10-K

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

FORM 10-K

(Mark One)
X	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Fiscal Year Ended December 31, 2004
	OR
	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from ____________ to ____________

Commission File Number	Registrant, State of Incorporation, Address of Principal Executive Offices and Telephone Number	IRS Employer Identification No.
1-11299	ENTERGY CORPORATION (a Delaware corporation) 639 Loyola Avenue New Orleans, Louisiana 70113 Telephone (504) 576-4000	72-1229752
1-10764	ENTERGY ARKANSAS, INC. (an Arkansas corporation) 425 West Capitol Avenue Little Rock, Arkansas 72201 Telephone (501) 377-4000	71-0005900
1-27031	ENTERGY GULF STATES, INC. (a Texas corporation) 350 Pine Street Beaumont, Texas 77701 Telephone (409) 838-6631	74-0662730
1-8474	ENTERGY LOUISIANA, INC. (a Louisiana corporation) 4809 Jefferson Highway Jefferson, Louisiana 70121 Telephone (504) 840-2734	72-0245590
1-31508	ENTERGY MISSISSIPPI, INC. (a Mississippi corporation) 308 East Pearl Street Jackson, Mississippi 39201 Telephone (601) 368-5000	64-0205830
0-5807	ENTERGY NEW ORLEANS, INC. (a Louisiana corporation) 1600 Perdido Street, Building 505 New Orleans, Louisiana 70112 Telephone (504) 670-3674	72-0273040
1-9067	SYSTEM ENERGY RESOURCES, INC. (an Arkansas corporation) Echelon One 1340 Echelon Parkway Jackson, Mississippi 39213 Telephone (601) 368-5000	72-0752777

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

Registrant	Title of Class	Name of Each Exchange on Which Registered
Entergy Corporation	Common Stock, $0.01 Par Value - 213,145,161 shares outstanding at February 28, 2005	New York Stock Exchange, Inc. Chicago Stock Exchange Inc. Pacific Exchange Inc.
Entergy Arkansas, Inc.	Mortgage Bonds, 6.7% Series due April 2032 Mortgage Bonds, 6.0% Series due November 2032	New York Stock Exchange, Inc. New York Stock Exchange, Inc.
Entergy Gulf States, Inc.	Preferred Stock, Cumulative, $100 Par Value: $4.40 Dividend Series $4.52 Dividend Series $5.08 Dividend Series Adjustable Rate Series B (Depository Receipts)	New York Stock Exchange, Inc. New York Stock Exchange, Inc. New York Stock Exchange, Inc. New York Stock Exchange, Inc.
Entergy Gulf States Capital I	8.75% Cumulative Quarterly Income Preferred Securities, Series A (guaranteed by Entergy Gulf States, Inc.)	New York Stock Exchange, Inc.
Entergy Louisiana, Inc.	Mortgage Bonds, 7.6% Series due April 2032	New York Stock Exchange, Inc.
Entergy Mississippi, Inc.	Mortgage Bonds, 6.0% Series due November 2032 Mortgage Bonds, 7.25% Series due December 2032	New York Stock Exchange, Inc. New York Stock Exchange, Inc.

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

Registrant	Title of Class
Entergy Arkansas, Inc.	Preferred Stock, Cumulative, $100 Par Value Preferred Stock, Cumulative, $0.01 Par Value
Entergy Gulf States, Inc.	Preferred Stock, Cumulative, $100 Par Value
Entergy Louisiana, Inc.	Preferred Stock, Cumulative, $100 Par Value Preferred Stock, Cumulative, $25 Par Value
Entergy Mississippi, Inc.	Preferred Stock, Cumulative, $100 Par Value
Entergy New Orleans, Inc.	Preferred Stock, Cumulative, $100 Par Value

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

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

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

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

            The aggregate market value of Entergy Corporation Common Stock, $0.01 Par Value, held by non-affiliates as of the end of the second quarter of 2004, was $12.7 billion based on the reported last sale price of $56.01 per share for such stock on the New York Stock Exchange on June 30, 2004. Entergy Corporation is the sole holder of the common stock of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc., and System Energy Resources, Inc.

DOCUMENTS INCORPORATED BY REFERENCE

            Portions of the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders, to be held May 13, 2005, are incorporated by reference into Parts I and III hereof.

TABLE OF CONTENTS

	SEC Form 10-K Reference Number	PageNumber
Definitions		i
Entergy's Business	Part I. Item 1.	1
Financial Information for U.S. Utility, Non-Utility Nuclear, and Energy        Commodity Services		2
Strategy		3
Report of Management		4
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis	Part II. Item 7.
Results of Operations		5
Liquidity and Capital Resources		12
Significant Factors and Known Trends		22
Critical Accounting Estimates		33
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	41
Report of Independent Registered Public Accounting Firm		42
Consolidated Statements of Income For the Years Ended December 31,           2004, 2003, and 2002	Part II. Item 8.	43
Consolidated Statements of Cash Flows For the Years Ended December           31, 2004, 2003, and 2002	Part II. Item 8.	44
Consolidated Balance Sheets, December 31, 2004 and 2003	Part II. Item 8.	46
Consolidated Statements of Retained Earnings, Comprehensive Income,           and Paid in Capital for the Years Ended December 31, 2004, 2003,           and 2002	Part II. Item 8.	48
Notes to Consolidated Financial Statements	Part II. Item 8.	49
U.S. Utility	Part I. Item 1.	105
Customers		105
Electric Energy Sales		105
Retail Rate Regulation		107
Property and Other Generation Resources		113
Fuel Supply		116
Federal Regulation		119
Service Companies		128
Earnings Ratios		128
Non-Utility Nuclear	Part I. Item 1.	129
Property		129
Energy and Capacity Sales		129
Fuel Supply		130
Other Business Activities		131
Energy Commodity Services	Part I. Item 1.	131
Non-Nuclear Wholesale Assets Business		132
Entergy-Koch, L.P.		132
Regulation of Entergy's Business	Part I. Item 1.	133
PUHCA		133
Federal Power Act		133
State Regulation		134
Regulation of the Nuclear Power Industry		135
Environmental Regulation		137
Litigation		142
Research Spending		146
Employees		146

Entergy Arkansas, Inc.
Management's Financial Discussion and Analysis	Part II. Item 7.
Results of Operations		147
Liquidity and Capital Resources		147
Significant Factors and Known Trends		150
Critical Accounting Estimates		154
Report of Independent Registered Public Accounting Firm		164
Income Statements For the Years Ended December 31, 2004, 2003,          and 2002	Part II. Item 8.	165
Statements of Cash Flows For the Years Ended December 31, 2004,          2003, and 2002	Part II. Item 8.	167
Balance Sheets, December 31, 2004 and 2003	Part II. Item 8.	168
Statements of Retained Earnings for the Years Ended December 31, 2004,          2003, and 2002	Part II. Item 8.	170
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	171
Entergy Gulf States, Inc.
Management's Financial Discussion and Analysis	Part II. Item 7.
Results of Operations		172
Liquidity and Capital Resources		176
Significant Factors and Known Trends		179
Critical Accounting Estimates		188
Report of Independent Registered Public Accounting Firm		193
Income Statements For the Years Ended December 31, 2004, 2003,            and 2002	Part II. Item 8.	194
Statements of Cash Flows For the Years Ended December 31, 2004,            2003, and 2002	Part II. Item 8.	195
Balance Sheets, December 31, 2004 and 2003	Part II. Item 8.	196
Statements of Retained Earnings and Comprehensive Income for the            Years Ended December 31, 2004, 2003, and 2002	Part II. Item 8.	198
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	199
Entergy Louisiana, Inc.
Management's Financial Discussion and Analysis	Part II. Item 7.
Results of Operations		200
Liquidity and Capital Resources		203
Significant Factors and Known Trends		207
Critical Accounting Estimates		213
Report of Independent Registered Public Accounting Firm		218
Income Statements For the Years Ended December 31, 2004, 2003,            and 2002	Part II. Item 8.	219
Statements of Cash Flows For the Years Ended December 31, 2004,            2003, and 2002	Part II. Item 8.	221
Balance Sheets, December 31, 2004 and 2003	Part II. Item 8.	222
Statements of Retained Earnings for the Years Ended December 31, 2004,            2003, and 2002	Part II. Item 8.	224
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	225
Entergy Mississippi, Inc.
Management's Financial Discussion and Analysis	Part II. Item 7.
Results of Operations		226
Liquidity and Capital Resources		228
Significant Factors and Known Trends		231
Critical Accounting Estimates		236
Report of Independent Registered Public Accounting Firm		239
Income Statements For the Years Ended December 31, 2004, 2003,            and 2002	Part II. Item 8.	240
Statements of Cash Flows For the Years Ended December 31, 2004,            2003, and 2002	Part II. Item 8.	241
Balance Sheets, December 31, 2004 and 2003	Part II. Item 8.	242
Statements of Retained Earnings for the Years Ended December 31,            2004, 2003, and 2002	Part II. Item 8.	244
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	245

Entergy New Orleans, Inc.
Management's Financial Discussion and Analysis	Part II. Item 7.
Results of Operations		246
Liquidity and Capital Resources		248
Significant Factors and Known Trends		251
Critical Accounting Estimates		257
Report of Independent Registered Public Accounting Firm		260
Statements of Operations For the Years Ended December 31, 2004,            2003, and 2002	Part II. Item 8.	261
Statements of Cash Flows For the Years Ended December 31, 2004,            2003, and 2002	Part II. Item 8.	263
Balance Sheets, December 31, 2004 and 2003	Part II. Item 8.	264
Statements of Retained Earnings for the Years Ended December 31,            2004, 2003, and 2002	Part II. Item 8.	266
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	267
System Energy Resources, Inc.
Management's Financial Discussion and Analysis	Part II. Item 7.
Results of Operations		268
Liquidity and Capital Resources		268
Significant Factors and Known Trends		271
Critical Accounting Estimates		272
Report of Independent Registered Public Accounting Firm		276
Income Statements For the Years Ended December 31, 2004, 2003,            and 2002	Part II. Item 8.	277
Statements of Cash Flows For the Years Ended December 31, 2004,            2003, and 2002	Part II. Item 8.	279
Balance Sheets, December 31, 2004 and 2003	Part II. Item 8.	280
Statements of Retained Earnings for the Years Ended December 31,            2004, 2003, and 2002	Part II. Item 8.	282
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	283
Notes to Respective Financial Statements for the Domestic Utility Companies     and System Energy	Part II. Item 8.	284
Properties	Part I. Item 2.	349
Legal Proceedings	Part I. Item 3.	349
Submission of Matters to a Vote of Security Holders	Part I. Item 4.	349
Directors and Executive Officers of Entergy Corporation	Part III. Item 10.	349
Market for Registrants' Common Equity and Related Stockholder Matters	Part II. Item 5.	351
Selected Financial Data	Part II. Item 6.	352
Management's Discussion and Analysis of Financial Condition and Results of    Operations	Part II. Item 7.	352
Quantitative and Qualitative Disclosures About Market Risk	Part II. Item 7A.	352
Financial Statements and Supplementary Data	Part II. Item 8.	353
Changes in and Disagreements with Accountants on Accounting and Financial    Disclosure	Part II. Item 9.	353
Controls and Procedures	Part II. Item 9A.	353
Attestation Report of Registered Public Accounting Firm	Part II. Item 9A.	354
Other Information	Part II. Item 9B.	368
Directors and Executive Officers of the Registrants	Part III. Item 10.	369
Executive Compensation	Part III. Item 11.	373
Security Ownership of Certain Beneficial Owners and Management	Part III. Item 12.	383
Certain Relationships and Related Transactions	Part III. Item 13.	386
Principal Accountant Fees and Services	Part IV. Item 14	387
Exhibits, Financial Statement Schedules, and Reports on Form 8-K	Part IV. Item 15.	390
Signatures		391
Consent of Independent Registered Public Accounting Firm		398
Report of Independent Registered Public Accounting Firm		400
Index to Financial Statement Schedules		S-1
Exhibit Index		E-1

