106 million to a $146 million loss was primarily due to the impairment charges that are discussed below.

                The increase in earnings for Energy Commodity Services in 2001 from $55 million to $106 million was primarily due to the strong performance of the trading and gas pipeline businesses of Entergy-Koch.

2002 Compared to 2001

                The decrease in earnings for Energy Commodity Services in 2002 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 an after-tax gain 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 is 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 below 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.

Following are key performance measures for Entergy-Koch's operations for 2002 and 2001:

2002

2001

Entergy-Koch Trading

   Gas volatility

61%

72%

   Electricity volatility

48%

78%

   Gas marketed (BCF/D) (1)

5.8

3.0

   Electricity marketed (GWh) (1)

408,038

180,893

   Gain/loss days

1.8

2.8

Gulf South Pipeline

   Throughput (BCF/D)

2.40

2.45

   Production cost ($/MMBtu)

$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.

Entergy accounts for its 50% share in Entergy-Koch under the equity method of accounting. Certain terms of the partnership arrangement allocate 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 2002. Effective January 1, 2004, a revaluation of Entergy-Koch's assets for legal capital account purposes will occur, and future profit allocations will change after the revaluation. The profit allocations other than for weather trading and international trading are expected to become equal, unless special allocations are necessary to equalize the partners' legal capital accounts. Profit allocations for weather trading and international trading remain disproportionate to the ownership interests. Earnings allocated under the terms of the partnership agreement constitute equity, not subject to reallocation, for the partners.

2001 Compared to 2000

                The increase in earnings for Energy Commodity Services in 2001 was primarily due to:

    • the gain on the sale of the Saltend plant discussed below;
    • the favorable results from Entergy-Koch discussed below;
    • the $33.5 million ($23.5 million net of tax) cumulative effect of an accounting change marking to market the Damhead Creek gas contract;
    • liquidated damages of $13.9 million ($9.7 million net of tax) received in 2001 from the Damhead Creek construction contractor as compensation for lost operating margin from the plant due to construction delays; and
    • a $12.2 million ($7.9 million net of tax) gain on the sale of a permitted site in Desoto County, Florida, in May 2001.

                Partially offsetting the increase in earnings for Energy Commodity Services in 2001 was the following:

    • $60.1 million ($49.9 million net of tax) of losses or asset impairments recorded on Latin American investments and other development projects;
    • a $9.8 million ($6.4 million net of tax) loss recorded primarily because of the pending cancellation of four gas turbines scheduled for delivery in 2004;
    • liquidated damages of $55.1 million ($38.6 million net of tax) received in 2000 from the Saltend contractor as compensation for lost operating margin from the plant due to construction delays;
    • a $19.7 million ($12.8 million net of tax) gain on the sale of the Freestone project located in Fairfield, Texas, in June 2000;
    • increased depreciation expense of $23.6 million in 2001, primarily due to the commencement of the commercial operation of the Saltend and Damhead Creek plants; and
    • increased interest expense of $78.7 million in 2001, primarily because of the commencement of commercial operation of the Saltend and Damhead Creek plants.

                Revenues decreased for Energy Commodity Services by $983.3 million in 2001, primarily due to the contribution of substantially all of Entergy's power marketing and trading business to Entergy-Koch in 2001. As a result, in 2001, revenues from this activity were lower by $1,957.0 million compared to 2000 revenue for Entergy's power marketing and trading segment, and purchased power expenses were lower by $1,830.0 million. The net income effect in 2001 of the lower revenue was more than offset by the equity in earnings from Entergy's interest in Entergy-Koch. Entergy's earnings from this activity increased in 2001 as a result of increased electricity and gas trading volumes as well as a broader range of commodity sources and options provided to customers by the joint venture than provided previously by Entergy.

                The decrease in revenues in 2001 was partially offset by an increase in operating revenues primarily due to an increase of $409.8 million from Highland Energy and an increase of $450.1 million from the Saltend and Damhead Creek plants. Highland Energy was acquired in June 2000, and the Saltend and Damhead Creek plants began commercial operation in late November 2000 and early 2001, respectively. Highland Energy was sold in the fourth quarter of 2001. The increase in revenues from Highland Energy, Damhead Creek, and Saltend is largely offset by increased fuel and purchased power expenses of $644.1 million and increased other operation and maintenance expenses of $94.6 million.

                Entergy sold the Saltend plant in August 2001 and revenues include the $88.1 million ($57.2 million net of tax) gain on the sale.

Parent & Other

                The loss from Parent & Other decreased in 2002 from $58 million to $39 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.

                The loss from Parent & Other increased in 2001 from $11 million to $58 million primarily due to:

    • a decrease in interest income of $41.2 million;
    • $21.8 million ($14.1 million net of tax) of merger-related expenses incurred by Entergy Corporation in the first quarter of 2001; and
    • an increase in interest charges of $19.5 million.

The increased loss in 2001 was partially offset by the write-down in 2000 of investments in Latin American projects to their estimated fair values.

Income Taxes

                The effective income tax rates for 2002, 2001, and 2000 were 32.1%, 38.3%, and 40.3%, 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 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.

2002

2001

2000

Net debt to net capital at the end of the year

46.3%

49.7%

49.8%

Net debt consists of gross debt less cash and cash equivalents. Gross debt consists of notes payable, capital lease obligations, and long-term debt, including the currently maturing portion. Net capital consists of net debt, common shareholders' equity, and preferred stock and securities.

                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, 2002 by operating segment. These figures 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 (in millions)

2003

2004

2005

2006-2007

after 2007

U. S. Utility

$1,111

$855

$470

$466

$3,751

Non-Utility Nuclear

$87

$91

$95

$205

$205

Energy Commodity Services

$79

-

-

-

-

Parent and Other

-

$595

-

-

$267

                In the fourth quarter of 2002, the U.S. Utility issued $640 million of debt with maturities ranging from 2007 to 2032. Approximately $71 million of the proceeds of the debt issued in the fourth quarter were used to retire, in 2002, debt that was scheduled to mature in 2003, and the remainder will be used to meet certain 2003 maturities as they occur. Entergy Mississippi issued an additional $100 million of debt in January 2003 that matures in 2013. The proceeds will be used to repay, prior to maturity, debt of Entergy Mississippi that is scheduled to mature in 2003 and 2004. Note 7 to the consolidated financial statements provides more detail concerning long-term debt.

                The Energy Commodity Services debt was paid at maturity in January 2003 using money drawn on Entergy Corporation's 364-day credit facility.

                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:

2003

2004

2005

2006-2007

after 2007

Capital lease payments, including nuclear fuel leases (in millions)


$160


$137


$10


$9


$5

                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, 2002. 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, 2002

Entergy Corporation

 

May 2003

 

$1.450 billion

 

$535 million

Entergy Arkansas

 

May 2003

 

$63 million

 

-

Entergy Louisiana

 

May 2003

 

$15 million

 

-

Entergy Mississippi

 

May 2003

 

$25 million

 

-

Although the Entergy Corporation credit line expires in May 2003, 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 debt outstanding under the credit line is reflected in long-term debt on the balance sheet. The credit line is reflected as notes payable at December 31, 2001.

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 on noncancelable operating leases with a term over one year as of December 31, 2002:

2003

2004

2005

2006-2007

after 2007

Operating lease payments (in millions)

$98

$91

$73

$98

$140

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, 2002 total a maximum amount of $267.5 million. 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 will be 70% owned by EPV. Entergy's maximum liability on the guarantee is $232.5 million. In addition, one of the contracts transferred to Entergy-Koch by Entergy's power marketing and trading business is backed by an Entergy Corporation guarantee authorized in the amount of $35 million.

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 2003 through 2005 (in millions):

Planned construction and capital investment

2003

2004

2005

U.S. Utility

$924

$915

$965

Non-Utility Nuclear

$201

$142

$109

Energy Commodity Services

$24

$76

$3

Other

$7

$7

$9

                The capital plan for the U.S. Utility primarily consists of spending for maintenance capital, supporting continued reliability improvements, and customer growth. Also included is the replacement of the ANO 1 steam generator and reactor vessel closure head. Entergy estimates the cost of the fabrication and replacement 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 steam generator for ANO 2. Receipt of an order relating to the replacement at ANO 1 would provide additional support for the inclusion of these costs in a future general rate case; however, management cannot predict the outcome of either the request for a declaratory order or a general rate proceeding.

                The capital plan for Non-Utility Nuclear primarily consists of spending for maintenance capital. Entergy also includes some spending for power uprate projects in the estimate.

                The capital plan for Energy Commodity Services primarily consists of Entergy's obligation to make a $73 million cash contribution to Entergy-Koch in January 2004. The completion of the Harrison County project is also included in the plan. The plant has been under construction since 2001. Entergy will own approximately 385 MW once construction is completed and operation has begun, which Entergy expects to occur in June 2003.

                The planned construction and capital investments do not include potential investments in new businesses or assets. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of business restructuring, regulatory constraints, business opportunities, market volatility, economic trends, and the ability to access capital.

Dividends and Stock Repurchases

                Declarations of dividends on Entergy's common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy's common stock dividends based upon Entergy's earnings, financial strength, and future investment opportunities. At its October 2002 meeting, the Board increased Entergy's quarterly dividend per share by 6%, to $0.35. In 2002, Entergy paid $299 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. In order to reduce the potential increase in outstanding common shares created by the exercise of stock options, Entergy plans to purchase up to 10 million shares of its common stock through mid-2004 on a discretionary basis through open market purchases or privately negotiated transactions. Entergy repurchased 2,885,000 shares of common stock for a total purchase price of $118.5 million in 2002.

System Energy Letters of Credit

                System Energy had three-year letters of credit in place that were scheduled to expire in March 2003 securing certain of its obligations related to the sales/leaseback of a portion of Grand Gulf 1. System Energy replaced the letters of credit with new three-year letters of credit totaling approximately $192 million that are backed by cash collateral. System Energy used approximately $192 million in March 2003 to provide this cash collateral.

PUHCA Restrictions on Uses of Capital

                Entergy's ability to invest in domestic and foreign generation businesses is subject to the SEC's regulations under PUHCA. As authorized by the SEC, Entergy is allowed to invest an amount equal to 100% of its average consolidated retained earnings in domestic and foreign generation businesses. As of December 31, 2002, Entergy's investments subject to this rule totaled $1.97 billion constituting 52.5% 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.

                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, 2002 was approximately $1.8 billion.

Sources of Capital

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

    • internally generated funds, which have been the source of the majority of Entergy's capital;
    • cash on hand ($1.3 billion as of December 31, 2002);
    • 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, 2002, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $296.1 million and $36.2 million, respectively. Additionally, PUHCA prohibits Entergy Corporation's subsidiaries from making loans or advances to Entergy Corporation.

                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. In addition, this order restricts Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, or System Energy from issuing long-term debt unless that debt will be rated as investment grade. 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, 2002, 2001, and 2000 were as follows:

2002

2001

2000

(In Millions)

Cash and cash equivalents at beginning of period

$ 752 

$ 1,382 

$ 1,214 

Cash flow provided by (used in):

   Operating activities

2,181 

2,216 

1,968 

   Investing activities

(1,388)

(2,224)

(1,814)

   Financing activities

(213)

(622)

20 

Effect of exchange rates on cash and cash equivalents

          3 

          - 

        (6)

Net increase (decrease) in cash and cash equivalents

      583 

    (630)

     168 

Cash and cash equivalents at end of period

$ 1,335 

$ 752 

$ 1,382 

Operating Cash Flow Activity

2002 Compared to 2001

                Entergy's cash flow provided by operating activities decreased slightly 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 is retaining capital for business opportunities.
    • The non-nuclear wholesale asset business provided $43 million in operating cash flow in 2002, compared to using $73 million in 2001.

2001 Compared to 2000

                Entergy's consolidated net cash flow provided by operating activities increased in 2001 primarily due to:

    • An increase of $432 million in cash provided by the parent company primarily due to the tax accounting election made by Entergy Louisiana that is discussed below and the receipt of a federal tax refund associated primarily with deductions for 2000 ice storm costs, partially offset by increased interest expense and the payment of FPL merger-related costs.
    • An increase of $171 million in cash provided by the Non-Utility Nuclear business, primarily from the operation of the FitzPatrick and Indian Point 3 plants purchased in the fourth quarter of 2000 and the Indian Point 2 plant purchased in the third quarter of 2001.

                These increases were partially offset by a decrease of $129 million in cash provided by the U.S. Utility and net cash used of $128 million in 2001 compared to net cash provided of $64.3 million in 2000 by the Energy Commodity Services segment. The Energy Commodity Services segment includes the non-nuclear wholesale assets business and the Entergy-Koch joint venture. In 2001, the non-nuclear wholesale assets business used $73 million of net cash in operating activities; in 2000, the non-nuclear wholesale assets business provided $37 million of operating cash flow. This fluctuation is primarily due to a net loss, excluding the gain on the sale of the Saltend plant, generated in 2001 compared with net income generated in 2000. Entergy's investment in Entergy-Koch used $55 million of net cash in operating activities in 2001 compared with power marketing and trading providing $27 million of operating cash flow in 2000. This fluctuation is primarily because, although income from this activity was higher in 2001, Entergy did not receive dividends from Entergy-Koch, as the joint venture retained capital for business opportunities.

Entergy Louisiana 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 $867 million through 2002, which is expected to reverse in the years 2003 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: 2002-12 and 2013-31. During the first eight years of the 2002-12 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 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 2013-2031, Entergy Louisiana and its ratepayers would share the remaining benefits of this tax accounting election.

Investing Activities

2002 Compared to 2001

                Net cash used in investing activities decreased by $836 million 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 510 MW Vermont Yankee nuclear power plant for $180 million in cash. In September 2001, Entergy's Non-Utility Nuclear business purchased the 970 MW 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 did not make an investment in 2002 like the $272 million cash investment it made in 2001 to provide collateral for a line of credit that secures the installment obligations owed to NYPA for the acquisition of the FitzPatrick and Indian Point 3 nuclear power plants. As of December 31, 2002, $232 million remained invested as collateral for the line of credit.
    • 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 results 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.

2001 Compared to 2000

                Net cash used in investing activities increased by $410 million in 2001 primarily due to:

    • Entergy used $550 million more cash in its 2001 nuclear power plant purchase than it used in its 2000 nuclear power plant purchase. In September 2001, Entergy's Non-Utility Nuclear business purchased the 970 MW Indian Point 2 nuclear power plant for $600 million in cash. In 2000, Entergy paid $50 million cash and issued notes payable of approximately $750 million to NYPA to purchase the 980 MW Indian Point 3 and 825 MW FitzPatrick nuclear power plants.
    • Entergy made cash contributions of approximately $414 million in connection with the formation of Entergy-Koch in 2001.
    • Entergy made a $272 million cash investment in 2001 to provide collateral for a line of credit that secures the installment obligations it owes to NYPA for the acquisition of the FitzPatrick and Indian Point 3 nuclear power plants.
    • Entergy used $150 million to invest in temporary investments with a maturity of greater than 90 days in 2001.

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

    • Entergy received approximately $810 million in cash from the sale of the Saltend plant in August 2001.
    • Entergy spent less on construction due to completion of the Saltend and Damhead Creek plants.
    • The recovery of deferred fuel costs incurred at certain of the domestic utility companies increased in 2001. Entergy Arkansas, the Texas portion of Entergy Gulf States, and Entergy Mississippi for 2000 only, have treated these costs as regulatory investments because these companies are allowed by their regulatory jurisdictions to recover the accumulated fuel cost regulatory asset over longer than a twelve-month period. Entergy Mississippi's fuel recovery mechanism changed effective January 2001, and Entergy Mississippi's fuel cost under-recoveries incurred after that date are being recovered over less than a twelve-month period. The companies will recover carrying charges on the under-recovered balances.

Financing Activities

2002 Compared to 2001

                Financing activities used $409 million less cash in 2002 than in 2001 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.

2001 Compared to 2000

                Financing activities used cash in 2001 compared to providing a small amount of cash in 2000 primarily due to:

    • The $555 million retirement of the Saltend credit facility in August 2001 when the plant was sold.
    • A higher amount of net issuances of debt by the U.S. Utility in 2000 than in 2001.
    • No additional borrowings in 2001 under the Saltend and Damhead Creek credit facilities due to the completion of the construction of the plants in 2000. In 2000, borrowings under the Damhead Creek credit facility increased by approximately $164 million to finance construction of the plant
    • A reduction in the amount of debt outstanding on the Entergy Corporation credit facility.

Partially offsetting the increase in cash used in 2001 were the following:

    • Decreased repurchases of Entergy's common stock in 2001.
    • The redemption of Entergy Gulf States' preference stock in 2000.

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.

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, which is currently not expected to occur until at least the first quarter of 2004.

Entergy Gulf
  States-Louisiana

11.1%

The LPSC approved a settlement in December 2002 resolving the 4th - 8th post-merger earnings reviews resulting in a $22.1 million prospective rate reduction effective January 2003 and a refund of $16.3 million. Also, the 9th earnings analysis (2002), the last required post-merger earnings analysis, and prospective revenue study are currently pending before the LPSC with hearings set for October 2003. In conjunction with the LPSC staff, Entergy Gulf States is currently pursuing a formula rate plan proposal.

Entergy Louisiana

9.7%-

11.3%(1)

The LPSC approved a settlement in July 2002 covering the 5th and 6th annual rate reviews and future rate regulation that included a small rate reduction and reaffirmed the ROE midpoint of 10.5%. Entergy Louisiana's current rates will remain in effect until changed pursuant to a new formula rate plan filing or revenue analysis to be filed by June 30, 2003. In conjunction with the LPSC staff, Entergy Louisiana is currently pursuing a formula rate plan proposal.

Entergy Mississippi

10.64%-

12.86%(2)

An annual formula rate plan is in place. In December 2002, the MPSC approved a joint stipulation that resulted in a $48.2 million rate increase and an ROE midpoint of 11.75%. Entergy Mississippi will make its next formula rate plan filing in March 2004.

Entergy New
 
Orleans

11.4%

Rate case filed with the City Council in May 2002 requesting a rate increase of $44 million. An agreement in principle reached in March 2003 with the Advisors to the City Council would result in a $30 million base rate increase, if approved by the City Council.  A decision is expected in mid-2003

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% of the overage, and if below, increased by 60% of the shortfall.
  2. If Entergy Mississippi earns outside of the bandwidth range, rates will be adjusted on a prospective basis. If earnings are above the bandwidth range, rates are reduced by 50% of the overage, and if below, increased by 50% of the shortfall. The range presented is not adjusted for performance measures, under which the ROE midpoint can increase or decrease by as much as 1%.

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

                The domestic utility companies have historically 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 FERC. Litigation involving the System Agreement has been initiated by the LPSC and City Council. 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. Entergy believes that any changes in the allocation of costs would not have a material effect on Entergy's financial condition because any changes should result in similar rate changes for retail customers. Entergy further believes that state and local regulators are pre-empted by federal law from reviewing and deciding System Agreement issues for themselves. An unrelated case currently pending between the LPSC and Entergy Louisiana raises the question 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 January 2003, the U.S. Supreme Court granted Entergy Louisiana's request for a writ of certiorari for purposes of reviewing the decision of the LPSC and the Louisiana Supreme Court. Entergy cannot predict the timing or outcome of these proceedings.

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 Entergy's Non-Utility Nuclear business' and Energy Commodity Services' output that is currently sold forward under physical or financial contracts at fixed prices:

2003

 

2004

 

2005

 

2006

 

2007

Non-Utility Nuclear:

 

 

 

 

 

 

 

 

 

% of planned generation sold forward

100%

 

92%

 

25%

 

11%

 

9%

Planned generation (GWh)

33,317

 

33,361

 

34,006

 

34,613

 

34,300

Average price per MWh

$37.06

 

$38.36

 

$35.94

 

$31.97

 

$31.42

Energy Commodity Services:

 

 

 

 

 

 

 

 

 

% of planned generation sold forward

38%

 

18%

 

22%

 

19%

 

21%

Planned generation (GWh)

3,124

 

3,249

 

3,820

 

3,494

 

3,618

Contracted spark spread per MWh

$11.70

 

$10.63

 

$10.62

 

$9.69

 

$9.68

                The Vermont Yankee acquisition included a 10-year PPA under which the former owners will buy the power produced by the plant, which is through the expiration of the current operating license for the plant. The PPA includes an adjustment clause under which the prices specified in the PPA will be adjusted downward annually, beginning in 2006, if power market prices drop below the PPA prices. Accordingly, because the price is not fixed, the table above does not report power from that plant as sold forward after 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.

                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:

 

 

2002

 

2001

 

 

 

 

 

 

 

DE@R at end of period

 

$15.2 million

 

$5.5 million

 

Average DE@R for the period

 

$10.8 million

 

$6.4 million

 

                EKT's 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, 2002 approximately 86% 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, 2002



2003



2004



2005 - 2006



Total

 

 

 

(In Millions)

 

 

 

Prices actively quoted

 

$45.0  

 

$45.1

 

($20.2)

 

$69.9 

Prices provided by other sources

24.4  

3.3

1.9 

29.6 

Prices based on models

 

 (13.3)

 

   1.3

 

     3.4 

 

   (8.6)

Total

 

$56.1 

 

$49.7

 

($14.9)

 

$90.9 

                Following is a roll-forward of the change in the fair value of EKT's mark-to-market contracts during 2002 (in millions):

 

 

 

2002

Fair value of contracts at December 31, 2001

 

$106 

Fair value of contracts settled during the year

 

(347)

Initial recorded value of new contracts entered into during the year

 

Net option premiums received during the year

 

(78)

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

 

        403 

Net change in contracts outstanding during the year

 

        (15)

Fair value of contracts at December 31, 2002

$91 

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 249.5 million Euro and the forward currency rates range from .8624 to .9664. The maturities of these forward contracts depend on the purchase contract payment dates and range in time from January 2003 to January 2007. The mark-to-market valuation of the forward contracts at December 31, 2002 was a net asset of $38.9 million. The counterparty banks obligated on 233.0 million Euro of the notional amount of these agreements are rated by Standard & Poor's Rating Services at AA on their senior debt obligations as of December 31, 2002. The counterparty bank obligated on 16.5 million Euro of the notional amount of these agreements is rated by Standard & Poor's Rating Services at A+ on its senior debt obligations as of December 31, 2002.

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 the financial results of operations for the ANO, 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 $841 million of fixed-rate, fixed-income securities as of December 31, 2002. These securities have an average coupon rate of approximately 6.0%, an average duration of approximately 5.2 years, and an average maturity of approximately 8.3 years. The Pilgrim, Indian Point 1 and 2, and Vermont Yankee trust funds also collectively hold equity securities worth approximately $358 million as of December 31, 2002. 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 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

                Major changes are occurring in the wholesale and retail electric utility business, including in the electric transmission business. In Entergy's U.S. Utility service territory, movement to retail competition either has not occurred, has been significantly delayed, or has been abandoned. 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 (price 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 electric utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations). These organizations were to be operational by December 15, 2001, but delays have occurred as utility companies and federal and state regulators work to resolve various issues related to the establishment of RTOs.

                Entergy's domestic utility companies are participating with other transmission owners within the southeastern United States to establish an RTO, the proposed SeTrans RTO. In October 2002, FERC issued a declaratory order approving certain central aspects of the SeTrans RTO proposal. Because of retail regulatory concerns regarding RTOs, certain retail regulators ordered the domestic utility companies to evaluate the costs and benefits associated with establishing such entities. The Southeastern Association of Regulatory Utility Commissions commissioned a separate cost-benefit study that was intended to evaluate similar issues for the entire Southeast, including the region that would be covered by the proposed SeTrans RTO. Both cost-benefit studies concluded that an RTO, if properly structured (e.g., locational marginal prices to manage congestion, participant funding for expansion cost), can provide benefits for the customers of the domestic utility companies. However, a number of important issues relating to the design of the transmission tariffs and the terms of the proposed SeTrans RTO remain to be finalized and approved by regulators. Until this process is complete, Entergy cannot predict the impact that RTO developments will have on its financial condition, results of operations, or liquidity. Entergy does not expect the SeTrans RTO to become operational before the end of 2004.

Retail

                Only in the Texas portion of Entergy Gulf States' service territory has there been significant retail open access activity, but implementation has been delayed in that territory. Entergy does not expect that retail open access within the context of a functional FERC-approved RTO is likely to begin for Entergy Gulf States before the end of 2004. Entergy Gulf States has recently filed a proposal with the PUCT for an interim solution to begin retail open access on January 1, 2004, or otherwise delay retail open access until at least 2007. While the PUCT has approved a basic business separation plan for Entergy Gulf States in Texas, 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 needed to comply with Texas, Louisiana, and federal law and may therefore have an adverse effect on Entergy. Retail open access legislation has not been enacted in the other jurisdictions in Entergy's service territory, except for in Arkansas, where it was recently repealed.

Nuclear Matters

                The domestic utility companies, System Energy, and Non-Utility Nuclear subsidiaries own and operate, through affiliates, ten nuclear power generating units. 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 legal 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 safety. 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 has petitioned the United States Court of Appeals for the Second Circuit for review of this final action of the NRC. In order to prevail, Riverkeeper must show that the NRC has violated the Atomic Energy Act, abused its discretion, and has completely abdicated its statutory duty regarding this matter. Entergy believes that the action of the NRC was based upon a thorough and thoughtful review of the law and the facts and that the NRC decision will be affirmed by the court.

 

                In addition, certain concerns are being raised regarding the adequacy of the emergency response 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 response plans for Indian Point are in compliance with NRC requirements and thus adequately protect public health and safety.

 

                A January 2003 consultant's draft report prepared for the State of New York to review emergency preparedness around Indian Point concluded generically that federal emergency planning regulations and guidelines were not adequate to cope with new threats of terrorism. This conclusion was based in part on the view that radiation releases, including those caused by terrorist events, could be faster and larger than those for which the emergency plans were designed. As a result, even if emergency planning for Indian Point were to comply fully with all federal regulations and guidelines, this criticism in the report would stand. There were other plant-specific criticisms in the report. For these reasons, the report concluded that emergency planning for Indian Point is not adequate at this time. In March 2003, a final report was issued which reached similar conclusions. The NRC in reacting to the draft report observed that current emergency plans are already designed to cope with significant radiation releases regardless of cause and stated that it was reviewing the draft report's findings to determine if the emergency plans require modification.

 

                A February 2003, report issued by FEMA Region II evaluated a September 2002 exercise and related activities for the ten-mile emergency planning zone around Indian Point. The report identified no deficiencies with respect to the exercise. The report did conclude that in the absence of corrected and updated state and county plans, FEMA could not provide "reasonable assurance" that appropriate measures can be taken in the event of a radiological emergency. If the state provided this information and a schedule of corrective actions by May 2, 2003, the report stated that FEMA would reevaluate this decision. If corrective actions are not taken, FEMA Region II indicated that (a) it would notify FEMA headquarters that assurance cannot be provided regarding the adequacy of the plans to protect the health and safety of the public and (b) FEMA headquarters would notify the NRC and Governor of New York of the same. The notice from FEMA to the NRC would begin corrective action periods. If corrective action were not taken by the end of these periods, the NRC must determine whether there is reasonable assurance regarding the adequacy of plans to protect the health and safety of the public. If the NRC determines that there is not such assurance, it has the authority to order the Indian Point plants to shut down.

 

                Entergy is interacting with New York state and county officials, FEMA, NRC and other federal agencies to make additional improvements to the emergency response plans that may be warranted and to further assure them as to the adequacy of the plans. Entergy will vigorously oppose all attempts to shut down the Indian Point plants.

 

                The Westchester County Executive announced his proposal to acquire Indian Point by purchase or condemnation and has announced an intention to commission a feasibility study regarding municipalization of Indian Point. At this time, considering the financial and legal impediments that the County would face in implementing this proposal, it is improbable that the County could condemn or municipalize Indian Point.

 

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, a significant portion of which originates in Louisiana, Mississippi, and Texas. Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment in these states poses a significant business risk.

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:

                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 unit follow.

U.S. Utility

                Entergy collects substantially all of the projected costs of decommissioning the nuclear facilities in its U.S. Utility business unit 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. Accordingly, U.S. Utility decommissioning costs have no impact on Entergy's earnings, as accrued costs are offset by earnings on trust funds and collections from customers. 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.

                In the U.S. Utility business unit, the obligations recorded by Entergy for decommissioning are classified either as a component of accumulated depreciation (ANO 1 and 2, Waterford 3, and the regulated portion of River Bend) or as a deferred credit (System Energy and the nonregulated portion of River Bend) in the line item entitled "Decommissioning." The amounts recorded for these obligations are comprised of collections from customers and earnings on the trust funds. The classification and recording of these obligations will change with the implementation of SFAS 143, which is discussed in more detail below.

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. Upon purchase of the plants, Entergy recorded obligations that were equivalent to the amounts initially received in the decommissioning trust funds. These obligations are recorded as deferred credits in the line item entitled "Decommissioning." These obligations are accreted at implicit discount rates that are determined based upon the estimated costs of decommissioning. The accounting for these obligations will change with the implementation of SFAS 143, which is discussed in more detail below.

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 outlined above will change 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 will cause 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 increases cost estimates.

    • Discount rate - SFAS 143 requires that these obligations be discounted using a credit-adjusted, risk-free rate. This will result 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 of implementing this standard, to the extent that it was not recorded as regulatory assets or liabilities, will be recognized as a cumulative effect of an accounting change in Entergy's 2003 statement of income. Implementation will have the following effect on Entergy's financial statements:

    • The net effect of implementing this standard for the rate-regulated business of the domestic utility companies and System Energy will be recorded as regulatory assets or liabilities, with no resulting impact on Entergy's net income. Assets and liabilities are expected to increase 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 as determined under SFAS 143 and recording the related regulatory assets and liabilities. The implementation of SFAS 143 for the portion of River Bend not subject to cost-based ratemaking is expected to decrease earnings by approximately $25 million as a result of a one-time cumulative effect of accounting change.

    • For the Non-Utility Nuclear business, the implementation of SFAS 143 is expected to result in a decrease in liabilities in 2003 of approximately $520 million as a result of the discounting methodology required by SFAS 143. Assets are expected to decrease in 2003 by approximately $360 million. Earnings are expected to increase by approximately $160 million as a result of a one-time cumulative effect of accounting change.

Also Entergy expects 2003 earnings for the Non-Utility Nuclear business to increase by approximately $15 million after-tax over the current level because of the change in accretion of the liability and depreciation of the associated costs. This effect will gradually decrease over future years.

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.

                The carrying value of Entergy's nonregulated portions of River Bend and Grand Gulf approximates $1.2 billion at December 31, 2002. To date, Entergy's impairment tests have not required an impairment to be recorded for these assets.

                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

                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 or energy trading contracts under EITF 98-10. 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 or energy trading contracts, 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., 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. 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.

                In addition, the EITF reached a consensus to rescind Issue No. 98-10 effective January 1, 2003. Rescinding Issue No. 98-10 will result 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 will be 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 will be accounted for using accrual accounting. Energy commodity inventories held by trading companies such as physical natural gas will be accounted for at the lower of cost or market. The adoption of the consensus will have minimal cumulative and ongoing earnings effects for Entergy's Energy Commodity Services business.

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 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 2000 and 2001 to 6.75% in 2002. 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 rates from a range in 2001 of 8% gradually decreasing to 5% to a range in 2002 of 10% gradually decreasing to 4.5%.

                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 plan assets of roughly 65% equity securities and 35% fixed income securities. Based on recent market trends, Entergy decreased its expected long-term rate of return on plan assets from 9% in 2000 and 2001 to 8.75% for 2002. The trend of reduced inflation caused Entergy to reduce its assumed rate of increase in future compensation levels from 4.6% in 2000 and 2001 to 3.25% in 2002.

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 2002
Pension Cost

 

Impact on Projected Benefit Obligation

 

 

Increase/(Decrease)

Discount rate

 

(0.25%)

 

$3,043

 

$70,313

Rate of return on plan assets

 

(0.25%)

 

$4,335

 

-

Rate of increase in compensation

 

0.25%

 

$2,376

 

$15,556

                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 2002 Postretirement Benefit Cost

 

Impact on Accumulated Postretirement Benefit Obligation

 

 

Increase/(Decrease)

Health care cost trend

 

0.25%

 

$3,379

 

$20,900

Discount rate

 

(0.25%)

 

$2,105

 

$24,348

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 2002, Entergy's total pension cost was $38 million and funding was $13 million. Taking into account asset performance and the changes made in the actuarial assumptions, Entergy does not anticipate 2003 pension cost to be materially different from 2002. Pension funding for 2003 is anticipated to be $39 million.

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

                Total postretirement health care and life insurance benefit costs for Entergy in 2002 were $81 million. Because of a number of factors, including the increased health care cost trend rate, Entergy expects 2003 costs to approximate $108 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

  2002 2001 2000 1999 1998(1)
  (In Thousands, Except Percentages and Per Share Amounts)

Operating revenues

$ 8,305,035

$ 9,620,899

$ 10,022,129

$ 8,765,635

$11,494,772

Income before cumulative
  effect of accounting change


$ 623,072


$ 727,025


$ 710,915


$ 595,026


$ 785,629

Earnings per share before
  cumulative effect of accounting
  change
     Basic
     Diluted
 

 


$ 2.69
$ 2.64

 


$ 3.18
$ 3.13

 


$ 3.00
$ 2.97

 


$ 2.25
$ 2.25

 


$ 3.00
$ 3.00

Dividends declared per share

$ 1.34

$ 1.28

$ 1.22

$ 1.20

$ 1.50

Return on average common equity

7.85%

10.04%

9.62%

7.77%

10.71%

Book value per share, year-end

$ 35.24

$ 33.78

$ 31.89

$ 29.78

$ 28.82

Total assets

$26,947,969

$25,910,311

$ 25,451,896

$22,969,940

$22,836,694

Long-term obligations (2)

$ 7,482,269

$ 7,743,298

$ 8,214,724

$ 7,252,697

$ 7,349,349

 

 

 

 

 

 

(1) Includes the effects of the sales of London Electricity and CitiPower in December 1998.

(2) 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.

  1. 1998 includes the effect of a reserve for rate refund at Entergy Gulf States. 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, 2002 and 2001, 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, 2002. These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with 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 provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Corporation and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, Entergy Corporation adopted the provisions of Statement of Financial Accounting Standards No. 142 "Goodwill and Other Intangible Assets" in 2002 and Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities" in 2001.

