Envela 10-K 2002 FY Annual report

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. YesÖ No ____

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

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

	Yes	No
Entergy Corporation Entergy Arkansas, Inc. Entergy Gulf States, Inc. Entergy Louisiana, Inc. Entergy Mississippi, Inc. Entergy New Orleans, Inc. System Energy Resources, Inc.	Ö	Ö Ö Ö Ö Ö Ö

The aggregate market value of Entergy Corporation Common Stock, $0.01 Par Value, held by non-affiliates as of the end of the second quarter of 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	PageNumber
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 AcronymTerm

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 AcronymTerm

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 AcronymTerm

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. Utilitygenerates, transmits, distributes, and sells electric power, with a small amount of natural gas distribution.
• Non-Utility Nuclearowns and operates five nuclear power plants and is primarily focused on selling electric power produced by those plants to wholesale customers.
• Energy Commodity Servicesis 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	7	17	13	9
Energy Commodity Services	4	14	23	(23)	14	8	8	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 theU.S. Utility, Non-Utility Nuclear,andEnergy Commodity Services sections, including certain business segment financial information.

                TheU.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.

                TheNon-Utility Nuclear business andEnergy 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. SeeRate Regulation and Fuel-Cost Recoveryin"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. SeeUtility Restructuringin"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. SeeNuclear 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. SeeMarket and Credit Risksin"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. SeeMarket and Credit Risksin"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. SeeLiquidity 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 theU.S. Utility BusinessandNon-Utility NuclearBusiness 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 Nuclearowns and operates five nuclear power plants and is primarily focused on selling electric power produced by those plants to wholesale customers.
• Energy Commodity Servicesis 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	7	17	13	9
Energy Commodity Services	4	14	23	(23)	14	8	8	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 fuelcost 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 afull 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 theseLatin Americaninterests 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, n ot 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 steamgenerator 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 ventu re 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 ope rating 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 yea rs 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, $232million 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 co mmon 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 theend 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

7 

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 mi llion 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 benef its 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 th e 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:

• Cost Escalation Factors - Entergy's decommissioning revenue requirement studies include an assumption that decommissioning costs will escalate over present cost levels by annual factors ranging from 3.0% to 5.5%. A 50 basis point change in this assumption could change the ultimate cost of decommissioning a facility by as much as 11.0%.

• Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant's retirement must be estimated. The expiration of the plant's operating license is typically used for this purpose, or an assumption could be made that the plant will be relicensed and operate for some time beyond the original license term. Second, an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in "safestore" status for later decommissioning, as permitted by applicable regulations.
  While the impact of these assumptions cannot be determined with precision, assuming either license extension or use of a "safestore" status can significantly decrease the present value of these obligations.

• Spent Fuel Disposal - Federal regulations require the Department of Energy to provide a permanent repository for the storage of spent nuclear fuel, and recent legislation has been passed by Congress to develop this repository at Yucca Mountain, Nevada. However, until this site is available, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities.The costs of developing and maintaining these facilities can have a significant impact (as much as 16% of estimated decommissioning costs). Entergy's decommissioning studies include cost estimates for spent fuel storage, except for ANO 1 and 2. A study including these costs for ANO 1 and 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 U.S. with actual decommissioning of large nuclear facilities. As experience is gained and technology changes, cost estimates could also change. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant impact on cost estimates. The impact of these potential changes is not presently determinable. Entergy's decommissioning cost studies assume current technologies and regulations.

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

(Page left blank intentionally)

                   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.

2. Includes an 11.5% leasehold interest held by System Energy. System Energy's Grand Gulf 1 lease obligations are discussed in Note 10 to the consolidated financial statements.

 
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 dilutedearnings 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 cost s 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 n o 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)
EntergyArkansas	$ (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 Aug ust 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 throughestablished ratemaking procedures, including $22.2 millionclassified 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, shoul d 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. Ente rgy 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 forEntergy Mississippi's formula rate plan. Under the provisions of the order, Entergy Mississippiwill 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' r atepayers 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 deferr al 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 m illion 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 subsidiarie s 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 h ave 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 FitzPa trick 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 D ecommissioning 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 ter mination 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, respect ively.

                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 volunt ary 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 i n 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 fin ancial 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 Ent ergy'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 obta ined 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 per iods. 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.

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)

2. 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 reques ted 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 WhiteBluff'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 Orlean s 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 pl ant 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 generati ng 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 fo r 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 p arties 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 resul ting 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 St ates 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 r ecovered 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 repa y 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 custome rs 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 othe r 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, su perseded 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 E nergy 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 not es 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 Texaswith 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 (NO_x);
• an ozone non-attainment area program for control of NO_x 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 SO₂allowances 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 NO_x 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 c osts for NO_x 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 NO_x. 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 mee ting 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 NO_x 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 NO_x 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 limit s for NO_x.

                In September 2002, the EPA approved revisions to the SIP that address NO_x 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. 5^th 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. 5^th 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 NO_x, SO_2, 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 CO₂emission 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 dio xide 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 t o 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 lia bilities 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 a pproves 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 inter est 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 wh at 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 th e 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 thir d-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 success fully 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 pl ant 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 a lliance 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 me et 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 pri ce 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 st eam 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 proceed ing, 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 th e 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 trus t 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.

(Page left blank intentionally)

                             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 expec ted 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 Gul f 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 billio n 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 agreeme nt 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 schedul e 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 hea ring 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 proceed ing, 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 resu lt 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 uti lity 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                                                     23,192       26,576
Other                                                                     35,194       26,460
								      ----------   ----------
TOTAL                                                                    769,014      715,309
								      ----------   ----------

TOTAL ASSETS                                                          $6,507,857   $6,209,741
								      ==========   ==========

See Notes to Respective Financial Statements.

				 ENTERGY GULF STATES, INC.
				      BALANCE SHEETS
			   LIABILITIES AND SHAREHOLDERS' EQUITY

									   December 31,
									 2002        2001
									  (In Thousands)
		    CURRENT LIABILITIES
Currently maturing long-term debt                                       $293,000     $147,921
Accounts payable:
  Associated companies                                                    51,383       38,728
  Other                                                                  205,796      135,023
Customer deposits                                                         48,061       45,876
Taxes accrued                                                             35,914       90,604
Accumulated deferred income taxes                                              -       21,412
Nuclear refueling outage costs                                            14,244        2,080
Interest accrued                                                          38,870       43,414
Obligations under capital leases                                          36,157       36,668
Other                                                                     15,441       20,995
								      ----------   ----------
TOTAL                                                                    738,866      582,721
								      ----------   ----------

	  DEFERRED CREDITS AND OTHER LIABILITIES
Accumulated deferred income taxes and taxes accrued                    1,310,028    1,227,084
Accumulated deferred investment tax credits                              156,401      163,766
Obligations under capital leases                                          25,085       60,163
Other regulatory liabilities                                               5,557            -
Decommissioning                                                          148,728      144,926
Transition to competition                                                 79,098       79,098
Regulatory reserves                                                       44,738       33,591
Accumulated provisions                                                    65,289       63,811
Other                                                                     93,396       93,719
								      ----------   ----------
TOTAL                                                                  1,928,320    1,866,158
								      ----------   ----------

Long-term debt                                                         1,959,288    1,958,897
Preferred stock with sinking fund                                         24,327       26,185
Company-obligated mandatorily redeemable
  preferred securities of subsidiary trust holding
  solely junior subordinated deferrable debentures                        85,000       85,000

		   SHAREHOLDERS' EQUITY
Preferred stock without sinking fund                                      47,327       47,327
Common stock, no par value, authorized 200,000,000
  shares; issued and outstanding 100 shares in 2002 and 2001             114,055      114,055
Paid-in capital                                                        1,157,459    1,157,459
Retained earnings                                                        449,929      371,939
Accumulated other comprehensive income                                     3,286            -
								      ----------   ----------
TOTAL                                                                  1,772,056    1,690,780
								      ----------   ----------

Commitments and Contingencies

		 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY           $6,507,857   $6,209,741
								      ==========   ==========

See Notes to Respective Financial Statements.

				 ENTERGY GULF STATES, INC.
		STATEMENTS OF RETAINED EARNINGS AND COMPREHENSIVE INCOME

									 For the Years Ended December 31,
							       2002                   2001                   2000
										 (In Thousands)
		 RETAINED EARNINGS
Retained Earnings - Beginning of period                 $371,939               $285,128               $202,783

    Add  - Earnings applicable to common stock          $169,190    169,190     174,419    $174,419    170,345   $170,345

    Deduct:
	Dividends declared on common stock                91,200                 83,700                 88,000
	Capital stock and other expenses                       -                  3,908
						       ---------               --------               --------
	      Total                                       91,200                 87,608                 88,000
						       ---------               --------               --------
Retained Earnings - End of period                       $449,929               $371,939               $285,128
						       =========               ========               ========

   ACCUMULATED OTHER COMPREHENSIVE
      INCOME (Net of Taxes):
Balance at beginning of period:
  Accumulated derivative instrument fair value changes       $ -                    $ -                    $ -

Net derivative instrument fair value changes
  arising during the period                                3,286      3,286           -           -          -           -
						       ---------   --------    --------    --------   --------    --------
Balance at end of period:
  Accumulated derivative instrument fair value changes    $3,286                    $ -                    $ -
						       =========   ---------   ========    --------   ========    --------
Comprehensive Income                                                $172,476               $174,419               $170,345
								   =========               ========               ========
      See Notes to Respective Financial Statements.

ENTERGY GULF STATES, INC. AND SUBSIDIARIES

SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON

	2002	2001	2000	1999	1998
	(In Thousands)
Operating revenues	$ 2,183,879	$ 2,648,560	$ 2,511,240	$ 2,127,208	$ 1,853,809
Net income	$ 174,078	$ 179,444	$ 180,343	$ 125,000	$ 46,393
Total assets	$ 6,507,857	$ 6,209,741	$ 6,134,017	$ 5,733,022	$ 6,293,744
Long-term obligations (1)	$ 2,093,700	$ 2,130,245	$ 1,978,149	$ 1,966,269	$ 1,993,811

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

(1) 1998 includes the effects of an Entergy Gulf States reserve for rate refund.

ENTERGYLOUISIANA, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Operating Income

2002 Compared to 2001

                Operating income decreased $8.0 million primarily due to:

• the receipt of the final FERC order in July 2001 in the System Energy rate proceeding. The accounting entries necessary to record the effects of the order reduced purchased power expenses by $68.1 million in 2001. The 2001 System Energy rate proceeding is discussed in Note 2 to the domestic utility companies and System Energy financial statements;
• an increase in other operation and maintenance expenses of $41.3 million, which is explained below;
• the amortization of deferred capacity charges for the summers of 2001 and 2000 of $17.2 million; and
• an increase in depreciation and amortization expenses of $11.7 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.

Almost entirely offsetting the decrease were the following:

• more favorable volume on retail sales of $79.5 million;
• an increase in the price applied to unbilled sales causing an increase in revenue of $45.0 million; and
• franchise tax adjustments of $10.8 million as a result of a favorable court decision which would allow Entergy Louisiana to receive a refund for certain franchise taxes previously expensed and paid under protest.

                Other operation and maintenance expenses increased $41.3 million primarily due to:

• increased fossil expenses of $13.3 million due to maintenance outages at the Ninemile Point, Little Gypsy, and Waterford fossil plants and turbine inspection costs at Sterlington fossil plant;
• an increase of $11.9 million in benefit costs;
• an increase of $4.4 million in outside services employed; and
• increased transportation costs of $4.4 million.

2001 Compared to 2000

               Operating income decreased $47.7 million primarily due to:

• less favorable volume and weather reducing retail sales by $64.5 million;
• a decrease in price applied to unbilled sales causing a decrease in revenue of $96.6 million; and
• additional formula rate plan reductions effective August 2000 and August 2001 of $27.2 million.

The decrease was partially offset by the following:

• the reduction of $68.1 million in purchased power expenses as a result of the FERC-ordered refund from System Energy;
• lower accruals for potential rate refunds of $40.6 million; and
• a decrease in other operation and maintenance expenses of $19.3 million, which is discussed below.

                Other operation and maintenance expenses decreased $19.3 million primarily due to:

• a decrease of $11.0 million due to decreased legal fees; and
• a decrease of $9.4 million in expenses from maintenance and planned maintenance outages at Little Gypsy and Ninemile Point fossil plants in 2000.

Other Impacts on Earnings

2002 Compared to 2001

                Other income and interest charges increased earnings by $18.6 million primarily due to:

• decreased interest on long-term debt of $5.9 million due to the refinancing and net redemption of First Mortgage Bonds in the amounts of $18.7 million in 2001 and $140 million in 2002;
• interest of $4.6 million accrued in 2001 on reserves provided for fuel-related refunds that were made in the summer of 2001; and
• adjustments to interest expense and interest income of $7.8 million previously recorded on franchise tax accruals as a result of the franchise tax adjustment discussed above.

2001 Compared to 2000

                Other income and interest charges decreased earnings by $8.8 million primarily due to:

• decreased interest income of $4.2 million recorded on deferred fuel costs due to the recovery of those costs;
• interest expense accrued of $2.8 million on the over-recovered fuel and purchased power expenses in 2001; and
• interest expense accrued of $4.6 million in 2001 on reserves provided for fuel-related refunds that were refunded in July through September 2001.

Other Income Statement Variances

2002 Compared to 2001

                Operating revenues decreased $86.6 million primarily due to a decrease in fuel recovery revenues due to lower fuel rates, partially offset by an increase in price applied to unbilled sales and an increase in electricity usage in the service territory. Billed usage increased 1,042 GWh primarily in the residential and industrial sectors.

                Fuel and purchased power expenses decreased $155.7 million primarily due to:

• the decline in natural gas prices in 2002;
• a decrease in the average price of purchased power; and
• a decrease in deferred fuel expense due to lower fuel revenues.

The decrease was partially offset by the reduction of purchased power expenses in 2001 as a result of the FERC-ordered refund from System Energy.

                Other regulatory charges increased $42.0 million primarily due to the deferral in 2001 of capacity charges included in purchased power costs for the summers of 2000 and 2001 and the amortization of these capacity charges in 2002. The amortization of the summer 2000 capacity charges ended in July 2002. The amortization of the capacity charges for the summer of 2001 began in August 2002 and will occur through July 2003. Refer to Note 2 to the domestic utility companies and System Energy financial statements for further discussion of deferred capacity charges.

2001 Compared to 2000

Operating revenues decreased $160.5 million primarily due to a decrease in price applied to unbilled and decreased electricity usage in the service territory. Billed usage decreased 1,156 GWh primarily in the industrial and residential sectors.

                Fuel and purchased power expenses decreased $67.1 million primarily due to the reduction of purchased power expenses as a result of the FERC-ordered refund from System Energy.

                Other regulatory credits increased $25.7 million due to the deferral of capacity charges included in purchased power costs for the summers of 2000 and 2001, partially offset by the amortization of the 2000 capacity charges.

Income taxes

      The effective income tax rates for 2002, 2001, and 2000 were 36.9%, 39.4%, and 40.9%. 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

$ 42,408 

$ 43,959 

$ 7,734 

Cash flow provided by (used in):

   Operating activities

1,035,777 

430,515 

270,423 

   Investing activities

(212,333)

(218,331)

(211,020)

   Financing activities

 (554,052)

(213,735)

 (23,178)

   Net increase (decrease) in cash and cash equivalents

  269,392 

   (1,551)

  36,225 

Cash and cash equivalents at end of period

$ 311,800 

$ 42,408 

$ 43,959 

Operating Activities

                Cash flow from operations increased $605.3 million in 2002 as a result of Entergy Louisiana changing its method of accounting for tax purposes in 2001 related to the contract to purchase power from the Vidalia project (the contract is discussed in Note 9 to the domestic utility companies and System Energy financial statements). The new tax accounting method provided a cumulative cash flow benefit of approximately $867 million in 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.

                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 th e entire deduction related to the tax accounting method. Entergy Louisiana agreed to credit ratepayers additional amounts unless the tax accounting election is not sustained, if it is challenged. During the years 2013-2031, Entergy Louisiana and its ratepayers would share the remaining benefits of this tax accounting election.

                Management expects to reduce Entergy Louisiana's indebtedness and preferred stock with a portion of the cash. In accordance with the terms of the settlement, Entergy Louisiana requested SEC approval to return up to $350 million of common equity capital to Entergy Corporation in order to maintain Entergy Louisiana's current capital structure. In December 2002, Entergy Louisiana repurchased $120 million of common stock from Entergy Corporation and paid a dividend of $122.6 million pursuant to the SEC approval.

                Cash flow from operations increased $160.1 million in 2001 compared to 2000 primarily due to the FERC-ordered refund from System Energy. The amount Entergy Louisiana was required to pass on to customers was significantly lower than the refund amount because Entergy Louisiana had not passed through to customers all of System Energy's rate increase in effect since 1995. The increase was also due to recovery of deferred fuel costs in 2001.

                Entergy Louisiana's 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)
$18,854	$3,812	$22,907	($91,467)

Money pool activity decreased Entergy Louisiana's operating cash flows by $15.0 million in 2002, increased operating cash flow by $19.1 million in 2001, and decreased operating cash flow by $114.4 million in 2000. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.

Financing Activities

                The increase of $340.3 million in net cash used by financing activities in 2002 was primarily due to:

• the net retirement of an additional $120.9 million of first mortgage bonds in 2002;
• an increase in common stock dividends paid of $134.5 million; and
• the repurchase of $120.0 million of common stock from Entergy Corporation.

                The increase of $190.6 million in net cash used by financing activities in 2001 was primarily due to:

• an increase in dividends paid of $71.7 million;
• the mandatory redemption of $35.0 million of preferred stock; and
• the net issuance of an additional $83.8 million of First Mortgage Bonds in 2000.

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

Uses of Capital

               Entergy Louisiana requires capital resources for:

• construction and other capital investments;
• debt and preferred stock maturities, including debt reduction as a result of the Vidalia tax benefit election;
• working capital purposes, including the financing of fuel and purchased power costs;
• dividend and interest payments; and
• repurchase of common stock from Entergy Corporation.

                Following are the amounts of Entergy Louisiana's 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	$197	$184	$195	N/A	N/A
Long-term debt maturities	$296	$15	$55	$-	$760
Capital and operating lease payments	$13	$12	$7	$5	$1
Unconditional fuel and purchased
power obligations	$162	$168	$172	$356	$3,354
Nuclear fuel lease obligations (1)	$34	$17	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.

                The planned capital investment estimate for Entergy Louisiana 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 Louisiana dividends its earnings to Entergy Corporation at a percentage determined monthly. Currently, all of Entergy Louisiana's retained earnings are available for distribution.

Sources of Capital

                Entergy Louisiana's sources to meet its capital requirements include:

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

                In 2002, Entergy Louisiana issued $150 million of long-term debt and used a portion of the proceeds to redeem $115 million of outstanding debt. The remaining net proceeds were used to reduce short-term indebtedness incurred for working capital and other purposes. Entergy Louisiana 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 Louisiana 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 Louisiana, including borrowings under the money pool, are limited to an amount authorized by the SEC, $225 million. Under the SEC order authorizing the short-term borrowing limits, Entergy Louisiana cannot incur new short-term indebtedness if its common equity would comprise less than 30% of its capital. In addition, Entergy Louisiana is restricted from publicly issuing new long-term debt unless its senior secured debt will be rated as investment grade. Entergy Louisiana has a 364-day credit facility available expiring May 2003 in the amount of $15 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 Louisiana's 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 a July 2001 report to the LPSC, the LPSC staff concluded that retail competition is not in the public interest at this time for any customer class. Nevertheless, the LPSC staff recommended that retail open access be made available for certain large industrial customers as early as January 2003. An eligible customer choosing to go to competition would be required to provide its utility with a minimum of six months notice prior to the date of retail open access. The LPSC staff report also recommended that all customers who do not currently co- or self-generate, or have co- or self-generation under construction as of a date to be specified by the LPSC, remain liable for their share of stranded costs. During its October 2001 meeting, the LPSC adopted dates by which a total of 800 MW of co- or self-generation could be developed in Louisiana without being affected by stranded costs. During its November 2001 meeting, the LPSC decided not to adopt a plan for retail open access at this time, but to have collaborative group meetings concerning open access from time to time, and to have the LPSC staff monitor developments in neighboring states and to report to the LPSC regarding the progress of retail access developments in those states.

                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.

State Rate Regulation

                The rates that Entergy Louisiana charges for its services are an important item influencing its financial position, results of operations, and liquidity. Entergy Louisiana is closely regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approval of the rates charged to customers.

                In July 2002, the LPSC approved a settlement that resolved all remaining issues in the 2000 and 2001 formula rate plan proceedings in which 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.

                Performance based formula rate plan filings expired in 2001 for Entergy Louisiana. Performance based formula rate plan filings are designed to reward increased efficiency and productivity, with utility shareholders and customers sharing in the benefits. Negotiations with the LPSC staff and advisors for a statewide formula rate plan in Louisiana are ongoing.

                In addition to rate proceedings, Entergy Louisiana's fuel costs recovered from customers are subject to regulatory scrutiny. This regulatory risk represents Entergy Louisiana's largest potential exposure to price changes in the commodity markets.

               Entergy Louisiana's 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 proceed ing, 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 Louisiana's annual production costs over the period 2002 to 2007 will be $132 million to $139 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 Louisiana, 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 and Commercial Customers

                Entergy Louisiana's 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 Louisiana's industrial customer base. Entergy Louisiana 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 Louisiana lost a large industrial customer to cogeneration late in 2002. The customer accounted for approximately 2% of its net revenue in 2001. In addition to working with its current customers, Entergy Louisiana 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 Louisiana 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 Louisiana's nuclear decommissioning trust funds expose it to fluctuations in equity prices and interest rates. The NRC requires Entergy Louisiana to maintain trusts to fund the costs of decommissioning Waterford 3. 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 Waterford 3 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.

Nuclear Matters

                Entergy Louisiana owns and operates, through an affiliate, Waterford 3. Entergy Louisiana 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 Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.

Environmental Risks

                Entergy Louisiana'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 Entergy Louisiana 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 state of Louisiana has proven to be an unusually litigious environment. Judges and juries in Louisiana have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy Louisiana uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment poses a significant business risk.

Critical Accounting Estimates

                The preparation of Entergy Louisiana'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 Louisiana's financial statements.

Nuclear Decommissioning Costs

                Regulations require that Waterford 3 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 Louisiana 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 Louisiana's most recent study and the obligations recorded by Entergy Louisiana related to decommissioning. The following key assumptions have a significant effect on these estimates:

• Cost Escalation Factors - Entergy Louisiana's decommissioning studies include an assumption that decommissioning costs will escalate over present cost levels by an annual factor averaging approximately 4.4%. 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 Louisiana's decommissioning studies for Waterford 3 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 Louisiana's decommissioning studies include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors.
• Technology and Regulation - To date, there is limited practical experience in the United States with actual decommissioning of large nuclear facilities. As experience is gained and technology changes, cost estimates could also change. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant impact on cost estimates. The impact of these potential changes is not presently determinable. Entergy Louisiana's decommissioning cost studies assume current technologies and regulations.

                Entergy Louisiana collects substantially all of the projected costs of decommissioning Waterford 3 through rates charged to customers. 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 estimated to be sufficient to fund the future decommissioning costs. Accordingly, decommissioning costs have no impact on Entergy Louisiana's 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.

                The obligations recorded by Entergy Louisiana for decommissioning are classified as a component of accumulated depreciation. 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 Louisiana implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs comprise substantially all of Entergy Louisiana's asset retirement obligations, and the measurement and recording of Entergy Louisiana'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 of Entergy Louisiana to increase significantly, as Entergy Louisiana 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 Louisiana's decommissioning studies to date have been based on Entergy Louisiana 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 Louisiana will be recorded as a regulatory asset or liability, with no resulting impact on Entergy Louisiana's net income. Assets and liabilities are expected to increase by approximately $300 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%)	$ 223	$ 9,775
Rate of return on plan assets	(0.25%)	$ 836	-
Rate of increase in compensation	0.25%	$ 222	$ 1,937

                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%	$ 312	$ 2,518
Discount rate	(0.25%)	$ 142	$ 3,002

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 Louisiana in 2002 was $3.9 million. Taking into account asset performance and the changes made in the actuarial assumptions, Entergy Louisiana does not anticipate 2003 pension income to be materially different from 2002. Entergy Louisiana 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 Louisiana's accumulated benefit obligation at December 31, 2002 exceeded plan assets. As a result, Entergy Louisiana was required to recognize an additional minimum liability of $44.2 million as prescribed by SFAS 87. Entergy Louisiana recorded an intangible asset for the $5.4 million of unrecognized prior service cost and the remaining $38.8 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 Louisiana in 2002 were $12.6 million. Because of a number of factors, including the increased health care cost trend rate, Entergy Louisiana expects 2003 costs to approximate $15.4 million.

INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Shareholders of

Entergy Louisiana, Inc.:

We have audited the accompanying balance sheets of Entergy Louisiana, Inc. as of December 31, 2002 and 2001, and the related statements of income, retained earnings, and cash flows (pages 195 through 200 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 Louisiana, 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 LOUISIANA, INC.INCOME STATEMENTS

								For the Years Ended December 31,
								   2002         2001        2000
									 (In Thousands)
		   OPERATING REVENUES

Domestic electric                                              $1,815,352   $1,901,913  $2,062,437
							       ----------   ----------  ----------
		   OPERATING EXPENSES
Operation and Maintenance:
   Fuel, fuel-related expenses, and
     gas purchased for resale                                     436,568      620,415     560,329
   Purchased power                                                438,627      410,435     537,589
   Nuclear refueling outage expenses                               11,502       12,624      13,542
   Other operation and maintenance                                340,803      299,532     318,841
Decommissioning                                                    10,422       10,422      10,422
Taxes other than income taxes                                      60,698       77,376      77,190
Depreciation and amortization                                     182,871      171,217     171,204
Other regulatory charges (credits) - net                           17,219      (24,738)        960
							       ----------   ----------  ----------
TOTAL                                                           1,498,710    1,577,283   1,690,077
							       ----------   ----------  ----------

OPERATING INCOME                                                  316,642      324,630     372,360
							       ----------   ----------  ----------

		      OTHER INCOME
Allowance for equity funds used during construction                 5,195        4,531       4,328
Gain on sale of assets                                                  -          152           -
Interest and dividend income                                        7,668        6,234      10,100
Miscellaneous - net                                                (3,244)      (4,056)     (3,496)
							       ----------   ----------  ----------
TOTAL                                                               9,619        6,861      10,932
							       ----------   ----------  ----------

	       INTEREST AND OTHER CHARGES
Interest on long-term debt                                         91,942       97,887      98,655
Other interest - net                                                2,425       11,889       6,788
Distributions on preferred securities of subsidiary                 6,300        6,300       6,300
Allowance for borrowed funds used during construction              (3,880)      (3,422)     (3,775)
							       ----------   ----------  ----------
TOTAL                                                              96,787      112,654     107,968
							       ----------   ----------  ----------

INCOME BEFORE INCOME TAXES                                        229,474      218,837     275,324

Income taxes                                                       84,765       86,287     112,645
							       ----------   ----------  ----------

NET INCOME                                                        144,709      132,550     162,679

Preferred dividend requirements and other                           6,714        7,495       9,514
							       ----------   ----------  ----------

EARNINGS APPLICABLE TO
COMMON STOCK                                                     $137,995     $125,055    $153,165
							       ==========   ==========  ==========

See Notes to Respective Financial Statements.

(Page left blank intentionally)

				    ENTERGY LOUISIANA, INC.
				   STATEMENTS OF CASH FLOWS

							       For the Years Ended December 31,
								 2002         2001        2000
									 (In Thousands)

		 OPERATING ACTIVITIES

Net income                                                     $144,709     $132,550    $162,679
Noncash items included in net income:
  Reserve for regulatory adjustments                                  -      (11,456)     11,456
  Other regulatory charges (credits) - net                       17,219      (24,738)        960
  Depreciation, amortization, and decommissioning               193,293      181,639     181,626
  Deferred income taxes and investment tax credits               39,849      (27,382)     16,350
  Allowance for equity funds used during construction            (5,195)      (4,531)     (4,328)
  Gain on sale of assets                                              -         (152)          -
Changes in working capital:
  Receivables                                                   (68,936)     131,313     (97,154)
  Accounts payable                                                7,370      (50,121)    (11,848)
  Taxes accrued                                                 779,590       (2,897)     (2,555)
  Interest accrued                                               (3,971)      (1,012)     15,300
  Deferred fuel costs                                           (41,891)     151,544     (81,890)
  Other working capital accounts                               (118,718)     (71,119)     38,064
Provision for estimated losses and reserves                       5,818        4,321       6,114
Changes in other regulatory assets                              (23,879)       2,569      25,400
Other                                                           110,519       19,987      10,249
							      ---------     --------    --------
Net cash flow provided by operating activities                1,035,777      430,515     270,423
							      ---------     --------    --------

		 INVESTING ACTIVITIES
Construction expenditures                                      (209,826)    (203,059)   (203,049)
Allowance for equity funds used during construction               5,195        4,531       4,328
Nuclear fuel purchases                                          (50,473)           -     (38,270)
Proceeds from sale/leaseback of nuclear fuel                     50,473            -      38,270
Decommissioning trust contributions and realized
    change in trust assets                                      (13,854)     (13,651)    (12,299)
Changes in other temporary investments - net                      6,152       (6,152)          -
							      ---------     --------    --------
Net cash flow used in investing activities                     (212,333)    (218,331)   (211,020)
							      ---------     --------    --------

		 FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt                    144,679            -     148,736
Retirement of long-term debt                                   (300,617)     (35,088)   (100,000)
Redemption of preferred stock                                         -      (35,000)          -
Repurchase of common stock                                     (120,000)           -           -
Dividends paid:
  Common stock                                                 (271,400)    (134,600)    (62,400)
  Preferred stock                                                (6,714)      (9,047)     (9,514)
							      ---------     --------    --------
Net cash flow used in financing activities                     (554,052)    (213,735)    (23,178)
							      ---------     --------    --------

Net increase (decrease) in cash and cash equivalents            269,392       (1,551)     36,225

Cash and cash equivalents at beginning of period                 42,408       43,959       7,734
							      ---------     --------    --------

Cash and cash equivalents at end of period                     $311,800      $42,408     $43,959
							      =========     ========    ========

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid/(received) during the period for:
  Interest - net of amount capitalized                          $99,998     $110,971     $89,627
  Income taxes                                                ($781,540)    $111,507    $105,354
 Noncash investing and financing activities:
  Change in unrealized depreciation of
   decommissioning trust assets                                 ($8,463)     ($4,251)    ($2,979)

See Notes to Respective Financial Statements.

				   ENTERGY LOUISIANA, INC.
				       BALANCE SHEETS
					   ASSETS

									   December 31,
									 2002        2001
									 (In Thousands)

		      CURRENT ASSETS

Cash and cash equivalents:
  Cash                                                                  $15,130      $28,768
  Temporary cash investments - at cost,
    which approximates market                                           296,670       13,640
								     ----------   ----------
	Total cash and cash equivalents                                 311,800       42,408
								     ----------   ----------
Other temporary investments                                                   -        6,152
Accounts receivable:
  Customer                                                               95,009       48,640
  Allowance for doubtful accounts                                        (4,090)      (2,909)
  Associated companies                                                   30,722        9,090
  Other                                                                  17,949       49,103
  Accrued unbilled revenues                                             104,470       71,200
								     ----------   ----------
    Total accounts receivable                                           244,060      175,124
								     ----------   ----------
Accumulated deferred income taxes                                         4,400       42,566
Materials and supplies - at average cost                                 78,327       77,523
Deferred nuclear refueling outage costs                                  10,017        4,096
Prepayments and other                                                   117,720        9,008
								     ----------   ----------
TOTAL                                                                   766,324      356,877
								     ----------   ----------

	      OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity                                     14,230       14,230
Decommissioning trust funds                                             125,054      119,663
Non-utility property - at cost (less accumulated depreciation)           21,489       21,671
								     ----------   ----------
TOTAL                                                                   160,773      155,564
								     ----------   ----------


		      UTILITY PLANT
Electric                                                              5,557,776    5,456,093
Property under capital lease                                            241,071      239,395
Construction work in progress                                           147,122      110,792
Nuclear fuel under capital lease                                         50,893       70,316
								     ----------   ----------
TOTAL UTILITY PLANT                                                   5,996,862    5,876,596
Less - accumulated depreciation and amortization                      2,651,336    2,538,964
								     ----------   ----------
UTILITY PLANT - NET                                                   3,345,526    3,337,632
								     ----------   ----------

	     DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
  SFAS 109 regulatory asset - net                                       157,642      179,368
  Unamortized loss on reacquired debt                                    25,846       28,341
  Other regulatory assets                                               119,359       73,754
Long-term receivables                                                     1,511        1,515
Other                                                                    26,007       16,650
								     ----------   ----------
TOTAL                                                                   330,365      299,628
								     ----------   ----------

TOTAL ASSETS                                                         $4,602,988   $4,149,701
								     ==========   ==========
See Notes to Respective Financial Statements.

				 ENTERGY LOUISIANA, INC.
				      BALANCE SHEETS
			   LIABILITIES AND SHAREHOLDERS' EQUITY

									   December 31,
									 2002        2001
									  (In Thousands)

		   CURRENT LIABILITIES

Currently maturing long-term debt                                      $296,366     $185,627
Accounts payable:
  Associated companies                                                   54,622       73,208
  Other                                                                 119,416       93,460
Customer deposits                                                        63,255       61,359
Taxes accrued                                                                 -       20,410
Interest accrued                                                         30,553       34,524
Deferred fuel costs                                                      25,602       67,493
Obligations under capital leases                                         33,927       34,171
Other                                                                     8,941       14,119
								     ----------   ----------
TOTAL                                                                   632,682      584,371
								     ----------   ----------

	  DEFERRED CREDITS AND OTHER LIABILITIES
Accumulated deferred income taxes and taxes accrued                   1,695,570      776,610
Accumulated deferred investment tax credits                             106,539      111,942
Obligations under capital leases                                         16,966       36,144
Other regulatory liabilities                                              6,601            -
Accumulated provisions                                                   74,340       68,522
Other                                                                    95,504       82,780
								     ----------   ----------
TOTAL                                                                 1,995,520    1,075,998
								     ----------   ----------

Long-term debt                                                          830,188    1,091,329
Company-obligated mandatorily redeemable
  preferred securities of subsidiary trust holding
  solely junior subordinated deferrable debentures                       70,000       70,000

		   SHAREHOLDERS' EQUITY
Preferred stock without sinking fund                                    100,500      100,500
Common stock, no par value, authorized 250,000,000
  shares; issued 165,173,180 shares in 2002 and 2001                  1,088,900    1,088,900
Capital stock expense and other                                          (1,718)      (1,718)
Retained earnings                                                         6,916      140,321
Less - treasury stock, at cost (18,202,573 shares in 2002)              120,000            -
								     ----------   ----------
TOTAL                                                                 1,074,598    1,328,003
								     ----------   ----------

Commitments and Contingencies

		TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY           $4,602,988   $4,149,701
								     ==========   ==========
See Notes to Respective Financial Statements.

			       ENTERGY LOUISIANA, INC.
			   STATEMENTS OF RETAINED EARNINGS

					      For the Years Ended December 31,
						  2002      2001        2000
						       (In Thousands)

Retained Earnings, January 1                    $140,321   $150,319    $59,554

  Add:
    Net income                                   144,709    132,550    162,679

  Deduct:
    Dividends declared:
      Preferred stock                              6,714      7,495      9,514
      Common stock                               271,400    134,600     62,400
    Capital stock expenses                             -        453          -
						--------   --------   --------
	Total                                    278,114    142,548     71,914
						--------   --------   --------

Retained Earnings, December 31                    $6,916   $140,321   $150,319
						========   ========   ========

See Notes to Respective Financial Statements.

ENTERGY LOUISIANA, INC.

SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON

	2002	2001	2000	1999	1998
	(In Thousands)
Operating revenues	$ 1,815,352	$ 1,901,913	$ 2,062,437	$ 1,806,594	$ 1,710,908
Net income	$ 144,709	$ 132,550	$ 162,679	$ 191,770	$ 179,487
Total assets	$ 4,602,988	$ 4,149,701	$ 4,289,409	$ 4,084,650	$ 4,181,041
Long-term obligations (1)	$ 917,154	$ 1,197,473	$ 1,411,345	$ 1,274,006	$ 1,530,590

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

ENTERGY MISSISSIPPI, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Operating Income

2002 Compared to 2001

                Operating income increased by $16.5 million primarily due to:

• sales growth and weather of $10.1 million in the residential and commercial sectors;

• a reduction of $5.2 million in storm damage reserve expense;

• increased revenues of $9.1 million from new customer fees and late charges; and

• a formula rate plan revenue increase of $3.1 million.

Partially offsetting the increase were the following:

• increased other operation and maintenance expenses of $14.4 million, which is explained below; and

• increased depreciation and amortization expenses of $6.5 million due to increased 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 primarily due to:

• an increase of $5.5 million in plant maintenance expense due to an unscheduled outage at a fossil plant in 2002; and

• an increase of $5.0 million in benefit costs.

2001 Compared to 2000

                Operating income decreased by $3.5 million primarily due to decreased sales volume, primarily due to weather, of $14.7 million, partially offset by decreased other operation and maintenance expenses of $12.8 million.

                Other operation and maintenance expenses decreased primarily due to a decrease in plant maintenance expenses of $14.6 million due to outage costs at certain fossil plants in 2000.

Other Impacts on Earnings

2002 Compared to 2001

                Other income and interest expense decreased earnings by $6.3 million primarily due to:

• decreased other income of $13.1 million primarily due to the final FERC order which ceased interest on the deferred System Energy costs that Entergy Mississippi was not recovering through rates. See Note 2 to the domestic utility companies and System Energy financial statements for further discussion of the System Energy rate proceeding and FERC order; and

• decreased interest expense on long-term debt of $4.4 million primarily due to the retirement of $65 million of 6.875% Series First Mortgage Bonds in June 2002.

2001 Compared to 2000

                Other income and interest expense increased earnings by $1.7 million primarily due to:

• increased other income of $7.5 million primarily due to interest recorded on the deferred fuel balance as a result of the MPSC order providing for a 24-month recovery of the September 2000 under-recovered deferred fuel balance of $136.7 million; offset by

• increased interest expense on long-term debt of $5.4 million primarily due to the issuance of $70 million of 6.25% Series First Mortgage Bonds in January 2001.

Income Taxes

                The effective income tax rates for 2002, 2001, and 2000 were 25.4%, 34.1%, and 37.0%, 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 by $102.6 million primarily due to a decrease in fuel cost recovery revenues primarily due to lower fuel factors resulting from the decreases in the market prices for natural gas and purchased power.

                Fuel and purchased power expenses decreased primarily due to:

• the displacement of oil generation by lower priced gas generation. Oil generation was used in 2001 due to significant increases in the market price of natural gas;

• a decrease in generation; and

• a decrease in the average market price of purchased power.