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

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

FORWARD-LOOKING INFORMATION

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

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

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

DEFINITIONS

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

Abbreviation or Acronym	Term
AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
ANO 1 and 2	Units 1 and 2 of Arkansas Nuclear One Steam Electric Generating Station (nuclear), owned by Entergy Arkansas
APSC	Arkansas Public Service Commission
Board	Board of Directors of Entergy Corporation
Cajun	Cajun Electric Power Cooperative, Inc.
capacity factor	Actual plant output divided by maximum potential plant output for the period
City Council or Council	Council of the City of New Orleans, Louisiana
CPI-U	Consumer Price Index - Urban
DOE	United States Department of Energy
domestic utility companies	Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, collectively
EITF	FASB's Emerging Issues Task Force
Energy Commodity Services	Entergy's business segment that includes Entergy-Koch, LP and Entergy's non-nuclear wholesale assets business
Entergy	Entergy Corporation and its direct and indirect subsidiaries
Entergy Corporation	Entergy Corporation, a Delaware corporation
Entergy-Koch	Entergy-Koch, LP, a joint venture equally owned by subsidiaries of Entergy and Koch Industries, Inc.
EPA	United States Environmental Protection Agency
EPDC	Entergy Power Development Corporation, a wholly-owned subsidiary of Entergy Corporation
FASB	Financial Accounting Standards Board
FEMA	Federal Emergency Management Agency
FERC	Federal Energy Regulatory Commission
firm liquidated damages	Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset); if a party fails to deliver or receive energy, the defaulting party must compensate the other party as specified in the contract
FSP	FASB Staff Position
Grand Gulf	Unit No. 1 of Grand Gulf Steam Electric Generating Station (nuclear), 90% owned or leased by System Energy
GWh	Gigawatt-hour(s), which equals one million kilowatt-hours
Independence	Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi, and 7% by Entergy Power
IRS	Internal Revenue Service
ISO	Independent System Operator
kV	Kilovolt
kW	Kilowatt
kWh	Kilowatt-hour(s)

DEFINITIONS (Continued)

Abbreviation or Acronym	Term
LDEQ	Louisiana Department of Environmental Quality
LPSC	Louisiana Public Service Commission
Mcf	1,000 cubic feet of gas
MMBtu	One million British Thermal Units
MPSC	Mississippi Public Service Commission
MW	Megawatt(s), which equals one thousand kilowatt(s)
MWh	Megawatt-hour(s)
Nelson Unit 6	Unit No. 6 (coal) of the Nelson Steam Electric Generating Station, owned 70% by Entergy Gulf States
Net debt ratio	Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents
Net MW in operation	Installed capacity owned or operated
Net revenue	Operating revenue net of fuel, fuel-related, and purchased power expenses; and other regulatory credits
Non-Utility Nuclear	Entergy's business segment that owns and operates five nuclear power plants and sells electric power produced by those plants to wholesale customers
NRC	Nuclear Regulatory Commission
NYPA	New York Power Authority
PPA	Purchased power agreement
production cost	Cost in $/MMBtu associated with delivering gas, excluding the cost of the gas
PRP	Potentially responsible party (a person or entity that may be responsible for remediation of environmental contamination)
PUCT	Public Utility Commission of Texas
PUHCA	Public Utility Holding Company Act of 1935, as amended
PURPA	Public Utility Regulatory Policies Act of 1978
Ritchie Unit 2	Unit 2 of the R.E. Ritchie Steam Electric Generating Station (gas/oil)
River Bend	River Bend Steam Electric Generating Station (nuclear), owned by Entergy Gulf States
SEC	Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards as promulgated by the FASB
SMEPA	South Mississippi Electric Power Agency, which owns a 10% interest in Grand Gulf
spark spread	Dollar difference between electricity prices per unit and natural gas prices after assuming a conversion ratio for the number of natural gas units necessary to generate one unit of electricity
System Agreement	Agreement, effective January 1, 1983, as modified, among the domestic utility companies relating to the sharing of generating capacity and other power resources
System Energy	System Energy Resources, Inc.
System Fuels	System Fuels, Inc.

DEFINITIONS (Concluded)

Abbreviation or Acronym	Term
TWh	Terawatt-hour(s), which equals one billion kilowatt-hours
unit-contingent	Transaction under which power is supplied from a specific generation asset; if the specified generation asset is unavailable as a result of forced outage or unanticipated event or circumstance, the seller is not liable to the buyer for any damages resulting from the seller's failure to deliver power
unit-contingent with availability guarantees	Transaction under which power is supplied from a specific generation asset; if the specified generation asset is unavailable as a result of forced outage or unanticipated event or circumstance, the seller is not liable to the buyer for any damages resulting from the seller's failure to deliver power unless the actual availability over a specified period of time is below an availability threshold specified in the contract
Unit Power Sales Agreement	Agreement, dated as of June 10, 1982, as amended and approved by FERC, among Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, relating to the sale of capacity and energy from System Energy's share of Grand Gulf
UK	The United Kingdom of Great Britain and Northern Ireland
U.S. Utility	Entergy's business segment that generates, transmits, distributes, and sells electric power, with a small amount of natural gas distribution
Waterford 3	Unit No. 3 (nuclear) of the Waterford Steam Electric Generating Station, 100% owned or leased by Entergy Louisiana
weather-adjusted usage	Electric usage excluding the effects of deviations from normal weather
White Bluff	White Bluff Steam Electric Generating Station, 57% owned by Entergy Arkansas

ENTERGY'S BUSINESS

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

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

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

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

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

			Entergy Corporation
U. S. Utility		Non-Utility Nuclear		Energy Commodity Services
	Entergy Arkansas, Inc.		Entergy Nuclear Operations, Inc.	Entergy-Koch, LP	Non-Nuclear Wholesale Assets
	Entergy Gulf States, Inc.		Entergy Nuclear Finance, Inc.	(50% ownership)
	Entergy Louisiana, Inc.		Entergy Nuclear Generation Co. (Pilgrim)			Entergy Power Development Corp.
	Entergy Mississippi, Inc.		Entergy Nuclear FitzPatrick LLC			Entergy Asset Management, Inc.
	Entergy New Orleans, Inc.		Entergy Nuclear Indian Point 2, LLC			Entergy Power, Inc.
	System Energy Resources, Inc.		Entergy Nuclear Indian Point 3, LLC
	Entergy Operations, Inc.		Entergy Nuclear Vermont Yankee, LLC
	Entergy Services, Inc.		Entergy Nuclear, Inc.
	System Fuels, Inc.		Entergy Nuclear Fuels Company
			Entergy Nuclear Nebraska LLC

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

Strategy

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

___________________________________________________________________________________________

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

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

Part I, Item 1 is continued on page 105.

ENTERGY CORPORATION AND SUBSIDIARIES

REPORT OF MANAGEMENT

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

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

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

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

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

J. WAYNE LEONARD Chief Executive Officer of Entergy Corporation	LEO P. DENAULT Executive Vice President and Chief Financial Officer of Entergy Corporation
HUGH T. MCDONALD Chairman, President, and Chief Executive Officer of Entergy Arkansas, Inc.	JOSEPH F. DOMINO Chairman of Entergy Gulf States, Inc., President and Chief Executive Officer - Texas of Entergy Gulf States, Inc.
E. RENAE CONLEY Chairman, President, and Chief Executive Officer of Entergy Louisiana, Inc.; President and Chief Executive Officer- Louisiana of Entergy Gulf States, Inc.	CAROLYN C. SHANKS Chairman, President, and Chief Executive Officer of Entergy Mississippi, Inc.
DANIEL F. PACKER Chairman, President, and Chief Executive Officer of Entergy New Orleans, Inc.	GARY J. TAYLOR Chairman, President, and Chief Executive Officer of System Energy Resources, Inc.
THEODORE H. BUNTING, JR. Vice President and Chief Financial Officer of System Energy Resources, Inc.	JAY A. LEWIS Vice President and Chief Financial Officer of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc.

ENTERGY CORPORATION AND SUBSIDIARIES

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

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

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

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

	% of Revenue			% of Net Income			% of Total Assets
Segment	2004	2003	2002	2004	2003	2002	2004	2003	2002
U.S. Utility	81	82	82	72	52	97	80	79	79
Non-Utility Nuclear	13	14	14	26	32	32	16	15	16
Energy Commodity Services	2	2	4	-	19	(23)	3	7	8
Parent & Other	4	2	-	2	(3)	(6)	1	(1)	(3)

Results of Operations

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

Operating Segment	2004	2003	2002
	(In Thousands)
U.S. Utility	$643,408	$469,050	$583,251
Non-Utility Nuclear	245,029	300,799	200,505
Energy Commodity Services	3,481	180,454	(145,830)
Parent & Other	17,606	(23,360)	(38,566)
Total	$909,524	$926,943	$599,360

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

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

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

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

U.S. UTILITY

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

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

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

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

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

Net Revenue

2004 Compared to 2003

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

	(In Millions)
2003 net revenue	$4,214.5
Volume/weather	68.3
Summer capacity charges	17.4
Base rates	10.6
Deferred fuel cost revisions	(46.3)
Price applied to unbilled sales	(19.3)
Other	(1.2)
2004 net revenue	$4,244.0

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

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

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

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

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

Gross operating revenues and regulatory credits

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

Other regulatory credits increased primarily due to the following:

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

2003 Compared to 2002

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

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

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

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

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

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

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

Gross operating revenues and regulatory credits

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

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

Other Income Statement Variances

2004 Compared to 2003

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

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

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

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

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

2003 Compared to 2002

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

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

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

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

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

NON-UTILITY NUCLEAR

Following are key performance measures for Non-Utility Nuclear:

	2004	2003	2002
Net MW in operation at December 31	4,058	4,001	3,955
Average realized price per MWh	$41.26	$39.38	$40.07
Generation in GWh for the year	32,524	32,379	29,953
Capacity factor for the year	92%	92%	93%

2004 Compared to 2003

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

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

Partially offsetting this increase were the following:

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

2003 Compared to 2002

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

ENERGY COMMODITY SERVICES

Sales of Entergy-Koch Businesses

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

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

Results of Operations

2004 Compared to 2003

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

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

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

2003 Compared to 2002

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

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

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

PARENT & OTHER

2004 Compared to 2003

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

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

2003 Compared to 2002

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

Income Taxes

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

Liquidity and Capital Resources

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

Capital Structure

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

	2004	2003	2002
Net debt to net capital at the end of the year	44.7%	45.3%	47.7%
Effect of subtracting cash from debt	2.7%	2.2%	4.1%
Debt to capital at the end of the year	47.4%	47.5%	51.8%

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

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

Long-term debt maturities	2004	2005	2006	2007	2008-2009	after 2009
	(In Millions)
As of December 31, 2003
U.S. Utility	$450	$355	$28	$573	$721	$4,305
Non-Utility Nuclear	74	72	76	80	40	173
Energy Commodity Services	-	-	-	-	-	-
Parent and Other	-	60	-	-	539	301
Total	$524	$487	$104	$653	$1,300	$4,779
As of December 31, 2004
U.S. Utility	-	$359	$27	$98	$749	$4,880
Non-Utility Nuclear	-	77	76	80	40	173
Energy Commodity Services	-	-	-	-	-	-
Parent and Other	-	60	-	50	539	301
Total	-	$496	$103	$228	$1,328	$5,354

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

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

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

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

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

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

	2005	2006	2007	2008-2009	after 2009
	(In Millions)
Capital lease payments, including nuclear fuel leases	$136	$143	$3	$2	$3

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

Company	Expiration Date	Amount of Facility	Amount Drawn as of Dec. 31, 2004
Entergy Arkansas	April 2005	$85 million	-
Entergy Louisiana	April 2005	$15 million (a)	-
Entergy Mississippi	May 2005	$25 million	-
Entergy New Orleans	April 2005	$14 million (a)	-

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

Operating Lease Obligations and Guarantees of Unconsolidated Obligations

Entergy has a minimal amount of operating lease obligations and guarantees in support of unconsolidated obligations. Entergy's guarantees in support of unconsolidated obligations are not likely to have a material effect on Entergy's financial condition or results of operations. Following are Entergy's payment obligations as of December 31, 2004 on non-cancelable operating leases with a term over one year:

	2005	2006	2007	2008-2009	after 2009
	(In Millions)
Operating lease payments	$99	$86	$69	$100	$210

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

Summary of Contractual Obligations of Consolidated Entities

Contractual Obligations	2005	2006-2007	2008-2009	after 2009	Total
	(In Millions)
Long-term debt (1)	$496	$331	$1,328	$5,354	$7,509
Capital lease payments (2)	$136	$146	$2	$3	$287
Operating leases (2)	$99	$155	$100	$210	$564
Purchase obligations (3)	$1,160	$1,402	$962	$1,156	$4,680

(1)	Long-term debt is discussed in Note 5 to the consolidated financial statements.
(2)	Capital lease payments include nuclear fuel leases. Lease obligations are discussed in Note 9 to the consolidated financial statements.
(3)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. Approximately 99% of the total pertains to fuel and purchased power obligations that are recovered in the normal course of business through various fuel cost recovery mechanisms in the U.S. Utility business.