 

 

 

DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 21, 2003

 

 

 

 

 

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                   ENTERGY CORPORATION AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME
                                               
                                                              For the Years Ended December 31,
                                                              2002          2001        2000
                                                             (In Thousands, Except Share Data)
                  OPERATING REVENUES                                                            
Domestic electric                                           $6,646,414   $7,244,827   $7,219,686
Natural gas                                                    125,353      185,902      165,872
Competitive businesses                                       1,533,268    2,190,170    2,636,571
                                                            ----------   ----------   ----------
TOTAL                                                        8,305,035    9,620,899   10,022,129
                                                            ----------   ----------   ----------
                                                                                                
                  OPERATING EXPENSES                                                            
Operating and Maintenance:                                                                      
   Fuel, fuel-related expenses, and                                                             
     gas purchased for resale                                2,154,596    3,681,677    2,645,835
   Purchased power                                             832,334    1,021,432    2,662,881
   Nuclear refueling outage expenses                           105,592       89,145       70,511
   Provision for turbine commitments, asset impairments
     and restructuring charges                                 428,456            -            -
   Other operation and maintenance                           2,488,112    2,151,742    1,943,814
Decommissioning                                                 30,458        3,189       39,484
Taxes other than income taxes                                  380,462      399,849      370,344
Depreciation and amortization                                  839,181      721,033      746,125
Other regulatory charges (credits) - net                      (141,836)     (20,510)      34,073
                                                            ----------   ----------   ----------
TOTAL                                                        7,117,355    8,047,557    8,513,067
                                                            ----------   ----------   ----------
                                                                                                
OPERATING INCOME                                             1,187,680    1,573,342    1,509,062
                                                            ----------   ----------   ----------
                                                                                                
                     OTHER INCOME                                                               
Allowance for equity funds used during construction             31,658       26,209       32,022
Gain on sale of assets - net                                     6,612        5,226        2,340
Interest and dividend income                                   118,325      159,805      163,050
Equity in earnings of unconsolidated equity affiliates         183,878      162,882       13,715
Miscellaneous - net                                              7,280       (4,769)      27,077
                                                            ----------   ----------   ----------
TOTAL                                                          347,753      349,353      238,204
                                                            ----------   ----------   ----------
                                                                                                
              INTEREST AND OTHER CHARGES                                                        
Interest on long-term debt                                     507,604      544,920      477,071
Other interest - net                                           116,519      197,638       85,635
Distributions on preferred securities of subsidiaries           18,838       18,838       18,838
Allowance for borrowed funds used during construction          (24,538)     (21,419)     (24,114)
                                                            ----------   ----------   ----------
TOTAL                                                          618,423      739,977      557,430
                                                            ----------   ----------   ----------
                                                                                                
INCOME BEFORE INCOME TAXES AND                                                                  
CUMULATIVE EFFECT OF ACCOUNTING CHANGE                         917,010    1,182,718    1,189,836
                                                                                                
Income taxes                                                   293,938      455,693      478,921
                                                            ----------   ----------   ----------
                                                                                                
INCOME BEFORE CUMULATIVE EFFECT                                                                 
OF ACCOUNTING CHANGE                                           623,072      727,025      710,915
                                                                                                
CUMULATIVE EFFECT OF ACCOUNTING                                                                 
CHANGE (net of income taxes of $10,064)                              -       23,482            -
                                                            ----------   ----------   ----------
                                                                                                
CONSOLIDATED NET INCOME                                        623,072      750,507      710,915
                                                                                                
Preferred dividend requirements and other                       23,712       24,311       31,621
                                                            ----------   ----------   ----------
                                                                                                
EARNINGS APPLICABLE TO                                                                          
COMMON STOCK                                                  $599,360     $726,196     $679,294
                                                            ==========   ==========   ==========
Earnings per average common share before cumulative                                   
effect of accounting change:                                                                    
    Basic                                                        $2.69        $3.18        $3.00
    Diluted                                                      $2.64        $3.13        $2.97
Earnings per average common share:                                                              
    Basic                                                        $2.69        $3.29        $3.00
    Diluted                                                      $2.64        $3.23        $2.97
Dividends declared per common share                              $1.34        $1.28        $1.22
Average number of common shares outstanding:                                                    
    Basic                                                  223,047,431  220,944,270  226,580,449
    Diluted                                                227,303,103  224,733,662  228,541,307
                                                                                                
See Notes to Consolidated Financial Statements.                                                 
                                                 

                   ENTERGY CORPORATION AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                  
                                                                                      For the Years Ended December 31,
                                                                                        2002          2001          2000
                                                                                                 (In Thousands)
                              OPERATING ACTIVITIES                                                                        
Consolidated net income                                                               $623,072      $750,507      $710,915
Noncash items included in net income:                                                                                     
  Reserve for regulatory adjustments                                                    18,848      (359,199)       18,482
  Other regulatory charges (credits) - net                                            (141,836)      (20,510)       34,073
  Depreciation, amortization, and decommissioning                                      869,638       724,222       785,609
  Deferred income taxes and investment tax credits                                    (256,664)       87,752       124,457
  Allowance for equity funds used during construction                                  (31,658)      (26,209)      (32,022)
  Cumulative effect of accounting change                                                     -       (23,482)            -
  Gain on sale of assets - net                                                          (6,612)       (5,226)       (2,340)
  Equity in undistributed earnings of subsidiaries and unconsolidated affiliates      (181,878)     (150,799)      (13,715)
  Provision for turbine commitments and asset impairments                              428,456             -             -
 Changes in working capital (net of effects from acquisitions and dispositions):                                    
  Receivables                                                                          (43,957)      302,230      (437,146)
  Fuel inventory                                                                         1,030        (3,419)      (20,447)
  Accounts payable                                                                     286,230      (415,160)      543,606
  Taxes accrued                                                                        462,956       486,676        20,871
  Interest accrued                                                                       7,209        17,287        45,789
  Deferred fuel                                                                        156,181       495,007       (38,001)
  Other working capital accounts                                                      (286,232)      (39,978)      102,336
Provision for estimated losses and reserves                                             10,533        19,093         6,019
Changes in other regulatory assets                                                      71,132       119,215       (66,903)
Other                                                                                  195,255       257,541       186,264
                                                                                    ----------    ----------    ----------
Net cash flow provided by operating activities                                       2,181,703     2,215,548     1,967,847
                                                                                    ----------    ----------    ----------
                                                                                                                          
                               INVESTING ACTIVITIES                                                                       
Construction/capital expenditures                                                   (1,530,301)   (1,380,417)   (1,493,717)
Allowance for equity funds used during construction                                     31,658        26,209        32,022
Nuclear fuel purchases                                                                (250,309)     (130,670)     (121,127)
Proceeds from sale/leaseback of nuclear fuel                                           183,664        71,964       117,154
Proceeds from sale of assets and businesses                                            215,088       784,282        61,519
Investment in nonutility properties                                                   (216,956)     (647,015)     (222,119)
Decrease (increase) in other investments                                                38,964      (631,975)      (15,943)
Changes in other temporary investments - net                                           150,000      (150,000)      321,351
Decommissioning trust contributions and realized change in trust assets                (84,914)      (95,571)      (63,805)
Other regulatory investments                                                           (39,390)       (3,460)     (385,331)
Other                                                                                  114,033       (68,067)      (44,016)
                                                                                    ----------    ----------    ----------
Net cash flow used in investing activities                                          (1,388,463)   (2,224,720)   (1,814,012)
                                                                                    ----------    ----------    ----------
                                                                                                                          
See Notes to Consolidated Financial Statements.                                                                           
                                                                                                                          
                                                                                                                          
                                                                                                                          
                                                                                                                          
                                                                                                                        
                                                                                                                          
                                                                                                                          
                                                                                                                          
                      ENTERGY CORPORATION AND SUBSIDIARIES                                                          
                     CONSOLIDATED STATEMENTS OF CASH FLOWS                                                          
                                                                                                                    
                                                                                        For the Years Ended December 31,
                                                                                        2002          2001          2000
                                                                                                (In Thousands)
                              FINANCING ACTIVITIES                                                                  
Proceeds from the issuance of:                                                                                            
  Long-term debt                                                                     1,197,330       682,402       904,522
  Common stock                                                                         130,061        64,345        41,908
Retirement of long-term debt                                                        (1,341,274)     (962,112)     (181,329)
Repurchase of common stock                                                            (118,499)      (36,895)     (550,206)
Redemption of preferred stock                                                           (1,858)      (39,574)     (157,658)
Changes in short-term borrowings - net                                                 244,333       (37,004)      267,000
Dividends paid:                                                                                                           
  Common stock                                                                        (298,991)     (269,122)     (271,019)
  Preferred stock                                                                      (23,712)      (24,044)      (32,400)
                                                                                    ----------    ----------    ----------
Net cash flow provided by (used in) financing activities                              (212,610)     (622,004)       20,818
                                                                                    ----------    ----------    ----------
                                                                                                                          
Effect of exchange rates on cash and cash equivalents                                    3,125           325        (5,948)
                                                                                    ----------    ----------    ----------
                                                                                                                          
Net increase (decrease) in cash and cash equivalents                                   583,755      (630,851)      168,705
                                                                                                                          
Cash and cash equivalents at beginning of period                                       751,573     1,382,424     1,213,719
                                                                                    ----------    ----------    ----------
                                                                                                                          
Cash and cash equivalents at end of period                                          $1,335,328      $751,573    $1,382,424
                                                                                    ==========    ==========    ==========
                                                                                                                          
                                                                                                                          
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:                                    
  Cash paid (received) during the period for:                                                                             
    Interest - net of amount capitalized                                              $633,931      $708,748      $505,414
    Income taxes                                                                       $57,856     ($113,466)     $345,361
  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             -
    Change in unrealized depreciation of                                                                                  
       decommissioning trust assets                                                   ($72,982)     ($34,517)     ($11,577)
    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             -
    Acquisition of Indian Point 3 and FitzPatrick                                                                         
       Fair value of assets acquired                                                         -             -      $917,667
       Initial cash paid at closing                                                          -             -       $50,000
       Liabilities assumed and notes issued to seller                                        -             -      $867,667
                                                                                                                          
 See Notes to Consolidated Financial Statements.                                                                          
                                                                                                                          


                     ENTERGY CORPORATION AND SUBSIDIARIES
                          CONSOLIDATED BALANCE SHEETS                       
                                     ASSETS                                 
                                                     
                                                     
                                                                              December 31,
                                                                           2002          2001
                                                                             (In Thousands)
                         CURRENT ASSETS                                                        
Cash and cash equivalents:                                                                     
  Cash                                                                   $169,788      $129,866
  Temporary cash investments - at cost,                                                        
   which approximates market                                            1,165,260       618,327
  Special deposits                                                            280         3,380
                                                                      -----------   -----------
     Total cash and cash equivalents                                    1,335,328       751,573
                                                                      -----------   -----------
Other temporary investments                                                     -       150,000
Notes receivable                                                            2,078         2,137
Accounts receivable:                                                                           
  Customer                                                                323,215       294,799
  Allowance for doubtful accounts                                         (27,285)      (28,355)
  Other                                                                   244,621       295,771
  Accrued unbilled revenues                                               319,133       268,680
                                                                      -----------   -----------
     Total receivables                                                    859,684       830,895
                                                                      -----------   -----------
Deferred fuel costs                                                        55,653       172,444
Accumulated deferred income taxes                                               -         6,488
Fuel inventory - at average cost                                           96,467        97,497
Materials and supplies - at average cost                                  525,900       460,644
Deferred nuclear refueling outage costs                                   163,646        79,755
Prepayments and other                                                     166,827       205,097
                                                                      -----------   -----------
TOTAL                                                                   3,205,583     2,756,530
                                                                      -----------   -----------
                                                                                               
                 OTHER PROPERTY AND INVESTMENTS                                                
Investment in affiliates - at equity                                      824,209       766,103
Decommissioning trust funds                                             2,069,198     1,775,950
Non-utility property - at cost (less accumulated depreciation)            297,294       295,616
Other                                                                     270,889       495,542
                                                                      -----------   -----------
TOTAL                                                                   3,461,590     3,333,211
                                                                      -----------   -----------
                                                                                               
                 PROPERTY, PLANT AND EQUIPMENT                                                 
Electric                                                               26,789,538    26,359,676
Property under capital lease                                              746,624       753,310
Natural gas                                                               209,969       201,841
Construction work in progress                                           1,232,891       882,829
Nuclear fuel under capital lease                                          259,433       265,464
Nuclear fuel                                                              263,609       232,387
                                                                      -----------   -----------
TOTAL PROPERTY, PLANT AND EQUIPMENT                                    29,502,064    28,695,507
Less - accumulated depreciation and amortization                       12,307,112    11,805,578
                                                                      -----------   -----------
PROPERTY, PLANT AND EQUIPMENT - NET                                    17,194,952    16,889,929
                                                                      -----------   -----------
                                                                                               
                DEFERRED DEBITS AND OTHER ASSETS                                               
Regulatory assets:                                                                             
  SFAS 109 regulatory asset - net                                         844,105       946,126
  Unamortized loss on reacquired debt                                     155,161       166,546
  Other regulatory assets                                                 738,328       707,439
Long-term receivables                                                      24,703        28,083
Goodwill                                                                  377,172       377,172
Other                                                                     946,375       705,275
                                                                      -----------   -----------
TOTAL                                                                   3,085,844     2,930,641
                                                                      -----------   -----------
                                                                                               
TOTAL ASSETS                                                          $26,947,969   $25,910,311
                                                                      ===========   ===========
See Notes to Consolidated Financial Statements.                                                


                    ENTERGY CORPORATION AND SUBSIDIARIES                 
                         CONSOLIDATED BALANCE SHEETS                                            
                    LIABILITIES AND SHAREHOLDERS' EQUITY                                       
                                                                                         
                                                                                         
                                                                             December 31,
                                                                          2002          2001
                                                                            (In Thousands)
                      CURRENT LIABILITIES                                                      
Currently maturing long-term debt                                      $1,191,320      $682,771
Notes payable                                                                 351       351,018

Accounts payable                                                          855,446       592,529
Customer deposits                                                         198,442       188,230
Taxes accrued                                                             385,315       550,133
Accumulated deferred income taxes                                          26,468             -
Nuclear refueling outage costs                                             14,244         2,080
Interest accrued                                                          175,440       192,420
Obligations under capital leases                                          153,822       149,352
Other                                                                     171,341       396,616
                                                                      -----------   -----------
TOTAL                                                                   3,172,189     3,105,149
                                                                      -----------   -----------
                                                                                               
             DEFERRED CREDITS AND OTHER LIABILITIES                                            
Accumulated deferred income taxes and taxes accrued                     4,250,800     3,974,664
Accumulated deferred investment tax credits                               447,925       471,090
Obligations under capital leases                                          155,943       181,085
Other regulatory liabilities                                              185,579       135,878
Decommissioning                                                         1,565,997     1,194,333
Transition to competition                                                  79,098       231,512
Regulatory reserves                                                        56,438        37,591
Accumulated provisions                                                    389,868       425,399
Other                                                                   1,145,232       801,040
                                                                      -----------   -----------
TOTAL                                                                   8,276,880     7,452,592
                                                                      -----------   -----------
                                                                                               
Long-term debt                                                          7,086,999     7,321,028
Preferred stock with sinking fund                                          24,327        26,185
Preferred stock without sinking fund                                      334,337       334,337
Company-obligated mandatorily redeemable                                                       
  preferred securities of subsidiary trusts holding                                            
  solely junior subordinated deferrable debentures                        215,000       215,000
                                                                                               
                      SHAREHOLDERS' EQUITY                                                     
Common stock, $.01 par value, authorized 500,000,000                                           
  shares; issued 248,174,087 shares in 2002 and in 2001                     2,482         2,482
Paid-in capital                                                         4,666,753     4,662,704
Retained earnings                                                       3,938,693     3,638,448
Accumulated other comprehensive loss                                      (22,360)      (88,794)
Less - treasury stock, at cost (25,752,410 shares in 2002 and                                  
  27,441,384 shares in 2001)                                              747,331       758,820
                                                                      -----------   -----------
TOTAL                                                                   7,838,237     7,456,020
                                                                      -----------   -----------
                                                                                               
Commitments and Contingencies                                                                  
                                                                                               
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                            $26,947,969   $25,910,311
                                                                      ===========   ===========
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,
                                                                   2002                      2001                   2000            
                                                                                       (In Thousands)
                   RETAINED EARNINGS                                                                                             
Retained Earnings - Beginning of period                   $3,638,448               $3,190,639              $2,786,467            
                                                                                                                                 
     Add: Earnings applicable to common stock                599,360   $599,360       726,196   $726,196      679,294    $679,294
                                                                                                                                 
     Deduct:                                                                                                                     
        Dividends declared on common stock                   299,031                  278,342                 275,929            
        Capital stock and other expenses                          84                       45                    (807)            
                                                          ----------               ----------              ----------
              Total                                          299,115                  278,387                 275,122            
                                                          ----------               ----------              ----------
                                                                                                                                 
Retained Earnings - End of period                         $3,938,693               $3,638,448              $3,190,639            
                                                          ==========               ==========              ==========   
                                                                                                                                 
                                                                                                                                 
                                                                                                                                 
                                                                                                                                 
  ACCUMULATED OTHER COMPREHENSIVE 
  INCOME (LOSS) (Net of taxes):
Balance at beginning of period:                                                                                                  
  Accumulated derivative instrument fair value changes      ($17,973)                      $-                      $-      
  Other accumulated comprehensive (loss) items               (70,821)                 (75,033)                (73,805)            
                                                          ----------               ----------              ----------
     Total                                                   (88,794)                 (75,033)                (73,805)            
                                                          ----------               ----------              ----------
                                                                                                                                 
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                                   35,286     35,286            48         48            -           -
                                                                                                                                 
Foreign currency translation adjustments                      65,948    (15,487)        4,615      4,615       (5,216)     (5,216)
                                                                                                                                 
Minimum pension liability adjustment                         (10,489)   (10,489)            -          -            -           -
                                                                                                                                 
Net unrealized investment gains (losses)                     (24,311)   (24,311)         (403)      (403)       3,988       3,988
                                                          ----------               ----------              ----------
                                                                                                                                 
Balance at end 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)      
                                                          ==========   --------    ==========   --------   ==========    --------
Comprehensive Income                                                   $584,359                 $730,456                 $678,066
                                                                       ========                 ========                 ========
                                                                                                                                 
                                                                                                                                 
                                                                                                                                 
                                                                                                                                 
                    PAID-IN CAPITAL                                                                                              
Paid-in Capital - Beginning of period                     $4,662,704               $4,660,483              $4,636,163            
                                                                                                                                 
     Add:                                                                                                                        
          Common stock issuances related to stock plans        4,049                    2,221                  24,320            
                                                          ----------               ----------              ----------
                                                                                                                
                                                                                                                    
Paid-in Capital - End of period                           $4,666,753               $4,662,704              $4,660,483
                                                          ==========               ==========              ==========
                                                                                                         
                                                                                                            
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, certain 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.

                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. System Energy's 1995 rate proceeding that was resolved in 2001 is discussed in Note 2 to the consolidated financial statements.

                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. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is 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. Effective January 2001, Entergy Mississippi's fuel factor includes an energy cost rider that is adjusted quarterly. 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.

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, plus the applicable removal costs, 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, 2002 and 2001, is shown below (in millions):

(1) This is reflected in accumulated depreciation and amortization on the balance sheet. The decommissioning liabilities related to Grand Gulf 1, Pilgrim, Indian Point 2, Vermont Yankee, and the 30% of River Bend previously owned by Cajun are reflected in the applicable balance sheets in "Deferred Credits and Other Liabilities - Decommissioning."

                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 2.9% in 2002, 2001, and 2000. Included in these rates are the depreciation rates on average depreciable utility property of 2.8% in 2002 and 2001 and 2.9% in 2000 and the depreciation rates on average depreciable non-utility property of 3.8% in 2002, 4.5% in 2001, and 3.5% in 2000.

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, 2002, 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



Depreciation

Grand Gulf

Unit 1

Nuclear

1,282

90.00%(2)

$3,587

$1,515

Independence

Units 1 and 2

Coal

1,657

47.90%

457

228

White Bluff

Units 1 and 2

Coal

1,620

57.00%

418

244

Roy S. Nelson

Unit 6

Coal

550

70.00%

404

227

Big Cajun 2

Unit 3

Coal

575

42.00%

229

119

Harrison County, Texas

 

Gas

550 (3)

70.00%

191

-

   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.

  1. 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.

  2.  
  3. Represents estimated capacity as station is under construction and has yet to perform under actual operating conditions.

Goodwill

                Entergy implemented SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002. 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. Goodwill is now subject to impairment testing. 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, 2002, 2001, and 2000:

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 accrual 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:

(1) Options to purchase approximately 109,897 and 148,500 shares of common stock at various prices were outstanding at the end of 2002 and 2001, respectively, 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. At the end of 2000, all outstanding options, totaling 11,468,316, were included in the computation of diluted earnings per share as a result of the average market price of the common shares being greater than the exercise prices.

Stock-based Compensation Plans

                Entergy has two plans that grant stock options, which are described more fully in Note 5 to the consolidated financial statements. Entergy applies 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 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. Beginning January 1, 2003, Entergy will prospectively apply the fair value based method of accounting for stock options prescribed by SFAS 123, "Accounting for Stock-Based Compensation." Entergy expects the effect of applying the fair value method to be insignificant to its results of operations. The effect is less than may be indicated by the pro forma presentation below because Entergy expects prospectively to grant fewer stock options than in recent years, and because the fair value method is being applied prospectively. 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 meet 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 of 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, 2002 and 2001, the fair value of the securities held in such funds differs from the amounts deposited plus the earnings on the deposits by ($24) million and $93 million, respectively. In accordance with the regulatory treatment for decommissioning trust funds, the domestic utility companies have recorded an offsetting amount of unrealized gains/(losses) on investment securities in accumulated depreciation. For the nonregulated portion of River Bend, Entergy Gulf States has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. System Energy's offsetting amount of unrealized gains/(losses) on investment securities is in other regulatory liabilities.

                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 as a separate 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. Entergy discontinues the recognition of losses on equity 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. The changes in the fair value of 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, if it is, the type of hedge transaction.

                For cash-flow hedge transactions in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transaction, changes in the fair value of the derivative instrument are reported in other comprehensive income. The gains and losses on the derivative instrument that are reported in other comprehensive income are reclassified as earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. The ineffective portions of all hedges are recognized in current-period earnings.

                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. 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.

                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 current year asset impairments in the Energy Commodity Services segment.

River Bend AFUDC

                The River Bend AFUDC gross-up 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 allows 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 Pronouncement

                SFAS 143, which was implemented in the first quarter of 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. These liabilities will be recorded at their fair values (which are likely to be 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 will be 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 Entergy's regulated utilities will be recorded as a regulatory asset or liability, with no resulting impact on Entergy's net income. The implementation of SFAS 143 for the portion of River Bend not subject to cost-based ratemaking is expected to decrease earnings by approximately $25 million as a result of a one-time cumulative effect of accounting change. For the Non-Utility Nuclear business, the implementation of SFAS 143 is expected to result in a decrease in liabilities of approximately $520 million as a result of the discounting methodology required by SFAS 143, assets are expected to decrease in 2003 by approximately $360 million, and earnings are expected to increase by approximately $160 million as a result of a one-time cumulative effect of accounting change.

 

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
2002 Revenues Derived from
Retail Electric Utility Operations
in the Jurisdiction

Arkansas

Retail open access legislation was repealed in February 2003.

14.5%

Texas

Implementation delayed in Entergy Gulf States' service area in a settlement approved by the PUCT. Retail open access not likely before the first quarter of 2004. Status is discussed further below.

10.4%

Louisiana

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

33.5%

Mississippi

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

10.6%

New Orleans

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

5%

                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 with 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 appears by January 15, 2003 that a FERC-approved RTO will not be functional by January 1, 2004. On January 24, 2003, Entergy Gulf States filed its proposal, which among other elements, includes:

  • 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 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 is expected to consider this proposal on March 21, 2003.

This proposal takes into account that other regulatory approvals, including that of the LPSC and the SEC, are necessary prior to January 1, 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, 2002 and 2001 (in millions).

 

 

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, 2002 and 2001 that has been or will be recovered or (refunded) through the fuel mechanisms of the domestic utility companies.

 

 

2002

2001

 

(In Millions)

Entergy Arkansas $ (42.6 )

$ 17.2 

Entergy Gulf States

$ 100.6 

$ 126.7 

Entergy Louisiana

$ (25.6 )

$ (67.5 )

Entergy Mississippi

$ 38.2 

$ 106.2 

Entergy New Orleans

$ (14.9 )

$ (10.2 )

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 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.

                As a result of reduced fuel and purchased power costs in 2001 and the accumulated over-recovery of 2001 energy costs, Entergy Arkansas decreased the energy cost rate effective April 2002. In September 2002, Entergy Arkansas filed and the APSC approved an interim revision to the energy cost rate effective October 2002 through March 2003. Entergy Arkansas reduced the energy cost rate to offset the accumulated over-recovery of energy costs through June 2002 and the projected over-recovery through December 2002. The revised energy cost rate will be effective through March 2003 when the annual energy cost rate redetermination will be filed for the period April 2003 through March 2004.

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 are 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 $91.8 million as of December 31, 2002, which includes the following:

Interim surcharge

 

$53.9 million

Items to be addressed as part of unbundling

 

$29.0 million

Imputed capacity charges

 

$ 8.6 million

Other

 

$ 0.3 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, when or if a base rate proceeding before the PUCT will be initiated. The current settlement agreement delaying retail open access in Texas requires a rate freeze during the delay period. If Entergy Gulf States goes to retail open access without a Texas base rate proceeding, it is possible that Entergy Gulf States will not be allowed to recover these imputed capacity charges.

                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 $583.0 million of fuel and purchased power costs. As part of this filing, Entergy Gulf States requested authority to collect $28.0 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 share of River Bend. No assurance can be given as to the final outcome of this proceeding.

                In September 2002, Entergy Gulf States filed an application with the PUCT for an interim surcharge to collect $53.9 million, including interest and $6.3 million from the January 2001 fuel reconciliation proceeding discussed above, of under-recovered fuel and purchased power expenses incurred from March 2002 through August 2002. The PUCT authorized collection of the amounts requested over an 11-month period beginning in February 2003. Expenses collected through this interim surcharge, with the exception of expenses already reconciled in prior proceedings, are subject to review in a future fuel reconciliation proceeding.

Entergy Gulf States, Entergy Louisiana, and Entergy New Orleans

                The Louisiana jurisdiction of Entergy Gulf States, Entergy Louisiana, and Entergy New Orleans recover electric fuel costs on a two-month lag. The Louisiana jurisdiction of Entergy Gulf States' and 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.

                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. The LPSC staff has submitted several requests for information from Entergy Louisiana, and it is expected that the LPSC staff will issue its audit report in the spring of 2003, following which a procedural schedule will be established.

                In January 2003 the LPSC opened a docket to investigate the fuel adjustment clause practices of Entergy Gulf States and its affiliates. The investigation will include a review of the reasonableness of charges flowed by Entergy Gulf States through its fuel adjustment clause in Louisiana for the period subsequent to 1994. No assurance can be given at this time as to the timing or outcome of this proceeding.

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. The deferred fuel balances as of December 31, 2002 and 2001 reflect the 24-month recovery of $136.7 million of under-recoveries that began in January 2001 as approved by the MPSC.

Retail Rate Proceedings

Filings with the APSC

March 2002 Settlement Agreement

                In May 2002, the APSC approved a settlement agreement submitted by Entergy Arkansas, the APSC staff, and the Arkansas Attorney General. Provisions of the agreement are discussed below under "Retail Rates," "Transition Cost Account," and "December 2000 Ice Storm Cost Recovery."

Retail Rates

                As discussed in "December 2000 Ice Storm Cost Recovery" below, Entergy Arkansas was scheduled to file a general rate proceeding in February 2002, in which Entergy Arkansas would have sought an increase in rates. The March 2002 settlement agreement states, however, that Entergy Arkansas will not file an application seeking to increase base rates prior to January 2003.

Transition Cost Account

                A 1997 settlement provided for the collection of earnings in excess of an 11% return on equity in a transition cost account (TCA) to offset stranded costs if retail open access were implemented. In May 2002, Entergy Arkansas filed its 2001 earnings evaluation report with the APSC. In June 2002, the APSC approved a contribution of $5.9 million to the TCA. A principal provision in the March 2002 settlement agreement was to offset $137.4 million of ice storm recovery costs with the TCA on a rate class basis. In accordance with the settlement agreement and following the APSC's approval of the 2001 earnings review, Entergy Arkansas filed to return $18.1 million of the TCA to certain large general service class customers that paid more into the TCA than their allocation of storm costs. The APSC approved the return of funds to the large general service customer class in the form of refund checks in August 2002. As part of the implementation of the March 2002 settlement agreement provisions, the TCA procedure ceased with the 2001 earnings evaluation.

December 2000 Ice Storm Cost Recovery

                In mid- and late December 2000, two separate ice storms left 226,000 and 212,500 Entergy Arkansas customers, respectively, without electric power in its service area. Entergy Arkansas filed a proposal to recover costs plus carrying charges associated with power restoration caused by the ice storms. In an order issued in June 2001, the APSC decided not to give final approval to Entergy's proposed storm cost recovery rider outside of a fully developed cost-of-service study in a general rate proceeding. The APSC action resulted in the deferral in 2001 of storm damage costs expensed in 2000 as reflected in Entergy Arkansas' financial statements.

                Entergy Arkansas filed its final storm damage cost determination, which reflected costs of approximately $195 million. In the March 2002 settlement, the parties agreed that $153 million of the ice storm costs would be classified as incremental ice storm expenses that can be offset against the TCA, and any excess of ice storm costs over the amount available in the TCA would be deferred and amortized over 30 years, although such excess costs were not allowed to be included as a separate component of rate base. The allocated ice storm expenses exceeded the available TCA funds by $15.8 million and was recorded as a regulatory asset in June 2002. Of the remaining ice storm costs, $32.2 million will be addressed through established ratemaking procedures, including $22.2 million classified as capital additions. $3.8 million of the ice storm costs will not be recovered through rates.

Filings with the PUCT and Texas Cities

Retail Rates

                Entergy Gulf States is operating in Texas under the terms of a June 1999 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 in a subsequent settlement 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 has appealed this ruling to the Third District Court of Appeals. The Court of Appeals heard oral argument in November 2002 but has not yet issued a final decision. The financial statement impact of the retail rate settlement agreement on the remaining abeyed plant costs will ultimately depend on several factors, including the possible discontinuance of SFAS 71 accounting treatment for the Texas generation business, the determination of the market value of generation assets, and any future legislation in Texas addressing the pass-through or sharing of any stranded benefits with Texas ratepayers. While Entergy Gulf States expects to prevail in its lawsuit, no assurance can be given that additional reserves or write-offs will not be required in the future.

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 relating to remaining issues that arose in 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. The filing also contained a prospective revenue requirement study based on the 2001 test year that shows that a prospective rate increase of approximately $21.7 million would be appropriate. Both components of the filing are subject to review by the LPSC and may result in changes in rates other than those sought in the filing. A procedural schedule has been adopted and hearings are scheduled for October 2003.

Formula Rate Plan Filings (Entergy Louisiana)

                In July 2002, the LPSC approved a settlement between Entergy Louisiana and the LPSC Staff in Entergy Louisiana's 2000 and 2001 formula rate plan proceedings. Entergy Louisiana agreed to a $5 million rate reduction effective August 2001. The prospective rate reduction was implemented beginning in August 2002 and the refund for the retroactive period occurred in September 2002. As part of the settlement, Entergy Louisiana's current rates, including its previously authorized ROE midpoint of 10.5%, remain in effect until changed pursuant to a new formula rate plan filing or a revenue requirement analysis to be filed by June 30, 2003.

                In May 1997, Entergy Louisiana made its second annual performance-based formula rate plan filing with the LPSC for the 1996 test year. This filing resulted in a rate reduction of approximately $54.5 million, which was implemented in July 1997. At the same time, rates were reduced by an additional $0.7 million and by an additional $2.9 million effective March 1998. Upon completion of the hearing process in December 1998, the LPSC issued an order requiring an additional rate reduction and refund based upon the LPSC's contention that it could interpret and enforce a FERC rate schedule. The resulting amounts were not quantified, although they are expected to be immaterial. Entergy Louisiana appealed this order and obtained a preliminary injunction pending a final decision on appeal. The Louisiana Supreme Court rendered a non-unanimous decision in April 2002 affirming the LPSC's order. Entergy Louisiana filed with the U.S. Supreme Court an application for writ of certiorari, which application was supported by an amicus curiae brief filed on behalf of the United States of America by the Solicitor General and the General Counsel and Solicitor for the FERC. The U.S. Supreme Court granted certiorari in January 2003, and the case will be argued during the last week of April 2003.

Filings with the MPSC

Formula Rate Plan Filings

                Pursuant to Entergy Mississippi's annual performance-based formula rate plan filing for the 2001 test year, the MPSC approved a stipulation between the Mississippi Public Utilities Staff and Entergy Mississippi. The stipulation provided for a $1.95 million rate increase effective in May 2002.

                In August 2002, Entergy Mississippi filed a rate case with the MPSC requesting a $68.8 million rate increase effective January 2003. Entergy Mississippi requested this increase as a result of capital investments and operation and maintenance expenditures necessary to replace and maintain aging electric facilities and to improve reliability and customer service. 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 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 the order, Entergy Mississippi will make its next formula rate plan filing during March 2004.

Filings with the Council

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 exists and that a $28.9 million electric rate increase and a $15.3 million gas rate increase are appropriate. Additionally, Entergy New Orleans has proposed a $6.0 million public benefit fund. The City Council has established a procedural schedule for consideration of the filing and hearings are scheduled to begin in May 2003. The procedural schedule provides for the City Council's decision with respect to Entergy New Orleans' filing by June 15, 2003.   On March 13, 2003, Entergy New Orleans and the Advisors to the City Council presented to the City Council an agreement in principle that, if approved by the City Council, would resolve the proceeding.  The agreement in principle, if approved by the City Council, would result in a $30.2 million base rate increase for Entergy New Orleans.  A procedural schedule for the City Council's consideration of the agreement in principle has not been established.  Entergy New Orleans' rates will remain at their current level until the earlier of a decision in the proceeding or June 15, 2003.

Natural Gas

                In a resolution adopted in August 2001, the City Council ordered Entergy New Orleans to account for $36 million of certain natural gas costs charged to its gas distribution customers from July 1997 through May 2001. The resolution suggests that refunds may be due to the gas distribution customers if Entergy New Orleans cannot account satisfactorily for these costs. Entergy New Orleans filed a response to the City Council in September 2001, which is still being evaluated by the City Council. Entergy New Orleans has documented a full reconciliation for the natural gas costs during that period. Entergy New Orleans has filed for a hearing on this matter. The presentation made to the City Council on March 13, 2003 regarding the agreement in principle that would resolve Entergy New Orleans' rate proceeding also included proposed terms for resolution of this proceeding, if approved by the City Council.  A procedural schedule for consideration of the agreement has not been established.  The ultimate outcome of the proceeding cannot be predicted at this time.

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. At present, the suit in state court is stayed by stipulation of the parties.

                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 in April 2000 and has been supplemented. The testimony, as supplemented, asserts, 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. In June 2001, the City Council's advisors filed testimony on these issues in which they allege that Entergy New Orleans ratepayers may have been overcharged by more than $32 million, the vast majority of which is reflected in the plaintiffs' claim. However, it is not clear precisely what periods and damages are being alleged in the proceeding. Entergy intends to defend this matter vigorously, both in court and before the City Council. Hearings were held in February and March 2002. The parties have submitted post-hearing briefs and the matter has been submitted to the City Council for a decision. In October 2002, the plaintiffs filed a motion to re-open the evidentiary record, or in the alternative, a motion for a new trial seeking to re-open the record to accept certain testimony filed by the City Council advisors in a separate proceeding at the FERC. The ultimate outcome of the lawsuit and the City Council proceeding cannot be predicted at this time.

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.

                Entergy Arkansas refunded $54.3 million, including interest, through the issuance of refund checks in March 2002 as approved by the APSC.

                Entergy Louisiana refunded $4.9 million, including interest, to its customers through a credit on the September 2002 bills as approved by the LPSC.

                Entergy Mississippi's allocation of the proposed System Energy wholesale rate increase was $21.6 million annually. In July 1995, Entergy Mississippi filed a schedule with the MPSC that deferred the retail recovery of the System Energy rate increase. The deferral plan, which was approved by the MPSC, began in December 1995, the effective date of the System Energy rate increase, and was effective until the issuance of the final order by FERC. Entergy Mississippi revised the deferral plan two times during the pendency of the System Energy proceeding. As a result of the final resolution of the FERC order and in accordance with Entergy Mississippi's second revised deferral plan, refunds to Entergy Mississippi from System Energy, including interest, have been credited against deferral balances and a refund of the remaining $14.8 million in excess of the deferral balances were included as credits to the amounts billed to Entergy Mississippi's customers in October 2001 through September 2002 under its Grand Gulf Riders.

                Entergy New Orleans' allocation of the proposed System Energy wholesale rate increase was $11.1 million annually. In February 1996, Entergy New Orleans filed a plan with the Council to defer 50% of the amount of the System Energy rate increase. In December 2001, the Council approved a refund to customers. The total amount of the refund to Entergy New Orleans' customers was $43 million. In anticipation of the FERC order, Entergy New Orleans advanced the refunding of $10 million in February 2001 to customers to assist with unexpected high energy bills. The total refund was also reduced by an additional $6 million which was used for the establishment of a public benefits and payments assistance program. The remaining $27 million was refunded through the issuance of refund checks during the first quarter of 2002.