                Other regulatory charges (credits) have no material effect on operating income due to recovery and/or refund of such expenses. Other regulatory credits decreased by $6.6 million primarily due to the settlement of the System Energy rate proceeding in 2001 which ceased the deferral of costs associated with purchases from System Energy.

2001 Compared to 2000

                Operating revenues increased by $156.4 million primarily due to increased fuel cost recovery revenues of $157.8 million due to an increase in the energy cost recovery rider to collect the under-recovered fuel and purchased power costs incurred as of September 30, 2000, as well as an additional increase in the energy cost recovery rider effective in April 2001. The recovery of $136.7 million, plus carrying charges, occurred over a 24-month period, which began in January 2001.

                Fuel and purchased power expenses increased primarily due to over-recovery of fuel costs, including the effect of increased recoveries approved by the MPSC to recover previous under-recoveries.

                Other regulatory charges (credits) have no material effect on operating income due to recovery and/or refund of such expenses. Other regulatory credits increased by $23.1 million primarily due to an under-recovery of Grand Gulf 1-related costs as a result of a lower rider implemented in October 2000.

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

$ 54,048 

$ 5,113 

$ 4,787 

Cash flow provided by (used in):

     Operating activities

156,868 

178,110 

182,261 

     Investing activities

(135,122)

(175,822)

(279,478)

     Financing activities

   71,927 

  46,647 

  97,543 

          Net increase in cash and cash equivalents

   93,673 

  48,935 

       326 

Cash and cash equivalents at end of period

$147,721 

$ 54,048 

$ 5,113 

Operating Activities

                Cash flow from operations decreased by $21.2 million in 2002 due to the net effect of the System Energy refund, partially offset by increased net income and money pool activity. Money pool activity increased operating cash flow due to Entergy Mississippi lending to the money pool in 2002 and 2001 versus borrowing from the money pool in 2000.

                Entergy Mississippi's 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)
$8,702	$11,505	($30,719)	($40,622)

                See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.

                Cash flow from operations decreased by $4.2 million in 2001 due to money pool activity offset by the net effect of the System Energy refund. Money pool activity decreased operating cash flow due to Entergy Mississippi lending to the money pool in 2001 versus borrowing from the money pool in 2000 and 1999.

Investing Activities

                The decrease of $40.7 million in net cash flow used in investing activities in 2002 was primarily due to other temporary cash investments of $18.6 million made in 2001 that provided cash in 2002 when they matured.

                The decrease of $103.7 million in net cash flow used in investing activities in 2001 was primarily due to the recovery in 2001 of deferred fuel costs. Entergy Mississippi treated these costs as regulatory investments because the MPSC allowed recovery of the accumulated fuel cost regulatory asset over longer than a twelve-month period. Entergy Mississippi's fuel recovery period changed effective January 2001, and Entergy Mississippi's fuel cost under-recoveries after that date are being recovered over less than a twelve-month period.

                The decrease in net cash flow used in investing activities in 2001 was partially offset due to a temporary cash investment of $18.6 million made in 2001 and increased construction expenditures of $38.6 million due to various economic development and substation projects.

Financing Activities

                The increase of $25.3 million in net cash flow provided by financing activities in 2002 was primarily due to an increase in net issuances of long-term debt, partially offset by an increase in dividends paid of $7.7 million.

                The decrease of $50.9 million in net cash flow provided by financing activities in 2001 was primarily due to a decrease in net issuances of long-term debt.

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

Uses of Capital

                Entergy Mississippi 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 Mississippi's planned construction and other capital investments, and existing debt obligations:

	2003	2004	2005	2006-2007	after 2007
	(In Millions)
Planned construction and
capital investment	$132	$136	$138	N/A	N/A
Long-term debt maturities	$255	$150	$-	$-	$360
Unconditional fuel and purchased
power obligations	$168	$168	$168	$336	$2,436

                The planned capital investment estimate for Entergy Mississippi 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 Mississippi dividends its earnings to Entergy Corporation at a percentage determined monthly. Entergy Mississippi is restricted by its 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 Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $36.2 million.

Sources of Capital

                Entergy Mississippi's 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 Mississippi issued $175 million of long-term debt. The net proceeds from Entergy Mississippi's 2002 debt issuances were used to retire, at maturity, $70 million of 6.25% Series First Mortgage Bonds due February 1, 2003, and a portion of the $120 million 7.75% Series First Mortgage Bonds due February 15, 2003. Entergy Mississippi issued an additional $100 million of long-term debt in January 2003 that will be used to meet 2003 maturities. Entergy Mississippi 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 Mississippi 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 Mississippi, including borrowings under the money pool, are limited to an amount authorized by the SEC, $160 million. Under the SEC order authorizing the short-term borrowing limits, Entergy Mississippi cannot incur new short-term indebtedness if the issuer's common equity would comprise less than 30% of its capital. Entergy Mississippi has a 364-day credit facility available expiring May 2003 in the amount of $25 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 Mississippi's 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. The MPSC has recommended not pursuing open access at this time. 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.

State and Local Rate Regulation

                The rates that Entergy Mississippi charges for its services are an important item influencing its financial position, results of operations, and liquidity. Entergy Mississippi is closely regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the MPSC, is primarily responsible for approval of the rates charged to customers.

                Pursuant to Entergy Mississippi's annual performance-based formula rate plan filing for the 2001 test year, the MPSC approved a stipulation between the MPSC 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, which is based on an ROE midpoint 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 in March 2004.

                In addition to rate proceedings, Entergy Mississippi's fuel costs recovered from customers are subject to regulatory scrutiny. Entergy Mississippi's 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.

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 proceed ing, 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 Mississippi's annual production costs over the period 2002 to 2007 will be $27 million under to $13 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 les s 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 Mississippi, although neither the timing nor the outcome of the proceedings at FERC can be predicted at this time.

Market and Credit Risks

               Entergy Mississippi 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.

Litigation Risks

The state of Mississippi has proven to be an unusually litigious environment. Judges and juries in Mississippi have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. In November 2002 the Mississippi Legislature passed House Bill 19, which was generally characterized as tort reform legislation. House Bill 19 included, among other things, provisions dealing with the venue of civil actions, the status of innocent sellers as defendants, limitations on the amount of punitive damages, and the elimination of a 15 percent appeal penalty. Entergy Mississippi uses legal and appropriate means to contest litigation threatened or filed against it but the litigation environment in this jurisdiction is a significant business risk.

Critical Accounting Estimates

                The preparation of Entergy Mississippi'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 Mississippi's financial statements.

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%)	$ 78	$ 5,062
Rate of return on plan assets	(0.25%)	$ 448	-
Rate of increase in compensation	0.25%	$ 107	$ 967

                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%	$ 203	$ 1,186
Discount rate	(0.25%)	$ 111	$ 1,496

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 Mississippi in 2002 was $1.5 million. Taking into account asset performance and the changes made in the actuarial assumptions, Entergy Mississippi does not anticipate 2003 pension income to be materially different from 2002. Entergy Mississippi 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 Mississippi's accumulated benefit obligation at December 31, 2002 exceeded plan assets. As a result, Entergy Mississippi was required to recognize an additional minimum liability of $13 million as prescribed by SFAS 87. Entergy Mississippi recorded an intangible asset for the $3.2 million of unrecognized prior service cost and the remaining $9.8 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 Mississippi in 2002 were $4.5 million. Because of a number of factors, including the increased health care cost trend rate, Entergy Mississippi expects 2003 costs to approximate $6 million.

INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Shareholders of

Entergy Mississippi, Inc.:

We have audited the accompanying balance sheets of Entergy Mississippi, Inc. as of December 31, 2002 and 2001, and the related statements of income, retained earnings, and cash flows (pages 212 through 216 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 Mississippi, 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 MISSISSIPPI, INC.
                            INCOME STATEMENTS

                                                              For the Years Ended December 31,
                                                              2002          2001        2000
                                                                       (In Thousands)
                 OPERATING REVENUES
Domestic electric                                            $991,095     $1,093,741   $937,371
                                                             --------     ----------   --------
                 OPERATING EXPENSES
Operation and Maintenance:
   Fuel, fuel-related expenses, and
     gas purchased for resale                                 318,350        415,347    221,075
   Purchased power                                            315,963        365,540    366,491
   Other operation and maintenance                            170,052        155,646    168,432
Taxes other than income taxes                                  47,993         47,956     45,436
Depreciation and amortization                                  55,409         48,933     49,046
Other regulatory credits - net                                (23,438)       (29,993)    (6,872)
                                                             --------     ----------   --------
TOTAL                                                         884,329      1,003,429    843,608
                                                             --------     ----------   --------

OPERATING INCOME                                              106,766         90,312     93,763
                                                             --------     ----------   --------

                    OTHER INCOME
Allowance for equity funds used during construction             3,844          2,559      2,385
Gain on sale of assets                                              -              3         19
Interest and dividend income                                    4,213         18,904     10,750
Miscellaneous - net                                            (2,572)        (2,918)    (2,070)
                                                             --------     ----------   --------
TOTAL                                                           5,485         18,548     11,084
                                                             --------     ----------   --------

             INTEREST AND OTHER CHARGES
Interest on long-term debt                                     42,580         46,950     41,583
Other interest - net                                            2,884          4,041      3,294
Allowance for borrowed funds used during construction          (3,467)        (2,215)    (1,871)
                                                             --------     ----------   --------
TOTAL                                                          41,997         48,776     43,006
                                                             --------     ----------   --------

INCOME BEFORE INCOME TAXES                                     70,254         60,084     61,841

Income taxes                                                   17,846         20,464     22,868
                                                             --------     ----------   --------

NET INCOME                                                     52,408         39,620     38,973

Preferred dividend requirements and other                       3,369          3,082      3,370
                                                             --------     ----------   --------

EARNINGS APPLICABLE TO
COMMON STOCK                                                  $49,039        $36,538    $35,603
                                                             ========     ==========   ========
See Notes to Respective Financial Statements.

                         ENTERGY MISSISSIPPI, INC.
                         STATEMENTS OF CASH FLOWS

                                                                 For the Years Ended December 31,
                                                                2002           2001         2000
                                                                          (In Thousands)
                 OPERATING ACTIVITIES
Net income                                                       $52,408       $39,620      $38,973
Noncash items included in net income:
  Other regulatory credits - net                                 (23,438)      (29,993)      (6,872)
  Depreciation and amortization                                   55,409        48,933       49,046
  Deferred income taxes and investment tax credits                (7,940)      (68,133)      51,081
  Allowance for equity funds used during construction             (3,844)       (2,559)      (2,385)
  Gain on sale of assets                                               -            (3)         (19)
Changes in working capital:
  Receivables                                                     (2,000)        1,059      (30,628)
  Fuel inventory                                                    (828)       (1,388)         338
  Accounts payable                                                16,736       (46,976)       3,064
  Taxes accrued                                                  (10,576)         (378)      (4,106)
  Interest accrued                                                 2,027         4,568        3,062
  Deferred fuel costs                                             67,981        54,453       47,939
  Other working capital accounts                                 (22,897)       13,672        6,160
Provision for estimated losses and reserves                          386           821         (568)
Changes in other regulatory assets                                (6,028)      130,333       (9,929)
Other                                                             39,472        34,081       37,105
                                                                --------      --------     --------
Net cash flow provided by operating activities                   156,868       178,110      182,261
                                                                --------      --------     --------

                 INVESTING ACTIVITIES
Construction expenditures                                       (157,532)     (159,815)    (121,252)
Allowance for equity funds used during construction                3,844         2,559        2,385
Changes in other temporary investments - net                      18,566       (18,566)           -
Other regulatory investments                                           -             -     (160,611)
                                                                --------      --------     --------
Net cash flow used in investing activities                      (135,122)     (175,822)    (279,478)
                                                                --------      --------     --------

                 FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt                     167,596        69,616      118,913
Retirement of long-term debt                                     (65,000)            -            -
Dividends paid:
  Common stock                                                   (27,300)      (19,600)     (18,000)
  Preferred stock                                                 (3,369)       (3,369)      (3,370)
                                                                --------      --------     --------
Net cash flow provided by financing activities                    71,927        46,647       97,543
                                                                --------      --------     --------

Net increase in cash and cash equivalents                         93,673        48,935          326

Cash and cash equivalents at beginning of period                  54,048         5,113        4,787
                                                                --------      --------     --------

Cash and cash equivalents at end of period                      $147,721       $54,048       $5,113
                                                                ========      ========     ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid/(received) during the period for:
  Interest - net of amount capitalized                           $40,572       $43,915      $39,569
  Income taxes                                                   $28,440       $88,657     ($23,763)

See Notes to Respective Financial Statements.

                         ENTERGY MISSISSIPPI, INC.
                              BALANCE SHEETS
                                  ASSETS

                                                                        December 31,
                                                                    2002          2001
                                                                       (In Thousands)
                    CURRENT ASSETS
Cash and cash equivalents:
  Cash                                                               $10,782       $12,883
  Temporary cash investments - at cost,
    which approximates market                                        136,939        41,165
                                                                  ----------    ----------
        Total cash and cash equivalents                              147,721        54,048
                                                                  ----------    ----------
Other temporary investments                                                -        18,566
Accounts receivable:
  Customer                                                            52,480        50,370
  Allowance for doubtful accounts                                     (1,633)       (1,232)
  Associated companies                                                11,978        14,201
  Other                                                                6,434         3,080
  Accrued unbilled revenues                                           29,460        30,300
                                                                  ----------    ----------
    Total accounts receivable                                         98,719        96,719
                                                                  ----------    ----------
Deferred fuel costs                                                   38,177       106,158
Accumulated deferred income taxes                                      7,822             -
Fuel inventory - at average cost                                       5,652         4,824
Materials and supplies - at average cost                              18,650        16,896
Prepayments and other                                                 18,777         8,521
                                                                  ----------    ----------
TOTAL                                                                335,518       305,732
                                                                  ----------    ----------

            OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity                                   5,531         5,531
Non-utility property - at cost (less accumulated depreciation)         6,594         6,723
                                                                  ----------    ----------
TOTAL                                                                 12,125        12,254
                                                                  ----------    ----------

                    UTILITY PLANT
Electric                                                           2,076,828     1,939,182
Property under capital lease                                             175           211
Construction work in progress                                        102,783       110,450
                                                                  ----------    ----------
TOTAL UTILITY PLANT                                                2,179,786     2,049,843
Less - accumulated depreciation and amortization                     768,609       741,892
                                                                  ----------    ----------
UTILITY PLANT - NET                                                1,411,177     1,307,951
                                                                  ----------    ----------

           DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
  SFAS 109 regulatory asset - net                                     18,250        22,387
  Unamortized loss on reacquired debt                                 12,756        13,925
  Other regulatory assets                                             23,668        13,503
Other                                                                 18,878         7,274
                                                                  ----------    ----------
TOTAL                                                                 73,552        57,089
                                                                  ----------    ----------

TOTAL ASSETS                                                      $1,832,372    $1,683,026
                                                                  ==========    ==========
See Notes to Respective Financial Statements.

                         ENTERGY MISSISSIPPI, INC.
                              BALANCE SHEETS
                   LIABILITIES AND SHAREHOLDERS' EQUITY

                                                                        December 31,
                                                                     2002          2001
                                                                       (In Thousands)
                 CURRENT LIABILITIES
Currently maturing long-term debt                                   $255,000       $65,000
Accounts payable:
  Associated companies                                                50,973        45,554
  Other                                                               38,700        27,383
Customer deposits                                                     33,264        29,421
Taxes accrued                                                         20,908        31,484
Accumulated deferred income taxes                                          -        19,277
Interest accrued                                                      19,694        17,667
Obligations under capital leases                                          39            36
System Energy refund                                                       -        14,836
Other                                                                  2,070         1,964
                                                                  ----------    ----------
TOTAL                                                                420,648       252,622
                                                                  ----------    ----------

        DEFERRED CREDITS AND OTHER LIABILITIES
Accumulated deferred income taxes and taxes accrued                  292,809       266,498
Accumulated deferred investment tax credits                           16,497        17,908
Obligations under capital leases                                         136           175
Accumulated provisions                                                 8,013         7,627
Other                                                                 51,670        37,678
                                                                  ----------    ----------
TOTAL                                                                369,125       329,886
                                                                  ----------    ----------

Long-term debt                                                       510,104       589,762

                 SHAREHOLDERS' EQUITY
Preferred stock without sinking fund                                  50,381        50,381
Common stock, no par value, authorized 15,000,000
  shares; issued and outstanding 8,666,357 shares in
  2002 and 2001                                                      199,326       199,326
Capital stock expense and other                                          (59)          (59)
Retained earnings                                                    282,847       261,108
                                                                  ----------    ----------
TOTAL                                                                532,495       510,756
                                                                  ----------    ----------

Commitments and Contingencies

            TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY            $1,832,372    $1,683,026
                                                                  ==========    ==========
See Notes to Respective Financial Statements.

                        ENTERGY MISSISSIPPI, INC.
                     STATEMENTS OF RETAINED EARNINGS

                                                  For the Years Ended December 31,
                                                   2002        2001        2000
                                                           (In Thousands)

Retained Earnings, January 1                      $261,108   $244,170    $226,567

  Add:
    Net income                                      52,408     39,620      38,973

  Deduct:
    Dividends declared:
      Preferred stock                                3,369      3,082       3,370
      Common stock                                  27,300     19,600      18,000
                                                  --------   --------    --------
        Total                                       30,669     22,682      21,370
                                                  --------   --------    --------

Retained Earnings, December 31                    $282,847   $261,108    $244,170
                                                  ========   ========    ========

See Notes to Respective Financial Statements.

ENTERGY MISSISSIPPI, INC.

SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON

	2002	2001	2000	1999	1998
	(In Thousands)
Operating revenues	$ 991,095	$ 1,093,741	$ 937,371	$ 832,819	$ 976,300
Net income	$ 52,408	$ 39,620	$ 38,973	$ 41,588	$ 62,638
Total assets	$ 1,832,372	$ 1,683,026	$ 1,683,939	$ 1,460,017	$ 1,350,929
Long-term obligations (1)	$ 510,240	$ 589,937	$ 584,678	$ 464,756	$ 464,000

(1) Includes long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations.

ENTERGY NEW ORLEANS, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

                Entergy New Orleans experienced a net loss in 2002 primarily due to accruals for potential rate actions and refunds, increased other operation and maintenance expenses, decreased interest income, and increased interest charges. These factors were offset by increased retail sales, and an increase in the price applied to unbilled sales.

                Entergy New Orleans experienced a net loss in 2001 because of lower operating revenues. Compared to 2000, operating revenues decreased as a result of lower electric sales volume and less favorable weather in addition to a decrease in the price applied to unbilled sales. An increase in other operation and maintenance expenses, interest expense, and rate refund provisions also contributed to the decrease.

Operating Income

2002 Compared to 2001

2002 Compared to 2001

                Operating income increased by $10.3 million primarily due to:

• sales growth and weather of $6.9 million. Higher electric sales volume increased revenues due to increased billed usage of 258 GWh in the residential, commercial, and governmental sectors after adjusting for the effects of weather. The effect of weather increased sales by 26 GWh in those sectors;
• an increase in revenue of $11.0 million due to an increase in the price applied to unbilled sales; and
• decreased taxes other than income taxes primarily due to a decrease in local franchise taxes of $5.9 million due to lower retail revenue.

Partially offsetting the increase were the following:

• a decrease of $7.3 million due to accruals for potential rate actions and refunds; and
• increased other operation and maintenance expenses of $6.5 million, which is explained below.

                Other operation and maintenance expenses increased in 2002 due to:

• increased benefit costs of $2.6 million;
• increased rate proceedings costs of $2.4 million; and
• increased fossil expenses of $2.1 million due to increased asbestos litigation reserves in 2002 and the write-off of obsolete materials.

2001 Compared to 2000

                Operating income decreased by $32.3 million primarily due to:

• decreased sales volume and weather impacts of $11.8 million. Lower electric sales volume reduced revenues due to decreased billed usage of 186 GWh in the residential, commercial, and governmental sectors after adjusting for the effects of weather. The effect of less favorable weather decreased usage by 107 GWh in the residential sector;
• a decrease in revenue of $13.2 million primarily due to a decrease in the price applied to unbilled sales;
• a decrease of $5.9 million due to accruals for potential rate actions and refunds; and
• increased other operation and maintenance expenses of $4.6 million, which is explained below.

Partially offsetting the decrease was an increase in net gas revenue of $17.5 million due to increased fuel recovery, partially offset by decreased sales volume.

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

• maintenance of fossil plants of $2.4 million;
• rate proceedings costs of $3.3 million; and
• uncollectible accounts expense for miscellaneous accounts receivable of $3.5 million.

The increase in other operation and maintenance expenses was partially offset by a decrease in administrative and general salaries expense of $2.2 million and a decrease in injuries and damage expense of $1.5 million.

Other Impacts on Earnings

2002 Compared to 2001

                Other income and interest expense decreased earnings by $4.4 million in 2002 primarily due to:

• increased other interest charges of $3.3 million primarily due to interest recorded for potential rate actions and refunds; and
• decreased other income of $1.2 million due to $3.6 million of interest recorded in the first half of 2001 on deferred System Energy costs that Entergy New Orleans was not recovering through rates. The deferral of these costs ceased in the third quarter of 2001 as a result of a final FERC order. See Note 2 to the domestic utility companies and System Energy financial statements for additional discussion of the rate proceeding and refund. The decrease was offset by a $2.0 million gain on the sale of property in October 2002.

2001 Compared to 2000

                Interest on long-term debt increased earnings by $3.3 million primarily due to the issuance of $30 million of long-term debt in February 2001 and the issuance of $30 million of long-term debt in July 2000.

Income Taxes

                The effective income tax rates for 2002, 2001, and 2000 were 64.7%, 66.7%, and 41.2%, 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 $123.0 million primarily due to decreased fuel cost recovery revenues of $81.4 million and decreased gas revenue of $44.8 million. Corresponding to the decrease in fuel cost recovery revenues, fuel and purchased power expenses decreased by $139.5 million. These decreases were primarily due to a decrease in the market prices of natural gas and purchased power.

                Other regulatory credits decreased $14.8 million primarily due to the completion of the Grand Gulf 1 Rate Deferral Plan in 2001. Also contributing to the decrease was an over-recovery of Grand Gulf 1-related costs in 2002 compared to an under-recovery in 2001 and the deferral in 2001 of capacity charges included in purchased power costs for summer capacity that Entergy New Orleans expected to recover in the future.

2001 Compared to 2000

                Operating revenues decreased $9.4 million primarily due to:

• decreased sales for resale revenues of $26.8 million due to decreased demand from affiliated systems somewhat offset by increased prices for resale electricity;
• decreased revenue due to a decrease in the price applied to unbilled sales; and
• decreased electricity usage in the service territory.

Largely offsetting the decrease was an increase in fuel cost recovery revenue of $53.4 million primarily due to recovery of higher fuel and purchased power expenses.

                Fuel and purchased power expenses increased $33.8 million primarily due to the increased market prices of natural gas and purchased power.

                Other regulatory credits increased by $5.0 million primarily due to the deferral of capacity charges included in purchased power costs for summer capacity that Entergy New Orleans expects to recover in the future. The increase was also due to an under-recovery of Grand Gulf 1- related costs in 2001 compared to an over-recovery in 2000.

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	$ 38,184	$ 6,302	$ 4,454
Cash flow provided by (used in):
Operating activities	72,143	77,706	30,461
Investing activities	(41,647)	(74,061)	(47,712)
Financing activities	(2,433)	28,237	19,099
Net increase in cash and cash equivalents	28,063	31,882	1,848
Cash and cash equivalents at end of period	$ 66,247	$ 38,184	$ 6,302

Operating Activities

                Cash flow from operations decreased in 2002 compared to 2001 primarily due to the payment of the System Energy refund in the first quarter of 2002 in addition to a decrease in customer receivables due to the timing of collections. These decreases were offset by an increase in payables in 2002 compared to 2001 due to the timing of fuel payments.

                Cash flow from operations increased in 2001 compared to 2000 primarily due to the net effect of the System Energy refund, partially offset by decreased net income.

                Entergy New Orleans' 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)
$3,500	$9,208	($5,734)	($9,663)

Money pool activity increased Entergy New Orleans' operating cash flows by $5.7 million in 2002, decreased operating cash flows by $14.9 million in 2001, and decreased operating cash flow by $3.9 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 $14.9 million of other temporary investments.

                The increase in net cash used in investing activities in 2001 was primarily due to an increase in temporary investments made in 2001 and an increase in construction expenditures of $12.3 million. Construction expenditures increased primarily due to spending on the customer care system project, distribution substation projects, fossil projects, and City of New Orleans mandated gas projects.

Financing Activities

                Financing activities used a small amount of cash in 2002 compared to providing cash in 2001 primarily due to the net issuance of $30 million of long-term debt in 2001.

                The increase in net cash provided by financing activities in 2001 was primarily due the net issuance of $30 million of long-term debt in 2001 and a decrease in common stock dividends paid to Entergy Corporation of $8.7 million.

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

Uses of Capital

                Entergy New Orleans 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 New Orleans' planned construction and other capital investments and existing debt obligations:

	2003	2004	2005	2006-2007	After 2007
	(In Millions)
Planned construction and
capital investment	$51	$53	$54	N/A	N/A
Long-term debt maturities	N/A	$30	$30	$40	$130
Unconditional fuel and purchased power     obligations	$84	$84	$84	$168	$1,218

                The planned capital investment estimate for Entergy New Orleans reflects capital required to support existing business. 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 New Orleans dividends its earnings to Entergy Corporation at a percentage determined monthly. Currently, all of Entergy New Orleans' retained earnings are available for distribution.

Sources of Capital

                Entergy New Orleans' sources to meet its capital requirements include:

• internally generated funds;
• cash on hand; and
• debt issuances.

                As shown in the Earnings Ratios presented in Item 1 of this Form 10-K, Entergy New Orleans' earnings for the twelve months ended December 31, 2002 and 2001 were not adequate to cover its fixed charges and preferred dividends. Under its mortgage covenants, Entergy New Orleans does not currently have the capacity to issue new incremental mortgage-backed debt. Since the settlement of Entergy New Orleans' last rate proceeding, which was approved by the City Council in 1998, its fixed charge coverage has declined and its debt ratio has increased. While Entergy New Orleans has made investments (some of which were required by agreement with the City Council) and incurred expenses necessary to improve customer service since  its  last rate proceeding, its base revenues have not increased. In an October 2002 report, Moody's Investors Service states that its rating outlook for Entergy New Orleans is negative due to the declining credit measures and the uncertainty of Entergy New Orleans' pending rate cas e. Moody's currently rates Entergy New Orleans senior secured debt at Baa2.

                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. 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. Absent constructive rate-making in its pending proceeding, it is likely that the cost of and access to the capital necessary to finance Entergy New Orleans' current level of service will be adversely affected.

                The net proceeds of Entergy New Orleans' debt issuance in 2002 were used to redeem, prior to maturity, $25 million of 7% Series First Mortgage Bonds due March 1, 2003. Entergy New Orleans 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 New Orleans 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 New Orleans, including borrowings under the money pool, are limited to an amount authorized by the SEC, $100 million. Under restrictions contained in its articles of incorporation, Entergy New Orleans could incur approximately $38 million of new unsecured debt as of December 31, 2002. Under the SEC order authorizing the short-term borrowing limits, Entergy New Orleans cannot incur new short-term indebtedness if its common equity would comprise less than 30% of its capital. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy New Orleans' short-term borrowing limits.

Significant Factors and Known Trends

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 proceed ing, 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 New Orleans' annual production costs over the period 2002 to 2007 will be $7 million to $46 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 New Orleans, although neither the timing nor the outcome of the proceedings at FERC can be predicted at this time.

                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.

Market and Credit Risks

                Entergy New Orleans has certain market and credit risks inherent in its business. 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.

State and Local Rate Regulatory Risks

                The rates that Entergy New Orleans charges for its services are an important item influencing its financial position, results of operations, and liquidity. Entergy New Orleans is closely regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the City Council, is primarily responsible for approval of the rates charged to customers.

                In addition to rate proceedings, Entergy New Orleans' fuel costs recovered from customers are subject to regulatory scrutiny.

               Entergy New Orleans' retail and wholesale 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.

Environmental Risks

                Entergy New Orleans' facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous solid wastes, and other environmental matters. Management believes that Entergy New Orleans 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 territory in which Entergy New Orleans operates has proven to be an unusually litigious environment. Judges and juries in New Orleans have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy New Orleans uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment poses a significant business risk.

Critical Accounting Estimates

                The preparation of Entergy New Orleans' 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 New Orleans' financial statements.

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%)	$67	$ 2,091
Rate of return on plan assets	(0.25%)	$75	-
Rate of increase in compensation	0.25%	$56	$ 504

                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%	$ 103	$1,066
Discount rate	(0.25%)	$ 26	$1,324

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 New Orleans in 2002 was $3.0 million. Taking into account asset performance and the changes made in the actuarial assumptions, Entergy New Orleans does not anticipate 2003 pension cost to be materially different from 2002. Entergy New Orleans 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 New Orleans' accumulated benefit obligation at December 31, 2002 exceeded plan assets. As a result, Entergy New Orleans was required to recognize an additional minimum liability of $4.8 million as prescribed by SFAS 87. Entergy New Orleans recorded an intangible asset for the $1.8 million of unrecognized prior service cost and the remaining $3 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 New Orleans in 2002 were $4.9 million. Because of a number of factors, including the increased health care cost trend rate, Entergy New Orleans expects 2003 costs to approximate $5.8 million.

INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Shareholders of

Entergy New Orleans, Inc.:

We have audited the accompanying balance sheets of Entergy New Orleans, Inc. as of December 31, 2002 and 2001, and the related statements of operations, retained earnings, and cash flows (pages 228 through 232 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 New Orleans, 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 NEW ORLEANS INC.
                        STATEMENTS OF OPERATIONS

                                                             For the Years Ended December 31,
                                                               2002         2001       2000
                                                                       (In Thousands)
                 OPERATING REVENUES
Domestic electric                                             $424,527    $502,672    $514,774
Natural gas                                                     83,347     128,178     125,516
                                                              --------    --------    --------
TOTAL                                                          507,874     630,850     640,290
                                                              --------    --------    --------

                 OPERATING EXPENSES
Operation and Maintenance:
   Fuel, fuel-related expenses, and
     gas purchased for resale                                  163,323     240,781     253,869
   Purchased power                                             158,191     220,268     173,371
   Other operation and maintenance                              98,511      92,023      87,254
Taxes other than income taxes                                   40,099      46,878      45,132
Depreciation and amortization                                   27,699      24,922      23,550
Other regulatory charges (credits) - net                         2,701     (12,049)     (7,058)
Amortization of rate deferrals                                       -      10,977      24,786
                                                              --------    --------    --------
TOTAL                                                          490,524     623,800     600,904
                                                              --------    --------    --------

OPERATING INCOME                                                17,350       7,050      39,386
                                                              --------    --------    --------

                    OTHER INCOME
Allowance for equity funds used during construction              1,835       1,987       1,190
Gain on sale of assets                                           1,985           -           -
Interest and dividend income                                       689       5,005       3,514
Miscellaneous - net                                             (1,401)     (2,675)       (984)
                                                              --------    --------    --------
TOTAL                                                            3,108       4,317       3,720
                                                              --------    --------    --------

             INTEREST AND OTHER CHARGES
Interest on long-term debt                                      18,011      17,699      14,429
Other interest - net                                             4,939       1,962       1,462
Allowance for borrowed funds used during construction           (1,840)     (1,703)       (900)
                                                              --------    --------    --------
TOTAL                                                           21,110      17,958      14,991
                                                              --------    --------    --------

INCOME (LOSS) BEFORE INCOME TAXES                                 (652)     (6,591)     28,115

Income taxes                                                      (422)     (4,396)     11,597
                                                              --------    --------    --------

NET INCOME (LOSS)                                                 (230)     (2,195)     16,518

Preferred dividend requirements and other                          965         965         965
                                                              --------    --------    --------

EARNINGS (LOSS) APPLICABLE TO
COMMON STOCK                                                   ($1,195)    ($3,160)    $15,553
                                                              ========    ========    ========
See Notes to Respective Financial Statements.

                           ENTERGY NEW ORLEANS, INC.
                           STATEMENTS OF CASH FLOWS

                                                                    For the Years Ended December 31,
                                                                    2002           2001         2000
                                                                               (In Thousands)
                   OPERATING ACTIVITIES
Net income (loss)                                                      ($230)      ($2,195)     $16,518
Noncash items included in net income (loss):
  Amortization of rate deferrals                                           -        10,977       24,786
  Other regulatory charges (credits) - net                             2,701       (12,049)      (7,058)
  Depreciation and amortization                                       27,699        24,922       23,550
  Deferred income taxes and investment tax credits                     6,729       (24,198)        (639)
  Allowance for equity funds used during construction                 (1,835)       (1,987)      (1,190)
  Gain on sale of assets                                              (1,985)            -            -
Changes in working capital:
  Receivables                                                         10,540        33,183      (45,580)
  Fuel inventory                                                        (203)        1,123         (911)
  Accounts payable                                                    18,070       (40,364)      29,592
  Taxes accrued                                                        1,999        (5,823)       5,394
  Interest accrued                                                      (544)          913        1,163
  Deferred fuel costs                                                  4,686        38,430      (13,751)
  Other working capital accounts                                      (4,971)        9,115         (223)
Provision for estimated losses and reserves                           (3,348)       (2,669)        (365)
Changes in other regulatory assets                                    (3,061)       33,833      (11,637)
Other                                                                 15,896        14,495       10,812
                                                                     -------       -------      -------
Net cash flow provided by operating activities                        72,143        77,706       30,461
                                                                     -------       -------      -------

                   INVESTING ACTIVITIES
Construction expenditures                                            (58,341)      (61,189)     (48,902)
Allowance for equity funds used during construction                    1,835         1,987        1,190
Changes in other temporary investments - net                          14,859       (14,859)           -
                                                                     -------       -------      -------
Net cash flow used in investing activities                           (41,647)      (74,061)     (47,712)
                                                                     -------       -------      -------

                   FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt                          24,332        29,761       29,564
Retirement of long-term debt                                         (25,000)            -            -
Dividends paid:
  Common stock                                                          (800)         (800)      (9,500)
  Preferred stock                                                       (965)         (724)        (965)
                                                                     -------       -------      -------
Net cash flow provided by (used in) financing activities              (2,433)       28,237       19,099
                                                                     -------       -------      -------

Net increase in cash and cash equivalents                             28,063        31,882        1,848

Cash and cash equivalents at beginning of period                      38,184         6,302        4,454
                                                                     -------       -------      -------

Cash and cash equivalents at end of period                           $66,247       $38,184       $6,302
                                                                     =======       =======      =======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid/(received) during the period for:
  Interest - net of amount capitalized                               $19,961       $18,230      $14,331
  Income taxes                                                      ($37,929)      $47,380       $9,207

See Notes to Respective Financial Statements.

                          ENTERGY NEW ORLEANS INC.
                               BALANCE SHEETS
                                   ASSETS

                                                                      December 31,
                                                                   2002        2001
                                                                     (In Thousands)
                   CURRENT ASSETS
Cash and cash equivalents:
  Cash                                                             $11,175       $5,237
  Temporary cash investments - at cost,
    which approximates market                                       55,072       32,947
                                                                  --------     --------
        Total cash and cash equivalents                             66,247       38,184
                                                                  --------     --------
Other temporary investments                                              -       14,859
Accounts receivable:
  Customer                                                          24,901       33,827
  Allowance for doubtful accounts                                   (4,774)      (4,273)
  Associated companies                                               4,901       10,527
  Other                                                             10,133        6,550
  Accrued unbilled revenues                                         20,957       20,027
                                                                  --------     --------
    Total accounts receivable                                       56,118       66,658
                                                                  --------     --------
Accumulated deferred income taxes                                    1,230        4,882
Fuel inventory - at average cost                                     3,284        3,081
Materials and supplies - at average cost                             7,785        8,273
Prepayments and other                                                4,689       26,239
                                                                  --------     --------
TOTAL                                                              139,353      162,176
                                                                  --------     --------

           OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity                                 3,259        3,259
                                                                  --------     --------

                    UTILITY PLANT
Electric                                                           627,249      597,575
Natural gas                                                        149,102      142,741
Construction work in progress                                       48,345       43,166
                                                                  --------     --------
TOTAL UTILITY PLANT                                                824,696      783,482
Less - accumulated depreciation and amortization                   403,379      396,535
                                                                  --------     --------
UTILITY PLANT - NET                                                421,317      386,947
                                                                  --------     --------

          DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
  Unamortized loss on reacquired debt                                  556          761
  Other regulatory assets                                           13,904       10,843
Other                                                                4,855        2,051
                                                                  --------     --------
TOTAL                                                               19,315       13,655
                                                                  --------     --------

TOTAL ASSETS                                                      $583,244     $566,037
                                                                  ========     ========
See Notes to Respective Financial Statements.

                          ENTERGY NEW ORLEANS INC.
                               BALANCE SHEETS
                    LIABILITIES AND SHAREHOLDERS' EQUITY

                                                                     December 31,
                                                                   2002        2001
                                                                    (In Thousands)
                 CURRENT LIABILITIES
Accounts payable:
  Associated companies                                             $23,228      $18,199
  Other                                                             36,681       23,640
Customer deposits                                                   17,634       18,931
Taxes accrued                                                        1,999            -
Interest accrued                                                     6,488        7,032
Deferred fuel costs                                                 14,882       10,196
System Energy refund                                                     -       33,614
Other                                                                9,702        1,799
                                                                  --------     --------
TOTAL                                                              110,614      113,411
                                                                  --------     --------

       DEFERRED CREDITS AND OTHER LIABILITIES
Accumulated deferred income taxes and taxes accrued                 22,245       25,326
Accumulated deferred investment tax credits                          4,893        5,361
SFAS 109 regulatory liability - net                                 31,318       19,868
Other regulatory liabilities                                         1,311            -
Accumulated provisions                                               2,454        5,802
Other                                                               32,776       16,735
                                                                  --------     --------
TOTAL                                                               94,997       73,092
                                                                  --------     --------

Long-term debt                                                     229,191      229,097

                SHAREHOLDERS' EQUITY
Preferred stock without sinking fund                                19,780       19,780
Common stock, $4 par value, authorized 10,000,000
  shares; issued and outstanding 8,435,900 shares in 2002
  and 2001                                                          33,744       33,744
Paid-in capital                                                     36,294       36,294
Retained earnings                                                   58,624       60,619
                                                                  --------     --------
TOTAL                                                              148,442      150,437
                                                                  --------     --------

Commitments and Contingencies

           TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY             $583,244     $566,037
                                                                  ========     ========
See Notes to Respective Financial Statements.

                        ENTERGY NEW ORLEANS, INC.
                     STATEMENTS OF RETAINED EARNINGS

                                                   For the Years Ended December 31,
                                                    2002        2001        2000
                                                           (In Thousands)

Retained Earnings, January 1                        $60,619    $64,579     $58,526

  Add:
    Net income (loss)                                  (230)    (2,195)     16,518

  Deduct:
    Dividends declared:
      Preferred stock                                   965        965         965
      Common stock                                      800        800       9,500
                                                    -------    -------     -------
        Total                                         1,765      1,765      10,465
                                                    -------    -------     -------
Retained Earnings, December 31                      $58,624    $60,619     $64,579
                                                    =======    =======     =======

See Notes to Respective Financial Statements.

