10-K 1 a10-kn.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)

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

	For the Fiscal Year Ended December 31, 2003
	OR
	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the transition period from ____________ to ____________

Commission File Number	Registrant, State of Incorporation, Address of Principal Executive Offices and Telephone Number	IRS Employer Identification No.
1-11299	ENTERGY CORPORATION (a Delaware corporation) 639 Loyola Avenue New Orleans, Louisiana 70113 Telephone (504) 576-4000	72-1229752

1-10764	ENTERGY ARKANSAS, INC. (an Arkansas corporation) 425 West Capitol Avenue Little Rock, Arkansas 72201 Telephone (501) 377-4000	71-0005900

1-27031	ENTERGY GULF STATES, INC. (a Texas corporation) 350 Pine Street Beaumont, Texas 77701 Telephone (409) 838-6631	74-0662730

1-8474	ENTERGY LOUISIANA, INC. (a Louisiana corporation) 4809 Jefferson Highway Jefferson, Louisiana 70121 Telephone (504) 840-2734	72-0245590

1-31508	ENTERGY MISSISSIPPI, INC. (a Mississippi corporation) 308 East Pearl Street Jackson, Mississippi 39201 Telephone (601) 368-5000	64-0205830

0-5807	ENTERGY NEW ORLEANS, INC. (a Louisiana corporation) 1600 Perdido Street, Building 505 New Orleans, Louisiana 70112 Telephone (504) 670-3674	72-0273040

1-9067	SYSTEM ENERGY RESOURCES, INC. (an Arkansas corporation) Echelon One 1340 Echelon Parkway Jackson, Mississippi 39213 Telephone (601) 368-5000	72-0752777

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

Registrant	Title of Class	Name of Each Exchange on Which Registered

Entergy Corporation	Common Stock, $0.01 Par Value - 231,032,604 shares outstanding at February 27, 2004	New York Stock Exchange, Inc. Chicago Stock Exchange Inc. Pacific Exchange Inc.

Entergy Arkansas, Inc.	Mortgage Bonds, 6.7% Series due April 2032 Mortgage Bonds, 6.0% Series due November 2032	New York Stock Exchange, Inc. New York Stock Exchange, Inc.

Entergy Arkansas Capital I	8-1/2% Cumulative Quarterly Income Preferred Securities, Series A (guaranteed by Entergy Arkansas, Inc.)	New York Stock Exchange, Inc.

Entergy Gulf States, Inc.	Preferred Stock, Cumulative, $100 Par Value: $4.40 Dividend Series $4.52 Dividend Series $5.08 Dividend Series Adjustable Rate Series B (Depository Receipts)	New York Stock Exchange, Inc. New York Stock Exchange, Inc. New York Stock Exchange, Inc. New York Stock Exchange, Inc.

Entergy Gulf States Capital I	8.75% Cumulative Quarterly Income Preferred Securities, Series A (guaranteed by Entergy Gulf States, Inc.)	New York Stock Exchange, Inc.

Entergy Louisiana, Inc.	Mortgage Bonds, 7.6% Series due April 2032	New York Stock Exchange, Inc.

Entergy Louisiana Capital I	9% Cumulative Quarterly Income Preferred Securities, Series A (guaranteed by Entergy Louisiana, Inc.)	New York Stock Exchange, Inc.

Entergy Mississippi, Inc.	Mortgage Bonds, 6.0% Series due November 2032 Mortgage Bonds, 7.25% Series due December 2032	New York Stock Exchange, Inc. New York Stock Exchange, Inc.

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

Registrant	Title of Class

Entergy Arkansas, Inc.	Preferred Stock, Cumulative, $100 Par Value Preferred Stock, Cumulative, $0.01 Par Value

Entergy Gulf States, Inc.	Preferred Stock, Cumulative, $100 Par Value

Entergy Louisiana, Inc.	Preferred Stock, Cumulative, $100 Par Value Preferred Stock, Cumulative, $25 Par Value

Entergy Mississippi, Inc.	Preferred Stock, Cumulative, $100 Par Value

Entergy New Orleans, Inc.	Preferred Stock, Cumulative, $100 Par Value

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

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

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

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

The aggregate market value of Entergy Corporation Common Stock, $0.01 Par Value, held by non-affiliates as of the end of the second quarter of 2003, was $12.0 billion based on the reported last sale price of $52.78 per share for such stock on the New York Stock Exchange on June 30, 2003. Entergy Corporation is the sole holder of the common stock of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc., and System Energy Resources, Inc.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders, to be held May 14, 2004, are incorporated by reference into Parts I and III hereof.

TABLE OF CONTENTS

	SEC Form 10-K Reference Number	Page Number

Definitions		i
Entergy's Business	Part I. Item 1.	1
Financial Information for U.S. Utility, Non-Utility Nuclear, and Energy Commodity Services		2
Strategy		3
Report of Management		4
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis	Part II. Item 7.
Results of Operations		5
Liquidity and Capital Resources		12
Significant Factors and Known Trends		21
Critical Accounting Estimates		33
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	41
Independent Auditors' Report		42
Consolidated Statements of Income For the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	43
Consolidated Statements of Cash Flows For the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	44
Consolidated Balance Sheets, December 31, 2003 and 2002	Part II. Item 8.	46
Consolidated Statements of Retained Earnings, Comprehensive Income, and Paid in Capital for the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	48
Notes to Consolidated Financial Statements	Part II. Item 8.	49
U.S. Utility	Part I. Item 1.	104
Customers		104
Electric Energy Sales		104
Retail Rate Regulation		106
Property and Other Generation Resources		112
Fuel Supply		115
Wholesale Rate Matters		118
Service Companies		126
Earnings Ratios		126
Non-Utility Nuclear	Part I. Item 1.	127
Property		127
Energy and Capacity Sales		128
Fuel Supply		129
Other Business Activities		129
Other Matters		130
Energy Commodity Services	Part I. Item 1.	130
Entergy-Koch, L.P.		130
Non-Nuclear Wholesale Assets Business		132
Regulation of Entergy's Business	Part I. Item 1.	133
PUHCA		133
Federal Power Act		133
State Regulation		133
Regulation of the Nuclear Power Industry		134
Environmental Regulation		137
Other Environmental Matters		140
Litigation		141
Research Spending		146
Employees		146
Entergy Arkansas, Inc.
Management's Financial Discussion and Analysis	Part II. Item 7.
Results of Operations		147
Liquidity and Capital Resources		151
Significant Factors and Known Trends		154
Critical Accounting Estimates		157
Independent Auditors' Report		162
Income Statements For the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	163
Statements of Cash Flows For the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	165
Balance Sheets, December 31, 2003 and 2002	Part II. Item 8.	166
Statements of Retained Earnings for the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	168
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	169
Entergy Gulf States, Inc.
Management's Financial Discussion and Analysis	Part II. Item 7.
Results of Operations		170
Liquidity and Capital Resources		173
Significant Factors and Known Trends		176
Critical Accounting Estimates		184
Independent Auditors' Report		189
Income Statements For the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	190
Statements of Cash Flows For the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	191
Balance Sheets, December 31, 2003 and 2002	Part II. Item 8.	192
Statements of Retained Earnings and Comprehensive Income for the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	194
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	195
Entergy Louisiana, Inc.
Management's Financial Discussion and Analysis	Part II. Item 7.
Results of Operations		196
Liquidity and Capital Resources		199
Significant Factors and Known Trends		202
Critical Accounting Estimates		206
Independent Auditors' Report		210
Income Statements For the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	211
Statements of Cash Flows For the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	213
Balance Sheets, December 31, 2003 and 2002	Part II. Item 8.	214
Statements of Retained Earnings for the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	216
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	217
Entergy Mississippi, Inc.
Management's Financial Discussion and Analysis	Part II. Item 7.
Results of Operations		218
Liquidity and Capital Resources		220
Significant Factors and Known Trends		223
Critical Accounting Estimates		225
Independent Auditors' Report		229
Income Statements For the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	230
Statements of Cash Flows For the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	231
Balance Sheets, December 31, 2003 and 2002	Part II. Item 8.	232
Statements of Retained Earnings for the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	234
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	235
Entergy New Orleans, Inc.
Management's Financial Discussion and Analysis	Part II. Item 7.
Results of Operations		236
Liquidity and Capital Resources		238
Significant Factors and Known Trends		241
Critical Accounting Estimates		244
Independent Auditors' Report		247
Statements of Operations For the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	248
Statements of Cash Flows For the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	249
Balance Sheets, December 31, 2003 and 2002	Part II. Item 8.	250
Statements of Retained Earnings for the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	252
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	253
System Energy Resources, Inc.
Management's Financial Discussion and Analysis	Part II. Item 7.
Results of Operations		254
Liquidity and Capital Resources		255
Significant Factors and Known Trends		257
Critical Accounting Estimates		258
Independent Auditors' Report		262
Income Statements For the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	263
Statements of Cash Flows For the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	265
Balance Sheets, December 31, 2003 and 2002	Part II. Item 8.	266
Statements of Retained Earnings for the Years Ended December 31, 2003, 2002, and 2001	Part II. Item 8.	268
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	269
Notes to Respective Financial Statements for the Domestic Utility Companies and System Energy	Part II. Item 8.	270
Properties	Part I. Item 2.	332
Legal Proceedings	Part I. Item 3.	332
Submission of Matters to a Vote of Security Holders	Part I. Item 4.	332
Directors and Executive Officers of Entergy Corporation	Part III. Item 10.	332
Market for Registrants' Common Equity and Related Stockholder Matters	Part II. Item 5.	334
Selected Financial Data	Part II. Item 6.	335
Management's Discussion and Analysis of Financial Condition and Results of Operations	Part II. Item 7.	335
Quantitative and Qualitative Disclosures About Market Risk	Part II. Item 7A.	335
Financial Statements and Supplementary Data	Part II. Item 8.	336

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	Part II. Item 9.	336
Controls and Procedures	Part II. Item 9A.	336
Directors and Executive Officers of the Registrants	Part III. Item 10.	337
Executive Compensation	Part III. Item 11.	342
Security Ownership of Certain Beneficial Owners and Management	Part III. Item 12.	352
Certain Relationships and Related Transactions	Part III. Item 13.	355
Principal Accountant Fees and Services	Part IV. Item 14	356
Exhibits, Financial Statement Schedules, and Reports on Form 8-K	Part IV. Item 15.	359
Signatures		360
Independent Auditors' Consents		367
Independent Auditors' Report on Financial Statement Schedules		368
Index to Financial Statement Schedules		S-1
Exhibit Index		E-1

This combined Form 10-K is separately filed by Entergy Corporation, Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc., and System Energy Resources, Inc. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes representations only as to itself and makes no other representations whatsoever as to any other company.

The report should be read in its entirety as it pertains to each respective registrant. No one section of the report deals with all aspects of the subject matter. Separate Item 6, 7, and 8 sections are provided for each registrant, except for the Notes to the financial statements. The Entergy Corporation Notes to the financial statements are separately presented, but the Notes to the financial statements for the other registrants are combined. These two sets of Notes are marked by headers. All other Items are combined for the registrants.