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 2002, 2001, and 2000 consist of the following (in thousands):

(a) The actual cash taxes paid/(received) were $57,856 in 2002, ($113,466) in 2001, and $345,361 in 2000. Entergy Louisiana's mark to market tax accounting election has significantly reduced taxes paid in 2001 and 2002. For a more detailed discussion of the tax accounting election, see the discussion of Entergy Louisiana Tax Accounting Election in Management's Financial Discussion and Analysis section.

                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 2002, 2001, and 2000 are (in thousands):

 

                Significant components of net deferred and noncurrent accrued tax liabilities as of December 31, 2002 and 2001 are as follows (in thousands):

                The 2002 valuation allowance is 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.

                The 2001 valuation allowance is provided primarily against foreign tax credit carryforwards, which can be utilized against future United States taxes on foreign source income. If these carryforwards are not utilized, they will expire between 2002 and 2006.

                At December 31, 2002, Entergy had $11.2 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 $1.450 billion, of which $535 million was outstanding as of December 31, 2002. The weighted-average interest rate on Entergy's outstanding borrowings under this facility as of December 31, 2002 and 2001 was 2.5% and 3.2%, respectively. 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 2003, 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 debt outstanding under the credit line is reflected in long-term debt on the balance sheet. The credit line is reflected as notes payable at December 31, 2001. Entergy Corporation's facility requires 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 the domestic utility companies default on other credit facilities or are in bankruptcy or insolvency proceedings, an acceleration of the facility's maturity 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. 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, 2002, Entergy's subsidiaries' authorized limit was $1.6 billion and the outstanding borrowing from the money pool was $61.5 million. There were no borrowings outstanding from external sources.

                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, 2002

             

Entergy Arkansas

 

May 2003

 

$63 million

 

-

Entergy Louisiana

 

May 2003

 

$15 million

 

-

Entergy Mississippi

 

May 2003

 

$25 million

 

-

The facilities have variable interest rates and the average commitment fee is 0.13%.

 

NOTE 5. PREFERRED AND COMMON STOCK

Preferred Stock

                The number of shares authorized and outstanding and dollar value of preferred stock for Entergy Corporation subsidiaries as of December 31, 2002 and 2001 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.

                All outstanding preferred stock is cumulative.

                Entergy Gulf States has annual sinking fund requirements of $3.45 million through 2007 for its preferred stock outstanding.

  1. Represents weighted-average annualized rate for 2002.
  2. 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.


Common Stock

                Treasury stock activity for Entergy for 2002 and 2001:

                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 2002, 2001, and 2000 will become exercisable in equal amounts on each of the first three anniversaries of the date of grant. Options are forfeited if they are not exercised within ten years from the date of the grant.

                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 2002, 2001, and 2000, $28 million, $14 million, and $17 million, respectively, was charged to compensation expense.

                The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following stock option weighted-average assumptions:

       

 

2002

2001

2000

Stock price volatility

27.2%

26.3%

24.4%

Expected term in years

5

5

5

Risk-free interest rate

4.2%

4.9%

6.6%

Dividend yield

3.2%

3.4%

5.2%

Dividend payment

$1.32

$1.26

$1.20

 

Stock option transactions are summarized as follows:

The following table summarizes information about stock options outstanding as of December 31, 2002:

                During the first quarter of 2003, an additional 7,196,699 options became exercisable with a weighted-average exercise price of $34.71.

                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. The Savings Plan provides that the employing Entergy subsidiary may:

    • make matching contributions to the plan in an amount equal to 75% of the participants' basic contributions, up to 6% of their salaries, 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 salaries, if the employees direct their company-matching contribution to other investment funds.

Entergy's subsidiaries contributed $29.6 million in 2002, $25.4 million in 2001, and $16.1 million in 2000 to the Savings Plan.

 

NOTE 6. COMPANY-OBLIGATED REDEEMABLE PREFERRED SECURITIES

                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, for the purpose of issuing common and preferred securities. The Trusts issue Cumulative Quarterly Income Preferred Securities (Preferred Securities) to the public and issue common securities to their parent companies. Proceeds from such issues are 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.





Trusts

 




Date
of Issue

 



Preferred
Securities
Issued

 



Common
Securities Issued

 


Interest Rate Securities/
Debentures

 


Trust's
Investment
 in
Debentures

 

Fair Market Value of Preferred Securities at
12-31-02

       

(In Millions)

     

(In Millions)

                         

Louisiana Capital I

 

7-16-96

 

$70.0

 

$2.2

 

9.00%

 

$72.2

 

$70.8

Arkansas Capital I

 

8-14-96

 

$60.0

 

$1.9

 

8.50%

 

$61.9

 

$60.1

Gulf States Capital I

 

1-28-97

 

$85.0

 

$2.6

 

8.75%

 

$87.6

 

$85.3

                The Preferred Securities of the Trusts mature in the years 2045 and 2046. The Preferred Securities are currently redeemable at 100% of their principal amount at the option of Entergy Louisiana, Entergy Arkansas, or Entergy Gulf States. Entergy Louisiana, Entergy Arkansas, and Entergy Gulf States have, pursuant to certain agreements, fully and unconditionally guaranteed payment of distributions on the Preferred Securities issued by their respective Trusts. Entergy Louisiana, Entergy Arkansas, and Entergy Gulf States are the owners of all of the common securities of their individual Trusts, which constitute 3% of each Trust's total capital.

 

NOTE 7. LONG - TERM DEBT

Long-term debt as of December 31, 2002 and 2001 consisted of:

 

  1. Consists of pollution control revenue bonds and environmental revenue bonds, certain series of which are secured by non-interest bearing first mortgage bonds.
  2. The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on September 1, 2005 and will then be remarketed.
  3. The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on September 1, 2004 and will then be remarketed.
  4. The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on October 1, 2003 and will then be remarketed.
  5. 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.
  6. The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on June 1, 2005 and will then be remarketed.
  7. 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) and annual cash sinking fund requirements for debt outstanding as of December 31, 2002, for the next five years are as follows (in thousands):

2003

$1,150,786

2004

$925,005

2005

$540,372

2006

$139,952

2007

$475,288

Not included are other sinking fund requirements of approximately $30.2 million annually, which may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements.

                In December 2002, when the Damhead Creek project was sold, the buyer of the project assumed all obligations under the Damhead Creek credit facilities and the Damhead Creek interest rate swap agreements.

                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.

                Covenants in the Entergy Corporation 7.75% 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 credit facilities or are in bankruptcy or insolvency proceedings, an acceleration of the facility's maturity may occur.

                In January 2003, Entergy paid in full, at maturity, the outstanding debt relating to the Top of Iowa wind project.

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 8. 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, 2002, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $296.1 million and $36.2 million, respectively. Additionally, PUHCA prohibits Entergy Corporation's subsidiaries from making loans or advances to Entergy Corporation. In 2002, Entergy Corporation received dividend payments totaling $618.4 million from subsidiaries. In addition, Entergy Louisiana repurchased $120 million of its common shares from Entergy Corporation in 2002.

 

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.

Capital Requirements and Financing

                Entergy plans to spend approximately $3.4 billion on construction and other capital investments during 2003-2005. This plan reflects capital required to support existing businesses as well as the approval by the Board of the ANO 1 steam generator replacement project. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of business restructuring, regulatory constraints, business opportunities, market volatility, economic trends, and the ability to access capital. Entergy's estimated construction and other capital expenditures by year for 2003-2005 are as follows (in millions):

Planned construction and capital investment

2003

2004

2005

U.S. Utility

$924

$915

$965

Non-Utility Nuclear

$201

$142

$109

Energy Commodity Services

$24

$76

$3

Other

$7

$7

$9

                The U.S. Utility will focus its planned spending on projects that will support continued reliability improvements and customer growth.

                Non-Utility Nuclear will focus its planned spending on routine construction projects and power uprates.

                Energy Commodity Services expenditures will primarily be on a merchant power plant project currently under construction and a $73 million cash contribution to Entergy-Koch in January 2004.

                The planned construction and capital investments do not include potential investments in new businesses or assets.

                Entergy will also require $2.6 billion during the period 2003-2005 to meet long-term debt and preferred stock maturities and cash sinking fund requirements. Entergy plans to meet these requirements primarily with internally generated funds and cash on hand, supplemented by proceeds from the issuance of debt and outstanding credit facilities. In the fourth quarter of 2002, the U.S. Utility issued $640 million of debt with maturities ranging from 2007 to 2032. Approximately $71 million of the proceeds of the debt issued in the fourth quarter were used to retire, in 2002, debt that was scheduled to mature in 2003, and the remainder will be used to meet certain 2003 maturities as they occur. Entergy Mississippi issued an additional $100 million of debt in January 2003 that matures in 2013. The proceeds will be used to repay, prior to maturity, debt of Entergy Mississippi that is scheduled to mature in 2003 and 2004. Certain domestic utility companies may also continue the reacquisition or refinancing of all or a portion of certain outstanding series of preferred stock and long-term debt.

Sales Warranties and Indemnities

                In the CitiPower sales transaction, Entergy or its subsidiaries made certain warranties to the purchaser. These warranties include representations regarding litigation, accuracy of financial accounts, and the adequacy of existing tax provisions. The purchasers of CitiPower have asserted notice of claims against Entergy under the terms of the Tax Warranty Deed dated November 23, 1998 between them and Entergy. The Tax Warranty Deed includes a reservation of rights relating to a potential liability in the event of an adverse tax ruling. In November 2002, the Australian Taxation Office assessed CitiPower for taxes for the years 1997 through 1999. Management believes it has adequately provided for the ultimate resolution of this matter.

                In the Saltend 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 adequately for the warranties as of December 31, 2002.

Power Purchase Agreements

                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 $104.2 million in 2002, $86.0 million in 2001, and $58.6 million in 2000. If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $79.5 million in 2003, and a total of $2.7 billion for the years 2004 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 treatment of the Vidalia contract, Entergy Louisiana agreed to credit monthly rates by $11 million each year for up to ten years, beginning in October 2002.

Nuclear Insurance

                The Price-Anderson Act limits public liability of a nuclear plant owner for a single nuclear incident to approximately $9.5 billion. Protection for this liability is provided through a combination of private insurance underwritten by American Nuclear Insurers (ANI) (currently $300 million for each reactor) and an industry assessment program. In addition, liability arising out of terrorist acts will be covered by ANI subject to one industry aggregate limit of $300 million, with a conditional option for one shared industry aggregate limit reinstatement of $300 million. (There are no terrorism limitations under the Price-Anderson Secondary Financial Protection program, which responds upon the exhaustion of ANI coverage). Under the assessment program, the maximum payment requirement for each nuclear incident would be $88.1 million per reactor, payable at a rate of $10 million per licensed reactor per incident per year. Entergy has ten licensed reactors, with five each in the U.S. Utility segment and the Non-Utility Nuclear segment. As a co-licensee of Grand Gulf 1 with System Energy, SMEPA would share in 10% of this obligation. In addition, each owner/licensee of Entergy's ten nuclear units participates in a private insurance program that provides coverage for worker tort claims filed for bodily injury caused by radiation exposure. The program provides for a maximum assessment of approximately $3 million for each licensed reactor in the event that losses exceed accumulated reserve funds.

                Entergy's nuclear owner/licensee subsidiaries are also members of certain insurance programs that provide coverage for property damage, including decontamination and premature decommissioning expense, to members' nuclear generating plants. These programs are underwritten by Nuclear Electric Insurance, Limited (NEIL). As of December 31, 2002, Entergy was insured against such losses up to $2.3 billion for each of its nuclear units, except for Pilgrim and Vermont Yankee which are insured for $1.115 billion in property damages. In addition, Entergy's nuclear owner/licensee subsidiaries are members of the NEIL insurance program that covers certain replacement power and business interruption costs incurred due to prolonged nuclear unit outages. Under the property damage and replacement power/business interruption insurance programs, these Entergy subsidiaries could be subject to assessments if losses exceed the accumulated funds available to the insurers. As of December 31, 2002, the maximum amounts of such possible assessments were $81.4 million for the U.S. Utility segment and $95.3 million for the Non-Utility Nuclear segment.

                Entergy maintains property insurance for each of its nuclear units in excess of the NRC's minimum requirement for nuclear power plant licensees of $1.06 billion per site. 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.

                Effective November 15, 2001, in the event that one or more acts of terrorism cause accidental property damage under one or more of all nuclear insurance policies issued by NEIL (including, but not limited to, those described above) within 12 months from the date the first accidental 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 source applicable to such losses.

Spent Nuclear Fuel

                Entergy's nuclear owner/licensee subsidiaries provide for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE will furnish disposal service at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2002 of $153 million for the one-time fee. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities.

                Entergy's Non-Utility Nuclear business has accepted assignment of the Pilgrim, FitzPatrick, Indian Point 3, Indian Point 2, and Vermont Yankee spent fuel disposal contracts with the DOE held by their previous owners. The previous owners have paid or retained liability for the fees for all generation prior to the purchase dates of those plants.

                Delays have occurred in the DOE's program for the acceptance and disposal of spent nuclear fuel at a permanent repository. After twenty years of study, the DOE, in February 2002, formally recommended, and President Bush approved, Yucca Mountain, Nevada as the permanent spent fuel repository. DOE will now proceed with the licensing and, if the license is granted by the NRC, eventual construction of the repository will begin and receipt of spent fuel may begin as early as approximately 2010. Considerable uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy's facilities for storage or disposal. As a result, future expenditures will be required to increase spent fuel storage capacity at Entergy's nuclear plant sites.

                Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are responsible for their own spent fuel storage. Current on-site spent fuel storage capacity at Grand Gulf 1 and River Bend is estimated to be sufficient until approximately 2006 and 2004, respectively, at which time dry cask storage facilities will be placed into service. The spent fuel pool at Waterford 3 was recently expanded through the replacement of the existing storage racks with higher density storage racks. This expansion should provide sufficient storage for Waterford 3 until after 2010. An ANO storage facility using dry casks began operation in 1996 and has been expanded since and will be further expanded as needed. The spent fuel storage facility at Pilgrim is licensed to provide enough storage capacity until approximately 2012. The first dry spent fuel storage casks were loaded at FitzPatrick in 2002, and further casks will be loaded there as needed. Indian Point and Vermont Yankee currently have sufficient spent fuel storage capacity until approximately 2004 and 2006, respectively, at which time planned additional dry cask storage capacity are to begin operation.

Nuclear Decommissioning Costs

                Total approved decommissioning costs for rate recovery purposes as of December 31, 2002, for Entergy Arkansas', Entergy Gulf States', Entergy Louisiana's, and System Energy's nuclear power plants, excluding SMEPA's share of Grand Gulf 1, are as follows:

                Entergy has been recording decommissioning liabilities for these plants as the estimated decommissioning costs are collected from customers or as earnings on the trust funds are realized. Effective January 1, 2003, Entergy adopted SFAS 143, "Accounting for Asset Retirement Obligations." The provisions of this statement will result in a different amount of decommissioning costs being recorded than under the method described above in use prior to December 31, 2002. Entergy expects to adjust for financial reporting purposes this different level of decommissioning expense to the level previously being recorded through the use of regulatory assets/regulatory liabilities for a substantial portion of the decommissioning costs associated with the units listed above. The decommissioning liabilities recorded are discussed below.

                Decommissioning costs recovered in rates are deposited in trust funds and reported at market value based upon market quotes or as determined by widely used pricing services. These trust fund assets largely offset the accumulated decommissioning liability that is recorded as accumulated depreciation for Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana, and are recorded as deferred credits for System Energy and Entergy's Non-Utility Nuclear business. The liability associated with the trust funds received from Cajun with the transfer of Cajun's 30% share of River Bend is also recorded as a deferred credit by Entergy Gulf States. The actual decommissioning costs may vary from the estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment.

                Entergy periodically reviews and updates estimated decommissioning costs. Entergy is presently under-recovering decommissioning costs for ANO 1, ANO 2, Grand Gulf 1, Waterford 3, and the Louisiana-regulated share of River Bend. Under-recovery for Grand Gulf 1 and Waterford 3 is based on the existence of more recent estimates reflecting higher costs. Under-recovery of ANO 1, ANO 2, and River Bend is based on suspension of decommissioning collections under the assumption that the lives of those plants have been or will be extended.

                In June 2001, Entergy Arkansas received notification from the NRC of approval for a renewed operating license authorizing operations at ANO 1 through May 2034. In October 2000, the APSC ordered Entergy Arkansas to reflect 20-year license extensions in its determination of the ANO 1 and ANO 2 decommissioning revenue requirements for rates to be effective January 1, 2001. Entergy Arkansas will not make additional contributions to the trust funds in 2003 for ANO 1 and ANO 2 based on the extension of the ANO 1 license, the assumption that the ANO 2 license will be extended, and that the existing decommissioning trust funds, together with their expected future earnings, will meet the estimated decommissioning costs. An updated decommissioning cost study for ANO 1 and 2 will be filed with the APSC in March 2003.

                In December 2002, Entergy Gulf States and the LPSC reached a settlement of the fourth through eighth post-merger earnings reviews. Among other things, the settlement includes suspension of collections for decommissioning the Louisiana-regulated portion of River Bend beginning January 1, 2003 based upon an assumption that the operating license and the useful life of River Bend will be extended. According to the settlement agreement, in the event that the NRC formally notifies Entergy that the decommissioning funding for River Bend is or would become inadequate, Entergy Gulf States would be permitted recognition in rates of decommissioning expense at a level sufficient to address reasonably the NRC's concern as expressed in the notification. The decommissioning liability for the 30% share of River Bend formerly owned by Cajun was fully funded by a transfer of $132 million to the River Bend Decommissioning Trust at the completion of Cajun's bankruptcy proceedings.

                Entergy Louisiana prepared a decommissioning cost update for Waterford 3 in 1999 and produced a revised decommissioning cost update of $481.5 million. This cost update was filed with the LPSC in the third quarter of 2000.

                System Energy included updated decommissioning costs (based on the updated 1994 study) in its 1995 rate increase filing with FERC. Rates requested in this proceeding were placed into effect in December 1995, subject to refund. In July 2000, FERC issued an order approving a lower decommissioning cost than what was requested by System Energy in the 1995 filing. System Energy adjusted its collection to the FERC-approved level of $341 million in the third quarter of 2001. A 1999 decommissioning cost update of $540.8 million for System Energy's 90% share of Grand Gulf 1 has not yet been filed with FERC.

                As part of the Pilgrim, Indian Point 1 and 2, and Vermont Yankee purchases, the previous owners transferred decommissioning trust funds, along with the liability to decommission the plants, to Entergy. Entergy believes that the decommissioning trust funds will be adequate to cover future decommissioning costs for these plants without any additional deposits to the trusts.

                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.

                The provisions of SFAS 143 will also be applicable to the non-regulated nuclear units beginning in 2003. Refer to Note 1 to the consolidated financial statements for a discussion of the effect of SFAS 143 on Entergy.

 

The cumulative liabilities and decommissioning expenses recorded in 2002 by Entergy were as follows:

    1. Includes decommissioning expenses and interest from accretion of the obligations.
    2. Trust earnings on the decommissioning trust funds for Pilgrim, Indian Point 1 & 2, and Vermont Yankee are recorded as income and do not increase the decommissioning liability.
    3. Added in third quarter of 2002, when the unit was acquired.

                In 2000, ANO's decommissioning expense was $3.8 million. River Bend's decommissioning expense was $6.2 million in both 2001 and 2000, and Waterford 3's decommissioning expense was $10.4 million for both years. Grand Gulf 1's 2001 decommissioning expense, which included the effect of the FERC-ordered refund, was ($23.8 million); its 2000 decommissioning expense was $18.9 million. Pilgrim's decommissioning expense was $20.1 million in 2001 and $19.2 million in 2000. In 2001, Indian Point 1 & 2's decommissioning expense was $5.3 million.

                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 2002 dollars), which will be adjusted annually for inflation, are for 15 years and were $4.2 million for Entergy Arkansas, $1.0 million for Entergy Gulf States, $1.6 million for Entergy Louisiana, and $1.6 million for System Energy in 2002. At December 31, 2002, four years of assessments were remaining. D&D fees are included in other current liabilities and other non-current liabilities and, as of December 31, 2002, recorded liabilities were $16.7 million for Entergy Arkansas, $4.0 million for Entergy Gulf States, $6.4 million for Entergy Louisiana, and $6.3 million for System Energy. Regulatory assets in the financial statements offset these liabilities, with the exception of Entergy Gulf States' 30% non-regulated portion. FERC requires that utilities treat these assessments as costs of fuel as they are amortized and recover these costs through rates in the same manner as other 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, 2002, 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 $60.1 million in 2002, $65.1 million in 2001, and $53.3 million in 2000.

Nuclear Fuel Leases

                As of December 31, 2002, arrangements to lease nuclear fuel existed in an aggregate amount up to $140 million for Entergy Arkansas, $80 million for each of Entergy Gulf States and Entergy Louisiana, and $95 million for System Energy. As of December 31, 2002, the unrecovered cost base of nuclear fuel leases amounted to approximately $88.1 million for Entergy Arkansas, $41.4 million for Entergy Gulf States, $50.9 million for Entergy Louisiana, and $79.0 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 have termination dates of November 2003, November 2003, December 2004, and November 2003, respectively. Such 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 arrangements have varying maturities through March 15, 2006. 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.

                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 $137.8 million (including interest of $11.3 million) in 2002, $149.3 million (including interest of $17.2 million) in 2001, and $158.7 million (including interest of $19.9 million) in 2000.

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, 2002, Entergy Louisiana's total equity capital (including preferred stock) was 46.28% of adjusted capitalization and its fixed charge coverage ratio for 2002 was 3.14.

                As of December 31, 2002, 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 (in thousands):

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 $79.5 million and $88.7 million as of December 31, 2002 and 2001, respectively.

                As of December 31, 2002, System Energy had future minimum lease payments (reflecting an implicit rate of 7.02%), which are recorded as long-term debt as follows (in thousands):

NOTE 11. RETIREMENT AND OTHER POSTRETIREMENT BENEFITS

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 earnings 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, 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 pension costs are recovered from customers as a component of cost of service in each of its jurisdictions.

                Total 2002, 2001, and 2000 pension costs of Entergy Corporation and its subsidiaries, including amounts capitalized, included the following components (in thousands):

The funded status of Entergy's pension plans as of December 31, 2002 and 2001 was (in thousands):

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.

                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.

                Entergy Arkansas, the portion of Entergy Gulf States regulated by the PUCT, Entergy Mississippi, and Entergy New Orleans have received regulatory approval to recover SFAS 106 costs through rates. Entergy Arkansas began recovery in 1998, pursuant to an APSC order. This order also allowed Entergy Arkansas to amortize a regulatory asset (representing the difference between SFAS 106 costs and cash expenditures for other postretirement benefits incurred for a five-year period that began January 1, 1993) over a 15-year period that began in January 1998.

                The LPSC ordered the portion of Entergy Gulf States regulated by the LPSC and Entergy Louisiana to continue the use of the pay-as-you-go method for ratemaking purposes for postretirement benefits other than pensions. However, the LPSC retains the flexibility to examine individual companies' accounting for postretirement benefits to determine if special exceptions to this order are warranted.

                Pursuant to regulatory directives, Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, the portion of Entergy Gulf States regulated by the PUCT, and System Energy fund postretirement benefit obligations collected in rates. System Energy is funding on behalf of Entergy Operations postretirement benefits associated with Grand Gulf 1. Entergy Louisiana and Entergy Gulf States continue to recover a portion of these benefits regulated by the LPSC and FERC on a pay-as-you-go basis. The assets of the various postretirement benefit plans other than pensions include common stocks, fixed-income securities, and a money market fund.

                Total 2002, 2001, and 2000 other postretirement benefit costs of Entergy Corporation and its subsidiaries, including amounts capitalized and deferred, included the following components (in thousands):

 

                The funded status of Entergy's other postretirement benefit plans as of December 31, 2002 and 2001 was (in thousands):

                The assumed health care cost trend rate used in measuring the APBO of Entergy was 10% for 2003, 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 2002 would have increased the APBO and the sum of the service cost and interest cost of Entergy as of December 31, 2002, by approximately $87.8 million and $10.6 million, respectively. A one percentage point decrease in the assumed health care cost trend rate for 2002 would have decreased the APBO and the sum of the service cost and interest cost of Entergy as of December 31, 2002, by approximately $79.8 million and $9.4 million, respectively.

                The significant actuarial assumptions used in determining the pension PBO and the SFAS 106 APBO for 2002, 2001, and 2000 were as follows:

                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.

 

NOTE 12. BUSINESS SEGMENT INFORMATION

                Entergy's reportable segments as of December 31, 2002 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, L.P. 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 separately 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 (in thousands):

                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 Entergy Wholesale Operations, including impairments of administrative fixed assets, estimated sublease losses, and employee-related costs for approximately 135 affected employees. These restructuring costs, which are included in the "Provision for turbine commitments, asset impairments and restructuring charges" in the accompanying consolidated statement of income as of December 31, 2002, were comprised of the following (in millions):

Restructuring
 Costs

Paid in
 Cash

Non-Cash
 Portion

Remaining
Accrual

Fixed asset impairments
Sublease losses
Severance and related costs
      Total

$22.5
10.7
    5.9
$39.1

$ -
0.9
  2.5
$3.4

$22.5
-
       -
$22.5

$-
9.8
    3.4
$13.2

  • $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, (in thousands):

 

2002

2001

2000

Domestic

$8,051,992

$9,098,861

$9,950,229

Foreign

     253,043

    522,038

        71,900

Consolidated

$8,305,035

$9,620,899

$10,022,129

                Long-lived assets as of December 31 were as follows (in thousands):

 

2002

2001

2000

Domestic

$17,194,179

$16,468,059

$15,425,915

Foreign

              773

       421,870

    1,019,831

Consolidated

$17,194,952

$16,889,929

$16,445,746

 

NOTE 13. EQUITY METHOD INVESTMENTS

                Entergy owns investments in the following companies that it accounts for under the equity method of accounting: Entergy-Koch, LP (in which Entergy holds a 50% member interest), a company 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 (in which Entergy holds a 50% member interest), a co-generation project that provides power on an industrial and merchant basis in the Lake Charles, Louisiana area; EntergyShaw LLC (in which Entergy holds a 50% member interest), a company which provides management, engineering, procurement, construction, and commissioning services for electric power plants; and Crete Energy Ventures, LLC (in which Entergy holds a 50% member interest), a merchant power plant located in Crete, Illinois. Following is a reconciliation of Entergy's investments in equity affiliates (in thousands):

   

2002

 

2001

 

2000

Beginning of year

 

$766,103 

 

$136,487 

 

$117,378 

Additional investments

 

36,372 

 

471,102 

 

25,943 

Income from the investments

 

205,340 

 

180,956 

 

13,715 

Dividends received

 

(73,902)

 

(21,191)

 

(20,468)

Currency translation adjustments

 

 

138 

 

(891)

Dispositions and other adjustments

 

 (109,704)

 

     (1,389)

 

         810 

End of year

 

$824,209 

 

$766,103 

 

$136,487 

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

   

2002

 

2001

 

2000

Income Statement Items

           

Operating revenues
Operating income
Net income

 

$551,853
$192,173
$100,926

 

$693,400
$309,752
$226,039

 

$200,026
$90,694
$74,042

Balance Sheet Items

           

Current assets
Noncurrent assets
Current liabilities
Current liabilities

 

$2,334,133
$1,490,355
$1,777,142
$734,816

 

$2,969,132
$3,309,752
$2,729,769
$1,491,957

   

                Two of the unconsolidated 50/50 joint ventures, Entergy-Koch and RS Cogen, have obtained debt financing for their operations. As of December 31, 2002, the debt financing outstanding for those two entities totals $818 million, which is included in the liability figures given above. This debt is nonrecourse to Entergy.

Related-party transactions and guarantees

                During 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 2002 and 2001 was approximately $11.2 million and $7.8 million, respectively. Entergy's operating transactions with its other equity method investees were not material in 2002, 2001, or 2000.

                One of the contracts transferred to Entergy-Koch by Entergy's power marketing and trading business is backed by an Entergy Corporation guarantee authorized in the amount of $35 million. The guarantee term is through the expiration of the underlying contract, which ends in 2018.

                EntergyShaw is currently constructing the Harrison County project for Entergy. Entergy has guaranteed the obligations of EntergyShaw to construct the plant, and Entergy's maximum liability on the guarantee is $232.5 million. The project is expected to be completed in 2003.

 

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 where 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 preliminarily allocated to the assets acquired and liabilities assumed based on their estimated fair values on the purchase date. The allocation was based on preliminary information and the final allocation may differ, although management does not expect the difference to be material.

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 1970s.

                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.

Indian Point 3 and FitzPatrick

                In November 2000, Entergy's Non-Utility Nuclear business acquired from NYPA the 825 MW James A. FitzPatrick nuclear power plant near Oswego, New York, and the 980 MW Indian Point 3 nuclear power plant located in Westchester County, New York, in exchange for $50 million at closing and notes to NYPA with payments totaling $906 million. Entergy will also be required to make certain additional payments to NYPA in the event that the plants' license lives are extended.

                The acquisition encompassed the nuclear plants, materials and supplies, and nuclear fuel, as well as the assumption of $124 million in liabilities. The purchase agreement provides that NYPA will purchase a substantial majority of the output of the units at specified prices through 2004. The purchase agreement also provides that NYPA will retain the decommissioning obligations and related trust funds through the original license expiration date (approximately 2015). At that time, NYPA is required either to transfer the decommissioning liability to Entergy along with a specified amount in the decommissioning trust funds, or to retain Entergy to perform decommissioning services for a specified price that may be limited by the amount in the trust. In the purchase price allocation, Entergy recorded an asset representing its estimate of the net present value of the decommissioning contract obtained in the acquisition, based on an independent decommissioning cost study and other projections. The asset increases by monthly accretion based on the discount rate used to determine the original net present value. Entergy records the monthly accretion as interest income.

                The acquisition was accounted for using the purchase method. The results of operations of Indian Point 3 and FitzPatrick subsequent to the purchase date have been included in Entergy's consolidated statements of income. 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 lives of the plants.

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 for an after-tax gain on the sale of $31.4 million. The Damhead Creek buyer assumed all market and regulatory risks associated with the facility.

                In August 2001, Entergy sold the Saltend plant 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, 2002.

 

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 their 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

 

Energy Commodity Services

Foreign currency forwards

 

U.S. Utility, Non-Utility Nuclear

                Cash flow hedges with unrealized gains of approximately $21 million at December 31, 2002 are scheduled to mature during 2003. Gains totaling approximately $4.3 million were realized during 2002 on the maturity of cash flow hedges. A substantial majority of these unrealized and realized gains resulted from foreign currency hedges related to Euro-denominated nuclear fuel acquisition contracts, and related gains or losses, when realized, are included in the capitalized cost of nuclear fuel. The maximum length of time over which Entergy is currently hedging the variability in future cash flows for forecasted transactions at December 31, 2002 is approximately five years. The ineffective portion of the change in the value of Entergy's cash flow hedges during 2002 was insignificant.

Other Derivatives

                Entergy also holds derivative instruments such as natural gas and electricity options and forwards that are not accounted for as hedges. These instruments are entered into to optimize asset values or limit risks.

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, 2002 and 2001, the fair values of Energy Commodity Services' energy-related commodity contracts accounted for on a mark-to-market basis were as follows:

 

2002

 

2001

 

Assets

 

Liabilities

 

Assets

 

Liabilities

 

(In Thousands)

               

Consolidated subsidiaries

$4,071

 

$8,395

 

$59,996

 

$18,882

Equity method investees (1)

$754,678

 

$663,765

 

$774,509

 

$667,752

(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 the 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, 2002

2003

2004

2005 - 2006

Total

     

(In Millions)

     

Prices actively quoted

 

$45.0

 

$45.1

 

($20.2)

 

$69.9

Prices provided by other sources

24.4

3.3

1.9

29.6

Prices based on models

 

(13.3)

 

1.3

 

3.4

 

(8.6)

Total

 

$56.1

 

$49.7

 

($14.9)

 

$90.9

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, 6, and 7 to the consolidated financial statements.

 

NOTE 16. QUARTERLY FINANCIAL DATA (UNAUDITED)

                Operating results for the four quarters of 2002 and 2001 were:

 

Operating
Revenues

 

Operating
Income (Loss)

 

Net
 Income (Loss)

2002:

(In Thousands)

   First Quarter

$1,860,834

 

$(45,675)

 

$(72,983)

   Second Quarter

2,096,581

 

496,154 

 

247,585 

   Third Quarter

2,468,875

 

663,689 

 

366,800 

   Fourth Quarter

1,878,745

 

73,512 

 

81,670 

2001:

         

   First Quarter

$2,652,427

 

$360,967 

 

$160,871 

   Second Quarter

2,506,275

 

480,549 

 

245,583 

   Third Quarter

2,576,889

 

607,656 

 

317,454 

   Fourth Quarter

1,885,308

 

124,170 

 

26,599 (a) 

  1. Net income before cumulative effect of accounting change for the fourth quarter of 2001 was $3,117.
  2. Earnings per Average Common Share

     

    2002

    2001

     

      Basic  

     Diluted 

      Basic  

     Diluted 

             

    First Quarter

    $(0.36)

    $(0.36)

    $0.70

    $0.69

    Second Quarter

    $1.08

    $1.06

    $1.08

    $1.06

    Third Quarter

    $1.61

    $1.59

    $1.41

    $1.39

    Fourth Quarter

    $0.36

    $0.35

    $0.10 (b)

    $0.09 (b)

  3. Basic and diluted earnings per average common share before the cumulative effect of accounting change for the fourth quarter of 2001 was ($0.01).

 

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 all the power and capacity from Grand Gulf 1 at wholesale to the domestic utility companies.

                Entergy Services, a corporation wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the domestic utility companies. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf 1, subject to the owner oversight of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the domestic utility companies and System Energy on an "at cost" basis, pursuant to service agreements approved by the SEC under PUHCA.

                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 either been delayed, abandoned, or not initiated in its service territories. The overall generation portfolio of the U.S. Utility, which is primarily made up of 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, 2002, Entergy's domestic utility companies provided retail electric and gas service to approximately 2.6 million customers in Arkansas, Louisiana, Mississippi, and Texas.

 

 

Electric Energy Sales

                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 2, 2002, Entergy reached a 2002 peak demand of 20,419 MW, compared to the 2001 peak of 20,257 MW recorded on August 21 of that year. Selected electric energy sales data is shown in the table below:

Selected 2002 Electric Energy Sales Data

  1. Includes the effect of intercompany eliminations.

                The following table illustrates the domestic utility companies' 2002 combined electric sales volume as a percentage of total electric sales volume, and 2002 combined electric revenues as a percentage of total 2002 electric revenue, each by customer class.

Customer Class                         % of Sales Volume         % of Revenue

Residential...................                                                 29.2                             36.7
Commercial.................                                                 22.7                             25.2
Industrial (a)................                                                 36.9                             27.9
Wholesale...................                                                   8.8                              7.5
Governmental..............                                                   2.4                              2.7

  1. 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 2000, 2001, and 2002.

Selected 2002 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 14,596,366 and 6,745,400 Mcf, respectively, of natural gas to retail customers in 2002. In 2002, 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, 84% of operating revenue was derived from the electric utility business and 16% from the natural gas distribution business in 2002. Following is data concerning Entergy New Orleans 2002 retail operating revenue sources and customer data.