ENTERGY NEW ORLEANS, INC.

SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON

	2002	2001	2000	1999	1998
	(In Thousands)
Operating revenues	$ 507,874	$ 630,850	$ 640,290	$ 507,788	$ 513,750
Net income (loss)	$ (230)	$ (2,195)	$ 16,518	$ 18,961	$ 16,137
Total assets	$ 583,244	$ 566,037	$ 559,231	$ 485,746	$ 471,904
Long-term obligations (1)	$ 229,191	$ 229,097	$ 199,031	$ 169,083	$ 169,018

(1) Includes long-term debt (excluding currently maturing debt).

SYSTEM ENERGY RESOURCES, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

                System Energy's principal asset consists of a 90% ownership and leasehold interest in Grand Gulf 1. The capacity and energy from its 90% interest is sold under the Unit Power Sales Agreement to its only four customers, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. System Energy's operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% interest in Grand Gulf 1 pursuant to the Unit Power Sales Agreement. Payments under the Unit Power Sales Agreement are System Energy's only source of operating revenues.

Results of Operations

Operating Income

2002 Compared to 2001

                Operating income decreased by $21.3 million in 2002 primarily due to the following drivers:

• increased other operation and maintenance expenses of $12.8 million, which is explained below; and
• the effect in 2001 of the final resolution of System Energy's 1995 rate proceeding, as discussed below.

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

• an increase of $4.2 million in benefit costs;
• an increase of $3.3 million primarily in outside services employed; and
• an increase in insurance costs of $2.0 million primarily due to lower nuclear insurance refunds.

2001 Compared to 2000

                Operating income was relatively flat in 2001 compared to 2000. The issuance of the final order related to System Energy's 1995 rate proceeding resulted in decreased operating revenues due to an increase in the provision for rate refund. Decreased decommissioning expenses and depreciation expenses, also resulting from the final order, partially offset the decreased revenues.

Other Impacts on Earnings

2002 Compared to 2001

                Other income and interest charges increased earnings by $40.7 million primarily due to:

• decreased other interest charges of $66.4 million primarily due to interest recorded in 2001 on System Energy's reserve for rate refund. The refund was made in December 2001;
• decreased interest income of $10.6 million due to interest recognized in 2001 on decommissioning trust funds resulting from the effects of the final FERC order addressing System Energy's rate proceeding combined with a decrease of $13.1 million in interest earned on System Energy's investments in the money pool due to lower advances to the money pool in 2002 compared to 2001. The money pool is discussed in Note 4 to the domestic utility companies and System Energy financial statements; and
• increased interest on long-term debt of $5.1 million primarily due to an increase in interest expense of $13.8 million associated with the sale-leaseback of Grand Gulf 1, partially offset by a decrease in interest expense of $8.0 million due to the retirement of $135 million of first mortgage bonds in August 2001.

2001 Compared to 2000

                Other income and interest charges decreased earnings by $14.6 million primarily due to:

• decreased interest on long-term debt of $18.9 million primarily due to a decrease of $9.0 million in interest expense associated with the sale-leaseback of Grand Gulf 1 combined with a decrease in interest expense of $7.0 million due to the retirement of $135 million of First Mortgage Bonds in August 2001;
• increased interest income of $10.3 million resulting from the final FERC order addressing System Energy's rate proceeding; and
• increased other interest charges of $38.4 million resulting from the final FERC order addressing System Energy's rate proceeding.

Income Taxes

               The effective income tax rates for 2002, 2001, and 2000 were 42.4%, 27.3%, and 46.4%, 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	$49,579	$ 202,218	$ 35,152
Cash flow provided by (used in):
Operating activities	225,639	165,895	395,580
Investing activities	(28,873)	(47,634)	(58,767)
Financing activities	(133,186)	(270,900)	(169,747)
Net increase (decrease) in cash and cash equivalents	63,580	(152,639)	167,066
Cash and cash equivalents at end of period	$113,159	$ 49,579	$ 202,218

Operating Activities

                Cash flow from operations increased in 2002 and decreased in 2001 primarily due to the effects in 2001 of the final resolution of the System Energy rate proceeding.

                System Energy's receivables from the money pool were as follows as of December 31 for each of the following years:

2002	2001	2000	1999
	(In Thousands)
$7,046	$13,853	$155,301	$234,222

Money pool activity increased System Energy's operating cash flows by $6.8 million, $141.4 million, and $78.9 million in 2002, 2001, and 2000, respectively, because of decreases in cash loaned to the money pool. 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 $22.4 million of other temporary investments that had been made in 2001.

Financing Activities

                The decrease in net cash used in financing activities in 2002 was primarily due to the retirement of $135.0 million of first mortgage bonds in 2001. There was no net reduction of first mortgage bonds in 2002.

                The increase in net cash used in financing activities in 2001 was primarily due to:

• the net retirement of an additional $60 million of long-term debt in 2001;
• an increase in common stock dividends paid of $27.3 million; and
• an increase in the principal payment made on the sale-leaseback of $13.9 million.

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

Uses of Capital

               System Energy requires capital resources for:

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

                Following are the amounts of System Energy's 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	$13	$15	$19	N/A	N/A
Long-term debt maturities	$11	$6	$25	$126	$732
Nuclear fuel lease obligations (1)	$25	$54	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.

                The planned capital investment estimate for System Energy reflects capital required to support the existing business of System Energy. 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, System Energy dividends its earnings to Entergy Corporation at a percentage determined monthly. Currently, all of System Energy's retained earnings are available for distribution.

                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.

Sources of Capital

               System Energy's 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 System Energy issued $70 million of long-term debt. The net proceeds were used to meet an October 2002 debt maturity. All debt and common stock issuances by System Energy require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements.

                Short-term borrowings by System Energy, including borrowings under the money pool, are limited to an amount authorized by the SEC, $140 million. Under the SEC order authorizing the short-term borrowing limits, System Energy cannot incur new short-term indebtedness if its common equity would comprise less than 30% of its capital. In addition this order restricts System Energy from publicly issuing new long-term debt unless that debt will be rated as investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of System Energy's short-term borrowing limits.

Significant Factors and Known Trends

Market and Credit Risks

               System Energy 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

                System Energy's nuclear decommissioning trust funds expose it to fluctuations in equity prices and interest rates. The NRC requires System Energy to maintain trusts to fund the costs of decommissioning Grand Gulf 1. 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 Grand Gulf 1 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.

Nuclear Matters

               System Energy owns and operates, through an affiliate, Grand Gulf 1. System Energy 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 Grand Gulf 1, System Energy may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.

 Litigation Risks

               The states in which System Energy's customers operate 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. System Energy uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment poses a significant business risk.

Environmental Risks

               System Energy'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 System Energy 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 System Energy'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 System Energy's financial statements.

Nuclear Decommissioning Costs

               Regulations require that Grand Gulf 1 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. System Energy 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 System Energy's most recent study and the obligations recorded by System Energy related to decommissioning. The following key assumptions have a significant effect on these estimates:

• Cost Escalation Factors - System Energy's decommissioning studies include an assumption that decommissioning costs will escalate over present cost levels by an annual factor averaging approximately 5.5%. 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. System Energy's decommissioning studies for Grand Gulf 1 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). System Energy's decommissioning studies include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors.

• Technology and Regulation - To date, there is limited practical experience in the United States with actual decommissioning of large nuclear facilities. As experience is gained and technology changes, cost estimates could also change. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant impact on cost estimates. The impact of these potential changes is not presently determinable. Entergy Arkansas' decommissioning cost studies assume current technologies and regulations.

                System Energy collects substantially all of the projected costs of decommissioning Grand Gulf 1 through rates charged to customers. 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 estimated to be sufficient to fund the future decommissioning costs. Accordingly, decommissioning costs have almost no impact on System Energy's 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.

                The obligation recorded by System Energy for decommissioning is classified as a deferred credit in the line item entitled "Decommissioning." The amount recorded for this obligation is comprised of collections from customers and earnings on the trust funds. The classification and recording of this obligation will change with the implementation of SFAS 143.

SFAS 143

               System Energy implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs are System Energy's only asset retirement obligations, and the measurement and recording of System Energy'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 of System Energy to increase significantly, as System Energy 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. System Energy's decommissioning studies to date have been based on System Energy 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 System Energy will be recorded as a regulatory asset or liability, with no resulting impact on System Energy's net income. Assets and liabilities are expected to increase by approximately $140 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%)	$ 170	$2,692
Rate of return on plan assets	(0.25%)	$ 104	-
Rate of increase in compensation	0.25%	$ 100	$848

               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%	$ 131	$ 663
Discount rate	(0.25%)	$ 93	$ 739

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 System Energy in 2002 was $2.3 million. Taking into account asset performance and the changes made in the actuarial assumptions, System Energy does not anticipate 2003 pension cost to be materially different from 2002. System Energy 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, System Energy's accumulated benefit obligation at December 31, 2002 exceeded plan assets. As a result, System Energy was required to recognize an additional minimum liability of $0.4 million as prescribed by SFAS 87. System Energy recorded an intangible asset for the $0.4 million of unrecognized prior service cost. Net income for 2002 was not impacted.

                Total postretirement health care and life insurance benefit costs for System Energy in 2002 were $1.7 million. Because of a number of factors, including the increased health care cost trend rate, System Energy expects 2003 costs to approximate $2.7 million.

INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Shareholder of
System Energy Resources, Inc.:

We have audited the accompanying balance sheets of System Energy Resources, Inc. as of December 31, 2002 and 2001, and the related statements of income, retained earnings, and cash flows (pages 243 through 248 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 System Energy Resources, 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

                        SYSTEM ENERGY RESOURCES, INC.
                               INCOME STATEMENTS

                                                               For the Years Ended December 31,
                                                                2002         2001        2000
                                                                        (In Thousands)
                  OPERATING REVENUES
Domestic electric                                              $602,486     $535,027    $656,749
                                                               --------     --------    --------
                  OPERATING EXPENSES
Operation and Maintenance:
   Fuel, fuel-related expenses, and
     gas purchased for resale                                    36,456       37,010      42,369
   Nuclear refueling outage expenses                             10,723       13,275      14,423
   Other operation and maintenance                               98,264       85,491      88,257
Decommissioning                                                  16,055      (13,493)     18,944
Taxes other than income taxes                                    25,992       26,134      30,517
Depreciation and amortization                                   112,093       53,414     127,904
Other regulatory charges - net                                   53,769       62,742      63,590
                                                               --------     --------    --------
TOTAL                                                           353,352      264,573     386,004
                                                               --------     --------    --------

OPERATING INCOME                                                249,134      270,454     270,745
                                                               --------     --------    --------

                     OTHER INCOME
Allowance for equity funds used during construction               2,449        1,769       1,482
Interest and dividend income                                      2,857       26,271      20,528
Miscellaneous - net                                                 826       (1,190)        (82)
                                                               --------     --------    --------
TOTAL                                                             6,132       26,850      21,928
                                                               --------     --------    --------

              INTEREST AND OTHER CHARGES
Interest on long-term debt                                       73,891       68,833      87,689
Other interest - net                                              2,748       69,185      30,830
Allowance for borrowed funds used during construction              (902)        (830)       (854)
                                                               --------     --------    --------
TOTAL                                                            75,737      137,188     117,665
                                                               --------     --------    --------

INCOME BEFORE INCOME TAXES                                      179,529      160,116     175,008

Income taxes                                                     76,177       43,761      81,263
                                                               --------     --------    --------

NET INCOME                                                     $103,352     $116,355     $93,745
                                                               ========     ========    ========

See Notes to Respective Financial Statements.

(Page left blank intentionally)

                         SYSTEM ENERGY RESOURCES, INC.
                           STATEMENTS OF CASH FLOWS

                                                                For the Years Ended December 31,
                                                                 2002         2001        2000
                                                                         (In Thousands)
                 OPERATING ACTIVITIES
Net income                                                     $103,352     $116,355     $93,745
Noncash items included in net income:
  Reserve for regulatory adjustments                                  -     (322,368)     54,598
  Other regulatory charges - net                                 53,769       62,742      63,590
  Depreciation, amortization, and decommissioning               128,148       39,921     146,848
  Deferred income taxes and investment tax credits              (38,246)     106,764     (71,212)
  Allowance for equity funds used during construction            (2,449)      (1,769)     (1,482)
Changes in working capital:
  Receivables                                                     5,719      142,797      87,212
  Accounts payable                                               14,767       (9,587)     (7,401)
  Taxes accrued                                                 (44,122)      43,992      13,147
  Interest accrued                                               (4,568)       3,088       4,008
  Other working capital accounts                                 (6,108)        (664)     20,754
Provision for estimated losses and reserves                         163           16      (1,328)
Changes in other regulatory assets                               52,448       38,732      58,592
Other                                                           (37,234)     (54,124)    (65,491)
                                                               --------     --------    --------
Net cash flow provided by operating activities                  225,639      165,895     395,580
                                                               --------     --------    --------

                 INVESTING ACTIVITIES
Construction expenditures                                       (40,306)     (40,144)    (36,555)
Allowance for equity funds used during construction               2,449        1,769       1,482
Nuclear fuel purchases                                          (43,140)     (37,639)          -
Proceeds from sale/leaseback of nuclear fuel                     43,140       37,639           -
Decommissioning trust contributions and realized
    change in trust assets                                      (13,370)     (16,147)    (23,694)
Changes in other temporary investments - net                     22,354      (22,354)          -
Other                                                                 -       29,242           -
                                                               --------     --------    --------
Net cash flow used in investing activities                      (28,873)     (47,634)    (58,767)
                                                               --------     --------    --------

                 FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt                     69,505            -           -
Retirement of long-term debt                                   (100,891)    (151,800)    (77,947)
Dividends paid:
  Common stock                                                 (101,800)    (119,100)    (91,800)
                                                               --------     --------    --------
Net cash flow used in financing activities                     (133,186)    (270,900)   (169,747)
                                                               --------     --------    --------

Net increase (decrease) in cash and cash equivalents             63,580     (152,639)    167,066

Cash and cash equivalents at beginning of period                 49,579      202,218      35,152
                                                               --------     --------    --------

Cash and cash equivalents at end of period                     $113,159      $49,579    $202,218
                                                               ========     ========    ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid/(received) during the period for:
  Interest - net of amount capitalized                          $77,190     $130,596    $109,046
  Income taxes                                                 $156,957    ($107,831)   $143,040
 Noncash investing and financing activities:
  Change in unrealized depreciation of
   decommissioning trust assets                                ($12,931)     ($5,931)    ($1,506)

See Notes to Respective Financial Statements.

                        SYSTEM ENERGY RESOURCES, INC.
                               BALANCE SHEETS
                                   ASSETS


                                                                        December 31,
                                                                      2002        2001
                                                                       (In Thousands)
                    CURRENT ASSETS
Cash and cash equivalents:
  Cash                                                                $2,282          $15
  Temporary cash investments - at cost,
    which approximates market
      Other                                                          110,877       49,564
                                                                  ----------   ----------
        Total cash and cash equivalents                              113,159       49,579
                                                                  ----------   ----------
Other temporary investments                                                -       22,354
Accounts receivable:
  Associated companies                                                64,852       70,755
  Other                                                                1,377        1,193
                                                                  ----------   ----------
    Total accounts receivable                                         66,229       71,948
                                                                  ----------   ----------
Materials and supplies - at average cost                              51,492       51,665
Deferred nuclear refueling outage costs                               15,666        8,728
Prepayments and other                                                  1,319        1,631
                                                                  ----------   ----------
TOTAL                                                                247,865      205,905
                                                                  ----------   ----------

            OTHER PROPERTY AND INVESTMENTS
Decommissioning trust funds                                          138,985      138,546
                                                                  ----------   ----------

                     UTILITY PLANT
Electric                                                           3,131,945    3,098,446
Property under capital lease                                         455,229      450,014
Construction work in progress                                         28,128       36,868
Nuclear fuel under capital lease                                      78,991       61,905
                                                                  ----------   ----------
TOTAL UTILITY PLANT                                                3,694,293    3,647,233
Less - accumulated depreciation and amortization                   1,514,921    1,416,337
                                                                  ----------   ----------
UTILITY PLANT - NET                                                2,179,372    2,230,896
                                                                  ----------   ----------

           DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
  SFAS 109 regulatory asset - net                                    134,895      173,470
  Unamortized loss on reacquired debt                                 45,026       48,381
  Other regulatory assets                                            144,076      157,949
Other                                                                 11,191        8,894
                                                                  ----------   ----------
TOTAL                                                                335,188      388,694
                                                                  ----------   ----------

TOTAL ASSETS                                                      $2,901,410   $2,964,041
                                                                  ==========   ==========
See Notes to Respective Financial Statements.

                         SYSTEM ENERGY RESOURCES, INC.
                                 BALANCE SHEETS
                     LIABILITIES AND SHAREHOLDER'S EQUITY


                                                                        December 31,
                                                                     2002        2001
                                                                       (In Thousands)
                  CURRENT LIABILITIES
Currently maturing long-term debt                                    $11,375     $100,891
Accounts payable:
  Associated companies                                                 4,851        2,404
  Other                                                               26,636       14,316
Taxes accrued                                                         68,400      112,522
Accumulated deferred income taxes                                      5,322        2,360
Interest accrued                                                      42,527       47,095
Obligations under capital leases                                      24,954       26,503
Other                                                                  1,928        1,583
                                                                  ----------   ----------
TOTAL                                                                185,993      307,674
                                                                  ----------   ----------

        DEFERRED CREDITS AND OTHER LIABILITIES
Accumulated deferred income taxes and taxes accrued                  439,540      498,404
Accumulated deferred investment tax credits                           82,564       86,040
Obligations under capital leases                                      54,036       35,401
Other regulatory liabilities                                         172,111      135,878
Decommissioning                                                      153,473      140,103
Accumulated provisions                                                   868          705
Other                                                                 31,927       39,117
                                                                  ----------   ----------
TOTAL                                                                934,519      935,648
                                                                  ----------   ----------

Long-term debt                                                       888,665      830,038

                 SHAREHOLDER'S EQUITY
Common stock, no par value, authorized 1,000,000 shares;
issued and outstanding 789,350 shares in 2002 and 2001               789,350      789,350
Retained earnings                                                    102,883      101,331
                                                                  ----------   ----------
TOTAL                                                                892,233      890,681
                                                                  ----------   ----------

Commitments and Contingencies

             TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY           $2,901,410   $2,964,041
                                                                  ==========   ==========
See Notes to Respective Financial Statements.

                     SYSTEM ENERGY RESOURCES, INC.
                    STATEMENTS OF RETAINED EARNINGS

                                                   For the Years Ended December 31,
                                                    2002        2001        2000
                                                           (In Thousands)
Retained Earnings, January 1                       $101,331   $104,076    $102,131

  Add:
    Net income                                      103,352    116,355      93,745

  Deduct:
    Dividends declared                              101,800    119,100      91,800
                                                   --------   --------    --------
Retained Earnings, December 31                     $102,883   $101,331    $104,076
                                                   ========   ========    ========

See Notes to Respective Financial Statements.

SYSTEM ENERGY RESOURCES, INC.

SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON

	2002	2001	2000	1999	1998
	(Dollars In Thousands)
Operating revenues	$ 602,486	$ 535,027	$ 656,749	$ 620,032	$ 602,373
Net income	$ 103,352	$ 116,355	$ 93,745	$ 82,372	$ 106,476
Total assets	$ 2,901,410	$ 2,964,041	$ 3,274,550	$ 3,369,048	$ 3,431,205
Long-term obligations (1)	$ 942,701	$ 865,439	$ 947,991	$ 1,122,178	$ 1,182,616
Electric energy sales (GWh)	9,053	8,921	9,621	7,567	8,259

(1) Includes long-term debt (excluding current maturities) and noncurrent capital lease obligations.

ENTERGY ARKANSAS, ENTERGY GULF STATES, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND SYSTEM ENERGY

NOTES TO RESPECTIVE FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

               The accompanying separate financial statements of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy are included in this document and result from these companies having registered securities with the SEC. These companies 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 the domestic utility companies' and System Energy's 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

               Entergy Arkansas, Entergy Louisiana, and Entergy Mississippi generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, and Mississippi, respectively. Entergy Gulf States generates, transmits, and distributes electric power primarily to retail customers in Texas and Louisiana. Entergy Gulf States also distributes gas to retail customers in and around Baton Rouge, Louisiana. Entergy New Orleans sells both electric power and gas to retail customers in the City of New Orleans, except for Algiers, where Entergy Louisiana is the electric power supplier.

               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 domestic utility companies and System Energy 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. 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 company 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 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 are shown below:

	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System  Energy(1)
2002	3.2%	2.4%	3.0%	2.5%	3.1%	2.8%
2001	3.1%	2.5%	2.9%	2.4%	3.0%	2.8%
2000	3.2%	2.4%	3.0%	2.5%	3.1%	3.3%

1. Per a FERC order in 2001, the depreciation rate for System Energy was changed from 3.3% to 2.8%, retroactive to December 1995. The retroactive effect of the change is reflected in the 2001 financial statements. Refer to Note 2 to the domestic utility companies and System Energy financial statements for further details of the FERC order in the System Energy rate proceeding.

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 MW Capability (1)	Ownership	Investment	Accumulated Depreciation
Entergy Arkansas -
Independence	Unit 1	Coal	815	31.50%	$117	$66
	Common Facilities	Coal		15.75%	31	16
White Bluff	Units 1 and 2	Coal	1,620	57.00%	418	244
Entergy Gulf States -
Roy S. Nelson	Unit 6	Coal	550	70.00%	404	227
Big Cajun 2	Unit 3	Coal	575	42.00%	229	119
Entergy Mississippi -   Independence	Units 1 and 2 and Common Facilities	Coal	1,657	25.00%	228	107
System Energy Grand Gulf	Unit 1	Nuclear	1,282	90.00%(2)	3,587	1,515

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

(2) Includes an 11.5% leasehold interest held by System Energy. System Energy's Grand Gulf 1 lease obligations are discussed in Note 10 to the domestic utility companies and System Energy financial statements.

Nuclear Refueling Outage Costs

                The domestic utility companies record 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, the 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. 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 law 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.

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 re gulatory 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 domestic utility companies and System Energy financial statements for discussion of transition to competition activity in the retail regulatory jurisdictions served by the domestic utility companies. Only Texas currently has an 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 purchased with an original maturity of three months or less 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 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 the following (in millions):

	2002	2001
Entergy Arkansas	$35.3	$69.8
Entergy Gulf States	$1.4	$18.5
Entergy Louisiana	($0.3 )	$8.2
System Energy	($14.5 )	($1.6 )

                In accordance with the regulatory treatment for decommissioning trust funds, Entergy Arkansas, Entergy Gulf States (for the regulated portion of River Bend), and Entergy Louisiana 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.

Derivatives and Hedging

                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.

Fair Values

                The estimated fair values of the domestic utility companies' and System Energy's financial instruments and derivatives are determined using bid prices and market quotes. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that the domestic utility companies and System Energy could realize in a current market exchange. Gains or losses realized on financial instruments held by regulated businesses may be reflected in future rates and therefore do not accrue to the benefit or detriment of stockholders.

                The domestic utility companies and System Energy consider the carrying amounts of most of their 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 domestic utility companies and System Energy financial statements.

Impairment of Long-Lived Assets

                The domestic utility companies and System Energy periodically review their long-lived assets whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the 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.

River Bend AFUDC

                The River Bend AFUDC gross-up represents the incremental difference imputed by the LPSC between the AFUDC actually recorded by Gulf States Utilities 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.

Entergy Gulf States' Deregulated Operations

                Entergy Gulf States does not apply regulatory accounting principles to its wholesale jurisdiction, Louisiana retail deregulated portion of River Bend, and the 30% interest in River Bend formerly owned by Cajun. The Louisiana retail deregulated portion of River Bend is operated under a deregulated asset plan representing a portion (approximately 16%) of River Bend plant costs, generation, revenues, and expenses established under a 1992 LPSC order. The plan allows Entergy Gulf States to sell the electricity from the deregulated assets to Louisiana retail customers at 4.6 cents per kWh or off-system at higher prices, with certain provisions for sharing such incremental revenue above 4.6 cents per kWh between ratepayers and shareholders.

                The results of these deregulated operations before interest charges for the years ended December 31, 2002, 2001, and 2000 are as follows (in thousands):

               The net investment associated with these deregulated operations as of December 31, 2002 and 2001 was approximately $805 million and $822 million, respectively.

New Accounting Pronouncement

                SFAS 143, which must be implemented by January 1, 2003, requires the recording of liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of those assets, which primarily consists of decommissioning liabilities for Entergy. 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 utilit ies 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 $25 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 also believes that significant issues remain to be addressed by Texas regulators, and the enacted law 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.

Arkansas

(Entergy Arkansas)

                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.

Texas

(Entergy Gulf States)

                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 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.

Louisiana

(Entergy Gulf States and Entergy Louisiana)

                In March 1999, the LPSC deferred making a decision on whether competition in the electric utility industry is in the public interest. However, the LPSC directed the LPSC staff, outside consultants, and counsel to work together to analyze and resolve issues related to competition and to recommend a plan for consideration by the LPSC. In July 2001, the LPSC staff submitted a final response to the LPSC. In its report the LPSC staff concluded that retail competition is not in the public interest at this time for any customer class. Nevertheless, the LPSC staff recommended that retail open access be made available for certain large industrial customers as early as January 2003. An eligible customer choosing to go to competition would be required to provide its utility with a minimum of six months notice prior to the date of retail open access. The LPSC staff report also recommended that all customers who do not currently co- or self-generate, or have co- or self-generation under construction as of a date to be specified by the LPSC, remain liable for their share of stranded costs. During its October 2001 meeting, the LPSC adopted dates by which a total of 800 MW of co- or self-generation could be developed in Louisiana without being affected by stranded costs. During its November 2001 meeting, the LPSC decided not to adopt a plan for retail open access for any customers at this time, but to have collaborative group meetings concerning open access from time to time, and to have the LPSC staff monitor developments in neighboring states and to report to the LPSC regarding the progress of retail access developments in those states.

Mississippi

(Entergy Mississippi)

                In May 2000, after two years of studies and hearings, the MPSC announced that it was suspending its docket studying the opening of the state's retail electricity markets to competition. The MPSC based its decision on its finding that competition could raise the electric rates paid by residential and small commercial customers. The final decision regarding the introduction of retail competition ultimately lies with the Mississippi Legislature, which is holding its 2003 session from January through March. Management cannot predict when, or if, Mississippi will deregulate its retail electricity market.

New Orleans

(Entergy New Orleans)

                Entergy New Orleans filed an electric transition to competition plan in September 1997. No procedural schedule has been established for consideration of that plan by the Council.

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 tables below provide detail of "Other regulatory assets" included on the balance sheets of the domestic utility companies and System Energy 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, as to when and if Entergy Gulf States will initiate a base rate proceeding before the PUCT. 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 (Entergy Arkansas)

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.

Decommissioning Cost Recovery

               The APSC ordered Entergy Arkansas to cease collection of funds to decommission ANO 1 and 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. An updated decommissioning cost study for ANO 1 and 2 will be filed with the APSC in March 2003.

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

Retail Rates

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

Recovery of River Bend Costs

                In March 1998, the PUCT disallowed recovery of $1.4 billion of company-wide abeyed River Bend plant costs, which have been held in abeyance since 1988. Entergy Gulf States appealed the PUCT's decision on this matter to the Travis County District Court in Texas. A 1999 settlement agreement limits potential recovery of the remaining plant asset to $115 million as of January 1, 2002, less depreciation after that date. Entergy Gulf States accordingly reduced the value of the plant asset in 1999. Entergy Gulf States has also agreed that it will not seek recovery of the abeyed plant costs through any additional charge to Texas ratepayers. In an interim order approving this agreement, however, the PUCT recognized that any additional River Bend investment found prudent, subject to the $115 million cap, could be used as an offset against stranded benefits, should legislation be passed requiring Entergy Gulf States to return stranded benefits to retail customers.

                In April 2002, the Travis County District Court issued an order affirming the PUCT's order on remand disallowing recovery of the abeyed plant costs. Entergy Gulf States 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 an 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 supporte d 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 (Entergy Mississippi)

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 forEntergy Mississippi's formula rate plan. Under the provisions of the order, Entergy Mississippiwill make its next formula rate plan filing during March 2004.

Grand Gulf Accelerated Recovery Tariff (GGART)

                In September 1998, FERC approved the GGART for Entergy Mississippi's allocable portion of Grand Gulf, which was filed with FERC in August 1998. The GGART provides for the acceleration of Entergy Mississippi's Grand Gulf purchased power obligation in an amount totaling $221.3 million over the period October 1, 1998 through June 30, 2004.

Filings with the Council (Entergy New Orleans)

Rate Proceedings

                In May 2002, Entergy New Orleans filed a cost of service study and revenue requirement filing with the City Council for the 2001 test year. The filing indicated that a revenue deficiency 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 the City Council's 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 inter est 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 wh at 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.

Purchased Power for Summer 2000, 2001, and 2002 (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans)

                The domestic utility companies requested that the APSC, the LPSC, the MPSC, and the City Council approve the sale of power by Entergy Gulf States from its unregulated 30% interest in River Bend formerly owned by Cajun to the domestic utility companies during the summer of 2000. These applications were approved subject to subsequent prudence reviews. In addition, Entergy Gulf States and Entergy Louisiana filed an application with the LPSC for authorization to purchase capacity and electric power from third parties for the summer of 2000, and filed similar applications for the summers of 2001 and 2002. The LPSC approved these applications, with reservation of its rights to review the prudence of the purchases and the appropriate categorization of the costs as either capacity or energy charges for purposes of recovery.

                The LPSC reviewed the 2000 purchases and found that Entergy Louisiana's and Entergy Gulf States' costs were prudently incurred, but decided that approximately 34% of the costs should be categorized as capacity charges, and therefore should be recovered through base rates and not through the fuel adjustment clause. In November 2000, the LPSC ordered refunds of $11.1 million for Entergy Louisiana and $3.6 million for Entergy Gulf States, for which adequate provisions previously had been made. In May 2001, the LPSC determined that 24% of Entergy Louisiana's and Entergy Gulf States' costs relating to summer 2001 purchases should be categorized as capacity charges. Subsequently, the LPSC raised certain prudence issues related to the 2001 purchases. The prudence issues involve approximately $6 million of Entergy Louisiana costs and approximately $5 million of Entergy Gulf States costs. The LPSC has questioned in the prudence review the Entergy system's contract mix and raised issues relating to potential upra tes at nuclear facilities. Hearings on those issues were conducted in May 2002 and briefs have been filed by the parties. Those costs that are categorized as capacity charges will be included in the cost of service used to determine the base rates of Entergy Louisiana and Entergy Gulf States. In 2001, these companies recorded a regulatory asset for the capacity charges incurred in both 2000 and 2001. The regulatory assets were not allowed to be included as a separate component of rate base, but are being amortized as a component of cost of service as discussed above. The capacity charges for 2000 were amortized through May 2002 for Entergy Gulf States and through July 2002 for Entergy Louisiana. The capacity charges for 2001 are being amortized over a twelve-month period, which began in June 2002 for Entergy Gulf States and in August 2002 for Entergy Louisiana.

                In March 2002, Entergy Louisiana and Entergy Gulf States filed an application with the LPSC for the approval of capacity and energy purchases for the summer of 2002 similar to the applications filed for the summers of 2000 and 2001. Entergy Louisiana, Entergy Gulf States, and the LPSC staff reached a settlement in which those parties agreed that 14% of Entergy Louisiana's and Entergy Gulf States' costs relating to summer 2002 purchases should be categorized as capacity charges. The LPSC approved the settlement at its July 2002 public meeting. Prudence issues relating to summer 2002 purchases were resolved in a subsequent settlement approved by the LPSC at its September 2002 open session. In the event that decisions relating to potential uprates at nuclear facilities are found to have been imprudent in the summer 2001 case, this settlement reserves the LPSC's right to propose in a future case disa llowances relating to the effect that such uprates would have had on the summer 2002 firm energy contracts, while Entergy Gulf States and Entergy Louisiana reserve their right to oppose any such proposal. No refunds were ordered, although with respect to the capacity costs to be incurred pursuant to a particular purchased power contract, Entergy Louisiana agreed in the settlement to forgo recovery of approximately $0.8 million in 2002, $1.3 million in 2003, and $1.0 million in 2004, and Entergy Gulf States agreed to forgo recovery of approximately $0.5 million in 2002, $0.9 million in 2003, and $0.7 million in 2004. All other purchases were found to be prudent. Issues relating to the reasonableness of the long-term planning process were moved into a separate sub-docket. Issues relating to the need for and potential scope of that proceeding are currently under review.

Grand Gulf 1 Deferrals and Retained Shares

(Entergy Arkansas)

                Under the settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf 1-related costs and recovers the remaining 78% of its share in rates. In the event that 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 its retained share.

(Entergy Louisiana)

                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. Entergy Louisiana retains and does not recover from retail ratepayers, 18% of its 14% share of the costs of Grand Gulf 1 capacity and energy and recovers the remaining 82% of its share in rates. 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. Non-fuel operation and maintenance costs for Grand Gulf 1 are recovered through Entergy Louisiana's base rates. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC's approval.

(Entergy New Orleans)

                Under 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. As of December 31, 2001, the entire deferred amount has been recovered through rates.

System Energy's 1995 Rate Proceeding (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

                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 (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

                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):

1. Entergy Louisiana's actual cash taxes paid/(refunded) were ($781,540) in 2002, $111,507 in 2001, and $105,354 in 2000. Entergy Louisiana's mark to market tax accounting election has significantly reduced taxes paid in 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 long-term accrued tax liabilities as of December 31, 2002 and 2001 are as follows (in thousands):

NOTE 4. LINES OF CREDIT AND RELATED SHORT-TERM BORROWINGS (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

                The short-term borrowings of the domestic utility companies and System Energy 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, the domestic utility companies and System Energy are authorized to borrow from the Entergy System Money Pool (money pool). The money pool is an inter-company borrowing arrangement designed to reduce the domestic utility companies' 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, there were no borrowings from the money pool or outstanding from external sources for the domestic utility companies and System Energy. The following are the SEC-authorized limits for short-term borrowings for the domestic utility companies and System Energy as o f December 31, 2002:

	Authorized (In Millions)
Entergy Arkansas Entergy Gulf States Entergy Louisiana Entergy Mississippi Entergy New Orleans System Energy	$ 235 340 225 160 100 140

               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, PREFERENCE, AND COMMON STOCK (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans)

Preferred Stock

            The number of shares authorized and outstanding, and dollar value of preferred stock for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans as of December 31, 2002 and 2001 are presented below. Only the two Entergy Gulf States series "with sinking fund" contain mandatory redemption requirements. All other series are redeemable at Entergy's option at the call prices presented. Dividends paid on all of Entergy's preferred stock series are eligible for the dividends received deduction.The dividends received deduction is limited by Internal Revenue Code section 244 for the following preferred stock series: Entergy Arkansas 4.72%, Entergy Gulf States 4.40%, Entergy Louisiana 4.96%, Entergy Mississippi 4.56%, and Entergy New Orleans 4.75%.

1. The total dollar value represents the liquidation value of $25 per share.
2. Represents weighted-average annualized rates for 2002.
3. Fair values were determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. There is an additional disclosure of fair value of financial instruments in Note 15 to the domestic utility companies and System Energy financial statements.

                Changes in the preferred stock and preference stock of Entergy Gulf States and Entergy Louisiana during the last three years were:

	Number of Shares
	2002	2001	2000
Preference stock retirements
Entergy Gulf States	-	-	(6,000,000)
Preferred stock retirements
Entergy Gulf States
$100 par value	(18,579)	(49,237)	(76,585)
Entergy Louisiana
$100 par value	-	(350,000)	-

               Entergy Gulf States has annual sinking fund requirements of $3.45 million through 2007 for its preferred stock outstanding. Entergy Gulf States has the annual non-cumulative option to redeem, at par, additional amounts of certain series of its outstanding preferred stock.

Common Stock

                In December 2002, Entergy Louisiana repurchased 18,202,573 shares of its no par value common stock from Entergy Corporation for $120 million.

NOTE 6. COMPANY-OBLIGATED REDEEMABLE PREFERRED SECURITIES (Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana)

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

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 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.
4. 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.
5. 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.
6. On June 1, 2002, Entergy Louisiana remarketed $55 million St. Charles Par ish Pollution Control Revenue Refunding Bonds due 2030, resetting the interest rate to 4.9% through May 2005.
7. 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.

                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:

	Entergy Arkansas	Entergy Gulf  States (a)	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
2003	$255,000	$293,000	$260,950	$255,000	-	-
2004	-	$654,000	-	$150,000	$30,000	-
2005	$262,000	$98,000	$55,000	-	$30,000	-
2006	-	-	-	-	$40,000	-
2007	$100,000	$200,000	-	-	-	$70,000

(a) 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.

                On January 31, 2003, Entergy Mississippi issued $100 million of 5.15% Series First Mortgage Bonds due 2013. The net proceeds will be used to redeem, at maturity, a portion of the $120 million 7.75% Series First Mortgage Bonds due February 15, 2003, and to redeem prior to maturity the $65 million 6.625% Series First Mortgage Bonds due November 1, 2003 and the $25 million 8.25% Series First Mortgage Bonds due July 1, 2004.

NOTE 8. DIVIDEND RESTRICTIONS (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, System Energy)

                Provisions within the Articles of Incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of the domestic utility companies and System Energy restrict the payment of cash dividends or other distributions on their common and preferred stock. Additionally, PUHCA prohibits Entergy Corporation's subsidiaries from making loans or advances to Entergy Corporation. 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.

NOTE 9. COMMITMENTS AND CONTINGENCIES

                The domestic utility companies and System Energy are involved in a number of legal, tax, and regulatory proceedings before various courts, regulatory commissions, and governmental agencies in the ordinary course of their business. While management is unable to predict the outcome of such proceedings, it is not expected that the ultimate resolution of these matters will have a material adverse effect on Entergy Arkansas', Entergy Gulf States', Entergy Louisiana's, Entergy Mississippi's, Entergy New Orleans', or System Energy's results of operations, cash flows, or financial condition.

Capital Requirements and Financing (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

                The domestic utility companies and System Energy plan to spend approximately $2.8 billion on construction and other capital investments during 2003-2005. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and the ability to access capital. The domestic utility companies' and System Energy's estimated construction and other capital expenditures by year for 2003-2005 are as follows:

               On July 25, 2002, the Board authorized Entergy Arkansas and Entergy Operations to replace the ANO 1 steam generator and reactor vessel closure head. Management estimates the cost of the fabrication and replacement to be approximately $235 million, of which approximately $135 million will be incurred through 2004. These amounts are reflected in the above table. Management expects that the replacement will occur during a planned refueling outage in 2005. Additional capital investments are possible during these years, but they will be discretionary in nature. The domestic utility companies and System Energy will focus their planned spending on projects that will support continued reliability improvements and customer growth.