FORWARD-LOOKING INFORMATION

From time to time, Entergy makes statements concerning its expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Although Entergy believes that these forward-looking statements and the underlying assumptions are reasonable, it cannot provide assurance that they will prove correct. Except to the extent required by the federal securities laws, Entergy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Forward-looking statements involve a number of risks and uncertainties, and there are factors that could cause actual results to differ materially from those expressed or implied in the statements. Some of those factors (in addition to others described elsewhere in this report and in subsequent securities filings) include:

resolution of pending and future rate cases and negotiations, including various performance-based rate discussions, and other regulatory decisions, including those related to Entergy's System Agreement and utility supply plan
Entergy's ability to reduce its operation and maintenance costs, particularly at its Non-Utility Nuclear generating facilities, including the uncertainty of negotiations with unions to agree to such reductions
the performance of Entergy's generating plants, and particularly the capacity factors at its nuclear generating facilities
prices for power generated by Entergy's unregulated generating facilities, the ability to extend or replace the existing purchased power agreements for those facilities, including the Non-Utility Nuclear plants, and the prices and availability of power Entergy must purchase for its utility customers
Entergy's ability to develop and execute on a point of view regarding prices of electricity, natural gas, and other energy-related commodities
Entergy-Koch's profitability in trading physical and financial natural gas and power as well as other energy and weather-related contracts
changes in the number of participants in the energy trading market, and in their creditworthiness and risk profile
changes in the financial markets, particularly those affecting the availability of capital and Entergy's ability to refinance existing debt and to fund investments and acquisitions
actions of rating agencies, including changes in the ratings of debt and preferred stock
changes in inflation and interest rates
Entergy's ability to purchase and sell assets at attractive prices and on other attractive terms
changes in ownership of joint ventures
volatility and changes in markets for electricity, natural gas, uranium, and other energy-related commodities
changes in utility regulation, including the beginning or end of retail and wholesale competition, the ability to recover net utility assets and other potential stranded costs, and the establishment of a regional transmission organization that includes Entergy's utility service territory
changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown of Indian Point or other nuclear generating facilities
resolution of pending or future applications for license extensions of nuclear generating facilities
changes in law resulting from proposed energy legislation
changes in environmental, tax, and other laws, including requirements for reduced emissions of sulfur, nitrogen, carbon, mercury, and other substances
the economic climate, and particularly growth in Entergy's service territory
variations in weather, hurricanes, and other disasters
advances in technology
the potential impacts of threatened or actual terrorism and war
the success of Entergy's strategies to reduce current tax payments
the effects of litigation
changes in accounting standards, corporate governance, and securities law requirements
Entergy's ability to attract and retain talented management and directors.

DEFINITIONS

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

Abbreviation or Acronym	Term

AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
ANO 1 and 2	Units 1 and 2 of Arkansas Nuclear One Steam Electric Generating Station (nuclear), owned by Entergy Arkansas
APSC	Arkansas Public Service Commission
BCF	One billion cubic feet of natural gas
BCF/D	One billion cubic feet of natural gas per day
Board	Board of Directors of Entergy Corporation
BPS	British pounds sterling
Cajun	Cajun Electric Power Cooperative, Inc.
capacity factor	Actual plant output divided by maximum potential plant output for the period
City Council or Council	Council of the City of New Orleans, Louisiana
CPI-U	Consumer Price Index - Urban
Damhead Creek	800 MW (gas) combined cycle electric generating facility located in the United Kingdom that entered commercial operations in the first quarter of 2001 and was sold by Entergy in 2002
DOE	United States Department of Energy
domestic utility companies	Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, collectively
EITF	FASB's Emerging Issues Task Force
electricity marketed	Total physical volume marketed by Entergy-Koch in the U.S. and Europe during the period
electricity volatility	Measure of price fluctuation over time using standard deviation of daily price differences for into-Entergy and into-Cinergy power prices for the upcoming month
Energy Commodity Services	Entergy's business segment that is focused almost exclusively on providing energy commodity trading and gas transportation and storage services through Entergy-Koch, LP and also includes Entergy's non-nuclear wholesale assets business
Entergy	Entergy Corporation and its direct and indirect subsidiaries
Entergy Corporation	Entergy Corporation, a Delaware corporation
Entergy-Koch	Entergy-Koch, LP, a joint venture equally owned by subsidiaries of Entergy and Koch Industries, Inc.
EPA	United States Environmental Protection Agency
EPDC	Entergy Power Development Corporation, a wholly-owned subsidiary of Entergy Corporation
FASB	Financial Accounting Standards Board
FEMA	Federal Emergency Management Agency
FERC	Federal Energy Regulatory Commission
FitzPatrick	James A. FitzPatrick nuclear power plant, 825 MW facility located near Oswego, New York, purchased in November 2000 from New York Power Authority (NYPA) by Entergy's Non-Utility Nuclear business

DEFINITIONS (Continued)

Abbreviation or Acronym	Term

gain/loss days	Ratio of the number of days when Entergy-Koch recognized a net gain from commodity trading activities to the number of days when Entergy-Koch recognized a net loss from commodity trading activities
gas marketed	Total physical volume marketed by Entergy-Koch in the U.S. and Europe during the period
gas volatility	Measure of price fluctuation over time using standard deviation of daily price differences for Henry Hub natural gas prices for the upcoming month
Grand Gulf 1	Unit No. 1 of Grand Gulf Steam Electric Generating Station (nuclear), 90% owned or leased by System Energy
GWh	Gigawatt-hour(s), which equals one million kilowatt-hours
Independence	Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi, and 7% by Entergy Power
Indian Point 1	Indian Point Energy Center Unit 1 nuclear power plant that has been shut-down and in safe storage since the 1970s, located in Westchester County, New York, purchased in September 2001 together with Indian Point 2 from Consolidated Edison by Entergy's Non-Utility Nuclear business
Indian Point 2	Indian Point Energy Center Unit 2 nuclear power plant, 984 MW facility located in Westchester County, New York, purchased in September 2001 from Consolidated Edison by Entergy's Non-Utility Nuclear business
Indian Point 3	Indian Point Energy Center Unit 3 nuclear power plant, 994 MW facility located in Westchester County, New York, purchased in November 2000 from NYPA by Entergy's Non-Utility Nuclear business
IRS	Internal Revenue Service
kV	Kilovolt
kW	Kilowatt
kWh	Kilowatt-hour(s)
LDEQ	Louisiana Department of Environmental Quality
LPSC	Louisiana Public Service Commission
Mcf	1,000 cubic feet of gas
miles of pipeline	Total miles of transmission and gathering pipeline
MMBtu	One million British Thermal Units
MPSC	Mississippi Public Service Commission
MW	Megawatt(s), which equals one thousand kilowatt(s)
MWh	Megawatt-hour(s)
Nelson Unit 6	Unit No. 6 (coal) of the Nelson Steam Electric Generating Station, owned 70% by Entergy Gulf States
Net debt ratio	Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents
Net MW in operation	Installed capacity owned or operated
Net revenue	Operating revenue net of fuel, fuel-related, and purchased power expenses; other regulatory credits; and amortization of rate deferrals

DEFINITIONS (Concluded)

Abbreviation or Acronym	Term

Non-Utility Nuclear	Entergy's business segment that owns and operates five nuclear power plants and sells electric power produced by those plants to wholesale customers
NRC	Nuclear Regulatory Commission
Pilgrim	Pilgrim Nuclear Station, 688 MW facility located in Plymouth, Massachusetts, purchased in July 1999 from Boston Edison by Entergy's Non-Utility Nuclear business
PPA	Purchased power agreement
production cost	Cost in $/MMBtu associated with delivering gas, excluding the cost of the gas
PRP	Potentially responsible party (a person or entity that may be responsible for remediation of environmental contamination)
PUCT	Public Utility Commission of Texas
PUHCA	Public Utility Holding Company Act of 1935, as amended
PURPA	Public Utility Regulatory Policies Act of 1978
Ritchie Unit 2	Unit 2 of the R.E. Ritchie Steam Electric Generating Station (gas/oil)
River Bend	River Bend Steam Electric Generating Station (nuclear), owned by Entergy Gulf States
SEC	Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards as promulgated by the FASB
SMEPA	South Mississippi Electric Power Agency, which owns a 10% interest in Grand Gulf 1
spark spread	Dollar difference between electricity prices per unit and natural gas prices after assuming a conversion ratio for the number of natural gas units necessary to generate one unit of electricity
storage capacity	Working gas storage capacity
System Energy	System Energy Resources, Inc.
throughput	Gas in BCF/D transported through a pipeline during the period
UK	The United Kingdom of Great Britain and Northern Ireland
U.S. Utility	Entergy's business segment that generates, transmits, distributes, and sells electric power, with a small amount of natural gas distribution
Vermont Yankee	Vermont Yankee nuclear power plant, 510 MW facility located in Vernon, Vermont, purchased in July 2002 from Vermont Yankee Nuclear Power Corporation (VYNPC) by Entergy's Non-Utility Nuclear business
Waterford 3	Unit No. 3 (nuclear) of the Waterford Steam Electric Generating Station, 100% owned or leased by Entergy Louisiana
weather-adjusted usage	Electric usage excluding the effects of deviations from normal weather
White Bluff	White Bluff Steam Electric Generating Station, 57% owned by Entergy Arkansas

ENTERGY'S BUSINESS

Entergy Corporation is an integrated energy company engaged primarily in electric power production, retail electric distribution operations, energy marketing and trading, and gas transportation. Entergy owns and operates power plants with approximately 30,000 MW of electric generating capacity, and it is the second-largest nuclear power generator in the United States. Entergy delivers electricity to 2.6 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Through Entergy-Koch, Entergy is a leading provider of wholesale energy marketing and trading services, as well as an operator of natural gas pipeline and storage facilities. Entergy generated annual revenues of over $9 billion in 2003 and had approximately 14,800 employees as of December 31, 2003.

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

U.S. Utility generates, transmits, distributes, and sells electric power, with a small amount of natural gas distribution.

Non-Utility Nuclear owns and operates five nuclear power plants and sells the electric power produced by those plants to wholesale customers. This business also provides services to other nuclear power plant owners.

Energy Commodity Services provides energy commodity trading and gas transportation and storage services through Entergy-Koch, LP. Energy Commodity Services also includes Entergy's non-nuclear wholesale assets business, which sells electric power produced by those assets to wholesale customers while it focuses on selling the majority of those assets.

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

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

	U.S. Utility	Non-Utility Nuclear	Energy Commodity Services	Entergy Consolidated (a)
	(In Thousands)
2003
Operating revenues	$7,584,857	$1,274,983	$184,888	$9,194,920
Operating expenses	6,274,830	1,039,614	224,567	7,710,365
Other income	(35,965)	33,997	337,334	325,238
Interest and other charges	419,111	34,460	15,193	506,326
Income taxes	341,044	88,619	105,903	490,074
Cumulative effect of accounting change	(21,333)	154,512	3,895	137,074
Net income	492,574	300,799	180,454	950,467

2002
Operating revenues	$6,773,509	$1,200,238	$294,670	$8,305,035
Operating expenses	5,434,694	868,288	769,834	7,163,314
Other income	47,603	48,572	249,678	347,753
Interest and other charges	465,703	47,291	61,632	572,464
Income taxes	313,752	132,726	(141,288)	293,938
Net income (loss)	606,963	200,505	(145,830)	623,072

2001
Operating revenues	$7,432,920	$789,244	$1,370,485	$9,620,899
Operating expenses	6,050,534	576,510	1,361,153	8,072,954
Other income	69,157	50,916	222,571	349,353
Interest and other charges	576,705	55,717	74,953	714,580
Income taxes	300,284	80,053	74,493	455,693
Cumulative effect of accounting change	-	-	23,482	23,482
Net income	574,554	127,880	105,939	750,507


CASH FLOW INFORMATION
For the Years Ended December 31, 2003, 2002, and 2001

	U.S. Utility	Non-Utility Nuclear	Energy Commodity Services	Entergy Consolidated (a)
	(In Thousands)
2003
Net cash flow provided by (used in) operating activities	$1,675,069	$182,524	($111,291)	$2,005,820
Net cash flow used in investing activities	(1,441,992)	(184,913)	(78,120)	(1,783,130)
Net cash flow provided by (used in) financing activities	(919,983)	(6,672)	166,165	(869,130)