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

Capital Funds Agreement

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

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

Capital Expenditure Plans and Other Uses of Capital

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

Planned construction and capital investments		2005	2006	2007
		(In Millions)
Maintenance Capital:
	U.S. Utility	$734	$699	$763
	Non-Utility Nuclear	72	72	60
	Energy Commodity Services	3	4	6
	Parent and Other	11	19	11
		820	794	840
Capital Commitments:
	U.S. Utility	571	349	201
	Non-Utility Nuclear	90	67	43
	Energy Commodity Services	-	-	-
	Parent and Other	-	-	-
		661	416	244
Total		$1,481	$1,210	$1,084

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

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

• Replacement of the ANO 1 steam generators and reactor vessel closure head. Management estimates the cost of the ANO 1 project to be approximately $235 million, of which approximately $96 million has been incurred through 2004. $115 million is expected to be incurred in 2005, with the remainder expected to be spent in 2006. Entergy expects the replacement to occur during a planned refueling outage in 2005. Entergy Arkansas filed with the APSC in January 2003 a request for a declaratory order that the investment in the replacement is in the public interest. The APSC issued the requested order in May 2003. This order is analogous to the order received in 1998 prior to the replacement of the ANO 2 steam generators.
• Purchase of the Perryville power plant in Louisiana. In January 2004, Entergy Louisiana signed a definitive agreement to acquire the 718 MW Perryville power plant for $170 million. The agreement has subsequently been amended to allow the current plant owner to retain the interconnection facilities associated with the plant, resulting in a decrease in the acquisition price to $162 million. As a result of the amended terms, the FERC issued an order in October 2004 disclaiming jurisdiction over the acquisition. This order currently is subject to rehearing by the FERC. 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 outpu t to Entergy Gulf States under a long-term cost-of-service power purchase agreement. In addition, Entergy Louisiana and Entergy Gulf States executed an interim power purchase agreement with the plant's owner through the date of the acquisition's closing (as long as that occurs by December 2005) for 100 percent of the output of the Perryville power plant. In April 2004, the bankruptcy court approved Entergy Louisiana's agreement to acquire the plant. In March 2004, Entergy Gulf States and Entergy Louisiana filed with the LPSC for its approval of the acquisition and long-term cost-of-service power purchase agreement. Entergy is seeking approval from the LPSC of cost recovery for the acquisition, giving consideration to the need for the power and the prudence of Entergy Louisiana and Entergy Gulf States in engaging in the transaction. Hearings are scheduled for March 2005. Assuming regulatory approval by the LPSC, Entergy Louisiana expects the Perryville acquisition to close in mid-2005.
• Transmission expansion designed to address immediate load growth needs and to provide improved transmission flexibility for the southeastern Louisiana and Texas regions of Entergy's service territory. Entergy expects to spend $170 million on high voltage transmission infrastructure to be completed in phases between mid-2005 to mid-2007.
• Purchase of additional generation supply sources within the U.S. Utility's service territory.
• Nuclear power plant uprates, dry cask spent fuel storage, and license renewals.

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

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

Dividends and Stock Repurchases

Declarations of dividends on Entergy's common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy's common stock dividends based upon Entergy's earnings, financial strength, and future investment opportunities. At its October 2004 meeting, the Board increased Entergy's quarterly dividend per share by 20%, to $0.54. In 2004, Entergy paid approximately $428 million in cash dividends on its common stock.

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

PUHCA Restrictions on Uses of Capital

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

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

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

Sources of Capital

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

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

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

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

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

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

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

Cash Flow Activity

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

		2004	2003	2002
		(In Millions)
Cash and cash equivalents at beginning of period		$692	$1,335	$752
Cash flow provided by (used in):
	Operating activities	2,929	2,006	2,181
	Investing activities	(1,140)	(1,783)	(1,388)
	Financing activities	(1,672)	(869)	(213)
Effect of exchange rates on cash and cash equivalents		(1)	3	3
	Net increase (decrease) in cash and cash equivalents	116	(643)	583
Cash and cash equivalents at end of period		$808	$692	$1,335

Operating Cash Flow Activity

2004 Compared to 2003

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

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

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

2003 Compared to 2002

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

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

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

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

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

Investing Activities

2004 Compared to 2003

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

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

2003 Compared to 2002

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

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

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

Financing Activities

2004 Compared to 2003

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

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

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

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

2003 Compared to 2002

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

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

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

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

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

Significant Factors and Known Trends

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

State and Local Rate Regulation and Fuel-Cost Recovery

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

Company	Authorized ROE	Pending Proceedings/Events
Entergy Arkansas	11.0%	No base rate cases are pending. Transition cost recovery rider approved to collect $8.5 million effective October 2004 with recovery expected over subsequent 16 months. It is likely that a rate filing will be made in 2005 in connection with the ANO 1 steam generator and reactor vessel head replacement.
Entergy Gulf States-Texas	10.95%	Base rates are currently set at rates approved by the PUCT in June 1999. Entergy Gulf States filed a retail electric rate case with the PUCT in August 2004. In October 2004, the PUCT issued a written order in which it dismissed the rate case indicating that Entergy Gulf States is still subject to a rate freeze based on an agreement, approved by PUCT order in 2001, stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory, unless lifted by the PUCT prior thereto. Entergy Gulf States has appealed this decision and intends to pursue other available remedies, including legislation that would clarify that it is no longer operating under a rate freeze. In February 2005, bills were filed in the Texas legislature that would clarify that Entergy Gulf States is no longer operating under a rate freeze and specify that retail open access will not commence in Entergy Gulf States' territory until the PUCT certifies a power region.
Entergy Gulf States-Louisiana	11.1%	In December 2003, the LPSC staff recommended a $30.6 million rate refund and a prospective rate reduction of approximately $50 million as a result of the ninth post-merger earnings analysis (2002). Hearings concluded in May 2004. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement that would resolve, among other dockets, Entergy Gulf States' ninth post-merger review, and dockets established to consider issues concerning the companies' power purchases for the summers of 2001, 2002, 2003, and 2004. The proposed settlement currently includes an offer to refund $76 million to Entergy Gulf States' Louisiana customers through a credit on bills rendered in March 2005, with no immediate change in the current base rates. The settlement also proposes a formula rate plan with an ROE mid-point of 10.65%. The LPSC has solicited comments on the proposed settlement from the parties to the various proceedings at issue in the settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005.
Entergy Louisiana	9.7%- 11.3%(1)	In January 2004, Entergy Louisiana filed with the LPSC an application for a $167 million base rate increase and an ROE of 11.4%. The currently authorized ROE midpoint is 10.5%. Hearings in this matter concluded in December 2004. Based on the evidence submitted at the hearing, the LPSC staff is recommending approximately a $7 million base rate increase. The LPSC staff proposed the implementation of a formula rate plan that includes a provision for the recovery of incremental capacity costs, including those related to the proposed Perryville acquisition. A decision by the LPSC is expected in mid- to late-March 2005 on these issues. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement with the LPSC that would resolve, among other dockets, dockets established to consider issues concerning the companies' power purchases for the summers of 2001, 2002, 2003, and 2004. The proposed settlement currently includes an offer to refund $14 million to Entergy Louisiana's customers. The LPSC has solicited comments on the proposed settlement from the parties to the various proceedings at issue in the proposed settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005.
Entergy Mississippi	9.3%- 12.2%(2)	An annual formula rate plan is in place. Entergy Mississippi made its annual formula rate plan filing in March 2004 based on a 2003 test year. There was no change in rates based on an adjusted ROE midpoint of 10.77%.
Entergy New Orleans	10.25%- 12.25%(3)	The midpoint ROE of the electric and gas plans is 11.25%, with a target equity component of the capital structure of 42%. Entergy New Orleans made a formula rate plan filing in April 2004. The City Council ordered that electric and gas rates remain unchanged from levels set in 2003. Entergy New Orleans will file its formula rate plan for the year ended December 31, 2004 by May 1, 2005 and also intends to file for an extension of the formula rate plan by September 1, 2005. If the formula rate plan is not extended by the City Council, the rate adjustments in effect based on the December 31, 2004 test year shall continue.
System Energy	10.94%	ROE approved by July 2001 FERC order. No cases pending before FERC.

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

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

Federal Regulation

The FERC regulates wholesale rates (including Entergy intrasystem sales pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy's sales of capacity and energy from Grand Gulf 1 to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement.

System Agreement Litigation

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

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

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

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

	Range of Annual Payments or (Receipts)	Average Annual Payments or (Receipts) for 2005-2009 Period
	(In Millions)	(In Millions)
Entergy Arkansas	$154 to $281	$215
Entergy Gulf States	($130) to ($15)	($63)
Entergy Louisiana	($199) to ($98)	($141)
Entergy Mississippi	($16) to $8	$1
Entergy New Orleans	($17) to ($5)	($12)

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

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

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

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

Transmission

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

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

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

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

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

FERC's Supply Margin Assessment

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

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

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

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

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

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

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

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

Interconnection Orders

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

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

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

Available Flowgate Capacity Proceeding

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

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

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

Federal Legislation

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

Market and Credit Risks

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

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

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

Commodity Price Risk

Power Generation

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

		2005	2006	2007	2008	2009
Non-Utility Nuclear:
Percent of planned generation sold forward:
	Unit-contingent	36%	20%	17%	1%	0%
	Unit-contingent with availability guarantees	54%	52%	38%	25%	0%
	Firm liquidated damages	4%	4%	2%	0%	0%
	Total	94%	76%	57%	26%	0%
Planned generation (TWh)		34	35	34	34	35
Average contracted price per MWh		$39	$41	$42	$44	N/A

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

A sale of power on a unit contingent basis coupled with an availability guarantee provides for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. To date, Entergy has not incurred any payment obligation to any power purchaser pursuant to an availability guarantee. All of Entergy's outstanding availability guarantees provide for dollar limits on Entergy's maximum liability under such guarantees.

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

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

		2005	2006	2007	2008	2009
Non-Utility Nuclear:
Percent of capacity sold forward:
	Bundled capacity and energy contracts	13%	13%	13%	13%	13%
	Capacity contracts	58%	67%	36%	22%	10%
	Total	71%	80%	49%	35%	23%
Planned net MW in operation		4,155	4,200	4,200	4,200	4,200
Average capacity contract price per kW per month		$1.2	$1.1	$1.1	$1.0	$0.9
Blended Capacity and Energy (based on revenues)
% of planned generation and capacity sold forward		93%	87%	65%	36%	12%
Average contract revenue per MWh		$40	$42	$43	$44	$43

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

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

	2005	2006	2007	2008	2009
Energy Commodity Services:
Capacity
Planned MW in operation	1,578	1,578	1,578	1,578	1,578
% of capacity sold forward	44%	33%	29%	29%	19%
Energy
Planned generation (TWh)	3	3	3	3	4
% of planned generation sold forward	69%	54%	45%	45%	35%
Blended Capacity and Energy (based on revenues)
% of planned energy and capacity sold forward	63%	44%	38%	39%	22%
Average contract revenue per MWh	$24	$24	$28	$28	$21

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

Foreign Currency Exchange Rate Risk

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

Interest Rate and Equity Price Risk - Decommissioning Trust Funds

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

Nuclear Matters

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

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

Litigation

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

Critical Accounting Estimates

The preparation of Entergy's financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy's financial position or results of operations.

Nuclear Decommissioning Costs

Entergy owns a significant number of nuclear generation facilities in both its U.S. Utility and Non-Utility Nuclear business units. Regulations require Entergy to decommission its nuclear power plants after each facility is taken out of service, and money is collected and deposited in trust funds during the facilities' operating lives in order to provide for this obligation. Entergy conducts periodic decommissioning cost studies (typically updated every three to five years) to estimate the costs that will be incurred to decommission the facilities. The following key assumptions have a significant effect on these estimates:

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

SFAS 143

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

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

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

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

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

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

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

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

Unbilled Revenue

As discussed in Note 1 to the consolidated financial statements, Entergy records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month, including fuel price. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period and fuel price fluctuations, in addition to changes in certain components of the calculation including changes to estimates such as line loss, which affects the estimate of unbilled customer usage, and assumptio ns regarding price such as the fuel cost recovery mechanism.