 

 
Entergy New Orleans

Electric Operating
Revenue

Natural Gas
Revenue

     

Residential

41%

54%

Commercial

37%

22%

Industrial

6%

9%

Governmental/Municipal

16%

15%

     

Property

Generating Stations

                The total capability of the generating stations owned and leased by the domestic utility companies and System Energy as of December 31, 2002, is indicated below:

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

                Entergy's load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections in light of the availability and price of power, the location of new loads, and economy. In September 2002, Entergy Louisiana and Entergy Gulf States made an informational filing with the LPSC containing a draft request for proposal for supply-side resources. The final request for proposal was issued on November 1, 2002 by Entergy Services on behalf of the domestic utility companies. The request for proposal sought resources to meet both the domestic utility companies' summer 2003 and longer term resource needs through a broad range of wholesale power products, including short and long-term contractual products and possibly asset acquisitions. As a result of the fall 2002 request for proposal, Entergy Services selected approximately 550 MW of short-term capacity and energy products. In January 2003, Entergy Services executed agreements for 425 MW in one- to three-year contracts as one of the selected bidders failed to honor its offer. Entergy Services also is pursuing discussions with several bidders for life of unit purchased power agreements or the acquisition of an ownership interest in existing generating facilities. Also in January 2003, Entergy Services issued a Supplemental Request for Proposals for Short-Term Unit Capacity Purchase Agreement Products to solicit only proposals for the delivery of short-term dispatchable electric capacity and energy products beginning in the summer of 2003. As a result, Entergy Services selected approximately 500 MW of short-term capacity and energy products and expects to finalize the agreements in March 2003.

                On January 31, 2003, Entergy Louisiana and Entergy New Orleans made filings with their respective retail regulators seeking authorization for the companies to enter into new purchase power agreements and permitting recovery of the additional capacity costs associated with these agreements in retail rates. These proposed purchases include potential power purchases from nuclear and coal generating resources owned by Entergy Gulf States and Entergy Arkansas, which are available for wholesale sales. In support of these filings, Entergy Louisiana and Entergy New Orleans submitted information demonstrating that their customers would benefit from these proposed purchases through the reduction in overall retail rates resulting from the projected savings in fuel and purchased power costs, from reduced exposure to natural gas price volatility and by reducing the differential between their total production costs and the Entergy system's average total production costs. Entergy Louisiana and Entergy New Orleans requested that these approvals be granted before the summer of 2003. On March 6, 2003, Entergy Arkansas requested that the APSC find that it is in the public interest for Entergy Arkansas to enter into these contracts.  On March 13, 2003, Entergy New Orleans and the Advisors to the City Council presented to the City Council an agreement in principle that, if approved by the City Council, would grant Entergy New Orleans the authorization it requested.  A procedural schedule for the City Council's consideration of the agreement in principle has not been established.  Management cannot predict the timing or outcome of these proceedings.

Interconnections

                Entergy's generating units are interconnected by a transmission system operating at various voltages up to 500 kV. These generating units consist primarily of steam-electric production facilities and are centrally dispatched and operated. Entergy's domestic utility companies are interconnected with many neighboring utilities. In addition, the domestic utility companies are members of the Southeastern Electric Reliability Council. The primary purpose of SERC is to ensure the reliability and adequacy of the electric bulk power supply in the southeast region of the United States. SERC is a member of the North American Electric Reliability Council.

Gas Property

                As of December 31, 2002, Entergy New Orleans distributed and transported natural gas for distribution solely within New Orleans, Louisiana, through a total 33 miles of gas transmission pipelines, 1,476 miles of gas distribution mains, and 1,034 miles of gas service line from the distribution mains to the customers. As of December 31, 2002, the gas properties of Entergy Gulf States, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Gulf States' financial position.

Titles

                Entergy's generating stations and major transmission substations are generally located on properties owned in fee simple. Most of the transmission and distribution lines are constructed over private property or public rights-of-way pursuant to easements or appropriate franchises. The domestic utility companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.

                Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy are subject to the liens of mortgages securing the first mortgage bonds of such company. The Lewis Creek generating station is owned by GSG&T, Inc., a subsidiary of Entergy Gulf States, and is not subject to the lien of the Entergy Gulf States mortgage securing its first mortgage bonds. Lewis Creek is leased to and operated by Entergy Gulf States. All of the debt outstanding under the original first mortgages of Entergy Mississippi and Entergy New Orleans is retired and original first mortgages cancelled. As a result, the general and refunding mortgages of Entergy Mississippi and Entergy New Orleans constitute a first mortgage lien on substantially all of the respective physical properties and assets of these two companies.

Fuel Supply

                The generation portfolio of the U.S. Utility contains a high percentage of natural gas and nuclear generation. The sources of generation and average fuel cost per kWh for the domestic utility companies and System Energy for the years 2000-2002 were:

 

 

Natural Gas

Fuel Oil

Nuclear Fuel

Coal

 

%

Cents

%

Cents

%

Cents

%

Cents

 

of

Per

of

Per

of

Per

of

Per

Year

Gen

kWh

Gen

kWh

Gen

kWh

Gen

kWh

                 

2002

39

3.88

-

15.78

46

.47

15

1.37

2001

34

4.62

8

4.33

43

.50

15

1.58

2000

42

4.90

4

3.90

39

.56

15

1.51

                Actual 2002 and projected 2003 sources of generation for the domestic utility companies and System Energy, including proposed power purchases from affiliates under power purchase agreements in 2003, are:

 

Natural Gas

Fuel Oil

Nuclear

Coal

 

2002

2003

2002

2003

2002

2003

2002

2003

                 

Entergy Arkansas (a)

7%

-

-

-

62%

69%

30%

30%

Entergy Gulf States

54%

45%

-

-

31%

31%

15%

24%

Entergy Louisiana

55%

36%

-

-

45%

62%

-

2%

Entergy Mississippi

68%

5%

-

32%

-

-

32%

63%

Entergy New Orleans

100%

53%

-

-

-

33%

-

14%

System Energy

-

-

-

-

100%(b)

100% (b)

-

-

Total (a)

39%

22%

0%

2%

46%

57%

15%

19%

  1. Hydroelectric power provided 1% of Entergy Arkansas' generation in 2002 and is expected to provide 1% of its generation in 2003.
  2. Capacity and energy from System Energy's interest in Grand Gulf 1 is allocated as follows: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%.

Natural Gas

                The domestic utility companies have long-term firm and short-term interruptible gas contracts. Long-term firm contracts comprise less than 26% of the domestic utility companies' total requirements but can be called upon, if necessary, to satisfy a significant percentage of the utility companies' needs. Short-term contracts and spot-market purchases satisfy additional gas requirements. Entergy Gulf States has a transportation service agreement with a gas supplier that provides flexible natural gas service to certain generating stations by using such supplier's pipeline and gas storage facility.

                Many factors, including wellhead deliverability, storage and pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is tied to weather conditions as well as to the prices of other energy sources. Entergy's supplies of natural gas are expected to be adequate in 2003. However, pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the domestic utility companies will use alternate fuels, such as oil, or rely to a larger extent on coal, nuclear generation, and purchased power.

Coal

                Entergy Arkansas has a long-term contract for low-sulfur Wyoming coal for Independence. This contract, which expires in 2011, provides for approximately 90% of Independence's expected coal requirements for 2003. Entergy Arkansas has entered into one- to three-year contracts for approximately 52% of White Bluff's coal supply needs and plans to enter into another for approximately 13% of White Bluff's coal supply needs. Entergy Arkansas has an additional 20% of its 2003 coal requirement committed in a number of one- to two-year contracts. Additional coal requirements for both Independence and White Bluff are satisfied by spot market or over the counter purchases. Additionally, Entergy Arkansas has a long-term railroad transportation contract for the delivery of coal to both White Bluff and Independence that expires in 2011. A second carrier now delivers a portion of White Bluff's coal requirements under a long-term transportation agreement that began in 2002 and expires on December 31, 2006.

                Entergy Gulf States has a contract for the supply of low-sulfur Wyoming coal for Nelson Unit 6, which should be sufficient to satisfy its requirements for that unit at current consumption rates through the first quarter of 2003. The contract includes options to extend supply to 2010 if all price re-openers are accepted. Notice has been made for a price re-opener session. If both parties cannot agree upon a price, then the contract terminates. The operator of Big Cajun 2, Unit 3, Louisiana Generating LLC, has advised Entergy Gulf States that it has coal supply and transportation contracts that should provide an adequate supply of coal for the operation of Big Cajun 2, Unit 3 for the foreseeable future. Additionally, Entergy Gulf States has transportation requirements contracts with railroads to deliver coal to Nelson Unit 6 through December 31, 2004. Each of the two contracts governs the movement of about half of the plant's requirements and the base contract provides flexibility for shipping up to all of the plant's requirements.

Nuclear Fuel

                The nuclear fuel cycle consists of the following:

    • mining and milling of uranium ore to produce a concentrate;
    • conversion of the concentrate to uranium hexafluoride gas;
    • enrichment of the hexafluoride gas;
    • fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
    • disposal of spent fuel.

                System Fuels, a company owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, is responsible for contracts to acquire nuclear material to be used in fueling Entergy's utility nuclear units, except for River Bend. System Fuels also maintains inventories of such materials during the various stages of processing. The domestic utility companies purchase enriched uranium hexafluoride from System Fuels, but contract separately for the fabrication of their own nuclear fuel. The requirements for River Bend are pursuant to contracts made by Entergy Gulf States.

                Based upon currently planned fuel cycles, Entergy's nuclear units have contracts and inventory that provide adequate materials and services. Existing contracts for uranium concentrate, conversion of the concentrate to uranium hexafluoride, and enrichment of the uranium hexafluoride will provide a significant percentage of these materials and services over the next several years. Additional materials and services required beyond the coverage of these contracts are expected to be available at a manageable cost for the foreseeable future.

                The Nuclear Waste Policy Act of 1982 provides for the disposal of spent nuclear fuel or high level waste by the DOE. Refer to Note 9 to the domestic utility companies and System Energy financial statements for a discussion of spent nuclear fuel disposal and spent fuel storage capacity.

                Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These arrangements are subject to periodic renewal. It will be necessary for these companies to enter into additional arrangements to acquire nuclear fuel in the future. It is not possible to predict the ultimate cost of such arrangements. See Note 10 to the domestic utility companies and System Energy financial statements for a discussion of nuclear fuel leases.

Natural Gas Purchased for Resale

                Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with three interstate and three intrastate pipelines. Entergy New Orleans' primary suppliers currently are Bridgeline Gas Distributors and Louisiana Gas Services. Entergy New Orleans has a "no-notice" service gas purchase contract with Bridgeline Gas Marketing, LLC which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The Bridgeline Gas Marketing, LLC gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Entergy-Koch's Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans has firm contracts with its two intrastate suppliers and also makes interruptible spot market purchases. In recent years, natural gas deliveries to Entergy New Orleans have been subject primarily to weather-related curtailments. However, Entergy New Orleans experienced no such curtailments in 2002.

                As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy New Orleans' suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline could curtail transportation capacity only in the event of pipeline system constraints. Based on the current supply of natural gas, and absent extreme weather-related curtailments, Entergy New Orleans does not anticipate any interruptions in natural gas deliveries to its customers.

                Entergy Gulf States purchases natural gas for resale under a firm contract from Enbridge Marketing (U.S.) Inc. (formerly Mid Louisiana Gas Company) for five years.

Regulation of the Nuclear Power Industry

                Entergy Operations operates ANO, River Bend, Waterford 3, and Grand Gulf 1, subject to the owner oversight of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy, respectively. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy pay directly or reimburse Entergy Operations at cost for its operation of the nuclear units.

Atomic Energy Act of 1954 and Energy Reorganization Act of 1974

                Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend, Waterford 3, and Grand Gulf 1, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC. Entergy has made substantial capital expenditures at these nuclear plants because of revised safety requirements of the NRC in the past, and additional expenditures could be required in the future.

Nuclear Waste Policy Act of 1982

                Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Delays have occurred in the DOE's program for the acceptance and disposal of spent nuclear fuel at a permanent repository. After twenty years of study, the DOE, in February 2002, formally recommended, and President Bush approved, Yucca Mountain, Nevada as the permanent spent fuel repository. DOE will now proceed with the licensing and, if the license is granted by the NRC, eventual construction of the repository will begin and receipt of spent fuel may begin as early as approximately 2010. Considerable uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy's facilities for storage or disposal. As a result, future expenditures will be required to increase spent fuel storage capacity at Entergy's nuclear plant sites. Information concerning spent fuel disposal contracts with the DOE, current on-site storage capacity, and costs of providing additional on-site storage is presented in Note 9 to the financial statements.

 

Low-Level Radioactive Waste Policy Act of 1980

                The Low-Level Radioactive Waste Policy Act of 1980, as amended, holds each state responsible for disposal of waste originating in that state, but allows states to participate in regional compacts to fulfill their responsibilities jointly. Arkansas and Louisiana participate in the Central Interstate Low-Level Radioactive Waste Compact (Central States Compact) and Mississippi participates in the Southeast Low-Level Radioactive Waste Compact (Southeast Compact). Both the Central States Compact and the Southeast Compact waste facility development projects are on hold and further development efforts are unknown at this time. Currently the Entergy nuclear stations have disposal access at two waste disposal facilities: the Barnwell facility in South Carolina and the Envirocare facility in Utah. The Barnwell facility is licensed as a 10CFR61 facility and can accept all three classes of low level radwastes (Classes A, B, and C). With South Carolina's alliance as a member of the Atlantic Compact, disposal access for out-of-region waste generators will be limited at Barnwell. Over the next several years available out-of-region disposal capacity will continue to decrease and in 2008 out-of-region disposal will be prohibited. Currently the Envirocare facility is licensed to accept lower activity radwaste including Class A radioactive wastes. Envirocare has applied for a full service Class B and C license but has decided not to pursue that license at this time.

                The Southeast Compact has filed sanctions against the host state of North Carolina and the process is currently on hold pending resolution of the sanctions action by the compact. In December 1998, the host state for the Central States Compact, Nebraska, denied the compact's license application. In December 1998, Entergy, two other utilities in the Central States Compact, and the Compact Commission filed a lawsuit against the state of Nebraska seeking damages resulting from delays and a faulty license review process. After two months of trial, United States District Court concluded that Nebraska violated its federal obligation to the United States and the States of Arkansas, Kansas, Louisiana, and Oklahoma. To be specific, Nebraska failed to act in good faith as required by an interstate compact when it considered, delayed, and then denied a license to build a low-level radioactive waste disposal facility that was to be used by the citizens of those states. As a remedy, the court ordered Nebraska to pay the Compact Commission, with interest, over $151 million that was expended during the attempt to license the facility in Nebraska. Although Entergy's cross-claims against the Commission were denied, the court's decision leaves open Entergy's claim against the Commission once the Commission receives the funds from the State of Nebraska. Until long-term disposal facilities are established, Entergy will seek continued access to existing facilities. If such access is unavailable, Entergy will store low-level waste at its nuclear plant sites.

Nuclear Plant Decommissioning

                Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy recover from customers through electric rates the estimated decommissioning costs for ANO, River Bend, Waterford 3, and Grand Gulf 1, respectively. These amounts are deposited in trust funds that can only be used for future decommissioning costs. Entergy periodically reviews and updates estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.

                In June 2001, Entergy Arkansas received notification from the NRC of approval for a renewed operating license authorizing operations at ANO 1 through May 2034. In October 2000, the APSC ordered Entergy Arkansas to reflect 20-year license extensions in its determination of the ANO 1 and ANO 2 decommissioning revenue requirements for rates to be effective January 1, 2001. Entergy Arkansas will not recover decommissioning costs in 2003 for ANO 1 and ANO 2 based on the extension of the ANO 1 license, the assumption that the ANO 2 license will be extended, and the fact that existing decommissioning trust funds, together with their expected future earnings, will meet the estimated decommissioning costs.

                Additional information with respect to decommissioning costs for ANO, River Bend, Waterford 3, and Grand Gulf 1 is found in Note 9 to the financial statements.

 

Energy Policy Act of 1992

                The Energy Policy Act of 1992 requires all electric utilities (including Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy) that purchased uranium enrichment services from the DOE to contribute up to a total of $150 million annually over approximately 15 years (adjusted for inflation, up to a total of $2.25 billion) for decontamination and decommissioning of enrichment facilities. At December 31, 2002, four years of assessments remain. In accordance with the Energy Policy Act of 1992, contributions to decontamination and decommissioning funds are recovered through rates in the same manner as other fuel costs. The estimated annual contributions by Entergy for decontamination and decommissioning fees are discussed in Note 9 to the financial statements.

Price Anderson Act

                The Price-Anderson Act limits public liability for a single nuclear incident to approximately $9.5 billion. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy have protection with respect to this liability through a combination of private insurance and an industry assessment program, as well as insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units. Insurance applicable to the nuclear programs of Entergy is discussed in Note 9 to the financial statements.

Rate Matters

                State or local regulatory authorities, as described below, regulate the retail rates of Entergy's domestic utility companies. FERC regulates wholesale rates (including intrasystem sales pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy's sales of capacity and energy from Grand Gulf 1 to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement.

Wholesale Rate Matters

System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

                The domestic utility companies have historically engaged in the coordinated planning, construction, and operation of generation and transmission facilities pursuant to the terms of the System Agreement. Under the terms of the System Agreement, generating capacity and other power resources are jointly operated by the domestic utility companies. The System Agreement provides, among other things, that parties having generating reserves greater than their load requirements (long companies) shall receive payments from those parties having deficiencies in generating reserves (short companies). Such payments are at amounts sufficient to cover certain of the long companies' costs for intermediate and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred and preference stock, and a fair rate of return on common equity investment. Under the System Agreement, these charges are based on costs associated with the long companies' steam electric generating units fueled by oil or gas. In addition, for all energy exchanged among the domestic utility companies under the System Agreement, the short companies are required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.

                The LPSC and the Council commenced a proceeding at FERC in April 2000 that requested revisions to the System Agreement, which the LPSC and the Council alleged were necessary to accommodate the proposed introduction of retail competition in Texas and Arkansas. In June 2000, the domestic utility companies filed proposed amendments to the System Agreement with FERC to facilitate the proposed implementation of retail competition in Arkansas and Texas and to provide for continued sharing of generation resources and costs among the domestic utility companies in Louisiana and Mississippi. These proceedings have been consolidated with a previous complaint filed with FERC by the LPSC in 1995. In that complaint, the LPSC requested, among other things, modification of the System Agreement to exclude curtailable load from the allocation determination related to reserve sharing. In June 2001, in connection with these proceedings, the parties filed an offer of settlement with FERC. The offer of settlement provides for the following amendments to the System Agreement:

    • the Texas retail jurisdictional division of Entergy Gulf States will terminate its participation in the System Agreement, except for the aspects related to transmission equalization, when Texas implements retail open access for Entergy Gulf States, and that division will sell up to five percent of its generation to those other domestic utility companies who choose to purchase their share of the five percent; and
    • the service schedule developed to track changes in energy costs resulting from the Entergy-Gulf States Utilities merger is modified to include one final true-up of fuel costs when the Texas retail jurisdictional division of Entergy Gulf States ceases participation in the System Agreement, after which the service schedule will no longer be applicable for any purpose.

                As anticipated by the offer of settlement, the LPSC and the Council commenced a new proceeding at FERC in June 2001. In this proceeding, the LPSC and the Council allege that the rough production cost equalization required by FERC under the System Agreement and the Unit Power Sales Agreement has been disrupted by changed circumstances. The LPSC and the Council have requested that FERC amend the System Agreement or the Unit Power Sales Agreement or both to achieve full production cost equalization or to restore rough production cost equalization. Their complaint does not seek a change in the total amount of the costs allocated by either the System Agreement or the Unit Power Sales Agreement. In addition the LPSC and the Council allege that provisions of the System Agreement relating to minimum run and must run units, the methodology of billing versus dispatch, and the use of a rolling twelve-month average of system peaks, increase costs paid by ratepayers in the LPSC and Council's jurisdictions. Several parties have filed interventions in the proceeding, including the APSC and the MPSC. Entergy filed its response to the complaint in July 2001 denying the allegations of the LPSC and the Council. The APSC and the MPSC also filed responses opposing the relief sought by the LPSC and the Council.

                In their complaint, the LPSC and the Council allege 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. In February 2002, the FERC set the matter for hearing and established a refund effective period consisting of the 15 months following September 13, 2001. Negotiations among the parties have not resolved the proceeding, and the proceeding is now set for hearing commencing in June 2003. The case had been set for trial commencing in February 2003. The extension of the schedule also extended the refund effective period by 120 days. If FERC grants the relief requested by the LPSC and the Council, 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 neither the timing nor the outcome of the proceedings at FERC can be predicted at this time. In January 2003 the domestic utility companies filed testimony in the case, showing that over the life of the System Agreement the relative production costs of the domestic utility companies are roughly equal, and suggesting that no changes to the System Agreement such as those sought by the LPSC and the Council are appropriate.  On March 13, 2003, Entergy New Orleans and the Advisors to the City Council presented to the Council an agreement in principle that, if approved by the Council, would resolve Entergy New Orleans' pending rate proceeding. The agreement in principle, if approved by the Council, would result in the Council withdrawing as a complainant in the FERC proceeding. A procedural schedule for the City Council's consideration of the agreement in principle has not been established.

                The LPSC has instituted a companion ex parte System Agreement investigation to litigate several of the System Agreement issues that the LPSC is litigating before the FERC in the previously discussed System Agreement proceeding. This companion proceeding will require the LPSC to interpret various provisions of the System Agreement, including those relating to minimum run and must run units, the propriety of the methods used for billing and dispatch on the Entergy System, and the use of a rolling, twelve-month average of system peaks for allocating certain costs. In addition, by this companion proceeding the LPSC is questioning whether Entergy Louisiana and Entergy Gulf States were prudent for not seeking changes to the System Agreement previously, so as to lower costs imposed upon their ratepayers and to increase costs imposed upon ratepayers of other domestic utility companies. The LPSC staff has filed testimony suggesting that the remedy for the alleged imprudence of Entergy Louisiana and Entergy Gulf States should be a reduction in allowed rate of return on common equity of 100 basis points. The domestic utility companies have challenged the propriety of the LPSC's litigating System Agreement issues. Nevertheless, on January 16, 2002 the LPSC affirmed a decision of its ALJ upholding the LPSC staff's right to litigate System Agreement issues at the LPSC, rather than before the FERC. In September 2002, the LPSC staff filed a motion to delay hearing and remaining pre-hearing deadlines. After no objections from the other parties, the LPSC ALJ continued the procedural schedule until after the FERC ALJ's initial decision in the related matter, or June 13, 2003, whichever occurs first.

System Energy

                System Energy recovers costs related to its interest in Grand Gulf 1 through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In December 1995, System Energy implemented a $65.5 million rate increase, subject to refund. In July 2001, the rate increase proceeding became final, with FERC approving a prospective 10.94% return on equity, which is less than System Energy sought. FERC's decision also affected other aspects of System Energy's charges to the domestic utility companies that it supplies with power. In 1998, FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas' acceleration of Grand Gulf purchased power obligations ceased effective July 2001, as approved by FERC. The rate increase request filed by System Energy with FERC and the Grand Gulf accelerated recovery tariffs are discussed in Note 2 to the financial statements.

Unit Power Sales Agreement

                The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy's 90% ownership and leasehold interests in Grand Gulf 1 to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered, so long as Grand Gulf 1 remains in commercial operation. Payments under the Unit Power Sales Agreement are System Energy's only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf 1 and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers. In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf 1. The retained shares are discussed in Note 2 to the domestic utility companies and System Energy financial statements under the heading "Grand Gulf 1 Deferrals and Retained Shares."

Availability Agreement

                The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the financing by System Energy of Grand Gulf. The Availability Agreement provided that System Energy join in the System Agreement on or before the date on which Grand Gulf 1 was placed in commercial operation and make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy's share of Grand Gulf.

                Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy's total operating expenses for Grand Gulf (including depreciation at a specified rate) and interest charges. The September 1989 write-off of System Energy's investment in Grand Gulf 2, amounting to approximately $900 million, is being amortized for Availability Agreement purposes over 27 years.

                The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.

                System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for its first mortgage bonds and reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 10 to the financial statements under "Sale and Leaseback Transactions - Grand Gulf 1 Lease Obligations." In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.

                Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.

                The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to FERC for approval with respect to the terms of such sale. No such filing with FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to FERC for approval. Other aspects of the Availability Agreement are subject to the jurisdiction of the SEC, whose approval has been obtained, under PUHCA.

                Since commercial operation of Grand Gulf 1 began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement. Therefore, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.

                The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.

Capital Funds Agreement

                System Energy and Entergy Corporation have entered into the Capital Funds Agreement, whereby Entergy Corporation has agreed to supply System Energy with sufficient capital to (i) maintain System Energy's equity capital at an amount equal to a minimum of 35% of its total capitalization (excluding short-term debt) and (ii) permit the continued commercial operation of Grand Gulf 1 and pay in full all indebtedness for borrowed money of System Energy when due.

                Entergy Corporation has entered into various supplements to the Capital Funds Agreement. System Energy has assigned its rights under such supplements as security for its first mortgage bonds and for reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 10 to the financial statements under "Sale and Leaseback Transactions - Grand Gulf 1 Lease Obligations." Each such supplement provides that permitted indebtedness for borrowed money incurred by System Energy in connection with the financing of Grand Gulf may be secured by System Energy's rights under the Capital Funds Agreement on a pro rata basis (except for the Specific Payments, as defined below). In addition, in the supplements to the Capital Funds Agreement relating to the specific indebtedness being secured, Entergy Corporation has agreed to make cash capital contributions directly to System Energy sufficient to enable System Energy to make payments when due on such indebtedness (Specific Payments). However, if there is an event of default, Entergy Corporation must make those payments directly to the holders of indebtedness benefiting from the supplemental agreements. The payments (other than the Specific Payments) must be made pro rata according to the amount of the respective obligations benefiting from the supplemental agreements.

                The Capital Funds Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, upon obtaining the consent, if required, of those holders of System Energy's indebtedness then outstanding who have received the assignments of the Capital Funds Agreement.

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

                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 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 are participating with other transmission owners within the southeastern United States to establish an RTO, the proposed SeTrans RTO. In October 2002, FERC issued a declaratory order approving certain central aspects of the SeTrans RTO proposal, including the governance structure, the transmission pricing policy, the business model, and the selection process for the Independent System Administrator. The FERC order states that the FERC will not revisit certain findings made in the SeTrans docket if inconsistencies exist between those findings and the final rules issued in the standardized market design proceeding discussed immediately below.

                Because of retail regulatory concerns regarding RTOs generally, Entergy was required to perform a cost-benefit study of the domestic utility companies' participation in an RTO. Separately, the Southeast Association of Regulatory Utility Commissions (SEARUC) requested a cost-benefit study be performed analyzing the effects on the entire southeastern United States, including the SeTrans region. Both the Entergy cost-benefit study and the SEARUC study confirm that a properly structured RTO including proper transmission pricing can provide benefits for Entergy and the area covered by SeTrans.

                A number of important issues relating to the design of the transmission tariffs and the terms of the proposed SeTrans RTO remain to be finalized and approved by regulators. At this time, Entergy does not expect the proposed SeTrans RTO to become operational before the end of 2004.

                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 to an ITC (independent transmission company) or any similar organization, asserting that FERC does not have jurisdiction to mandate an ITC or RTO. A settlement was reached with the LPSC staff and adopted by the LPSC that requires, among other things, that when Entergy files with the FERC to participate in an RTO, it will request a transfer of control of transmission assets and, as an alternative, request a transfer of ownership of those assets to an ITC.

FERC Notice of Proposed Rulemaking - Standard Market Design (Entergy, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans)

                On July 31, 2002, FERC issued a notice of proposed rulemaking to establish a standardized transmission service and wholesale electric market design (SMD NOPR). The proposed rules would

    • establish a network access transmission service applicable to all transmission users;
    • require utilities to take the transmission component of bundled transmission service under an open access transmission tariff;
    • require transmission facilities to be operated by an independent transmission provider;
    • require that the independent transmission provider administer the day-ahead and real-time energy and ancillary services markets;
    • establish an access charge for embedded transmission costs;
    • use location marginal pricing for transmission congestion management and provide tradable congestion revenue rights;
    • establish open imbalance energy markets;
    • establish procedures to mitigate market power in the day-ahead and real-time markets
    • require under certain conditions that generation owners submit offers to supply energy at prices that do not exceed specified price ceilings; and
    • establish procedures to assure adequate transmission, generation and demand-side resources.

                Comments on the proposed rule were filed in mid-November 2002 and mid-January 2003. Reply comments on all issues are due in February 2003. Several technical conferences on the issues contained in the SMD NOPR were also held during November and December 2002. Some of the retail regulators in Entergy's service territory have publicly expressed opposition to the proposed rulemaking. In a recent letter sent to the Chairman of the FERC, retail regulators from Alabama, Arkansas, Florida, Georgia, Kentucky, Louisiana, North Carolina South Carolina, Tennessee, and Virginia expressed their belief that an "incremental and voluntary approach" to RTO formation and wholesale market development is necessary and appropriate for the Southeast. In the letter, the retail regulators identified certain threshold issues that FERC must commit to (including, among other things, a commitment that the FERC would not assert jurisdiction over the transmission component of bundled retail service, that native load customers would retain the same or equivalent rights to use the transmission system as they have today, the immediate implementation of participant funding, and RTO formation should be supported by evidence that the costs of RTO formation are outweighed by the benefits) prior to further detailed discussions between the FERC and retail regulators concerning the development of RTOs and SMD. The retail regulators requested that FERC modify the current SMD proposal to recognize these commitments. A similar letter was submitted separately by retail regulators from Mississippi. It is anticipated that the FERC will issue a white paper addressing these and other issues contained in the SMD during the spring of 2003, with the final rule issued during the latter part of the summer of 2003.

                Separately, the conference report on the Fiscal Year 2003 Omnibus Appropriations bill signed into law contains language directing the Department of Energy to prepare an independent analysis of the effect of the proposed SMD rule on wholesale and retail electric prices, the safety and reliability of generation and transmission facilities, and state utility regulation. The report is to be submitted no later than April 30, 2003.

Interconnection Orders

                On January 28 and 29, 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 also may file complaints to obtain the same or similar relief. In the event that the generators that have interconnected to the Entergy transmission system are successful in obtaining such relief, it is 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 February 18, 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 assigning 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.

FERC's Market Power Screen

                In November 2001, FERC issued an order that established a new generation market power screen 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. FERC announced it will convene a technical conference prior to issuing a rehearing order.

Generator Operating Limits proceeding

                In June 2002 Entergy filed with FERC proposed Generator Operating Limit ("GOL") procedures to address local transmission constraints on the domestic utility companies' transmission system and to provide a process for generators interconnected to the transmission system to participate in short-term bulk power markets without first submitting each proposed transaction for a study. On August 2002, FERC issued an order accepting the proposed GOL procedures for filing, subject to a suspension period of five months and a final FERC order on the merits. FERC also required that prior to a final order a technical conference be held to further examine the initial GOL filing. Following the technical conference, Entergy submitted comments proposing to revise the initial GOL procedures in response to the various concerns raised during the technical conference. Certain intervenors in the proceeding filed comments opposing the proposed GOL procedures as anticompetitive and discriminatory alleging, among other things, that Entergy does not dispatch its system in the most economically efficient manner because it is attempting to protect its own generation from competition with the newer, more efficient independent generation on its system, and that Entergy's GOL proposal exacerbates Entergy's already existing market power by (a) fostering Entergy's ability to engage in uneconomic dispatch; (b) reducing the supply into, and liquidity of, short-term firm transmission markets; (c) forcing generators into the short-term non-firm market; and (d) impairing independent generators' ability to maximize their revenue streams. The intervenors further allege that Entergy's GOL proposal will distress independent generators, allowing Entergy to acquire such generators at "bargain prices." In its responsive documents, Entergy strongly denied these allegations and explained that the allegations found no basis in fact. In December 2002, FERC concluded that Entergy's proposal to revise its GOL procedures, in effect, superseded the initial GOL filing and required additional detail and specification, including tariff sheets that implement the proposed revisions. FERC directed Entergy to refile the proposal described in its comments. Entergy submitted its GOL procedures for short-term firm transmission service for exports off the Entergy transmission system on January 15, 2003, which filing the FERC approved on March 13. FERC found that the proposal represented a reasonable balance between ensuring the reliability of the transmission grid and the requirement to make transmission capacity available on a non-discriminatory basis. Entergy filed GOL procedures in late-February 2003 concerning short-term firm transmission service for transactions internal to the Entergy control area. That portion of the GOL procedures is still pending before the FERC. Entergy is required to monitor the effectiveness of the GOL proposal over the summer peak period and to report the results to the FERC later in 2003.

 

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 formula rate plans are designed to encourage efficiencies and productivity while permitting utilities and their customers to share in the benefits. Entergy Mississippi and Entergy Louisiana 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
2002 Revenues Derived from
Retail Electric Utility Operations
in the Jurisdiction

Arkansas

Retail open access was repealed in February 2003.

14.5%

Texas

Implementation delayed in Entergy Gulf States' service area in a settlement approved by PUCT. Retail open access not likely before the first quarter of 2004.

10.4%

Louisiana

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

33.5%

Mississippi

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

10.6%

New Orleans

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

5%

Retail Rate Proceedings

                Each domestic utility operating subsidiary participates in retail rate proceedings on a consistent basis. The status of material retail rate proceedings are 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.

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, which is currently expected not to occur until at least the first quarter of 2004.

Entergy Gulf
   States-Louisiana

11.1%

The LPSC approved a settlement in December 2002 resolving the 4th - 8th post-merger earnings reviews resulting in a $22.1 million prospective rate reduction effective January 2003 and a refund of $16.3 million. Also, the 9th earnings analysis (2002), the last required post-merger earnings analysis, and prospective revenue study are currently pending before the LPSC with hearings set for October 2003. In conjunction with the LPSC staff, Entergy Gulf States is currently pursuing a formula rate plan proposal.

Entergy Louisiana

9.7%-

11.3%(1)

The LPSC approved a settlement in July 2002 covering the 5th and 6th annual rate reviews and future rate regulation that included a small rate reduction and reaffirmed the ROE midpoint of 10.5%. Entergy Louisiana's current rates will remain in effect until changed pursuant to a new formula rate plan filing or revenue analysis to be filed by June 30, 2003. In conjunction with the LPSC staff, Entergy Louisiana is currently pursuing a formula rate plan proposal.

Entergy Mississippi

10.64%-

12.86%(2)

An annual formula rate plan is in place. In December 2002, the MPSC approved a joint stipulation that resulted in a $48.2 million rate increase and an ROE midpoint of 11.75%. Entergy Mississippi will make its next formula rate plan filing in March 2004.

Entergy New
   Orleans

11.4%

Rate case filed with the City Council in May 2002 requesting a rate increase of $44 million. An agreement in principle reached in March 2003 with the Advisors to the City Council would result in a $30 million base rate increase, if approved by the City Council. A decision is expected in mid-2003.

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. If Entergy Mississippi earns outside of the bandwidth range, rates will be adjusted on a prospective basis. If earnings are above the bandwidth range, rates are reduced by 50 percent of the overage, and if below, increased by 50 percent of the shortfall. The range presented is not adjusted for performance measures, under which the ROE midpoint can increase or decrease by as much as 1%.

Entergy Arkansas

Recovery of Grand Gulf 1 Costs

                Under the settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its share of Grand Gulf 1 costs and recovers the remaining 78% of its share through rates. Under the Unit Power Sales Agreement, Entergy Arkansas' share of Grand Gulf 1 costs is 36%. In the event Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas' cost from the retained share.

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 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

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 has appealed that ruling to the Third District Court of Appeals. 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 are 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 2004, fuel and purchased power cost recovery will be subject to the fuel component of the price-to-beat rates approved by the PUCT.

                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. 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 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

Recovery of Grand Gulf 1 Costs

                In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted rate relief with respect to costs associated with Entergy Louisiana's share of capacity and energy from Grand Gulf 1, subject to certain terms and conditions. Under the Unit Power Sales Agreement, Entergy Louisiana's share of Grand Gulf 1 costs is 14%. In November 1988, Entergy Louisiana agreed to retain 18% of its share of Grand Gulf 1 costs and recover the remaining 82% of its share through rates. Non-fuel operation and maintenance costs for Grand Gulf 1 are recovered through Entergy Louisiana's base rates. Additionally, Entergy Louisiana is allowed to recover, through the fuel adjustment clause, 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to nonaffiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC's approval.

Performance-Based Formula Rate Plan

                Negotiations with the LPSC staff and advisors for a statewide formula rate plan in Louisiana are ongoing.