2002
Net cash flow provided by (used in) operating activities	$2,341,161	$281,589	($3,714)	$2,181,703
Net cash flow used in investing activities	(1,020,087)	(438,664)	(760)	(1,388,463)
Net cash flow provided by (used in) financing activities	(688,201)	176,162	(66,151)	(212,610)

2001
Net cash flow provided by (used in) operating activities	$1,647,969	$263,476	($127,938)	$2,215,548
Net cash flow provided by (used in) investing activities	(1,243,715)	(1,061,820)	138,351	(2,224,720)
Net cash flow provided by (used in) financing activities	(303,520)	292,872	(148,501)	(622,004)



FINANCIAL POSITION INFORMATION
December 31, 2003 and 2002

	U.S. Utility	Non-Utility Nuclear	Energy Commodity Services	Entergy Consolidated (a)
	(In Thousands)
2003
Current assets	$2,117,260	$542,837	$466,132	$2,919,244
Other property and investments	1,151,538	1,326,347	1,137,069	3,746,926
Property, plant and equipment - net	16,242,775	1,557,025	463,403	18,298,797
Deferred debits and other assets	2,917,563	745,568	10,317	3,589,243
Current liabilities	1,671,607	330,684	478,693	2,282,223
Non-current liabilities	15,309,482	1,891,805	41,450	17,568,329
Shareholders' equity	5,448,047	1,949,288	1,614,620	8,703,658

2002
Current assets	$2,517,001	$706,056	$504,836	$3,205,583
Other property and investments	1,089,871	1,437,896	1,175,842	3,468,240
Property, plant and equipment - net	15,594,128	1,613,369	429,677	17,665,003
Deferred debits and other assets	2,429,523	724,987	57,117	3,165,540
Current liabilities	2,479,783	947,731	348,200	3,172,189
Non-current liabilities	13,755,569	2,175,467	182,750	16,493,940
Shareholders' equity	5,395,171	1,359,110	1,636,522	7,838,237

(a) In addition to the 3 operating segments presented here, Entergy Consolidated also includes Entergy Corporation (parent company), other business activity, and intercompany eliminations.

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

Entergy Corporation

U. S. Utility

Non-Utility Nuclear

Energy Commodity Services

Entergy Arkansas, Inc.

Entergy Nuclear Operations, Inc.

Entergy-Koch, LP

Non-Nuclear Wholesale Assets

Entergy Gulf States, Inc.

Entergy Nuclear Finance, Inc.

(50% ownership)

Entergy Louisiana, Inc.

Entergy Nuclear Generation Co. (Pilgrim)

Entergy Mississippi, Inc.

Entergy Nuclear FitzPatrick LLC

Gulf South Pipeline

Entergy Power Development Corp.

Entergy New Orleans, Inc.

Entergy Nuclear Indian Point 2, LLC

Entergy-Koch Trading

Entergy Asset Management, Inc.

System Energy Resources, Inc.

Entergy Nuclear Indian Point 3, LLC

Entergy Operations, Inc.

Entergy Nuclear Vermont Yankee, LLC

Entergy Services, Inc.

Entergy Nuclear, Inc.

System Fuels, Inc.

Entergy Nuclear Fuels Company

Entergy Nuclear Nebraska LLC

In addition to its three primary operating segments, Entergy's Competitive Retail Services business markets and sells electricity, thermal energy and related services in competitive markets, primarily the ERCOT region in Texas, where it has over 60,000 customers. This business is also preparing to operate as Entergy's affiliated competitive retailer when retail open access commences in Entergy Gulf States' service territory in Texas. Competitive Retail Services does not currently have material levels of revenue, net income, or total assets; and Entergy reports this business as part of All Other in its segment disclosures.

Strategy

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

___________________________________________________________________________________________

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

Entergy's internet address is www.entergy.com. Entergy's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to any of these reports, are available free of charge through Entergy's website as soon as reasonably practicable after filing with the SEC. Financial presentations and news releases are also available through Entergy's website. Additionally, Entergy's Corporate Governance Guidelines, Board Committee Charters for the Corporate Governance, Audit, and Personnel Committees, and Entergy's Codes of Conduct are posted on Entergy's website. This information is also available in print to any investor that requests it.

Part I, Item 1 is continued on page 104.

ENTERGY CORPORATION AND SUBSIDIARIES

REPORT OF MANAGEMENT

Management of Entergy Corporation and its subsidiaries has prepared and is responsible for the financial statements and related financial information included herein. The financial statements are based on accounting principles generally accepted in the United States of America. Financial information included elsewhere in this report is consistent with the financial statements.

To meet their responsibilities with respect to financial information, management maintains and enforces a system of internal accounting controls designed to provide reasonable assurance, on a cost-effective basis, as to the integrity, objectivity, and reliability of the financial records, and as to the protection of assets. This system includes communication through written policies and procedures, an employee Code of Entegrity, and an organizational structure that provides for appropriate division of responsibility and the training of personnel. This system is also tested by a comprehensive internal audit program.

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

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

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

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


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


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


DANIEL F. PACKER Chairman, President, and Chief Executive Officer of Entergy New Orleans, Inc.	GARY J. TAYLOR Chairman, President, and Chief Executive Officer of System Energy Resources, Inc.


THEODORE H. BUNTING, JR. Vice President and Chief Financial Officer of System Energy Resources, Inc.	JAY A. LEWIS Vice President and Chief Financial Officer of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc.

ENTERGY CORPORATION AND SUBSIDIARIES

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

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

U.S. Utility generates, transmits, distributes, and sells electric power, with a small amount of natural gas distribution.

Non-Utility Nuclear owns and operates five nuclear power plants and sells the electric power produced by those plants to wholesale customers. This business also provides services to other nuclear power plant owners.

Energy Commodity Services provides energy commodity trading and gas transportation and storage services through Entergy-Koch, LP. Energy Commodity Services also includes Entergy's non-nuclear wholesale assets business, which sells electric power produced by those assets to wholesale customers while it focuses on selling the majority of those assets.

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

	% of Revenue			% of Net Income			% of Total Assets
Segment	2003	2002	2001	2003	2002	2001	2003	2002	2001

U.S. Utility	82	82	77	52	97	77	79	79	78
Non-Utility Nuclear	14	14	8	32	32	17	15	16	13
Energy Commodity Services	2	4	14	19	(23)	14	7	8	9
Parent & Other	2	-	1	(3)	(6)	(8)	(1)	(3)	-

Results of Operations

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

Operating Segment	2003	2002	2001
		(In Thousands)

U.S. Utility	$469,050	$583,251	$550,243
Non-Utility Nuclear	300,799	200,505	127,880
Energy Commodity Services	180,454	(145,830)	105,939
Parent & Other	(23,360)	(38,566)	(57,866)
Total	$926,943	$599,360	$726,196

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

Earnings for 2002 were negatively affected by net charges ($238.3 million after-tax) reflecting the effect of Entergy's decision to discontinue additional greenfield power plant development and asset impairments resulting from the deteriorating economics of wholesale power markets principally in the United States and the United Kingdom. The net charges are discussed more fully below in the Energy Commodity Services discussion. See Note 12 to the consolidated financial statements for further discussion of Entergy's business segments and their financial results in 2003, 2002, and 2001.

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

U.S. Utility

The decrease in earnings for the U.S. Utility for 2003 from $583 million to $469 million was primarily due to a $107.7 million ($65.6 million net-of-tax) accrual of the loss that would be associated with a final, non-appealable decision disallowing abeyed River Bend plant costs; $99.8 million ($70.1 million net-of-tax) of charges recorded in connection with the voluntary severance program; and the $21.3 million net-of-tax cumulative effect of a change in accounting principle that reduced earnings at Entergy Gulf States in the first quarter of 2003 upon implementation of SFAS 143. See "Critical Accounting Estimates - SFAS 143" below for discussion of the implementation of SFAS 143. Partially offsetting the decrease in earnings were decreased interest charges and increased net revenue.

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

Net Revenue

2003 Compared to 2002

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

		(In Millions)

2002 net revenue		$4,209.6
Base rate increases		66.2
Base rate decreases		(23.3)
Fuel price		56.2
Asset retirement obligation		42.9
Net wholesale revenue		23.2
March 2002 Ark. settlement agreement		(154.0)
Other		(6.3)
2003 net revenue		$4,214.5

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

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

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

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

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

Gross operating revenues and regulatory credits

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

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

2002 Compared to 2001

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

		(In Millions)

2001 net revenue		$3,873.1
March 2002 Ark. settlement agreement		180.7
Volume/weather		155.7
Fuel price		94.3
System Energy refund in 2001		(128.9)
Other		34.7
2002 net revenue		$4,209.6

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

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

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

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

Gross operating revenues

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

Other Income Statement Variances

2003 Compared to 2002

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

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

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

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

Interest charges decreased primarily due to a decrease of $28.5 million in interest on long-term debt due to the redemption and refinancing of long-term debt. Refer to Note 5 to the consolidated financial statements for detail of long-term debt outstanding as of December 31, 2003 and 2002.

2002 Compared to 2001

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

an increase of $51.2 million in benefit costs;

increased expenses of $24.5 million at Entergy Arkansas due to the reversal in 2001 of ice storm costs previously charged to expense in December 2000;

an increase of $14.6 million in fossil plant expenses due to maintenance outages and turbine inspection costs at various plants;

an increase of $10.9 million to reflect the current estimate of the liability for the future disposal of low-level radioactive waste materials; and

lower nuclear insurance refunds of $6.7 million.

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

Other income decreased primarily due to:

interest recognized in 2001 on Grand Gulf 1's decommissioning trust funds resulting from the final order addressing System Energy's rate proceeding;

interest recognized in 2001 at Entergy Mississippi and Entergy New Orleans on the deferred System Energy costs related to its 1995 rate filing that were not being recovered through rates; and

lower interest earned on declining deferred fuel balances.

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

Interest and other charges decreased primarily due to:

a decrease of $31.9 million in interest on long-term debt primarily due to the retirement of long-term debt in late 2001 and early 2002; and

a decrease of $76.0 million in other interest expense primarily due to interest recorded on System Energy's provision for rate refund in 2001 resulting from the effects of the final FERC order addressing System Energy's 1995 rate filing. The refund was made in December 2001.

Non-Utility Nuclear

Following are key performance measures for Non-Utility Nuclear:

	2003	2002	2001

Net MW in operation at December 31	4,001	3,955	3,445
Average realized price per MWh	$38.54	$40.49	$34.90
Generation in GWh for the year	32,379	29,953	22,614
Capacity factor for the year	92.4%	92.8%	92.7%

2003 Compared to 2002

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

2002 Compared to 2001

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

Energy Commodity Services

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

	2003	2002	2001
Entergy-Koch Trading
Gas volatility	62%	61%	72%
Electricity volatility	59%	48%	78%
Gas marketed (BCF/D) (1)	6.5	5.8	4.5
Electricity marketed (GWh)	445,979	408,038	180,893
Gain/loss days	1.5	1.8	2.8
Gulf South Pipeline
Throughput (BCF/D)	1.99	2.40	2.45
Production cost ($/MMBtu)	$0.146	$0.094	$0.093

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

2003 Compared to 2002

The increase in earnings for Energy Commodity Services in 2003 from a $145.8 million loss to $180.5 million in earnings was primarily due to $428.5 million ($238.3 million net-of-tax) of charges recorded in 2002, as discussed in the 2002 to 2001 comparison below. Higher earnings from Entergy's investment in Entergy-Koch also contributed to the increase in earnings. The income from Entergy's investment in Entergy-Koch was $73 million higher in 2003 primarily as a result of higher earnings at Entergy-Koch Trading (EKT). Volatility was slightly up and trading earnings reflected solid point-of-view trading results. In addition, EKT's physical optimization business continued to contribute earnings, and its European business earnings increased as trading activities continued to expand beyond the United Kingdom. Earnings at Gulf South Pipeline were lower due to lower throughput and higher production costs. The decreased throughput was due to shifting gas flow patterns in a sustained high gas price environment that led to higher fuel costs. Production costs were higher as the result of incremental legal and consultant expenses incurred primarily in connection with Gulf South's defense of a lawsuit which it believes has no merit.