Impairment of Long-lived Assets

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

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

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

• Future power and fuel prices - Electricity and gas prices have been very volatile in recent years, and this volatility is expected to continue. This volatility necessarily increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows. There is currently an oversupply of electricity throughout the U.S., including much of Entergy's service territory, and it is necessary to project economic growth and other macroeconomic factors in order to project when this oversupply will cease and prices will rise. Similarly, gas prices have been volatile as a result of recent fluctuations in both supply and demand, and projecting future trends in these prices is difficult.
• Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets. While market transactions provide evidence for this valuation, the market for such assets is volatile and the value of individual assets is impacted by factors unique to those assets.
• Future operating costs - Entergy assumes relatively minor annual increases in operating costs. Technological or regulatory changes that have a significant impact on operations could cause a significant change in these assumptions.

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

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

Pension and Other Postretirement Benefits

Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 10 to the consolidated financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate for the U.S. Utility and Non-Utility Nuclear segments.

Assumptions

Key actuarial assumptions utilized in determining these costs include:

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

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

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

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

Cost Sensitivity

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

Actuarial Assumption	Change in Assumption	Impact on 2004 Pension Cost	Impact on Projected Benefit Obligation
	Increase/(Decrease)
Discount rate	(0.25%)	$10,268	$94,903
Rate of return on plan assets	(0.25%)	$4,388	-
Rate of increase in compensation	0.25%	$4,928	$29,134

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

Actuarial Assumption	Change in Assumption	Impact on 2004 Postretirement Benefit Cost	Impact on Accumulated Postretirement Benefit Obligation
	Increase/(Decrease)
Health care cost trend	0.25%	$4,150	$23,892
Discount rate	(0.25%)	$2,715	$28,719

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

Accounting Mechanisms

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

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

Costs and Funding

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

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

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

Other Contingencies

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

Environmental

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

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

Litigation

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

Sales Warranty and Tax Reserves

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

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Entergy Corporation:

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

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

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

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

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

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 8, 2005

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

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

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

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

ENTERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Use of Estimates in the Preparation of Financial Statements

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

Revenues and Fuel Costs

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

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

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

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

Property, Plant, and Equipment

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

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

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

2004	Entergy	U.S. Utility	Non-Utility Nuclear	Energy Commodity Services	Parent and Other
	(In Millions)
Production
Nuclear	$7,308	$5,987	$1,321	$-	$-
Other	1,533	1,228	-	305	-
Transmission	2,182	2,182	-	-	-
Distribution	4,672	4,672	-	-	-
Other	1,123	1,115	-	-	8
Construction work in progress	1,198	924	244	2	28
Nuclear fuel (leased and owned)	583	297	286	-	-
Asset retirement obligation	97	97	-	-	-
Property, plant, and equipment - net	$18,696	$16,502	$1,851	$307	$36

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

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

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

Jointly-Owned Generating Stations

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

Generating Stations		Fuel-Type	Total Megawatt Capability (1)	Ownership	Investment	Accumulated Depreciation
					(In Millions)
U.S. Utility:
Grand Gulf	Unit 1	Nuclear	1,270	90.00% (2)	$3,702	$1,780
Independence	Units 1 and 2	Coal	1,630	47.90%	$462	$249
White Bluff	Units 1 and 2	Coal	1,635	57.00%	$428	$264
Roy S. Nelson	Unit 6	Coal	550	60.90%	$403	$241
Big Cajun 2	Unit 3	Coal	575	42.00%	$233	$128
Energy Commodity Services:
Harrison County		Gas	550	61.00%	$209	$7
Warren		Gas	300	75.00%	$24	$9

(1)	"Total Megawatt Capability" is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
(2)	Includes an 11.5% leasehold interest held by System Energy. System Energy's Grand Gulf lease obligations are discussed in Note 9 to the consolidated financial statements.

Nuclear Refueling Outage Costs

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

Allowance for Funds Used During Construction (AFUDC)

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

Income Taxes

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

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

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

Earnings per Share

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

	For the Years Ended December 31,
	2004			2003			2002
	(In Millions, Except Per Share Data)
		$/share			$/share			$/share
Income before cumulative effect of accounting change	$909.5		$789.9			$599.4
Average number of common shares outstanding - basic	226.9	$4.01	226.8		$3.48	223.0		$2.69
Average dilutive effect of:
Stock Options (1)	4.3	(0.075)	4.1		(0.062)	3.9		(0.046)
Equity Awards	-	-	0.2		(0.004)	0.4		(0.005)
Average number of common shares outstanding - diluted	231.2	$3.93	231.1		$3.42	227.3		$2.64
Earnings applicable to common stock	$909.5		$926.9			$599.4
Average number of common shares outstanding - basic	226.9	$4.01	226.8		$4.09	223.0		$2.69
Average dilutive effect of:
Stock Options (1)	4.3	(0.075)	4.1		(0.073)	3.9		(0.046)
Equity Awards	-	-	0.2		(0.004)	0.4		(0.005)
Average number of common shares outstanding - diluted	231.2	$3.93	231.1		$4.01	227.3		$2.64

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

Stock-based Compensation Plans

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

	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands, Except Per Share Data)
Earnings applicable to common stock	$909,524	$926,943	$599,360
Add back: Stock-based compensation expense included in earnings applicable to common stock, net   of related tax effects	5,141	2,818	- -
Deduct: Total stock-based employee compensation   expense determined under fair value method for all   awards, net of related tax effects	16,668	24,518	28,110
Pro forma earnings applicable to common stock	$897,997	$905,243	$571,250
Earnings per average common share:
Basic	$4.01	$4.09	$2.69
Basic - pro forma	$3.96	$3.99	$2.56
Diluted	$3.93	$4.01	$2.64
Diluted - pro forma	$3.88	$3.92	$2.51

Application of SFAS 71

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

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

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

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

Cash and Cash Equivalents

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

Investments

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

Equity Method Investees

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

Derivative Financial Instruments and Commodity Derivatives

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

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

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

Impairment of Long-Lived Assets

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

River Bend AFUDC

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

Transition to Competition Liabilities

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

Reacquired Debt

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

Foreign Currency Translation

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

New Accounting Pronouncements

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

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

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

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

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

NOTE 2. RATE AND REGULATORY MATTERS

Electric Industry Restructuring and the Continued Application of SFAS 71

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

Jurisdiction	Status of Retail Open Access	% of Entergy's 2004 Revenues Derived from Retail Electric Utility Operations in the Jurisdiction
Arkansas	Retail open access was repealed in February 2003.	11.6%
Texas	In July 2004, the PUCT effectively rejected Entergy Gulf States' proposal to implement retail open access in its service territory. In February 2005, bills were submitted in the Texas Legislature that would specify that retail open access will not commence in Entergy Gulf States' territory until the PUCT certifies a power region.	11.8%
Louisiana	The LPSC has deferred pursuing retail open access, pending developments at the federal level and in other states. In response to a study submitted to the LPSC that was funded by a group of large industrial customers, the LPSC recently has solicited comments regarding a limited retail access program. It is uncertain what action, if any, the LPSC might take in response to the information it received.	34.1%
Mississippi	The MPSC has recommended not pursuing open access at this time.	10.9%
New Orleans	The Council has taken no action on Entergy New Orleans' proposal filed in 1997.	4.5%

Texas

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

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

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

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

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

Louisiana

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

Regulatory Assets

Other Regulatory Assets

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

	2004	2003
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 8)	$380.1	$464.9
Deferred fuel - non-current - recovered through rate riders when rates are redetermined annually	21.9	28.2
Depreciation re-direct - recovery begins at start of retail open access (Note 1)	79.1	79.1
DOE Decommissioning and Decontamination Fees - recovered through fuel rates until December 2006 (Note 8)	25.3	32.9
Low-level radwaste - recovery timing dependent upon pending lawsuit	19.4	19.4
Pension costs (Note 10)	207.3	134.0
Postretirement benefits - recovered through 2013 (Note 10)	19.1	21.5
Provision for storm damages - recovered through cost of service	124.5	123.3
Removal costs - recovered through depreciation rates (Note 8)	53.2	45.6
Resource planning - recovery timing will be determined by the LPSC in a base rate proceeding (Note 2)	25.4	5.8
River Bend AFUDC - recovered through August 2025 (Note 1)	37.5	39.4
Sale-leaseback deferral - recovered through June 2014 (Note 9)	127.3	131.7
Spindletop gas storage facility - recovered through December 2032	42.3	38.0
Unamortized loss on reaquired debt - recovered over term of debt	169.9	164.4
Other - various	97.0	70.1
Total	$1,429.3	$1,398.3

Deferred fuel costs

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

	2004	2003
	(In Millions)
Entergy Arkansas	$7.4	$10.6
Entergy Gulf States	$90.1	$118.4
Entergy Louisiana	$8.7	$30.6
Entergy Mississippi	($22.8)	$89.1
Entergy New Orleans	$2.6	($2.7)

Entergy Arkansas

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

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

Entergy Gulf States (Texas)

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

	Amount
	(In Millions)
Under-recovered fuel costs for the period 9/03 - 7/04 to be recovered through an interim fuel surcharge over a six-month period beginning in January 2005	$27.8
Items to be addressed as part of unbundling	$29.0
Imputed capacity charges	$ 9.3
Other	$12.5

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

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

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

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

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

Entergy Gulf States (Louisiana) and Entergy Louisiana

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

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

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

Entergy Mississippi

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

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

Entergy New Orleans

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

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

Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

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

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

Retail Rates

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

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

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

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

Recovery of River Bend Costs

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

Filings with the LPSC

Proposed Settlement

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

Annual Earnings Reviews (Entergy Gulf States)

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

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

Retail Rates

(Entergy Louisiana)

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

Filings with the MPSC (Entergy Mississippi)

Formula Rate Plan Filings

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

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

Filings with the Council (Entergy New Orleans)

Rate Proceedings

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

Fuel Adjustment Clause Litigation

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

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

NOTE 3. INCOME TAXES

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

	2004	2003	2002
	(In Thousands)
Current:
Federal (a)(b)	$54,380	($731,129)	$510,109
Foreign	(2,231)	8,284	(3,295)
State (a)(b)	38,301	23,396	43,788
Total (a)(b)	90,450	(699,449)	550,602
Deferred -- net	296,445	1,307,092	(233,532)
Investment tax credit
adjustments -- net	(20,987)	(27,644)	(23,132)
Recorded income tax expense	$365,908	$579,999	$293,938

(a)

The actual cash taxes paid were $28,241 in 2004, $188,709 in 2003, and $57,856 in 2002. Entergy Louisiana's mark-to-market tax accounting election significantly reduced taxes paid in 2002. In 2001, Entergy Louisiana changed its method of accounting for tax purposes related to its wholesale electric power contracts. The most significant of these is the contract to purchase power from the Vidalia project (the contract is discussed in Note 8 to the consolidated financial statements). The new tax accounting method has provided a cumulative cash flow benefit of approximately $790 million through 2004, which is expected to reverse in the years 2005 through 2031. The election did not reduce book income tax expense. The timing of the reversal of this benefit depends on several variables, including the price of power. Approximately half of the consolidated cash flow benefit of the election occurred in 2001 and the remainder occurred in 2002.

(b)

In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $2.95 billion deduction on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. On a consolidated basis, a $74 million cash tax benefit was realized in 2004. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit.

Total income taxes differ from the amounts computed by applying the statutory income tax rate to income before taxes. The reasons for the differences for the years 2004, 2003, and 2002 are:

	2004	2003	2002
	(In Thousands)
Computed at statutory rate (35%)	$454,635	$535,663	$320,954
Increases (reductions) in tax
resulting from:
State income taxes net of
federal income tax effect	36,185	54,024	44,835
Regulatory differences-
utility plant items	41,240	52,638	29,774
Amortization of investment
tax credits	(20,596)	(24,364)	(22,294)
EAM capital loss	(86,426)	-	-
Flow-through/permanent
differences	(42,902)	(30,221)	(38,197)
US tax on foreign income	2,014	7,888	(28,416)
Other -- net	(18,242)	(15,629)	(12,718)
Total income taxes	$365,908	$579,999	$293,938
Effective Income Tax Rate	28.2%	37.9%	32.1%

The EAM capital loss is a tax benefit resulting from the sale of preferred stock and less than 1% of the common stock of Entergy Asset Management, an Entergy subsidiary. In December 2004, an Entergy subsidiary sold the stock to a third party for $29.75 million. The sale resulted in a capital loss for tax purposes of $370 million, producing a federal and state net tax benefit of $97 million that Entergy recorded in the fourth quarter of 2004. Entergy has established a contingency provision in its financial statements that management believes will sufficiently cover the risk associated with this issue.