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.

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. The formula rate plan filing for the 2001 test year is discussed in Note 2 to the domestic utility companies and System Energy financial statements. In accordance with the MPSC's December 2002 rate order, there will be no formula rate plan filing in 2003 for the 2002 test year. The next formula rate plan 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 is utilizing 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.

Entergy New Orleans

Recovery of Grand Gulf 1 Costs

                Under Entergy New Orleans' various rate settlements with the Council in 1986, 1988, and 1991, Entergy New Orleans agreed to absorb and not recover from ratepayers a total of $96.2 million of its Grand Gulf 1 costs. Entergy New Orleans was permitted to implement annual rate increases in decreasing amounts each year through 1995, and to defer certain costs and related carrying charges for recovery on a schedule extending from 1991 through 2001.

Fuel Recovery

                Entergy New Orleans' electric rate schedules include a fuel adjustment clause designed to recover the cost of fuel, 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. 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, in addition to carrying charges. The Council is currently studying Entergy New Orleans' fuel adjustment methodologies, with the intention of considering means of mitigating the effect on ratepayers of sudden increases in fuel costs. The resolution commencing the study notes that the Council does not intend to deny Entergy New Orleans full recovery of its prudently incurred fuel and purchased power costs.

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

General

                Entergy Arkansas is subject to regulation by the APSC, which includes the authority to:

    • oversee utility service;
    • set rates;
    • determine reasonable and adequate service;
    • require proper accounting;
    • control leasing;
    • control the acquisition or sale of any public utility plant or property constituting an operating unit or system;
    • set rates of depreciation;
    • issue certificates of convenience and necessity and certificates of environmental compatibility and public need; and
    • regulate the issuance and sale of certain securities.

                Entergy Gulf States may be subject to the jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Gulf States' Texas business is also subject to regulation by the PUCT as to:

    • retail rates and service in rural areas;
    • customer service standards;
    • certification of new transmission lines; and
    • extensions of service into new areas.

                Entergy Gulf States' Louisiana electric and gas business and Entergy Louisiana are subject to regulation by the LPSC as to:

    • utility service;
    • rates and charges;
    • certification of generating facilities;
    • power or capacity purchase contracts; and
    • depreciation, accounting, and other matters.

                Entergy Louisiana is also subject to the jurisdiction of the Council with respect to such matters within Algiers in Orleans Parish.

                Entergy Mississippi is subject to regulation by the MPSC as to the following:

    • utility service;
    • service areas;
    • facilities; and
    • retail rates.

                Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.

                Entergy New Orleans is subject to regulation by the Council as to the following:

    • utility service;
    • rates and charges;
    • standards of service;
    • depreciation, accounting, and issuance and sale of certain securities; and
    • other matters.

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 approximately one incorporated municipality 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.

Environmental Regulation

                Entergy's facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that its affected companies are in substantial compliance with environmental regulations currently applicable to their facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Clean Air Act Amendments of 1990

                The Clean Air Act Amendments of 1990 (the Act) established the following four programs that currently or in the future may affect Entergy's fossil-fueled generation:

    • an acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx);
    • an ozone non-attainment area program for control of NOx and volatile organic compounds;
    • a hazardous air pollutant emissions reduction program; and
    • an operating permits program for administration and enforcement of these and other Act programs.

                The Act provides SO2 allowances to most of the affected Entergy generating units for emissions based upon past emission levels and operating characteristics. Each allowance is an entitlement to emit one ton of SO2 per year. Utilities are required to possess allowances for SO2 emissions from affected generating units. All Entergy fossil-fueled generating units are subject to SO2 allowance requirements. Entergy is a net buyer of allowances when it generates power using fuel oil.

                Controls were recently implemented at certain Entergy Gulf States generating units to achieve NOx reductions due to the ozone non-attainment status of areas served in and around Beaumont and Houston, Texas. To date, the cost of additional control equipment necessary to maintain this compliance is not material. In April and December 2000, Texas authorities adopted future ozone control strategies for the Beaumont and Houston areas, respectively, and EPA approved these strategies. In December 2002, the Houston area control strategy was revised. The strategy for the Beaumont area included an ozone level attainment date extension based on the transport of ozone precursor emissions from the Houston area. In December 2002, the U.S. Court of Appeals for the Fifth Circuit invalidated the attainment date extension, and to date no replacement strategy has been adopted. Even before this recent invalidation, the strategies adopted by the State of Texas will cause Entergy Gulf States to incur additional costs for NOx controls. Installation of equipment is well along and will be complete in 2005. Prior to the recent invalidation of the Beaumont area attainment date extension, Entergy estimated compliance costs to be $11 to $26 million in the Beaumont area and approximately $15 million in the Houston area. The Beaumont compliance costs will have to be reevaluated when the State of Texas adopts a replacement strategy. As part of legislation passed in Texas in June 1999 to restructure the electric power industry in the state, certain generating units of Entergy Gulf States will be required to obtain operating permits and meet new, lower emission limits for NOx. Entergy believes the control strategies in the ozone non-attainment regulations include emission limits that are more restrictive than those related to utility restructuring. Thus, Entergy Gulf States is expected to incur costs through 2003 to meet the standards in the restructuring legislation within its overall project of meeting the non-attainment regulations.

                The State of Louisiana has developed a new emission control strategy to address continued ozone non-attainment status of areas in and around Baton Rouge, Louisiana. Implementation of the strategy has been challenged in separate court actions by an environmental organization and by an unaffiliated electric generating company. More specifically, in August 2002, the LDEQ issued a rule for control of NOx as part of the State Implementation Plan (SIP) to bring this area into attainment with the National Ambient Air Quality standards for ozone by 2005. The rule is expected to lead to installation of new NOx control equipment at Entergy Gulf States generating units. The latest analyses indicate compliance costs at these units may be as much as $12 million in new capital spending from 2003 into early 2005. Cost estimates will be refined as engineering studies progress. Entergy Gulf States will be required to obtain revised operating permits from the LDEQ and meet new, lower emission limits for NOx.

                In September 2002, the EPA approved revisions to the SIP that address NOx control. In October 2002, the EPA then approved the entire ozone attainment demonstration SIP for the Baton Rouge area. In conjunction with this approval, the EPA extended the ozone attainment date to November 15, 2005, while retaining the area's current classification as a serious ozone non-attainment area. In November 2002, the Louisiana Environmental Action Network (LEAN) filed a Petition for Judicial Review of the EPA's approval of the Baton Rouge SIP with the U.S. 5th Circuit Court of Appeals challenging several aspects including the attainment date extension and the withdrawal of non-attainment determination and reclassification. In December 2002, the U.S. 5th Circuit Court of Appeals invalidated an ozone attainment date extension approved by the EPA for the Beaumont/Port Arthur area. It is not certain at this time what impact this ruling or the Petition for Judicial Review filings will have upon the new Baton Rouge emission control strategy at Entergy Gulf States.

                In December 2000, the EPA made a determination that coal and oil-fired steam electric generating units should be regulated under the section of the Clean Air Act relating to emissions of hazardous air pollutants ("HAPs"). The principal HAPs of concern are mercury from coal and nickel from oil. EPA is in the process of developing the regulations for these sources and has set a deadline of December 2004 for finalizing the rules. Entergy owns units that would be subject to these regulations. The regulations may require coal and oil-fired units to reduce mercury and nickel emissions through various methods, including installation of controls, switching fuels or fuel suppliers, reduced utilization of units or some combination of these methods. The earliest expected compliance date for this rule would be 2008 and could be extended for an additional year.

                In addition to the specific instances described above, there are a number of legislative and regulatory initiatives relating to the reduction of emissions that are under consideration at the federal, state, and international level. Because of the nature of Entergy's business, the adoption of each of these could effect its operations. These initiatives include:

    • designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
    • introduction of several bills in Congress proposing further limits on NOx, SO2, mercury, or limits on carbon dioxide (CO2) emissions; and
    • pursuit by the Bush administration of a voluntary program intended to reduce CO2 emissions.

Entergy continues to monitor these actions in order to analyze their potential operational and cost implications. In anticipation of the potential imposition of CO2 emission limits on the electric industry in the future, Entergy has initiated actions designed to reduce its exposure to potential new governmental requirements related to CO2 emissions. These actions include establishment of a formal program to stabilize power plant CO2 emissions at year 2000 levels through 2005 and support for national legislation that would increase planning certainty for electric utilities while addressing emissions in a responsible and flexible manner. By virtue of its proportionally large investment in low or non-emitting gas-fired and nuclear generation technologies, Entergy's overall CO2 emission "intensity," or rate of CO2 emitted per kilowatt-hour of electricity generated, is already among the lowest in the industry. Total carbon dioxide emissions representing the company's ownership share of power plants in the United States were approximately 53.24 million tons in 2000, 49.58 million tons in 2001, and 44.20 million tons in 2002.

Clean Water Act

                The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act or CWA) provide the statutory basis for the National Pollutant Discharge Elimination System (NPDES) permit program and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The CWA requires anyone who wants to discharge pollutants to first obtain an NPDES permit, or else that discharge will be considered illegal. The EPA recently proposed draft regulations for existing power plants, including certain electric generating stations employing once-through cooling technology (the draft Rule). The draft Rule seeks to reduce perceived impacts on aquatic resources by requiring covered facilities to take steps to implement technology or other measures to meet EPA-targeted reductions in water use and corresponding perceived aquatic impacts. While the draft Rule is the subject of extensive comment and also is expected to be challenged (which may result in changes to it prior to final promulgation), Entergy currently has begun and will continue to evaluate the draft Rule, including by considering options for complying with the draft Rule if promulgated in substantially its current form. Those options considered may include operational controls, the installation of equipment to address perceived aquatic impacts, and other mitigation measures, or combinations of these alternatives.

Oil Pollution Prevention Regulation

                The EPA published a revised Oil Pollution Prevention regulation in July 2002. The regulation affects Entergy's operation of its approximately 3,500 transmission and distribution electrical equipment installations that are potentially subject to the rule. While the published rule provides a great deal of flexibility to the regulated community insofar as allowable strategies, it also provides the EPA discretion in evaluation of compliance with the rule. The EPA Oil Program Headquarters staff is currently in the process of training the EPA Regions on the rule and its enforcement. Entergy is currently working directly with the EPA Oil Program Headquarters staff to have Entergy's electrical equipment oil pollution prevention strategy formally recognized as an industry standard.

Comprehensive Environmental Response, Compensation, and Liability Act of 1980

                The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA and, indirectly, the states, to mandate clean-up, or reimbursement of clean-up costs, by owners or operators of sites from which hazardous substances may be or have been released. Parties that generated or transported hazardous substances to these sites are also deemed liable by CERCLA. CERCLA has been interpreted to impose joint and several liability on responsible parties. The domestic utility companies have sent waste materials to various disposal sites over the years. In addition, environmental laws now regulate certain of the companies' operating procedures and maintenance practices which historically were not subject to regulation. Some of Entergy's disposal sites have been the subject of governmental action under CERCLA, resulting in site clean-up activities. The domestic utility companies have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected companies have established reserves for such environmental clean-up and restoration activities.

 

Other Environmental Matters

Entergy Arkansas

                Entergy Arkansas is currently involved in litigation relating to contamination at a site near Rison, Arkansas, which has been placed on the state Superfund list. The site was operated by Utilities Services, Inc. Neither Entergy Arkansas nor any other Entergy-affiliated company ever owned or operated the site. Entergy Arkansas had contracted with Utilities Services, Inc., to perform transformer and bushing repairs which involved filtering oil at various transformer sites. Hazardous substances found in the soil and in containers and drums at the site included polychlorinated biphenyls (PCBs) and pentachlorophenol (a wood preservative). The litigation is currently pending before the Arkansas Supreme Court on an appeal from the decision of the trial court to dismiss the complaint that had been filed against Entergy Arkansas and other defendants seeking declaratory and injunctive relief holding the defendants liable for having dispensed hazardous substances at the site and requiring remediation. In the light of the trial court's decision, Entergy Arkansas will not be liable for remediation of the site unless the trial court's order is overturned on appeal or it is adjudicated to be liable.

                Entergy Arkansas spent approximately $380,000 in its efforts to stabilize the site and has a claim against the State Trust Fund for reimbursement. The amount of clean-up costs associated with the site cannot be accurately determined until a site characterization has been performed, but it is estimated that such costs will be at least $5 million.

                During November 2002, Entergy Arkansas received notice from EPA Region IV that it is considered to be a PRP for the Industrial Pollution Control Site located in Jackson, Mississippi. The business operated a waste oil and water recycling facility from 1991 until 1997. Industrial Pollution Control, Inc. filed for Chapter 11 bankruptcy in 1997. In 1999, EPA began a removal response action and currently believes that no further clean up is needed. Entergy Arkansas is in the initial stages of addressing its liability in this site, but believes, based on information provided by EPA, that its share could be as much as $450,000.

Entergy Gulf States

                Several class action and other suits have been filed in state and federal courts seeking relief from Entergy Gulf States and others for damages caused by the disposal of hazardous waste and for asbestos-related disease allegedly resulting from exposure on Entergy Gulf States' premises (see "Litigation" below).

                Entergy Gulf States is currently involved in a remedial investigation of the Lake Charles Service Center site, located in Lake Charles, Louisiana. A manufactured gas plant (MGP) is believed to have operated at this site from approximately 1916 to 1931. Coal tar, a by-product of the distillation process employed at MGPs, was apparently routed to a portion of the property for disposal. The same area has also been used as a landfill. In 1999, Entergy Gulf States signed a second Administrative Consent Order with the EPA to perform removal action at the site. In 2002, approximately 7,400 tons of contaminated soil and debris were excavated and disposed of from an area within the service center. A ten-year groundwater monitoring program will begin in 2003. Entergy Gulf States believes that its ultimate responsibility for this site will not materially exceed its existing clean-up provision of $11.9 million.

                In 1994, Entergy Gulf States performed a site assessment in conjunction with a construction project at the Louisiana Station Generating Plant (Louisiana Station). In 1995, a further assessment confirmed subsurface soil and groundwater impact to three areas on the plant site. After further review, a notification was made to the LDEQ. The final phase of groundwater clean up and monitoring at Louisiana Station is expected to continue through 2005. The remediation cost incurred through December 31, 2002 for this site was $6.4 million. Future costs are not expected to exceed the existing provision of $1.1 million.

 

Entergy Louisiana and Entergy New Orleans

                Several class action and other suits have been filed in state and federal courts seeking relief from Entergy Louisiana and Entergy New Orleans and others for damages caused by the disposal of hazardous waste and for asbestos-related disease allegedly resulting from exposure on Entergy Louisiana's and Entergy New Orleans' premises (see "Litigation" below).

                The Southern Transformer Shop located in New Orleans served both Entergy Louisiana and Entergy New Orleans. This transformer shop is now closed and environmental assessments are being performed and communications with EPA and LDEQ are underway to determine what remediation may be necessary. Based on preliminary findings, an expected clean-up cost of $750,000 has been reserved for this project.

                During 1993, the LDEQ issued new rules for solid waste regulation, including regulation of wastewater impoundments. Entergy Louisiana and Entergy New Orleans have determined that certain of their power plant wastewater impoundments were affected by these regulations and chose to remediate and repair or close them. Completion of this work is pending LDEQ approval. LDEQ has issued notices of deficiencies for certain of these sites. As a result, recorded liabilities in the amounts of $5.8 million for Entergy Louisiana and $0.5 million for Entergy New Orleans existed at December 31, 2002 for wastewater remediation and repairs and closures. Management of Entergy Louisiana and Entergy New Orleans believes these reserves are adequate based on current estimates.

Litigation

                Certain states in which Entergy operates, in particular Louisiana, Mississippi, and Texas, have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment in these states poses a significant business risk.

Ratepayer Lawsuits (Entergy Corporation, Entergy Gulf States, Entergy Louisiana, and Entergy New Orleans)

Vidalia Project Sub-Docket

                Marathon Oil Company and Louisiana Energy Users Group, intervenors in another proceeding that has since been settled, requested that the LPSC review the prudence of a contract entered into by Entergy Louisiana to purchase energy generated by a hydroelectric facility known as the Vidalia project through the year 2031. Note 9 to the domestic utility companies and System Energy financial statements contains further discussion of the obligations related to the Vidalia project. By orders entered by the LPSC in 1985 and 1990, the LPSC approved Entergy Louisiana's entry into the Vidalia contract and Entergy Louisiana's right to recover from its customers, through the fuel adjustment clause, the costs of power purchased thereunder. Additionally, the wholesale electric rates under the Vidalia power purchase contract were filed at FERC. In December 1999, the LPSC instituted a review of the following issues relating to the Vidalia project: (i) the LPSC's jurisdiction over the Vidalia project; (ii) Entergy Louisiana's management of the Vidalia contract, including opportunities to restructure or otherwise reform the contract; (iii) the appropriateness of Entergy Louisiana's recovery of 100% of the Vidalia contract costs from ratepayers; (iv) the appropriateness of the fuel adjustment clause as the method for recovering all or part of the Vidalia contract costs; (v) the appropriate regulatory treatment of the Vidalia contract in the event the LPSC approves implementation of retail competition; and (vi) Entergy Louisiana's communication of pertinent information to the LPSC regarding the Vidalia project and contract.

                In September 2002, the LPSC approved a settlement of the proceeding and concluded the Vidalia project subdocket. The settlement is based on Entergy Louisiana sharing with Entergy Louisiana customers a portion of the benefits of a tax deduction that became available when Entergy Louisiana elected to mark the Vidalia contract to market for tax accounting purposes. The tax benefit sharing is described in more detail in Entergy's "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources" under the heading "Entergy Louisiana Tax Accounting Election." Three issues are not addressed by the settlement, but there is no proceeding pending before the LPSC at this time to consider them. Those issues are: (i) the LPSC's jurisdiction over the Vidalia project; (ii) the appropriateness of Entergy Louisiana's recovery of 100% of the Vidalia contract costs from customers; and (iii) the appropriate regulatory treatment of the Vidalia contract in the event the LPSC approves implementation of retail competition.

Entergy New Orleans Fuel Clause Lawsuit

                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. At present, the suit in state court is stayed by stipulation of the parties.

                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 in April 2000 and has been supplemented. The testimony, as supplemented, asserts, 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. In June 2001, the City Council's advisors filed testimony on these issues in which they allege that Entergy New Orleans ratepayers may have been overcharged by more than $32 million, the vast majority of which is reflected in the plaintiffs' claim. However, it is not clear precisely what periods and damages are being alleged in the proceeding. Entergy intends to defend this matter vigorously, both in court and before the City Council. Hearings were held in February and March 2002. The parties have submitted post-hearing briefs and the matter has been submitted to the City Council for a decision. In October 2002, the plaintiffs filed a motion to re-open the evidentiary record, or in the alternative, a motion for a new trial seeking to re-open the record to accept certain testimony filed by the City Council advisors in a separate proceeding at the FERC. The ultimate outcome of the lawsuit and the City Council proceeding cannot be predicted at this time.

Entergy New Orleans Rate of Return Lawsuit

                In April 1998, a group of residential and business ratepayers filed a complaint against Entergy New Orleans in state court in Orleans Parish purportedly on behalf of all ratepayers in New Orleans. The plaintiffs allege that Entergy New Orleans overcharged ratepayers by at least $300 million since 1975 in violation of limits on Entergy New Orleans' rate of return that the plaintiffs allege were established by ordinances passed by the Council in 1922. The plaintiffs seek, among other things, (i) a declaratory judgment that such franchise ordinances have been violated; and (ii) a remand to the Council for the establishment of the amount of overcharges plus interest. Entergy New Orleans believes the lawsuit is without merit. Entergy New Orleans has charged only those rates authorized by the Council in accordance with applicable law. In May 2000, a court of appeal granted Entergy New Orleans' exception to jurisdiction in the case and dismissed the proceeding. The Louisiana Supreme Court denied the plaintiff's request for a writ of certiorari. The plaintiffs then commenced a similar proceeding before the Council. The plaintiffs and the advisors for the Council each filed their first round of testimony in January 2002. In their testimony, the plaintiffs allege that Entergy New Orleans earned in excess of the legally authorized rate of return during the period 1979 to 2000 and that Entergy New Orleans should be required to refund between $240 million and $825 million to its ratepayers. In the testimony submitted by the Council advisors, the advisors allege that Entergy New Orleans has not earned in excess of its authorized rate of return for the period at issue and that no refund is therefore warranted. A hearing scheduled in June 2002 was canceled and the proceeding has been continued without a proposed trial date.

Entergy Gulf States Merger Savings Lawsuit

                In February 2002, various plaintiffs, who claim to be customers of Entergy Gulf States in Texas and further claim to be class representatives for all other similarly situated customers, filed a lawsuit against Entergy Gulf States and Entergy Corporation in the district court of Jefferson County, Texas. The petition alleges that Entergy Corporation and Entergy Gulf States violated the 1993 agreement entered by parties to the Entergy-Gulf States Utilities merger docket in Texas by failing to pass 100% of Texas retail non-fuel merger-related savings to Entergy Gulf States' ratepayers in Texas beginning on January 1, 2002. The petition alleges that the non-fuel merger-related savings accrue at a rate of about $2 million per month. The petition seeks damages, exemplary damages, and attorney's fees and costs, in addition to certification of the case as a class action. The district court has denied Entergy Gulf States' and Entergy Corporation's motions to transfer venue and to dismiss or abate on the basis of the PUCT's jurisdiction over this matter. In September 2002, Entergy Gulf States and Entergy Corporation sought mandamus relief at the Ninth District Court of Appeals which was denied. After the Court of Appeals denied rehearing, in January 2003, Entergy Corporation and Entergy Gulf States filed a petition for mandamus relief at the Texas Supreme Court. Proceedings have been stayed in the district court pending the decision in the mandamus application. Management cannot predict the outcome of this litigation at this time.

Entergy Louisiana Formula Ratemaking Plan Lawsuit

                In May 1998, a group of ratepayers filed a complaint against Entergy Louisiana and the LPSC in state court in East Baton Rouge Parish purportedly on behalf of all Entergy Louisiana ratepayers. The plaintiffs allege that the formula ratemaking plan authorized by the LPSC has allowed Entergy Louisiana to earn amounts in excess of a fair return. The plaintiffs seek, among other things, (i) a declaratory judgment that the formula ratemaking plan is an improper ratemaking practice; and (ii) a refund of the amounts allegedly charged in excess of proper ratemaking practices. Entergy Louisiana believes the lawsuit is without merit and plans to vigorously defend itself. This case has not been active, and abandonment issues are being evaluated. At this time, management cannot determine the amount of damages being sought.

Street Lighting Lawsuit (Entergy New Orleans)

                In February 2002, the City of New Orleans (City) filed a petition against Entergy New Orleans in state court in Orleans Parish, seeking declaratory relief, injunctive relief, an unspecified amount of monetary damages, and attorney and consulting fees and costs. The City's petition alleged that Entergy New Orleans had breached its obligations to the City related to the provision of street lighting maintenance services. After mediation, the City dismissed its lawsuit with prejudice on October 28, 2002, and any amounts that may be owed by Entergy New Orleans will be determined by an independent third party audit. Management believes that Entergy New Orleans does not owe the City any net amount under the street lighting contract, and will vigorously assert its rights in the audit.

Murphy Oil Lawsuit (Entergy Corporation and Entergy Louisiana)

                Residents located near the Murphy Oil Refinery in Meraux, Louisiana filed several lawsuits in state court in St. Bernard Parish, Louisiana against Murphy Oil, Entergy Louisiana, and others for injuries they allegedly suffered as a result of an explosion at the refinery in June 1995. The lawsuits were consolidated and a class of plaintiffs was certified. Plaintiffs alleged, among other things, that an electrical fault at an Entergy Louisiana substation contributed to causing the explosion. Murphy Oil filed a cross-claim against Entergy Louisiana based on the same allegation, in which Murphy Oil seeks recovery of any damages it has paid to the plaintiffs. Claiborne P. Deming, who became a director of Entergy Corporation in 2002, is the President and Chief Executive Officer of Murphy Oil.

                Murphy Oil and other defendants settled with the plaintiffs for $8.8 million, but Entergy Louisiana did not participate in the settlement. Entergy Louisiana believes the claims against it are without merit and is vigorously defending itself. Entergy Louisiana also has insurance in place for claims of this type. A trial date for the remaining parties in the proceeding has been set for September 2003.

Fiber Optic Cable Litigation (Entergy Corporation, Entergy Gulf States, Entergy Louisiana, and Entergy Mississippi)

                In 1998, a group of property owners filed a class action suit against Entergy Corporation, Entergy Gulf States, Entergy Services and ETHC in state court in Jefferson County, Texas purportedly on behalf of all property owners in each of the states throughout the Entergy service area who have conveyed easements to the defendants. The lawsuit alleged that Entergy installed fiber optic cable across their property without obtaining appropriate easements. The plaintiffs sought actual damages for the use of the land and a share of the profits made through use of the fiber optic cables and punitive damages. The state court petition was voluntarily dismissed, and the plaintiffs commenced a class action suit with the same claims in the United States District Court in Beaumont, Texas. Both sides have filed motions for summary judgment, which were heard by the court in late 2001. The district judge found that although four types of easements can be used for internal communications, two types cannot be used for third-party communications. Entergy believes that any damages suffered by the plaintiff landowners are negligible and that there is no basis for the claim seeking a share of profits. At this time, management cannot determine the specific amount of damages being sought.

                In January 2002, a class action lawsuit asserting similar allegations to those alleged in the lawsuit filed in Texas was commenced in state court in Ascension Parish, Louisiana, against Entergy Louisiana, Entergy Services, ETHC, and Entergy Technology Company, purportedly on behalf of all similarly situated property owners in Louisiana. Summary judgment was granted in Entergy's favor in January 2003 and the lawsuit has been dismissed.

                In June 2002, a class action lawsuit was filed by two defendants in the United States District Court of the Northern District of Mississippi against Entergy Mississippi, purportedly on behalf of others similarly situated, alleging that Entergy Mississippi installed fiber optic cable across their property without obtaining the appropriate easement. The plaintiffs seek declaratory relief and an unspecified amount of damages, including punitive damages. Entergy Mississippi filed a motion to dismiss in September 2002, contending that it has no fiber optic cables attached to its facilities and has not authorized any party to place fiber optic facilities on or under its right of way on the property in question. Entergy Mississippi intends to vigorously defend the lawsuit. At this time, management cannot determine the specific amount of damages being sought.

Asbestos and Hazardous Waste Suits (Entergy Gulf States, Entergy Louisiana, and Entergy New Orleans)

                Numerous lawsuits have been filed in federal and state courts in Texas and Louisiana primarily by contractor employees in the 1950-1980 timeframe against Entergy Gulf States, Entergy Louisiana and Entergy New Orleans, as premises owners of power plants, for damages caused by alleged exposure to asbestos or other hazardous material. Many other defendants are named in these lawsuits as well. Since 1992, these companies have resolved over three thousand claims for nominal amounts that in the aggregate total less that $13 million, including defense costs. Some of this loss has been offset by reimbursement from insurers. Presently there are over three thousand claims pending and reserves have been established that should be adequate to cover any exposure. Additionally, negotiations continue with insurers to recover more reimbursement, while new coverage is being secured to minimize anticipated future potential exposures. Management believes that loss exposure has been and will continue to be handled successfully so that the ultimate resolution of these matters will not be material, in the aggregate, to its financial position or results of operation.

Employment Litigation (Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

                Entergy Corporation and the domestic utility companies are defendants in numerous lawsuits that have been filed by former employees alleging that they were wrongfully terminated and/or discriminated against on the basis of age, race, and/or sex. Entergy Corporation and the domestic utility companies are vigorously defending these suits and deny any liability to the plaintiffs. However, no assurance can be given as to the outcome of these cases, and at this time management cannot estimate the total amount of damages sought.

                Included in the employment litigation are two cases filed in state court in Claiborne County, Mississippi in December 2002. The two cases were filed by former employees of Entergy Operations who were based at Grand Gulf. Entergy Operations and Entergy employees are named as defendants. The cases make employment-related claims, and seek in total $53 million in alleged actual damages and $168 million in punitive damages. Entergy Operations will vigorously defend these suits and denies any liability to the plaintiffs. However, no assurance can be given as to the outcome of these cases.

Research

                The domestic utility companies are members of the Electric Power Research Institute (EPRI). EPRI conducts a broad range of research in major technical fields related to the electric utility industry. Entergy participates in various EPRI projects based on Entergy's needs and available resources. The domestic utility companies contributed $2.1 million in 2002, $4 million in 2001, and $4.5 million in 2000 to EPRI.

Earnings Ratios of Domestic Utility Companies and System Energy

                The domestic utility companies' and System Energy's ratios of earnings to fixed charges and ratios of earnings to combined fixed charges and preferred dividends pursuant to Item 503 of SEC Regulation S-K are as follows:

Ratios of Earnings to Fixed Charges

Years Ended December 31,

 

2002

2001

2000

1999

1998

           

Entergy Arkansas

2.79

3.29

3.01

2.08

2.63

Entergy Gulf States

2.49

2.36

2.60

2.18

1.40

Entergy Louisiana

3.14

2.76

3.33

3.48

3.18

Entergy Mississippi

2.48

2.14

2.33

2.44

3.12

Entergy New Orleans

(b)

(c)

2.66

3.00

2.65

System Energy

3.25

2.12

2.41

1.90

2.52

                  Ratios of Earnings to Combined Fixed

Charges and Preferred Dividends

Years Ended December 31,

 

2002

2001

2000

1999

1998

           

Entergy Arkansas

2.53

2.99

2.70

1.80

2.28

Entergy Gulf States (a)

2.40

2.21

2.39

1.86

1.20

Entergy Louisiana

2.86

2.51

2.93

3.09

2.75

Entergy Mississippi

2.27

1.96

2.09

2.18

2.80

Entergy New Orleans

(b)

(c)

2.43

2.74

2.41

  1. "Preferred Dividends" in the case of Entergy Gulf States also include dividends on preference stock, which was redeemed in July 2000.
  2. For Entergy New Orleans, earnings for the twelve months ended December 31, 2002 were not adequate to cover fixed charges and combined fixed charges and preferred dividends by $0.7 million and $3.4 million, respectively.
  3. For Entergy New Orleans, earnings for the twelve months ended December 31, 2001 were not adequate to cover fixed charges and combined fixed charges and preferred dividends by $6.6 million and $9.5 million, respectively.
				  U.S. UTILITY                                          
			      FINANCIAL INFORMATION                                     
								 
								    For the Years Ended December 31,
								  2002            2001           2000
									     (In Thousands)
		 OPERATING INFORMATION                                                   
Operating revenues                                             $6,773,509      $7,432,920     $7,401,598
Operating expenses                                             $5,434,694      $6,050,534     $5,893,631
Other income                                                   $   47,603      $   69,157     $   61,119
Interest and other charges                                     $  465,703      $  576,705     $  515,156
Income taxes                                                   $  313,752      $  300,284     $  435,667
Net income                                                     $  606,963      $  574,554     $  618,263
													
													
													
		 CASH FLOW INFORMATION                                                            
Net cash flow provided by operating activities                 $2,341,161     $ 1,647,969    $ 1,705,370
Net cash flow used in investing activities                   $ (1,020,087)    $(1,243,715)   $(1,501,142)
Net cash flow provided by (used in) financing activities       $ (688,201)    $  (303,520)   $    12,702
													
													
													
									      December 31,                         
								 2002                           2001
									     (In Thousands)
	     FINANCIAL POSITION INFORMATION                                                             
Current assets                                                $ 2,517,001                    $ 2,076,437
Other property and investments                                $ 1,083,221                    $ 1,098,555
Property, plant and equipment - net                           $15,124,077                    $15,159,858
Deferred debits and other assets                              $ 2,354,066                    $ 1,974,846
Current liabilities                                           $ 2,479,783                    $ 2,136,778
Deferred credits and other liabilities                        $ 7,658,359                    $ 6,285,871
Long-term debt                                                $ 5,542,438                    $ 6,007,199
Shareholders' equity                                          $ 5,397,785                    $ 5,879,848
													
								    
								    

Non-Utility Nuclear

                Entergy's Non-Utility Nuclear business owns and operates five nuclear power plants and is primarily focused on selling electric power produced by those plants to wholesale customers. This business also provides operations and management services to nuclear power plants owned by other utilities in the United States. Operations and management services, including decommissioning services, are provided through Entergy's wholly-owned subsidiary, Entergy Nuclear, Inc.

Property

Generating Stations

                Entergy's Non-Utility Nuclear business owns the following nuclear power plants:



Power Plant

 



Acquired

 



Location

 


Maximum Capacity

 



Reactor Type

 

License Expiration Date

                     

Pilgrim

 

July 1999

 

Plymouth, MA

 

670 MW

 

Boiling Water Reactor

 

2012

FitzPatrick

 

Nov. 2000

 

Oswego, NY

 

825 MW

 

Boiling Water Reactor

 

2014

Indian Point 3

 

Nov. 2000

 

Westchester County, NY

 

980 MW

 

Pressurized Water Reactor

 

2015

Indian Point 2

 

Sept. 2001

 

Westchester County, NY

 

970 MW

 

Pressurized Water Reactor

 

2013

Vermont Yankee

 

July 2002

 

Vernon, VT

 

510 MW

 

Boiling Water Reactor

 

2012

Interconnections

                The Pilgrim and Vermont Yankee plants are dispatched as a part of Independent System Operator (ISO) New England and the James A. FitzPatrick and Indian Point Energy Center plants are dispatched by the New York Independent System Operator (NYISO). The primary purpose of ISO New England is to direct the operations of the major generation and transmission facilities in the New England region and the primary purpose of NYISO is to direct the operations of the major generation and transmission facilities in New York state.

Power Purchase Agreements

                Entergy's Non-Utility Nuclear business has entered into unit-contingent power purchase agreements (PPAs), as noted below, with creditworthy counterparties to sell the power produced by its power plants at prices established in the PPAs. 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:

   

2003

 

2004

 

2005

 

2006

 

2007

Non-Utility Nuclear:

                   

% of planned generation sold forward

 

100%

 

92%

 

25%

 

11%

 

9%

Planned generation (GWh)

 

33,317

 

33,361

 

34,006

 

34,613

 

34,300

Average price per MWh

 

$37.06

 

$38.36

 

$35.94

 

$31.97

 

$31.42

Power not sold under PPAs is subject to price fluctuations in the market. Entergy may be required to provide credit support in the form of guarantees in order to secure PPAs.

 

Fuel Supply

Nuclear Fuel

                The requirements for Pilgrim, FitzPatrick, Indian Point 2, Indian Point 3, and Vermont Yankee are pursuant to contracts made by Entergy's Non-Utility Nuclear business. Entergy Nuclear Fuels Company is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for these non-utility nuclear plants.

Other

Research

                Entergy's Non-Utility Nuclear business is a member of the Electric Power Research Institute (EPRI). EPRI conducts a broad range of research in major technical fields related to the electric utility industry. Entergy participates in various EPRI projects based on Entergy's needs and available resources. The Non-Utility Nuclear business contributed $3 million in 2002, $0.8 million in 2001, and $0.5 million in 2000 to EPRI.

Services

                Entergy Nuclear, Inc. also provides services to other nuclear power plants owners who seek the advantages of Entergy's scale and expertise but do not necessarily want to sell their assets. Services include engineering, operations and maintenance, fuel procurement, management and supervision, technical support and training, administrative support, and other managerial or technical services required to operate, maintain, and decommission nuclear electric power facilities. Entergy Nuclear, Inc. currently provides decommissioning services for the Maine Yankee nuclear power plant and continues to pursue opportunities with other nuclear plant owners through operating agreements or innovative arrangements such as structured leases.

                Entergy Nuclear, Inc. also is a party to two business arrangements that assist Entergy Nuclear, Inc. in providing operation and management services. Entergy Nuclear, Inc., in partnership with Framatome ANP, offers operating license renewal and life extension services to nuclear power plants in the United States. Entergy Nuclear Inc., through its subsidiary TLG Services, offers decommissioning, engineering, and related services to nuclear power plant owners.