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

2002 Compared to 2001

The decrease in earnings for Energy Commodity Services in 2002 from $105.9 million to a $145.8 million loss was primarily due to the charges to reflect the effect of Entergy's decision to discontinue additional greenfield power plant development and to reflect asset impairments resulting from the deteriorating economics of wholesale power markets principally in the United States and the United Kingdom. Entergy recorded net charges of $428.5 million ($238.3 million net-of-tax) to operating expenses. The net charges consist of the following:

The power development business obtained contracts in October 1999 to acquire 36 turbines from General Electric. Entergy's rights and obligations under the contracts for 22 of the turbines were sold to an independent special-purpose entity in May 2001. $178.0 million of the charges, including an offsetting net-of-tax benefit of $18.5 million related to the subsequent sale of four turbines to a third party, is a provision for the net costs resulting from cancellation or sale of the turbines subject to purchase commitments with the special-purpose entity;

$204.4 million of the charges results from the write-off of Entergy Power Development Corporation's equity investment in the Damhead Creek project and the impairment of the values of its Warren Power power plant and its Crete and RS Cogen projects. This portion of the charges reflects Entergy's estimate of the effects of reduced spark spreads in the United States and the United Kingdom. Damhead Creek was sold in December 2002, resulting in net income of $31.4 million;

$39.1 million of the charges relates to the restructuring of the non-nuclear wholesale assets business, which is comprised of $22.5 million of impairments of administrative fixed assets, $10.7 million of estimated sublease losses, and $5.9 million of employee-related costs;

$32.7 million of the charges results from the write-off of capitalized project development costs for projects that will not be completed; and

a gain of $25.7 million ($15.9 million net-of-tax) realized on the sale in August 2002 of an interest in projects under development in Spain.

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

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

a decrease of $542.9 million in revenues and $539.6 million in fuel and purchased power expenses resulting from the sale of Highland Energy in the fourth quarter of 2001;

a decrease of $161.7 million in revenues resulting from the sale of the Saltend plant in August 2001; and

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

Parent & Other

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

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

a decrease in income tax expense of $12.1 million resulting from the allocation of intercompany tax benefits; and

a decrease in interest charges of $6.0 million.

Income Taxes

The effective income tax rates for 2003, 2002, and 2001 were 37.9%, 32.1%, and 38.3%, respectively. See Note 3 to the consolidated financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rates.

Liquidity and Capital Resources

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

Capital Structure

Entergy's capitalization is balanced between equity and debt, as shown in the following table. The reduction in the percentage for 2003 is the result of reduced debt outstanding in the U.S. Utility and Non-Utility Nuclear businesses, and an increase in shareholders' equity, primarily due to increased retained earnings. The reduction in the percentage for 2002 is primarily the result of the sale of Damhead Creek in December 2002. Debt outstanding on the Damhead Creek facility was $458 million as of December 31, 2001.

	2003	2002	2001

Net debt to net capital at the end of the year	45.3%	47.7%	51.1%
Effect of subtracting cash from gross debt	2.2%	4.1%	2.2%
Debt to capital at the end of the year	47.5%	51.8%	53.3%

Net debt consists of gross debt less cash and cash equivalents. Gross debt consists of notes payable, capital lease obligations, preferred stock with sinking fund, and long-term debt, including the currently maturing portion. Net capital consists of net debt, common shareholders' equity, and preferred stock without sinking fund. The preferred stock with sinking fund is included in gross debt pursuant to SFAS 150, which Entergy implemented in the third quarter of 2003. The 2002 and 2001 ratios do not reflect that type of security as debt, but do include it in net capital, which is how Entergy presented those securities prior to implementation of SFAS 150. Entergy uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy's financial condition.

Long-term debt, including the currently maturing portion, makes up over 90% of Entergy's total debt outstanding. Following are Entergy's long-term debt principal maturities as of December 31, 2003 and 2002 by operating segment. A significant factor in the change from 2002 to 2003 is over $2 billion of debt refinancing or retirement activity in the U.S. Utility business in 2003. The figures below include principal payments on the Entergy Louisiana and System Energy sale-leaseback transactions, which are included in long-term debt on the balance sheet.

Long-term debt maturities	2003	2004	2005	2006	2007-2008	after 2008
	(In Millions)

As of December 31, 2002
U.S. Utility	$1,111	$855	$470	$68	$654	$3,718
Non-Utility Nuclear	$87	$91	$95	$98	$119	$193
Energy Commodity Services	$79	-	-	-	-	-
Parent and Other	-	$595	-	-	-	$267

As of December 31, 2003
U.S. Utility	-	$450	$355	$28	$1,254	$4,345
Non-Utility Nuclear	-	$74	$72	$76	$100	$193
Energy Commodity Services	-	-	-	-	-	-
Parent and Other	-	-	$60	-	$272	$568

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

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

	2004	2005	2006	2007-2008	after 2008
	(In Millions)
Capital lease payments, including nuclear fuel leases	$165	$142	$6	$5	$3

Notes payable, which include borrowings outstanding on credit facilities with original maturities of less than one year, were less than $1 million as of December 31, 2003. Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and Entergy Mississippi each have 364-day credit facilities available as follows:

Company	Expiration Date	Amount of Facility	Amount Drawn as of Dec. 31, 2003

Entergy Corporation	May 2004	$1.450 billion	-
Entergy Arkansas	April 2004	$63 million	-
Entergy Louisiana	May 2004	$15 million	-
Entergy Mississippi	May 2004	$25 million	-

Although the Entergy Corporation credit line expires in May 2004, Entergy has the discretionary option to extend the period to repay the amount then outstanding for an additional 364-day term. Because of this option, which Entergy intends to exercise if it does not renew the credit line or obtain an alternative source of financing, any debt outstanding on the credit line is reflected in long-term debt on the balance sheet. Entergy Corporation's facility requires it to maintain a consolidated debt ratio of 65% or less of its total capitalization, and maintain an interest coverage ratio of 2 to 1. If Entergy fails to meet these limits, or if Entergy or the domestic utility companies default on other indebtedness or are in bankruptcy or insolvency proceedings, an acceleration of the facility's maturity date may occur.

Operating Lease Obligations and Guarantees of Unconsolidated Obligations

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

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

	2004	2005	2006	2007-2008	after 2008
	(In Millions)

Operating lease payments	$99	$89	$70	$93	$245

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

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

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

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

Summary of Contractual Obligations of Consolidated Entities

Contractual Obligations	2004	2005-2006	2007-2008	after 2008	Total
	(In Millions)

Long-term debt (1)	$524	$591	$1,626	$5,106	$7,847
Capital lease obligations (2)	$165	$148	$5	$3	$321
Operating leases (2)	$99	$159	$93	$245	$596
Purchase obligations (3)	$925	$1,007	$907	$1,446	$4,285

(1)	Long-term debt is discussed in Note 5 to the consolidated financial statements.
(2)	Capital lease obligations include nuclear fuel leases. Lease obligations are discussed in Note 10 to the consolidated financial statements.
(3)	As defined by SEC rule. For Entergy, it includes unconditional fuel and purchased power obligations and other purchase obligations. Approximately 97% of the total pertains to fuel and purchased power obligations that are recovered in the normal course of business through various fuel cost recovery mechanisms in the U.S. Utility business.

Capital Funds Agreement

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

maintain System Energy's equity capital at a minimum of 35% of its total capitalization (excluding short-term debt);

permit the continued commercial operation of Grand Gulf 1;

pay in full all System Energy indebtedness for borrowed money when due; and

enable System Energy to make payments on specific System Energy debt, under supplements to the agreement assigning System Energy's rights in the agreement as security for the specific debt.

Capital Expenditure Plans and Other Uses of Capital

Following are the amounts of Entergy's planned construction and other capital investments by operating segment for 2004 through 2006:

Planned construction and capital investments	2004	2005	2006
	(In Millions)

Maintenance Capital:
U.S. Utility	$767	$767	$759
Non-Utility Nuclear	73	68	76
Energy Commodity Services	7	2	2
Parent and Other	7	10	14
	854	847	851
Capital Commitments:
U.S. Utility	569	295	112
Non-Utility Nuclear	123	-	-
Energy Commodity Services	73	-	-
Parent and Other	32	-	-
	797	295	112
Total	$1,651	$1,142	$963

Maintenance Capital refers to amounts Entergy plans to spend on routine capital projects that are necessary to support reliability of its service, equipment or systems and to support normal customer growth.

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

Replacement of the ANO 1 steam generators and reactor vessel closure head. Entergy estimates the cost of the ANO 1 project to be approximately $235 million, of which approximately $135 million will be incurred through 2004. Entergy expects the replacement to occur during a planned refueling outage in 2005. Entergy Arkansas filed in January 2003 a request for a declaratory order by the APSC that the investment in the replacement is in the public interest analogous to the order received in 1998 prior to the replacement of the ANO 2 steam generators. The APSC found that the replacement is in the public interest in a declaratory order issued in May 2003.

Purchase of the Perryville power plant in Louisiana. In January 2004, Entergy Louisiana signed an agreement to acquire the 718 MW Perryville power plant for $170 million. The plant is owned by a subsidiary of Cleco Corporation, which subsidiary submitted a bid in response to Entergy's Fall 2002 request for proposals for supply-side resources. The signing of the agreement followed a voluntary Chapter 11 bankruptcy filing by the plant's owner. Entergy expects that Entergy Louisiana will own 100 percent of the Perryville plant, and that Entergy Louisiana will sell 75 percent of the output to Entergy Gulf States under a long-term cost-of-service purchased power agreement. The purchase of the plant, expected to be completed by December 2004, is contingent upon obtaining necessary approvals from the bankruptcy court and from state and federal regulators, including approval of full cost recovery, giving consideration to the need for the power and the prudence of Entergy Louisiana and Entergy Gulf States for engaging in the transaction. In addition, Entergy Louisiana and Entergy Gulf States executed a purchased power agreement with the plant's owner through the date of the acquisition's closing (as long as that occurs by September 2005) for 100 percent of the output of the Perryville plant.

Nuclear power plant uprates.

Entergy's obligation in the Energy Commodity Services business to make a $72.7 million cash contribution to Entergy-Koch in January 2004. Entergy made the contribution on January 2, 2004.

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

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

Dividends and Stock Repurchases

Declarations of dividends on Entergy's common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy's common stock dividends based upon Entergy's earnings, financial strength, and future investment opportunities. At its July 2003 meeting, the Board increased Entergy's quarterly dividend per share by 29%, to $0.45. Entergy expects the next review of a potential dividend increase will occur in October 2004. Given the current number of Entergy common shares outstanding, Entergy expects the July 2003 dividend increase to result in an incremental annual increase in cash used of approximately $90 million. In 2003, Entergy paid $363 million in cash dividends on its common stock.