Significant components of net deferred and noncurrent accrued tax liabilities as of December 31, 2004 and 2003 are as follows:

	2004	2003
	(In Thousands)
Deferred and Noncurrent Accrued Tax Liabilities:
Net regulatory liabilities	($978,815)	($1,072,898)
Plant-related basis differences	(4,699,803)	(3,574,593)
Power purchase agreements	(972,348)	(945,495)
Nuclear decommissioning	(545,109)	(519,028)
Other	(346,993)	(379,875)
Total	(7,543,068)	(6,491,889)
Deferred Tax Assets:
Accumulated deferred investment
tax credit	133,979	141,723
Capital losses	134,688	92,423
Net operating loss carryforwards	1,201,006	129,122
Sale and leaseback	227,155	223,134
Unbilled/deferred revenues	28,741	18,983
Pension-related items	247,662	204,083
Reserve for regulatory adjustments	131,112	138,933
Customer deposits	107,652	108,591
Nuclear decommissioning	158,796	272,551
Other	225,659	399,080
Valuation allowance	(43,864)	(39,210)
Total	2,552,586	1,689,413
Net deferred and noncurrent accrued tax liability	($4,990,482)	($4,802,476)

At December 31, 2004, Entergy had $342.4 million in net realized federal capital loss carryforwards that will expire as follows: $103.8 million in 2007, $10.6 million in 2008, and $228.0 million in 2009.

At December 31, 2004, Entergy had federal net operating loss carryforwards of $2.9 billion. If the federal net operating loss carryforwards are not utilized, they will expire in the years 2023 through 2024.

At December 31, 2004, Entergy had state net operating loss carryforwards of $3.5 billion, primarily resulting from Entergy Louisiana's mark-to-market tax election and the change in method of accounting for tax purposes related to cost of goods sold, as discussed above. If the state net operating loss carryforwards are not utilized, they will expire in the years 2008 through 2019.

The 2004 and 2003 valuation allowances are provided against UK capital loss and UK net operating loss carryforwards, and certain state net operating loss carryforwards. The UK losses can be utilized against future UK taxable income. For UK tax purposes, these carryforwards do not expire.

On October 22, 2004, the American Jobs Creation Act of 2004 (the Act) was enacted. The Act promotes domestic production and investing activities by providing a number of tax incentives including a temporary incentive to repatriate accumulated foreign earnings, subject to certain limitations, by providing an 85% dividends received deduction for certain repatriated earnings and also providing a tax deduction of up to 9% of qualifying production activities. In 2004, Entergy repatriated $64 million of accumulated foreign earnings, which resulted in approximately $16.1 million of tax benefit. At December 31, 2004, Entergy has approximately $7.4 million of undistributed earnings from subsidiary companies outside the United States that are being considered for repatriation. If these earnings are repatriated in accordance with the Act, the repatriation would result in approximately $1.5 million of income tax expense. In accordance with FSP 109-1, which was issued by the FASB to address the accounting for the impacts of the Act, the allowable production tax credit will be treated as a special deduction in the period in which it is deducted rather than treated as a tax rate change during 2004 which is the period in which the Act was signed into law. The adoption of FSP 109-1 and FSP 109-2, also issued by the FASB to address the accounting for the repatriation provisions of the Act, did not have a material effect on Entergy's financial statements.

NOTE 4. LINES OF CREDIT AND SHORT-TERM BORROWINGS

Entergy Corporation has in place two separate revolving credit facilities, a 5-year credit facility and a 3-year credit facility. The 5-year credit facility, which expires in December 2009, has a borrowing capacity of $500 million, none of which was outstanding at December 31, 2004. The 3-year credit facility, which expires in May 2007, has a borrowing capacity of $965 million, of which $50 million was outstanding at December 31, 2004. Entergy also has the ability to issue letters of credit against the total borrowing capacity of both credit facilities, and $50 million had been issued against the 3-year facility at December 31, 2004. The commitment fee for these facilities is currently 0.13% of the line amount. Commitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior debt ratings of the domestic utility companies.

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

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

Company	Expiration Date	Amount of Facility	Amount Drawn as of Dec. 31, 2004
Entergy Arkansas	April 2005	$85 million	-
Entergy Louisiana	April 2005	$15 million(a)	-
Entergy Mississippi	May 2005	$25 million	-
Entergy New Orleans	April 2005	$14 million(a)	-

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

The 364-day credit facilities have variable interest rates and the average commitment fee is 0.13%. The Entergy Arkansas facility requires it to maintain total shareholder's equity of at least 25% of its total assets.

The short-term borrowings of Entergy's subsidiaries are limited to amounts authorized by the SEC. The current limits authorized are effective through November 30, 2007. In addition to borrowing from commercial banks, Entergy's subsidiaries are authorized under the SEC order to borrow from Entergy's money pool. The money pool is an inter-company borrowing arrangement designed to reduce Entergy's subsidiaries' dependence on external short-term borrowings. Borrowings from the money pool and external borrowings combined may not exceed the SEC authorized limits. As of December 31, 2004, Entergy's subsidiaries' aggregate authorized limit was $1.6 billion and the aggregate outstanding borrowing from the money pool was $151.6 million. There were no borrowings outstanding from external sources. Under the SEC order and without further SEC authorization, the domestic utility companies and System Energy cannot issue new short-term indebtedness unless (a) Entergy and the borrower each mainta in common equity of at least 30% of its capital and, (b) with the exception of money pool borrowings, the debt security to be issued (if rated) and all outstanding securities of the issuer and Entergy Corporation that are rated must be rated investment grade. There is further discussion of commitments for long-term financing arrangements in Note 5 to the consolidated financial statements.

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

NOTE 5. LONG - TERM DEBT

Long-term debt as of December 31, 2004 and 2003 consisted of:

	2004	2003
	(In Thousands)
Mortgage Bonds:
8.25% Series due April 2004 - Entergy Gulf States	$-	$292,000
6.2% Series due May 2004 - Entergy Mississippi	-	75,000
6.125% Series due July 2005 - Entergy Arkansas	100,000	100,000
8.125% Series due July 2005 - Entergy New Orleans	30,000	30,000
6.77% Series due August 2005 - Entergy Gulf States	98,000	98,000
Libor + 0.90% Series due June 2007 - Entergy Gulf States	-	275,000
4.875% Series due October 2007 - System Energy	70,000	70,000
5.2% Series due December 2007 - Entergy Gulf States	-	200,000
6.5% Series due March 2008 - Entergy Louisiana	-	115,000
4.35% Series due April 2008 - Entergy Mississippi	100,000	100,000
6.45% Series due April 2008 - Entergy Mississippi	-	80,000
3.6% Series due June 2008 - Entergy Gulf States	325,000	325,000
3.875% Series due August 2008 - Entergy New Orleans	30,000	30,000
Libor + 0.40% Series due December 2009 - Entergy Gulf States	225,000	-
4.65% Series due May 2011 - Entergy Mississippi	80,000	-
4.875% Series due November 2011 - Entergy Gulf States	200,000	-
6.0% Series due December 2012 - Entergy Gulf States	140,000	140,000
5.15% Series due February 2013 - Entergy Mississippi	100,000	100,000
5.25% Series due August 2013 - Entergy New Orleans	70,000	70,000
5.09% Series due November 2014 - Entergy Louisiana	115,000	-
5.6% Series due December 2014 - Entergy Gulf States	50,000	-
5.25% Series due August 2015 - Entergy Gulf States	200,000	200,000
6.75% Series due October 2017 - Entergy New Orleans	25,000	25,000
5.4% Series due May 2018 - Entergy Arkansas	150,000	150,000
4.95% Series due June 2018 - Entergy Mississippi	95,000	95,000
5.0% Series due July 2018 - Entergy Arkansas	115,000	115,000
5.5% Series due April 2019 - Entergy Louisiana	100,000	-
8.0% Series due March 2023 - Entergy New Orleans	-	45,000
7.7% Series due July 2023 - Entergy Mississippi	-	60,000
7.55% Series due September 2023 - Entergy New Orleans	-	30,000
7.0% Series due October 2023 - Entergy Arkansas	175,000	175,000
5.6% Series due September 2024 - Entergy New Orleans	35,000	-
5.65% Series due September 2029 - Entergy New Orleans	40,000	-
6.7% Series due April 2032 - Entergy Arkansas	100,000	100,000
7.6% Series due April 2032 - Entergy Louisiana	150,000	150,000
6.0% Series due November 2032 - Entergy Arkansas	100,000	100,000
6.0% Series due November 2032 - Entergy Mississippi	75,000	75,000
7.25% Series due December 2032 - Entergy Mississippi	100,000	100,000
5.9% Series due June 2033 - Entergy Arkansas	100,000	100,000
6.20% Series due July 2033 - Entergy Gulf States	240,000	240,000
6.25% Series due April 2034 - Entergy Mississippi	100,000	-
6.4% Series due October 2034 - Entergy Louisiana	70,000	-
6.38% Series due November 2034 - Entergy Arkansas	60,000	-
Total mortgage bonds	$3,763,000	$3,860,000

	2004	2003
	(In Thousands)
Governmental Bonds (a):
5.45% Series due 2010, Calcasieu Parish - Louisiana	$22,095	$22,095
6.75% Series due 2012, Calcasieu Parish - Louisiana	48,285	48,285
6.7% Series due 2013, Pointe Coupee Parish - Louisiana	17,450	17,450
5.7% Series due 2014, Iberville Parish - Louisiana	21,600	21,600
7.7% Series due 2014, West Feliciana Parish - Louisiana	94,000	94,000
5.8% Series due 2015, West Feliciana Parish - Louisiana	28,400	28,400
7.0% Series due 2015, West Feliciana Parish - Louisiana	39,000	39,000
7.5% Series due 2015, West Feliciana Parish - Louisiana	41,600	41,600
9.0% Series due 2015, West Feliciana Parish - Louisiana	45,000	45,000
5.8% Series due 2016, West Feliciana Parish - Louisiana	20,000	20,000
6.3% Series due 2016, Pope County - - Arkansas (h)	19,500	19,500
5.6% Series due 2017, Jefferson County - Arkansas	45,500	45,500
6.3% Series due 2018, Jefferson County - - Arkansas (h)	9,200	9,200
6.3% Series due 2020, Pope County - - Arkansas	120,000	120,000
6.25% Series due 2021, Independence County - - Arkansas (h)	45,000	45,000
7.5% Series due 2021, St. Charles Parish - - Louisiana (h)	50,000	50,000
5.875% Series due 2022, Mississippi Business Finance Corp.	216,000	216,000
5.9% Series due 2022, Mississippi Business Finance Corp.	102,975	102,975
7.0% Series due 2022, Warren County - Mississippi	-	8,095
7.0% Series due 2022, Washington County - Mississippi	-	7,935
7.0% Series due 2022, St. Charles Parish - - Louisiana (h)	24,000	24,000
7.05% Series due 2022, St. Charles Parish - - Louisiana (h)	20,000	20,000
Auction Rate due 2022, Independence County - - Mississippi (h)	30,000	30,000
4.6% Series due 2022, Mississippi Business Finance Corp.	16,030	-
5.95% Series due 2023, St. Charles Parish - - Louisiana (h)	25,000	25,000
6.2% Series due 2023, St. Charles Parish - - Louisiana (h)	33,000	33,000
6.875% Series due 2024, St. Charles Parish - - Louisiana (h)	20,400	20,400
6.375% Series due 2025, St. Charles Parish - Louisiana	16,770	16,770
7.3% Series due 2025, Claiborne County - Mississippi	-	7,625
6.2% Series due 2026, Claiborne County - Mississippi	90,000	90,000
5.05% Series due 2028, Pope County - Arkansas (b)	47,000	47,000
5.65% Series due 2028, West Feliciana Parish - Louisiana (c)	-	62,000
6.6% Series due 2028, West Feliciana Parish - Louisiana	40,000	40,000
5.35% Series due 2029, St. Charles Parish - - Louisiana (i)	-	-
Auction Rate due 2030, St. Charles Parish - - Louisiana (h)	60,000	60,000
4.9% Series due 2030, St. Charles Parish - Louisiana (d) (e)	55,000	55,000
Total governmental bonds	1,462,805	1,532,430
Other Long-Term Debt:
Note Payable to NYPA, non-interest bearing, 4.8% implicit rate	$445,605	$514,708
3 year Bank Credit Facility (Entergy Corporation and Subsidiaries,          Note 4)	50,000	-
Bank term loan, Entergy Corporation, avg rate 2.98%, due 2005	60,000	60,000
Bank term loan, Entergy Corporation, avg rate 3.08%, due 2008	35,000	35,000
6.17% Notes due March 2008, Entergy Corporation	72,000	72,000
6.23% Notes due March 2008, Entergy Corporation	15,000	15,000
6.13% Notes due September 2008, Entergy Corporation	150,000	150,000