                The domestic utility companies and System Energy will also require $2.3 billion during the period 2003-2005 to meet long-term debt and preferred stock maturities and cash sinking fund requirements. Long-term debt maturities as of December 31, 2002 for the domestic utility companies and System Energy for 2003 through 2005 are as follows:

Company	2003	2004	2005
Entergy Arkansas	$255 million	-	$262 million
Entergy Gulf States	$293 million	$654 million	$98 million
Entergy Louisiana	$261 million	-	$55 million
Energy Mississippi	$255 million	$150 million	-
Entergy New Orleans	-	$30 million	$30 million
System Energy	-	-	-

The domestic utility companies and System Energy plan to meet these requirements primarily with internally generated funds and cash on hand, supplemented by proceeds from the issuance of new debt and outstanding credit facilities. In the fourth quarter of 2002, the domestic utility companies, except Entergy New Orleans, issued a total of $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 companies may also continue the reacquisition or refinancing of all or a portion of certain outstanding series of preferred stock and long-term debt.

Fuel Supply Agreements

(Entergy Arkansas and Entergy Mississippi)

                Entergy Arkansas has a long-term contract for the supply of low-sulfur coal for Independence (which is also 25% owned by Entergy Mississippi). This contract, which expires in 2011, provides for approximately 90% of Independence's expected annual coal requirements. Additional requirements are satisfied by spot market purchases. Entergy Arkansas has entered into one- to three-year contracts for approximately 52% 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.

(Entergy Gulf States)

               Entergy Gulf States has a contract for a supply of low-sulfur coal for Nelson Unit 6, which should be sufficient to satisfy the fuel requirements for that unit at current consumption rates. The contract, which expires at the end of the first quarter of 2003, includes options to extend supply to 2010 if all price re-openers are accepted. If both parties cannot agree upon a price, then the contract terminates.

                Effective April 1, 2000, Louisiana Generating LLC assumed ownership of Cajun's interest in the Big Cajun generating facilities, in which Entergy Gulf States owns a 42% interest. The management of Louisiana Generating LLC has advised Entergy Gulf States that it has executed 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.

(Entergy Louisiana)

                In June 1992, Entergy Louisiana agreed to a 20-year natural gas supply contract, in which Entergy Louisiana agreed to purchase natural gas in annual amounts equal to approximately one-third of its projected annual fuel requirements for certain generating units. Annual demand charges associated with this contract are estimated to be $7.6 million. Such charges aggregate $76 million for the years 2003 through 2012.

Power Purchase Agreements

(Entergy Louisiana)

               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.

System Fuels (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

               The domestic utility companies that are owners of System Fuels have made loans to System Fuels to finance its fuel procurement, delivery, and storage activities. The following loans outstanding to System Fuels as of December 31, 2002 mature in 2008:

Owner	Ownership Percentage	Loan Outstanding at December 31, 2002
Entergy Arkansas	35%	$11.0 million
Entergy Louisiana	33%	$14.2 million
Entergy Mississippi	19%	$5.5 million
Entergy New Orleans	13%	$3.3 million

Nuclear Insurance (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

               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 Arkansas has two licensed reactors and Entergy Gulf States, Entergy Louisiana, and System Energy each have one licensed reactor. 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 the five nuclear units participates in a private insurance progr am 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.

                The domestic utility companies' and System Energy's nuclear owner/licensees 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, the domestic utility companies and System Energy were insured against such losses up to $2.3 billion for each of their nuclear units.In addition, the domestic utility companies' and System Energy's nuclear owner/licensees 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, the nuclear owner/licensees 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: Entergy Arkansas - $24.9 million; Entergy Gulf States - $18.8 million; Entergy Louisiana - $19.1 million; Entergy Mississippi - $1.4 million; Entergy New Orleans - $0.7 million; and System Energy - $16.5 million.

                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 Arkansas, Entergy Gulf States, Entergy Louisiana, System Energy)

               The nuclear owner/licensees of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy provide for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected 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 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.

                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 the U.S. Utility's facilities for storage or disposal. As a result, future expenditures will be required to increase spent fuel storage capacity at the U.S. Utility'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 storage capacity 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.

Nuclear Decommissioning Costs (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, System Energy)

               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:

               The domestic utility companies and System Energy have 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 by Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana, and are recorded as deferred credits by System Energy. 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 portion 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 has not yet been filed with FERC.

                The cumulative liabilities and decommissioning expenses recorded in 2002 by Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy were as follows:

               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.

                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 exce ption 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.

Environmental Issues (Entergy Gulf States)

               Entergy Gulf States has been designated as a PRP for the cleanup of certain hazardous waste disposal sites. Entergy Gulf States is currently negotiating with the EPA and state authorities regarding the cleanup of these sites. As of December 31, 2002, Entergy Gulf States does not expect the remaining clean-up costs to exceed its recorded liability of $12 million for the remaining sites at which the EPA has designated Entergy Gulf States as a PRP.

City Franchise Ordinances (Entergy New Orleans)

               Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to franchise ordinances. These ordinances contain a continuing option for the city to purchase Entergy New Orleans' electric and gas utility properties.

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.

Waterford 3 Lease Obligations (Entergy Louisiana)

                On September 28, 1989, Entergy Louisiana entered into three identical transactions for the sale and leaseback of undivided interests (aggregating approximately 9.3%) in Waterford 3. In July 1997, Entergy Louisiana caused the lessors to issue $307.6 million aggregate principal amount of Waterford 3 Secured Lease Obligation Bonds, 8.76% Series due 2017, to refinance the outstanding bonds originally issued to finance the purchase of the undivided interests by the lessors. The lease payments were reduced to reflect the lower interest costs. Upon the occurrence of certain events, Entergy Louisiana may be obligated to pay amounts sufficient to permit the termination of the lease transactions and may be required to assume the outstanding bonds issued to finance, in part, the lessors' acquisition of the undivided interests in Waterford 3.

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

                Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy New Orleans, System Energy, or their affiliates, 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 Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, System Energy, and their affilitates 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.

Asbestos and Hazardous Material Litigation (Entergy Gulf States, Entergy Louisiana, 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, the Entergy companies have resolved over 3 thousand claims for nominal amounts that in the aggregate total less than $13 million, including defense costs. Some of this loss has been offset by reimbursement from insurers. Presently there are over 3 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 successf ully so that the ultimate resolution of these matters will not be material, in the aggregate, to its financial position or results of operation.

Grand Gulf 1-Related Agreements

Capital Funds Agreement (System Energy)

                System Energy has entered into agreements with Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans whereby they are obligated to purchase their respective entitlements of capacity and energy from System Energy's 90% interest in Grand Gulf 1, and to make payments that, together with other available funds, are adequate to cover System Energy's operating expenses. System Energy would have to secure funds from other sources, including Entergy Corporation's obligations under the Capital Funds Agreement, to cover any shortfalls from payments received from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under these agreements.

Unit Power Sales Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

                System Energy has agreed to sell all of its 90% share of capacity and energy from Grand Gulf 1 to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans in accordance with specified percentages (Entergy Arkansas-36%, Entergy Louisiana-14%, Entergy Mississippi-33%, and Entergy New Orleans-17%) as ordered by FERC. Charges under this agreement are paid in consideration for the purchasing companies' respective entitlement to receive capacity and energy and are payable irrespective of the quantity of energy delivered so long as the unit remains in commercial operation. The agreement will remain in effect until terminated by the parties and the termination is approved by FERC, most likely upon Grand Gulf 1's retirement from service. Monthly obligations for payments under the agreement are approximately $16 million for Entergy Arkansas, $6 million for Entergy Louisiana, $14 million for Entergy Mississippi, and $7 million for Entergy New Orleans.

Availability Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

                Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans are individually obligated to make payments or subordinated advances to System Energy in accordance with stated percentages (Entergy Arkansas-17.1%, Entergy Louisiana-26.9%, Entergy Mississippi-31.3%, and Entergy New Orleans-24.7%) in amounts that, when added to amounts received under the Unit Power Sales Agreement or otherwise, are adequate to cover all of System Energy's operating expenses as defined, including an amount sufficient to amortize the cost of Grand Gulf 2 over 27 years. (See Reallocation Agreement terms below.) System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Since commercial operation of Grand Gulf 1, payments under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Accordingly, 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.

Reallocation Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

                System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans entered into the Reallocation Agreement relating to the sale of capacity and energy from Grand Gulf and the related costs, in which Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans agreed to assume all of Entergy Arkansas' responsibilities and obligations with respect to Grand Gulf under the Availability Agreement. FERC's decision allocating a portion of Grand Gulf 1 capacity and energy to Entergy Arkansas supersedes the Reallocation Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (Entergy Louisiana-26.23%, Entergy Mississippi-43.97%, and Entergy New Orleans-29.80%) under the terms of the Reallocation Agreement. However, the Reallocation Agreement does not affect Entergy Arkansas' obligation to System Energy's lenders under the assignments referred to in the preceding paragraph. Entergy Arkansas would be liable fo r its share of such amounts if Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans were unable to meet their contractual obligations. No payments of any amortization amounts will be required so long as amounts paid to System Energy under the Unit Power Sales Agreement, including other funds available to System Energy, exceed amounts required under the Availability Agreement, which is expected to be the case for the foreseeable future.

Reimbursement Agreement (System Energy)

                In December 1988, System Energy entered into two separate, but identical, arrangements for the sale and leaseback of an approximate aggregate 11.5% ownership interest in Grand Gulf 1. In connection with the equity funding of the sale and leaseback arrangements, letters of credit are required to be maintained to secure certain amounts payable for the benefit of the equity investors by System Energy under the leases. The previous letters of credit were due to expire on March 20, 2003, and were replaced early in March 2003. The new letters of credit are effective until March 2006, and are backed by approximately $192 million of cash collateral.

NOTE 10. LEASES (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

General

                As of December 31, 2002, the domestic utility companies had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities (excluding nuclear fuel leases and the sale and leaseback transactions) with minimum lease payments as follows:

Capital Leases

Operating Leases

Rental expense amounted to $20.8 million, $21.1 million, and $18.9 million for Entergy Arkansas; $17.6 million, $22.0 million, and $18.9 million for Entergy Gulf States; and $11.2 million, $11.7 million, and $7.9 million for Entergy Louisiana in 2002, 2001, and 2000, respectively. In addition to the above rental expense, railcar operating lease payments, which are recorded in fuel expense, were $8.3 million in 2002, $12.2 million in 2001, and $12.5 million in 2000 for Entergy Arkansas and $2.0 million in 2002 and $2.8 million in 2001 and 2000 for Entergy Gulf States. The railcar lease payments are recorded as fuel expense in accordance with regulatory treatment.

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 table below represents the total nuclear fuel lease payments (principal and interest) as well as the separate interest component charged to operations in 2002, 2001, and 2000:

Sale and Leaseback Transactions

Waterford 3 Lease Obligations (Entergy Louisiana)

                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 (System Energy)

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

Pension Plans

                The domestic utility companies and System Energy have two pension plans, "Entergy Corporation Retirement Plan for Non-Bargaining Employees," and "Entergy Corporation Retirement Plan for Bargaining Employees," covering substantially all of their employees. 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 domestic utility companies and System Energy 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 cost of the domestic utility companies and System Energy, including amounts capitalized, included the following components (in thousands):

                The funded status of the domestic utility companies and System Energy's pension plans as of December 31, 2002 and 2001 was (in thousands):

Other Postretirement Benefits

                The domestic utility companies and System Energy also provide health care and life insurance benefits for retired employees. Substantially all 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 the domestic utility companies and System Energy, including amounts capitalized and deferred, included the following components (in thousands):

               The funded status of the domestic utility companies and System Energy'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 the domestic utility companies and System Energy was 10% for 2003, gradually decreasing each successive year until it reaches 4.5% in 2009 and beyond. A one percentage point change in the assumed health care cost trend rate for 2002 would have the following effects (in thousands):

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

               The domestic utility companies' and System Energy'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. RISK MANAGEMENT AND DERIVATIVES

Market and Commodity Risks

                In the normal course of business, the domestic utility companies and System Energy are exposed to a number of market and commodity risks including power price risk, fuel price risk, foreign currency exchange rate risk, and equity price and interest rate risks. Market risk is the potential loss that the domestic utility companies and System Energy 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.

                The domestic utility companies and System Energy manage these risks through both contractual arrangements and derivatives. Contractual risk management tools include long-term power and fuel purchase agreements. The domestic utility companies and System Energy also use a variety of commodity and financial derivatives, including natural gas and electricity futures, forwards and options, and foreign currency forwards to manage the following risks:

• power price risk resulting from Entergy's short position during the summer months;
• fuel price risk for spot market gas purchases; and
• foreign currency exchange rate risk resulting from euro-denominated nuclear fuel acquisition contracts.

                Gains and losses realized from derivative transactions used to manage power and fuel price risk are included in fuel costs recovered through rates. Accordingly, these gains and losses are accounted for as regulatory assets and liabilities prior to transaction maturity. Power price risk is managed primarily through the purchase of short-term forward contracts that are accounted for as normal purchases. Any option premiums paid to manage power price risk are booked with an offsetting regulatory asset or liability. The volume of these purchases is based on Entergy's demand forecast.

                Entergy manages fuel price risk for its Louisiana jurisdictions (Entergy Louisiana, Entergy New Orleans, and the Louisiana portion of Entergy Gulf States) primarily through the purchase of short-term swaps. These swaps are marked-to-market with offsetting regulatory assets or liabilities. The notional volumes of these swaps are based on a portion of projected purchases of gas for the summer (electric generation) and winter (gas distribution at Entergy Gulf States and Entergy New Orleans) peak seasons.

                Entergy Gulf States manages foreign currency exchange rate risk through the purchase of forwards that are accounted for as cash flow hedges. The notional volumes of these forwards are based on forecasted purchases and the realized gain or loss from these forwards is included in the capitalized cost of the applicable batches of nuclear fuel.

                There were no forward contracts at Entergy Gulf States that matured in 2002. During 2003, forward contracts with unrealized gains of $2.8 million at December 31, 2002 will mature, at which time the final gain or loss on these contracts will be included in the capitalized cost of nuclear fuel. The maximum length of time over which Entergy Gulf States is currently hedging the variability in future cash flows for forecasted transactions (excluding interest rate swaps) at December 31, 2002 is approximately 18 months. The ineffective portion of the change in the value of Entergy Gulf States' cash flow hedges during 2002 was insignificant.

NOTE 13. TRANSACTIONS WITH AFFILIATES (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

               Each domestic utility company purchases electricity from and sells electricity to the other domestic utility companies, System Energy, and Entergy Power (in the case of Entergy Arkansas) under rate schedules filed with FERC. In addition, the domestic utility companies and System Energy purchase fuel from System Fuels; receive management, technical, advisory, operating, and administrative services from Entergy Services; and receive management, technical, and operating services from Entergy Operations. Pursuant to SEC rules under PUHCA, these transactions are on an "at cost" basis, and are eliminated in the consolidated financial statements of Entergy.

                As described in Note 1 to the domestic utility companies and System Energy financial statements, all of System Energy's operating revenues consist of billings to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

                Additionally, as described in Note 4 to the domestic utility companies and System Energy financial statements, the domestic utility companies and System Energy participate in the Entergy System Money Pool and earn interest income from the Money Pool. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, also receive interest income from System Fuels, Inc.

                The tables below contain the various affiliate transactions among the domestic utility companies and System Energy (in millions).

Intercompany Revenues

	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
2002	$ 172.6	$28.8	$ 8.8	$ 70.6	$ 7.1	$ 602.5
2001	$ 250.2	$75.2	$ 26.1	$ 118.3	$ 10.0	$ 535.0
2000	$ 255.3	$93.7	$ 20.8	$ 88.1	$ 31.6	$ 656.7

Intercompany Operating Expenses

	Entergy Arkansas (1)	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
2002	$ 284.6	$211.1	$ 277.3	$298.6	$166.7	$ 11.7
2001	$ 262.9	$274.8	$ 298.1	$535.2	$ 231.7	$ 9.5
2000	$ 387.9	$239.4	$ 388.5	$388.2	$ 177.0	$ 10.1

1. Includes $0.7 million in 2002, $3.5 million in 2001, and $47.3 million in 2000 for power purchased from Entergy Power.

Operating Expenses Paid or Reimbursed to Entergy Operations

	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	System Energy
2002	$ 172.1	$110.1	$ 112.4	$97.3
2001	$ 141.4	$102.7	$ 104.6	$75.8
2000	$ 163.0	$116.0	$ 113.2	$92.6

Intercompany Interest Income

	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
2002	$ 1.0	$ 0.3	$ 0.7	$ 0.4	$ 0.2	$ 0.9
2001	$ 0.8	$ 0.5	$ 2.2	$ 0.5	$ 0.3	$ 6.3
2000	$ 1.5	$ 0.6	$ 2.0	$ 0.9	$ 0.4	$ 6.9

NOTE 14. QUARTERLY FINANCIAL DATA (UNAUDITED) (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

                The business of the domestic utility companies and System Energy is subject to seasonal fluctuations with the peak periods occurring during the third quarter. Operating results for the four quarters of 2002 and 2001 were:

Operating Revenue

	EntergyArkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
2002:
First Quarter	$377,823	$463,904	$369,963	$191,690	$102,947	$142,330
Second Quarter	367,926	567,563	483,389	261,743	121,422	142,892
Third Quarter	474,873	648,849	528,052	316,745	157,417	156,930
Fourth Quarter	340,488	503,563	433,948	220,917	126,088	160,334
2001:
First Quarter	$393,800	$734,476	$548,914	$256,158	$204,015	$151,166
Second Quarter	453,108	730,893	547,784	274,148	160,309	152,902
Third Quarter	541,556	714,488	473,342	354,518	167,137	66,276
Fourth Quarter	388,312	468,703	331,873	208,917	99,389	164,683

Operating Income (Loss)

	EntergyArkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
2002:
First Quarter	$55,731	$74,486	$75,888	$16,928	$(1,675)	$59,940
Second Quarter	69,394	133,741	134,481	29,253	13,151	59,122
Third Quarter	138,887	125,543	108,837	50,451	19,283	65,014
Fourth Quarter	38,197	17,960	(2,564)	10,134	(13,409)	65,058
2001:
First Quarter	$71,647	$126,182	$39,267	$14,524	$4,218	$60,594
Second Quarter	104,118	111,562	88,913	31,647	9,373	61,281
Third Quarter	163,538	118,201	192,528	34,302	2,653	83,906
Fourth Quarter	40,387	41,247	3,922	9,839	(9,194)	64,673

Net Income (Loss)

	EntergyArkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
2002:
First Quarter	$22,838	$28,038	$29,494	$5,829	$(3,940)	$26,727
Second Quarter	19,247	65,236	75,845	12,752	3,199	25,250
Third Quarter	74,664	64,489	50,063	26,213	9,307	25,640
Fourth Quarter	18,894	16,315	(10,693)	7,614	(8,796)	25,735
2001:
First Quarter	$28,978	$59,046	$6,859	$4,535	$474	$20,798
Second Quarter	47,038	51,382	37,034	15,673	3,369	21,202
Third Quarter	82,401	52,353	101,515	18,748	(308)	37,793
Fourth Quarter	19,768	16,663	(12,858)	664	(5,730)	36,562

Item 2.Properties

                Information regarding the registrant's properties is included in Part I. Item 1. - Business under the sections titled "Property" in this report.

Item 3.Legal Proceedings

                Details of the registrant's material environmental regulation and proceedings and other regulatory proceedings and litigation that are pending or those terminated in the fourth quarter of 2002 are discussed in Part I. Item 1. - Business under the sections titled "Rate Matters", "Environmental Regulation", and "Litigation" in this report.

Item 4.Submission of Matters to a Vote of Security Holders

                During the fourth quarter of 2002, no matters were submitted to a vote of the security holders of Entergy Corporation.

DIRECTORS AND EXECUTIVE OFFICERS OF ENTERGY CORPORATION

Directors

                Information required by this item concerning directors of Entergy Corporation is set forth under the heading "Proposal 1--Election of Directors" contained in the Proxy Statement of Entergy Corporation, (the "Proxy Statement"), to be filed in connection with its Annual Meeting of Stockholders to be held May 9, 2003, ("Annual Meeting"), and is incorporated herein by reference. Information required by this item concerning officers and directors of the remaining registrants is reported in Part III of this document.

Executive Officers

Name	Age	Position	Period
J. Wayne Leonard (a)	52	Chief Executive Officer and Director of Entergy Corporation	1999-Present
		Director of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy	1998-1999
		President and Chief Operating Officer of Entergy Corporation	1998
		Chief Operating Officer of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans	1998
		Vice Chairman of Entergy New Orleans	1998
		President of Energy Commodities Strategic Business Unit	1996-1998
		President of Cinergy Capital & Trading	1996-1998
Donald C. Hintz (a)	60	President of Entergy Corporation	1999-Present
		Executive Vice President and Chief Nuclear Officer of Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana	1998
		Group President and Chief Nuclear Operating Officer of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana	1997-1998
		Chief Executive Officer and President of System Energy	1992-1998
		Director of Entergy Gulf States	1993-Present
		Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and System Energy	1992-Present
		Director of Entergy New Orleans	1999-Present
Richard J. Smith (a)	51	Group President, Utility Operations of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans	2001-Present
		Director of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans	2001-Present
		Senior Vice President, Transition Management of Entergy Corporation	2000-2001
		President of Cinergy Resources, Inc.	1999
		Vice President Energy Services	1999
		Vice President of Finance Services Business Unit	1996-1999
Curtis L. Hebert, Jr. (a)	40	Executive Vice President, External Affairs of Entergy Corporation	2001-Present
		Chairman and Commissioner of the Federal Energy Regulatory Commission	1997-2001
		Chairman and Commissioner of the Mississippi Public Service Commission	1992 - 1997
Jerry D. Jackson (a)	58	Executive Vice President of Entergy Corporation	1999-Present
		Group President - Utility Operations of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans	2000-2001
		President and Chief Executive Officer - Louisiana of Entergy Gulf States	1999-2000
		President and Chief Executive Officer of Entergy Louisiana	1999-2000
		Chief Administrative Officer of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans	1997-1998
		Executive Vice President - External Affairs of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans	1995-1998
		Executive Vice President - External Affairs of Entergy Corporation	1994-1998
		Director of Entergy Gulf States	1994-2001
		Director of Entergy Louisiana	1992-2001
		Director of Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans	2000-2001 1992-1999
Michael G. Thompson (a)	62	Executive Vice President, General Counsel and Secretary of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans	2001-Present
		Senior Vice President and General Counsel of Entergy Corporation	1992-2001
		Senior Vice President, General Counsel, and Secretary of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans	1995-2001
		Secretary of Entergy Corporation	1994-2001
C. John Wilder (a)	44	Executive Vice President and Chief Financial Officer of Entergy Corporation and System Energy	1998-Present
		Executive Vice President and Chief Financial Officer of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans	1998 - 2002
		Director of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy	1999-Present
		Chief Executive Officer of Shell Capital Company	1998
		Assistant Treasurer of the Royal Dutch/Shell Group	1996-1998
Frank F. Gallaher (a)	57	Senior Vice President of Entergy Corporation	2001-Present
		Senior Vice President, Generation, Transmission and Energy Management of Entergy Corporation	1999-2001
		President, Fossil Operations and Transmission of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans	2000-Present
		Senior Vice President, Generation, Transmission and Energy Management of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans	1999-2000
		Executive Vice President and Chief Utility Operating Officer for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans	1998-1999
		Group President and Chief Utility Operating Officer of Entergy Corporation	1997-1999
		Group President and Chief Utility Operating Officer of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans	1997-1998
		Director of Entergy Arkansas, Entergy Louisiana, and Entergy Mississippi	1997-1999
		Director of Entergy Gulf States	1993-1999
Joseph T. Henderson (a)	45	Senior Vice President and General Tax Counsel of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy	2001-Present
		Vice President and General Tax Counsel of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy	1999-2001
		Associate General Tax Counsel of Shell Oil Company	1998-1999
		Senior Tax Counsel of Shell Oil Company	1995-1998
Nathan E. Langston (a)	54	Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy	2001-Present
		Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy	1998-2001
		Director of Tax Services of Entergy Services	1993-1998
William E. Madison (a)	56	Senior Vice President - Human Resources and Administration of Entergy Corporation	2002 - Present
		Senior Vice President - Human Resources and Administration of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans	2001-Present
		Senior Vice President & Chief Human Resources Officer, Avis Group Holdings, Inc. - Garden City, New York	2000-2001
		President, US Region and Vice President, Global Human Resource Strategy, E.I. DuPont de Nemours, Wilmington, Delaware	1997-2000
Steven C. McNeal (a)	46	Vice President and Treasurer of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy	1998-Present
		Assistant Treasurer of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy	1994-1998
		Director of Corporate Finance of Entergy Services	1994-1998

1. In addition, this officer is an executive officer and/or director of various other wholly owned subsidiaries of Entergy Corporation and its operating companies.

                Each officer of Entergy Corporation is elected yearly by the Board of Directors.

PART II

Item 5.Market for Registrants' Common Equity and Related Stockholder Matters

Entergy Corporation

                The shares of Entergy Corporation's common stock are listed on the New York Stock, Chicago Stock, and Pacific Exchanges under the ticker symbol ETR.

                Entergy Corporation's stock price as of February 28, 2003 was $45.55. The high and low prices of Entergy Corporation's common stock for each quarterly period in 2002 and 2001 were as follows:

	2002		2001
	High	Low	High	Low
	(In Dollars)
First	43.88	38.25	42.88	32.56
Second	46.85	41.05	44.67	36.82
Third	44.95	32.12	40.95	33.60
Fourth	46.42	36.80	39.50	35.10

                Consecutive quarterly cash dividends on common stock were paid to stockholders of Entergy Corporation in 2002 and 2001. In 2002, dividends of $0.33 per share were paid in the first three quarters, and a dividend of $0.35 per share was paid in the fourth quarter. In 2001, dividends of $0.315 per share were paid in the first three quarters, and a dividend of $0.33 per share was paid in the fourth quarter.

                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. The following table summarizes information about Entergy's stock options awarded under these plans.

Plan	Number of Securities to be Issued Upon Exercise of Outstanding Options	Weighted Average Exercise Price	Number of Securities Remaining Available for Future Issuance
Equity Ownership Plan	3,963,349	$ 34.96	8,614,275
Equity Awards Plan	15,979,765	36.07	5,671,792
Total	19,943,114	$ 35.85	14,286,067

                As of February 28, 2003, there were 57,062 stockholders of record of Entergy Corporation.

                Entergy Corporation's future ability to pay dividends is discussed in Note 8 to the consolidated financial statements. In addition to the restrictions described in Note 8, PUHCA provides that, without approval of the SEC, the unrestricted, undistributed retained earnings of any Entergy Corporation subsidiary are not available for distribution to Entergy Corporation's common stockholders until such earnings are made available to Entergy Corporation through the declaration of dividends by such subsidiaries.

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

                There is no market for the common stock of Entergy Corporation's wholly owned subsidiaries. Cash dividends on common stock paid by the domestic utility companies and System Energy to Entergy Corporation during 2002 and 2001, were as follows:

	2002	2001
	(In Millions)
Entergy Arkansas	$125.9	$82.5
Entergy Gulf States	$91.2	$83.7
Entergy Louisiana	$271.4	$134.6
Entergy Mississippi	$27.3	$19.6
Entergy New Orleans	$0.8	$0.8
System Energy	$101.8	$119.1

                Information with respect to restrictions that limit the ability of the domestic utility companies and System Energy to pay dividends is presented in Note 8 to the domestic utility companies and System Energy financial statements.

Item 6.Selected Financial Data

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

Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations

                Refer to "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC., ENTERGY GULF STATES, INC., ENTERGY LOUISIANA, INC., ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., and SYSTEM ENERGY RESOURCE, INC."

Item 7A.Quantitative and Qualitative Disclosures About Market Risk

               Refer to "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS -Significant Factors and Known Trends - Market and Credit Risks OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC., ENTERGY GULF STATES, INC., ENTERGY LOUISIANA, INC., ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., and SYSTEM ENERGY RESOURCES, INC."

Item 8.Financial Statements and Supplementary Data

               Refer to "TABLE OF CONTENTS - Entergy Corporation, Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc., and System Energy Resources, Inc."

Item 9.Changes In and Disagreements With Accountants On Accounting and Financial Disclosure.

               On the recommendation of the Audit Committee of the Board, the Executive Committee of the Board (acting between board meetings) appointed Deloitte & Touche as independent accountants for Entergy Corporation, effective August 13, 2001. The Boards of Directors of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy also appointed Deloitte & Touche as independent accountants for each of those corporations effective August 13, 2001. Entergy's former independent accountants, PricewaterhouseCoopers, were dismissed effective August 13, 2001. The reports issued by PricewaterhouseCoopers on Entergy's financial statements for either of the two most recent fiscal years did not contain any adverse opinion or a disclaimer of opinion, or any qualification or modification as to uncertainty, audit scope or accounting principles. During Entergy's two most recent fiscal years and through August 13, 2001, there were no disagreements with PricewaterhouseCoopers on a matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which, if not resolved to the satisfaction of PricewaterhouseCoopers, would have caused PricewaterhouseCoopers to make reference to the subject matter of the disagreement in connection with its reports.

                Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy initially reported the change in accountants on Form 8-K on August 13, 2001. The Form 8-K contained a letter from PricewaterhouseCoopers to the Securities and Exchange Commission stating that it agreed with the statements concerning their firm made therein.

PART III

Item 10.Directors and Executive Officers of the Registrants (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

               All officers and directors listed below held the specified positions with their respective companies as of the date of filing this report.

    Name              Age                Position                                Period

ENTERGY ARKANSAS, INC.

Directors

Hugh T. McDonald      44   President and Chief Executive Officer of            2000-Present
                             Entergy Arkansas
                           Director of Entergy Arkansas                        2000-Present
                           Senior Vice President, Retail of Entergy            1999-2000
                             Services, Inc.
                           Director, Regulatory Affairs - TX of                1995-1999
                             Entergy Gulf States
Donald C. Hintz            See information under the Entergy
                             Corporation Officers Section in Part I.
Richard J. Smith           See information under the Entergy
                             Corporation Officers Section in Part I.
C. John Wilder             See information under the Entergy
                             Corporation Officers Section in Part I.
       
Officers

Theodore Bunting      44   Vice President and Chief Financial                  2002 - Present
                             Officer of Entergy Arkansas, Entergy
                             Gulf States, Entergy Louisiana, Entergy
                             Mississippi, and Entergy New Orleans
                           Vice President and Chief Financial                  2000 - 2002
                             Officer - Operations of Entergy Services
                           Director, Utility Operations of Entergy             1999 - 2000
                             Services
                           Partner with Public Energy Services, Inc.           1997 - 1999
John Thomas Kennedy   43   Vice President - State Governmental                 2000-Present
                             Affairs of Entergy Arkansas
                           Attorney at Law, Russellville, Arkansas             1985-2000
Steve K. Strickland   46   Vice President - Regulatory Affairs of              2002 - Present
                             Entergy Arkansas
                           Director, Regulatory Affairs of Entergy             1995 - 2002
                             Arkansas
Frank F. Gallaher          See information under the Entergy
                             Corporation Officers Section in Part I.
Joseph T. Henderson        See information under the Entergy
                             Corporation Officers Section in Part I.
Nathan E. Langston         See information under the Entergy
                             Corporation Officers Section in Part I.
William E. Madison         See information under the Entergy
                             Corporation Officers Section in Part I.
Hugh T. McDonald           See information under the Entergy
                             Arkansas Directors Section above.
Steven C. McNeal           See information under the Entergy
                             Corporation Officers Section in Part I.
Richard J. Smith           See information under the Entergy
                             Corporation Officers Section in Part I.
Michael G. Thompson        See information under the Entergy
                             Corporation Officers Section in Part I.


ENTERGY GULF STATES, INC.

Directors

E. Renae Conley       45   Director of Entergy Gulf States and                 2000-Present
                             Entergy Louisiana
                           President and Chief Executive Officer -             2000-Present
                             LA of Entergy Gulf States and Entergy
                             Louisiana
                           Vice President, Investor Relations of               1999-2000
                             Entergy Services
                           President of Cincinnati Gas & Electric,             1998-1999
                             (a subsidiary of Cinergy Corp.)
                           Chief Executive Officer of Cadence LLC (a           1997-1998
                             subsidiary of Cinergy Corp.)
Joseph F. Domino      54   Director of Entergy Gulf States                     1999-Present
                           President and Chief Executive Officer -             1998-Present
                             TX of Entergy Gulf States
                           Director - Southwest Franchise of Entergy           1997-1998
                             Gulf States
Donald C. Hintz            See information under the Entergy
                             Corporation Officers Section in Part I.
Richard J. Smith           See information under the Entergy
                             Corporation Officers Section in Part I.
C. John Wilder             See information under the Entergy
                             Corporation Officers Section in Part I.
  
Officers

Jack Blakley          48   Vice President - Regulatory Affairs, TX             2002 - Present
                             of Entergy Gulf States
                           Director - Regulatory Affairs, TX of                1999 - 2002
                             Entergy Gulf States
                           Director - System Regulatory Strategy of            1996 - 1999
                             Entergy Services
Murphy A. Dreher      50   Vice President - State Governmental                 1999-Present
                             Affairs - LA of Entergy Gulf States and
                             Entergy Louisiana
                           Legislative Executive - Governmental                1995-1998
                             Affairs of Entergy Gulf States
Randall W. Helmick    48   Vice President - Operations - LA of                 1998-Present
                             Entergy Gulf States and Entergy
                             Louisiana
                           Director of Special Projects of London              1997-1998
                             Electricity
Eduardo Melendreras   45   Vice President, Customer Service and                2001-Present
                             Commercial and Industrial Accounts of
                             Entergy Gulf States and Entergy
                             Louisiana
                           Director - Jurisdictional Accounts of               2000-2001
                             Entergy Services
                           Director - Large Industrial Sales &                 1996-2000
                             Service of Entergy Gulf States
J. Parker McCollough  51   Vice President - State Governmental                 1996-Present
                             Affairs - TX of Entergy Gulf States
Wade H. Stewart       57   Vice President, Regulatory Affairs - LA             2000-Present
                             of Entergy Gulf States and Entergy
                             Louisiana
                           Director, Regulatory Affairs - LA of                1995-2000
                             Entergy Gulf States and Entergy
                             Louisiana
Theodore Bunting           See information under the Entergy
                             Arkansas Officers Section above.
E. Renae Conley            See information under the Entergy Gulf
                             States Directors Section above.
Joseph F. Domino           See information under the Entergy Gulf
                             States Directors Section above.
Frank F. Gallaher          See information under the Entergy
                             Corporation Officers Section in Part I.
Joseph T. Henderson        See information under the Entergy
                             Corporation Officers Section in Part I.
Nathan E. Langston         See information under the Entergy
                             Corporation Officers Section in Part I.
William E. Madison         See information under the Entergy
                             Corporation Officers Section in Part I.
Steven C. McNeal           See information under the Entergy
                             Corporation Officers Section in Part I.
Richard J. Smith           See information under the Entergy
                             Corporation Officers Section in Part I.
Michael G. Thompson        See information under the Entergy
                             Corporation Officers Section in Part I.


ENTERGY LOUISIANA, INC.

Directors

E. Renae Conley            See information under the Entergy Gulf
                             States Directors Section above.
Donald C. Hintz            See information under the Entergy
                             Corporation Officers Section in Part I.
Richard J. Smith           See information under the Entergy
                             Corporation Officers Section in Part I.
C. John Wilder             See information under the Entergy
                             Corporation Officers Section in Part I.
 
Officers

Theodore Bunting           See information under the Entergy
                             Arkansas Officers Section above.
E. Renae Conley            See information under the Entergy Gulf
                             States Directors Section above.
Murphy A. Dreher           See information under the Entergy Gulf
                             States Officers Section above.
Frank F. Gallaher          See information under the Entergy
                             Corporation Officers Section in Part I.
Randall W. Helmick         See information under the Entergy Gulf
                             States Officers Section above.
Joseph T. Henderson        See information under the Entergy
                             Corporation Officers Section in Part I.
Nathan E. Langston         See information under the Entergy
                             Corporation Officers Section in Part I.
William E. Madison         See information under the Entergy
                             Corporation Officers Section in Part I.
Steven C. McNeal           See information under the Entergy
                             Corporation Officers Section in Part I.
Eduardo Melendreras        See information under the Entergy Gulf
                             States Officers Section above.
Richard J. Smith           See information under the Entergy
                             Corporation Officers Section in Part I.
Michael G. Thompson        See information under the Entergy
                             Corporation Officers Section in Part I.
Wade H. Stewart            See information under the Entergy Gulf
                             States Officers Section above.
                     
ENTERGY MISSISSIPPI, INC.

Directors

Carolyn C. Shanks     41   President and Chief Executive Officer of            1999-Present
                             Entergy Mississippi
                           Director of Entergy Mississippi                     1999-Present
                           Vice President of Finance and                       1997-1999
                             Administration of Entergy Mississippi
Donald C. Hintz            See information under the Entergy
                             Corporation Officers Section in Part I.
Richard J. Smith           See information under the Entergy
                             Corporation Officers Section in Part I.
C. John Wilder             See information under the Entergy
                             Corporation Officers Section in Part I.
   
Officers

Bill F. Cossar        64   Vice President - State Governmental                 1987-Present
                             Affairs of Entergy Mississippi
Robert C. Grenfell    49   Vice President - Regulatory Affairs, MS             2002 - Present
                             of Entergy Mississippi
                           Director, Regulatory Affairs of Entergy             1994 - 2002
                             Mississippi
Haley R. Fisackerly   37   Vice President - Customer Service of                2002 - Present
                             Entergy Mississippi
                           Director - System Regulatory Strategy of            1999 - 2002
                             Entergy Services
                           Governmental Affairs Executive of Entergy           1995 - 1999
                             Services
Will L. Mayo          55   Vice President - State Governmental                 2002 - Present
                             Affairs of Entergy Mississippi
                           Director - Economic Development of                  1997 - 2002
                             Entergy Mississippi
Theodore Bunting           See information under the Entergy
                             Arkansas Officers Section above.
Frank F. Gallaher          See information under the Entergy
                             Corporation Officers Section in Part I.
Joseph T. Henderson        See information under the Entergy
                             Corporation Officers Section in Part I.
Nathan E. Langston         See information under the Entergy
                             Corporation Officers Section in Part I.
William E. Madison         See information under the Entergy
                             Corporation Officers Section in Part I.
Steven C. McNeal           See information under the Entergy
                             Corporation Officers Section in Part I.
Carolyn C. Shanks          See information under the Entergy
                             Mississippi Directors Section above.
Richard J. Smith           See information under the Entergy
                             Corporation Officers Section in Part I.
Michael G. Thompson        See information under the Entergy
                             Corporation Officers Section in Part I.


ENTERGY NEW ORLEANS, INC.