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

PUHCA Restrictions on Uses of Capital

Entergy's ability to invest in electric wholesale generators and foreign utility companies is subject to the SEC's regulations under PUHCA. As authorized by the SEC, Entergy is allowed to invest earnings in electric wholesale generators and foreign utility companies in an amount equal to 100% of its average consolidated retained earnings. As of December 31, 2003, Entergy's investments subject to this rule totaled $2.59 billion constituting 58.3% of Entergy's average consolidated retained earnings.

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

Under PUHCA, the SEC imposes a limit equal to 15% of consolidated capitalization on the amount that may be invested in "energy-related" businesses without specific SEC approval. Entergy has made investments in energy-related businesses, including power marketing and trading. Entergy's available capacity to make additional investments at December 31, 2003 was approximately $1.6 billion.

Sources of Capital

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

internally generated funds;

cash on hand ($692 million as of December 31, 2003);

securities issuances;

bank financing under new or existing facilities; and

sales of assets.

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

Provisions within the Articles of Incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of certain of Entergy Corporation's subsidiaries restrict the payment of cash dividends or other distributions on their common and preferred stock. As of December 31, 2003, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $309.4 million and $41.9 million, respectively. Additionally, PUHCA prohibits Entergy Corporation's subsidiaries from making loans or advances to Entergy Corporation. All debt and common and preferred stock issuances by the domestic utility companies and System Energy require prior regulatory approval and their preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, other agreements. The domestic utility companies and System Energy have sufficient capacity under these tests to meet foreseeable capital needs.

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

Cash Flow Activity

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

	2003	2002	2001
	(In Millions)

Cash and cash equivalents at beginning of period	$1,335	$752	$1,382

Cash flow provided by (used in):
Operating activities	2,006	2,181	2,216
Investing activities	(1,783)	(1,388)	(2,224)
Financing activities	(869)	(213)	(622)
Effect of exchange rates on cash and cash equivalents	3	3	-
Net increase (decrease) in cash and cash equivalents	(643)	583	(630)

Cash and cash equivalents at end of period	$692	$1,335	$752

Operating Cash Flow Activity

2003 Compared to 2002

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

The U.S. Utility provided $1,675 million in operating cash flow in 2003 compared to providing $2,341 million in 2002. The decrease primarily resulted from the tax accounting election made by Entergy Louisiana, as discussed below. Also contributing to the decrease were higher payments for fuel during the period, which also significantly increased the amount of deferred fuel costs. Management expects that the deferred fuel costs will be recovered through regulatory recovery mechanisms currently in place.

The non-nuclear wholesale assets business used $70 million in operating cash flow in 2003 compared to providing $43 million in 2002 primarily due to a decrease of $64 million in the income tax refund received in 2003 compared to 2002. Also contributing to the increase in cash used was a one-time $33 million payment related to a generation contract in the non-nuclear wholesale assets business.

The Non-Utility Nuclear segment provided $183 million in operating cash flow in 2003 compared to providing $282 million in 2002 primarily due to higher tax payments and unplanned outages.

Operating cash flow used by the investment in Entergy-Koch, LP decreased by $6 million in 2003. This decrease in cash flow used was due to the receipt of $100 million in dividends from Entergy-Koch in 2003. Almost entirely offsetting the dividends received was an increase in tax payments related to Entergy's investment in Entergy-Koch due to increased income from the investment.

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

2002 Compared to 2001

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

The U.S. Utility provided $2,341 million in operating cash flow, an increase of $693 million compared to 2001. The increase primarily resulted from the tax accounting election made by Entergy Louisiana that is discussed below.

The parent company used $439 million in operating cash flow compared to providing $407 million in 2001. The decrease primarily resulted from the payment that Entergy Corporation made to Entergy Louisiana pursuant to the tax accounting election made by Entergy Louisiana that is discussed below.

The Non-Utility Nuclear business provided $282 million in operating cash flow, an increase of $18 million compared to 2001.

Entergy's investment in Entergy-Koch used $47 million in operating cash flow in 2002, a decrease of $8 million compared to 2001. The use of cash primarily relates to tax payments on Entergy's share of the partnership income. Entergy did not receive a dividend from Entergy-Koch in 2002 or in 2001 because the joint venture was retaining capital for business opportunities.

The non-nuclear wholesale assets business provided $43 million in operating cash flow in 2002, compared to using $73 million in 2001.

Tax Election

In 2001, Entergy Louisiana changed its method of accounting for tax purposes related to the contract to purchase power from the Vidalia project (the contract is discussed in Note 9 to the consolidated financial statements). The new tax accounting method has provided a cumulative cash flow benefit of approximately $805 million through 2003, which is expected to reverse in the years 2005 through 2031. The election did not reduce book income tax expense. The timing of the reversal of this benefit depends on several variables, including the price of power. Approximately half of the consolidated cash flow benefit of the election occurred in 2001 and the remainder occurred in 2002. In accordance with Entergy's intercompany tax allocation agreement, the cash flow benefit for Entergy Louisiana occurred in the fourth quarter of 2002.

In a September 2002 settlement of an LPSC proceeding that concerned the Vidalia contract, the LPSC approved Entergy Louisiana's proposed treatment of the regulatory impact of the tax accounting election. In general, the settlement permits Entergy Louisiana to keep a portion of the tax benefit in exchange for bearing the risk associated with sustaining the tax treatment. The LPSC settlement divided the term of the Vidalia contract into two segments: 2002-2012 and 2013-2031. During the first eight years of the 2002-2012 segment, Entergy Louisiana agreed to credit rates by flowing through its fuel adjustment calculation $11 million each year, beginning monthly in October 2002. Entergy Louisiana must credit rates in this way and by this amount even if Entergy Louisiana is unable to sustain the tax deduction. Entergy Louisiana also must credit rates by $11 million each year for an additional two years unless either the tax accounting method elected is retroactively repealed or the 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

2003 Compared to 2002

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

The non-nuclear wholesale assets business realized $215 million in net proceeds from sales of businesses in 2002.

Temporary investments of $150 million matured in 2002, which provided cash flow in 2002.

Temporary investments of $50 million were made in 2003, which used cash flow in 2003.

Entergy Gulf States has $77 million and Entergy Mississippi has $73 million of other regulatory investments in 2003 as a result of fuel cost under-recoveries. See Note 1 to the consolidated financial statements for discussion of the accounting treatment of these fuel cost under-recoveries. See Note 2 to the consolidated financial statements for discussion of the change in Entergy Mississippi's energy cost recovery rider.

Partially offsetting these uses of cash, approximately $172 million of the cash collateral for a letter of credit that secures the installment obligations owed to NYPA for the acquisition of the FitzPatrick and Indian Point 3 nuclear power plants was released to Entergy during 2003. There is approximately $60 million of cash collateral remaining that Entergy expects to be released in March 2004 as a result of the regularly scheduled payment on the note payable to NYPA.

2002 Compared to 2001

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

Entergy used $420 million less cash in its 2002 nuclear power plant purchase than it used in its 2001 purchase. In July 2002, Entergy's Non-Utility Nuclear business purchased the Vermont Yankee nuclear power plant for $180 million in cash. In September 2001, Entergy's Non-Utility Nuclear business purchased the Indian Point 2 nuclear power plant for $600 million in cash. The liabilities to decommission both plants, as well as related decommissioning trust funds, were also transferred to Entergy. These decommissioning trust transfers are reflected in the non-cash activity section of the cash flow statements.

Entergy made cash contributions of approximately $414 million in 2001 in connection with the formation of Entergy-Koch.

Entergy made a $272 million cash investment in 2001 to provide the collateral, discussed above, for the letter of credit that secures the installment obligations owed to NYPA. Approximately $40 million of this collateral was released to Entergy in 2002.

Entergy used $150 million to invest in temporary investments with a maturity of greater than 90 days in 2001 and those investments matured in 2002. This resulted in a net decrease of $300 million in cash used in 2002.

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

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

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

Financing Activities

2003 Compared to 2002

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

Net long-term debt retirements by the U.S. Utility segment were approximately $470 million in 2003 compared to net issuances of approximately $76 million in 2002. See Note 5 to the consolidated financial statements for the details of Entergy's long-term debt outstanding.

The net borrowings under Entergy Corporation's credit facilities decreased $500 million in 2003 compared to an increase of $244 million in 2002.

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

Entergy Corporation issued $538 million of long-term notes in 2003 compared to $267 million in 2002.

The non-nuclear wholesale assets business retired $268 million of long-term debt in 2002 related to the repurchase of the rights to acquire turbines discussed in Results of Operations above. Partially offsetting this was the retirement of the $79 million Top of Iowa wind project debt at its maturity in January 2003.

Entergy repurchased $8 million of its common stock in 2003 compared to $118 million in 2002.

2002 Compared to 2001

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

Entergy increased the net borrowings under Entergy Corporation's credit facilities by $295 million in 2002.

Entergy Corporation issued $267 million of long-term notes in 2002.

The non-nuclear wholesale assets business used $196 million less cash in 2002 to retire debt than it did in 2001. This primarily resulted from two transactions. The non-nuclear wholesale assets business retired $268 million of long-term debt in April 2002 related to the acquisition of the rights to purchase turbines from a special-purpose financing entity. In 2001 the non-nuclear wholesale assets business retired the $555 million outstanding on the Saltend credit facility when the plant was sold.

Issuances of long-term debt net of retirements by the U.S. Utility segment provided $113 million less cash in 2002 than in 2001. Net issuances were $76 million in 2002 compared to $189 million in 2001.

Entergy repurchased $81.6 million more of its common stock in 2002 than in 2001.

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

Significant Factors and Known Trends

Rate Regulation and Fuel-Cost Recovery

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

Company	Authorized ROE	Pending Proceedings/Events

Entergy Arkansas	11.0%	No cases are pending. Transition cost account mechanism expired on December 31, 2001. It is likely that a rate filing will be made in mid-2005 in connection with the steam generator replacement at ANO.

Entergy Gulf States-Texas	10.95%	Base rates have been frozen since settlement order issued in June 1999. Freeze will likely extend to the start of retail open access, given management's current expectations as to the start date of retail open access.

Entergy Gulf States-Louisiana	11.1%	The LPSC approved a settlement resolving the 4^th - 8^th post-merger earning reviews resulting in a $22.1 million prospective rate reduction effective January 2003 and a refund of $16.3 million. In December 2003, the LPSC staff recommended a $30.6 million rate refund and a prospective rate reduction of approximately $50 million as a result of the 9^th earnings analysis (2002). Hearings are set for April 2004. With the LPSC staff, Entergy Gulf States continues to pursue the development of a performance-based rate structure.

Entergy Louisiana	9.7%- 11.3%(1)	In January 2004, Entergy Louisiana filed with the LPSC for a $167 million base rate increase and an ROE of 11.4%. The current ROE midpoint is 10.5%. Hearings are currently set for September 2004. With the LPSC staff, Entergy Louisiana continues to pursue the development of a performance-based rate structure.

Entergy Mississippi	10.64%- 12.86%(2)	An annual formula rate plan is in place. The MPSC approved a $48.2 million rate increase effective January 2003 and an ROE midpoint of 11.75%. Entergy Mississippi will make a formula rate plan filing in March 2004.

Entergy New Orleans	10.25%-12.25%(3)	The City Council approved an agreement in May 2003 allowing for a $30.2 million increase in base rates effective June 1, 2003 and approved the implementation of formula rate plans for the electric and gas service that will be evaluated annually until 2005. An appeal of the approval by intervenors is pending, but the rates remain in effect. The midpoint ROE of both plans is 11.25%, with a target equity component of 42%. Entergy New Orleans will make a formula rate plan filing in May 2004.

System Energy	10.94%	ROE approved by July 2001 FERC order. No cases pending before FERC.