	2004	2003
	(In Thousands)
Other Long-Term Debt (continued):
7.75% Notes due December 2009, Entergy Corporation	267,000	267,000
6.58% Notes due May 2010, Entergy Corporation	75,000	75,000
6.9% Notes due November 2010, Entergy Corporation	140,000	140,000
7.06% Notes due March 2011, Entergy Corporation	86,000	86,000
Long-term DOE Obligation (f)	156,332	154,409
Waterford 3 Lease Obligation        7.45% (Entergy Corporation and Subsidiaries, Note 9)	247,725	262,534
Grand Gulf Lease Obligation        5.01% (Entergy Corporation and Subsidiaries, Note 9)	397,119	403,468
Unamortized Premium and Discount - Net	(10,277)	(11,853)
8.5% Junior Subordinated Deferrable Interest Debentures         Due 2045 - Entergy Arkansas	-	61,856
8.75% Junior Subordinated Deferrable Interest Debentures         Due 2046 - Entergy Gulf States	87,629	87,629
9.0% Junior Subordinated Deferrable Interest Debentures         Due 2045 - Entergy Louisiana	-	72,165
Other	9,457	9,966
Total Long-Term Debt	7,509,395	7,847,312
Less Amount Due Within One Year	492,564	524,372
Long-Term Debt Excluding Amount Due Within One Year	$7,016,831	$7,322,940
Fair Value of Long-Term Debt (g)	$6,614,211	$7,123,706

(a)	Consists of pollution control revenue bonds and environmental revenue bonds.
(b)	The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on September 1, 2005 and can then be remarketed.
(c)	The bonds had a mandatory tender date of September 1, 2004. Entergy Gulf States purchased the bonds from the holders, pursuant to the mandatory tender provision, and has not remarketed the bonds at this time.
(d)	On June 1, 2002, Entergy Louisiana remarketed $55 million St. Charles Parish Pollution Control Revenue Refunding Bonds due 2030, resetting the interest rate to 4.9% through May 2005.
(e)	The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on June 1, 2005 and can then be remarketed.
(f)	Pursuant to the Nuclear Waste Policy Act of 1982, Entergy's nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service. The contracts include a one-time fee for generation prior to April 7, 1983. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt.
(g)	The fair value excludes lease obligations and long-term DOE obligations, and includes debt due within one year. It is determined using bid prices reported by dealer markets and by nationally recognized investment banking firms.
(h)	The bonds are secured by a series of collateral first mortgage bonds.
(i)	The bonds in the principal amount of $110.95 million had a mandatory tender date of October 1, 2003. Entergy Louisiana purchased the bonds from the holders, pursuant to the mandatory tender provision, and has not remarketed the bonds at this time.

The annual long-term debt maturities (excluding lease obligations) for debt outstanding as of December 31, 2004, for the next five years are as follows:

	(In Thousands)
2005	$467,298
2006	$75,896
2007	$199,539
2008	$747,246
2009	$512,584

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

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

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

Junior Subordinated Deferrable Interest Debentures and Implementation of FIN 46

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

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

Capital Funds Agreement

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

• maintain System Energy's equity capital at a minimum of 35% of its total capitalization (excluding short-term debt);
• permit the continued commercial operation of Grand Gulf 1;
• pay in full all System Energy indebtedness for borrowed money when due; and
• enable System Energy to make payments on specific System Energy debt, under supplements to the agreement assigning System Energy's rights in the agreement as security for the specific debt.

NOTE 6. PREFERRED STOCK

The number of shares authorized and outstanding and dollar value of preferred stock and minority interest for Entergy Corporation subsidiaries as of December 31, 2004 and 2003 are presented below. Only the Entergy Gulf States series "with sinking fund" contain mandatory redemption requirements. All other series of the U.S. Utility are redeemable at Entergy's option.

	Shares Authorized		Shares Outstanding
	2004	2003	2004	2003	2004	2003
Entergy Corporation					(Dollars in Thousands)
U.S. Utility:
Preferred Stock without sinking fund:
Entergy Arkansas, 4.32%-7.88% Series	1,613,500	1,613,500	1,613,500	1,613,500	$116,350	$116,350
Entergy Gulf States, 4.20%-7.56% Series	473,268	473,268	473,268	473,268	47,327	47,327
Entergy Louisiana, 4.16%-8.00% Series	2,115,000	2,115,000	2,115,000	2,115,000	100,500	100,500
Entergy Mississippi, 4.36%-8.36% Series	503,807	503,807	503,807	503,807	50,381	50,381
Entergy New Orleans, 4.36%-5.56% Series	197,798	197,798	197,798	197,798	19,780	19,780
Total U. S. Utility Preferred Stock without sinking fund	4,903,373	4,903,373	4,903,373	4,903,373	334,337	334,337
Energy Commodity Services:
Preferred Stock without sinking fund:
Entergy Asset Management, 11.50% rate	1,000,000	-	297,376	-	29,738	-
Other	-	-	-	-	1,281	-
Total Preferred Stock without sinking fund	5,903,373	4,903,373	5,200,749	4,903,373	$365,356	$334,337
U.S. Utility:
Preferred Stock with sinking fund:
Entergy Gulf States, Adjustable
Rate 7.0% (a)	174,000	208,520	174,000	208,520	$17,400	$20,852
Total Preferred Stock with sinking fund	174,000	208,520	174,000	208,520	$17,400	$20,852
Fair Value of Preferred Stock with
sinking fund (b)					$15,286	$15,354

(a)	Represents weighted-average annualized rate for 2004 and 2003.
(b)	Fair values were determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. There is additional disclosure of fair value of financial instruments in Note 14 to the consolidated financial statements.

All outstanding preferred stock is cumulative.

Entergy Gulf States' preferred stock with sinking fund retirements were 34,500 shares in 2004 and 2003, and 18,579 shares in 2002. Entergy Gulf States has annual sinking fund requirements of $3.45 million through 2009 for its preferred stock outstanding.

In 2004, Entergy realized a pre-tax gain of $0.9 million upon the sale to a third party of preferred shares, and less than 1% of the common shares, of Entergy Asset Management, an Entergy subsidiary. See Note 3 to the consolidated financial statements for a discussion of the tax benefit realized on the sale. Entergy Asset Management's stockholders' agreement provides that at any time during the 180-day period prior to December 31, 2007 or each subsequent December 31 thereafter, either Entergy Asset Management or the preferred shareholders may request that the preferred dividend rate be reset. If Entergy Asset Management and the preferred shareholders are unable to agree on a dividend reset rate, a preferred shareholder can request that its shares be sold to a third party. If Entergy Asset Management is unable to sell the preferred shares within 75 days, the preferred shareholder has the right to take control of the Entergy Asset Management board of directors for the purpose of liquidat ing the assets of Entergy Asset Management in order to repay the preferred shares and any accrued dividends.

NOTE 7. COMMON EQUITY

Common Stock

Treasury Stock

Treasury stock activity for Entergy for 2004 and 2003 is as follows:

	2004		2003
	Treasury Shares	Cost	Treasury Shares	Cost
		(In Thousands)		(In Thousands)
Beginning Balance, January 1	19,276,445	$561,152	25,752,410	$747,331
Repurchases	16,631,800	1,017,996	155,000	8,135
Issuances:
Employee Stock-Based Compensation Plans	(4,555,897)	(146,877)	(6,622,095)	(194,057)
Directors' Plan	(7,320)	(252)	(8,870)	(257)
Ending Balance, December 31	31,345,028	$1,432,019	19,276,445	$561,152

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

Equity Compensation Plan Information

Entergy grants stock options, equity awards, and incentive awards to key employees of the Entergy subsidiaries under the Equity Ownership Plan which is a shareholder-approved stock-based compensation plan. Stock options are granted at exercise prices not less than market value on the date of grant. The majority of options granted in 2004, 2003, and 2002 will become exercisable in equal amounts on each of the first three anniversaries of the date of grant. Unless they are forfeited previously under the terms of the grant, options expire ten years after the date of the grant if they are not exercised.

Entergy grants most of the equity awards and incentive awards earned under its stock benefit plans in the form of performance units, which are equal to the cash value of shares of Entergy Corporation common stock at the time of payment. In addition to the potential for equivalent share appreciation or depreciation, performance units will earn the cash equivalent of the dividends paid during the performance period applicable to each plan. The costs of equity and incentive awards, given either as company stock or performance units, are charged to income over the period of the grant or restricted period, as appropriate. In 2004, 2003, and 2002, $47 million, $45 million, and $28 million, respectively, was charged to compensation expense.

Entergy was assisted by external valuation firms to determine the fair value of the stock option grants made in 2004 and 2003. The fair value applied to these grants was an average of two firms' option valuations, which included adjustments for factors such as lack of marketability, stock retention requirements, and regulatory restrictions on exercisability. In 2002, the fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model, without any such adjustments. The stock option weighted-average assumptions used in determining the fair values were as follows:

	2004	2003	2002
Stock price volatility	23.1%	26.3%	27.2%
Expected term in years	6.3	6.2	5.0
Risk-free interest rate	3.2%	3.3%	4.2%
Dividend yield	3.3%	3.3%	3.2%
Dividend payment	$1.80	$1.40	$1.32

Stock option transactions are summarized as follows:

	2004		2003		2002
	Number of Options	Average Exercise Price	Number of Options	Average Exercise Price	Number of Options	Average Exercise Price
Beginning-of-year balance	15,429,383	$38.64	19,943,114	$35.85	17,316,816	$31.06
Options granted	1,898,098	$58.63	2,936,236	$44.98	8,168,025	$41.72
Options exercised	(4,541,053)	$38.07	(6,927,000)	$33.12	(4,877,688)	$28.62
Options forfeited/expired	(476,351)	$39.94	(522,967)	$40.98	(664,039)	$36.36
End-of-year balance	12,310,077	$41.88	15,429,383	$38.64	19,943,114	$35.85
Options exercisable at year-end	7,162,884	$37.25	6,153,043	$34.82	4,837,511	$31.39
Weighted-average fair value of options at time of grant	$7.76		$6.86		$9.22

The following table summarizes information about stock options outstanding as of December 31, 2004:

	Options Outstanding			Options Exercisable
Range of Exercise Prices	As of 12/31/2004	Weighted-Avg. Remaining Contractual Life-Yrs.	Weighted- Avg. Exercise Price	Number Exercisable at 12/31/2004	Weighted- Avg. Exercise Price
$23 - $33.99	1,674,430	5.0	$26.28	1,674,430	$26.28
$34 - $44.99	8,547,519	7.1	$41.09	5,195,493	$39.95
$45 - $55.99	230,445	5.6	$49.61	222,378	$49.68
$56 - $67.99	1,857,683	9.1	$58.64	70,583	$59.67
$23 - $67.99	12,310,077	7.1	$41.88	7,162,884	$37.25

Retained Earnings and Dividend Restrictions

Provisions within the Articles of Incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of certain of Entergy Corporation's subsidiaries restrict the payment of cash dividends or other distributions on their common and preferred stock. As of December 31, 2004, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively. Additionally, PUHCA prohibits Entergy Corporation's subsidiaries from making loans or advances to Entergy Corporation. In 2004, Entergy Corporation received dividend payments totaling $825 million from subsidiaries.

Investments in affiliates that are not controlled by Entergy Corporation, but over which it has significant influence, are accounted for using the equity method. Entergy's retained earnings for 2003 included $472 million of undistributed earnings of equity method investees. Due to the receipt of dividends from Entergy-Koch, LP after the sale of its energy trading and pipeline businesses in 2004, there were no undistributed earnings in Entergy's retained earnings at December 31, 2004. Equity method investments are discussed in Note 12 to the consolidated financial statements.

NOTE 8. COMMITMENTS AND CONTINGENCIES

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

Vidalia Purchased Power Agreement

Entergy Louisiana has an agreement extending through the year 2031 to purchase energy generated by a hydroelectric facility known as the Vidalia project. Entergy Louisiana made payments under the contract of approximately $147.7 million in 2004, $112.6 million in 2003, and $104.2 million in 2002. If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $125.3 million in 2005, and a total of $3.5 billion for the years 2006 through 2031. Entergy Louisiana currently recovers the costs of the purchased energy through its fuel adjustment clause. In an LPSC-approved settlement related to tax benefits from the tax treatment of the Vidalia contract, Entergy Louisiana agreed to credit rates by $11 million each year for up to ten years, beginning in October 2002. The provisions of the settlement also provide that the LPSC shall not recognize or use Entergy Louisiana's use of the cash benefits from the tax treatment in setting any of Entergy Louisiana's rates. Therefore, to the extent Entergy Louisiana's use of the proceeds would ordinarily have reduced its rate base, no change in rate base shall be reflected for ratemaking purposes.