Regulation of the Nuclear Power Industry

Atomic Energy Act of 1954 and Energy Reorganization Act of 1974

                Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy's Non-Utility Nuclear business is subject to the NRC's jurisdiction as the owner and operator of Pilgrim, Indian Point Energy Center, FitzPatrick, and Vermont Yankee. Substantial capital expenditures at these nuclear plants because of revised safety requirements of the NRC could be required in the future.

Nuclear Waste Policy Act of 1982

                Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Delays have occurred in the DOE's program for the acceptance and disposal of spent nuclear fuel at a permanent repository. After twenty years of study, the DOE, in February 2002, formally recommended, and President Bush approved, Yucca Mountain, Nevada as the permanent spent fuel repository. DOE will now proceed with the licensing and, if the license is granted by the NRC, eventual construction of the repository will begin and receipt of spent fuel may begin as early as approximately 2010. Considerable uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy's facilities for storage or disposal. As a result, future expenditures will be required to increase spent fuel storage capacity at Entergy's nuclear plant sites. Information concerning spent fuel disposal contracts with the DOE, current on-site storage capacity, and costs of providing additional on-site storage is presented in Note 9 to the consolidated financial statements.

Low-Level Radioactive Waste Policy Act of 1980

                The Low-Level Radioactive Waste Policy Act of 1980, as amended, holds each state responsible for disposal of waste originating in that state, but allows states to participate in regional compacts to fulfill their responsibilities jointly. Neither Massachusetts, where Pilgrim is located, nor New York, where Indian Point Energy Center and FitzPatrick are located, participates in any regional compact and efforts to fulfill their responsibilities have been minimal. The state of Vermont, where Vermont Yankee is located, participates in a compact with Maine and Texas. The efforts to develop a disposal facility in the host state of Texas have been minimal during the last several years. Currently the Entergy nuclear stations have disposal access at two waste disposal facilities: the Barnwell facility in South Carolina and the Envirocare facility in Utah. The Barnwell facility is licensed as a 10CFR61 facility and can accept all three classes of low level radwastes (Classes A, B, and C). With South Carolina's alliance as a member of the Atlantic Compact, disposal access for out-of-region waste generators will be limited at Barnwell. Over the next several years available out-of-region disposal capacity will continue to decrease and in 2008 out-of-region disposal will be prohibited. Currently the Envirocare facility is licensed to accept lower activity radwaste including Class A radioactive wastes. Envirocare has applied for a full service Class B and C license but has decided not to pursue that license at this time.

Nuclear Plant Decommissioning

                As part of the Pilgrim, Indian Point 1 and 2, and Vermont Yankee purchases, Boston Edison, Consolidated Edison, and VYNPC, respectively, transferred decommissioning trust funds, along with the liability to decommission the plants, to Entergy. Entergy believes that the decommissioning trust funds will be adequate to cover future decommissioning costs for these plants without any additional deposits to the trusts.

                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. In conjunction with the Pilgrim acquisition, Entergy received Pilgrim's decommissioning trust fund. Entergy believes that Pilgrim's decommissioning fund will be adequate to cover future decommissioning costs for the plant without any additional deposits to the trust. Subject to decommissioning service agreements between Entergy and NYPA, NYPA retains the decommissioning liability and trusts relating to Indian Point 3 and FitzPatrick up to a specified amount. Entergy believes that the amounts that will be available from the trusts will be sufficient to cover the future decommissioning costs of Indian Point 3 and FitzPatrick without any additional contributions to the trusts. As part of the Indian Point 1 and 2 purchase, Consolidated Edison transferred the decommissioning trust fund and the liability to decommission Indian Point 1 and 2 to Entergy. Entergy also funded an additional $25 million to the decommissioning trust fund and believes that the trust will be adequate to cover future decommissioning costs for Indian Point 1 and 2 without any additional deposits to the trust. Additional information with respect to decommissioning costs for ANO, River Bend, Waterford 3, Grand Gulf 1, Pilgrim, Indian Point 1, Indian Point 2, Indian Point 3, and FitzPatrick is found in Note 9 to the financial statements.

Price Anderson Act

                The Price-Anderson Act limits public liability for a single nuclear incident to approximately $9.5 billion. Entergy's Non-Utility Nuclear business has protection with respect to this liability through a combination of private insurance and an industry assessment program, as well as insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units. Insurance applicable to the nuclear programs of Entergy is discussed in Note 9 to the consolidated financial statements.

Nuclear Matters

                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 legal 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 safety. 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 has petitioned the United States Court of Appeals for the Second Circuit for review of this final action of the NRC. In order to prevail, Riverkeeper must show that the NRC has violated the Atomic Energy Act, abused its discretion, and has completely abdicated its statutory duty regarding this matter. Entergy believes that the action of the NRC was based upon a thorough and thoughtful review of the law and the facts and that the NRC decision will be affirmed by the court.

 

                In addition, certain concerns are being raised regarding the adequacy of the emergency response 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 response plans for Indian Point are in compliance with NRC requirements and thus adequately protect public health and safety.

 

                A January 2003 consultant's draft report prepared for the State of New York to review emergency preparedness around Indian Point concluded generically that federal emergency planning regulations and guidelines were not adequate to cope with new threats of terrorism. This conclusion was based in part on the view that radiation releases, including those caused by terrorist events, could be faster and larger than those for which the emergency plans were designed. As a result, even if emergency planning for Indian Point were to comply fully with all federal regulations and guidelines, this criticism in the report would stand. There were other plant-specific criticisms in the report. For these reasons, the report concluded that emergency planning for Indian Point is not adequate at this time. In March 2003, a final report was issued which reached similar conclusions. The NRC in reacting to the draft report observed that current emergency plans are already designed to cope with significant radiation releases regardless of cause and stated that it was reviewing the draft report's findings to determine if the emergency plans require modification.

 

                A February 2003, report issued by FEMA Region II evaluated a September 2002 exercise and related activities for the ten-mile emergency planning zone around Indian Point. The report identified no deficiencies with respect to the exercise. The report did conclude that in the absence of corrected and updated state and county plans, FEMA could not provide "reasonable assurance" that appropriate measures can be taken in the event of a radiological emergency. If the state provided this information and a schedule of corrective actions by May 2, 2003, the report stated that FEMA would reevaluate this decision. If corrective actions are not taken, FEMA Region II indicated that (a) it would notify FEMA headquarters that assurance cannot be provided regarding the adequacy of the plans to protect the health and safety of the public and (b) FEMA headquarters would notify the NRC and Governor of New York of the same. The notice from FEMA to the NRC would begin corrective action periods. If corrective action were not taken by the end of these periods, the NRC must determine whether there is reasonable assurance regarding the adequacy of plans to protect the health and safety of the public. If the NRC determines that there is not such assurance, it has the authority to order the Indian Point plants to shut down.

 

                Entergy is interacting with New York state and county officials, FEMA, NRC and other federal agencies to make additional improvements to the emergency response plans that may be warranted and to further assure them as to the adequacy of the plans. Entergy will vigorously oppose all attempts to shut down the Indian Point plants.

 

                The Westchester County Executive announced his proposal to acquire Indian Point by purchase or condemnation and has announced an intention to commission a feasibility study regarding municipalization of Indian Point. At this time, considering the financial and legal impediments that the County would face in implementing this proposal, it is improbable that the County could condemn or municipalize Indian Point.

 

Environmental Regulation

Clean Water Act

                The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act or CWA) provide the statutory basis for the National Pollutant Discharge Elimination System (NPDES) permit program and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The CWA requires anyone who wants to discharge pollutants to first obtain an NPDES permit, or else that discharge will be considered illegal. Entergy's Non-Utility Nuclear business is currently in negotiations with EPA for renewal of the Pilgrim NPDES permit, and is in negotiations with the New York environmental authority for renewal of the Indian Point discharge permit issued by New York. It is possible that the environmental authorities will require operating or physical modifications to the plants before renewing the permits. The EPA recently proposed draft regulations for existing power plants, including certain electric generating stations employing once-through cooling technology (the draft Rule). The draft Rule seeks to reduce perceived impacts on aquatic resources by requiring covered facilities to take steps to implement technology or other measures to meet EPA-targeted reductions in water use and corresponding perceived aquatic impacts. While the draft Rule is the subject of extensive comment and also is expected to be challenged (which may result in changes to it prior to final promulgation), Entergy currently has begun and will continue to evaluate the draft Rule, including by considering options for complying with the draft Rule if promulgated in substantially its current form. Those options considered may include operational controls, the installation of equipment to address perceived aquatic impacts, and other mitigation measures, or combinations of these alternatives.

 

 


			   NON-UTILITY NUCLEAR                                      
			  FINANCIAL INFORMATION                                     
								 
								For the Years Ended December 31,
							      2002           2001           2000
									 (In Thousands)
		OPERATING INFORMATION                                                               
Operating revenues                                         $ 1,200,238    $   789,244    $   298,147
Operating expenses                                         $   837,429    $   551,113    $   211,700
Other income                                               $    63,672    $    50,916    $    27,416
Interest and other charges                                 $    93,250    $    81,114    $    33,213
Income taxes                                               $   132,726    $    80,053    $    31,492
Net income                                                 $   200,505    $   127,880    $    49,158
												    
												    
												    
		CASH FLOW INFORMATION                                                         
Net cash flow provided by operating activities             $   281,589    $   263,476    $    92,286
Net cash flow used in investing activities                 $  (438,664)   $(1,061,850)   $   (65,547)
Net cash flow provided by financing activities             $   176,162    $   292,872    $   599,827
												    
												    
												    
									 December 31,                        
							      2002                          2001
									(In Thousands)
	   FINANCIAL POSITION INFORMATION                                                           
Current assets                                             $   706,056                   $   475,631
Other property and investments                             $ 1,437,896                   $ 1,164,186
Property, plant and equipment - net                        $ 1,613,369                   $ 1,349,982
Deferred debits and other assets                           $   724,987                   $   459,357
Current liabilities                                        $   947,731                   $   555,797
Deferred credits and other liabilities                     $ 1,557,144                   $ 1,234,750
Long-term debt                                             $   618,323                   $   688,796
Shareholders' equity                                       $ 1,359,110                   $   969,813
												    
												    
								    

Energy Commodity Services

                Entergy's Energy Commodity Services business is focused almost exclusively on providing energy commodity marketing and trading and gas transportation and storage services through Entergy-Koch, L.P. Entergy's non-nuclear wholesale asset business generates electricity to be sold in the wholesale market. Previously, Entergy's Energy Commodity Services business also engaged in power development activities through Entergy Wholesale Operations, but these activities were discontinued in early 2002. Entergy recorded net charges of $428.5 million ($238.3 million net of tax) to operating expenses because of the decision to discontinue additional EWO greenfield power plant development and to reflect asset impairments resulting from the deteriorating economics of wholesale power markets in principally the United States and the United Kingdom. EWO sold its Damhead Creek power plant in the UK and its interests in Latin American projects during 2002.

Entergy-Koch, LP

                Entergy-Koch is a venture between subsidiaries of Entergy and Koch Industries, Inc. Entergy-Koch launched on February 1, 2001, and is a 50-50 limited partnership with about 700 employees and $1 billion in assets. Entergy contributed most of the assets and trading contracts of its power marketing and trading business and $414 million cash to the venture and Koch contributed its 8,025-mile Koch Gateway Pipeline (renamed Gulf South Pipeline), gas storage facilities, and Koch Energy Trading, which marketed and traded electricity, gas, weather derivatives, and other energy-related commodities and services.

                Entergy-Koch is engaged in two major businesses: energy commodity trading which includes power, gas, weather derivatives, emissions, and cross-commodities through Entergy-Koch Trading; and gas transportation and storage through the Gulf South Pipeline. Each of these businesses contributes from 40-60% of Entergy-Koch's earnings. Entergy-Koch has attained the following credit ratings: an "A" rating from Standard and Poor's and an "A3" rating from Moody's Investors Service.

Entergy-Koch Trading

                Entergy-Koch Trading buys and sells natural gas, power, and other energy-related services and commodities, such as weather derivatives, in the United States, the United Kingdom, Western Europe, and Canada. It provides energy management services using knowledge systems that promote fundamental and quantitative understanding of market risk. Entergy-Koch Trading uses advanced analytics and knowledge of the marketplace, natural gas pipelines, power transmission infrastructure, transportation management, gas storage, and weather.

Gulf South Pipeline

                Gulf South Pipeline owns and operates an interstate natural gas pipeline system in the Gulf Coast region and provides critical links to many major markets nationwide. Gulf South Pipeline gathers natural gas from the Gulf South region and transports it to local distribution companies, industrial facilities, power generators, utility companies, other pipelines, and natural gas marketing companies. The Gulf South Pipeline's existing system comprises 8,025 miles of pipeline (6,875 transmission, 1,150 gathering) with connections to more than 100 pipelines including Texas Eastern, Transco and Florida Gas Transmission. The pipeline system covers parts of Texas, Louisiana, Mississippi, Alabama, and Florida and connects to the Henry Hub, located in Vermilion Parish, Louisiana.

                Gulf South's operational flexibility is enhanced by its Bistineau and Jackson storage facilities with total working storage capacity of 68.5 Bcf. Additionally, Gulf South Pipeline is developing a natural gas salt dome storage facility - Magnolia Gas Storage located near Napoleanville, Louisiana. This new facility, expected to be in service by early 2004, complements the existing storage at Bistineau and Jackson, and offers multiple pipeline interconnects providing increased reliability for customers and opportunities for Gulf South to improve gas flows across its system. The facility will have an initial working capacity of approximately 4.1 Bcf and will be expanded to 6.5 Bcf in 2007.

 

Entergy-Koch, LP Agreement Details

                Although the ownership interests of Entergy and Koch Industries are equal, the capital accounts are different. As described above, each contributed different assets to the partnership with those contributed by Koch valued at more than those contributed by Entergy. Through the end of 2003, substantially all of the partnership profits are allocated to Entergy to allow the capital accounts to equalize. The capital accounts are expected to be equal in 2004 as a result of this disproportionate sharing of income. In all years, losses and distributions from operations are allocated equally to the capital accounts based on ownership interest.

                In the partnership agreement, Entergy agreed to contribute $72.7 million to the partnership in January 2004. Koch also will receive a distribution of $72.7 million in 2004. In addition, at that time, Entergy-Koch's assets will be revalued for capital account purposes. If the value of the assets exceeds their carrying value for capital account purposes, then that difference will be allocated to the capital accounts. Entergy expects that after this revaluation the capital accounts of Entergy and Koch Industries will be approximately equal and that future profit allocations other than for weather trading and international trading will be equal. If the capital accounts differ significantly, however, then profits may be allocated disproportionately to one partner or the other until the capital accounts are approximately equal.

                The partnership agreement provides that losses are allocated between the capital accounts of the partners based on ownership interest. Distributions from operations are shared based on ownership interest and distributions in the event of liquidation are shared based on capital accounts, as revalued at the time of the liquidation. Prior to 2004, a partner may transfer its partnership interest only with the consent of the other partner. Beginning in 2004, a partner may transfer its interest to a third party, only if it has first offered to sell its interest to the other partner at the approximate sales price and the other partner has not accepted the offer. Certain buy/sell rights are triggered (a) at the option of the non-defaulting partner, upon a change of control of, or material breach of the agreement by, either partner or (b) at the option of either partner, at any time beginning in 2004. Under the buy/sell rights, the initiating partner offers to sell all its partnership interest at a specified price and other terms or to buy all of the other partner's partnership interest at the same price and same other terms.

Non-Nuclear Wholesale Asset Business

Property

Generating Stations

                The capacity of the generating stations owned in Entergy's non-nuclear wholesale asset business as of December 31, 2002 is indicated below:

Plant

 

Location

 

Ownership

 

Net Owned Capacity(1)

 

Type

                 

Ritchie Unit 2, 544 MW

 

Helena, AR

 

100%

 

544 MW

 

Fossil

Independence Unit 2, 842 MW

 

Newark, AR

 

14%

 

121 MW (2)

 

Fossil

Warren Power, 300 MW

 

Vicksburg, MS

 

100%

 

300 MW

 

Fossil

Top of Iowa, 80 MW

 

Worth County, IA

 

99%

 

80 MW

 

Wind

Crete, 320 MW

 

Crete, IL

 

50%

 

160 MW

 

Fossil

RS Cogen, 425 MW

 

Lake Charles, LA

 

50%

 

212 MW

 

Fossil

(1) "Owned Capacity" refers to the nameplate rating on the generating unit.

(2) The owned MW capacity is the portion of the plant capacity owned by Entergy. For a complete listing of Entergy's joint-owned generating stations, refer to "Jointly-Owned Generating Stations" in Note 1 to the Entergy Corporation and Subsidiaries financial statements.

                Entergy's non-nuclear wholesale asset business is currently constructing a 550 MW combined-cycle gas turbine power plant in Harrison County, Texas. Entergy will own approximately 385 MW once construction is completed and operation has begun (currently projected to be June 2003), with Northeast Texas Electric Cooperative, Inc. owning the remainder.

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

 

2003

 

2004

 

2005

 

2006

 

2007

Energy Commodity Services:

                 

% of planned generation sold forward

38%

 

18%

 

22%

 

19%

 

21%

Planned generation (GWh)

3,124

 

3,249

 

3,820

 

3,494

 

3,618

Contracted spark spread per MWh

$11.70

 

$10.63

 

$10.62

 

$9.69

 

$9.68

Litigation

Power Generation Mexico, Inc. Lawsuit

                In May 2001, Power Generation Mexico, Inc. (PGI) filed suit against Entergy Power Development Corporation (EPDC), Entergy Power Netherlands Company, B.V., and Entergy Corporation in the San Francisco Superior Court. In December 2001, PGI filed a First Amended Complaint. PGI asserts that EPDC agreed to develop several power projects and to receive certain fees and equity interest for its efforts, and that EPDC failed to fulfill its obligations and deliberately frustrated development of the projects, all to PGI's detriment. PGI seeks general compensatory, consequential, incidental, and punitive damages in excess of $10 million. Entergy has filed motions that, if successful, will limit the number of defendants and claims, as well as the type of damages that could be recovered. Entergy is vigorously defending this suit and denies any liability to the plaintiff. However, no assurance can be given as to the ultimate outcome of this suit.

 

 

 


 

		       ENERGY COMMODITY SERVICES                                   
			 FINANCIAL INFORMATION                                     
								 
								    For the Years Ended December 31,
								   2002           2001           2000
									     (In Thousands)
		  OPERATING INFORMATION                                                                  
Operating revenues                                              $   294,670    $ 1,370,485    $ 2,353,792
Operating expenses                                              $   769,834    $ 1,323,371    $ 2,377,316
Other income                                                    $   249,678    $   208,271    $    99,396
Interest and other charges                                      $    61,632    $    74,953    $    (3,725)
Income taxes                                                    $  (141,288)   $    74,493    $    24,689
Net income                                                      $  (145,830)   $   105,939    $    54,908
													 
													 
													 
		  CASH FLOW INFORMATION                                                            
Net cash flow provided by (used in) operating activities        $    (3,714)   $  (127,938)   $    64,292
Net cash flow provided by (used in) investing activities        $      (760)   $   138,351    $  (547,024)
Net cash flow provided by (used in) financing activities        $   (66,151)   $  (148,501)   $   538,948
													 
													 
													 
									      December 31,                        
								   2002                          2001
									     (In Thousands)
	      FINANCIAL POSITION INFORMATION                                                             
Current assets                                                  $   504,836                   $   442,667
Other property and investments                                  $ 1,175,842                   $   982,628
Property, plant and equipment - net                             $   429,677                   $   749,661
Deferred debits and other assets                                $    57,117                   $   202,777
Current liabilities                                             $   348,200                   $   225,865
Deferred credits and other liabilities                          $    11,782                   $   257,264
Long-term debt                                                  $    79,029                   $   671,668
Shareholders' equity                                            $ 1,728,461                   $ 1,222,936
													 
													 


 

ENTERGY ARKANSAS, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

 

Results of Operations

Operating Income

2002 Compared to 2001

                Operating income decreased by $77.5 million primarily due to the following:

    • the receipt of the final FERC order in July 2001 in the 1995 System Energy rate proceeding. The accounting entries necessary to record the effects of the order reduced purchased power expenses by $62.7 million in 2001, which resulted in a corresponding increase in operating income in 2001 (refer to Note 2 to the domestic utility companies and System Energy financial statements for further discussion);
    • an increase in other operation and maintenance expenses of $179.3 million, $159.9 million of which is offset by an increase in other regulatory credits and has no effect on operating income; and
    • an increase in depreciation and amortization expenses of $13.0 million due to an increase in plant in service combined with revisions made to the useful lives of certain intangible plant assets to more appropriately reflect their actual lives, which lowered expense in 2001 in accordance with regulatory treatment.

                Other operation and maintenance expenses increased in 2002 primarily due to:

    • increased expenses of $159.9 million due to a March 2002 settlement agreement and 2001 earnings review allowing Entergy Arkansas to recover a large majority of 2000 and 2001 ice storm repair expenses through the previously-collected transition cost account amounts (offset in other regulatory credits as discussed above);
    • increased expenses of $24.5 million due to the reversal in 2001 of ice storm costs previously charged to expense in 2000;
    • increased benefit costs of $10.3 million; and
    • an increase in expense of $6.6 million to reflect the current estimate of the liability for the future disposal of low-level radioactive waste materials.

The increase in other operation and maintenance expenses was partially offset by a $16 million decrease due to turbine refurbishing costs expensed in 2001 at a plant after its lease expired.

                The March 2002 settlement agreement is discussed further in Note 2 to the domestic utility companies and System Energy financial statements.

2001 Compared to 2000

                Operating income increased by $69.7 million primarily due to the following:

    • the aforementioned refund from System Energy; and
    • a decrease in other operation and maintenance expenses of $63 million, which is explained below.

The increase in operating income was partially offset by:

    • a decrease in revenues of $10.8 million due to less favorable sales volume primarily due to the effect of colder winter weather in 2000;
    • the accrual of $26.8 million to the transition cost account; and
    • an increase in fuel and purchased power expenses of $22.3 million due to an adjustment to the deferred fuel balance in 2000 as a result of the 1999 and 2000 Rider ECR filings.

                Other operation and maintenance expenses decreased in 2001 primarily due to:

    • a decrease in property damage expenses of $49.7 million primarily due to a reversal of $24.5 million in June 2001, upon recommendation from the APSC, of ice storm costs previously charged to expense in December 2000. The effect of the reversal of the ice storm costs on net income was largely offset by the adjustment to the transition cost account as a result of the 2000 earnings review in 2001;
    • a decrease in nuclear expenses of $17 million due to maintenance and inspection outages in 2000, compared to no outages in 2001, as well as the steam generator replacement project at ANO 2 in late 2000; and
    • a decrease in expense of $9.3 million primarily due to decreased transition to competition support costs.

The decrease in other operation and maintenance expenses was partially offset by a $16 million increase due to the payment of turbine refurbishing costs discussed above.

                The December 2000 ice storms are discussed in more detail in Note 2 to the domestic utility companies and System Energy financial statements.

Other Impacts on Earnings

2002 Compared to 2001

                Other income decreased in 2002 primarily due to a decrease in interest income of $7.1 million recorded on the deferred fuel balance due to the balance shifting from an asset to a liability in 2002.

                Interest charges decreased in 2002 primarily due to:

    • a decrease of $3.3 million due to a lower interest rate on spent nuclear fuel disposal costs;
    • decreased interest of $2.8 million on intercompany money pool borrowings due to Entergy Arkansas being in a lending position in 2002; and
    • interest expense of $2.7 million on a $63 million credit facility that was outstanding in 2001.

2001 Compared to 2000

                Other income decreased in 2001 primarily due to a decrease in the allowance for equity funds used during construction due to a lower construction work in progress balance during 2001 compared to the same period in 2000. The construction balance was lower because the ANO 2 replacement steam generators were placed in service in late 2000.

                Interest charges increased in 2001 primarily due to:

    • a decrease in the allowance for borrowed funds used for construction because of the lower construction work in progress balance during 2001;
    • the issuance of $100 million of long-term debt in July 2001; and
    • interest expense on a $63 million credit facility obtained in January 2001.

Other Income Statement Variances

2002 Compared to 2001

                Fuel cost recovery revenue decreased in 2002 due to decreases in the annual recovery rider in April and again in October (refer to Note 2 to the domestic utility companies and System Energy financial statements for further discussion). Corresponding to the decrease in fuel cost recovery revenue, fuel and purchased power expenses also decreased.

2001 Compared to 2000

                Fuel cost recovery revenue increased in 2001 due to increases in the annual recovery rider in April 2000 and April 2001. Fuel and purchased power expenses increased (excluding the aforementioned System Energy refund) consistent with the increase in fuel cost recovery revenue.

                Other regulatory credits decreased in 2001 primarily due to:

    • the decreased accrual of transition costs recorded as a regulatory asset expected to be recovered in a customer transition tariff; and
    • increased recovery of Grand Gulf 1 costs due to an increase in the Grand Gulf 1 rider effective January 2001, partially offset by a later decrease in the rider effective July 2001.

Income Taxes

                The effective income tax rates for 2002, 2001, and 2000 were 34.5%, 37.3%, and 42.3%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate.

Liquidity and Capital Resources

Cash Flow

                Cash flows for the years ended December 31, 2002, 2001, and 2000 were as follows:

2002

2001

2000

(In Thousands)

Cash and cash equivalents at beginning of period

$ 103,466 

$ 7,838 

$ 6,862 

Cash flow provided by (used in):

   Operating activities

357,421 

413,178 

421,560 

   Investing activities

(249,438)

(326,602)

(467,454)

   Financing activities

(115,936)

      9,052 

  46,870 

      Net increase (decrease) in cash and cash equivalents

    (7,953)

    95,628 

       976 

Cash and cash equivalents at end of period

$ 95,513 

$ 103,466 

$ 7,838 

Operating Activities

                Cash flow from operations decreased in 2002 compared to 2001 primarily due to a decrease in net income as explained above.

 

                Entergy Arkansas' receivable from or (payables) to the money pool were as follows as of December 31 for each of the following years:

2002

 

2001

 

2000

 

1999

   

(In Thousands)

 
             

$4,279

 

$23,794

 

($30,719)

 

($40,622)

                Money pool activity increased Entergy Arkansas' operating cash flows by $19.5 million in 2002. In 2001, money pool activity decreased Entergy Arkansas' operating cash flows by $54.5 million. Money pool activity decreased Entergy Arkansas' operating cash flows by $9.9 million in 2000. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.

Investing Activities

                The decrease in net cash used in investing activities in 2002 was primarily due to the maturity of $38.4 million of other temporary investments.

                The decrease in net cash used in investing activities in 2001 was primarily due to a decrease in construction expenditures of $88.6 million and the recovery of $93.8 million of other regulatory investments (deferred fuel costs). Construction expenditures decreased primarily due to ANO Unit 2 steam generator replacement costs being incurred in 2000. The decrease was partially offset by other temporary investments of $38.4 million made in 2001.

Financing Activities

                Entergy Arkansas used cash in financing activities in 2002 compared to providing a small amount of cash in 2001 primarily due to an increase of $43.4 million in common stock dividends paid to Entergy Corporation. Entergy Arkansas had a net issuance of $18.4 million of long-term debt in 2002 compared to a net issuance of $97.4 million in 2001 that also contributed to the decrease in net cash provided.

                The decrease in net cash provided by financing activities in 2001 was primarily due to an increase of $37.9 million in common stock dividends paid to Entergy Corporation.

                See Note 7 to the domestic utility companies and System Energy financial statements for details on long-term debt.

Uses of Capital

                Entergy Arkansas requires capital resources for:

    • construction and other capital investments;
    • debt and preferred stock maturities;
    • working capital purposes, including the financing of fuel and purchased power costs; and
    • dividend and interest payments.

 

                Following are the amounts of Entergy Arkansas' planned construction and other capital investments, existing debt and lease obligations, and other purchase obligations:

2003

2004

2005

2006-2007

after 2007

(In Millions)

Planned construction and

   capital investment

$283

$286

$315

N/A

N/A

Long-term debt maturities

$255

$-

$262

$100

$763

Capital and operating lease payments

$28

$28

$25

$31

$58

Unconditional fuel and purchased

   power obligations

$380

$382

$383

$775

$3,631

Nuclear fuel lease obligations (1)

$53

$35

N/A

N/A

N/A

  1. 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. If such additional financing cannot be arranged, however, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations.

                On July 25, 2002, the Board authorized Entergy Arkansas and Entergy Operations to replace the ANO 1 steam generator and reactor vessel closure head. Entergy management estimates the cost of the fabrication and replacement to be approximately $235 million, of which approximately $135 million will be incurred through 2004. Management expects that the replacement will 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 steam generator for ANO 2. Receipt of an order relating to the replacement at ANO 1 would provide additional support for the inclusion of these costs in a future general rate case, however, management cannot predict the outcome of either the request for a declaratory order or a general rate proceeding. See "Nuclear Matters" below for further discussion of the ANO 1 steam generators and reactor vessel closure head.

                In addition to the steam generator and reactor vessel closure head replacement, the planned capital investment estimate for Entergy Arkansas also reflects capital required to support existing business and customer growth. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, market volatility, economic trends, and the ability to access capital. Management provides more information on construction expenditures and long-term debt and preferred stock maturities in Notes 5, 6, 7, and 9 to the domestic utility companies and System Energy financial statements.

                As a wholly-owned subsidiary, Entergy Arkansas dividends its earnings to Entergy Corporation at a percentage determined monthly. Entergy Arkansas is restricted by long-term debt indentures in the payment of cash dividends or other distributions on its common and preferred stock. As of December 31, 2002, Entergy Arkansas had restricted retained earnings unavailable for distribution to Entergy Corporation of $296.1 million.

Sources of Capital

                Entergy Arkansas' sources to meet its capital requirements include:

    • internally generated funds;
    • cash on hand;
    • debt issuances; and
    • bank financing under new or existing facilities.

                In 2002, Entergy Arkansas issued $200 million of long-term debt and used the net proceeds to redeem outstanding debt of $85 million in 2002 and $100 million in 2003. The 2003 redemption occurred at maturity. Entergy Arkansas is expected to continue refinancing or redeeming higher-cost debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

                All debt and common and preferred stock issuances by Entergy Arkansas require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements.

                Short-term borrowings by Entergy Arkansas, including borrowings under the money pool, are limited to an amount authorized by the SEC, $235 million. Under the SEC order authorizing the short-term borrowing limits, Entergy Arkansas cannot incur new short-term indebtedness if its common equity would comprise less than 30% of its capital. Entergy Arkansas has a 364-day credit facility available with an expiration date of May 2003 in the amount of $63 million, of which none was drawn at December 31, 2002. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy Arkansas' short-term borrowing limits.

Significant Factors and Known Trends

Utility Restructuring

                Major changes are occurring in the wholesale and retail electric utility business, including in the electric transmission business. In April 1999, the Arkansas legislature enacted Act 1556, the Arkansas Electric Consumer Choice Act, providing for competition in the electric utility industry through retail open access. In December 2001, the APSC recommended to the Arkansas General Assembly that legislation be enacted during the 2003 legislative session to either repeal Act 1556 or further delay retail open access until at least 2010. In February 2003, the Arkansas legislature voted to repeal Act 1556 and the repeal was signed into law by the governor.

                At FERC, the pace of restructuring at the wholesale level has begun but has 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. However, 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.

System Agreement Proceedings

                The System Agreement provides for the integrated planning, construction, and operation of Entergy's electric generation and transmission assets throughout the retail service territories of the domestic utility companies. Under the terms of the System Agreement, generating capacity and other power resources are jointly operated by the domestic utility companies. The System Agreement provides, among other things, that parties having generating reserves greater than their load requirements (long companies) shall receive payments from those parties having deficiencies in generating reserves (short companies). Such payments are at amounts sufficient to cover certain of the long companies' costs for intermediate and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred and preference stock, and a fair rate of return on common equity investment. Under the System Agreement, these charges are based on costs associated with the long companies' steam electric generating units fueled by oil or gas. In addition, for all energy exchanged among the domestic utility companies under the System Agreement, the short companies are required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.

                The LPSC and the Council commenced a proceeding at FERC in June 2001. In this proceeding, the LPSC and the Council allege that the rough production cost equalization required by FERC under the System Agreement and the Unit Power Sales Agreement has been disrupted by changed circumstances. The LPSC and the Council have requested that FERC amend the System Agreement or the Unit Power Sales Agreement or both to achieve full production cost equalization or to restore rough production cost equalization. Their complaint does not seek a change in the total amount of the costs allocated by either the System Agreement or the Unit Power Sales Agreement. In addition, the LPSC and the Council allege that provisions of the System Agreement relating to minimum run and must run units, the methodology of billing versus dispatch, and the use of a rolling twelve-month average of system peaks, increase costs paid by ratepayers in the LPSC and Council's jurisdictions. Several parties have filed interventions in the proceeding, including the APSC and the MPSC. Entergy filed its response to the complaint in July 2001 denying the allegations of the LPSC and the Council. The APSC and the MPSC also filed responses opposing the relief sought by the LPSC and the Council.

            In their complaint, the LPSC and the Council allege that Entergy Arkansas' annual production costs over the period 2002 to 2007 will be $130 million to $278 million under the average for the domestic utility companies. 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. In February 2002, the FERC set the matter for hearing and established a refund effective period consisting of the 15 months following September 13, 2001. Negotiations among the parties have not resolved the proceeding, and the proceeding is now set for hearing commencing in June 2003. The case had been set for trial commencing in February 2003. The extension of the schedule also extended the refund effective period by 120 days. If FERC grants the relief requested by the LPSC and the Council, 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 Entergy Arkansas, although neither the timing nor the outcome of the proceedings at FERC can be predicted at this time.

Market and Credit Risks

                Entergy Arkansas has certain market and credit risks inherent in its business operations. Market risks represent 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. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement.

Interest Rate and Equity Price Risk - Decommissioning Trust Funds

                Entergy Arkansas' nuclear decommissioning trust funds are exposed to fluctuations in equity prices and interest rates. The NRC requires Entergy Arkansas to maintain trusts to fund the costs of decommissioning ANO 1 and ANO 2. The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that its exposure to market fluctuations will not affect results of operations for the ANO trust funds because of the application of regulatory accounting principles. The decommissioning trust funds are discussed more thoroughly in Notes 1 and 9 to the domestic utility companies and System Energy financial statements.

State and Local Rate Regulatory Risks

                The rates that Entergy Arkansas charges for its services are an important item influencing Entergy Arkansas' financial position, results of operations, and liquidity. Entergy Arkansas is closely regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the APSC, is primarily responsible for approval of the rates charged to customers. In addition to rate proceedings, Entergy Arkansas' fuel costs recovered from customers are subject to regulatory scrutiny.

                Entergy Arkansas' retail rate matters and proceedings, including fuel cost recovery-related issues, are discussed more thoroughly in Note 2 to the domestic utility companies and System Energy financial statements.

Nuclear Matters

                Entergy Arkansas owns and operates, through an affiliate, ANO 1 and 2. Entergy Arkansas is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of either ANO 1 or 2, Entergy Arkansas may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.

                In August 2001, the NRC issued a bulletin requesting all pressurized water reactor owners and operators to report on the structural integrity of their reactor vessel head penetration nozzles to justify continued operations past December 31, 2001. These types of reactors are susceptible to water stress corrosion cracking of the reactor vessel head nozzles. ANO 1 and 2 are pressurized water reactors. In March 2001, an inspection of ANO 1 revealed one leaking control rod drive mechanism nozzle, which was subsequently repaired. During a planned refueling outage that began in October 2002, visual inspection of the reactor vessel head at ANO 1 revealed one nozzle leak. Further ultrasonic testing showed the presence of seven additional minor indications that could potentially develop into leaks. Entergy Arkansas made repairs during the outage. Entergy Arkansas has received favorable responses from the NRC for continued operations of ANO 1 and 2.