Directors

Daniel F. Packer      55   Chief Executive Officer Entergy New                 1998-Present
                             Orleans
                           President and Director of Entergy New               1997-Present
                             Orleans
Donald C. Hintz            See information under the Entergy
                             Corporation Officers Section in Part I.
Richard J. Smith           See information under the Entergy
                             Corporation Officers Section in Part I.
C. John Wilder             See information under the Entergy
                             Corporation Officers Section in Part I.
                                  
Officers

Elaine Coleman        53   Vice President, External Affairs of                 1998-Present
                             Entergy New Orleans
                           Director of Customer Service of Entergy             1998
                             Services
                           Lead Customer Service Manager of Entergy            1995-1998
                             Services
Theodore Bunting           See information under the Entergy
                             Arkansas Officers Section above.
Frank F. Gallaher          See information under the Entergy
                             Corporation Officers Section in Part I.
Joseph T. Henderson        See information under the Entergy
                             Corporation Officers Section in Part I.
Nathan E. Langston         See information under the Entergy
                             Corporation Officers Section in Part I.
William E. Madison         See information under the Entergy
                             Corporation Officers Section in Part I.
Steven C. McNeal           See information under the Entergy
                             Corporation Officers Section in Part I.
Daniel F. Packer           See information under the Entergy New
                             Orleans Directors Section above.
Richard J. Smith           See information under the Entergy
                             Corporation Officers Section in Part I.
Michael G. Thompson        See information under the Entergy
                             Corporation Officers Section in Part I.
                                                              
SYSTEM ENERGY RESOURCES, INC.

Directors

Jerry W. Yelverton    58   Director, President and Chief Executive             1999-Present
                             Officer of System Energy
                           Senior Vice President of Nuclear of                 1997-1998
                             Entergy Services
                           Executive Vice President and Chief                  1996-1998
                             Operating Officer of Entergy Operations
                           In addition, Mr. Yelverton is an
                             executive officer and/or director of
                             various other wholly owned subsidiaries
                             of Entergy Corporation and its operating
                             companies.
Donald C. Hintz            See information under the Entergy
                             Corporation Officers Section in Part I.
C. John Wilder             See information under the Entergy
                             Corporation Officers Section in Part I.
                          
Officers

Joseph L. Blount      56   Secretary of System Energy and Entergy              1991-Present
                             Operations
Joseph T. Henderson        See information under the Entergy
                             Corporation Officers Section in Part I.
Nathan E. Langston         See information under the Entergy
                             Corporation Officers Section in Part I.
Steven C. McNeal           See information under the Entergy
                             Corporation Officers Section in Part I.
C. John Wilder             See information under the Entergy
                             Corporation Officers Section in Part I.
Jerry W. Yelverton         See information under the System Energy
                             Directors Section above.

                Each director and officer of the applicable Entergy company is elected yearly to serve by the unanimous consent of the sole stockholder, Entergy Corporation, at its annual meeting.

Section 16(a) Beneficial Ownership Reporting Compliance

                Information called for by this item concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held on May 9, 2003, under the heading "Section 16(a) Beneficial Ownership Reporting Compliance", which information is incorporated herein by reference.

Item 11.Executive Compensation

ENTERGY CORPORATION

                Information called for by this item concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement under the headings "Executive Compensation Tables", "General Information About Nominees", "Director Compensation", and "Comparison of Five Year Cumulative Total Return", all of which information is incorporated herein by reference.

ENTERGY ARKANSAS, ENTERGY GULF STATES, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND SYSTEM ENERGY

Summary Compensation Table

               The following table includes the Chief Executive Officer and the four other most highly compensated executive officers in office as of December 31, 2002 at Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy (collectively, the "Named Executive Officers"). This determination was based on total annual base salary and bonuses from all Entergy sources earned by each officer for the year 2002. See Item 10, "Directors and Executive Officers of the Registrants," for information on the principal positions of the Named Executive Officers in the table below.

Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy

               As shown in Item 10, most Named Executive Officers are employed by several Entergy companies. Because it would be impracticable to allocate such officers' salaries among the various companies, the table below includes the aggregate compensation paid by all Entergy companies.

                                                                                  Long-Term Compensation
                                          Annual Compensation                      Awards                  Payouts
                                                             Other       Restricted     Securities           (a)      (b) All
                                                            Annual         Stock        Underlying          LTIP       Other
           Name              Year   Salary       Bonus       Comp.         Awards       Options            Payouts     Comp.

E. Renae Conley              2002   $321,500   $320,000      $88,946        (c)         40,000 shares    $331,114      $15,211
CEO-Entergy Louisiana        2001    308,769    486,186       46,240        (c)         34,600                  -       10,742
CEO-LA-Entergy Gulf States   2000    282,642    280,000       41,573        (c)         20,000            181,109        8,559

Joseph F. Domino             2002   $255,295   $210,070      $63,361        (c)         22,000 shares    $153,202      $13,568
CEO-TX-Entergy Gulf States   2001    245,384    292,583       48,254        (c)         14,800                  -        7,150
                             2000    235,358    180,732       51,399        (c)         20,000            142,314        7,084

Donald C. Hintz              2002   $629,423   $754,800     $206,963        (c)        160,000 shares  $1,408,470      $34,318
                             2001    599,423    779,000      198,321        (c)        160,000                  -       21,605
                             2000    570,096    743,000      104,399        (c)        175,000          1,181,837       26,516

Jerry D. Jackson             2002   $491,281   $513,150      $19,261        (c)         75,898 shares    $627,634      $17,600
                             2001    475,345    576,382       19,646        (c)         80,000                  -       17,378
                             2000    458,223    554,214       58,758        (c)         58,500          1,181,575       15,162

J. Wayne Leonard             2002   $962,500 $1,450,400       $5,257        (c)        330,600 shares  $2,372,160      $20,517
                             2001    897,500  1,684,800        3,709  $7,400,000(c)(d) 330,600                  -            -
                             2000    836,538  1,190,000       11,646        (c)        330,600          2,410,413            -

Hugh T. McDonald             2002   $247,373   $185,000      $56,295        (c)         22,000 shares    $182,854      $14,867
CEO-Entergy Arkansas         2001    231,335    333,078      118,502        (c)         14,800                  -       18,664
                             2000    209,400    165,000       53,808        (c)         34,600            172,773       54,878

Daniel F. Packer             2002   $244,776    $95,000      $17,705        (c)         20,000 shares    $153,202      $13,469
CEO-Entergy New Orleans      2001    228,209    262,881       15,410        (c)         14,800                  -        7,055
                             2000    219,432    167,382       16,433        (c)         20,000            196,929        6,658

Carolyn C. Shanks            2002   $252,478   $200,000      $77,460        (c)         20,000 shares    $153,202      $14,138
CEO-Entergy Mississippi      2001    241,085    287,672       17,140        (c)         14,800                  -        7,206
                             2000    231,193    182,530        2,594        (c)         20,000            104,241        4,858

C. John Wilder               2002   $521,923   $549,080     $156,683        (c)        131,366 shares    $627,634      $24,459
                             2001    493,128    600,000      158,059        (c)         87,700                  -       16,284
                             2000    468,392    619,370      148,540        (c)         87,700            953,006       13,919

Jerry W. Yelverton           2002   $464,798   $658,350     $180,186        (c)         85,000 shares    $627,634      $28,455
CEO-System Energy            2001    443,269    540,000      145,389        (c)         65,000                  -       14,697
                             2000    408,846    510,000        4,197   $201,875(c)(d)   58,900            503,482       12,732

1. Amounts include the value of restricted shares that vested in 2000 and 2002 (see note (c) below) under Entergy's Equity Ownership Plan.
2. Includes the following:

1. 2002 benefit accruals under the Defined Contribution Restoration Plan as follows: Ms. Conley $5,510; Mr. Domino $2,592; Mr. Hintz $22,499; Mr. Jackson $16,135; Mr. Leonard $20,517; Mr. McDonald $2,043; Mr. Packer $1,642; Ms. Shanks $2,485; Mr. Wilder $14,553; and Mr. Yelverton $13,158.
2. 2002 employer contributions to the System Savings Plan as follows: Ms. Conley $9,701; Mr. Domino $10,976; Mr. Hintz $11,819; Mr. Jackson $1,465; Mr. McDonald $12,824; Mr. Packer $11,827; Ms. Shanks $11,653; Mr. Wilder $9,906; and Mr. Yelverton $15,297.

3. Performance unit (equivalent to shares of Entergy common stock) awards in 2002 are reported under the "Long-Term Incentive Plan Awards" table, and reference is made to this table for information on the aggregate number of performance units awarded during 2002 and the vesting schedule for such units. At December 31, 2002, the number and value of the aggregate performance unit holdings were as follows: Ms. Conley 17,500 units, $797,825; Mr. Domino 7,300 units, $332,807; Mr. Hintz 66,500 units, $3,031,735; Mr. Jackson 29,700 units, $1,354,023; Mr. Leonard 212,000 units, $9,665,080; Mr. McDonald 7,300 units, $332,807; Mr. Packer 7,300 units, $332,807; Ms. Shanks 7,300 units, $332,807; Mr. Wilder 29,700 units, $1,354,023; and Mr. Yelverton 33,700 units, $1,536,383. Accumulated dividends are paid on performance units when vested. The value of performance unit holdings as of December 31, 2002 is determined by multiplying the total number of units held by the closing market price of Entergy com mon stock on the New York Stock Exchange Composite Transactions on December 31, 2002 ($45.59 per share). The value of stock for which restrictions were lifted in 2002 and 2000, and the applicable portion of accumulated cash dividends, are reported in the LTIP payouts column in the above table.
4. In addition to the performance units granted under the Equity Ownership Plan, in January 2001, Mr. Leonard was granted 200,000 restricted stock units. 50,000 of the restricted stock units vest on each of December 31, 2001, December 31, 2002, December 31, 2003 and December 31, 2004, based on continued service with Entergy. Accumulated dividends will not be paid on Mr. Leonard's restricted stock units when vested. Mr. Yelverton was granted 10,000 restricted stock units in 2000. Restrictions were lifted on 3,000 units in 2001 and 2002, and the remaining 4,000 units in 2003. Accumulated dividends will not be paid. The value these individuals may realize is dependent upon both the number of units that vest and the future market price of Entergy common stock.

Option Grants in 2002

               The following table summarizes option grants during 2002 to the Named Executive Officers. The absence, in the table below, of any Named Executive Officer indicates that no options were granted to such officer.

Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy

	Individual Grants				Potential Realizable
		% of Total			Value
	Number of	Options			at Assumed Annual
	Securities	Granted to	Exercise		Rates of Stock
	Underlying	Employees	Price		Price Appreciation
	Options	in	(per	Expiration	for Option Term(b)
Name	Granted (a)	2002	share) (a)	Date	5%	10%
E. Renae Conley	40,000	0.5%	$ 41.69	2/11/12	$1,048,745	$2,657,725
Joseph F. Domino	22,000	0.3%	41.69	2/11/12	576,810	1,461,749
Donald C. Hintz	160,000	2.0%	41.69	2/11/12	4,194,979	10,630,900
Jerry D. Jackson	50,000	0.6%	41.69	2/11/12	1,310,931	3,322,156
	12,949 (c)	0.2%	46.37	1/27/10	272,375	646,414
	3,811 (c)	0.1%	45.67	2/01/03	1,421	2,787
	4,056 (c)	0.1%	45.67	1/27/04	10,054	20,149
	5,082 (c)	0.1%	45.67	1/27/10	105,283	249,864
J. Wayne Leonard	330,600	4.1%	41.69	2/11/12	8,667,875	21,966,097
Hugh T. McDonald	22,000	0.3%	41.69	2/11/12	576,810	1,461,749
Daniel F. Packer	20,000	0.2%	41.69	2/11/12	524,372	1,328,862
Carolyn C. Shanks	20,000	0.2%	41.69	2/11/12	524,372	1,328,862
C. John Wilder	87,700	1.1%	41.69	2/11/12	2,299,373	5,827,062
	8,666 (c)	0.1%	46.45	1/27/10	180,225	426,740
	1,109 (c)	0.0%	43.85	1/27/10	20,076	46,891
	3,891 (c)	0.1%	43.85	1/28/09	58,959	134,054
	5,000 (c)	0.1%	43.90	1/28/09	75,849	172,458
	5,000 (c)	0.1%	44.00	1/28/09	76,022	172,851
	15,000 (c)	0.2%	43.90	1/28/09	227,548	517,375
	5,000 (c)	0.1%	43.88	1/28/09	75,815	172,380
Jerry W. Yelverton	85,000	1.0%	41.69	2/11/12	2,228,582	5,647,665

1. Options were granted on February 11, 2002, pursuant to the Equity Ownership Plan. All options granted on this datehave an exercise price equal to the closing price of Entergy common stock on the New York Stock Exchange Composite Transactions on February 11, 2002. These options will vest in equal increments, annually, over a three-year period beginning in 2003.
2. Calculation based on the market price of the underlying securities assuming the market price increases over the option period and assuming annual compounding. The column presents estimates of potential values based on simple mathematical assumptions. The actual value, if any, a Named Executive Officer may realize is dependent upon the market price on the date of option exercise.
3. During 2002, Mr. Jackson and Mr. Wilder converted presently exercisable stock options into an equivalent total of phantom stock units and reload stock options. They accomplished this by exercising stock options, paying the exercise price for these options by surrendering shares of Entergy stock, and deferring the taxable gain into phantom stock units. Additional options, as indicated above, were granted pursuant to the reload feature of this "stock for stock" exercise method. Under the reload mechanism, eligible participants are granted an additional number of options equal to the number of shares surrendered to pay the exercise price. The reloaded stock options vest immediately and have an exercise price equal to the price of Entergy common stock on the New York Stock Exchange Composite Transactions on the date of exercise of the original options. The reloaded options retain the original grant's expiration date. The reload feature is proposed to be removed from the Equity Ownership P lan as described in Proposal 2 in the Proxy Statement. If the proposal is approved by the Stockholders, reloads will no longer be available for options granted after February 13, 2003.

Aggregated Option Exercises in 2002 and December 31, 2002 Option Values

                The following table summarizes the number and value of all unexercised options held by the Named Executive Officers. The absence, in the table below, of any Named Executive Officer indicates that no options are held by such officer.

                                                        Number of Securities          Value of Unexercised
                                                  Underlying Unexercised Options      In-the-Money Options
                    Shares Acquired       Value       as of December 31, 2002     as of December 31, 2002(b)
       Name            on Exercise    Realized (a)  Exercisable    Unexercisable  Exercisable  Unexercisable

E. Renae Conley             -             $    -       32,366         69,734        $531,717      $504,753
Joseph F. Domino            -                  -       33,253         38,534         587,807       321,165
Donald C. Hintz        30,000            624,375      384,499        405,001       6,411,858     4,070,235
Jerry D. Jackson       45,927            930,553      118,304        122,834       1,279,375     1,093,644
J. Wayne Leonard            -                  -      585,600        661,200       9,916,842     5,671,994
Hugh T. McDonald            -                  -       24,500         43,401         436,784       431,111
Daniel F. Packer       30,083            492,005        4,933         36,534          42,374       313,365
Carolyn C. Shanks      10,351            163,659        4,933         36,534          42,374       313,365
C. John Wilder        108,041          1,943,277       75,824        175,401         355,895     1,504,658
Jerry W. Yelverton     57,766            913,970            -        147,968               -     1,147,271

1. Based on the difference between the closing price of Entergy's common stock on the New York Stock Exchange Composite Transactions on the exercise date and the option exercise price.
2. Based on the difference between the closing price of Entergy's common stock on the New York Stock Exchange Composite Transactions on December 31, 2002, and the option exercise price.

Long-Term Incentive Plan Awards in 2002

                The following table summarizes the awards of performance units (equivalent to shares of Entergy common stock) granted under the Equity Ownership Plan in 2002 to the Named Executive Officers.

			Estimated Future Payouts Under
			Non-Stock Price-Based Plans (# of units) (a) (b)
	Number of	Performance Period Until
Name	Units	Maturation or Payout	Threshold	Target	Maximum
E. Renae Conley	10,000	1/1/02-12/31/04	1,300	5,000	10,000
Joseph F. Domino	4,200	1/1/02-12/31/04	600	2,100	4,200
Donald C. Hintz	38,000	1/1/02-12/31/04	4,800	19,000	38,000
Jerry D. Jackson	17,000	1/1/02-12/31/04	2,200	8,500	17,000
J. Wayne Leonard	64,000	1/1/02-12/31/04	8,000	32,000	64,000
Hugh T. McDonald	4,200	1/1/02-12/31/04	600	2,100	4,200
Daniel F. Packer	4,200	1/1/02-12/31/04	600	2,100	4,200
Carolyn C. Shanks	4,200	1/1/02-12/31/04	600	2,100	4,200
C. John Wilder	17,000	1/1/02-12/31/04	2,200	8,500	17,000
Jerry W. Yelverton	17,000	1/1/02-12/31/04	2,200	8,500	17,000

1. Performance units awarded will vest at the end of a three-year period, subject to the attainment of approved performance goals for Entergy. Restrictions are lifted based upon the achievement of the cumulative result of these goals for the performance period. The value any Named Executive Officer may realize is dependent upon the number of units that vest, the future market price of Entergy common stock, and the dividends paid during the performance period.
2. The threshold, target, and maximum levels correspond to the achievement of 25%, 100%, and 200%, respectively, of Equity Ownership Plan goals. Achievement of a threshold, target, or maximum level would result in the award of the number of units indicated in the respective column. Achievement of a level between these three specified levels would result in the award of a number of units calculated by means of interpolation.

Pension Plan Tables

Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy

Retirement Income Plan Table

Annual Covered Compensation	Years of Service
	15	20	25	30	35
$100,000	$ 22,500	$ 30,000	$ 37,500	$ 45,000	$ 52,500
200,000	45,000	60,000	75,000	90,000	105,000
300,000	67,500	90,000	112,500	135,000	157,500
400,000	90,000	120,000	150,000	180,000	210,000
500,000	112,500	150,000	187,500	225,000	262,500
650,000	146,250	195,000	243,750	292,500	341,250
950,000	213,750	285,000	356,250	427,500	498,750

                All of the Named Executive Officers participate in a Retirement Income Plan, a defined benefit plan, that provides a benefit for employees at retirement from Entergy based upon (1) generally all years of service beginning at age 21 throughtermination, with a forty-year maximum, multiplied by (2) 1.5%, multiplied by (3) the final average compensation. Final average compensation is based on the highest consecutive 60 months of covered compensation in the last 120 months of service. The normal form of benefit for a single employee is a lifetime annuity and for a married employee is a 50% joint and survivor annuity. Other actuarially equivalent options are available to each retiree. Retirement benefits are not subject to any deduction for Social Security or other offset amounts. The amount of the Named Executive Officers' annual compensation covered by the plan as of December 31, 2002, is represented by the salary column in the Summary Compensation Table above.

                The credited years of service under the Retirement Income Plan, as of December 31, 2002, for the following Named Executive Officers is as follows: Mr. Domino 32; Mr. Jackson 23; Mr. Leonard 4; Mr. McDonald 20; Mr. Packer 20; Ms. Shanks 19; and Mr. Yelverton 23. The credited years of service under the Retirement Income Plan, as of December 31, 2002 for the following Named Executive Officers, as a result of entering into supplemental retirement agreements, is as follows: Ms. Conley 20; Mr. Hintz 31; and Mr. Wilder 19.

                The maximum benefit under the Retirement Income Plan is limited by Sections 401 and 415 of the Internal Revenue Code of 1986, as amended; however, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy have elected to participate in the Pension Equalization Plan sponsored by Entergy Corporation. Under this plan, certain executives, including the Named Executive Officers, would receive an additional amount equal to the benefit that would have been payable under the Retirement Income Plan, except for the Sections 401 and 415 limitations discussed above.

                In addition to the Retirement Income Plan discussed above, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy participate inthe Supplemental Retirement Plan of Entergy Corporation and Subsidiaries and the Post-Retirement Plan of Entergy Corporation and Subsidiaries. Participation is limited to one of these two plans and is at the invitation of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy. The participant may receive from the appropriate Entergy company a monthly benefit payment not in excess of .025 (under the Supplemental Retirement Plan) or .0333 (under the Post-Retirement Plan) times the participant's average basic annual salary (as defined in the plans) for a maximum of 120 months. Mr. Hintz, Mr. Packer and Mr. Yelverton have entered into a Supplemental Retirement Plan participation contract, and Mr. Jackson has entered into a Post-Retirement Plan part icipation contract. Current estimates indicate that the annual payments to each Named Executive Officer under the above plans would be less than the payments to that officer under the System Executive Retirement Plan discussed below.

System Executive Retirement Plan Table (1)

Annual Covered Compensation	Years of Service
	10	15	20	25	30+
$ 200,000	$ 60,000	$ 90,000	$ 100,000	$ 110,000	$ 120,000
300,000	90,000	135,000	150,000	165,000	180,000
400,000	120,000	180,000	200,000	220,000	240,000
500,000	150,000	225,000	250,000	275,000	300,000
600,000	180,000	270,000	300,000	330,000	360,000
700,000	210,000	315,000	350,000	385,000	420,000
1,000,000	300,000	450,000	500,000	550,000	600,000

(1) Covered pay includes the average of the highest three years of annual base pay and incentive awards earned by the executive during the ten years immediately preceding his retirement. Benefits shown are based on a target replacement ratio of 50% based on the years of service and covered compensation shown. The benefits for 10, 15, and 20 or more years of service at the 45% and 55% replacement levels would decrease (in the case of 45%) or increase (in the case of 55%) by the following percentages: 3.0%, 4.5%, and 5.0%, respectively.

                In 1993, Entergy Corporation adopted the System Executive Retirement Plan (SERP). This plan was amended in 1998. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy are participating employers in the SERP. The SERP is an unfunded defined benefit plan offered at retirement to certain senior executives, which would currently include all the Named Executive Officers (except for Mr. Leonard). Participating executives choose, at retirement, between the retirement benefits paid under provisions of the SERP or those payable under the Supplemental Retirement Plan or the Post-Retirement Plan discussed above. The plan was amended in 1998 to provide that covered pay is the average of the highest three years annual base pay and incentive awards earned by the executive during the ten years immediately preceding his retirement. Benefits paid under the SERP are calculated by multiplying the covered pay times target pay replacement ratios (45%, 50%, or 55%, dependent on job rating at retirement) that are attained, according to plan design, at 20 years of credited service. The target ratios are increased by 1% for each year of service over 20 years, up to a maximum of 30 years of service. In accordance with the SERP formula, the target ratios are reduced for each year of service below 20 years. The credited years of service under this plan are identical to the years of service for Named Executive Officers (other than Ms. Conley, Mr. Jackson, Mr. Wilder and Mr. Yelverton) disclosed above in the section entitled "Pension Plan Tables-Retirement Income Plan Table". Ms. Conley, Mr. Jackson, Mr. Wilder, and Mr. Yelverton have 3 years, 29 years, 4 years, and 33 years, respectively, of credited service under this plan.

                The amended plan provides that a single employee receives a lifetime annuity and a married employee receives the reduced benefit with a 50% surviving spouse annuity. Other actuarially equivalent options are available to each retiree. SERP benefits are offset by any and all defined benefit plan payments from Entergy. SERP benefits are not subject to Social Security offsets.

                Eligibility for and receipt of benefits under any of the executive plans described above are contingent upon several factors. The participant must agree, without the specific consent of the Entergy company for which such participant was last employed, not to take employment after retirement with any entity that is in competition with, or similar in nature to, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy or any affiliate thereof. Eligibility for benefits is forfeitable for various reasons, including violation of an agreement with Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, certain resignations of employment, or certain terminations of employment without Company permission.

Compensation of Directors

                For information regarding compensation of the directors of Entergy Corporation, see the Proxy Statement under the heading "Director Compensation", which information is incorporated herein by reference. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy currently have no non-employee directors, and none of the current directors of these companies

(1) Covered pay includes the average of the highest three years of annual base pay and incentive awards earned by the executive during the ten years immediately preceding his retirement. Benefits shown are based on a target replacement ratio of 50% based on the years of service and covered compensation shown. The benefits for 10, 15, and 20 or more years of service at the 45% and 55% replacement levels would decrease (in the case of 45%) or increase (in the case of 55%) by the following percentages: 3.0%, 4.5%, and 5.0%, respectively.

                In 1993, Entergy Corporation adopted the System Executive Retirement Plan (SERP). This plan was amended in 1998. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy are participating employers in the SERP. The SERP is an unfunded defined benefit plan offered at retirement to certain senior executives, which would currently include all the Named Executive Officers (except for Mr. Leonard). Participating executives choose, at retirement, between the retirement benefits paid under provisions of the SERP or those payable under the Supplemental Retirement Plan or the Post-Retirement Plan discussed above. The plan was amended in 1998 to provide that covered pay is the average of the highest three years annual base pay and incentive awards earned by the executive during the ten years immediately preceding his retirement. Benefits paid under the SERP are calculated by multiplying the covered pay times target pay replacement ratios (45%, 50%, or 55%, dependent on job rating at retirement) that are attained, according to plan design, at 20 years of credited service. The target ratios are increased by 1% for each year of service over 20 years, up to a maximum of 30 years of service. In accordance with the SERP formula, the target ratios are reduced for each year of service below 20 years. The credited years of service under this plan are identical to the years of service for Named Executive Officers (other than Ms. Conley, Mr. Jackson, Mr. Wilder and Mr. Yelverton) disclosed above in the section entitled "Pension Plan Tables-Retirement Income Plan Table". Ms. Conley, Mr. Jackson, Mr. Wilder, and Mr. Yelverton have 3 years, 29 years, 4 years, and 33 years, respectively, of credited service under this plan.

                The amended plan provides that a single employee receives a lifetime annuity and a married employee receives the reduced benefit with a 50% surviving spouse annuity. Other actuarially equivalent options are available to each retiree. SERP benefits are offset by any and all defined benefit plan payments from Entergy. SERP benefits are not subject to Social Security offsets.

                Eligibility for and receipt of benefits under any of the executive plans described above are contingent upon several factors. The participant must agree, without the specific consent of the Entergy company for which such participant was last employed, not to take employment after retirement with any entity that is in competition with, or similar in nature to, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy or any affiliate thereof. Eligibility for benefits is forfeitable for various reasons, including violation of an agreement with Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, certain resignations of employment, or certain terminations of employment without Company permission.

Compensation of Directors

                For information regarding compensation of the directors of Entergy Corporation, see the Proxy Statement under the heading "Director Compensation", which information is incorporated herein by reference. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy currently have no non-employee directors, and none of the current directors of these companiesare compensated for their responsibilities as director.

                Retired non-employee directors of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans with a minimum of five years of service on the respective Boards of Directors are paid $200 a month for a term of years corresponding to the number of years of active service as directors. Retired non-employee directors with over ten years of service receive a lifetime benefit of $200 a month. Years of service as an advisory director are included in calculating this benefit. System Energy has no retired non-employee directors.

                Retired non-employee directors of Entergy Gulf States receive retirement benefits under a plan in which all directors who served continuously for a period of years will receive a percentage of their retainer fee in effect at the time of their retirement for life. The retirement benefit is 30 percent of the retainer fee for service of not less than five nor more than nine years, 40 percent for service of not less than ten nor more than fourteen years, and 50 percent for fifteen or more years of service. For those directors who retired prior to the retirement age, their benefits are reduced. The plan also provides disability retirement and optional hospital and medical coverage if the director has served at least five years prior to the disability. The retired director pays one-third of the premium for such optional hospital and medical coverage and Entergy Gulf States pays the remaining two-thirds. Years of service as an advisory director are included in calculating this benefit.

Executive Retention and Employment Agreements and Change-in-Control Arrangements

Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy

                Upon completion of a transaction resulting in a change-in-control of Entergy (a "Merger"), benefits already accrued under Entergy's System Executive Retirement Plan, Post-Retirement Plan, Supplemental Retirement Plan and Pension Equalization Plan will become fully vested if the participant is involuntarily terminated without "cause" or terminates employment for "good reason" (as such terms are defined in such plans).

Retention Agreement with Mr. Leonard - The retention agreement with Mr. Leonard provides that upon a termination of employment while a Merger is pending (a) by Entergy without "cause" or by Mr. Leonard for "good reason", as such terms are defined in the agreement, other than a termination of employment described in the next paragraph, or (b) by reason of Mr. Leonard's death or disability:

• Entergy will pay to him a lump sum cash severance payment equal to three times (in limited circumstances, five times) the sum of Mr. Leonard's base salary and target annual incentive award;

• Entergy will pay to him a pro rata annual incentive award, based on an assumed maximum annual achievement of applicable performance goals;

• his supplemental retirement benefit will fully vest, will be determined as if he had remained employed with Entergy until the attainment of age 55, and will commence upon his attainment of age 55;

• he will be entitled to immediate payment of performance awards, based upon an assumed target achievement of applicable performance goals;

• all of his stock options will become fully vested and will remain outstanding for their full ten-year term; and

• Entergy will pay to him a "gross-up" payment in respect of any excise taxes he might incur.

                If Mr. Leonard's employment is terminated by Entergy for "cause" at any time, or by Mr. Leonard without "good reason" and without Entergy's permission prior to his attainment of age 55, Mr. Leonard will forfeit his supplemental retirement benefit. If Mr. Leonard's employment is terminated by Mr. Leonard without "good reason" with Entergy's permission prior to his attainment of age 55, Mr. Leonard will be entitled to a supplemental retirement benefit, reduced by 6.5% for each year that the termination date precedes his attainment of age 55, payable commencing upon Mr. Leonard's attainment of age 62. If Mr. Leonard's employment is terminated by Mr. Leonard without "good reason" following his attainment of age 55, Mr. Leonard will be entitled to his full supplemental retirement benefit. The amounts payable under the agreement will be funded in a rabbi trust.

Retention agreement with Mr. Hintz - The retention agreement with Mr. Hintz provides that Mr. Hintz will be paid an initial retention payment of approximately $2.8 million on the date on which a Merger is completed and an additional retention payment of approximately $2.3 million on the second anniversary of the completion of a Merger if he remains employed on each of those dates. The agreement also provides that upon termination of employment while a Merger is pending and for two years after completion (a) by Mr. Hintz for "good reason" or by Entergy without "cause", as such terms are defined in the agreement or (b) by reason of Mr. Hintz's death or disability:

• Entergy will pay to him a lump sum cash severance payment equal to $2.8 million if such termination occurs prior to completion of a Merger or equal to $2.3 million if such termination occurs following completion of a Merger;

• Entergy will pay to him a pro rata annual incentive award, based on an assumed maximum achievement of applicable performance goals, if such termination occurs following completion of a Merger;

• he will be entitled to immediate payment of performance awards based upon an assumed target achievement of applicable performance goals, if such termination occurs prior to completion of a Merger, or based upon an assumed maximum achievement of applicable performance goals, if such termination occurs following completion of a Merger;

• all of his stock options will become fully vested and will remain outstanding for their full ten-year term;

• he will be entitled to receive a supplemental retirement benefit that, when combined with Mr. Hintz's SERP benefit, equals the benefit he would have earned under the terms of the SERP as in effect immediately prior to March 25, 1998; and

• Entergy will pay to him a "gross-up" payment in respect of any excise taxes he might incur.

Retention Agreement with Mr. Jackson - The retention agreement with Mr. Jackson provides that upon retirement in accordance with the agreement, Mr. Jackson: (a) will be entitled to a subsidized retirement benefit equal to the applicable nonqualified retirement benefit payable to Mr. Jackson without reduction for early retirement ("Subsidized Retirement Benefit"); and (b) may enter into a consulting arrangement with Entergy through March 31, 2005, under terms and conditions set forth in the agreement.

                Pursuant to the agreement, should Mr. Jackson experience a Qualifying Event (as defined in the agreement) after the Successor Placement Date (as defined in the agreement) but before March 31, 2003, he shall not be entitled to benefits under the System Executive Continuity Plan but shall instead be entitled to the following:

• a lump sum amount equal to any unpaid base salary that would otherwise have been paid through March 31, 2003;

• the Subsidized Retirement Benefit; and

• all other benefits to which he may be entitled under the terms and conditions of those Entergy plans and programs in which he participates in accordance with the agreement.

                Additionally, Mr. Jackson is entitled to certain benefits, as described in the agreement, in the event of a change in control (as defined in the System Executive Continuity Plan) after which Entergy or its successor company fails to honor Mr. Jackson's consulting arrangement.

Retention Agreement with Mr. Wilder - The retention agreement with Mr. Wilder provides that if Mr. Wilder terminates his employment without "good reason" and prior to a termination for "cause," as those terms are defined in his agreement, Entergy will pay to him a lump sum cash severance payment equal to three times the sum of his base salary and target annual award and a "gross-up" payment in respect of any excise taxes he might incur.

                The agreement also provides that, as a substitute for the above entitlement, upon termination of employment (a) by Mr. Wilder for "good reason" or by Entergy without "cause", as such terms are defined in the agreement, in each case prior to the termination of a Merger or prior to the second anniversary of the completion of a Merger, (b) by reason of Mr. Wilder's death or disability while a Merger is pending and for two years after completion of a Merger or (c) for any reason following the second anniversary of a Merger:

• Mr. Wilder will be entitled to a lump sum cash severance payment equal to four times (in limited circumstances, three times) the sum of the his base salary and maximum annual incentive award;

• Mr. Wilder will be entitled to a pro rata annual incentive award, based on an assumed maximum achievement of applicable performance goals;

• except in the case of a termination by reason of death or disability, he will continue to be employed as a Special Project Coordinator at an annual base salary of $200,000, and will continue to participate in all of Entergy's benefit plans, until the earliest of (a) his attainment of age 55 (at which time he will be deemed eligible to retire under Entergy's plans then in effect), (b) his employment with a company listed in the Fortune Global 500 Index or (c) his employment with any company that has a conflict of interest policy that would prohibit his continued employment with Entergy;

• Entergy will credit him with 15 additional years of service under Entergy's supplemental retirement plan and he may elect to receive either (a) approximately $1.9 million in a cash lump sum in full settlement of all nonqualified retirement benefits or (b) the benefit that he would have earned under the terms of the SERP applicable to individuals who became participants on or after March 25, 1998 (which amount he may elect to receive upon completion of a Merger);

• he will be entitled to immediate vesting of performance awards, based upon an assumed maximum achievement of applicable performance goals;

• all of his stock options will become fully vested and will remain outstanding for their full ten-year term; and

• he will be entitled to a "gross-up" payment in respect of any excise taxes he might incur.

                If Mr. Wilder terminates employment without good reason and other than on account of death or disability, on or after the completion of a Merger and before the second anniversary of the completion of a Merger:

• Mr. Wilder is entitled to a lump sum cash severance payment equal to three times the sum of his base salary and target annual incentive award;

• Mr. Wilder is entitled to a pro rata annual incentive award, based on an assumed maximum achievement of applicable performance goals;

• he will continue to be employed as a Special Project Coordinator at an annual base salary of $200,000, and will continue to participate in all of Entergy's benefit plans, until the earliest of (a) his attainment of age 55 (at which time he will be deemed eligible to retire under Entergy's plans then in effect), (b) his employment with a company listed in the Fortune Global 500 Index or (c) his employment with any company that has a conflict of interest policy that would prohibit his continued employment with Entergy;

• Entergy will credit him with 15 additional years of service under Entergy's supplemental retirement plan and he may elect either (a) approximately $1.9 million in a cash lump sum in full settlement of all nonqualified retirement benefits or (b) the benefit that he would have earned under the terms of the SERP applicable to individuals who became participants on or after March 25, 1998 (which amount he may elect to receive upon completion of a Merger);

• he will be entitled to immediate vesting of performance awards, based upon an assumed target achievement of applicable performance goals;

• all of his stock options will become fully vested and will remain outstanding for their full ten-year term; and

• he will be entitled to a "gross-up" payment in respect of any excise taxes he might incur.

Retention Agreement with Mr. Yelverton - The retention agreement with Mr. Yelverton provides that he will be paid cash retention payments of $680,000 on each of the first three anniversaries of the completion of a Merger if he remains employed on each of those dates. The agreement also provides that upon termination of employment while a Merger is pending and for three years after completion (a) by Mr. Yelverton for "good reason" or by Entergy without "cause", as such terms are defined in the agreement or (b) by reason of Mr. Yelverton's death or disability:

• Entergy will pay him a lump sum cash severance payment equal to the remaining unpaid portion of the cash retention payments;

• he will be entitled to immediate payment of performance awards, based upon an assumed target achievement of applicable performance goals;

• all of his stock options will become fully vested and will remain outstanding for their full ten-year term; and

• Entergy will pay to him a "gross-up" payment in respect of any excise taxes he might incur.

System Executive Continuity Plan - Ms. Conley, Mr. Domino, Mr. McDonald, Mr. Packer and Ms. Shanks are participants in Entergy's System Executive Continuity Plan, which provides severance pay and benefits under specified circumstances following a change in control. In the event a participant's employment is involuntarily terminated without cause or if a participant terminates for good reason during the change in control period, the participant will be entitled to:

• a cash severance payment equal to 1-3 times (depending on the participant's System Management Level) base annual salary and target award payable over a continuation period of 1-3 years (depending on the participant's System Management Level);

• continued medical and dental insurance coverage for the continuation period (subject to offset for any similar coverage provided by the participant's new employer);

• immediate vesting of performance awards, based upon an assumed achievement of applicable performance targets; and

• payment of a "gross-up" payment in respect of any excise taxes the participant might incur.

                Participants in the Continuity Plan are subject to post-employment restrictive covenants, including noncompetition provisions, which run for two years for executive officers, but extend to three years if permissible under applicable law.

Personnel Committee Interlocks and Insider Participation

                The compensation of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy executive officers was set by the Personnel Committee of Entergy Corporation's Board of Directors, composed solely of Directors of Entergy Corporation.

Item 12.Security Ownership of Certain Beneficial Owners and Management

                Entergy Corporation owns 100% of the outstanding common stock of registrants Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy. The information with respect to persons known by Entergy Corporation to be beneficial owners of more than 5% of Entergy Corporation's outstanding common stock is included under the heading "Stockholders Who Own at Least Five Percent" in the Proxy Statement, which information is incorporated herein by reference. The registrants know of no contractual arrangements that may, at a subsequent date, result in a change in control of any of the registrants.