Nuclear Insurance

Third Party Liability Insurance

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

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

Currently, 104 nuclear reactors are participating in the Secondary Financial Protection program - 103 operating reactors and one closed reactor that still stores used nuclear fuel on site. The product of the maximum retrospective premium assessment to the nuclear power industry and the number of nuclear power reactors provides over $10 billion in insurance coverage to compensate the public in the event of a nuclear power reactor accident.

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

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

Property Insurance

Entergy's nuclear owner/licensee subsidiaries are members of certain mutual insurance companies that provide property damage coverage, including decontamination and premature decommissioning expense, to the members' nuclear generating plants. These programs are underwritten by Nuclear Electric Insurance Limited (NEIL). As of December 31, 2004, Entergy was insured against such losses per the following structures:

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

• Primary Layer (per plant) - $500 million per occurrence
• Excess Layer (per plant) - $100 million per occurrence
• Blanket Layer (shared among all plants) - $1.0 billion per occurrence
• Total limit - $1.6 billion per occurrence
• Deductibles:

• $5.0 million per occurrence - Turbine/generator damage
• $5.0 million per occurrence - Other than turbine/generator damage

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

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

• Primary Layer (per plant) - $500 million per occurrence
• Blanket Layer (shared among all plants) - $615 million per occurrence
• Total limit - $1.115 billion per occurrence
• Deductibles:

• $1.0 million per occurrence - Turbine/generator damage
• $2.5 million per occurrence - Other than turbine/generator damage

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

In addition, the Non-Utility Nuclear plants are also covered under NEIL's Accidental Outage Coverage program. This coverage provides certain fixed indemnities in the event of an unplanned outage that results from a covered NEIL property damage loss, subject to a deductible. The following summarizes this coverage as of December 31, 2004:

Indian Point 2 and 3

• $4.5 million weekly indemnity
• $490 million maximum indemnity
• Deductible: 12 week waiting period

FitzPatrick and Pilgrim (each plant has an individual policy with the noted parameters)

• $4.0 million weekly indemnity
• $490 million maximum indemnity
• Deductible: 12 week waiting period

Vermont Yankee

• $3.5 million weekly indemnity
• $435 million maximum indemnity
• Deductible: 12 week waiting period

Entergy's U.S. Utility nuclear plants have significantly less or no accidental outage coverage. Under the property damage and accidental outage insurance programs, Entergy nuclear plants could be subject to assessments should losses exceed the accumulated funds available from NEIL. As of December 31, 2004, the maximum amounts of such possible assessments per occurrence were $50.8 million for the U.S. Utility plants and $68.9 million for the Non-Utility Nuclear plants.

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

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

Nuclear Decommissioning and Other Retirement Costs

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

These liabilities are recorded at their fair values (which is the present values of the estimated future cash outflows) in the period in which they are incurred, with an accompanying addition to the recorded cost of the long-lived asset. The asset retirement obligation is accreted each year through a charge to expense, to reflect the time value of money for this present value obligation. The amounts added to the carrying amounts of the long-lived assets will be depreciated over the useful lives of the assets. The net effect of implementing 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 principle that Entergy will recover all ultimate costs of decommissioning from customers.

Upon implementation of SFAS 143 in 2003, assets and liabilities increased $1.1 billion for the U.S. Utility segment as a result of recording the asset retirement obligations at their fair values of $1.1 billion as determined under SFAS 143, increasing utility plant by $287 million, reducing accumulated depreciation by $361 million, and recording the related regulatory assets of $422 million. The implementation of SFAS 143 for the portion of River Bend not subject to cost-based ratemaking decreased earnings by $21 million net-of-tax as a result of a one-time cumulative effect of accounting change. In accordance with ratemaking treatment and as required by SFAS 71, the depreciation provisions for the domestic utility companies and System Energy include a component for removal costs that are not asset retirement obligations under SFAS 143. In accordance with regulatory accounting principles, Entergy has recorded a regulatory asset for certain of its domestic utility companies and Syste m Energy of $86.9 million as of December 31, 2004 and $72.4 million as of December 31, 2003 to reflect an estimate of incurred but uncollected removal costs previously recorded as a component of accumulated depreciation. The decommissioning and retirement cost liability for certain of the domestic utility companies and System Energy includes a regulatory liability of $34.6 million as of December 31, 2004 and $26.8 million as of December 31, 2003 representing an estimate of collected but not yet incurred removal costs. For the Non-Utility Nuclear business, the implementation of SFAS 143 resulted in a decrease in liabilities of $595 million due to reductions in decommissioning liabilities, a decrease in assets of $340 million, including a decrease in electric plant in service of $315 million, and an increase in earnings in 2003 of $155 million net-of-tax as a result of a one-time cumulative effect of accounting change.

The cumulative decommissioning liabilities and expenses recorded in 2004 by Entergy were as follows:

	Liabilities as of December 31, 2003	Accretion	Change in Cash Flow Estimate	Spending	Liabilities as of December 31, 2004
	(In Millions)
U.S. Utility	$1,504.1	$98.0	($274.1)	-	$1,328.0
Non-Utility Nuclear	$710.4	$57.6	($20.3)	($9.4)	$738.3

In addition, an insignificant amount of removal costs associated with non-nuclear power plants are also included in the decommissioning line item on the balance sheet. Entergy periodically reviews and updates estimated decommissioning costs. The actual decommissioning costs may vary from the estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment. During 2004, Entergy updated decommissioning cost studies for ANO 1 and 2 and River Bend.

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

In the third quarter of 2004, Entergy Gulf States recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for River Bend that reflected an expected life extension for the plant. The revised estimate resulted in a $166.4 million reduction in decommissioning liability, along with a $31.3 million reduction in utility plant, a $49.6 million reduction in non-utility property, a $40.1 million reduction in the related regulatory asset, and a regulatory liability of $17.7 million. For the portion of River Bend not subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous other income of $27.7 million.

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

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

	Year Ended December 31, 2002
Earnings applicable to common stock - as reported	$599,360
Pro forma effect of SFAS 143	$14,119
Earnings applicable to common stock - pro forma	$613,479
Basic earnings per average common share - as reported	$2.69
Pro forma effect of SFAS 143	$0.06
Basic earnings per average common share - pro forma	$2.75
Diluted earnings per average common share - as reported	$2.64
Pro forma effect of SFAS 143	$0.06
Diluted earnings per average common share - pro forma	$2.70

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

Entergy maintains decommissioning trust funds that are committed to meeting the costs of decommissioning the nuclear power plants. The fair values of the decommissioning trust funds and asset retirement obligation-related regulatory assets of Entergy as of December 31, 2004 are as follows:

	Decommissioning Trust	Regulatory Asset
	(In Millions)
U.S. Utility	$1,052.0	$380.1
Non-Utility Nuclear	$1,401.6	-

The Energy Policy Act of 1992 contains a provision that assesses domestic nuclear utilities with fees for the decontamination and decommissioning (D&D) of the DOE's past uranium enrichment operations. Annual assessments in 2004 were $4.4 million for Entergy Arkansas, $1.1 million for Entergy Gulf States, $1.6 million for Entergy Louisiana, and $1.8 million for System Energy. The Energy Policy Act calls for cessation of annual D&D assessments not later than October 24, 2007. At December 31, 2004, two years of assessments were remaining. D&D fees are included in other current liabilities and other non-current liabilities and, as of December 31, 2004, recorded liabilities were $8.8 million for Entergy Arkansas, $1.9 million for Entergy Gulf States, $3.3 million for Entergy Louisiana, and $3.3 million for System Energy. Regulatory assets in the financial statements offset these liabilities, with the exception of Entergy Gulf States' 30% non-regulated portion. These assess ments are recovered through rates in the same manner as fuel costs.

Income Taxes

            Entergy is currently under audit by the IRS with respect to tax returns for tax periods subsequent to 1995 and through 2001, and is subject to audit by the IRS and other taxing authorities for subsequent tax periods.  The amount and timing of any tax assessments resulting from these audits are uncertain, and could have a material effect on Entergy's financial position and results of operations.  Entergy believes that the contingency provisions established in its financial statements will sufficiently cover the risk associated with tax matters. Certain material audit matters as to which management believes there is a reasonable possibility of a future tax assessment are discussed below. See Note 3 to the consolidated financial statements for additional discussion of income taxes.

Foreign Tax Credits

In July 1997, the UK government enacted the Windfall Tax, which was a one-time tax imposed on formerly government-owned companies in regulated industries. The Windfall Tax applied to companies that the government had previously privatized in the telecommunication, airport operation, gas, water, electricity, and railway industries. London Electricity, the UK public limited company purchased and subsequently sold by Entergy, was subject to the UK Windfall Tax.  Entergy fulfilled its obligation with respect to the tax in 1997 and 1998. In subsequent tax years, Entergy reported a foreign tax credit for the UK Windfall Tax that London Electricity paid. Entergy has claimed a net tax benefit of $152 million related to this foreign tax credit.

During 2004, the IRS proposed to disallow this foreign tax credit. Entergy disagreed with the position of the IRS and protested the disallowance of the credit to the Office of IRS Appeals. Entergy expects to receive a Notice of Deficiency in 2005 for this item, and plans to vigorously contest this matter. The amount at issue including tax and interest as of December 31, 2004 is $195 million. Entergy believes that the contingency provision established in its financial statements will sufficiently cover the risk associated with this dispute.

Depreciable Property Lives

During the years 1997 through 2004, Entergy subsidiaries, Entergy Services, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy Resources reflected changes in tax depreciation methods with respect to certain types of depreciable property (e.g. street lighting, billing meters, and various generation plant equipment). The cumulative effect of these changes results in additional depreciation deductions generating a cash flow benefit of approximately $152 million as of December 31, 2004. The related IRS interest exposure if the deduction is ultimately disallowed is $44 million at December 31, 2004. This benefit reverses over time and will also fluctuate with each year's addition to those types of assets. Due to the temporary nature of the tax benefit, the potential interest charge represents the total net earnings exposure of Entergy.

For the years under audit, 1996-2001, the IRS challenged Entergy's classification of these assets and proposed adjustments to the depreciation deductions taken. Entergy disagrees with the position of the IRS and has protested the disallowance of these deductions to the Office of IRS Appeals. Entergy expects to receive a Notice of Deficiency in 2005 for this item, and plans to vigorously contest this matter. Entergy believes that the contingency provision established in its financial statements sufficiently covers the risk associated with this item.

Mark to Market of Certain Power Contracts

In 2001, Entergy Louisiana changed its method of accounting for tax purposes related to its wholesale electric power contracts. The most significant of these is the contract to purchase power from the Vidalia hydroelectric project. The new tax accounting method has provided a cumulative cash flow benefit of approximately $790 million as of December 31, 2004. The related IRS interest exposure is $93 million at December 31, 2004. This benefit 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. Due to the temporary nature of the tax benefit, the potential interest charge represents Entergy's net earnings exposure. Entergy Louisiana's 2001 tax return is currently under examination by the IRS, though no adjustments have yet been proposed with respect to the mark to market election. Entergy believes that the contingency p rovision established in its financial statements will sufficiently cover the risk associated with this issue.

CashPoint Bankruptcy

In 2003 the domestic utility companies entered an agreement with CashPoint Network Services (CashPoint) under which CashPoint was to manage a network of payment agents through which Entergy's utility customers could pay their bills. The payment agent system allows customers to pay their bills at various commercial or governmental locations, rather than sending payments by mail. Approximately one-third of Entergy's utility customers use payment agents.

On April 19, 2004, CashPoint failed to pay funds due to the domestic utility companies that had been collected through payment agents. The domestic utility companies then obtained a temporary restraining order from the Civil District Court for the Parish of Orleans, State of Louisiana, enjoining CashPoint from distributing funds belonging to Entergy, except by paying those funds to Entergy. On April 22, 2004, a petition for involuntary Chapter 7 bankruptcy was filed against CashPoint by other creditors in the United States Bankruptcy Court for the Southern District of New York. In response to these events, the domestic utility companies expanded an existing contract with another company to manage all of their payment agents. The domestic utility companies filed proofs of claim in the CashPoint bankruptcy proceeding in September 2004. Although Entergy cannot precisely determine at this time the amount that CashPoint owes to the domestic utility companies that may not be repaid, it has accrued an estimate of loss based on current information. If no cash is repaid to the domestic utility companies, an event Entergy does not believe is likely, the current estimate of maximum exposure to loss is approximately $25 million.