                Inspections of the ANO 1 steam generators during planned outages also have revealed cracks in certain steam generator tubes, which have been repaired or plugged. The current number of cracks is below the limit authorized by the NRC to allow the unit to remain in operation and has not affected ANO 1's output to date. Using current projections of steam generator tube plugging, the current best estimate is that replacement of the ANO Unit 1 steam generators will be required by 2013. Entergy Operations currently does not expect ANO Unit 1 to have to conduct mid-cycle outages for steam generator inspection before 2005. ANO 2's steam generator was replaced during a refueling outage in the second half of 2000.

                In December 2001, Entergy issued a Request for Proposal ("RFP") to provide replacement steam generators" for ANO 1. Two companies submitted bids in response to the RFP. Entergy subsequently entered a contract with one of the companies for delivery of the replacement generators in August 2005 in time for installation during a scheduled refueling outage beginning in September 2005. The other company filed a suit in federal district court in Virginia seeking a temporary and permanent injunction against winning bidder claiming that the winning bidder was using the other company's proprietary information in the design and fabrication of the replacement generators. The preliminary injunction hearing was conducted in October 2002 and the court granted the temporary injunction, subject to adequate bond being posted, on February 13, 2003.

                The two companies have agreed to jointly move the district court to modify its order granting the preliminary injunction to provide that the injunction is stayed and shall not take effect until 30 days following a decision of the Fourth Circuit Court of Appeals affirming the injunction, assuming such an affirmance is granted. The parties also agreed to request expedited handling of the appeal by the court of appeals. Should the other company prevail on this appeal and no settlement is reached between the two companies prior to the issuance of the temporary injunction, the installation of the steam generators at ANO 1 may be delayed until a 2007 scheduled refueling outage.

Environmental Risks

                Entergy Arkansas' facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Arkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

                The preparation of Entergy Arkansas' 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 Arkansas' financial statements.

Nuclear Decommissioning Costs

                Regulations require that ANO 1 and ANO 2 be decommissioned after the facilities are 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 Arkansas conducts periodic decommissioning cost studies (typically updated every five years) to estimate the costs that will be incurred to decommission the facilities. See Note 9 to the domestic utility companies and System Energy financial statements for details regarding Entergy Arkansas' most recent study and the obligations recorded by Entergy Arkansas related to decommissioning. The following key assumptions have a significant effect on these estimates:

    • Cost Escalation Factors - Entergy Arkansas' decommissioning studies include an assumption that decommissioning costs will escalate over present cost levels by an annual factor averaging approximately 3%. A 50 basis point change in this assumption could change the ultimate cost of decommissioning a facility by as much as 11%.
    • Timing - The date of the plant's retirement must be estimated and 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. Entergy Arkansas' decommissioning studies for ANO 1 and ANO 2 assume immediate decommissioning upon expiration of the original plant license. 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 Arkansas' decommissioning studies do not include cost estimates for spent fuel storage. A study including these costs for ANO 1 and ANO 2 is currently underway. However, these estimates could change in the future based on the timing of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors.
    • Technology and Regulation - To date, there is limited practical experience in the United States with actual decommissioning of large nuclear facilities. As experience is gained and technology changes, cost estimates could also change. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant impact on cost estimates. The impact of these potential changes is not presently determinable. Entergy Arkansas' decommissioning cost studies assume current technologies and regulations.

                Through 2001, Entergy Arkansas collected the projected costs of decommissioning ANO 1 and ANO 2 through rates charged to customers. The APSC ordered Entergy Arkansas to cease collection of funds to decommission ANO 1 and ANO 2 effective with the calendar year 2001, and approved the continued cessation of collection of funds during 2003. The APSC based its decision on the approval of Entergy's application with the NRC to extend the license of ANO 1 by 20 years, anticipated approval of a 20 year license extension for ANO 2, and the conclusion that the funds previously collected will be sufficient to decommission the units. This decision will be reviewed annually and reflected in Entergy Arkansas' filing of its annual determination of the nuclear decommissioning rate rider. The amounts collected through rates, which were based upon decommissioning cost studies, were deposited in decommissioning trust funds. Decommissioning costs have no impact on Entergy Arkansas' earnings, as earnings on trust funds are offset by recording increases to the decommissioning obligation.

                The obligations recorded by Entergy Arkansas for decommissioning are classified as a component of accumulated depreciation. The amounts recorded for these obligations are comprised of past collections from customers and earnings on the trust funds. The classification and recording of these obligations will change with the implementation of SFAS 143.

SFAS 143

                Entergy Arkansas implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs comprise substantially all of Entergy Arkansas' asset retirement obligations, and the measurement and recording of Entergy Arkansas' decommissioning obligations outlined above will change 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 will cause the recorded decommissioning obligation of Entergy Arkansas to increase significantly, as Entergy Arkansas 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 Arkansas' decommissioning studies to date have been based on Entergy Arkansas performing the work, and have not included any such margins or premiums. Inclusion of these items increases cost estimates.
    • Discount rate - SFAS 143 requires that these obligations be discounted using a credit-adjusted risk-free rate.

The net effect of implementing this standard for Entergy Arkansas will be recorded as a regulatory asset or liability, with no resulting impact on Entergy Arkansas' net income. Assets and liabilities are expected to increase by approximately $500 million in 2003 as a result of recording the asset retirement obligation at its fair value as determined under SFAS 143 and recording the related regulatory asset and liability.

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 domestic utility companies and System Energy 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.

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 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 2000 and 2001 to 6.75% in 2002. 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 rates from a range of 8% gradually decreasing to 5% in 2001 to a range of 10% gradually decreasing to 4.5% in 2002.

                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 plan assets of roughly 65% equity securities and 35% fixed income securities. Based on recent market trends, Entergy decreased its expected long-term rate of return on plan assets from 9% in 2000 and 2001 to 8.75% for 2002. The trend of reduced inflation caused Entergy to reduce its assumed rate of increase in future compensation levels from 4.6% in 2000 and 2001 to 3.25% in 2002.

 

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 2002 Pension Cost

 

Impact on Projected Benefit Obligation

   

Increase/(Decrease)

 
             

Discount rate

(0.25%)

$ 390

$15,831

Rate of return on plan assets

(0.25%)

$ 1,116

-

Rate of increase in compensation

0.25%

$ 369

$ 3,372

                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 2002 Postretirement Benefit Cost

Impact on Accumulated Postretirement Benefit Obligation

   

Increase/(Decrease)

 
           

Health care cost trend

 

0.25%

 

$ 694

$3,911

Discount rate

 

(0.25%)

 

$ 386

$4,670

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

                Total pension cost for Entergy Arkansas in 2002 was $2.1 million. Taking into account asset performance and the changes made in the actuarial assumptions, Entergy Arkansas does not anticipate 2003 pension cost to be materially different from 2002. Entergy Arkansas was not required to make contributions to its pension plan in 2002 and does not anticipate funding in 2003.

                Due to negative pension plan asset returns over the past several years, Entergy Arkansas' accumulated benefit obligation at December 31, 2002 exceeded plan assets. As a result, Entergy Arkansas was required to recognize an additional minimum liability of $29.6 million as prescribed by SFAS 87. Entergy Arkansas recorded an intangible asset for the $10.6 million of unrecognized prior service cost and the remaining $19 million was recorded as a regulatory asset. Net income for 2002 was not impacted.

                Total postretirement health care and life insurance benefit costs for Entergy Arkansas in 2002 were $16.1 million. Because of a number of factors, including the increased health care cost trend rate, Entergy Arkansas expects 2003 costs to approximate $20.4 million.

INDEPENDENT AUDITORS' REPORT

 

To the Board of Directors and Shareholders of

Entergy Arkansas, Inc.:

We have audited the accompanying balance sheets of Entergy Arkansas, Inc. as of December 31, 2002 and 2001, and the related statements of income, retained earnings, and cash flows (pages 151 through 156 and applicable items in pages 250 through 303) for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with 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 provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Arkansas, Inc. as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.

 

 

 

DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 21, 2003

                           ENTERGY ARKANSAS, INC.                             
                              INCOME STATEMENTS                                
                                                     
                                                                  For the Years Ended December 31,
                                                                  2002           2001        2000
                                                                             (In Thousands)
 
                   OPERATING REVENUES                                                                
Domestic electric                                               $1,561,110    $1,776,776   $1,762,635
                                                                ----------    ----------   ----------
                   OPERATING EXPENSES                                                          
Operation and Maintenance:                                                                           
   Fuel, fuel-related expenses, and                                                                  
     gas purchased for resale                                      294,244       397,080      258,294
   Purchased power                                                 355,211       397,885      560,793
   Nuclear refueling outage expenses                                24,387        28,695       25,884
   Other operation and maintenance                                 543,677       364,409      427,409
Decommissioning                                                          -            13        3,845
Taxes other than income taxes                                       38,127        35,186       39,662
Depreciation and amortization                                      187,525       174,539      169,806
Other regulatory credits - net                                    (184,270)         (721)     (33,078)
                                                                ----------    ----------   ----------
TOTAL                                                            1,258,901     1,397,086    1,452,615
                                                                ----------    ----------   ----------
                                                                                                     
OPERATING INCOME                                                   302,209       379,690      310,020
                                                                ----------    ----------   ----------
                                                                                                     
                      OTHER INCOME                                                             
Allowance for equity funds used during construction                  7,324         6,115       15,020
Interest and dividend income                                         2,467         8,983        8,784
Miscellaneous - net                                                 (6,442)       (5,109)      (4,453)
                                                                ----------    ----------   ----------
TOTAL                                                                3,349         9,989       19,351
                                                                ----------    ----------   ----------
                                                                                                     
               INTEREST AND OTHER CHARGES                                                      
Interest on long-term debt                                          84,823        90,260       88,140
Other interest - net                                                13,287        14,163        8,360
Distributions on preferred securities of subsidiary                  5,100         5,100        5,100
Allowance for borrowed funds used during construction               (4,699)       (3,962)      (9,788)
                                                                ----------    ----------   ----------
TOTAL                                                               98,511       105,561       91,812
                                                                ----------    ----------   ----------
                                                                                                     
INCOME BEFORE INCOME TAXES                                         207,047       284,118      237,559
                                                                                                     
Income taxes                                                        71,404       105,933      100,512
                                                                ----------    ----------   ----------
                                                                                                     
NET INCOME                                                         135,643       178,185      137,047
                                                                                                     
Preferred dividend requirements and other                            7,776         7,744        7,776
                                                                ----------    ----------   ----------
                                                                                                     
EARNINGS APPLICABLE TO                                                                               
COMMON STOCK                                                      $127,867      $170,441     $129,271
                                                                ==========    ==========   ==========
See Notes to Respective Financial Statements.                                                        
                                                                                               

 

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                             ENTERGY ARKANSAS, INC.                                    
                            STATEMENTS OF CASH FLOWS                                   
                                                               
                                                                       For the Years Ended December 31,
                                                                        2002         2001        2000
                                                                                (In Thousands)
                     OPERATING ACTIVITIES                                                               
Net income                                                             $135,643     $178,185    $137,047
Noncash items included in net income:                                                                   
  Other regulatory credits - net                                       (184,270)        (721)    (33,078)
  Depreciation, amortization, and decommissioning                       187,525      174,552     173,651
  Deferred income taxes and investment tax credits                       54,955        6,389      39,776
  Allowance for equity funds used during construction                    (7,324)      (6,115)    (15,020)
Changes in working capital:                                                                             
  Receivables                                                            50,898      (16,073)    (47,647)
  Fuel inventory                                                         (6,509)       5,437      (6,512)
  Accounts payable                                                       39,077     (206,185)    141,172
  Taxes accrued                                                         (88,019)      64,018       1,731
  Interest accrued                                                       (2,772)       2,920       5,246
  Deferred fuel costs                                                    59,849       89,184      35,993
  Other working capital accounts                                        (15,491)      23,283      17,162
Provision for estimated losses and reserves                              (9,952)        (978)       (895)
Changes in other regulatory assets                                      182,244      (39,924)    (85,452)
Changes in other deferred credits                                        10,423       43,157      13,253
Other                                                                   (48,856)      96,049      45,133
                                                                      ---------    ---------   ---------
Net cash flow provided by operating activities                          357,421      413,178     421,560
                                                                      ---------    ---------   ---------
                                                                                                        
                     INVESTING ACTIVITIES                                                               
Construction expenditures                                              (277,189)    (280,755)   (369,370)
Allowance for equity funds used during construction                       7,324        6,115      15,020
Nuclear fuel purchases                                                  (68,127)     (19,103)    (44,722)
Proceeds from sale/leaseback of nuclear fuel                             68,127       19,103      44,722
Decommissioning trust contributions and realized                                                        
    change in trust assets                                              (17,970)     (10,105)    (15,761)
Changes in other temporary investments - net                             38,397      (38,397)          -
Other regulatory investments                                                  -       (3,460)    (97,343)
                                                                      ---------    ---------   ---------
Net cash flow used in investing activities                             (249,438)    (326,602)   (467,454)
                                                                      ---------    ---------   ---------
                                                                                                        
                     FINANCING ACTIVITIES                                                               
Proceeds from the issuance of long-term debt                            188,407       97,384      99,381
Retirement of long-term debt                                           (170,000)           -        (220)
Changes in short-term borrowings                                           (667)           -           -
Dividends paid:                                                                                         
  Common stock                                                         (125,900)     (82,500)    (44,600)
  Preferred stock                                                        (7,776)      (5,832)     (7,691)
                                                                      ---------    ---------   ---------
Net cash flow provided by (used in) financing activities               (115,936)       9,052      46,870
                                                                      ---------    ---------   ---------
                                                                                                        
Net increase (decrease) in cash and cash equivalents                     (7,953)      95,628         976
                                                                                                        
Cash and cash equivalents at beginning of period                        103,466        7,838       6,862
                                                                      ---------    ---------   ---------
                                                                                                        
Cash and cash equivalents at end of period                              $95,513     $103,466      $7,838
                                                                      =========    =========   =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:                                                                        
  Interest - net of amount capitalized                                 $100,965     $101,330     $91,291
  Income taxes                                                          $83,911      $31,939     $60,291
 Noncash investing and financing activities:                                                            
  Change in unrealized depreciation of                                                                  
   decommissioning trust assets                                        ($34,453)    ($14,843)    ($3,920)
  Proceeds from long-term debt issued for the purpose                                                   
   of refunding prior long-term debt                                          -      $47,000           -
  Long-term debt refunded with proceeds from                                                            
   long-term debt issued in prior period                               ($47,000)           -           -
                                                                                                        
See Notes to Respective Financial Statements.                                                           

                          ENTERGY ARKANSAS, INC.
                              BALANCE SHEETS
                                  ASSETS
                                                    
                                                                      December 31,
                                                                  2002           2001
                                                                     (In Thousands)
                      CURRENT ASSETS                                                    
Cash and cash equivalents:                                                              
  Cash                                                             $28,174       $18,331
  Temporary cash investments - at cost,                                                 
    which approximates market                                       67,339        85,135
                                                                ----------    ----------
        Total cash and cash equivalents                             95,513       103,466
                                                                ----------    ----------
Other temporary investments                                              -        38,397
Accounts receivable:                                                                    
  Customer                                                          67,674        80,719
  Allowance for doubtful accounts                                   (8,031)       (5,837)
  Associated companies                                              32,352        65,102
  Other                                                             16,619        25,059
  Accrued unbilled revenues                                         67,838        62,307
                                                                ----------    ----------
    Total accounts receivable                                      176,452       227,350
                                                                ----------    ----------
Deferred fuel costs                                                      -        17,246
Accumulated deferred income taxes                                    5,061        22,698
Fuel inventory - at average cost                                    10,881         4,372
Materials and supplies - at average cost                            78,533        75,499
Deferred nuclear refueling outage costs                             25,858        14,508
Prepayments and other                                                8,335        53,386
                                                                ----------    ----------
TOTAL                                                              400,633       556,922
                                                                ----------    ----------
                                                                                        
              OTHER PROPERTY AND INVESTMENTS                                            
Investment in affiliates - at equity                                11,215        11,217
Decommissioning trust funds                                        334,631       351,114
Non-utility property - at cost (less accumulated depreciation)       1,460         1,465
Other                                                                2,976         2,976
                                                                ----------    ----------
TOTAL                                                              350,282       366,772
                                                                ----------    ----------
                                                                                        
                       UTILITY PLANT                                                    
Electric                                                         5,644,477     5,399,294
Property under capital lease                                        30,354        35,604
Construction work in progress                                      132,792       157,994
Nuclear fuel under capital lease                                    88,101        65,556
Nuclear fuel                                                        10,543         8,156
                                                                ----------    ----------
TOTAL UTILITY PLANT                                              5,906,267     5,666,604
Less - accumulated depreciation and amortization                 2,722,342     2,615,013
                                                                ----------    ----------
UTILITY PLANT - NET                                              3,183,925     3,051,591
                                                                ----------    ----------
                                                                                        
             DEFERRED DEBITS AND OTHER ASSETS                                           
Regulatory assets:                                                                      
  SFAS 109 regulatory asset - net                                  111,748       164,146
  Unamortized loss on reacquired debt                               39,792        40,817
  Other regulatory assets                                          130,689       260,535
Other                                                               39,899        10,797
                                                                ----------    ----------
TOTAL                                                              322,128       476,295
                                                                ----------    ----------
                                                                                        
TOTAL ASSETS                                                    $4,256,968    $4,451,580
                                                                ==========    ==========
See Notes to Respective Financial Statements.                                           

    
                          ENTERGY ARKANSAS, INC.
                              BALANCE SHEETS
                   LIABILITIES AND SHAREHOLDERS' EQUITY
                                                    
                                                                       December 31,
                                                                   2002           2001
                                                                      (In Thousands)
                    CURRENT LIABILITIES                                                  
Currently maturing long-term debt                                  $255,000       $85,000
Notes payable                                                             -           667
Accounts payable:                                                                        
  Associated companies                                               37,833        32,868
  Other                                                             121,148        87,036
Customer deposits                                                    35,886        32,589
Taxes accrued                                                        16,262       104,281
Interest accrued                                                     27,772        30,544
Deferred fuel costs                                                  42,603             -
Obligations under capital leases                                     58,745        51,973
System Energy refund                                                  3,764        53,732
Other                                                                17,734        17,221
                                                                 ----------    ----------
TOTAL                                                               616,747       495,911
                                                                 ----------    ----------
                                                                                         
          DEFERRED CREDITS AND OTHER LIABILITIES                                         
Accumulated deferred income taxes and taxes accrued                 821,829       809,742
Accumulated deferred investment tax credits                          78,231        83,239
Obligations under capital leases                                     59,711        49,187
Transition to competition                                                 -       152,414
Accumulated provisions                                               31,463        41,415
Other                                                               117,847       107,424
                                                                 ----------    ----------
TOTAL                                                             1,109,081     1,243,421
                                                                 ----------    ----------
                                                                                         
Long-term debt                                                    1,125,000     1,308,075
Company-obligated mandatorily redeemable                                                 
  preferred securities of subsidiary trust holding                                       
  solely junior subordinated deferrable debentures                   60,000        60,000
                                                                                         
                   SHAREHOLDERS' EQUITY                                                  
Preferred stock without sinking fund                                116,350       116,350
Common stock, $0.01 par value, authorized 325,000,000                                    
   shares; issued and outstanding 46,980,196 shares in 2002                                  
  and 2001                                                              470           470
Paid-in capital                                                     591,127       591,127
Retained earnings                                                   638,193       636,226
                                                                 ----------    ----------
TOTAL                                                             1,346,140     1,344,173
                                                                 ----------    ----------
                                                                                         
Commitments and Contingencies                                                            
                                                                                         
            TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY           $4,256,968    $4,451,580
                                                                 ==========    ==========
See Notes to Respective Financial Statements.                                            

                         ENTERGY ARKANSAS, INC.                             
                   STATEMENTS OF RETAINED EARNINGS                        
                                                        
                                                For the Years Ended December 31,
                                                    2002      2001        2000
                                                         (In Thousands)

Retained Earnings, January 1                      $636,226  $548,285   $463,614
                                                                               
  Add:                                                                         
    Net income                                     135,643   178,185    137,047
                                                                               
  Deduct:                                                                      
    Dividends declared:                                                        
      Preferred stock                                7,776     7,744      7,776
      Common stock                                 125,900    82,500     44,600
                                                  --------  --------   --------
        Total                                      133,676    90,244     52,376
                                                  --------  --------   --------
                                                                               
Retained Earnings, December 31                    $638,193  $636,226   $548,285
                                                  ========  ========   ========
                                                                               
See Notes to Respective Financial Statements.                                  

 

ENTERGY ARKANSAS, INC.

SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON

 

 

2002

2001

2000

1999

1998

 

(In Thousands)

Operating revenues

$ 1,561,110

$ 1,776,776

$ 1,762,635

$ 1,541,894

$ 1,608,698

Net income

$ 135,643

$ 178,185

$ 137,047

$ 69,313

$ 110,951

Total assets

$ 4,256,968

$ 4,451,580

$ 4,228,211

$ 3,917,111

$ 4,006,651

Long-term obligations (1)

$ 1,244,711

$ 1,417,262

$ 1,401,062

$ 1,265,846

$ 1,335,248

           

  1. Includes long-term debt (excluding currently maturing debt), preferred securities of subsidiary trust, and noncurrent capital lease obligations.

 

 

 

 

 

 

 

 

ENTERGY GULF STATES, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Operating Income

2002 Compared to 2001

                Operating income decreased $45.5 million primarily due to the following:

    • regulatory items (net) of $21.2 million primarily relating to capacity charges associated with power purchases for the summers of 2002 and 2001 and the settlement of the fourth through eighth post-merger earnings reviews in Louisiana, partially offset by the gain recognition of the Louisiana portion of the 1988 Nelson Units 1 and 2 sale;
    • decreased net wholesale revenue of $38.6 million primarily due to a decrease in sales volume;
    • increased other operation and maintenance expenses of $15.6 million, which are explained below; and
    • increased depreciation and amortization expenses of $13.1 million due to an increase in plant in service combined with revisions made to the useful lives of certain intangible plant assets to more appropriately reflect their actual lives, which lowered expense in 2001 in accordance with regulatory treatment.

The decrease in operating income was partially offset by:

    • an increase in the price applied to unbilled revenues of $38.0 million; and
    • more favorable retail sales volume and weather of $36.5 million.

                Other operation and maintenance expenses increased primarily due to:

    • increased benefit costs of $15.9 million;
    • increased maintenance outage costs of $9.5 million at several plants; and
    • higher nuclear expenses of $2.0 million.

The increase in other operation and maintenance expenses was partially offset by decreased unbundling and transition to competition costs of $7.2 million.

2001 Compared to 2000

            Operating income decreased $16.1 million primarily due to the following drivers:

    • less favorable volume and weather reducing retail sales by $63.4 million. Lower electric sales volume reduced revenues due to decreased usage of 1,302 GWh in the industrial sector and 338 GWh in the residential and commercial sectors; and
    • a decrease in price applied to unbilled revenues of $55.8 million.

The decrease was partially offset by increased net wholesale revenues of $34.1 million primarily due to increased sales volume to municipal and co-op customers.

Other Impacts on Earnings

2002 Compared to 2001

                Other income decreased $5.9 million primarily due to decreased interest income of $11.4 million recorded on the deferred fuel balance due to partial recovery of the balance, somewhat offset by the settlement of liability insurance coverage for $5.6 million.

                Interest charges decreased $30.0 million primarily due to:

    • lower interest expense of $12.2 million as a result of the retirement of $148 million of first mortgage bonds in January 2002;
    • lower interest expense of $9.3 million on variable-rate first mortgage bonds; and
    • an adjustment of $5.5 million in 2001 to the liability for deferred compensation for certain former Entergy Gulf States employees in accordance with an actuarial study.

2001 Compared to 2000

                Other income increased $6.7 million primarily due to increased interest income recorded on the deferred fuel balance due to significantly higher natural gas prices in 2001.

                Interest charges increased $13.1 million primarily due to:

    • higher interest expense of $10.3 million primarily due to the issuance of $300 million of long-term debt in June 2000 and the net issuance of an additional $177 million of long-term debt in August 2001; and
    • an adjustment of $5.5 million to the liability for deferred compensation for certain former Entergy Gulf States employees in accordance with an actuarial study.

Income Taxes

                The effective income tax rates for 2002, 2001, and 2000 were 27.5%, 31.4%, and 36.5%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate.

Other Income Statement Variances

2002 Compared to 2001

                Operating revenues decreased $464.7 million primarily due to decreased fuel cost recovery revenues which are offset by decreased fuel and purchased power expenses of $467.2 million due to lower prices.

                Decreased usage in the industrial sector in 2002 was due to contractual modifications that reclassified sales associated with certain customers from retail to wholesale. Under the terms of the former contract with these customers, Entergy Gulf States was also required to purchase the electricity produced by the customers' generating units. As a result of the cessation of the purchased power obligation, the reclassification of these sales did not have a material impact on Entergy Gulf States' earnings.

                Other regulatory credits decreased $18.9 million primarily due to the:

    • deferral in 2001 of $16.9 million in capacity charges in the Louisiana jurisdiction associated with power purchases for the summers of 2000 and 2001 and the amortization of these capacity charges for $7.1 million in 2002; and
    • costs of $9.3 million associated with the establishment of the Texas System Benefit Fund in 2001.

The decrease was somewhat offset by the income recognition of $15.2 million of the Louisiana portion of the unamortized deferred gain on the 1988 sale of Nelson Units 1 and 2. The deferred gain was recognized in income because the LPSC no longer requires that amortization of the gain reduce Entergy Gulf States' recoverable fuel.

2001 Compared to 2000

                Operating revenues increased $137.3 million primarily due to:

    • increased fuel cost recovery revenues in the Louisiana jurisdiction primarily due to the recovery through the fuel adjustment clause of higher fuel and purchased power costs; and
    • increased fuel cost recovery revenues in the Texas jurisdiction primarily due to increases in the fixed fuel factor in March and again in August as well as a fuel recovery surcharge which became effective in February 2001 and expired in December 2001.

                Fuel and purchased power expenses related to electric sales increased by $177.6 million primarily as a result of the over-recovery of fuel and purchased power costs. The over-recovery is due to the collection of higher fuel and purchased power costs through the fuel adjustment clause in the Louisiana jurisdiction and due to increases in the fixed fuel factor and a fuel recovery surcharge in the Texas jurisdiction.

                Other regulatory credits increased $18.5 million primarily due to:

    • the deferral of $16.9 million in capacity charges in the Louisiana jurisdiction associated with power purchases for the summers of 2000 and 2001; and
    • costs of $9.3 million associated with the establishment of the Texas System Benefit Fund.

The increase was partially offset by the recording of a regulatory asset of $3.2 million in 2000 related to low-level radiation waste expenses and the amortization of the Louisiana capacity charges of $2.0 million.

Liquidity and Capital Resources

Cash Flow

                Cash flows for the years ended December 31, 2002, 2001, and 2000 were as follows:

2002

2001

2000

(In Thousands)

Cash and cash equivalents at beginning of period

$123,728 

$ 68,279 

$ 32,312 

Cash flow provided by (used in):

   Operating activities

500,654 

338,486 

403,880 

   Investing activities

(351,456)

(363,416)

(410,027)

   Financing activities

    45,478 

    80,379 

    42,114 

      Net increase in cash and cash equivalents

  194,676 

    55,449 

    35,967 

Cash and cash equivalents at end of period

$318,404 

$123,728 

$ 68,279 

Operating Activities

                Cash flow from operations increased in 2002 compared to 2001 primarily due to an increase in payables due to the timing of fuel payments, partially offset by the decreased collection of deferred fuel in 2002 due to collections in 2001 of high balances.

                Cash flow from operations decreased in 2001 compared to 2000 primarily due to a decrease in payables due to increased payments to fuel suppliers in 2001, partially offset by the increased collection of deferred fuel.

                Entergy Gulf States' receivables from or (payables) to the money pool were as follows as of December 31 for each of the following years:

2002

 

2001

 

2000

 

1999

   

(In Thousands)

 

$18,131

 

$27,665

 

$23,437

 

($36,104)

Money pool activity increased Entergy Gulf States' operating cash flows by $9.5 million in 2002, decreased operating cash flow by $4.2 million in 2001, and decreased operating cash flow by $59.5 million in 2000. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.

Investing Activities

                Net cash used in investing activities decreased slightly in 2002 compared to 2001 because of the maturity in 2002 of the other temporary investments made in 2001. The decrease in net cash used was almost entirely offset by increases in other regulatory investments, which are deferred fuel costs expected to be collected over a period greater than twelve month, and capital expenditures. Capital expenditures increased primarily due to increased spending on environmental projects.

                The decrease in net cash used in investing activities in 2001 compared to 2000 was primarily due to increases in other temporary investments and capital expenditures, partially offset by a decrease in other regulatory investments due to collection of deferred fuel costs. Capital expenditures increased primarily due to additional transmission line work, transition to competition projects, and increased spending on customer information systems projects.

Financing Activities

                The decrease in net cash provided by financing activities in 2002 was primarily due to a decrease of $30.3 million in net issuances of long-term debt.

                The increase in net cash provided by financing activities in 2001 was primarily due to the redemption of $150 million of preference stock in 2000, partially offset by the decrease of $124.9 million in net issuances of long-term debt in 2001.

                See Note 7 to the domestic utility companies and System Energy financial statements for details on long-term debt.

Uses of Capital

                Entergy Gulf States requires capital resources for:

    • construction and other capital investments;
    • debt and preferred stock maturities;
    • working capital purposes, including the financing of fuel and purchased power costs; and
    • dividend and interest payments.

                Following are the amounts of Entergy Gulf States' planned construction and other capital investments, existing debt and lease obligations, and other purchase obligations:

2003

2004

2005

2006-2007

after 2007

(In Millions)

Planned construction and

   capital investment

$236

$226

$230

N/A

N/A

Long-term debt maturities

$293

$654

$98

$200

$1,007

Capital and operating lease payments (1)

$29

$28

$17

$24

$14

Unconditional fuel and purchased

   power obligations (2)

$28

$24

$2

$4

$25

Nuclear fuel lease obligations (1)(3)

$29

$12

N/A

N/A

N/A

    1. Lease obligations are discussed in Note 10 to the domestic utility companies and System Energy financial statements.
    2. Unconditional fuel and purchased power obligations are discussed in Note 9 to the domestic utility companies and System Energy financial statements under "Fuel Supply Agreements" and "Power Purchase Agreements."
    3. It is expected that additional financing under these leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. If such additional financing cannot be arranged, however, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations.

The planned capital investment estimate for Entergy Gulf States reflects capital required to support existing business and customer growth. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, market volatility, economic trends, business restructuring, and the ability to access capital. Management provides more information on construction expenditures and long-term debt and preferred stock maturities in Notes 5, 6, 7, and 9 to the domestic utility companies and System Energy financial statements.

                As a wholly-owned subsidiary, Entergy Gulf States dividends its earnings to Entergy Corporation at a percentage determined monthly. Currently, all of Entergy Gulf States' retained earnings are available for distribution.

Sources of Capital

                Entergy Gulf States' sources to meet its capital requirements include:

    • internally generated funds;
    • cash on hand;
    • debt issuances; and
    • bank financing under new or existing facilities.

                In 2002, Entergy Gulf States issued $340 million of long-term debt. The net proceeds were used to redeem or repurchase prior to maturity, or to repay at maturity, $339 million of Entergy Gulf States' outstanding debt with 2003 maturities. Entergy Gulf States is expected to continue refinancing or redeeming higher-cost debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

                All debt and common and preferred stock issuances by Entergy Gulf States require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in its corporate charter, bond indentures, and other agreements.

                Short-term borrowings by Entergy Gulf States, including borrowings under the money pool, are limited to an amount authorized by the SEC, $340 million. Under the SEC order authorizing the short-term borrowing limits, Entergy Gulf States cannot incur new short-term indebtedness if its common equity would comprise less than 30% of its capital. In addition, this order restricts Entergy Gulf States from publicly issuing new long-term debt unless its senior secured debt will be rated as investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy Gulf States' short-term borrowing limits.

Significant Factors and Known Trends

Transition to Retail Competition

                Retail open access commenced in portions of Texas on January 1, 2002. The staff of the PUCT filed a petition to determine readiness for retail open access, and, if appropriate, delay retail open access in Entergy Gulf States' service area, and Entergy Gulf States reached a settlement agreement that was 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 appears by January 15, 2003 that a FERC-approved RTO will not be functional by January 1, 2004. On January 24, 2003, Entergy Gulf States filed its proposal, which among other elements, includes:

    • 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 is expected to consider this proposal on March 21, 2003.

This proposal takes into account that other regulatory approvals, including that of the LPSC and the SEC, are necessary prior to January 1, 2004.

                With retail open access, generation and a new retail electric provider operation are competitive businesses, but transmission and distribution operations continue to be regulated. The new retail electric providers are the primary point of contact with customers. The provisions of the retail open access law in Texas:

    • require a rate freeze through December 31, 2001 (subject to extension, as described below), with rates reduced by 6% beyond that for residential and small commercial customers of most incumbent utilities except Entergy Gulf States, whose rates are exempt from the 6% reduction requirement. These rates to residential and small commercial customers are known as the "price-to-beat," and they may be adjusted periodically after retail open access begins for fuel and purchased power costs according to PUCT rules;
    • require utilities to charge the price-to-beat rates until 36 months after the date competition begins or 40% of customers in the jurisdiction have chosen an alternative supplier, whichever comes first. Nevertheless, the price-to-beat rates must continue to be made available at least through 2006;
    • required utilities to submit a plan to separate (unbundle) their generation, transmission, distribution, and retail electric provider functions, which Entergy Gulf States filed in January 2000 as discussed below;
    • require utilities to comply with a code of conduct to ensure that utilities do not allow affiliates to have a business advantage over competitors;
    • require operation in a non-discriminatory manner of transmission and distribution facilities by an organization independent from the generation and retail operations by the time competition is implemented;
    • allow for recovery of stranded costs incurred in purchasing power and providing electric generation service if the costs are approved by the PUCT;
    • allow for securitization of regulatory assets and PUCT-approved stranded costs;
    • provide for the determination of and mitigation measures for generation market power; and
    • required utilities to file separated cost data and proposed transmission, distribution, and competition transition tariffs by April 1, 2000 (Entergy Gulf States filed a non-unanimous settlement in March 2001 addressing these tariffs and costs, as discussed below).

                On August 3, 2001, the PUCT staff filed a petition requesting that the PUCT determine whether the market is ready for retail open access in the portion of Texas within the Southeastern Electric Reliability Council (SERC), which includes Entergy Gulf States' service territory. Several parties, including Entergy Gulf States and the PUCT staff, agreed to a non-unanimous settlement that was approved by the PUCT after a hearing in October 2001. In December 2001, the PUCT issued a written order approving the settlement. The settlement agreement contains several points, including:

    • a delay in the commencement of retail open access in Entergy Gulf States' Texas service territory until at least September 15, 2002, subject to certain provisions of the settlement agreement;
    • recovery of transition to competition costs incurred by Entergy Gulf States through December 31, 2001 if a rate proceeding is initiated for Entergy Gulf States during the delay period. The settlement agreement provides for a rate freeze during the delay period. Entergy cannot predict whether a new rate proceeding for Entergy Gulf States will be initiated during the delay period or what the outcome of such proceeding might be;
    • suspension of capacity auctions until at least sixty days before retail open access commences (the capacity auctions are discussed below);
    • continuation of Entergy Gulf States' pilot project;
    • initiation by the PUCT of a project to develop market protocols to support retail open access;
    • efforts to develop an interim solution to implement retail open access no sooner than September 15, 2002 in the event that a functional, FERC-approved RTO is not likely to be achieved in the 2002 time frame (the RTO and related power region certification issue are discussed below);
    • continuation of pending proceedings (discussed below) to determine the fuel and base rate components of the price-to-beat rates with implementation of these rates when retail open access begins, without escalation of the fuel component during the delay period;
    • continuation of Entergy Gulf States' current bundled rates and fuel factor methodology until the commencement of retail open access unless addressed in the interim solution;
    • continuation of efforts by Entergy Gulf States to obtain the appropriate approvals with respect to its business separation plan (discussed below) with the actual business separation not occurring until the eve of retail open access; and
    • filing by Entergy Gulf States for certification by the PUCT of a qualified power region, which filing must contain an assessment of market power, including transmission constraints.