                As of December 31, 2002, the directors, the Named Executive Officers, and the directors and officers as a group for Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, respectively, beneficially owned directly or indirectly common stock of Entergy Corporation as indicated:

	Entergy Corporation Common Stock Amount and Nature of Beneficial Ownership(a)		Entergy Corporation Stock Equivalent Units (c)
Name	Sole Voting and Investment Power	Other  Beneficial Ownership(b)
Entergy Corporation
Maureen S. Bateman*	1,500	-	1,600
W. Frank Blount*	8,034	-	12,000
George W. Davis*	2,700	-	3,200
Simon D. deBree*	568	-	800
Claiborne P. Deming*	500	-	-
Frank F. Gallaher**	8,519	63,167	66,097
Alexis Herman*	(f)	-	-
Donald C. Hintz**	4,055	549,499	52,192
Jerry D. Jackson**	22,083	181,136	47,374
J. Wayne Leonard***	13,065	916,200	496
Robert v.d. Luft*	23,272	268,998	8,000
Kathleen A. Murphy*	1,500	1,000 (e)	1,600
Paul W. Murrill*	2,740 (d)	-	12,800
James R. Nichols*	10,673	-	12,800
William A. Percy, II*	1,750	-	1,600
Dennis H. Reilley*	600 (d)	-	2,400
Wm. Clifford Smith*	11,335	-	15,200
Bismark A. Steinhagen*	8,224	2,623 (e)	22,400
C. John Wilder**	798	163,524	119,673
All directors and executive
officers	137,842	2,591,229	532,251

	Entergy Corporation Common Stock Amount and Nature of Beneficial Ownership(a)		Entergy Corporation Stock Equivalent Units (c)
Name	Sole Voting and Investment Power	Other  Beneficial Ownership(b)
Entergy Arkansas
Donald C Hintz***	4,055	549,499	52,192
Jerry D. Jackson**	22,083	181,136	47,374
J. Wayne Leonard**	13,065	916,200	496
Hugh T. McDonald***	4,122	48,300	6,786
Richard J. Smith*	574	111,201	25,364
C. John Wilder***	798	163,524	119,673
All directors and executive
officers	77,397	2,376,306	440,436
Entergy Gulf States
E. Renae Conley***	1,444	63,899	17,100
Joseph F. Domino***	11,889	52,186	11,833
Donald C. Hintz***	4,055	549,499	52,192
Jerry D. Jackson**	22,083	181,136	47,374
J. Wayne Leonard**	13,065	916,200	496
Richard J. Smith*	574	111,201	25,364
C. John Wilder***	798	163,524	119,673
All directors and executive
officers	96,542	2,531,339	464,678
Entergy Louisiana
E. Renae Conley***	1,444	63,899	17,100
Donald C. Hintz***	4,055	549,499	52,192
Jerry D. Jackson**	22,083	181,136	47,374
J. Wayne Leonard**	13,065	916,200	496
Richard J. Smith*	574	111,201	25,364
C. John Wilder***	798	163,524	119,673
All directors and executive
officers	80,682	2,445,020	452,571
Entergy Mississippi
Donald C. Hintz***	4,055	549,499	52,192
Jerry D. Jackson**	22,083	181,136	47,374
J. Wayne Leonard**	13,065	916,200	496
Carolyn C. Shanks***	4,371	23,199	3,043
Richard J. Smith*	574	111,201	25,364
C. John Wilder***	798	163,524	119,673
All directors and executive
officers	80,522	2,370,341	439,263

	Entergy Corporation Common Stock Amount and Nature of Beneficial Ownership(a)		Entergy Corporation Stock Equivalent Units (c)
Name	Sole Voting and Investment Power	Other  Beneficial Ownership(b)
Entergy New Orleans
Donald C. Hintz***	4,055	549,499	52,192
Jerry D. Jackson**	22,083	181,136	47,374
J. Wayne Leonard**	13,065	916,200	496
Daniel F. Packer***	3,691	23,199	3,884
Richard J. Smith*	574	111,201	25,364
C. John Wilder***	798	163,524	119,673
All directors and executive
officers	71,774	2,328,340	437,529
System Energy
Donald C. Hintz***	4,055	549,499	52,192
Jerry D. Jackson**	22,083	181,136	47,374
J. Wayne Leonard**	13,065	916,200	496
C. John Wilder***	798	163,524	119,673
Jerry W. Yelverton***	9,312	69,634	19,088
All directors and executive
officers	65,438	2,025,817	283,099

    * Director of the respective Company

  ** Named Executive Officer of the respective Company

*** Director and Named Executive Officer of the respective Company

1. Based on information furnished by the respective individuals. Except as noted, each individual has sole voting and investment power. The number of shares of Entergy Corporation common stock owned by each individual and by all directors and executive officers as a group does not exceed one percent of the outstanding Entergy Corporation common stock.
2. Other Beneficial Ownership includes, for the Named Executive Officers, shares of Entergy Corporation common stock that may be acquired within 60 days after December 31, 2002, in the form of unexercised stock options awarded pursuant to the Equity Ownership Plan.
3. Represents the balances of stock equivalent units each executive holds under the Executive Annual Incentive Plan Deferral Program, Defined Contribution Restoration Plan, and the Executive Deferred Compensation Plan. These units will be paid out in a combination of Entergy Corporation Common Stock and cash based on the value of Entergy Corporation Common Stock on the date of payout. The deferral period is determined by the individual and is at least two years from the award of the bonus. For directors of Entergy Corporation the stock equivalent units are part of the Service Award for Directors. All non-employee directors are credited with 800 units for each year of service on the Board.
4. Dr. Murrill and Mr. Reilley have deferred receipt of an additional 4,500 shares and 1,500 shares, respectively.
5. Includes 1,000 shares in which Ms. Murphy has joint ownership and 2,623 shares for Mr. Steinhagen that are in his wife's name.
6. Ms. Herman is a nominee and does not own any shares of Entergy 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. The following table summarizes information about Entergy's stock options awarded under these plans.

Plan	Number of Securities to be Issued Upon Exerciseof Outstanding Options	Weighted Average ExercisePrice	Number of Securities Remaining Available forFuture Issuance
Equity Ownership Plan	3,963,349	$ 34.96	8,614,275
Equity Awards Plan	15,979,765	36.07	5,671,792
Total	19,943,114	$ 35.85	14,286,067

Item 13.Certain Relationships and Related Transactions

                During 2002, T. Baker Smith & Son, Inc. performed land-surveying services for, and received payments of approximately $287,000 from Entergy companies. Mr. Wm. Clifford Smith, a director of Entergy Corporation, is Chairman of the Board of T. Baker Smith & Son, Inc. Mr. Smith's children own 100% of the voting stock of T. Baker Smith & Son, Inc.

                See Item 10, "Directors and Executive Officers of the Registrants," for information on certain relationships and transactions required to be reported under this item.

                Other than as provided under applicable corporate laws, Entergy does not have policies whereby transactions involving executive officers and directors are approved by a majority of disinterested directors. However, pursuant to the Entergy Corporation Code of Conduct, transactions involving an Entergy company and its executive officers must have prior approval by the next higher reporting level of that individual, and transactions involving an Entergy company and its directors must be reported to the secretary of the appropriate Entergy company.

PART IV

Item 14. Controls and Procedures

Within the 90-day period prior to the filing of this report, evaluations were performed under the supervision and with the participation of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy Resources (individually "Registrant" and collectively the "Registrants") management, including their respective Chief Executive Officers (CEO) and Chief Financial Officers (CFO). The evaluations assessed the effectiveness of the Registrants' disclosure controls and procedures. Based on the evaluations, each CEO and CFO has concluded that, as to the Registrant or Registrants for which they serve as CEO or CFO, the Registrants' disclosure controls and procedures are effective to ensure that information required to be disclosed by each Registrant in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securiti es and Exchange Commission rules and forms. Subsequent to the date of the evaluations, there were no significant changes in the Registrants' internal controls or in other factors that could significantly affect the disclosure controls, including any corrective actions with regard to significant deficiencies and material weaknesses.

Item 15.Exhibits, Financial Statement Schedules, and Reports on Form 8-K

(a)1.	Financial Statements and Independent Auditors' Reports for Entergy, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy are listed in the Table of Contents.
(a)2.	Financial Statement Schedules Reports of Independent Accountants on Financial Statement Schedules (see page 347) Financial Statement Schedules are listed in the Index to Financial Statement Schedules (see page S-1)
(a)3.	Exhibits Exhibits for Entergy, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy are listed in the Exhibit Index (see page E-1). Each management contract or compensatory plan or arrangement required to be filed as an exhibit hereto is identified as such by footnote in the Exhibit Index.
(b)	Reports on Form 8-K
	Entergy Corporation
	A Current Report on Form 8-K, dated January 14, 2003, was filed with the SEC on January 14, 2003, reporting information under Item 7. "Financial Statements, Pro Forma Financial Statements and Exhibits" and Item 9. "Regulation FD Disclosure."
	Entergy Corporation
	A Current Report on Form 8-K, dated February 4, 2003, was filed with the SEC on February 4, 2003, reporting information under Item 7. "Financial Statements, Pro Forma Financial Statements and Exhibits" and Item 9. "Regulation FD Disclosure."

ENTERGY CORPORATION

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

ENTERGY CORPORATION


By /s/ Nathan E. Langston
Nathan E. Langston, Senior Vice President
and Chief Accounting Officer

Date: March 17, 2003

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	Title	Date
/s/ Nathan E. Langston Nathan E. Langston	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 17, 2003

J. Wayne Leonard (Chief Executive Officer and Director; Principal Executive Officer); Robert v.d. Luft (Chairman of the Board and Director); C. John Wilder (Executive Vice President and Chief Financial Officer; Principal Financial Officer); Maureen S. Bateman, W. Frank Blount, George W. Davis, Simon deBee, Claiborne P. Deming, Norman C. Francis, Kathleen A. Murphy, Paul W. Murrill, James R. Nichols, William A. Percy, II, Dennis H. Reilley, Wm. Clifford Smith, and Bismark A. Steinhagen (Directors).

By:/s/ Nathan E. Langston
(Nathan E. Langston, Attorney-in-fact) March 17, 2003

ENTERGY ARKANSAS, INC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

ENTERGY ARKANSAS, INC.


By /s/ Nathan E. Langston
Nathan E. Langston, Senior Vice President
and Chief Accounting Officer

Date: March 17, 2003

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	Title	Date
/s/ Nathan E. Langston Nathan E. Langston	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 17, 2003

Hugh T. McDonald (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Theodore H. Bunting, Jr. (Vice President and Chief Financial Officer; Principal Financial Officer); Donald C. Hintz, Richard J. Smith, and C. John Wilder (Directors).

By:/s/ Nathan E. Langston
(Nathan E. Langston, Attorney-in-fact) March 17, 2003

ENTERGY GULF STATES, INC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

ENTERGY GULF STATES, INC.


By /s/ Nathan E. Langston
Nathan E. Langston, Senior Vice President
and Chief Accounting Officer

Date: March 17, 2003

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	Title	Date
/s/ Nathan E. Langston Nathan E. Langston	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 17, 2003

Joseph F. Domino (Chairman of the Board, President, Chief Executive Officer-Texas, and Director; Principal Executive Officer); E. Renae Conley (President, Chief Executive Officer-Louisiana, and Director; Principal Executive Officer); Theodore H. Bunting, Jr. (Vice President and Chief Financial Officer; Principal Financial Officer); Donald C. Hintz, Richard J. Smith, and C. John Wilder (Directors).

By:/s/ Nathan E. Langston
(Nathan E. Langston, Attorney-in-fact) March 17, 2003

ENTERGY LOUISIANA, INC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

ENTERGY LOUISIANA, INC.


By /s/ Nathan E. Langston
Nathan E. Langston, Senior Vice President
and Chief Accounting Officer

Date: March 17, 2003

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	Title	Date
/s/ Nathan E. Langston Nathan E. Langston	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 17, 2003

E. Renae Conley (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Theodore H. Bunting, Jr. (Vice President and Chief Financial Officer; Principal Financial Officer); Donald C. Hintz, Richard J. Smith, and C. John Wilder (Directors).

By:/s/ Nathan E. Langston
(Nathan E. Langston, Attorney-in-fact) March 17, 2003

ENTERGY MISSISSIPPI, INC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

ENTERGY MISSISSIPPI, INC.


By /s/ Nathan E. Langston
Nathan E. Langston, Senior Vice President
and Chief Accounting Officer

Date: March 17, 2003

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	Title	Date
/s/ Nathan E. Langston Nathan E. Langston	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 17, 2003

Carolyn C. Shanks (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Theodore H. Bunting, Jr. (Vice President and Chief Financial Officer; Principal Financial Officer); Donald C. Hintz, Richard J. Smith, and C. John Wilder (Directors).

By:/s/ Nathan E. Langston
(Nathan E. Langston, Attorney-in-fact) March 17, 2003

ENTERGY NEW ORLEANS, INC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

ENTERGY NEW ORLEANS, INC.


By /s/ Nathan E. Langston
Nathan E. Langston, Senior Vice President
and Chief Accounting Officer

Date: March 17, 2003

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	Title	Date
/s/ Nathan E. Langston Nathan E. Langston	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 17, 2003

Daniel F. Packer (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Theodore H. Bunting, Jr. (Vice President and Chief Financial Officer; Principal Financial Officer); Donald C. Hintz, Richard J. Smith, and C. John Wilder (Directors).

By:/s/ Nathan E. Langston
(Nathan E. Langston, Attorney-in-fact) March 17, 2003

SYSTEM ENERGY RESOURCES, INC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

SYSTEM ENERGY RESOURCES, INC.


By /s/ Nathan E. Langston
Nathan E. Langston, Senior Vice President
and Chief Accounting Officer

Date: March 17, 2003

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	Title	Date
/s/ Nathan E. Langston Nathan E. Langston	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 17, 2003

Jerry W. Yelverton (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); C. John Wilder (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Donald C. Hintz (Director).

By:/s/ Nathan E. Langston
(Nathan E. Langston, Attorney-in-fact) March 17, 2003

CERTIFICATIONS

I, J. Wayne Leonard, certify that:

1. I have reviewed this annual report on Form 10-K of Entergy Corporation;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to
    make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period
    covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material
    respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
    Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

    a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated
        subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

    b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual
        report (the "Evaluation Date"); and

    c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of
        the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit
    committee of registrant's board of directors (or persons performing the equivalent function):

    a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process,
        summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

    b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls;
        and

6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in    
    other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions
    with regard to significant deficiencies and material weaknesses.

/s/ J. Wayne Leonard
J. Wayne Leonard
Chief Executive Officer of Entergy Corporation

Date: March 17, 2003

CERTIFICATIONS

I, C. John Wilder, certify that:

1. I have reviewed these annual reports on Form 10-K of Entergy Corporation and System Energy Resources, Inc.;

2. Based on my knowledge, these annual reports do not contain any untrue statement of a material fact or omit to state a material fact necessary to
    make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period
    covered by these annual reports;

3. Based on my knowledge, the financial statements, and other financial information included in these annual reports, fairly present in all material
    respects the financial condition, results of operations and cash flows of the registrants as of, and for, the periods presented in these annual reports;

4. The registrants' other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
    Exchange Act Rules 13a-14 and 15d-14) for the registrants and we have:

    a) designed such disclosure controls and procedures to ensure that material information relating to the registrants, including its consolidated
        subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

    b) evaluated the effectiveness of the registrants' disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual
        report (the "Evaluation Date"); and

    c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of
        the Evaluation Date;

5. The registrants' other certifying officers and I have disclosed, based on our most recent evaluation, to the registrants' auditors and the audit
    committee of registrants' board of directors (or persons performing the equivalent function):

    a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrants' ability to record, process,
        summarize and report financial data and have identified for the registrants' auditors any material weaknesses in internal controls; and

    b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants' internal controls;
        and

6. The registrants' other certifying officers and I have indicated in these annual reports whether there were significant changes in internal controls or in
    other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions
    with regard to significant deficiencies and material weaknesses.

/s/ C. John Wilder
C. John Wilder
Executive Vice President and Chief Financial Officer of
Entergy Corporation and System Energy Resources, Inc.

Date: March 17, 2003

CERTIFICATIONS

I, Hugh T. McDonald, certify that:

1. I have reviewed this annual report on Form 10-K of Entergy Arkansas, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to
    make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period
    covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material
    respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
    Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

    a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated
        subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

    b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual
        report (the "Evaluation Date"); and

    c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of
        the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit
    committee of registrant's board of directors (or persons performing the equivalent function):

    a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process,
        summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

    b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls;
        and

6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in
    other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions
    with regard to significant deficiencies and material weaknesses.

/s/ Hugh T. McDonald
Hugh T. McDonald
Chairman, President, and Chief Executive Officer of
Entergy Arkansas, Inc.

Date: March 17, 2003

CERTIFICATIONS

I, Joseph F. Domino, certify that:

1. I have reviewed this annual report on Form 10-K of Entergy Gulf States, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to
    make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period
    covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material
    respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
    Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

    a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated
        subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

    b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual
        report (the "Evaluation Date"); and

    c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of
        the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit
    committee of registrant's board of directors (or persons performing the equivalent function):

    a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process,
        summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

    b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls;
        and

6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in
    other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions
    with regard to significant deficiencies and material weaknesses.

/s/ Joseph F. Domino
Joseph F. Domino
Chairman, President and Chief Executive Officer-Texas of
Entergy Gulf States, Inc.

Date: March 17, 2003

CERTIFICATIONS

I, E. Renae Conley, certify that:

1. I have reviewed these annual reports on Form 10-K of Entergy Gulf States, Inc. and Entergy Louisiana, Inc.;

2. Based on my knowledge, these annual reports do not contain any untrue statement of a material fact or omit to state a material fact necessary to
    make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period
    covered by these annual reports;

3. Based on my knowledge, the financial statements, and other financial information included in these annual reports, fairly present in all material
    respects the financial condition, results of operations and cash flows of the registrants as of, and for, the periods presented in these annual reports;

4. The registrants' other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
    Exchange Act Rules 13a-14 and 15d-14) for the registrants and we have:

    a) designed such disclosure controls and procedures to ensure that material information relating to the registrants, including its consolidated
        subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

    b) evaluated the effectiveness of the registrants' disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual
        report (the "Evaluation Date"); and

    c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of
        the Evaluation Date;

5. The registrants' other certifying officers and I have disclosed, based on our most recent evaluation, to the registrants' auditors and the audit
    committee of registrants' board of directors (or persons performing the equivalent function):

    a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrants' ability to record, process,
        summarize and report financial data and have identified for the registrants' auditors any material weaknesses in internal controls; and

    b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants' internal controls;
        and

6. The registrants' other certifying officers and I have indicated in these annual reports whether there were significant changes in internal controls or in
    other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions
    with regard to significant deficiencies and material weaknesses.

/s/ E. Renae Conley
E. Renae Conley
Chairman, President, and Chief Executive Officer of
Entergy Louisiana, Inc.; President and Chief Executive
Officer-Louisiana of Entergy Gulf States, Inc.

Date: March 17, 2003

CERTIFICATIONS

I, Carolyn C. Shanks, certify that:

1. I have reviewed this annual report on Form 10-K of Entergy Mississippi, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to
    make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period
    covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material
    respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
    Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

    a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated
        subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

    b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual
        report (the "Evaluation Date"); and

    c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of
        the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit
    committee of registrant's board of directors (or persons performing the equivalent function):

    a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process,
        summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

    b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls;
        and

6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in
    other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions
    with regard to significant deficiencies and material weaknesses.

/s/ Carolyn C. Shanks
Carolyn C. Shanks
Chairman, President, and Chief Executive Officer of
Entergy Mississippi, Inc.

Date: March 17, 2003

CERTIFICATIONS

I, Daniel F. Packer, certify that:

1. I have reviewed this annual report on Form 10-K of Entergy New Orleans, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to
    make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period
    covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material
    respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
    Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

    a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated
        subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

    b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual
        report (the "Evaluation Date"); and

    c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of
        the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit
    committee of registrant's board of directors (or persons performing the equivalent function):

    a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process,
        summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

    b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls;
        and

6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in
    other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions
    with regard to significant deficiencies and material weaknesses.

/s/ Daniel F. Packer
Daniel F. Packer
Chairman, President, and Chief Executive Officer of
Entergy New Orleans, Inc.

Date: March 17, 2003

CERTIFICATIONS

I, Jerry W. Yelverton, certify that:

1. I have reviewed this annual report on Form 10-K of System Energy Resources, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to
    make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period
    covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material
    respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
    Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

    a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated
        subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

    b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual
        report (the "Evaluation Date"); and

    c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of
        the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit
    committee of registrant's board of directors (or persons performing the equivalent function):

    a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process,
        summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

    b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls;
        and

6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in
    other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions
    with regard to significant deficiencies and material weaknesses.

/s/ Jerry W. Yelverton
Jerry W. Yelverton
Chairman, President, and Chief Executive Officer of
System Energy Resources, Inc.

Date: March 17, 2003

CERTIFICATIONS

I, Theodore H. Bunting, Jr., certify that:

1. I have reviewed these annual reports on Form 10-K of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy
    Mississippi, Inc., and Entergy New Orleans, Inc.;

2. Based on my knowledge, these annual reports do not contain any untrue statement of a material fact or omit to state a material fact necessary to
    make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period
    covered by these annual reports;

3. Based on my knowledge, the financial statements, and other financial information included in these annual reports, fairly present in all material
    respects the financial condition, results of operations and cash flows of the registrants as of, and for, the periods presented in these annual reports;

4. The registrants' other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
    Exchange Act Rules 13a-14 and 15d-14) for the registrants and we have:

    a) designed such disclosure controls and procedures to ensure that material information relating to the registrants, including its consolidated
        subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

    b) evaluated the effectiveness of the registrants' disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual
        report (the "Evaluation Date"); and

    c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of
        the Evaluation Date;

5. The registrants' other certifying officers and I have disclosed, based on our most recent evaluation, to the registrants' auditors and the audit
    committee of registrants' board of directors (or persons performing the equivalent function):

    a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrants' ability to record, process,
        summarize and report financial data and have identified for the registrants' auditors any material weaknesses in internal controls; and

    b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants' internal controls;
        and

6. The registrants' other certifying officers and I have indicated in these annual reports whether there were significant changes in internal controls or
    in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions
    with regard to significant deficiencies and material weaknesses.

/s/ Theodore H. Bunting, Jr.
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.

Date: March 17, 2003

EXHIBIT 23(a)

INDEPENDENT AUDITORS' CONSENTS

We consent to the incorporation by reference in Post-Effective Amendments No. 3 and 5A on Form S-8 and their related prospectuses to Registration Statement No. 33-54298 on Form S-4, Registration Statements No. 333-02503 and 333-22007 of Entergy Corporation on Form S-3 and Registration Statements No. 333-98179, 333-90914, 333-75097, 333-55692, and 333-68950 of Entergy Corporation on Form S-8 of our report dated February 21, 2003, which report includes an explanatory paragraph regarding the Corporation's change in 2002 in the method of accounting for goodwill and intangible assets and the change in 2001 in the method of accounting for derivative instruments, appearing in this Annual Report on Form 10-K of Entergy Corporation for the year ended December 31, 2002.

We consent to the incorporation by reference in Registration Statements No. 33-50289, 333-00103, 333-05045 and 333-39018 of Entergy Arkansas, Inc. on Form S-3 of our report dated February 21, 2003, appearing in this Annual Report on Form 10-K of Entergy Arkansas, Inc. for the year ended December 31, 2002.

We consent to the incorporation by reference in Registration Statements No. 33-49739, 33-51181 and 333-60957 of Entergy Gulf States, Inc. on Form S-3 and Registration Statement No. 333-17911 on Form S-2 of our report dated February 21, 2003, appearing in this Annual Report on Form 10-K of Entergy Gulf States, Inc. for the year ended December 31, 2002.

We consent to the incorporation by reference in Registration Statements No. 33-46085, 33-39221, 33-50937, 333-00105, 333-01329, 333-03567 and 333-93683 of Entergy Louisiana, Inc. on Form S-3 of our report dated February 21, 2003, appearing in this Annual Report on Form 10-K of Entergy Louisiana, Inc. for the year ended December 31, 2002.

We consent to the incorporation by reference in Registration Statements No. 33-53004, 33-55826, 33-50507, 333-64023 and 333-53554 of Entergy Mississippi, Inc. on Form S-3 of our report dated February 21, 2003, appearing in this Annual Report on Form 10-K of Entergy Mississippi, Inc. for the year ended December 31, 2002.

We consent to the incorporation by reference in Registration Statements No. 33-57926, 333-00255 and 333-95599 of Entergy New Orleans, Inc. on Form S-3 of our report dated February 21, 2003, appearing in this Annual Report on Form 10-K of Entergy New Orleans, Inc. for the year ended December 31, 2002.

We consent to the incorporation by reference in Registration Statements No. 33-47662, 33-61189, and 333-06717 of System Energy Resources, Inc. on Form S-3 of our report dated February 21, 2003, appearing in this Annual Report on Form 10-K of System Energy Resources, Inc. for the year ended December 31, 2002.

DELOITTE & TOUCHE LLP
New Orleans, Louisiana
March 18, 2003

INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Shareholders of

Entergy Corporation:

We have audited the consolidated financial statements of Entergy Corporation and the financial statements of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc., as of December 31, 2002 and 2001, and for each of the three years in the period ended December 31, 2002, and have issued our reports thereon dated February 21, 2003, our report on the consolidated financial statements of the Corporation includes an explanatory paragraph regarding the Corporation's change in 2002 in the method of accounting for goodwill and intangible assets and the change in 2001 in the method of accounting for derivative instruments; such financial statements and reports are included in your 2002 Annual Report to Shareholders and are included herein. Our audits also included the consolidated financial statement schedules of Entergy Corporation and the financial statement schedules of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc., listed in Item 15. These financial statement schedules are the responsibility of the Corporation's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 21, 2003

INDEX TO FINANCIAL STATEMENT SCHEDULES

Schedule		Page
I	Financial Statements of Entergy Corporation:
	Statements of Income - For the Years Ended December 31, 2002, 2001, and 2000	S-2
	Statements of Cash Flows - For the Years Ended December 31, 2002, 2001, and 2000	S-3
	Balance Sheets, December 31, 2002 and 2001	S-4
	Statements of Retained Earnings, Comprehensive Income, and Paid-In Capital for the Years Ended December 31, 2002, 2001, and 2000	S-5
II	Valuation and Qualifying Accounts 2002, 2001 and 2000:
	Entergy Corporation and Subsidiaries	S-6
	Entergy Arkansas, Inc.	S-7
	Entergy Gulf States, Inc.	S-8
	Entergy Louisiana, Inc.	S-9
	Entergy Mississippi, Inc.	S-10
	Entergy New Orleans, Inc.	S-11

Schedules other than those listed above are omitted because they are not required, not applicable, or the required information is shown in the financial statements or notes thereto.

Columns have been omitted from schedules filed because the information is not applicable.

                          ENTERGY CORPORATION

         SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION
                          STATEMENTS OF INCOME

                                              For the Years Ended December 31,
                                               2002       2001        2000
                                                      (In Thousands)

Income:
  Equity in income of subsidiaries            $629,367   $801,155    $698,243
  Interest on temporary investments             46,964     18,889      12,273
                                              --------   --------    --------
        Total                                  676,331    820,044     710,516
                                              --------   --------    --------

Expenses and Other Deductions:
  Administrative and general expenses           41,126     45,525      25,146
  Income taxes (credit)                          6,948      9,787     (15,212)
  Taxes other than income                          588        825         661
  Interest                                      28,309     37,711      20,627
                                              --------   --------    --------
        Total                                   76,971     93,848      31,222
                                              --------   --------    --------

Net Income                                    $599,360   $726,196    $679,294
                                              ========   ========    ========
See Entergy Corporation and Subsidiaries Notes to Financial
Statements in Part II, Item 8.

                           ENTERGY CORPORATION

         SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION
                         STATEMENTS OF CASH FLOWS

                                                                  Year to Date December 31,
                                                                2002        2001       2000
                                                                       (In Thousands)
Operating Activities:
  Net income                                                   $599,360   $726,196    $679,294
  Noncash items included in net income:
    Equity in earnings of subsidiaries                         (629,367)  (801,155)   (698,243)
    Deferred income taxes                                        (4,803)    11,005      (9,014)
    Depreciation                                                    912      1,391         962
  Changes in working capital:
    Receivables                                                   1,430     (1,804)      2,013
    Payables                                                      4,898      1,140     (13,822)
    Other working capital accounts                             (480,711)   489,997      98,489
  Common stock dividends received from subsidiaries             618,400    440,300     314,300
  Other                                                          68,981    (19,418)    (11,694)
                                                               --------   --------    --------
             Net cash flow provided by operating activities     179,100    847,652     362,285
                                                               --------   --------    --------

Investing Activities:
  Investment in subsidiaries                                   (256,212)  (239,180)    194,665
  Capital expenditures                                             (768)      (103)       (360)
  Changes in other temporary investments                          4,782     (4,782)          -
  Other                                                             103        897      (1,000)
                                                               --------   --------    --------
  Net cash flow provided by (used in) investing activities     (252,095)  (243,168)    193,305
                                                               --------   --------    --------


Financing Activities:
  Changes in credit line borrowings                             245,000    (36,999)    267,000
  Advances to subsidiaries                                       (6,460)    27,067     (32,833)
  Common stock dividends paid                                  (298,991)  (269,122)   (271,019)
  Repurchase of common stock                                   (118,499)   (36,895)   (550,206)
  Notes receivable to/from associated companies                (146,380)  (368,992)          -
  Issuance of common stock                                      130,061     64,345      41,908
  Issuance of long-term debt                                    265,330          -           -
                                                               --------   --------    --------
    Net cash flow used in financing activities                   70,061   (620,596)   (545,150)
                                                               --------   --------    --------

Net increase (decrease) in cash and cash equivalents             (2,934)   (16,112)     10,440

Cash and cash equivalents at beginning of period                 10,821     26,933      16,493
                                                               --------   --------    --------

Cash and cash equivalents at end of period                       $7,887    $10,821     $26,933
                                                               ========   ========    ========
See Entergy Corporation and Subsidiaries Notes to Financial Statements
in Part II, Item 8.

                             ENTERGY CORPORATION

           SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION
                                BALANCE SHEETS

                                                                   December 31,
                                                                2002         2001
                        ASSETS                                    (In Thousands)
Current Assets:
  Cash and cash equivalents:
     Temporary cash investments - at cost,
        which approximates market                               $7,887      $10,821
                                                            ----------   ----------
          Total cash and cash equivalents                        7,887       10,821
                                                            ----------   ----------
  Other temporary investments                                        -        4,782
  Notes receivable - associated companies                      515,373      368,992
  Accounts receivable - associated companies                     9,989        4,915
  Other                                                         46,383        2,517
                                                            ----------   ----------
           Total                                               579,632      392,027
                                                            ----------   ----------

Investment in Wholly-owned Subsidiaries                      7,819,408    7,486,010
                                                            ----------   ----------

Deferred Debits and Other Assets                               475,797      472,587
                                                            ----------   ----------

           Total                                            $8,874,837   $8,350,624
                                                            ==========   ==========
         LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
  Notes payable                                              $       -     $350,001
  Accounts payable:
    Associated companies                                         2,937       13,618
    Other                                                       10,003        5,105
  Taxes accrued                                                      -      215,368
  Other current liabilities                                      8,725        7,861
                                                            ----------   ----------
           Total                                                21,665      591,953
                                                            ----------   ----------

Deferred Credits and Noncurrent Liabilities                    152,935      302,651
                                                            ----------   ----------

Long-term debt                                                 862,000            -

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 cost of treasury stock (25,752,410 shares in
    2002 and 27,441,384 shares in 2001)                        747,331      758,820
                                                            ----------   ----------
           Total common shareholders' equity                 7,838,237    7,456,020
                                                            ----------   ----------

           Total                                            $8,874,837   $8,350,624
                                                            ==========   ==========
See Entergy Corporation and Subsidiaries Notes to
  Financial Statements in Part II, Item 8.

                             ENTERGY CORPORATION
    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 Entergy Corporation and Subsidiaries Notes to Financial
Statements in Part II, Item 8.

                          ENTERGY CORPORATION

            SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
             Years Ended December 31, 2002, 2001, and 2000
                             (In Thousands)

            Column A                 Column B      Column C       Column D       Column E
                                                                   Other
                                                  Additions       Changes
                                                                Deductions
                                    Balance at                      from          Balance
                                     Beginning    Charged to     Provisions       at End
           Description               of Period      Income        (Note 1)       of Period
Year ended December 31, 2002
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                     $28,355      $13,024         $14,094      $27,285
                                      =========     ========        ========    =========
 Accumulated Provisions Not
  Deducted from Assets:
  Property insurance                  $(203,537)    $211,210        $101,614     $(93,941)
  Injuries and damages (Note 2)          29,385       26,667          25,423       30,629
  Environmental                          34,802       39,368          47,682       26,488
                                      ---------     --------        --------    ---------
     Total                            $(139,350)    $277,245        $174,719     $(36,824)
                                      =========     ========        ========    =========

Year ended December 31, 2001
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                     $17,782      $16,393          $5,820      $28,355
                                      =========     ========        ========    =========
 Accumulated Provisions Not
  Deducted from Assets:
  Property insurance                  $(108,351)     $45,714        $140,900    $(203,537)
  Injuries and damages (Note 2)          35,135       20,334          26,084       29,385
  Environmental                          37,183        7,442           9,823       34,802
                                      ---------     --------        --------    ---------
     Total                             $(36,033)     $73,490        $176,807    $(139,350)
                                      =========     ========        ========    =========

Year ended December 31, 2000
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                      $9,507      $25,436         $17,161      $17,782
                                      =========     ========        ========    =========
 Accumulated Provisions Not
  Deducted from Assets:
  Property insurance                   $(33,267)     $66,866        $141,950    $(108,351)
  Injuries and damages (Note 2)          34,309       16,785          15,959       35,135
  Environmental                          37,793        9,084           9,694       37,183
                                      ---------     --------        --------    ---------
     Total                              $38,835      $92,735        $167,603     $(36,033)
                                      =========     ========        ========    =========

___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the
    respective provisions were created. In the case of the provision for
    doubtful accounts, such deductions are reduced by recoveries of amounts
    previously written off.

(2) Injuries and damages provision is provided to absorb all current expenses
    as appropriate and for the estimated cost of settling claims for injuries
    and damages.

                          ENTERGY ARKANSAS, INC.

              SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
               Years Ended December 31, 2002, 2001, and 2000
                              (In Thousands)

           Column A                Column B    Column C      Column D     Column E
                                                             Other
                                              Additions     Changes
                                                           Deductions
                                  Balance at                   from       Balance
                                  Beginning   Charged to    Provisions     at End
          Description             of Period     Income       (Note 1)    of Period
Year ended December 31, 2002
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                   $5,837      $2,194           $-      $8,031
                                   =========    ========     ========    ========
 Accumulated Provisions Not
  Deducted from Assets:
  Property insurance               $(178,715)   $183,438      $18,512    $(13,789)
  Injuries and damages (Note 2)        2,890       3,129        3,319       2,700
  Environmental                        6,910       1,999        7,285       1,624
                                   ---------    --------     --------    --------
     Total                         $(168,915)   $188,566      $29,116     $(9,465)
                                   =========    ========     ========    ========

Year ended December 31, 2001
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                   $4,196      $1,758         $117      $5,837
                                   =========    ========     ========    ========
 Accumulated Provisions Not
  Deducted from Assets:
  Property insurance                $(80,297)    $16,155     $114,573   $(178,715)
  Injuries and damages (Note 2)        3,152       2,367        2,629       2,890
  Environmental                        7,136       2,181        2,407       6,910
                                   ---------    --------     --------    --------
     Total                          $(70,009)    $20,703     $119,609   $(168,915)
                                   =========    ========     ========    ========

Year ended December 31, 2000
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                   $1,768      $6,369       $3,941      $4,196
                                   =========    ========     ========    ========
 Accumulated Provisions Not
  Deducted from Assets:
  Property insurance                    $858     $35,521     $116,676    $(80,297)
  Injuries and damages (Note 2)        3,253       1,322        1,423       3,152
  Environmental                        4,934       4,082        1,880       7,136
                                   ---------    --------     --------    --------
     Total                            $9,045     $40,925     $119,979    $(70,009)
                                   =========    ========     ========    ========
___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the
    respective provisions were created. In the case of the provision for
    doubtful accounts, such deductions are reduced by recoveries of amounts
    previously written off.

(2) Injuries and damages provision is provided to absorb all current expenses
    as appropriate and for the estimated cost of settling claims for injuries
    and damages.

                         ENTERGY GULF STATES,  INC.

              SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
               Years Ended December 31, 2002, 2001, and 2000
                              (In Thousands)

           Column A                Column B    Column C      Column D     Column E
                                                             Other
                                              Additions     Changes
                                                           Deductions
                                  Balance at                   from       Balance
                                  Beginning   Charged to    Provisions     at End
          Description             of Period     Income       (Note 1)    of Period
Year ended December 31, 2002
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                   $3,696      $3,961       $1,764      $5,893
                                   =========    ========     ========    ========
 Accumulated Provisions
  Not Deducted from Assets--
  Property insurance                 $(8,721)     $4,486      $41,052    $(45,287)
  Injuries and damages (Note 2)        6,773       7,684        6,173       8,284
  Environmental                       18,716      34,296       37,595      15,417
                                   ---------    --------     --------    --------
     Total                           $16,768     $46,466      $84,820    ($21,586)
                                   =========    ========     ========    ========

Year ended December 31, 2001
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                   $4,810        $940       $2,054      $3,696
                                   =========    ========     ========    ========
 Accumulated Provisions
  Not Deducted from Assets--
  Property insurance                 $(5,698)     $4,485       $7,508     $(8,721)
  Injuries and damages (Note 2)        9,406       5,266        7,899       6,773
  Environmental                       20,671       2,306        4,261      18,716
                                   ---------    --------     --------    --------
     Total                           $24,379     $12,057      $19,668     $16,768
                                   =========    ========     ========    ========

Year ended December 31, 2000
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                   $1,828      $7,487       $4,505      $4,810
                                   =========    ========     ========    ========
 Accumulated Provisions
  Not Deducted from Assets--
  Property insurance                 $(3,452)     $4,486       $6,732     $(5,698)
  Injuries and damages (Note 2)        8,684       6,538        5,816       9,406
  Environmental                       24,445       1,844        5,618      20,671
                                   ---------    --------     --------    --------
     Total                           $29,677     $12,868      $18,166     $24,379
                                   =========    ========     ========    ========
___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the
    respective provisions were created. In the case of the provision for
    doubtful accounts, such deductions are reduced by recoveries of amounts
    previously written off.

(2) Injuries and damages provision is provided to absorb all current expenses
    as appropriate and for the estimated cost of settling claims for injuries
    and damages.

                          ENTERGY LOUISIANA, INC.

             SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
              Years Ended December 31, 2002, 2001, and 2000
                               (In Thousands)

           Column A                Column B    Column C      Column D     Column E
                                                             Other
                                              Additions     Changes
                                                           Deductions
                                  Balance at                   from       Balance
                                  Beginning   Charged to    Provisions     at End
          Description             of Period     Income       (Note 1)    of Period
Year ended December 31, 2002
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                   $2,909      $1,181           $-      $4,090
                                   =========    ========     ========    ========
 Accumulated Provisions Not
  Deducted from Assets:
  Property insurance                $(26,575)    $14,064      $26,537    $(39,048)
  Injuries and damages (Note 2)        9,829       4,750        5,465       9,114
  Environmental                        8,127       1,843        1,813       8,157
                                   ---------    --------     --------    --------
     Total                           $(8,619)    $20,657      $33,815    $(21,777)
                                   =========    ========     ========    ========

Year ended December 31, 2001
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                   $2,552        $385          $28      $2,909
                                   =========    ========     ========    ========
 Accumulated Provisions Not
  Deducted from Assets:
  Property insurance                $(27,040)    $11,900      $11,435    $(26,575)
  Injuries and damages (Note 2)       11,583       3,674        5,428       9,829
  Environmental                        7,793       2,051        1,717       8,127
                                   ---------    --------     --------    --------
     Total                           $(7,664)    $17,625      $18,580     $(8,619)
                                   =========    ========     ========    ========

Year ended December 31, 2000
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                   $1,615      $5,384       $4,447      $2,552
                                   =========    ========     ========    ========
 Accumulated Provisions Not
  Deducted from Assets:
  Property insurance                $(24,089)    $11,900      $14,851    $(27,040)
  Injuries and damages (Note 2)       12,452       3,889        4,758      11,583
  Environmental                        7,022       2,132        1,361       7,793
                                   ---------    --------     --------    --------
     Total                           $(4,615)    $17,921      $20,970     $(7,664)
                                   =========    ========     ========    ========

___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the
    respective provisions were created. In the case of the provision for
    doubtful accounts, such deductions are reduced by recoveries of amounts
    previously written off.