(1)	Entergy Louisiana's formula rate plan expired with the 2001 test year. Under the expired formula, if Entergy Louisiana earned outside of the bandwidth range, rates would be adjusted on a prospective basis. If earnings were above the bandwidth range, rates would be reduced by 60 percent of the overage, and if below, increased by 60 percent of the shortfall.
(2)	Under Mississippi law and Entergy Mississippi's formula rate plan, if Entergy Mississippi's earned ROE is above the top of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's rates are reduced by 50 percent of the difference between the earned ROE and the top of the bandwidth. In such circumstance, Entergy Mississippi's 'Allowed ROE' for the next twelve-month period is the point halfway between such earned ROE and the top of the bandwidth -- Entergy Mississippi's retail rates are set at that halfway-point ROE level. (Before the comparison is made of the earned ROE to the bandwidth, the bandwidth can be adjusted for performance measures by as much as 1%. Rates are adjusted pursuant to Entergy Mississippi's formula rate plan on a prospective basis only.) In the situation where Entergy Mississippi's earned ROE is not above the top of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's 'Allowed ROE' for the next twelve-month period is the top of the range-of-no-change at the top of the bandwidth. If earnings are below the bandwidth range, rates are increased by 50 percent of the difference between the earned ROE and the bottom of the bandwidth. Under the provisions of Entergy Mississippi's formula rate plan, each annual formula rate plan filing incorporates a revised calculation of the benchmark ROE. The benchmark ROE set out in the March 15, 2004, formula rate plan filing likely will differ from the last approved ROE. Entergy Mississippi anticipates the March 15, 2004, filing will show an allowed regulatory earnings range of 9.3% to 12.2%. Entergy Mississippi does not anticipate a reduction in revenues going forward.
(3)	If Entergy New Orleans earns outside of the bandwidth range, rates will be adjusted on a prospective basis. Under the gas formula rate plan, if earnings are above the bandwidth range, rates are reduced by 100 percent of the overage, and if below, increased by 100 percent of the shortfall. In addition, if the ROE falls between 11.5% and 12.25%, rates are reduced by 60 percent of the difference, and if the ROE falls between 10.25% and 11%, rates are increased by 40 percent of the differential. Under the electric formula rate plan, rates are adjusted accordingly by 100 percent of the amount of any overage or shortfall. Entergy New Orleans may earn up to 13.25% under the electric formula rate plan provided that the increase is caused by its share of energy cost savings under the generation performance-based recovery plan discussed below.

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

System Agreement Litigation

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

In the proceeding at FERC, the LPSC alleges that the domestic utility companies' annual production costs over the period 2002 to 2007 will be over or (under) the average for the domestic utility companies by the following amounts:

Entergy Arkansas	($130) to ($278) million
Entergy Gulf States - Louisiana	$11 to $87 million
Entergy Louisiana	$139 to $132 million
Entergy Mississippi	($27) to $13 million
Entergy New Orleans	$7 to $46 million

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

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

On February 10, 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC ALJ's Initial Decision would have on Entergy Arkansas' customers. The APSC order includes a preliminary estimate that the FERC ALJ's Initial Decision would shift approximately $125 million of costs for the year 2003 to Entergy Arkansas' retail customers, and would shift an average of approximately $113 million per year for the years 2004-2011 to Entergy Arkansas' retail customers. The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement is in the best interest of its customers, and whether there are steps that Entergy Arkansas or the APSC can take "to protect [Entergy Arkansas' customers] from future attempts by Louisiana, or any other Entergy retail regulator, to shift its high costs to Arkansas." Entergy Arkansas' initial testimony in the proceeding is due in April 2004.

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

Market and Credit Risks

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

The commodity price risk associated with Entergy's Non-Utility Nuclear and Energy Commodity Services segments.

The foreign currency exchange rate risk associated with certain of Entergy's contractual obligations.

The interest rate and equity price risk associated with Entergy's investments in decommissioning trust funds.

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

Commodity Price Risk

Power Generation

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

	2004	2005	2006	2007	2008
Non-Utility Nuclear:
% of planned generation sold forward	100%	52%	32%	16%	4%
Planned generation (GWh)	32,787	34,164	34,853	34,517	34,513
Average price per MWh	$38	$37	$35	$34	$38

The Vermont Yankee acquisition included a 10-year PPA, which is through the expiration of the current operating license for the plant, under which the former owners will buy the power produced by the plant. The PPA includes an adjustment clause under which the prices specified in the PPA will be adjusted downward annually, beginning in November 2005, if power market prices drop below PPA prices. Accordingly, because the price is not fixed, the table above does not report power from that plant as sold forward after October 2005. Approximately 2% of Non-Utility Nuclear's planned generation in 2005, 13% in 2006, 12% in 2007, and 13% in 2008 is under contract from Vermont Yankee after October 2005.

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

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

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

	2004	2005	2006	2007	2008
Non-Utility Nuclear:
Percent of capacity sold forward:
Bundled capacity and energy contracts	55%	15%	12%	13%	13%
Capacity contracts	28%	15%	6%	3%	0%
Total	83%	30%	18%	16%	13%
Planned MW in operation	4,111	4,203	4,203	4,203	4,203
Average capacity contract price per kW per month	$2.4	$1.3	$0.6	$0.7	N/A
Blended Capacity and Energy (based on revenues)
% of planned generation and capacity sold forward	99%	49%	28%	13%	4%
Average contract revenue per MWh	$39	$37	$35	$34	$38

As of December 31, 2003, approximately 99% of Entergy's counterparties to Non-Utility Nuclear's energy and capacity contracts have investment grade credit ratings.

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

	2004	2005	2006	2007	2008
Energy Commodity Services:
Capacity
Planned MW in operation	1,911	1,911	1,911	1,911	1,911
% of capacity sold forward	43%	43%	34%	31%	26%
Energy
Planned generation (GWh)	3,321	3,348	3,337	3,545	4,015
% of planned generation sold forward	64%	67%	52%	42%	39%
Blended Capacity and Energy (based on revenues)
% of planned energy and capacity sold forward	62%	66%	50%	41%	35%
Average contract revenue per MWh	$26	$25	$27	$31	$28

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

Entergy continually monitors industry trends in order to determine whether asset impairments or other losses could result from a decline in value, or cancellation, of merchant power projects, and records provisions for impairments and losses accordingly.

Marketing and Trading

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

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

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

Value-at-risk is used in conjunction with stress testing, position reporting, and profit and loss reporting in order to measure and control the risk inherent in the trading and mark-to-market portfolios.

EKT estimates its value-at-risk using a model based on J.P. Morgan's Risk Metrics methodology combined with a Monte Carlo simulation approach.

EKT estimates its daily value-at-risk for natural gas and power using a 97.5% confidence level. EKT's daily value-at-risk is a measure that indicates that, if prices moved against the positions, the loss in neutralizing the portfolio would not be expected to exceed the calculated value-at-risk.

EKT seeks to limit the daily value-at-risk on any given day to a certain dollar amount approved by the trading committee.

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

	2003	2002	2001
		(in millions)
DE@R at end of the year	$9.6	$15.2	$5.5
Average DE@R for the year	13.6	10.8	6.4
Low DE@R for the year	5.9	6.6	3.6
High DE@R for the year	35.2	16.9	8.0

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

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

EKT's operations are primarily concentrated in the energy industry.

EKT's trade receivables and other financial instruments are predominantly with energy, utility, and financial services related companies, as well as other trading companies in the U.S., UK, and Western Europe.

EKT maintains credit policies, which its management believes minimize overall credit risk.

Prospective and existing customers are reviewed for creditworthiness based upon pre-established standards, with customers not meeting minimum standards providing various secured payment terms, including the posting of cash collateral.

EKT also has master netting agreements in place. These agreements allow EKT to offset cash and non-cash gains and losses arising from derivative instruments with the same counterparty. EKT's policy is to have such master netting agreements in place with significant counterparties.

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

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

Maturities and Sources for Fair Value of Trading Contracts at December 31, 2003	0-12 months	13-24 months	25+ months	Total
	(In Millions)

Prices actively quoted	$126.3	($87.1)	($14.6)	$24.6
Prices provided by other sources	4.8	(10.1)	5.6	0.3
Prices based on models	(28.0)	14.2	4.9	(8.9)
Total	$103.1	($83.0)	($4.1)	$16.0

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

		2003
		(In Millions)

Fair value of contracts outstanding at December 31, 2002 after implementation of EITF 02-03		$90.9

(Gain)/loss from contracts realized/settled during the year		(580.0)
Net option premiums received during the year		275.7
Change in fair value of contracts attributable to market movements during the year		229.4
Net change in contracts outstanding during the year		(74.9)
Fair value of contracts outstanding at December 31, 2003		$16.0

Foreign Currency Exchange Rate Risk

Entergy Gulf States, System Fuels, and Entergy's Non-Utility Nuclear business enter into foreign currency forward contracts to hedge the Euro-denominated payments due under certain purchase contracts. The notional amounts of the foreign currency forward contracts are 142.8 million Euro and the forward currency rates range from .8641 to 1.085. The maturities of these forward contracts depend on the purchase contract payment dates and range in time from January 2004 to January 2007. The mark-to-market valuation of the forward contracts at December 31, 2003 was a net asset of $50 million. The counterparty banks obligated on these agreements are rated by Standard & Poor's Rating Services at AA on their senior debt obligations as of December 31, 2003.

Interest Rate and Equity Price Risk - Decommissioning Trust Funds

Entergy's nuclear decommissioning trust funds are exposed to fluctuations in equity prices and interest rates. The NRC requires Entergy to maintain trusts to fund the costs of decommissioning ANO 1, ANO 2, River Bend, Waterford 3, Grand Gulf 1, Pilgrim, Indian Point 1 and 2, and Vermont Yankee (NYPA currently retains the decommissioning trusts and liabilities for Indian Point 3 and FitzPatrick). The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that exposure of the various funds to market fluctuations will not affect Entergy's financial results of operations as it relates to the ANO 1 and 2, River Bend, Grand Gulf 1, and Waterford 3 trust funds because of the application of regulatory accounting principles. The Pilgrim, Indian Point 1 and 2, and Vermont Yankee trust funds collectively hold approximately $895 million of fixed-rate, fixed-income securities as of December 31, 2003. These securities have an average coupon rate of approximately 5.6%, an average duration of approximately 5.2 years, and an average maturity of approximately 7.9 years. The Pilgrim, Indian Point 1 and 2, and Vermont Yankee trust funds also collectively hold equity securities worth approximately $450 million as of December 31, 2003. These securities are generally held in funds that are designed to approximate or somewhat exceed the return of the Standard & Poor's 500 Index, and a relatively small percentage of the securities are held in a fund intended to replicate the return of the Wilshire 4500 Index. The decommissioning trust funds are discussed more thoroughly in Notes 1 and 9 to the consolidated financial statements.

Utility Restructuring

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

In the long-term, these changes may result in increased costs associated with utility unbundling of services or functions and transitioning in new organizational structures and ways of conducting business. It is possible that the new organizational structures that may be required will result in lost economies of scale, less beneficial cost sharing arrangements within utility holding company systems, and, in some cases, greater difficulty and cost in accessing capital. Furthermore, these changes could result in early refinancing of debt, the reorganization of debt, or other obligations between newly formed companies and Entergy. As a result of federal and state "codes of conduct" and affiliate transaction rules, adopted as part of restructuring, new non-utility affiliates in Entergy's system may be precluded from, or limited in, doing business with affiliated electric market participants, or have prices set at the lower of cost or market. In addition, regulators may impose limits on (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 utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays in implementing the FERC order have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to work to resolve various issues related to the establishment of such RTOs. Entergy's domestic utility companies were participating with other transmission owners within the southeastern United States to establish an RTO, the proposed SeTrans RTO, but the sponsors determined that the regulatory approvals necessary for the development of the SeTrans RTO were unlikely to be obtained at the present time and in December 2003 suspended further development activity. Although SeTrans development is suspended, Entergy continues to focus its efforts on reforms that can further the core objectives of FERC's 2000 order: achieving greater independence in the provision of transmission service and a more efficient method of pricing that service. Entergy intends to work with FERC and Entergy's retail regulators on certain voluntary steps to further those objectives.