In February 2002, certain cities in Texas (cities) served by Entergy Gulf States filed a petition in district court in Travis County, Texas seeking judicial review of the order issued by the PUCT. The cities' petition alleges that the PUCT's order is unlawful because it violates statutory and constitutional provisions. Entergy will defend vigorously its position that the cities' claims are without merit. Management cannot predict the outcome of this litigation at this time.

Business Separation Plan

                 Entergy Gulf States' business separation plan provides for the separation of its generation, transmission, distribution, and retail electric functions. It has been amended during the course of various PUCT and LPSC proceedings and is subject to further change and regulatory proceedings as described below.

                The amended plan currently provides that Entergy Gulf States will be separated into the following principal companies:

    • a Texas distribution company, which will own and operate Entergy Gulf States' electric distribution system in Texas;
    • an intermediate transmission company;
    • a Texas generation company (which may be more than one legal entity), which initially will purchase capacity and energy from the generating assets allocated to Texas load (Texas generating assets), and eventually will own those assets;
    • Texas retail electric providers, which will provide competitive retail electric service in Texas; and
    • Entergy Gulf States-Louisiana.

Entergy Gulf States-Louisiana will:

    • own and operate Entergy Gulf States' electric distribution system in Louisiana, the Texas generating assets (until they are transferred to the Texas generation company), the remainder of Entergy Gulf States' generating assets, and Entergy Gulf States' other businesses that are not separated, and own Entergy Gulf States' transmission assets allocated to Louisiana (until they are transferred to the intermediate transmission company described in the next bullet); and
    • indirectly own a portion of an intermediate transmission company, which will own Entergy Gulf States' electric transmission assets allocated to Texas, and later Entergy Gulf States' transmission assets allocated to Louisiana.

                Entergy Gulf States' assets and liabilities (other than its long-term debt and liabilities) will be allocated among these companies generally based upon categorizing them by function. Entergy Gulf States will allocate assets and liabilities not associated with a single function based upon specified factors. In an April 2001 filing with the LPSC discussing its separation methodology, Entergy Gulf States included a balance sheet separated by jurisdiction and function. The balance sheet was based on September 30, 1999 balances. In this balance sheet, Entergy Gulf States allocated approximately 27% of the net utility plant balance to Texas generation, approximately 12% to Texas distribution, approximately 6% to Texas transmission, approximately 7% to Louisiana transmission, and less than 1% to Texas retail. Applying these percentages to Entergy Gulf States' December 31, 2002 net utility plant book value of $4.4 billion, for illustrative purposes only, results in net book values of approximately $1.2 billion for Texas generation, approximately $520 million for Texas distribution, approximately $260 million for Texas transmission, approximately $300 million for Louisiana transmission, approximately $20 million for Texas retail, and approximately $2.1 billion for the remainder of Entergy Gulf States-Louisiana. The actual allocations could materially differ from these figures because of a number of factors, including changes to the plan and the allocation methodology. In addition, the actual allocations will be based on allocation factors and account balances as of a different date.

                The business separation plan provides that Entergy Gulf States-Louisiana will retain liability for all of its long-term debt and liabilities and that the property transferred to the Texas companies will be released from the lien of Entergy Gulf States' mortgage on the basis of property additions. Pursuant to separate agreements, the Texas distribution company and the intermediate transmission company will each assume a portion of Entergy Gulf States' long-term debt and liabilities, which assumptions will not act to release Entergy Gulf States-Louisiana's liability. The Texas distribution company and the intermediate transmission company will undertake to pay the outstanding assumed long-term debt and liabilities within 1 year and 3 years, respectively, of the assumption. Entergy must provide a contingent indemnity with respect to the intermediate transmission company's assumed portion of Entergy Gulf States' long-term debt and liabilities in the event that the obligations under the debt assumption agreement have not been extinguished within one year of the assumption. The Texas generation company will be required to pay an allocated portion of the outstanding principal amount of Entergy Gulf States' long-term debt and liabilities each time that Texas generating assets are transferred to it, and the transfers must be completed within 3 years of the commencement of retail open access.

                After the transfer of the Texas distribution and transmission assets contemplated by the current business separation plan, the distribution and transmission businesses conducted by the Texas distribution company and the intermediate transmission company, respectively, will continue to be regulated as to rates by the PUCT and the FERC, respectively. Accordingly, management believes that the Texas distribution company and the intermediate transmission company will be able to fund the payment of the assumed debt within the required period from a combination of cash flow from operations and third party financing.

                Entergy Gulf States filed the business separation plan with the PUCT in January 2000 and amended that plan in June and November 2000 and January 2001. In July 2000, the PUCT approved the amended business separation plan in an interim order. In January 2001, the PUCT consolidated remaining action on the business separation plan into the unbundled cost of service proceeding discussed below. In December 2001, the PUCT abated the proceeding and indicated it will consider a final order in a timely manner consistent with the settlement agreement delaying retail open access. The outcome of the LPSC proceedings described below, which have resulted in amendments to the plan beyond what was approved by the PUCT, have been and will continue to be reported to the PUCT and the Office of Public Utility Counsel and may require additional PUCT action before the business separation plan is final.

                The LPSC opened a docket to identify the changes in corporate structure and operations of Entergy Gulf States, and their potential impact on Louisiana retail ratepayers, resulting from restructuring in Texas and Arkansas. In those proceedings, Entergy Gulf States and the LPSC staff reached a settlement on certain Texas business separation plan issues described above, and after a May 2001 hearing, the LPSC issued an interim order in July 2001 approving the settlement. In July 2001, Entergy Gulf States and the LPSC staff completed an additional settlement on business separation plan issues relating to the separation of Texas distribution and transmission. A hearing on the distribution and transmission settlement has been held and the LPSC approved the settlement in September 2001. With respect to issues related to the separation of generation, the LPSC had scheduled a hearing in November 2001 to address settled issues. In light of the delay in the commencement of retail open access, the procedural schedule in the LPSC docket has been suspended to assess the impact of the PUCT approval of the settlement agreement delaying retail open access.

Generation-related Issues

                Regarding the generation-related issues referred to in the preceding paragraph, Entergy Gulf States has not yet reached agreement with the LPSC staff on certain matters related to the separation of the Texas generating assets. Entergy Gulf States has proposed that Texas generating assets be a jurisdictional portion (approximately 45 - 50%) of each generating plant and that Entergy Gulf States-Louisiana continue to operate the plants. Entergy Gulf States has also suggested that certain generating assets be allocated by specific plant such that the Texas generating assets have approximately the Texas jurisdictional portion of the capacity and value of all of Entergy Gulf States' generating assets.

                Until the Texas generating assets are transferred to the Texas generation company, which, as currently proposed, will occur within three years from the commencement of retail open access in Texas, Entergy Gulf States-Louisiana expects to sell most of the Texas jurisdictional capacity and energy from these assets to the Texas generation company under a power sale agreement. The power sale agreement is expected to require the Texas generation company to pay all costs, including a reasonable return on equity, for the capacity and energy of the Texas generating assets. The Texas generation company is expected to sell most of this capacity and energy to Entergy's affiliated Texas retail electric providers at a negotiated rate and sell any remainder to the market. Entergy's affiliated Texas retail electric providers will use the capacity and energy to provide retail electric service to retail customers in Texas, including Entergy's price-to-beat obligation, which requires it to sell electricity to residential and small commercial customers in the service territory of the Texas distribution company at a rate equal to the existing base rates plus a fuel component.

                Up to 20% of capacity and energy from the Texas generating assets must be sold to third parties under PUCT rules, or to Entergy's domestic utility companies that elect to purchase it, as described below:

    • Under the Texas restructuring legislation and a stipulation, Entergy Gulf States offered to sell at auction entitlements to approximately 15% (approximately 425MW) of its Texas-jurisdictional installed generation capacity. Auctions occurred in September 2001, but because of the delay in retail open access, Entergy has unwound the auction transactions, and no liability exists for them. Additional capacity auctions are suspended until at least 60 days prior to the introduction of retail open access. The obligation to auction capacity entitlements continues for up to 60 months after retail open access occurs, or until 40% of current customers have chosen an alternative supplier, whichever comes first.
    • Under the settlement of proceedings affecting the System Agreement, which are described in Item I. Part 1. "U.S. Utility - Rate Matters - Wholesale Rate Matters - System Agreement," Entergy's domestic utility companies have the option to purchase up to 5% of the megawatt capacity of the Texas generating assets. If the capacity purchase is elected, it will be for the period from the inception of retail open access in Texas for Entergy Gulf States through June 2008.

Beginning on the date retail open access begins, the market power measures in the Texas restructuring law will prohibit the Texas generation company and its affiliates from owning and controlling more than 20% of the installed generation capacity located in, or capable of delivering electricity to, a power region. The implications of this limit are uncertain. It is possible that the Texas generation company (or its affiliates) could be required to auction additional capacity entitlements, divest some of the Texas generating assets, or seek other means of mitigation if it is found to have ownership and control in excess of this limit.

Other PUCT Restructuring-related Proceedings

                In March 2001, Entergy Gulf States filed with the PUCT a non-unanimous settlement agreement in the unbundled cost proceeding that establishes the Texas distribution company's revenue requirement. The settlement agreement is between Entergy Gulf States, the PUCT staff, and other parties. Pursuant to a generic order by the PUCT, the Texas distribution company's allowed return on equity will be 11.25%. The capital structure prescribed by the PUCT is 60% debt and 40% equity. A rider to recover nuclear decommissioning costs will be implemented. Also in the settlement agreement, the parties agreed that Entergy Gulf States' Texas-jurisdictional stranded costs and benefits are $0, and no charge to recover stranded costs or credit to refund excess mitigation will be implemented. Entergy Gulf States agreed in the settlement to refund any excess earnings resulting from the restructuring law's annual report process for 2000 and 2001, which management does not expect to have a material financial effect. After a hearing in April 2001, the PUCT voted to approve a rate order consistent with the terms of the settlement. A written interim order was signed in May 2001. In December 2001, the PUCT abated the proceeding and indicated its intent to defer a final ruling on this proceeding until a date closer to the commencement of retail open access.

                The settlement that has delayed the commencement of retail open access requires a new power region certification proceeding for Entergy Gulf States' service territory in Texas. If Entergy Gulf States' power region in Texas is not certified by the PUCT before retail open access is introduced, Entergy's affiliated Texas retail electric provider could be required to maintain rates at the price-to-beat levels for residential and small commercial customers in Entergy Gulf States' service territory beyond January 1, 2007. Entergy's affiliated Texas retail electric provider could also be required to offer rates to industrial and large commercial customers in Entergy Gulf States' service territory that are no higher than the rates that, on a bundled basis, were in effect on January 1, 1999, subject to fuel factor adjustments. Entergy's affiliated Texas retail electric provider might also face requests for restrictions on its ability to compete for retail customers in parts of its power region in Texas outside of its current service area.

                In July 2001, Entergy Gulf States filed an application for approval of the fuel factor portion of Entergy's affiliated Texas retail electric provider's price-to-beat rates, and the gas prices included in that filing were updated in October 2001. After the gas price update, Entergy Gulf States recommended that the PUCT approve an average fuel factor of approximately $29/MWh adjusted, if necessary, to maintain an adequate competitive margin. After hearing, an ALJ recommended in November 2002 a lower fuel factor than Entergy Gulf States requested. The PUCT has not taken final action on the ALJ's recommendation. In June 2001, Entergy Gulf States filed tariffs for the non-fuel component of the price-to-beat rates. The tariffs are based on Entergy Gulf States' current base rates. In September 2001, Entergy Gulf States entered into a unanimous settlement regarding the non-fuel component of price-to-beat rates. In February 2002, the PUCT voted to approve the settlement.

State and Local Rate Regulatory Risks

                The rates that Entergy Gulf States charges for its services are an important item influencing its financial position, results of operations, and liquidity. Entergy Gulf States is closely regulated and the rates charged to its customers are determined in regulatory proceedings, except for a portion of its operations. Governmental agencies, the LPSC and the PUCT, are primarily responsible for approval of the rates charged to customers.

                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 relating to remaining issues that arose in Entergy Gulf States' fourth, fifth, sixth, seventh, and eighth 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. The filing also contained a prospective revenue requirement study based on the 2001 test year that showed that a prospective rate increase of approximately $21.7 million would be appropriate. Both components of the filing are subject to review by the LPSC and may result in changes in rates other than those sought in the filing. A procedural schedule has been adopted and hearings are scheduled for October 2003.

                In addition to rate proceedings, Entergy Gulf States' fuel costs recovered from customers are subject to regulatory scrutiny. In January 2003, the LPSC opened a docket to investigate the fuel adjustment clause practices of Entergy Gulf States and its affiliates. The investigation will include a review of the reasonableness of charges flowed by Entergy Gulf States through its fuel adjustment clause in Louisiana for the period subsequent to 1994. No assurance can be given as to the timing or outcome of this proceeding.

                Entergy Gulf States' retail rate matters and proceedings, including fuel cost recovery-related issues, are discussed in Note 2 to the domestic utility companies and System Energy financial statements.

System Agreement Proceedings

                The System Agreement provides for the integrated planning, construction, and operation of Entergy's electric generation and transmission assets throughout the retail service territories of the domestic utility companies. Under the terms of the System Agreement, generating capacity and other power resources are jointly operated by the domestic utility companies. The System Agreement provides, among other things, that parties having generating reserves greater than their load requirements (long companies) shall receive payments from those parties having deficiencies in generating reserves (short companies). Such payments are at amounts sufficient to cover certain of the long companies' costs for intermediate and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred and preference stock, and a fair rate of return on common equity investment. Under the System Agreement, these charges are based on costs associated with the long companies' steam electric generating units fueled by oil or gas. In addition, for all energy exchanged among the domestic utility companies under the System Agreement, the short companies are required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.

                The LPSC and the Council commenced a proceeding at FERC in June 2001. In this proceeding, the LPSC and the Council allege that the rough production cost equalization required by FERC under the System Agreement and the Unit Power Sales Agreement has been disrupted by changed circumstances. The LPSC and the Council have requested that FERC amend the System Agreement or the Unit Power Sales Agreement or both to achieve full production cost equalization or to restore rough production cost equalization. Their complaint does not seek a change in the total amount of the costs allocated by either the System Agreement or the Unit Power Sales Agreement. In addition, the LPSC and the Council allege that provisions of the System Agreement relating to minimum run and must run units, the methodology of billing versus dispatch, and the use of a rolling twelve-month average of system peaks, increase costs paid by ratepayers in the LPSC and Council's jurisdictions. Several parties have filed interventions in the proceeding, including the APSC and the MPSC. Entergy filed its response to the complaint in July 2001 denying the allegations of the LPSC and the Council. The APSC and the MPSC also filed responses opposing the relief sought by the LPSC and the Council.

                In their complaint, the LPSC and the Council allege that Entergy Gulf States' Louisiana annual production costs over the period 2002 to 2007 will be $11 million to $87 million over the average for the domestic utility companies. 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. In February 2002, the FERC set the matter for hearing and established a refund effective period consisting of the 15 months following September 13, 2001. Negotiations among the parties have not resolved the proceeding, and the proceeding is now set for hearing commencing in June 2003. The case had been set for trial commencing in February 2003. The extension of the schedule also extended the refund effective period by 120 days. If FERC grants the relief requested by the LPSC and the Council, 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 Entergy Gulf States, although neither the timing nor the outcome of the proceedings at FERC can be predicted at this time.

                The LPSC has instituted a companion ex parte System Agreement investigation to litigate several of the System Agreement issues that the LPSC is litigating before the FERC in the previously discussed System Agreement proceeding. This companion proceeding will require the LPSC to interpret various provisions of the System Agreement, including those relating to minimum run and must run units, the propriety of the methods used for billing and dispatch on the Entergy System, and the use of a rolling twelve-month average of system peaks for allocating certain costs. In addition, by this companion proceeding the LPSC is questioning whether Entergy Louisiana and Entergy Gulf States were prudent for not seeking changes to the System Agreement previously, so as to lower costs imposed upon their ratepayers and to increase costs imposed upon ratepayers of other domestic utility companies. The domestic utility companies have challenged the propriety of the LPSC's litigating System Agreement issues. Nevertheless, in January 2002 the LPSC affirmed a decision of its ALJ upholding the LPSC staff's right to litigate System Agreement issues at the LPSC, rather than before the FERC. In September 2002, the LPSC staff filed a motion to Delay Hearing and Remaining Pre-Hearing deadlines. After no objections from the other parties, the LPSC ALJ continued the procedural schedule until after the FERC ALJ's initial decision in the related matter, or June 13, 2003, whichever occurs first.

Industrial, Commercial, and Wholesale Customers

                Entergy Gulf States' large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Gulf States' industrial customer base. Entergy Gulf States responds by working with industrial and commercial customers and negotiating electric service contracts that provide service at rates lower than would otherwise be charged. Despite these actions, Entergy Gulf States lost two large industrial customers to cogeneration in 2002. The customers accounted for approximately 1% of its net revenue in 2001. In addition to working with its current customers, Entergy Gulf States also continually participates in economic development activities that can increase industrial and commercial energy demand, from both current and new customers.

Market and Credit Risks

                Entergy Gulf States has certain market and credit risks inherent in its business operations. Market risks represent 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. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement.

Interest Rate and Equity Price Risk - Decommissioning Trust Funds

                Entergy Gulf States' nuclear decommissioning trust funds expose it to fluctuations in equity prices and interest rates. The NRC requires Entergy Gulf States to maintain trusts to fund the costs of decommissioning River Bend. The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that its exposure to market fluctuations will not affect results of operations for the River Bend trust funds because of the application of regulatory accounting principles. The decommissioning trust funds are discussed more thoroughly in Note 9 to the domestic utility companies and System Energy financial statements.

Foreign Currency Exchange Rate Risk

                Entergy Gulf States entered into foreign currency forward contracts to hedge the Euro-denominated payments due under certain purchase contracts. As of December 31, 2002, the total notional amount of the foreign currency forward contracts is 33.7 million Euro and the forward currency rates range from .8742 to .8802. The maturities of these forward contracts depend on the purchase contract payment dates and range in time from January 2003 to July 2004. The mark-to-market valuation of the forward contracts at December 31, 2002 was a net asset of $5.5 million. The counterparty bank obligated on 16.5 million Euro of the notional amount of these agreements is rated by Standard & Poor's Rating Services at A+ on their senior debt obligations as of December 31, 2002. The counterparty bank obligated on 17.2 million Euro of the notional amount of these agreements is rated by Standard & Poor's Rating Services at AA on its senior debt obligations as of December 31, 2002.

Nuclear Matters

                Entergy Gulf States owns and operates, through an affiliate, River Bend. Entergy Gulf States is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of River Bend, Entergy Gulf States may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.

Environmental Risks

                Entergy Gulf States' facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Gulf States is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Litigation Risks

                The states of Louisiana and Texas in which Entergy Gulf States operates have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy Gulf States uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment in these states poses a significant business risk.

Critical Accounting Estimates

                The preparation of Entergy Gulf States' 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 Gulf States' financial statements.

Nuclear Decommissioning Costs

                Regulations require that River Bend be decommissioned after the facility is taken out of service, and funds are collected and deposited in trust funds during the facility's operating life in order to provide for this obligation. Entergy Gulf States conducts periodic decommissioning cost studies (typically updated every three to five years) to estimate the costs that will be incurred to decommission the facility. See Note 9 to the domestic utility companies and System Energy financial statements for details regarding Entergy Gulf States' most recent study and the obligations recorded by Entergy Gulf States related to decommissioning. The following key assumptions have a significant effect on these estimates:

    • Cost Escalation Factors - Entergy Gulf States' decommissioning studies include an assumption that decommissioning costs will escalate over present cost levels by an annual factor averaging approximately 4.5%. A 50 basis point change in this assumption could change the ultimate cost of decommissioning a facility by as much as 11%.
    • Timing - The date of the plant's retirement must be estimated and 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. Entergy Gulf States' decommissioning studies for River Bend assume immediate decommissioning upon expiration of the original plant license. 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 Gulf States' decommissioning studies include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors.
    • Technology and Regulation - To date, there is limited practical experience in the United States with actual decommissioning of large nuclear facilities. As experience is gained and technology changes, cost estimates could also change. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant impact on cost estimates. The impact of these potential changes is not presently determinable. Entergy Gulf States' decommissioning cost studies assume current technologies and regulations.

                Entergy Gulf States collects the projected costs of decommissioning River Bend through rates charged to customers for the portion of the plant subject to cost-based ratemaking. The amounts collected through rates, which are based upon decommissioning cost studies, are deposited in decommissioning trust funds. In December 2002, decommissioning collections from customers for the Louisiana-regulated portion of River Bend was suspended as a result of the settlement with the LPSC of Entergy Gulf States' fourth through eighth earnings reviews. Decommissioning costs have no impact on Entergy Gulf States' earnings, as accrued costs are offset by earnings on trust funds and collections from customers. If decommissioning cost study estimates were changed and approved by regulators, collections from customers would also change.

                Approximately half of River Bend is not subject to cost-based ratemaking. When Entergy Gulf States purchased the 30% share of River Bend formerly owned by Cajun, Entergy Gulf States obtained decommissioning trust funds of $132 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 from customers for decommissioning for this portion of the plant.

                The obligations recorded by Entergy Gulf States for decommissioning are classified either as a component of accumulated depreciation (the regulated portion of River Bend) or as a deferred credit (the nonregulated portion of River Bend) in the line item entitled "Decommissioning." The amounts recorded for these obligations are comprised of collections from customers and earnings on the trust funds. The classification and recording of these obligations will change with the implementation of SFAS 143.

SFAS 143

                Entergy Gulf States implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs comprise substantially all of Entergy Gulf States' asset retirement obligations, and the measurement and recording of Entergy Gulf States' decommissioning obligations outlined above will change 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 will cause the recorded decommissioning obligation of Entergy Gulf States to increase significantly, as Entergy Gulf States 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 Gulf States' decommissioning studies to date have been based on Entergy Gulf States performing the work, and have not included any such margins or premiums. Inclusion of these items increases cost estimates.
    • Discount rate - SFAS 143 requires that these obligations be discounted using a credit-adjusted risk-free rate.

The net effect of implementing this standard for the portion of River Bend subject to cost-based ratemaking will be recorded as a regulatory asset or liability, with no resulting impact on Entergy Gulf States' net income. The implementation of SFAS 143 is expected to result in increases in assets and liabilities in 2003 of approximately $165 million and $190 million, respectively, as a result of recording the asset retirement obligation at its fair value as determined under SFAS 143 and recording the related regulatory asset. Earnings are expected to decrease by $25 million as a result of a one-time cumulative effect of accounting change.

Application of SFAS 71

                The application of SFAS 71, "Accounting for the Effects of Certain Types of Regulation," has a significant and pervasive impact on accounting and reporting for Entergy Gulf States.

                Entergy Gulf States' financial statements primarily reflect assets and costs based on existing cost-based ratemaking regulation in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Under traditional ratemaking practice, Entergy Gulf States is granted a geographic franchise to sell electricity. In return, Entergy Gulf States must make investments and incur obligations to serve customers. Prudently incurred costs are recovered from customers along with a return on investment. Regulators may require Entergy Gulf States to defer collecting from customers some operating costs until a future date. These deferred costs are recorded as regulatory assets in the financial statements. In order to continue applying SFAS 71 to its financial statements, Entergy Gulf States' rates must be set on a cost-of-service basis by an authorized body and the rates must be charged to and collected from customers.

                As the generation portion of the utility industry moves toward competition, it is likely that generation rates will no longer be set on a cost-of-service basis. When that occurs, the generation portion of the business could be required to discontinue application of SFAS 71. The result of discontinuing application of SFAS 71 would be the removal of regulatory assets and liabilities from the balance sheet, and could include the recording of asset impairments. This result is because some of the costs or commitments incurred under a regulated pricing system might be impaired or not recovered in a competitive market. These costs are referred to as stranded costs.

                Retail open access legislation is in place in Texas, but the implementation of retail open access in Entergy Gulf States' territory is likely delayed until at least the first quarter of 2004. Several proceedings necessary to implement retail open access are still pending, including proceedings to implement Entergy Gulf States' business separation plan, and to form an RTO or pursue retail open access in the absence of an RTO in Entergy Gulf States' Texas service area. In addition, the LPSC has not approved for the Louisiana jurisdictional operations the transfer of generation assets to, or a power purchase agreement with, Entergy's Texas generation company. Therefore, neither the necessary regulatory actions nor the opportunity for a reasonable determination of the effect of deregulation has occurred that are prerequisites for Entergy Gulf States to discontinue the application of regulatory accounting principles to its Texas generation operation. For further information on Gulf States' retail open access law, see "Transition to Retail Competition" below.

 

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 domestic utility companies and System Energy 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.

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 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 2000 and 2001 to 6.75% in 2002. 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 rates from a range of 8% gradually decreasing to 5% in 2001 to a range of 10% gradually decreasing to 4.5% in 2002.

                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 plan assets of roughly 65% equity securities and 35% fixed income securities. Based on recent market trends, Entergy decreased its expected long-term rate of return on plan assets from 9% in 2000 and 2001 to 8.75% for 2002. The trend of reduced inflation caused Entergy to reduce its assumed rate of increase in future compensation levels from 4.6% in 2000 and 2001 to 3.25% in 2002.

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 2002
Pension Cost

 

Impact on Projected Benefit Obligation

   

Increase/(Decrease)

 
             

Discount rate

 

(0.25%)

 

$264

 

$13,526

Rate of return on plan assets

 

(0.25%)

 

$1,210

 

-

Rate of increase in compensation

 

0.25%

 

$294

 

$2,569

                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 2002 Postretirement Benefit Cost

 

Impact on Accumulated Postretirement Benefit Obligation

   

Increase/(Decrease)

 
             

Health care cost trend

 

0.25%

 

$ 649

 

$4,131

Discount rate

 

(0.25%)

 

$ 370

 

$4,724

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

                Total pension income for Entergy Gulf States in 2002 was $6.8 million. Taking into account asset performance and the changes made in the actuarial assumptions, Entergy Gulf States does not anticipate 2003 pension income to be materially different from 2002. Entergy Gulf States was not required to make contributions to its pension plan in 2002 and does not anticipate funding in 2003.

                Due to negative pension plan asset returns over the past several years, Entergy Gulf States' accumulated benefit obligation at December 31, 2002 exceeded plan assets. As a result, Entergy Gulf States was required to recognize an additional minimum liability of $7.1 million as prescribed by SFAS 87. Entergy Gulf States recorded an intangible asset for the $7.1 million of unrecognized prior service cost. Net income for 2002 was not impacted.

                Total postretirement health care and life insurance benefit costs for Entergy Gulf States in 2002 were $15.9 million. Because of a number of factors, including the increased health care cost trend rate, Entergy Gulf States expects 2003 costs to approximate $19.1 million.

INDEPENDENT AUDITORS' REPORT

 

To the Board of Directors and Shareholders of

Entergy Gulf States, Inc.:

We have audited the accompanying balance sheets of Entergy Gulf States, Inc. as of December 31, 2002 and 2001, and the related statements of income, retained earnings and comprehensive income, and cash flows (pages 176 through 180 and applicable items in pages 250 through 303) for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with 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 provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Gulf States, Inc. as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.

 

 

 

DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 21, 2003

 

 

 


			  ENTERGY GULF STATES, INC.                            
			      INCOME STATEMENTS                                
						     
							       For the Years Ended December 31,
								2002         2001        2000
									(In Thousands)
		  OPERATING REVENUES                                                            
Domestic electric                                            $2,141,873   $2,590,836  $2,470,884
Natural gas                                                      42,006       57,724      40,356
							     ----------   ----------  ----------
TOTAL                                                         2,183,879    2,648,560   2,511,240
							     ----------   ----------  ----------
												
		  OPERATING EXPENSES                                                       
Operation and Maintenance:                                                                      
   Fuel, fuel-related expenses, and                                                             
     gas purchased for resale                                   692,901    1,061,037     895,361
   Purchased power                                              368,140      467,196     455,300
   Nuclear refueling outage expenses                             12,190       11,159      16,663
   Other operation and maintenance                              438,259      422,667     423,031
Decommissioning                                                   3,980        6,247       6,273
Taxes other than income taxes                                   120,295      118,670     120,428
Depreciation and amortization                                   204,202      191,120     189,149
Other regulatory credits - net                                   (7,818)     (26,728)     (8,254)
							     ----------   ----------  ----------
TOTAL                                                         1,832,149    2,251,368   2,097,951
							     ----------   ----------  ----------
												
OPERATING INCOME                                                351,730      397,192     413,289
							     ----------   ----------  ----------
												
		     OTHER INCOME                                                          
Allowance for equity funds used during construction              11,010        9,248       7,617
Gain on sale of assets                                            3,409        2,454       2,327
Interest and dividend income                                      8,866       24,818      16,428
Miscellaneous - net                                                 151       (7,148)     (3,692)
							     ----------   ----------  ----------
TOTAL                                                            23,436       29,372      22,680
							     ----------   ----------  ----------
												
	      INTEREST AND OTHER CHARGES                                                   
Interest on long-term debt                                      131,906      153,393     143,053
Other interest - net                                              5,497       13,537       8,458
Distributions on preferred securities of subsidiary               7,437        7,438       7,438
Allowance for borrowed funds used during construction            (9,749)      (9,286)     (6,926)
							     ----------   ----------  ----------
TOTAL                                                           135,091      165,082     152,023
							     ----------   ----------  ----------
												
INCOME BEFORE INCOME TAXES                                      240,075      261,482     283,946
												
Income taxes                                                     65,997       82,038     103,603
							     ----------   ----------  ----------
												
NET INCOME                                                      174,078      179,444     180,343
												
Preferred dividend requirements and other                         4,888        5,025       9,998
							     ----------   ----------  ----------
												
EARNINGS APPLICABLE TO                                                                          
COMMON STOCK                                                   $169,190     $174,419    $170,345
							     ==========   ==========  ==========
												
See Notes to Respective Financial Statements. 
                                                 
							
				  ENTERGY GULF STATES, INC. 
				  STATEMENTS OF CASH FLOWS 

							      For the Years Ended December 31,
								2002         2001        2000
								      (In Thousands)
 
		 OPERATING ACTIVITIES                                                           
Net income                                                     $174,078     $179,444    $180,343
Noncash items included in net income:                                                           
  Reserve for regulatory adjustments                             11,147      (27,374)    (49,571)
  Other regulatory credits - net                                 (7,818)     (26,728)     (8,254)
  Depreciation, amortization, and decommissioning               208,182      197,367     195,422
  Deferred income taxes and investment tax credits              (11,576)       4,320      54,279
  Allowance for equity funds used during construction           (11,010)      (9,248)     (7,617)
  Gain on sale of assets                                         (3,409)      (2,454)     (2,327)
Changes in working capital:                                                                     
  Receivables                                                    18,155       59,132    (131,643)
  Fuel inventory                                                  4,617      (16,753)      1,013
  Accounts payable                                               83,428     (151,090)    130,435
  Taxes accrued                                                 (54,690)     (41,764)     30,570
  Interest accrued                                               (4,544)        (125)     14,969
  Deferred fuel costs                                            65,556      161,396     (26,291)
  Other working capital accounts                                (19,551)       6,183      20,896
Provision for estimated losses and reserves                       1,478       (3,593)     (1,991)
Changes in other regulatory assets                              (51,490)     (54,613)    (47,777)
Other                                                            98,101       64,386      51,424
							     ----------    ---------   ---------
Net cash flow provided by operating activities                  500,654      338,486     403,880
							     ----------    ---------   ---------
												
		 INVESTING ACTIVITIES                                                           
Construction expenditures                                      (355,334)    (317,776)   (277,635)
Allowance for equity funds used during construction              11,010        9,248       7,617
Nuclear fuel purchases                                          (21,820)     (14,148)    (34,735)
Proceeds from sale/leaseback of nuclear fuel                     21,923       15,222      34,154
Decommissioning trust contributions and realized                                                
    change in trust assets                                      (12,488)     (11,319)    (12,051)
Changes in other temporary investments - net                     44,643      (44,643)          -
Other regulatory investments                                    (39,390)           -    (127,377)
							     ----------    ---------   ---------
Net cash flow used in investing activities                     (351,456)    (363,416)   (410,027)
							     ----------    ---------   ---------
												
		 FINANCING ACTIVITIES                                                           
  Proceeds from the issuance of long-term debt                  337,481      298,554     298,819
  Retirement of long-term debt                                 (194,057)    (124,829)       (185)
  Redemption of preferred stock                                  (1,858)      (4,573)   (157,658)
Dividends paid:                                                                                 
  Common stock                                                  (91,200)     (83,700)    (88,000)
  Preferred stock                                                (4,888)      (5,073)    (10,862)
							     ----------    ---------   ---------
Net cash flow provided by financing activities                   45,478       80,379      42,114
							     ----------    ---------   ---------
												
Net increase in cash and cash equivalents                       194,676       55,449      35,967
												
Cash and cash equivalents at beginning of period                123,728       68,279      32,312
							     ----------    ---------   ---------
												
Cash and cash equivalents at end of period                     $318,404     $123,728     $68,279
							     ==========    =========   =========
												
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:                                                                
  Interest - net of amount capitalized                         $143,961     $169,067    $136,154
  Income taxes                                                  $98,734     $107,726     $23,259
 Noncash investing and financing activities:                                                    
  Change in unrealized depreciation of                                                          
   decommissioning trust assets                                ($17,135)     ($9,492)    ($3,172)
												
See Notes to Respective Financial Statements.                                                   

				ENTERGY GULF STATES, INC.                         
				     BALANCE SHEETS                               
					ASSETS  
						    
									   December 31,
									 2002        2001
									  (In Thousands)
		      CURRENT ASSETS                                                         
Cash and cash equivalents:                                                                   
  Cash                                                                   $25,591      $19,503
  Temporary cash investments - at cost,                                                      
    which approximates market                                            292,813      104,225
								      ----------   ----------
	Total cash and cash equivalents                                  318,404      123,728
								      ----------   ----------
Other temporary investments                                                    -       44,643
Accounts receivable:                                                                         
  Customer                                                                81,879       81,136
  Allowance for doubtful accounts                                         (5,893)      (3,696)
  Associated companies                                                    21,356       34,032
  Other                                                                   40,156       54,814
  Accrued unbilled revenues                                               95,377       84,744
								      ----------   ----------
    Total accounts receivable                                            232,875      251,030
								      ----------   ----------
Deferred fuel costs                                                      100,564      126,730
Accumulated deferred income taxes                                          1,681            -
Fuel inventory - at average cost                                          49,394       54,011
Materials and supplies - at average cost                                  99,190       95,674
Prepayments and other                                                     47,206       22,373
								      ----------   ----------
TOTAL                                                                    849,314      718,189
								      ----------   ----------
											     
	      OTHER PROPERTY AND INVESTMENTS                                                 
Decommissioning trust funds                                              240,735      245,382
Non-utility property - at cost (less accumulated depreciation)           192,975      194,830
Other                                                                     18,108       15,970
								      ----------   ----------
TOTAL                                                                    451,818      456,182
								      ----------   ----------
											     
		       UTILITY PLANT                                                         
Electric                                                               7,895,009    7,694,226
Property under capital lease                                              19,795       28,087
Natural gas                                                               60,810       59,100
Construction work in progress                                            306,209      221,730
Nuclear fuel under capital lease                                          41,447       67,688
								      ----------   ----------
TOTAL UTILITY PLANT                                                    8,323,270    8,070,831
Less - accumulated depreciation and amortization                       3,885,559    3,750,770
								      ----------   ----------
UTILITY PLANT - NET                                                    4,437,711    4,320,061
								      ----------   ----------
											     
	     DEFERRED DEBITS AND OTHER ASSETS                                                
Regulatory assets:                                                                           
  SFAS 109 regulatory asset - net                                        452,887      426,623
  Unamortized loss on reacquired debt                                     31,186       34,321
  Other regulatory assets                                                226,555      201,329
Long-term receivables