(2) Injuries and damages provision is provided to absorb all current expenses
    as appropriate and for the estimated cost of settling claims for injuries
    and damages.

                         ENTERGY MISSISSIPPI, INC.

             SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
              Years Ended December 31, 2002, 2001, and 2000
                               (In Thousands)

           Column A                Column B    Column C      Column D     Column E
                                                             Other
                                              Additions     Changes
                                                           Deductions
                                  Balance at                   from       Balance
                                  Beginning   Charged to    Provisions     at End
          Description             of Period     Income       (Note 1)    of Period
Year ended December 31, 2002
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                   $1,232      $1,063         $662      $1,633
                                   =========    ========     ========    ========
 Accumulated Provisions Not
  Deducted from Assets:
  Property insurance                  $1,279      $8,882      $13,098     $(2,937)
  Injuries and damages (Note 2)        6,306       5,526        3,904       7,928
  Environmental                          487         886          706         667
                                   ---------    --------     --------    --------
     Total                            $8,072     $15,294      $17,708      $5,658
                                   =========    ========     ========    ========

Year ended December 31, 2001
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                   $1,197         $45          $10      $1,232
                                   =========    ========     ========    ========
 Accumulated Provisions Not
  Deducted from Assets:
  Property insurance                 $(4,765)    $13,124       $7,080      $1,279
  Injuries and damages (Note 2)        6,694       8,196        8,584       6,306
  Environmental                          511         581          605         487
                                   ---------    --------     --------    --------
     Total                            $2,440     $21,901      $16,269      $8,072
                                   =========    ========     ========    ========

Year ended December 31, 2000
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                     $886      $2,788       $2,477      $1,197
                                   =========    ========     ========    ========
 Accumulated Provisions Not
  Deducted from Assets:
  Property insurance                $(16,356)    $14,956       $3,365     $(4,765)
  Injuries and damages (Note 2)        6,849       1,579        1,734       6,694
  Environmental                          594         418          501         511
                                   ---------    --------     --------    --------
     Total                           $(8,913)    $16,953       $5,600      $2,440
                                   =========    ========     ========    ========

___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the
    respective provisions were created. In the case of the provision for
    doubtful accounts, such deductions are reduced by recoveries of amounts
    previously written off.

(2) Injuries and damages provision is provided to absorb all current expenses
    as appropriate and for the estimated cost of settling claims for injuries
    and damages.

                          ENTERGY NEW ORLEANS,  INC.

               SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
                Years Ended December 31, 2002, 2001, and 2000
                                (In Thousands)

           Column A                Column B    Column C      Column D     Column E
                                                             Other
                                              Additions     Changes
                                                           Deductions
                                  Balance at                   from       Balance
                                  Beginning   Charged to    Provisions     at End
          Description             of Period     Income       (Note 1)    of Period
Year ended December 31, 2002
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                   $4,273        $501           $-      $4,774
                                   =========    ========     ========    ========
 Accumulated Provisions Not
  Deducted from Assets:
  Property insurance                  $9,195        $340       $2,415      $7,120
  Injuries and damages (Note 2)        3,587       5,578        6,562       2,603
  Environmental                          562         344          283         623
                                   ---------    --------     --------    --------
     Total                           $13,344      $6,262       $9,260     $10,346
                                   =========    ========     ========    ========

Year ended December 31, 2001
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                   $2,463      $5,422       $3,612      $4,273
                                   =========    ========     ========    ========
 Accumulated Provisions Not
  Deducted from Assets:
  Property insurance                  $9,449         $50         $304      $9,195
  Injuries and damages (Note 2)        4,300         831        1,544       3,587
  Environmental                        1,072         323          833         562
                                   ---------    --------     --------    --------
     Total                           $14,821      $1,204       $2,681     $13,344
                                   =========    ========     ========    ========

Year ended December 31, 2000
 Accumulated Provisions
  Deducted from Assets--
  Doubtful Accounts                     $846      $3,408       $1,791      $2,463
                                   =========    ========     ========    ========
 Accumulated Provisions Not
  Deducted from Assets:
  Property insurance                  $9,772          $3         $326      $9,449
  Injuries and damages (Note 2)        3,071       3,457        2,228       4,300
  Environmental                          798         608          334       1,072
                                   ---------    --------     --------    --------
     Total                           $13,641      $4,068       $2,888     $14,821
                                   =========    ========     ========    ========

___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the
    respective provisions were created. In the case of the provision for
    doubtful accounts, such deductions are reduced by recoveries of amounts
    previously written off.

(2) Injuries and damages provision is provided to absorb all current expenses
    as appropriate and for the estimated cost of settling claims for injuries
    and damages.

EXHIBIT INDEX

The following exhibits indicated by an asterisk preceding the exhibit number are filed herewith. The balance of the exhibits have heretofore been filed with the SEC, respectively, as the exhibits and in the file numbers indicated and are incorporated herein by reference. The exhibits marked with a (+) are management contracts or compensatory plans or arrangements required to be filed herewith and required to be identified as such by Item 14 of Form 10-K. Reference is made to a duplicate list of exhibits being filed as a part of this Form 10-K, which list, prepared in accordance with Item 102 of Regulation S-T of the SEC, immediately precedes the exhibits being physically filed with this Form 10-K

(3) (i) Articles of Incorporation

Entergy Corporation

(a) -- Certificate of Incorporation of Entergy Corporation dated December 31, 1993 (A-1(a) to Rule 24 Certificate in 70-8059).

System Energy

(b) -- Amended and Restated Articles of Incorporation of System Energy and amendments thereto through April 28, 1989 (A-1(a) to Form U-1 in 70-5399).

Entergy Arkansas

(c) -- Amended and Restated Articles of Incorporation of Entergy Arkansas effective November 12, 1999 (3(i)(c)1 to Form 10-K for the year ended December 31, 1999 in 1-10764).

Entergy Gulf States

(d) -- Restated Articles of Incorporation of Entergy Gulf States effective November 17, 1999 (3(i)(d)1 to Form 10-K for the year ended December 31, 1999 in 1-27031).

Entergy Louisiana

(e) -- Amended and Restated Articles of Incorporation of Entergy Louisiana effective November 15, 1999 (3(a) to Form S-3 in 333-93683).

Entergy Mississippi

(f) -- Amended and Restated Articles of Incorporation of Entergy Mississippi effective November 12, 1999 (3(i)(f)1 to Form 10-K for the year ended December 31, 1999 in 0-320).

Entergy New Orleans

(g) -- Amended and Restated Articles of Incorporation of Entergy New Orleans effective November 15, 1999 (3(a) to Form S-3 in 333-95599).

(3) (ii) By-Laws

(a) --	By-Laws of Entergy Corporation as amended January 29, 1999, and as presently in effect (4.2 to Form S-8 in File No. 333-75097).
(b) --	By-Laws of System Energy effective July 6, 1998, and as presently in effect (3(f) to Form 10-Q for the quarter ended June 30, 1998 in 1-9067).
(c) --	By-Laws of Entergy Arkansas effective November 26, 1999, and as presently in effect (3(ii)(c) to Form 10-K for the year ended December 31, 1999 in 1-10764).
(d) --	By-Laws of Entergy Gulf States effective November 26, 1999, and as presently in effect (3(ii)(d) to Form 10-K for the year ended December 31, 19991-27031).
(e) --	By-Laws of Entergy Louisiana effective November 26, 1999, and as presently in effect (3(b) to Form S-3 in File No. 333-93683).
(f) --	By-Laws of Entergy Mississippi effective November 26, 1999, and as presently in effect (3(ii)(f) to Form 10-K for the year ended December 31, 1999 in 0-320).
(g) --	By-Laws of Entergy New Orleans effective November 30, 1999, and as presently in effect (3(b) to Form S-3 in File No. 333-95599).

(4) Instruments Defining Rights of Security Holders, Including Indentures

Entergy Corporation

(a) 1 --	See (4)(b) through (4)(g) below for instruments defining the rights of holders of long-term debt of System Energy, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans.
(a) 2 --	Credit Agreement, dated as of May 16, 2002, among Entergy Corporation, the Banks (Citibank, N.A., ABN AMRO Bank N.V., The Bank of New York, Barclays Bank PLC, Mizuho Corporate Bank Limited, BNP Paribas, Bayerische Hypo-und Vereinsbank AG (New York Branch), J. P. Morgan Chase Bank, The Royal Bank of Scotland plc, Societe Generale, Wachovia Bank (National Association), Bank One, NA, Mellon Bank, N.A., The Bank of Nova Scotia, Morgan Stanley Bank, Union Bank of California, N.A., Deutsche Bank AG New York Branch, KBC Bank N.V., Lehman Commercial Paper Inc., Regions Bank, and Westdeutsche Landesbank Girozentrale), and Citibank, N.A., as Agent (4(a) to Form 10-Q for the quarter ended June 30, 2002 in 1-11299).
(a) 3 --	Assumption Agreement, dated July 15, 2002, among Entergy Corporation, CO Bank, ACB, (as Additional Lender), and Citibank N.A., (as Administrative Agent) (4(b) to Form 10-Q for the quarter ended June 30, 2002 in 1-11299).
*(a) 4 --	Indenture, dated as of December 1, 2002, between Entergy Corporation and Deutsche Bank Trust Company Americas, as Trustee.
*(a) 5 --	Officer' Certificate for Entergy Corporation.

System Energy

(b) 1 --	Mortgage and Deed of Trust, dated as of June 15, 1977, as amended by twenty-two Supplemental Indentures (A-1 in 70-5890 (Mortgage); B and C to Rule 24 Certificate in 70-5890 (First); B to Rule 24 Certificate in 70-6259 (Second); 20(a)-5 to Form 10-Q for the quarter ended June 30, 1981 in 1-3517 (Third); A-1(e)-1 to Rule 24 Certificate in 70-6985 (Fourth); B to Rule 24 Certificate in 70-7021 (Fifth); B to Rule 24 Certificate in 70-7021 (Sixth); A-3(b) to Rule 24 Certificate in 70-7026 (Seventh); A-3(b) to Rule 24 Certificate in 70-7158 (Eighth); B to Rule 24 Certificate in 70-7123 (Ninth); B-1 to Rule 24 Certificate in 70-7272 (Tenth); B-2 to Rule 24 Certificate in 70-7272 (Eleventh); B-3 to Rule 24 Certificate in 70-7272 (Twelfth); B-1 to Rule 24 Certificate in 70-7382 (Thirteenth); B-2 to Rule 24 Certificate in 70-7382 (Fourteenth); A-2(c) to Rule 24 Certificate in 70-7946 (Fifteenth); A-2(c) to Rule 24 Certificate in 70-7946 (Sixteenth); A-2(d) to Rule 24 Certificate in 70-7946 (Seventeenth); A-2(e) to Rule 24 Certificate dated May 4, 1993 in 70-7946 (Eighteenth); A-2(g) to Rule 24 Certificate dated May 6, 1994 in 70-7946 (Nineteenth); A-2(a)(1) to Rule 24 Certificate dated August 8, 1996 in 70-8511 (Twentieth); A-2(a)(2) to Rule 24 Certificate dated August 8, 1996 in 70-8511 (Twenty-first); and A-2(a) to Rule 24 Certificate dated October 4, 2002 in 70-9753 (Twenty-second)).
(b) 2 --	Facility Lease No. 1, dated as of December 1, 1988, between Meridian Trust Company and Stephen M. Carta (Steven Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (1) to Rule 24 Certificate dated April 21, 1989 in 70-7561) and Lease Supplement No. 2 dated as of January 1, 1994 (B-3(d) to Rule 24 Certificate dated January 31, 1994 in 70-8215).
(b) 3 --	Facility Lease No. 2, dated as of December 1, 1988 between Meridian Trust Company and Stephen M. Carta (Steven Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (2) to Rule 24 Certificate dated April 21, 1989 in 70-7561) and Lease Supplement No. 2 dated as of January 1, 1994 (B-4(d) Rule 24 Certificate dated January 31, 1994 in 70-8215).

Entergy Arkansas

*(c) 1 --	Mortgage and Deed of Trust, dated as of October 1, 1944, as amended by fifty-eight Supplemental Indentures (7(d) in 2-5463 (Mortgage); 7(b) in 2-7121 (First); 7(c) in 2-7605 (Second); 7(d) in 2-8100 (Third); 7(a)-4 in 2-8482 (Fourth); 7(a)-5 in 2-9149 (Fifth); 4(a)-6 in 2-9789 (Sixth); 4(a)-7 in 2-10261 (Seventh); 4(a)-8 in 2-11043 (Eighth); 2(b)-9 in 2-11468 (Ninth); 2(b)-10 in 2-15767 (Tenth); D in 70-3952 (Eleventh); D in 70-4099 (Twelfth); 4(d) in 2-23185 (Thirteenth); 2(c) in 2-24414 (Fourteenth); 2(c) in 2-25913 (Fifteenth); 2(c) in 2-28869 (Sixteenth); 2(d) in 2-28869 (Seventeenth); 2(c) in 2-35107 (Eighteenth); 2(d) in 2-36646 (Nineteenth); 2(c) in 2-39253 (Twentieth); 2(c) in 2-41080 (Twenty-first); C-1 to Rule 24 Certificate in 70-5151 (Twenty-second); C-1 to Rule 24 Certificate in 70-5257 (Twenty-third); C to Rule 24 Certificate in 70-5343 (Twenty-fourth); C-1 to Rule 24 Certificate in 70-5404 (Twenty-fifth); C to Rule 24 Certificate in 70-5502 (Twenty-sixth); C-1 to Rule 24 Certificate in 70-5556 (Twenty-seventh); C-1 to Rule 24 Certificate in 70-5693 (Twenty-eighth); C-1 to Rule 24 Certificate in 70-6078 (Twenty-ninth); C-1 to Rule 24 Certificate in 70-6174 (Thirtieth); C-1 to Rule 24 Certificate in 70-6246 (Thirty-first); C-1 to Rule 24 Certificate in 70-6498 (Thirty-second); A-4b-2 to Rule 24 Certificate in 70-6326 (Thirty-third); C-1 to Rule 24 Certificate in 70-6607 (Thirty-fourth); C-1 to Rule 24 Certificate in 70-6650 (Thirty-fifth); C-1 to Rule 24 Certificate dated December 1, 1982 in 70-6774 (Thirty-sixth); C-1 to Rule 24 Certificate dated February 17, 1983 in 70-6774 (Thirty-seventh); A-2(a) to Rule 24 Certificate dated December 5, 1984 in 70-6858 (Thirty-eighth); A-3(a) to Rule 24 Certificate in 70-7127 (Thirty-ninth); A-7 to Rule 24 Certificate in 70-7068 (Fortieth); A-8(b) to Rule 24 Certificate dated July 6, 1989 in 70-7346 (Forty-first); A-8(c) to Rule 24 Certificate dated February 1, 1990 in 70-7346 (Forty-second); 4 to Form 10-Q for the quarter ended September 30, 1990 in 1-10764 (Forty-third); A-2(a) to Rule 24 Certificate dated November 30, 1990 in 70-7802 (Forty-fourth); A-2(b) to Rule 24 Certificate dated January 24, 1991 in 70-7802 (Forty-fifth); 4(d)(2) in 33-54298 (Forty-sixth); 4(c)(2) to Form 10-K for the year ended December 31, 1992 in 1-10764 (Forty-seventh); 4(b) to Form 10-Q for the quarter ended June 30, 1993 in 1-10764 (Forty-eighth); 4(c) to Form 10-Q for the quarter ended June 30, 1993 in 1-10764 (Forty-ninth); 4(b) to Form 10-Q for the quarter ended September 30, 1993 in 1-10764 (Fiftieth); 4(c) to Form 10-Q for the quarter ended September 30, 1993 in 1-10764 (Fifty-first); 4(a) to Form 10-Q for the quarter ended June 30, 1994 in 1-10764 (Fifty-second); C-2 to Form U5S for the year ended December 31, 1995 (Fifty-third); C-2(a) to Form U5S for the year ended December 31, 1996 (Fifty-fourth); 4(a) to Form 10-Q for the quarter ended March 31, 2000 in 1-10764 (Fifty-fifth); 4(a) to Form 10-Q for the quarter ended September 30, 2001 in 1-10764 (Fifty-sixth); C-2(a) to Form U5S for the year ended December 31, 2001 (Fifty-seventh); and (Fifty-eighth)).
(c) 2 --	Indenture for Unsecured Subordinated Debt Securities relating to Trust Securities between Entergy Arkansas and Bank of New York (as Trustee), dated as of August 1, 1996 (A-1(a) to Rule 24 Certificate dated August 26, 1996 in 70-8723).
(c) 3 --	Amended and Restated Trust Agreement of Entergy Arkansas Capital I, dated as of August 14, 1996 (A-3(a) to Rule 24 Certificate dated August 26, 1996 in 70-8723).
(c) 4 --	Guarantee Agreement between Entergy Arkansas (as Guarantor) and The Bank of New York (as Trustee), dated as of August 14, 1996, with respect to Entergy Arkansas Capital I's obligations on its 8 1/2% Cumulative Quarterly Income Preferred Securities, Series A (A-4(a) to Rule 24 Certificate dated August 26, 1996 in 70-8723).

Entergy Gulf States

(d) 1 --	Indenture of Mortgage, dated September 1, 1926, as amended by certain Supplemental Indentures (B-a-I-1 in Registration No. 2-2449 (Mortgage); 7-A-9 in Registration No. 2-6893 (Seventh); B to Form 8-K dated September 1, 1959 (Eighteenth); B to Form 8-K dated February 1, 1966 (Twenty-second); B to Form 8-K dated March 1, 1967 (Twenty-third); C to Form 8-K dated March 1, 1968 (Twenty-fourth); B to Form 8-K dated November 1, 1968 (Twenty-fifth); B to Form 8-K dated April 1, 1969 (Twenty-sixth); 2-A-8 in Registration No. 2-66612 (Thirty-eighth); 4-2 to Form 10-K for the year ended December 31, 1984 in 1-27031 (Forty-eighth); 4-2 to Form 10-K for the year ended December 31, 1988 in 1-27031 (Fifty-second); 4 to Form 10-K for the year ended December 31, 1991 in 1-27031 (Fifty-third); 4 to Form 8-K dated July 29, 1992 in 1-27031 (Fifth-fourth); 4 to Form 10-K dated December 31, 1992 in 1-27031 (Fifty-fifth); 4 to Form 10-Q for the quarter ended March 31, 1993 in 1-27031 (Fifty-sixth); 4-2 to Amendment No. 9 to Registration No. 2-76551 (Fifty-seventh); 4(b) to Form 10-Q for the quarter ended March 31,1999 in 1-27031 (Fifty-eighth); A-2(a) to Rule 24 Certificate dated June 23, 2000 in 70-8721 (Fifty-ninth); A-2(a) to Rule 24 Certificate dated September 10, 2001 in 70-9751 (Sixtieth); A-2(b) to Rule 24 Certificate dated November 18, 2002 in 70-9751 (Sixty-first); and A-2(c) to Rule 24 Certificate dated December 6, 2002 in 70-9751 (Sixty-second)).
(d) 2 --	Indenture, dated March 21, 1939, accepting resignation of The Chase National Bank of the City of New York as trustee and appointing Central Hanover Bank and Trust Company as successor trustee (B-a-1-6 in Registration No. 2-4076).
(d) 3 --	Indenture for Unsecured Subordinated Debt Securities relating to Trust Securities, dated as of January 15, 1997 (A-11(a) to Rule 24 Certificate dated February 6, 1997 in 70-8721).
(d) 4 --	Amended and Restated Trust Agreement of Entergy Gulf States Capital I dated January 28, 1997 of Series A Preferred Securities (A-13(a) to Rule 24 Certificate dated February 6, 1997 in 70-8721).
(d) 5 --	Guarantee Agreement between Entergy Gulf States, Inc. (as Guarantor) and The Bank of New York (as Trustee) dated as of January 28, 1997 with respect to Entergy Gulf States Capital I's obligation on its 8.75% Cumulative Quarterly Income Preferred Securities, Series A (A-14(a) to Rule 24 Certificate dated February 6, 1997 in 70-8721).

Entergy Louisiana

(e) 1 --	Mortgage and Deed of Trust, dated as of April 1, 1944, as amended by fifty-six Supplemental Indentures (7(d) in 2-5317 (Mortgage); 7(b) in 2-7408 (First); 7(c) in 2-8636 (Second); 4(b)-3 in 2-10412 (Third); 4(b)-4 in 2-12264 (Fourth); 2(b)-5 in 2-12936 (Fifth); D in 70-3862 (Sixth); 2(b)-7 in 2-22340 (Seventh); 2(c) in 2-24429 (Eighth); 4(c)-9 in 2-25801 (Ninth); 4(c)-10 in 2-26911 (Tenth); 2(c) in 2-28123 (Eleventh); 2(c) in 2-34659 (Twelfth); C to Rule 24 Certificate in 70-4793 (Thirteenth); 2(b)-2 in 2-38378 (Fourteenth); 2(b)-2 in 2-39437 (Fifteenth); 2(b)-2 in 2-42523 (Sixteenth); C to Rule 24 Certificate in 70-5242 (Seventeenth); C to Rule 24 Certificate in 70-5330 (Eighteenth); C-1 to Rule 24 Certificate in 70-5449 (Nineteenth); C-1 to Rule 24 Certificate in 70-5550 (Twentieth); A-6(a) to Rule 24 Certificate in 70-5598 (Twenty-first); C-1 to Rule 24 Certificate in 70-5711 (Twenty-second); C-1 to Rule 24 Certificate in 70-5919 (Twenty-third); C-1 to Rule 24 Certificate in 70-6102 (Twenty-fourth); C-1 to Rule 24 Certificate in 70-6169 (Twenty-fifth); C-1 to Rule 24 Certificate in 70-6278 (Twenty-sixth); C-1 to Rule 24 Certificate in 70-6355 (Twenty-seventh); C-1 to Rule 24 Certificate in 70-6508 (Twenty-eighth); C-1 to Rule 24 Certificate in 70-6556 (Twenty-ninth); C-1 to Rule 24 Certificate in 70-6635 (Thirtieth); C-1 to Rule 24 Certificate in 70-6834 (Thirty-first); C-1 to Rule 24 Certificate in 70-6886 (Thirty-second); C-1 to Rule 24 Certificate in 70-6993 (Thirty-third); C-2 to Rule 24 Certificate in 70-6993 (Thirty-fourth); C-3 to Rule 24 Certificate in 70-6993 (Thirty-fifth); A-2(a) to Rule 24 Certificate in 70-7166 (Thirty-sixth); A-2(a) in 70-7226 (Thirty-seventh); C-1 to Rule 24 Certificate in 70-7270 (Thirty-eighth); 4(a) to Quarterly Report on Form 10-Q for the quarter ended June 30, 1988 in 1-8474 (Thirty-ninth); A-2(b) to Rule 24 Certificate in 70-7553 (Fortieth); A-2(d) to Rule 24 Certificate in 70-7553 (Forty-first); A-3(a) to Rule 24 Certificate in 70-7822 (Forty-second); A-3(b) to Rule 24 Certificate in 70-7822 (Forty-third); A-2(b) to Rule 24 Certificate in 70-7822 (Forty-fourth); A-3(c) to Rule 24 Certificate in 70-7822 (Forty-fifth); A-2(c) to Rule 24 Certificate dated April 7, 1993 in 70-7822 (Forty-sixth); A-3(d) to Rule 24 Certificate dated June 4, 1993 in 70-7822 (Forth-seventh); A-3(e) to Rule 24 Certificate dated December 21, 1993 in 70-7822 (Forty-eighth); A-3(f) to Rule 24 Certificate dated August 1, 1994 in 70-7822 (Forty-ninth); A-4(c) to Rule 24 Certificate dated September 28, 1994 in 70-7653 (Fiftieth); A-2(a) to Rule 24 Certificate dated April 4, 1996 in 70-8487 (Fifty-first); A-2(a) to Rule 24 Certificate dated April 3, 1998 in 70-9141 (Fifty-second); A-2(b) to Rule 24 Certificate dated April 9, 1999 in 70-9141 (Fifty-third); A-3(a) to Rule 24 Certificate dated July 6, 1999 in 70-9141 (Fifty-fourth); A-2(c) to Rule 24 Certificate dated June 2, 2000 in 70-9141 (Fifty-fifth); and A-2(d) to Rule 24 Certificate dated April 4, 2002 in 70-9141 (Fifty-sixth)).
(e) 2 --	Facility Lease No. 1, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-1 in Registration No. 33-30660).
(e) 3 --	Facility Lease No. 2, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-2 in Registration No. 33-30660).
(e) 4 --	Facility Lease No. 3, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-3 in Registration No. 33-30660).
(e) 5 --	Indenture for Unsecured Subordinated Debt Securities relating to Trust Securities, dated as of July 1, 1996 (A-14(a) to Rule 24 Certificate dated July 25, 1996 in 70-8487).
(e) 6 --	Amended and Restated Trust Agreement of Entergy Louisiana Capital I dated July 16, 1996 of Series A Preferred Securities (A-16(a) to Rule 24 Certificate dated July 25, 1996 in 70-8487).
(e) 7 --	Guarantee Agreement between Entergy Louisiana, Inc. (as Guarantor) and The Bank of New York (as Trustee) dated as of July 16, 1996 with respect to Entergy Louisiana Capital I's obligation on its 9% Cumulative Quarterly Income Preferred Securities, Series A (A-19(a) to Rule 24 Certificate dated July 25, 1996 in 70-8487).

Entergy Mississippi

(f) 1 -- Mortgage and Deed of Trust, dated as of February 1, 1988, as amended by nineteen Supplemental Indentures (A-2(a)-2 to Rule 24 Certificate in 70-7461 (Mortgage); A-2(b)-2 in 70-7461 (First); A-5(b) to Rule 24 Certificate in 70-7419 (Second); A-4(b) to Rule 24 Certificate in 70-7554 (Third); A-1(b)-1 to Rule 24 Certificate in 70-7737 (Fourth); A-2(b) to Rule 24 Certificate dated November 24, 1992 in 70-7914 (Fifth); A-2(e) to Rule 24 Certificate dated January 22, 1993 in 70-7914 (Sixth); A-2(g) to Form U-1 in 70-7914 (Seventh); A-2(i) to Rule 24 Certificate dated November 10, 1993 in 70-7914 (Eighth); A-2(j) to Rule 24 Certificate dated July 22, 1994 in 70-7914 (Ninth); (A-2(l) to Rule 24 Certificate dated April 21, 1995 in 70-7914 (Tenth); A-2(a) to Rule 24 Certificate dated June 27, 1997 in 70-8719 (Eleventh); A-2(b) to Rule 24 Certificate dated April 16, 1998 in 70-8719 (Twelfth); A-2(c) to Rule 24 Certificate dated May 12, 1999 in 70-8719 (Thirteenth); A-3(a) to Rule 24 Certificate dated June 8, 1999 in 70-8719 (Fourteenth); A-2(d) to Rule 24 Certificate dated February 24, 2000 in 70-8719 (Fifteenth); A-2(a) to Rule 24 Certificate dated February 9, 2001 in 70-9757 (Sixteenth); A-2(b) to Rule 24 Certificate dated October 31, 2002 in 70-9757 (Seventeenth); A-2(c) to Rule 24 Certificate dated December 2, 2002 in 70-9757 (Eighteenth); and A-2(d) to Rule 24 Certificate dated February 6, 2003 in 70-9757 (Nineteenth)).

Entergy New Orleans

(g) 1 -- Mortgage and Deed of Trust, dated as of May 1, 1987, as amended by ten Supplemental Indentures (A-2(c) to Rule 24 Certificate in 70-7350 (Mortgage); A-5(b) to Rule 24 Certificate in 70-7350 (First); A-4(b) to Rule 24 Certificate in 70-7448 (Second); 4(f)4 to Form 10-K for the year ended December 31, 1992 in 0-5807 (Third); 4(a) to Form 10-Q for the quarter ended September 30, 1993 in 0-5807 (Fourth); 4(a) to Form 8-K dated April 26, 1995 in 0-5807 (Fifth); 4(a) to Form 8-K dated March 22, 1996 in 0-5807 (Sixth); 4(b) to Form 10-Q for the quarter ended June 30, 1998 in 0-5807 (Seventh); 4(d) to Form 10-Q for the quarter ended June 30, 2000 in 0-5807 (Eighth); C-5(a) to Form U5S for the year ended December 31, 2000 (Ninth); and 4(b) to Form 10-Q for the quarter ended September 30, 2002 in 0-5807 (Tenth)).

(10) Material Contracts

Entergy Corporation

(a) 1 --	Agreement, dated April 23, 1982, among certain System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(a) 2 --	Middle South Utilities (now Entergy Corporation) System Agency Agreement, dated December 11, 1970 (5(a)-2 in 2-41080).
(a) 3 --	Amendment, dated February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)-4 in 2-41080).
(a) 4 --	Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)-4 in 2-41080).
(a) 5 --	Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)-3 in 2-41080).
(a) 6 --	Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)-5 in 2-41080).
(a) 7 --	Amendment, dated January 1, 1972, to Service Agreement with Entergy Services (5(a)-6 in 2-43175).
(a) 8 --	Amendment, dated April 27, 1984, to Service Agreement with Entergy Services (10(a)-7 to Form 10-K for the year ended December 31, 1984, in 1-3517).
(a) 9 --	Amendment, dated August 1, 1988, to Service Agreement with Entergy Services (10(a)-8 to Form 10-K for the year ended December 31, 1988, in 1-3517).
(a) 10 --	Amendment, dated January 1, 1991, to Service Agreement with Entergy Services (10(a)-9 to Form 10-K for the year ended December 31, 1990, in 1-3517).
(a) 11 --	Amendment, dated January 1, 1992, to Service Agreement with Entergy Services (10(a)-11 for the year ended December 31, 1994 in 1-11299).
(a) 12 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(a)-12 for the year ended December 31, 2001 in 1-11299).
*(a)13 --	Amendment, dated April 1, 2002, to Service Agreement with Entergy Services.
(a) 14 --	Availability Agreement, dated June 21, 1974, among System Energy and certain other System companies (B to Rule 24 Certificate dated June 24, 1974 in 70-5399).
(a) 15 --	First Amendment to Availability Agreement, dated as of June 30, 1977 (B to Rule 24 Certificate dated June 24, 1977 in 70-5399).
(a) 16 --	Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate dated July 1, 1981 in 70-6592).
(a) 17 --	Third Amendment to Availability Agreement, dated as of June 28, 1984 (B-13(a) to Rule 24 Certificate dated July 6, 1984 in 70-6985).
(a) 18 --	Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate dated June 8, 1989 in 70-5399).
(a) 19 --	Eighteenth Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-2 to Rule 24 Certificate dated October 1, 1986 in 70-7272).
(a) 20 --	Nineteenth Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-3 to Rule 24 Certificate dated October 1, 1986 in 70-7272).
(a) 21 --	Twenty-sixth Assignment of Availability Agreement, Consent and Agreement, dated as of October 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(c) to Rule 24 Certificate dated November 2, 1992 in 70-7946).
(a) 22 --	Twenty-seventh Assignment of Availability Agreement, Consent and Agreement, dated as of April 1, 1993, with United States Trust Company of New York and Gerard F. Ganey as Trustees (B-2(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946).
(a) 23 --	Twenty-ninth Assignment of Availability Agreement, Consent and Agreement, dated as of April 1, 1994, with United States Trust Company of New York and Gerard F. Ganey as Trustees (B-2(f) to Rule 24 Certificate dated May 6, 1994 in 70-7946).
(a) 24 --	Thirtieth Assignment of Availability Agreement, Consent and Agreement, dated as of August 1, 1996, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans, and United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(a) to Rule 24 Certificate dated August 8, 1996 in 70-8511).
(a) 25 --	Thirty-first Assignment of Availability Agreement, Consent and Agreement, dated as of August 1, 1996, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, and United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to Rule 24 Certificate dated August 8, 1996 in 70-8511).
(a) 26 --	Thirty-second Assignment of Availability Agreement, Consent and Agreement, dated as of December 27, 1996, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, and The Chase Manhattan Bank (B-2(a) to Rule 24 Certificate dated January 13, 1997 in 70-7561).
(a) 27 --	Thirty-third Assignment of Availability Agreement, Consent and Agreement, dated as of December 20, 1999, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, and The Chase Manhattan Bank (B-2(b) to Rule 24 Certificate dated March 3, 2000 in 70-7561).
(a) 28 --	Thirty-fourth Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 2002, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, The Bank of New York and Douglas J. MacInnes (B-2(a)(1) to Rule 24 Certificate dated October 4, 2001 in 70-9753).
(a) 29 --	Capital Funds Agreement, dated June 21, 1974, between Entergy Corporation and System Energy (C to Rule 24 Certificate dated June 24, 1974 in 70-5399).
(a) 30 --	First Amendment to Capital Funds Agreement, dated as of June 1, 1989 (B to Rule 24 Certificate dated June 8, 1989 in 70-5399).
(a) 31 --	Eighteenth Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (D-2 to Rule 24 Certificate dated October 1, 1986 in 70-7272).
(a) 32 --	Nineteenth Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (D-3 to Rule 24 Certificate dated October 1, 1986 in 70-7272).
(a) 33 --	Twenty-sixth Supplementary Capital Funds Agreement and Assignment, dated as of October 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(c) to Rule 24 Certificate dated November 2, 1992 in 70-7946).
(a) 34 --	Twenty-seventh Supplementary Capital Funds Agreement and Assignment, dated as of April 1, 1993, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946).
(a) 35 --	Twenty-ninth Supplementary Capital Funds Agreement and Assignment, dated as of April 1, 1994, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(f) to Rule 24 Certificate dated May 6, 1994 in 70-7946).
(a) 36 --	Thirtieth Supplementary Capital Funds Agreement and Assignment, dated as of August 1, 1996, among Entergy Corporation, System Energy and United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(a) to Rule 24 Certificate dated August 8, 1996 in 70-8511).
(a) 37 --	Thirty-first Supplementary Capital Funds Agreement and Assignment, dated as of August 1, 1996, among Entergy Corporation, System Energy and United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(b) to Rule 24 Certificate dated August 8, 1996 in 70-8511).
(a) 38 --	Thirty-second Supplementary Capital Funds Agreement and Assignment, dated as of December 27, 1996, among Entergy Corporation, System Energy and The Chase Manhattan Bank (B-1(a) to Rule 24 Certificate dated January 13, 1997 in 70-7561).
(a) 39 --	Thirty-third Supplementary Capital Funds Agreement and Assignment, dated as of December 20, 1999, among Entergy Corporation, System Energy and The Chase Manhattan Bank (B-3(b) to Rule 24 Certificate dated March 3, 2000 in 70-7561).
(a) 40 --	Thirty-fourth Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 2002, among Entergy Corporation, System Energy, The Bank of New York and Douglas J. MacInnes (B-3(a)(1) to Rule 24 Certificate dated October 4, 2002 in 70-9753).
(a) 41 --	First Amendment to Supplementary Capital Funds Agreements and Assignments, dated as of June 1, 1989, by and between Entergy Corporation, System Energy, Deposit Guaranty National Bank, United States Trust Company of New York and Gerard F. Ganey (C to Rule 24 Certificate dated June 8, 1989 in 70-7026).
(a) 42 --	First Amendment to Supplementary Capital Funds Agreements and Assignments, dated as of June 1, 1989, by and between Entergy Corporation, System Energy, United States Trust Company of New York and Gerard F. Ganey (C to Rule 24 Certificate dated June 8, 1989 in 70-7123).
(a) 43 --	First Amendment to Supplementary Capital Funds Agreement and Assignment, dated as of June 1, 1989, by and between Entergy Corporation, System Energy and Chemical Bank (C to Rule 24 Certificate dated June 8, 1989 in 70-7561).
(a) 44 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
(a) 45 --	Joint Construction, Acquisition and Ownership Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B-1(a) in 70-6337), as amended by Amendment No. 1, dated as of May 1, 1980 (B-1(c) in 70-6337) and Amendment No. 2, dated as of October 31, 1980 (1 to Rule 24 Certificate dated October 30, 1981 in 70-6337).
(a) 46 --	Operating Agreement dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337).
(a) 47 --	Assignment, Assumption and Further Agreement No. 1, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561).
(a) 48 --	Assignment, Assumption and Further Agreement No. 2, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561).
(a) 49 --	Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B(3)(a) in 70-6337).
(a) 50 --	Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033).
(a) 51 --	Compromise and Settlement Agreement, dated June 4, 1982, between Texaco, Inc. and Entergy Louisiana (28(a) to Form 8-K dated June 4, 1982 in 1-3517).
(a) 52 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)-39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(a) 53 --	First Amendment to Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
(a) 54 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(a) 55 --	Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
(a) 56 --	First Amendment, dated January 1, 1990, to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).
(a) 57 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
(a) 58 --	Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
(a) 59 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
(a) 60 --	Guaranty Agreement between Entergy Corporation and Entergy Arkansas, dated as of September 20, 1990 (B-1(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).
(a) 61 --	Guarantee Agreement between Entergy Corporation and Entergy Louisiana, dated as of September 20, 1990 (B-2(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).
(a) 62 --	Guarantee Agreement between Entergy Corporation and System Energy, dated as of September 20, 1990 (B-3(a) to Rule 24 Certificate dated September 27, 1990 in 70- 7757).
(a) 63 --	Loan Agreement between Entergy Operations and Entergy Corporation, dated as of September 20, 1990 (B-12(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679).
(a) 64 --	Loan Agreement between Entergy Power and Entergy Corporation, dated as of August 28, 1990 (A-4(b) to Rule 24 Certificate dated September 6, 1990 in 70-7684).
(a) 65 --	Loan Agreement between Entergy Corporation and Entergy Systems and Service, Inc., dated as of December 29, 1992 (A-4(b) to Rule 24 Certificate in 70-7947).
+(a) 66 --	Executive Financial Counseling Program of Entergy Corporation and Subsidiaries (10(a)64 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 67 --	Entergy Corporation Executive Annual Incentive Plan (10(a)65 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 68 --	Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate dated May 24, 1991 in 70-7831).
+(a) 69 --	Amendment No. 1 to the Equity Ownership Plan of Entergy Corporation and Subsidiaries (10(a) 71 to Form 10-K for the year ended December 31, 1992 in 1-3517).
+(a) 70 --	1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries (Filed with the Proxy Statement dated March 30, 1998).
+(a) 71 --	Amendments, effective June 13, 2000 and December 7, 2001, to the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries (10(a)69 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 72 --	Amendment, effective December 10, 2001, to the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries (10(a) to Form 10-Q for the quarter ended March 31, 2002 in 1-11299).
+(a) 73 --	Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)70 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 74 --	Amendment, effective December 28, 2001, to the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries (10(a)71 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 75 --	Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)72 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 76 --	Amendment, effective December 28, 2001, to the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries (10(a)73 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 77 --	Executive Disability Plan of Entergy Corporation and Subsidiaries (10(a)74 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 78 --	Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)75 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 79 --	Amendment, effective December 7, 2001, to the Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries (10(a)76 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 80 --	Amendment, effective December 10, 2001, to the Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries (10(c) to Form 10-Q for the quarter ended March 31, 2002 in 1-11299).
+(a) 81 --	Equity Awards Plan of Entergy Corporation and Subsidiaries, effective as of August 31, 2000 (10(a)77 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 82 --	Amendment, effective December 7, 2001, to the Equity Awards Plan of Entergy Corporation and Subsidiaries (10(a)78 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 83 --	Amendment, effective December 10, 2001, to the Equity Awards Plan of Entergy Corporation and Subsidiaries (10(b) to Form 10-Q for the quarter ended March 31, 2002 in 1-11299).
+(a) 84 --	System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective as of March 1, 2000 (10(a)79 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 85 --	Post-Retirement Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)80 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 86 --	Amendment, effective December 28, 2001, to the Post-Retirement Plan of Entergy Corporation and Subsidiaries (10(a)81 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 87 --	Pension Equalization Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)82 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 88 --	Amendment, effective December 28, 2001, to the Pension Equalization Plan of Entergy Corporation and Subsidiaries (10(a)83 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 89 --	Service Recognition Program for Non-Employee Outside Directors of Entergy Corporation and Subsidiaries, effective January 1, 2000 (10(a)84 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 90 --	Stock Plan for Outside Directors of Entergy Corporation and Subsidiaries, as amended (10(a) 74 to Form 10-K for the year ended December 31, 1992 in 1-3517).
+(a) 91 --	Executive Income Security Plan of Gulf States Utilities Company, as amended effective March 1, 1991 (10(a)86 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 92 --	System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 1, 2000 (10(a)87 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 93 --	Amendment, effective December 28, 2001, to the System Executive Retirement Plan of Entergy Corporation and Subsidiaries (10(a)88 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 94 --	Retention Agreement effective October 27, 2000 between J. Wayne Leonard and Entergy Corporation (10(a)81 to Form 10-K for the year ended December 31, 2000 in 1-11299).
+(a) 95 --	Retention Agreement effective July 29, 2000 between Frank F. Gallaher and Entergy Corporation (10(a)82 to Form 10-K for the year ended December 31, 2000 in 1-11299).
+(a) 96 --	Letter Agreement effective July 25, 2001 between Jerry D. Jackson and Entergy Corporation (10(a)91 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 97 --	Retention Agreement effective July 29, 2000 between Donald C. Hintz and Entergy Corporation (10(a)85 to Form 10-K for the year ended December 31, 2000 in 1-11299).
+(a) 98 --	Retention Agreement effective July 29, 2000 between Michael G. Thompson and Entergy Corporation (10(a)86 to Form 10-K for the year ended December 31, 2000 in 1-11299).
+(a) 99 --	Retention Agreement effective January 22, 2001 between Richard J. Smith and Entergy Services, Inc (10(a)87 to Form 10-K for the year ended December 31, 2000 in 1-11299).
+(a) 100 --	Retention Agreement effective July 29, 2000 between Jerry W. Yelverton and Entergy Corporation (10(a)89 to Form 10-K for the year ended December 31, 2000 in 1-11299).
+(a) 101 --	Retention Agreement effective July 29, 2000 between C. John Wilder and Entergy Corporation (10(a)90 to Form 10-K for the year ended December 31, 2000 in 1-11299).
+(a) 102 --	Employment Agreement effective August 7, 2001 between Curt L. Hebert and Entergy Corporation (10(a)97 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 103 --	Agreement of Limited Partnership of Entergy-Koch, LP among EKLP, LLC, EK Holding I, LLC, EK Holding II, LLC and Koch Energy, Inc. dated January 31, 2001 (10(a)94 to Form 10-K/A for the year ended December 31, 2000 in 1-11299).