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

Entergy also intends that the independent transmission entity will administer a transition to participant funding that should increase the efficiency of transmission pricing on the Entergy system. Entergy intends for the independent transmission entity to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers. This determination would be made in accordance with protocols approved by the FERC and any party contesting such determination, including Entergy, would be required to seek review at the FERC.

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

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

FERC's Supply Margin Assessment

In November 2001, FERC issued an order that established a new generation market power screen (called Supply Margin Assessment) for purposes of evaluating a utility's request for market-based rate authority, applied that new screen to the Entergy System (among others), determined that Entergy and the others failed the screen within their respective control areas, and ordered these utilities to implement certain mitigation measures as a condition to their continued ability to buy and sell at market-based rates. Among other things, the mitigation measures would require that Entergy transact at cost-based rates when it is buying or selling in the hourly wholesale market within its control area. Entergy requested rehearing of the order, and FERC has delayed the implementation of certain mitigation measures until such time as it has had the opportunity to consider the rehearing request. In June 2003, the FERC proposed and ultimately adopted new market behavior rules and tariff provisions that would be applied to any market-based sale. Entergy modified its market-based rate tariffs to reflect the new provisions but has requested rehearing of FERC's order. Additionally, during December 2003 the FERC announced it was holding additional technical conferences on proposed modifications to its Supply Margin Assessment screen. Two technical conferences were held during January 2004. Entergy has filed comments in this proceeding urging the FERC to rely on an "uncommitted capacity" version of any market screen in order to reflect a utility's native load obligations. It is Entergy's belief that cost-based regulation effectively mitigates both the ability and the incentive to exercise market power to the extent of the native load obligations. A FERC rule on Supply Margin Assessment could be issued by the end of March 2004.

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

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

Interconnection Orders

In January 2003, the FERC issued two orders in proceedings involving Interconnection Agreements between each of the domestic utility companies (except Entergy New Orleans) and certain generators interconnecting to the domestic utility companies' transmission system. In the orders, the FERC authorized the generators to abrogate certain provisions of the interconnection agreements in order to avail themselves of new FERC policies developed after the generators' execution of the agreements. Under the FERC's orders, capital costs that the generators had agreed to bear will now be shifted to Entergy's native load and other transmission customers. Other generators that previously had executed interconnection agreements agreeing to bear similar costs have also filed complaints to obtain the same or similar relief against the domestic utility companies. In the event that the generators that have interconnected to the Entergy transmission system are successful in obtaining such relief, it 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 in February 2003, the D.C. Circuit denied Entergy's petition for review in one proceeding, concluding that the FERC had not acted in an arbitrary and capricious manner when it changed its policy from that of directly 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.

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

Retail

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

Federal Legislation

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

Nuclear Matters

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

Concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel, in particular in the area where Entergy's Indian Point units are located, which are discussed in more detail below. These concerns have led to various proposals to federal regulators as well as governing bodies in some localities where Entergy owns nuclear plants for legislative and regulatory changes that could lead to the shut-down of nuclear units, denial of license extension applications, municipalization of nuclear units, restrictions on nuclear units as a result of unavailability of sites for nuclear fuel disposal, or other adverse effects on owning and operating nuclear power plants. Entergy believes that its generating units are in compliance with NRC requirements and intends to vigorously respond to these concerns and proposals.

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

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

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

Litigation

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

Critical Accounting Estimates

The preparation of Entergy's financial statements in conformity with generally accepted accounting principles requires management to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following estimates as critical accounting estimates because they are based on assumptions and measurements that involve an unusual degree of uncertainty, and there is the potential that different assumptions and measurements could produce estimates that are significantly different than those recorded in Entergy's financial statements.

Nuclear Decommissioning Costs

Entergy owns a significant number of nuclear generation facilities in both its U.S. Utility and Non-Utility Nuclear business units. Regulations require that these facilities be decommissioned after the facility is taken out of service, and funds are collected and deposited in trust funds during the facilities' operating lives in order to provide for this obligation. Entergy conducts periodic decommissioning cost studies (typically updated every three to five years) to estimate the costs that will be incurred to decommission the facilities. Note 9 to the consolidated financial statements contains details regarding Entergy's most recent studies and the obligations recorded by Entergy related to decommissioning. The following key assumptions have a significant effect on these estimates:

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

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

Spent Fuel Disposal - Federal regulations require the Department of Energy to provide a permanent repository for the storage of spent nuclear fuel, and recent legislation has been passed by Congress to develop this repository at Yucca Mountain, Nevada. However, until this site is available, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities.

The costs of developing and maintaining these facilities can have a significant impact (as much as 16% of estimated decommissioning costs). Entergy's decommissioning studies include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors.

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

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

U.S. Utility

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

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

Non-Utility Nuclear

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

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

SFAS 143

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

Recording of full obligation - SFAS 143 requires that the fair value of an asset retirement obligation be recorded when it is incurred. This caused the recorded decommissioning obligation in Entergy's U.S. Utility business to increase significantly, as Entergy had previously only recorded this obligation as the related costs were collected from customers, and as earnings were recorded on the related trust funds.

Fair value approach - SFAS 143 requires that these obligations be measured using a fair value approach. Among other things, this entails the assumption that the costs will be incurred by a third party and will therefore include appropriate profit margins and risk premiums. Entergy's decommissioning studies to date have been based on Entergy performing the work, and have not included any such margins or premiums. Inclusion of these items increased cost estimates.

Discount rate - SFAS 143 requires that these obligations be discounted using a credit-adjusted, risk-free rate. This resulted in significant decreases in Entergy's decommissioning obligations in the Non-Utility Nuclear business, as this discount rate is higher than the implicit rates utilized by Entergy in accounting for these obligations through December 31, 2002.

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

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

For the Non-Utility Nuclear business, the implementation of SFAS 143 resulted in a decrease in liabilities in 2003 of approximately $595 million due to reductions in decommissioning liabilities, a decrease in assets of approximately $340 million, including a decrease in electric plant in service of $315 million, and an increase in earnings of approximately $155 million net-of-tax ($0.67 per share) as a result of the one-time cumulative effect of accounting change.

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

Impairment of Long-lived Assets

Entergy has significant investments in long-lived assets in all of its segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment whenever there are indications that impairments may exist. This evaluation involves a significant degree of estimation and uncertainty, and these estimates are particularly important in Entergy's U.S. Utility and Energy Commodity Services segments. In the U.S. Utility segment, portions of River Bend and Grand Gulf are not included in rate base, which could reduce the revenue that would otherwise be recovered for the applicable portions of those units' generation. In the Energy Commodity Services segment, Entergy's investments in merchant generation assets are subject to impairment if adverse market conditions arise.

In order to determine if Entergy should recognize an impairment of a long-lived asset that is to be held and used, accounting standards require that the sum of the expected undiscounted future cash flows from the asset be compared to the asset's carrying value. If the expected undiscounted future cash flows exceed the carrying value, no impairment is recorded; if such cash flows are less than the carrying value, Entergy is required to record an impairment charge to write the asset down to its fair value. If an asset is held for sale, an impairment is required to be recognized if the fair value (less costs to sell) of the asset is less than its carrying value.

These estimates are based on a number of key assumptions, including:

Future power and fuel prices - Electricity and gas prices have been very volatile in recent years, and this volatility is expected to continue for some time. This volatility necessarily increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows. There is currently an oversupply of electricity throughout the U.S., and it is necessary to project economic growth and other macroeconomic factors in order to project when this oversupply will cease and prices will rise. Similarly, gas prices have been volatile as a result of recent fluctuations in both supply and demand, and projecting future trends in these prices is difficult.

Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets. While market transactions provide evidence for this valuation, the market for such assets is volatile and the value of individual assets is impacted by factors unique to those assets.

Future operating costs - Entergy assumes relatively minor annual increases in operating costs. Technological or regulatory changes that have a significant impact on operations could cause a significant change in these assumptions.

Due to the oversupply of power that existed throughout the U.S. and the UK in 2002, and the resulting decreases in spark spreads, consistent with Entergy's point of view, Entergy's impairment tests indicated that a number of impairments were required to be recognized in 2002 in the Energy Commodity Services segment. These impairments, which were also accompanied by other charges related to the restructuring of Entergy's independent power business, are further detailed in Note 12 to the consolidated financial statements.

Mark-to-market Accounting

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

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

commodity futures, options, swaps, and forwards that are expected to be net settled; and

power sales agreements that do not involve delivery of power from Entergy's power plants.

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

the PPAs for Entergy's Non-Utility Nuclear plants;

capacity purchases and sales by the U.S. Utility companies; and

forward contracts that will result in physical delivery.

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

Pension and Other Postretirement Benefits

Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 11 to the consolidated financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate for the U.S. Utility and Non-Utility Nuclear segments.

Assumptions

Key actuarial assumptions utilized in determining these costs include:

Discount rates used in determining the future benefit obligations;

Projected health care cost trend rates;

Expected long-term rate of return on plan assets; and

Rate of increase in future compensation levels.

Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and poor performance of the financial equity markets over the past several years have impacted Entergy's funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.

In selecting an assumed discount rate, Entergy reviews market yields on high-quality corporate debt. Based on recent market trends, Entergy reduced its discount rate from 7.5% in 2001 and 6.75% in 2002 to 6.25% in 2003. Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy increased its health care cost trend rate assumption used in calculating the 2003 accumulated postretirement benefit obligation. The assumed health care cost trend rate is a 10% increase in health care costs in 2004 gradually decreasing each successive year until it reaches a 4.5% annual increase in health care costs in 2010 and beyond.

In determining its expected long-term rate of return on plan assets, Entergy reviews past long-term performance, asset allocations, and long-term inflation assumptions. Entergy targets an asset allocation for its pension plan assets of roughly 66% equity securities, 30% fixed income securities, and 4% other investments. The target allocation for Entergy's other postretirement benefit assets is 45% equity securities and 55% fixed income securities. Based on recent market trends, Entergy decreased its expected long-term rate of return on plan assets from 9% in 2001 to 8.75% for 2002 and 2003. The trend of reduced inflation caused Entergy to reduce its assumed rate of increase in future compensation levels from 4.6% in 2001 to 3.25% in 2002 and 2003.

Cost Sensitivity

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

Actuarial Assumption	Change in Assumption	Impact on 2003 Pension Cost	Impact on Projected Benefit Obligation
	Increase/(Decrease)

Discount rate	(0.25%)	$4,882	$83,651
Rate of return on plan assets	(0.25%)	$4,346	-
Rate of increase in compensation	0.25%	$4,039	$28,101

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

Actuarial Assumption	Change in Assumption	Impact on 2003 Postretirement Benefit Cost	Impact on Accumulated Postretirement Benefit Obligation
	Increase/(Decrease)

Health care cost trend	0.25%	$5,206	$25,979
Discount rate	(0.25%)	$3,278	$29,500

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

Accounting Mechanisms

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

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

Costs and Funding

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

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

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

Other Contingencies

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

Environmental

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

Changes to existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters.

The identification of additional sites or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party.

The resolution or progression of existing matters through the court system or resolution by the EPA.

Litigation

Entergy has been named as defendant in a number of lawsuits involving employment, ratepayer, and injuries and damages issues, among other matters. Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably estimable, or remote and records reserves for cases which have a probable likelihood of loss and can be estimated. Notes 2 and 9 to the consolidated financial statements include more detail on ratepayer and other lawsuits and management's assessment of the adequacy of reserves recorded for these matters. Given the environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, however, the ultimate outcome of the litigation Entergy is exposed to has the potential to materially affect the results of operations of Entergy, or its operating company subsidiaries.

Sales Warranty and Tax Reserves

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

ENTERGY CORPORATION AND SUBSIDIARIES

SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON

	2003	2002	2001	2000	1999
	(In Thousands, Except Percentages and Per Share Amounts)

Operating revenues	$9,194,920	$8,305,035	$9,620,899	$10,022,129	$8,765,635
Income before cumulative effect of accounting change	$813,393	$623,072	$727,025	$710,915	$595,026
Earnings per share before cumulative effect of accounting change Basic Diluted	$3.48 $3.42	$2.69 $2.64	$3.18 $3.13	$3.00 $2.97	$2.25 $2.25
Dividends declared per share	$1.60	$1.34	$1.28	$1.22	$1.20
Return on average common equity	11.21%	7.85%	10.04%	9.62%	7.77%
Book value per share, year-end	$38.02	$35.24	$33.78	$31.89	$29.78
Total assets	$28,554,210	$27,504,366	$25,910,311	$25,451,896	$22,969,940
Long-term obligations (1)	$7,497,690	$7,488,919	$7,743,298	$8,214,724	$7,252,697

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

	2003	2002	2001	2000	1999
	(Dollars In Thousands)
Domestic Electric Operating Revenues:
Residential	$2,682,802	$2,439,590	$2,612,889	$2,524,529	$2,231,091
Commercial	1,882,060	1,672,964	1,860,040	1,699,699	1,502,267
Industrial	2,081,781	1,850,476	2,298,825	2,177,236	1,878,363
Governmental	194,998	179,508	205,054	185,286	163,403
Total retail	6,841,641	6,142,538	6,976,808	6,586,750	5,775,124
Sales for resale	371,646	330,010	395,353	423,519	397,844
Other (1)	183,888	173,866	(127,334)	209,417	98,446
Total	$7,397,175	$6,646,414	$7,244,827	$7,219,686	$6,271,414
Billed Electric Energy
Sales (GWh):
Residential	32,817	32,581	31,080	31,998	30,631
Commercial	25,863	25,354	24,706	24,657	23,775
Industrial	38,637	41,018	41,577	43,956	43,549
Governmental	2,651	2,678	2,593	2,605	2,564
Total retail	99,968	101,631	99,956	103,216	100,519
Sales for resale	9,248	9,828	8,896	9,794	9,714
Total	109,216	111,459	108,852	113,010	110,233

(1)	2001 includes the effect of a reserve for rate refund at System Energy.

INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Shareholders of
Entergy Corporation:

We have audited the accompanying consolidated balance sheets of Entergy Corporation and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income; of retained earnings, comprehensive income, and paid-in capital; and of cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Entergy-Koch, LP for the year ended December 31, 2003, the Corporation's investment in which is accounted for by the use of the equity method. The Corporation's equity in earnings of unconsolidated equity affiliates for the year ended December 31, 2003 includes $180,110,000 for Entergy Koch, LP, which earnings were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amount audited by other auditors included for such company, is based solely on the report of such other auditors.

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

In our opinion, based on our audits and the report of other auditors, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Corporation and subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.

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

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 9, 2004



                  ENTERGY CORPORATION AND SUBSIDIARIES
                    CONSOLIDATED STATEMENTS OF INCOME

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

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

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

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

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

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

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

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

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

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

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

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

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

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

See Notes to Consolidated Financial Statements.




                  ENTERGY CORPORATION AND SUBSIDIARIES
                  CONSOLIDATED STATEMENTS OF CASH FLOWS

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

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

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

See Notes to Consolidated Financial Statements.















                     ENTERGY CORPORATION AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF CASH FLOWS

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

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

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

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

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

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


SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
  Cash paid (received) during the period for:
    Interest - net of amount capitalized                                          $552,017      $633,931      $708,748
    Income taxes                                                                  $188,709       $57,856     ($113,466)
  Noncash investing and financing activities:
    Debt assumed by the Damhead Creek purchaser                                          -      $488,432             -
    Decommissioning trust funds acquired in nuclear power plant acquisitions             -      $310,000      $430,000
    Long-term debt refunded with proceeds from
       long-term debt issued in prior period                                             -      ($47,000)            -
    Proceeds from long-term debt issued for the purpose
       of refunding prior long-term debt                                                 -             -       $47,000

 See Notes to Consolidated Financial Statements.




                  ENTERGY CORPORATION AND SUBSIDIARIES
                       CONSOLIDATED BALANCE SHEETS
                                 ASSETS

                                                                            December 31,
                                                                       2003           2002
                                                                           (In Thousands)

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

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

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

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

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


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

                                                                             December 31,
                                                                         2003           2002
                                                                            (In Thousands)

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

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

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

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

Commitments and Contingencies

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                            $28,554,210    $27,504,366
                                                                      ===========    ===========
See Notes to Consolidated Financial Statements.


                   ENTERGY CORPORATION AND SUBSIDIARIES
   CONSOLIDATED STATEMENTS OF RETAINED EARNINGS, COMPREHENSIVE INCOME, AND
                              PAID-IN CAPITAL

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

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

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

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

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





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

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

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

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

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

Net unrealized investment gains (losses)                  52,367      52,367       (24,311)    (24,311)        (403)         (403)
                                                         -------    --------      --------    --------     --------      --------
Balance at end of period:
  Accumulated derivative instrument fair value changes   (25,811)                   17,313                  (17,973)
  Other accumulated comprehensive income (loss) items     18,016                   (39,673)                 (70,821)
                                                         -------                  --------                 --------
     Total                                               ($7,795)   --------      ($22,360)   --------     ($88,794)     --------
Comprehensive Income                                     =======    $941,508      ========    $584,359     ========      $730,456
                                                                    ========                  ========                   ========




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

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


See Notes to Consolidated Financial Statements.

ENTERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Use of Estimates in the Preparation of Financial Statements

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

Revenues and Fuel Costs

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

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

The domestic utility companies' rate schedules include either fuel adjustment clauses or fixed fuel factors, both of which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Because the fuel adjustment clause mechanism allows monthly adjustments to recover fuel costs, Entergy Louisiana, Entergy New Orleans, and the Louisiana portion of Entergy Gulf States include a component of fuel cost recovery in their unbilled revenue calculations. Where the fuel component of revenues is billed based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing. Entergy Mississippi's fuel factor includes an energy cost rider that is adjusted quarterly. Entergy Mississippi has deferred until 2004 the collection of fuel under-recoveries for the first and second quarters of 2003 that would have been collected in the third and fourth quarters of 2003, respectively. The deferred amount plus carrying charges will be collected over twelve months beginning January 2004. In the case of Entergy Arkansas and the Texas portion of Entergy Gulf States, their fuel under-recoveries are treated as regulatory investments in the cash flow statements because those companies are allowed by their regulatory jurisdictions to recover the fuel cost regulatory asset over longer than a twelve-month period, and the companies earn a carrying charge on the under-recovered balances.

System Energy's operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf 1. The capital costs are computed by allowing a return on System Energy's common equity funds allocable to its net investment in Grand Gulf 1, plus System Energy's effective interest cost for its debt allocable to its investment in Grand Gulf 1.

Property, Plant, and Equipment

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

Electric plant includes the portions of Grand Gulf 1 and Waterford 3 that have been sold and leased back. For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions.

Net property, plant, and equipment by business segment and functional category, as of December 31, 2003 and 2002, is shown below:

				Energy
		U.S.	Non-Utility	Commodity	Parent and
2003	Entergy	Utility	Nuclear	Services	Other
	(In Millions)
Production
Nuclear	$7,056	$6,112	$944	$-	$-
Other	1,816	1,359	-	457	-
Transmission	2,067	2,067	-	-	-
Distribution	4,231	4,231	-	-	-
Other	1,079	1,069	-	-	10
Construction work in progress	1,381	954	398	-	29
Nuclear fuel
(leased and owned)	513	298	215	-	-
Asset retirement obligation (1)	156	155	-	1	-
Property, plant, and equipment - net	$18,299	$16,245	$1,557	$458	$39

				Energy
		U.S.	Non-Utility	Commodity	Parent and
2002	Entergy	Utility	Nuclear	Services	Other
	(In Millions)
Production
Nuclear	$7,472	$6,314	$1,158	$-	$-
Other	1,616	1,382	-	234	-
Transmission	1,851	1,851	-	-	-
Distribution	4,037	4,037	-	-	-
Other	933	929	-	-	4
Construction work in progress	1,233	797	216	192	28
Nuclear fuel
(leased and owned)	523	284	239	-	-
Property, plant, and equipment - net	$17,665	$15,594	$1,613	$426	$32

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

Depreciation is computed on the straight-line basis at rates based on the estimated service lives of the various classes of property. Depreciation rates on average depreciable property approximated 2.8% in 2003 and 2.9% in 2002 and 2001. Included in these rates are the depreciation rates on average depreciable utility property of 2.8% in 2003, 2002 and 2001 and the depreciation rates on average depreciable non-utility property of 3.3% in 2003, 4.0% in 2002, and 4.8% in 2001.

Jointly-Owned Generating Stations

Certain Entergy subsidiaries jointly own electric generating facilities with third parties. The investments and expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, 2003, the subsidiaries' investment and accumulated depreciation in each of these generating stations were as follows:

Generating Stations		Fuel-Type	Total Megawatt Capability (1)	Ownership	Investment	Accumulated Depreciation
					(In Millions)

Grand Gulf	Unit 1	Nuclear	1,207	90.00% (2)	$3,672	$1,673
Independence	Units 1 and 2	Coal	1,630	47.90%	459	240
White Bluff	Units 1 and 2	Coal	1,635	57.00%	423	256
Roy S. Nelson	Unit 6	Coal	550	70.00%	404	234
Big Cajun 2	Unit 3	Coal	575	42.00%	233	123
Harrison County		Gas	550	70.00%	230	3

(1)	"Total Megawatt Capability" is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
(2)	Includes an 11.5% leasehold interest held by System Energy. System Energy's Grand Gulf 1 lease obligations are discussed in Note 10 to the consolidated financial statements.

Goodwill

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

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

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

Reported earnings applicable to common stock	$926,943	$599,360	$726,196
Add back: Goodwill amortization	-	-	16,265
Adjusted earnings applicable to common stock without
goodwill amortization	$926,943	$599,360	$742,461

Basic earnings per average common share:
Reported earnings applicable to common stock	$4.09	$2.69	$3.29
Goodwill amortization	-	-	0.07
Adjusted earnings applicable to common stock without
goodwill amortization	$4.09	$2.69	$3.36

Diluted earnings per average common share:
Reported earnings applicable to common stock	$4.01	$2.64	$3.23
Goodwill amortization	-	-	0.07
Adjusted earnings applicable to common stock without
goodwill amortization	$4.01	$2.64	$3.30

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

Nuclear Refueling Outage Costs

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

Allowance for Funds Used During Construction

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

Income Taxes

Entergy Corporation and its subsidiaries file a U.S. consolidated federal income tax return. Income taxes are allocated to the subsidiaries in prop