System Energy

(b) 1 through (b) 15 -- See 10(a)-14 through 10(a)-28 above.
(b) 16 through (b) 30 -- See 10(a)-29 through 10(a)-43 above.
(b) 31 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
(b) 32 --	Joint Construction, Acquisition and Ownership Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B-1(a) in 70-6337), as amended by Amendment No. 1, dated as of May 1, 1980 (B-1(c) in 70-6337) and Amendment No. 2, dated as of October 31, 1980 (1 to Rule 24 Certificate dated October 30, 1981 in 70-6337).
(b) 33 --	Operating Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337).
(b) 34 --	Amended and Restated Installment Sale Agreement, dated as of February 15, 1996, between System Energy and Claiborne County, Mississippi (B-6(a) to Rule 24 Certificate dated March 4, 1996 in 70-8511).
(b) 35 --	Loan Agreement, dated as of October 15, 1998, between System Energy and Mississippi Business Finance Corporation (B-6(b) to Rule 24 Certificate dated November 12, 1998 in 70-8511).
(b) 36 --	Loan Agreement, dated as of May 15, 1999, between System Energy and Mississippi Business Finance Corporation (B-6(c) to Rule 24 Certificate dated June 8, 1999 in 70-8511).
(b) 37 --	Facility Lease No. 1, dated as of December 1, 1988, between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (1) to Rule 24 Certificate dated April 21, 1989 in 70-7561) and Lease Supplement No. 2 dated as of January 1, 1994 (B-3(d) to Rule 24 Certificate dated January 31, 1994 in 70-8215).
(b) 38 --	Facility Lease No. 2, dated as of December 1, 1988 between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (2) to Rule 24 Certificate dated April 21, 1989 in 70-7561) and Lease Supplement No. 2 dated as of January 1, 1994 (B-4(d) Rule 24 Certificate dated January 31, 1994 in 70-8215).
(b) 39 --	Assignment, Assumption and Further Agreement No. 1, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561).
(b) 40 --	Assignment, Assumption and Further Agreement No. 2, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561).
(b) 41 --	Collateral Trust Indenture, dated as of January 1, 1994, among System Energy, GG1B Funding Corporation and Bankers Trust Company, as Trustee (A-3(e) to Rule 24 Certificate dated January 31, 1994 in 70-8215), as supplemented by Supplemental Indenture No. 1 dated January 1, 1994, (A-3(f) to Rule 24 Certificate dated January 31, 1994 in 70-8215).
(b) 42 --	Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B(3)(a) in 70-6337).
(b) 43 --	Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033).
(b) 44 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)-39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(b) 45 --	First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
(b) 46 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(b) 47 --	Fuel Lease, dated as of February 24, 1989, between River Fuel Funding Company #3, Inc. and System Energy (B-1(b) to Rule 24 Certificate dated March 3, 1989 in 70-7604).
(b) 48 --	System Energy's Consent, dated January 31, 1995, pursuant to Fuel Lease, dated as of February 24, 1989, between River Fuel Funding Company #3, Inc. and System Energy (B-1(c) to Rule 24 Certificate dated February 13, 1995 in 70-7604).
(b) 49 --	Sales Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (D to Rule 24 Certificate dated June 26, 1974 in 70-5399).
(b) 50 --	Service Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (E to Rule 24 Certificate dated June 26, 1974 in 70-5399).
(b) 51 --	Partial Termination Agreement, dated as of December 1, 1986, between System Energy and Entergy Mississippi (A-2 to Rule 24 Certificate dated January 8, 1987 in 70-5399).
(b) 52 --	Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
(b) 53 --	First Amendment, dated January 1, 1990 to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).
(b) 54 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
(b) 55 --	Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
(b) 56 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
(b) 57 --	Service Agreement with Entergy Services, dated as of July 16, 1974, as amended (10(b)-43 to Form 10-K for the year ended December 31, 1988 in 1-9067).
(b) 58 --	Amendment, dated January 1, 1991, to Service Agreement with Entergy Services (10(b)-45 to Form 10-K for the year ended December 31, 1990 in 1-9067).
(b) 59 --	Amendment, dated January 1, 1992, to Service Agreement with Entergy Services (10(a) -11 to Form 10-K for the year ended December 31, 1994 in 1-3517).
(b) 60 --	Operating Agreement between Entergy Operations and System Energy, dated as of June 6, 1990 (B-3(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679).
(b) 61 --	Guarantee Agreement between Entergy Corporation and System Energy, dated as of September 20, 1990 (B-3(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).
(b) 62 --	Amended and Restated Reimbursement Agreement, dated as of December 1, 1988 as amended and restated as of December 20, 1999, among System Energy Resources, Inc., The Bank of Tokyo-Mitsubishi, Ltd., as Funding Bank and The Chase Manhattan Bank, as administrating bank, Union Bank of California, N.A., as documentation agent, and the Banks named therein, as Participating Banks (B-1(b) to Rule 24 Certificate dated March 3, 2000 in 70-7561).

Entergy Arkansas

(c) 1 --	Agreement, dated April 23, 1982, among Entergy Arkansas and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a) 1 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(c) 2 --	Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)2 in 2-41080).
(c) 3 --	Amendment, dated February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)-4 in 2-41080).
(c) 4 --	Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) 4 in 2-41080).
(c) 5 --	Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)-3 in 2-41080).
(c) 6 --	Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)-5 in 2-41080).
(c) 7 --	Amendment, dated January 1, 1972, to Service Agreement with Entergy Services (5(a)- 6 in 2-43175).
(c) 8 --	Amendment, dated April 27, 1984, to Service Agreement, with Entergy Services (10(a)- 7 to Form 10-K for the year ended December 31, 1984 in 1-3517).
(c) 9 --	Amendment, dated August 1, 1988, to Service Agreement with Entergy Services (10(c)- 8 to Form 10-K for the year ended December 31, 1988 in 1-10764).
(c) 10 --	Amendment, dated January 1, 1991, to Service Agreement with Entergy Services (10(c)-9 to Form 10-K for the year ended December 31, 1990 in 1-10764).
(c) 11 --	Amendment, dated January 1, 1992, to Service Agreement with Entergy Services (10(c)-11 to Form 10-K for the year ended December 31, 1994 in 1-10764).
*(c) 12 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services.
*(c) 13 --	Amendment, dated April 1, 2002, to Service Agreement with Entergy Services.
(c) 14 through (c) 28 -- See 10(a)-14 through 10(a)-28 above.
(c) 29 --	Agreement, dated August 20, 1954, between Entergy Arkansas and the United States of America (SPA)(13(h) in 2-11467).
(c) 30 --	Amendment, dated April 19, 1955, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-2 in 2-41080).
(c) 31 --	Amendment, dated January 3, 1964, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-3 in 2-41080).
(c) 32 --	Amendment, dated September 5, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-4 in 2-41080).
(c) 33 --	Amendment, dated November 19, 1970, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-5 in 2-41080).
(c) 34 --	Amendment, dated July 18, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-6 in 2-41080).
(c) 35 --	Amendment, dated December 27, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-7 in 2-41080).
(c) 36 --	Amendment, dated January 25, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-8 in 2-41080).
(c) 37 --	Amendment, dated October 14, 1971, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-9 in 2-43175).
(c) 38 --	Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)-10 in 2-60233).
(c) 39 --	Agreement, dated May 14, 1971, between Entergy Arkansas and the United States of America (SPA) (5(e) in 2-41080).
(c) 40 --	Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated May 14, 1971 (5(e)-1 in 2-60233).
(c) 41 --	Contract, dated May 28, 1943, Amendment to Contract, dated July 21, 1949, and Supplement to Amendment to Contract, dated December 30, 1949, between Entergy Arkansas and McKamie Gas Cleaning Company; Agreements, dated as of September 30, 1965, between Entergy Arkansas and former stockholders of McKamie Gas Cleaning Company; and Letter Agreement, dated June 22, 1966, by Humble Oil & Refining Company accepted by Entergy Arkansas on June 24, 1966 (5(k)-7 in 2-41080).
(c) 42 --	Agreement, dated April 3, 1972, between Entergy Services and Gulf United Nuclear Fuels Corporation (5(l)-3 in 2-46152).
(c) 43 --	Fuel Lease, dated as of December 22, 1988, between River Fuel Trust #1 and Entergy Arkansas (B-1(b) to Rule 24 Certificate in 70-7571).
(c) 44 --	White Bluff Operating Agreement, dated June 27, 1977, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas (B-2(a) to Rule 24 Certificate dated June 30, 1977 in 70-6009).
(c) 45 --	White Bluff Ownership Agreement, dated June 27, 1977, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas (B-1(a) to Rule 24 Certificate dated June 30, 1977 in 70-6009).
(c) 46 --	Agreement, dated June 29, 1979, between Entergy Arkansas and City of Conway, Arkansas (5(r)-3 in 2-66235).
(c) 47 --	Transmission Agreement, dated August 2, 1977, between Entergy Arkansas and City Water and Light Plant of the City of Jonesboro, Arkansas (5(r)-3 in 2-60233).
(c) 48 --	Power Coordination, Interchange and Transmission Service Agreement, dated as of June 27, 1977, between Arkansas Electric Cooperative Corporation and Entergy Arkansas (5(r)-4 in 2-60233).
(c) 49 --	Independence Steam Electric Station Operating Agreement, dated July 31, 1979, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas and City of Conway, Arkansas (5(r)-6 in 2-66235).
(c) 50 --	Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c) 51 to Form 10-K for the year ended December 31, 1984 in 1-10764).
(c) 51 --	Independence Steam Electric Station Ownership Agreement, dated July 31, 1979, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas and City of Conway, Arkansas (5(r)-7 in 2-66235).
(c) 52 --	Amendment, dated December 28, 1979, to the Independence Steam Electric Station Ownership Agreement (5(r)-7(a) in 2-66235).
(c) 53 --	Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c) 54 to Form 10-K for the year ended December 31, 1984 in 1-10764).
(c) 54 --	Owner's Agreement, dated November 28, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station (10(c) 55 to Form 10-K for the year ended December 31, 1984 in 1-10764).
(c) 55 --	Consent, Agreement and Assumption, dated December 4, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station and United States Trust Company of New York, as Trustee (10(c) 56 to Form 10-K for the year ended December 31, 1984 in 1-10764).
(c) 56 --	Power Coordination, Interchange and Transmission Service Agreement, dated as of July 31, 1979, between Entergy Arkansas and City Water and Light Plant of the City of Jonesboro, Arkansas (5(r)-8 in 2-66235).
(c) 57 --	Power Coordination, Interchange and Transmission Agreement, dated as of June 29, 1979, between City of Conway, Arkansas and Entergy Arkansas (5(r)-9 in 2-66235).
(c) 58 --	Agreement, dated June 21, 1979, between Entergy Arkansas and Reeves E. Ritchie ((10)(b)-90 to Form 10-K for the year ended December 31, 1980 in 1-10764).
(c) 59 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
(c) 60 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (10(a) 39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(c) 61 --	First Amendment to Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
(c) 62 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(c) 63 --	Contract For Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste, dated June 30, 1983, among the DOE, System Fuels and Entergy Arkansas (10(b)-57 to Form 10-K for the year ended December 31, 1983 in 1-10764).
(c) 64 --	Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
(c) 65 --	First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).
(c) 66 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
(c) 67 --	Third Amendment dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
(c) 68 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
(c) 69 --	Assignment of Coal Supply Agreement, dated December 1, 1987, between System Fuels and Entergy Arkansas (B to Rule 24 letter filing dated November 10, 1987 in 70-5964).
(c) 70 --	Coal Supply Agreement, dated December 22, 1976, between System Fuels and Antelope Coal Company (B-1 in 70-5964), as amended by First Amendment (A to Rule 24 Certificate in 70-5964); Second Amendment (A to Rule 24 letter filing dated December 16, 1983 in 70-5964); and Third Amendment (A to Rule 24 letter filing dated November 10, 1987 in 70-5964).
(c) 71 --	Operating Agreement between Entergy Operations and Entergy Arkansas, dated as of June 6, 1990 (B-1(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679).
(c) 72 --	Guaranty Agreement between Entergy Corporation and Entergy Arkansas, dated as of September 20, 1990 (B-1(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).
(c) 73 --	Agreement for Purchase and Sale of Independence Unit 2 between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-3(c) to Rule 24 Certificate dated September 6, 1990 in 70-7684).
(c) 74 --	Agreement for Purchase and Sale of Ritchie Unit 2 between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-4(d) to Rule 24 Certificate dated September 6, 1990 in 70-7684).
(c) 75 --	Ritchie Steam Electric Station Unit No. 2 Operating Agreement between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-5(a) to Rule 24 Certificate dated September 6, 1990 in 70-7684).
(c) 76 --	Ritchie Steam Electric Station Unit No. 2 Ownership Agreement between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-6(a) to Rule 24 Certificate dated September 6, 1990 in 70-7684).
(c) 77 --	Power Coordination, Interchange and Transmission Service Agreement between Entergy Power and Entergy Arkansas, dated as of August 28, 1990 (10(c)-71 to Form 10-K for the year ended December 31, 1990 in 1-10764).
(c) 78 --	Loan Agreement dated June 15, 1993, between Entergy Arkansas and Independence Country, Arkansas (B-1 (a) to Rule 24 Certificate dated July 9, 1993 in 70-8171).
(c) 79 --	Loan Agreement dated June 15, 1994, between Entergy Arkansas and Jefferson County, Arkansas (B-1(a) to Rule 24 Certificate dated June 30, 1994 in 70-8405).
(c) 80 --	Loan Agreement dated June 15, 1994, between Entergy Arkansas and Pope County, Arkansas (B-1(b) to Rule 24 Certificate in 70-8405).
(c) 81 --	Loan Agreement dated November 15, 1995, between Entergy Arkansas and Pope County, Arkansas (10(c) 96 to Form 10-K for the year ended December 31, 1995 in 1-10764).
(c) 82 --	Agreement as to Expenses and Liabilities between Entergy Arkansas and Entergy Arkansas Capital I, dated as of August 14, 1996 (4(j) to Form 10-Q for the quarter ended September 30, 1996 in 1-10764).
(c) 83 --	Loan Agreement dated December 1, 1997, between Entergy Arkansas and Jefferson County, Arkansas (10(c)100 to Form 10-K for the year ended December 31, 1997 in 1-10764).
(c) 84 --	Refunding Agreement, dated December 1, 2001, between Entergy Arkansas and Pope Country, Arkansas (10(c)81 to Form 10-K for the year ended December 31, 2001 in 1-10764).

Entergy Gulf States

(d) 1 --	Guaranty Agreement, dated July 1, 1976, between Entergy Gulf States and American Bank and Trust Company (C and D to Form 8-K dated August 6, 1976 in 1-27031).
(d) 2 --	Guaranty Agreement, dated August 1, 1992, between Entergy Gulf States and Hibernia National Bank, relating to Pollution Control Revenue Refunding Bonds of the Industrial Development Board of the Parish of Calcasieu, Inc. (Louisiana) (10-1 to Form 10-K for the year ended December 31, 1992 in 1-27031).
(d) 3 --	Guaranty Agreement, dated January 1, 1993, between Entergy Gulf States and Hancock Bank of Louisiana, relating to Pollution Control Revenue Refunding Bonds of the Parish of Pointe Coupee (Louisiana) (10-2 to Form 10-K for the year ended December 31, 1992 in 1-27031).
(d) 4 --	Deposit Agreement, dated as of December 1, 1983 between Entergy Gulf States, Morgan Guaranty Trust Co. as Depositary and the Holders of Depository Receipts, relating to the Issue of 900,000 Depositary Preferred Shares, each representing 1/2 share of Adjustable Rate Cumulative Preferred Stock, Series E-$100 Par Value (4-17 to Form 10-K for the year ended December 31, 1983 in 1-27031).
(d) 5 --	Agreement effective February 1, 1964, between Sabine River Authority, State of Louisiana, and Sabine River Authority of Texas, and Entergy Gulf States, Central Louisiana Electric Company, Inc., and Louisiana Power & Light Company, as supplemented (B to Form 8-K dated May 6, 1964, A to Form 8-K dated October 5, 1967, A to Form 8-K dated May 5, 1969, and A to Form 8-K dated December 1, 1969 in 1-27031).
(d) 6 --	Joint Ownership Participation and Operating Agreement regarding River Bend Unit 1 Nuclear Plant, dated August 20, 1979, between Entergy Gulf States, Cajun, and SRG&T; Power Interconnection Agreement with Cajun, dated June 26, 1978, and approved by the REA on August 16, 1979, between Entergy Gulf States and Cajun; and Letter Agreement regarding CEPCO buybacks, dated August 28, 1979, between Entergy Gulf States and Cajun (2, 3, and 4, respectively, to Form 8-K dated September 7, 1979 in 1-27031).
(d) 7 --	Ground Lease, dated August 15, 1980, between Statmont Associates Limited Partnership (Statmont) and Entergy Gulf States, as amended (3 to Form 8-K dated August 19, 1980 and A-3-b to Form 10-Q for the quarter ended September 30, 1983 in 1-27031).
(d) 8 --	Lease and Sublease Agreement, dated August 15, 1980, between Statmont and Entergy Gulf States, as amended (4 to Form 8-K dated August 19, 1980 and A-3-c to Form 10-Q for the quarter ended September 30, 1983 in 1-27031).
(d) 9 --	Lease Agreement, dated September 18, 1980, between BLC Corporation and Entergy Gulf States (1 to Form 8-K dated October 6, 1980 in 1-27031).
(d) 10 --	Joint Ownership Participation and Operating Agreement for Big Cajun, between Entergy Gulf States, Cajun Electric Power Cooperative, Inc., and Sam Rayburn G&T, Inc, dated November 14, 1980 (6 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 1, dated December 12, 1980 (7 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 2, dated December 29, 1980 (8 to Form 8-K dated January 29, 1981 in 1-27031).
(d) 11 --	Agreement of Joint Ownership Participation between SRMPA, SRG&T and Entergy Gulf States, dated June 6, 1980, for Nelson Station, Coal Unit #6, as amended (8 to Form 8-K dated June 11, 1980, A-2-b to Form 10-Q for the quarter ended June 30, 1982; and 10-1 to Form 8-K dated February 19, 1988 in 1-27031).
(d) 12 --	Agreements between Southern Company and Entergy Gulf States, dated February 25, 1982, which cover the construction of a 140-mile transmission line to connect the two systems, purchase of power and use of transmission facilities (10-31 to Form 10-K for the year ended December 31, 1981 in 1-27031).
(d) 13 --	Transmission Facilities Agreement between Entergy Gulf States and Mississippi Power Company, dated February 28, 1982, and Amendment, dated May 12, 1982 (A-2-c to Form 10-Q for the quarter ended March 31, 1982 in 1-27031) and Amendment, dated December 6, 1983 (10-43 to Form 10-K for the year ended December 31, 1983 in 1-27031).
(d) 14 --	First Amended Power Sales Agreement, dated December 1, 1985 between Sabine River Authority, State of Louisiana, and Sabine River Authority, State of Texas, and Entergy Gulf States, Central Louisiana Electric Co., Inc., and Louisiana Power and Light Company (10-72 to Form 10-K for the year ended December 31, 1985 in 1-27031).
+(d) 15 --	Deferred Compensation Plan for Directors of Entergy Gulf States and Varibus Corporation, as amended January 8, 1987, and effective January 1, 1987 (10-77 to Form 10-K for the year ended December 31, 1986 in 1-27031). Amendment dated December 4, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551).
+(d) 16 --	Trust Agreement for Deferred Payments to be made by Entergy Gulf States pursuant to the Executive Income Security Plan, by and between Entergy Gulf States and Bankers Trust Company, effective November 1, 1986 (10-78 to Form 10-K for the year ended December 31, 1986 in 1-27031).
+(d) 17 --	Trust Agreement for Deferred Installments under Entergy Gulf States' Management Incentive Compensation Plan and Administrative Guidelines by and between Entergy Gulf States and Bankers Trust Company, effective June 1, 1986 (10-79 to Form 10-K for the year ended December 31, 1986 in 1-27031).
+(d) 18 --	Nonqualified Deferred Compensation Plan for Officers, Nonemployee Directors and Designated Key Employees, effective December 1, 1985, as amended, continued and completely restated effective as of March 1, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551).
+(d) 19 --	Trust Agreement for Entergy Gulf States' Nonqualified Directors and Designated Key Employees by and between Entergy Gulf States and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective July 1, 1991 (10-4 to Form 10-K for the year ended December 31, 1992 in 1-27031).
(d) 20 --	Lease Agreement, dated as of June 29, 1987, among GSG&T, Inc., and Entergy Gulf States related to the leaseback of the Lewis Creek generating station (10-83 to Form 10-K for the year ended December 31, 1988 in 1-27031).
(d) 21 --	Nuclear Fuel Lease Agreement between Entergy Gulf States and River Bend Fuel Services, Inc. to lease the fuel for River Bend Unit 1, dated February 7, 1989 (10-64 to Form 10-K for the year ended December 31, 1988 in 1-27031).
(d) 22 --	Trust and Investment Management Agreement between Entergy Gulf States and Morgan Guaranty and Trust Company of New York (the "Decommissioning Trust Agreement) with respect to decommissioning funds authorized to be collected by Entergy Gulf States, dated March 15, 1989 (10-66 to Form 10-K for the year ended December 31, 1988 in 1-27031).
(d) 23 --	Amendment No. 2 dated November 1, 1995 between Entergy Gulf States and Mellon Bank to Decommissioning Trust Agreement (10(d) 31 to Form 10-K for the year ended December 31, 1995 in 1-27031).
(d) 24 --	Partnership Agreement by and among Conoco Inc., and Entergy Gulf States, CITGO Petroleum Corporation and Vista Chemical Company, dated April 28, 1988 (10-67 to Form 10-K for the year ended December 31, 1988 in 1-27031).
+(d) 25 --	Gulf States Utilities Company Executive Continuity Plan, dated January 18, 1991 (10-6 to Form 10-K for the year ended December 31, 1990 in 1-27031).
+(d) 26 --	Trust Agreement for Entergy Gulf States' Executive Continuity Plan, by and between Entergy Gulf States and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective May 20, 1991 (10-5 to Form 10-K for the year ended December 31, 1992 in 1-27031).
+(d) 27 --	Gulf States Utilities Board of Directors' Retirement Plan, dated February 15, 1991 (10-8 to Form 10-K for the year ended December 31, 1990 in 1-27031).
(d) 28 --	Operating Agreement between Entergy Operations and Entergy Gulf States, dated as of December 31, 1993 (B-2(f) to Rule 24 Certificate in 70-8059).
(d) 29 --	Guarantee Agreement between Entergy Corporation and Entergy Gulf States, dated as of December 31, 1993 (B-5(a) to Rule 24 Certificate in 70-8059).
(d) 30 --	Service Agreement with Entergy Services, dated as of December 31, 1993 (B-6(c) to Rule 24 Certificate in 70-8059).
*(d) 31 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services.
*(d) 32 --	Amendment, dated April 1, 2002, to Service Agreement with Entergy Services.
(d) 33 --	Third Amendment, dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
(d) 34 --	Fourth Amendment, dated April 1, 1997, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
(d) 35 --	Agreement as to Expenses and Liabilities between Entergy Gulf States and Entergy Gulf States Capital I, dated as of January 28, 1997 (10(d)52 to Form 10-K for the year ended December 31, 1996 in 1-27031).
(d) 36 --	Refunding Agreement dated as of May 1, 1998 between Entergy Gulf States and Parish of Iberville, State of Louisiana (B-3(a) to Rule 24 Certificate dated May 29, 1998 in 70-8721).
(d) 37 --	Refunding Agreement dated as of May 1, 1998 between Entergy Gulf States and Industrial Development Board of the Parish of Calcasieu, Inc. (B-3(b) to Rule 24 Certificate dated January 29, 1999 in 70-8721).
(d) 38 --	Refunding Agreement (Series 1999-A) dated as of September 1, 1999 between Entergy Gulf States and Parish of West Feliciana, State of Louisiana (B-3(c) to Rule 24 Certificate dated October 8, 1999 in 70-8721).
(d) 39 --	Refunding Agreement (Series 1999-B) dated as of September 1, 1999 between Entergy Gulf States and Parish of West Feliciana, State of Louisiana (B-3(d) to Rule 24 Certificate dated October 8, 1999 in 70-8721).

Entergy Louisiana

(e) 1 --	Agreement, dated April 23, 1982, among Entergy Louisiana and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a) 1 to Form 10-K for the year ended December 31, 1982, in 1-3517).
(e) 2 --	Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)-2 in 2-41080).
(e) 3 --	Amendment, dated as of February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)-4 in 2-41080).
(e) 4 --	Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) 4 in 2-41080).
(e) 5 --	Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)-3 in 2-41080).
(e) 6 --	Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)-5 in 2-42523).
(e) 7 --	Amendment, dated as of January 1, 1972, to Service Agreement with Entergy Services (4(a)-6 in 2-45916).
(e) 8 --	Amendment, dated as of April 27, 1984, to Service Agreement with Entergy Services (10(a) 7 to Form 10-K for the year ended December 31, 1984 in 1-3517).
(e) 9 --	Amendment, dated as of August 1, 1988, to Service Agreement with Entergy Services (10(d)-8 to Form 10-K for the year ended December 31, 1988 in 1-8474).
(e) 10 --	Amendment, dated January 1, 1991, to Service Agreement with Entergy Services (10(d)-9 to Form 10-K for the year ended December 31, 1990 in 1-8474).
(e) 11 --	Amendment, dated January 1, 1992, to Service Agreement with Entergy Services (10(e)-11 to Form 10-K for the year ended December 31, 1994 in 1-8474).
*(e) 12 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services.
*(e) 13 --	Amendment, dated April 1, 2002, to Service Agreement with Entergy Services.
(e) 14 through (e) 28 -- See 10(a)-14 through 10(a)-28 above.
(e) 29 --	Fuel Lease, dated as of January 31, 1989, between River Fuel Company #2, Inc., and Entergy Louisiana (B-1(b) to Rule 24 Certificate in 70-7580).
(e) 30 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
(e) 31 --	Compromise and Settlement Agreement, dated June 4, 1982, between Texaco, Inc. and Entergy Louisiana (28(a) to Form 8-K dated June 4, 1982 in 1-8474).
(e) 32 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a) 39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(e) 33 --	First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
(e) 34 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(e) 35 --	Middle South Utilities, Inc. and Subsidiary Companies Intercompany Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
(e) 36 --	First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated January 1, 1990 (D-2 to Form U5S for the year ended December 31, 1989).
(e) 37 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
(e) 38 --	Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
(e) 39 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
(e) 40 --	Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste, dated February 2, 1984, among DOE, System Fuels and Entergy Louisiana (10(d)33 to Form 10-K for the year ended December 31, 1984 in 1-8474).
(e) 41 --	Operating Agreement between Entergy Operations and Entergy Louisiana, dated as of June 6, 1990 (B-2(c) to Rule 24 Certificate dated June 15, 1990 in 70-7679).
(e) 42 --	Guarantee Agreement between Entergy Corporation and Entergy Louisiana, dated as of September 20, 1990 (B-2(a), to Rule 24 Certificate dated September 27, 1990 in 70-7757).
(e) 43 --	Installment Sale Agreement, dated July 20, 1994, between Entergy Louisiana and St. Charles Parish, Louisiana (B-6(e) to Rule 24 Certificate dated August 1, 1994 in 70-7822).
(e) 44 --	Installment Sale Agreement, dated November 1, 1995, between Entergy Louisiana and St. Charles Parish, Louisiana (B-6(a) to Rule 24 Certificate dated December 19, 1995 in 70-8487).
(e) 45 --	Refunding Agreement (Series 1999-A), dated as of June 1, 1999, between Entergy Louisiana and Parish of St. Charles, State of Louisiana (B-6(a) to Rule 24 Certificate dated July 6, 1999 in 70-9141).
(e) 46 --	Refunding Agreement (Series 1999-B), dated as of June 1, 1999, between Entergy Louisiana and Parish of St. Charles, State of Louisiana (B-6(b) to Rule 24 Certificate dated July 6, 1999 in 70-9141).
(e) 47 --	Refunding Agreement (Series 1999-C), dated as of October 1, 1999, between Entergy Louisiana and Parish of St. Charles, State of Louisiana (B-11(a) to Rule 24 Certificate dated October 15, 1999 in 70-9141).
(e) 48 --	Agreement as to Expenses and Liabilities between Entergy Louisiana, Inc. and Entergy Louisiana Capital I dated July 16, 1996 (4(d) to Form 10-Q for the quarter ended June 30, 1996 in 1-8474).

Entergy Mississippi

(f) 1 --	Agreement dated April 23, 1982, among Entergy Mississippi and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a) 1 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(f) 2 --	Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)-2 in 2-41080).
(f) 3 --	Amendment, dated February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) 4 in 2-41080).
(f) 4 --	Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) 4 in 2-41080).
(f) 5 --	Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)-3 in 2-41080).
(f) 6 --	Service Agreement with Entergy Services, dated as of April 1, 1963 (D in 37-63).
(f) 7 --	Amendment, dated January 1, 1972, to Service Agreement with Entergy Services (A to Notice, dated October 14, 1971 in 37-63).
(f) 8 --	Amendment, dated April 27, 1984, to Service Agreement with Entergy Services (10(a) 7 to Form 10-K for the year ended December 31, 1984 in 1-3517).
(f) 9 --	Amendment, dated as of August 1, 1988, to Service Agreement with Entergy Services (10(e) 8 to Form 10-K for the year ended December 31, 1988 in 0-320).
(f) 10 --	Amendment, dated January 1, 1991, to Service Agreement with Entergy Services (10(e) 9 to Form 10-K for the year ended December 31, 1990 in 0-320).
(f) 11 --	Amendment, dated January 1, 1992, to Service Agreement with Entergy Services (10(a)-11 to Form 10-K for the year ended December 31, 1994 in 1-3517).
*(f) 12 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services.
*(f) 13 --	Amendment, dated April 1, 2002, to Service Agreement with Entergy Services.
(f) 14 through (f) 28 -- See 10(a)-14 through 10(a)-28 above.
(f) 29 --	Installment Sale Agreement, dated as of June 1, 1974, between Entergy Mississippi and Washington County, Mississippi (B-2(a) to Rule 24 Certificate dated August 1, 1974 in 70-5504).
(f) 30 --	Amended and Restated Installment Sale Agreement, dated as of April 1, 1994, between Entergy Mississippi and Warren County, Mississippi (B-6(a) to Rule 24 Certificate dated May 4, 1994 in 70-7914).
(f) 31 --	Amended and Restated Installment Sale Agreement, dated as of April 1, 1994, between Entergy Mississippi and Washington County, Mississippi, (B-6(b) to Rule 24 Certificate dated May 4, 1994 in 70-7914).
(f) 32 --	Refunding Agreement, dated as of May 1, 1999, between Entergy Mississippi and Independence County, Arkansas (B-6(a) to Rule 24 Certificate dated June 8, 1999 in 70-8719).
(f) 33 --	Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B-3(a) in 70-6337).
(f) 34 --	Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c) 51 to Form 10-K for the year ended December 31, 1984 in 0-375).
(f) 35 --	Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c) 54 to Form 10-K for the year ended December 31, 1984 in 0-375).
(f) 36 --	Owners Agreement, dated November 28, 1984, among Entergy Arkansas, Entergy Mississippi and other co-owners of the Independence Station (10(c) 55 to Form 10-K for the year ended December 31, 1984 in 0-375).
(f) 37 --	Consent, Agreement and Assumption, dated December 4, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station and United States Trust Company of New York, as Trustee (10(c) 56 to Form 10-K for the year ended December 31, 1984 in 0-375).
(f) 38 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
+(f) 39 --	Post-Retirement Plan (10(d) 24 to Form 10-K for the year ended December 31, 1983 in 0-320).
(f) 40 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (10(a) 39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(f) 41 --	First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
(f) 42 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(f) 43 --	Sales Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (D to Rule 24 Certificate dated June 26, 1974 in 70-5399).
(f) 44 --	Service Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (E to Rule 24 Certificate dated June 26, 1974 in 70-5399).
(f) 45 --	Partial Termination Agreement, dated as of December 1, 1986, between System Energy and Entergy Mississippi (A-2 to Rule 24 Certificate dated January 8, 1987 in 70-5399).
(f) 46 --	Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
(f) 47 --	First Amendment dated January 1, 1990 to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).
(f) 48 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
(f) 49 --	Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
(f) 50 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).

Entergy New Orleans

(g) 1 --	Agreement, dated April 23, 1982, among Entergy New Orleans and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)-1 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(g) 2 --	Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)-2 in 2-41080).
(g) 3 --	Amendment dated as of February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)-4 in 2-41080).
(g) 4 --	Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a) 4 in 2-41080).
(g) 5 --	Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)-3 in 2-41080).
(g) 6 --	Service Agreement with Entergy Services dated as of April 1, 1963 (5(a)-5 in 2-42523).
(g) 7 --	Amendment, dated as of January 1, 1972, to Service Agreement with Entergy Services (4(a)-6 in 2-45916).
(g) 8 --	Amendment, dated as of April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517).
(g) 9 --	Amendment, dated as of August 1, 1988, to Service Agreement with Entergy Services (10(f)-8 to Form 10-K for the year ended December 31, 1988 in 0-5807).
(g) 10 --	Amendment, dated January 1, 1991, to Service Agreement with Entergy Services (10(f)-9 to Form 10-K for the year ended December 31, 1990 in 0-5807).
(g) 11 --	Amendment, dated January 1, 1992, to Service Agreement with Entergy Services (10(a)-11 to Form 10-K for year ended December 31, 1994 in 1-3517).
*(g) 12 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services.
*(g) 13 --	Amendment, dated April 1, 2002, to Service Agreement with Entergy Services.
(g) 14 through (g) 28 -- See 10(a)-14 through 10(a)-28 above.
(g) 29 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
(g) 30 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a) 39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(g) 31 --	First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
(g) 32 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(g) 33 --	Transfer Agreement, dated as of June 28, 1983, among the City of New Orleans, Entergy New Orleans and Regional Transit Authority (2(a) to Form 8-K dated June 24, 1983 in 1-1319).
(g) 34 --	Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
(g) 35 --	First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).
(g) 36 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
(g) 37 --	Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
(g) 38 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).

(12) Statement Re Computation of Ratios

*(a)	Entergy Arkansas's Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.
*(b)	Entergy Gulf States' Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.
*(c)	Entergy Louisiana's Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.
*(d)	Entergy Mississippi's Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.
*(e)	Entergy New Orleans' Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.
*(f)	System Energy's Computation of Ratios of Earnings to Fixed Charges, as defined.

*(21) Subsidiaries of the Registrants

(23) Consents of Experts and Counsel

*(a) The consent of Deloitte & Touche LLP is contained herein at page 346.

*(24) Powers of Attorney

_________________

* Filed herewith.
+ Management contracts or compensatory plans or arrangements.