Employment Litigation

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

NOTE 9. LEASES

General

As of December 31, 2004, Entergy had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities (excluding nuclear fuel leases and the Grand Gulf and Waterford 3 sale and leaseback transactions) with minimum lease payments as follows:

Year	Operating Leases	Capital Leases
	(In Thousands)
2005	$99,246	$9,660
2006	85,769	5,724
2007	68,557	3,438
2008	55,155	1,754
2009	45,240	237
Years thereafter	210,474	2,606
Minimum lease payments	564,441	23,419
Less: Amount representing interest	-	3,388
Present value of net minimum lease payments	$564,441	$20,031

Total rental expenses for all leases (excluding nuclear fuel leases and the Grand Gulf and Waterford 3 sale and leaseback transactions) amounted to $81.3 million in 2004, $84.3 million in 2003, and $92.2 million in 2002.

Nuclear Fuel Leases

As of December 31, 2004, arrangements to lease nuclear fuel existed in an aggregate amount up to $150 million for Entergy Arkansas, $105 million for Entergy Gulf States, $80 million for Entergy Louisiana, and $110 million for System Energy. As of December 31, 2004, the unrecovered cost base of nuclear fuel leases amounted to approximately $93.9 million for Entergy Arkansas, $71.2 million for Entergy Gulf States, $31.7 million for Entergy Louisiana, and $65.6 million for System Energy. The lessors finance the acquisition and ownership of nuclear fuel through loans made under revolving credit agreements, the issuance of commercial paper, and the issuance of intermediate-term notes. The credit agreements for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy each have a termination date of October 30, 2006. The termination dates may be extended from time to time with the consent of the lenders. The intermediate-term notes issued pursuant to these fuel lease a rrangements have varying maturities through February 15, 2009. It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. However, if such additional financing cannot be arranged, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations in accordance with the fuel lease.

Lease payments are based on nuclear fuel use. The total nuclear fuel lease payments (principal and interest) as well as the separate interest component charged to operations by the domestic utility companies and System Energy were $146.6 million (including interest of $12.8 million) in 2004, $142.0 million (including interest of $11.8 million) in 2003, and $137.8 million (including interest of $11.3 million) in 2002.

Sale and Leaseback Transactions

Waterford 3 Lease Obligations

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

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

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

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

As of December 31, 2004, Entergy Louisiana's total equity capital (including preferred stock) was 51.33% of adjusted capitalization and its fixed charge coverage ratio for 2004 was 3.76.

As of December 31, 2004 Entergy Louisiana had future minimum lease payments (reflecting an overall implicit rate of 7.45%) in connection with the Waterford 3 sale and leaseback transactions, which are recorded as long-term debt, as follows:

	(In Thousands)
2005	$14,554
2006	18,261
2007	18,754
2008	22,606
2009	32,452
Years thereafter	334,062
Total	440,689
Less: Amount representing interest	192,964
Present value of net minimum lease payments	$247,725

Grand Gulf Lease Obligations

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

In May 2004 System Energy caused the Grand Gulf lessors to refinance the outstanding bonds that they had issued to finance the purchase of their undivided interest in Grand Gulf. The refinancing is at a lower interest rate, and System Energy's lease payments have been reduced to reflect the lower interest costs.

System Energy is required to report the sale-leaseback as a financing transaction in its financial statements. For financial reporting purposes, System Energy expenses the interest portion of the lease obligation and the plant depreciation. However, operating revenues include the recovery of the lease payments because the transactions are accounted for as a sale and leaseback for ratemaking purposes. Consistent with a recommendation contained in a FERC audit report, System Energy recorded as a net regulatory asset the difference between the recovery of the lease payments and the amounts expensed for interest and depreciation and is recording this difference as a regulatory asset or liability on an ongoing basis, resulting in a zero net balance at the end of the lease term. The amount of this net regulatory asset was $75.4 million and $83.2 million as of December 31, 2004 and 2003, respectively.

As of December 31, 2004 System Energy had future minimum lease payments (reflecting an implicit rate of 5.01%), which are recorded as long-term debt as follows:

	(In Thousands)
2005	$45,423
2006	46,019
2007	46,552
2008	47,128
2009	47,760
Years thereafter	302,402
Total	535,284
Less: Amount representing interest	138,165
Present value of net minimum lease payments	$397,119

NOTE 10. RETIREMENT, OTHER POSTRETIREMENT BENEFITS, AND DEFINED CONTRIBUTION PLANS

Pension Plans

Entergy has seven pension plans covering substantially all of its employees: "Entergy Corporation Retirement Plan for Non-Bargaining Employees," "Entergy Corporation Retirement Plan for Bargaining Employees," "Entergy Corporation Retirement Plan II for Non-Bargaining Employees," "Entergy Corporation Retirement Plan II for Bargaining Employees," "Entergy Corporation Retirement Plan III," "Entergy Corporation Retirement Plan IV for Non-Bargaining Employees," and "Entergy Corporation Retirement Plan IV for Bargaining Employees." Except for the Entergy Corporation Retirement Plan III, the pension plans are noncontributory and provide pension benefits that are based on employees' credited service and compensation during the final years before retirement. The Entergy Corporation Retirement Plan III includes a mandatory employee contribution of 3% of earnings during the first 10 years of plan participation, and allows voluntary contributions from 1% to 10% of earnings for a limited grou p of employees. Entergy Corporation and its subsidiaries fund pension costs in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the plans include common and preferred stocks, fixed-income securities, interest in a money market fund, and insurance contracts. As of December 31, 2004 and 2003, Entergy recognized an additional minimum pension liability for the excess of the accumulated benefit obligation over the fair market value of plan assets. In accordance with SFAS 87, an offsetting intangible asset, up to the amount of any unrecognized prior service cost, was also recorded, with the remaining offset to the liability recorded as a regulatory asset reflective of the recovery mechanism for pension costs in Entergy's jurisdictions or to other comprehensive income for Entergy's non-regulated business. Entergy's domestic utility companies' and System Energy's pension costs are recovered from customers as a component of cost of service in each of its jurisdictions. Entergy uses a December 31 measurement date for its pension plans.

Components of Net Pension Cost

Total 2004, 2003, and 2002 pension costs of Entergy Corporation and its subsidiaries, including amounts capitalized, included the following components:

	2004	2003	2002
	(In Thousands)
Service cost - benefits earned during the period	$76,946	$70,337	$56,947
Interest cost on projected benefit obligation	148,092	134,403	128,387
Expected return on assets	(153,584)	(155,460)	(158,202)
Amortization of transition asset	(763)	(763)	(763)
Amortization of prior service cost	5,143	5,886	5,993
Recognized net loss	21,687	6,399	5,504
Curtailment loss	-	14,864	-
Special termination benefits	-	32,006	-
Net pension costs	$97,521	$107,672	$37,866

Pension Obligations, Plan Assets, Funded Status, Amounts Not Yet Recognized and Recognized in the Balance Sheet as of December 31, 2004 and 2003:

	December 31,
	2004	2003
	(In Thousands)
Change in Projected Benefit Obligation (PBO)
Balance at beginning of year	$2,349,565	$1,992,207
Service cost	76,946	70,337
Interest cost	148,092	134,403
Amendments	3,709	227
Actuarial loss	171,146	205,949
Benefits paid	(117,234)	(97,574)
Employee contributions	1,212	1,059
Curtailment loss	-	10,951
Special termination benefits	-	32,006
Balance at end of year	$2,633,436	$2,349,565
Change in Plan Assets
Fair value of assets at beginning of year	$1,744,975	$1,451,802
Actual return on plan assets	170,964	355,043
Employer contributions	72,825	34,645
Employee contributions	1,212	1,059
Benefits paid	(117,234)	(97,574)
Fair value of assets at end of year	$1,872,742	$1,744,975
Funded status	($760,694)	($604,590)
Amounts not yet recognized in the balance sheet
Unrecognized transition asset	(662)	(1,426)
Unrecognized prior service cost	29,053	30,467
Unrecognized net loss	542,391	410,321
Accrued pension cost recognized in the balance sheet	($189,912)	($165,228)
Amounts recognized in the balance sheet
Accrued pension cost	($189,912)	($165,228)
Additional minimum pension liability	(244,280)	(180,212)
Intangible asset	26,167	30,832
Accumulated other comprehensive income	10,781	15,359
Regulatory asset	207,332	13,021
Net amount recognized	($189,912)	($165,228)

Other Postretirement Benefits

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

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

Components of Net Postretirement Benefit Cost

Total 2004, 2003, and 2002 other postretirement benefit costs of Entergy Corporation and its subsidiaries, including amounts capitalized and deferred, included the following components:

	2004	2003	2002
	(In Thousands)
Service cost - benefits earned during the period	$30,947	$37,799	$29,199
Interest cost on APBO	53,801	52,746	44,819
Expected return on assets	(18,825)	(15,810)	(14,066)
Amortization of transition obligation	9,429	15,193	17,874
Amortization of prior service cost	(5,222)	(925)	992
Recognized net (gain)/loss	15,546	12,369	1,874
Curtailment loss	-	57,958	-
Special termination benefits	-	5,444	-
Net other postretirement benefit cost	$85,676	$164,774	$80,692

Other Postretirement Benefit Obligations, Plan Assets, Funded Status, and Amounts Not Yet Recognized and Recognized in the Balance Sheet as of December 31, 2004 and 2003:

	December 31,
	2004	2003
	(In Thousands)
Change in APBO
Balance at beginning of year	$941,803	$799,506
Service cost	30,947	37,799
Interest cost	53,801	52,746
Actuarial loss	73,890	115,966
Benefits paid	(66,456)	(48,379)
Plan Amendments (a)	(60,231)	(84,722)
Plan participant contributions	9,312	7,074
Curtailments	-	56,369
Special termination benefits	-	5,444
Balance at end of year	$983,066	$941,803
Change in Plan Assets
Fair value of assets at beginning of year	$227,446	$182,692
Actual return on plan assets	15,550	22,794
Employer contributions	63,399	63,265
Plan participant contributions	9,312	7,074
Benefits paid	(66,455)	(48,379)
Fair value of assets at end of year	$249,252	$227,446
Funded status	($733,814)	($714,357)
Amounts not yet recognized in the balance sheet
Unrecognized transition obligation	5,594	44,815
Unrecognized prior service cost	(39,560)	(20,746)
Unrecognized net loss	391,940	336,005
Accrued other postretirement benefit cost recognized in the balance sheet	($375,840)	($354,283)

(a) Reflects plan design changes, including a change in the participation assumption for the majority of non-bargaining employees effective August 1, 2003 and certain bargaining employees and additional non-bargaining employees effective January 1, 2004.

Pension and Other Postretirement Plans' Assets

Entergy's pension and postretirement plans weighted-average asset allocations by asset category at December 31, 2004 and 2003 are as follows:

	Pension		Postretirement
	2004	2003	2004	2003
Domestic Equity Securities	46%	56%	38%	37%
International Equity Securities	21%	14%	14%	0%
Fixed-Income Securities	31%	28%	47%	60%
Other	2%	2%	1%	3%

Entergy's trust asset investment strategy is to invest the assets in a manner whereby long-term earnings on the assets (plus cash contributions) provide adequate funding for retiree benefit payments. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense.

In the optimization study, Entergy formulates assumptions (or hires a consultant to provide such analysis) about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes. The future market assumptions used in the optimization study are determined by examining historical market characteristics of the various asset classes, and making adjustments to reflect future conditions expected to prevail over the study period.

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

	Pension	Postretirement
Domestic Equity Securities	45%	37%
International Equity Securities	20%	14%
Fixed-Income Securities	31%	49%
Other (Cash and GACs)	4%	0%

These allocation percentages combined with each asset class' expected investment return produced an aggregate return expectation for the five years following the study of 7.6% for pension assets, 5.4% for taxable postretirement assets, and 7.2% for non-taxable postretirement assets. These returns are not inconsistent with Entergy's disclosed expected pre-tax return on assets of 8.50% over the life of the respective liabilities.

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

	Pension	Postretirement
Domestic Equity Securities	45% to 55%	32% to 42%
International Equity Securities	15% to 25%	9% to 19%
Fixed-Income Securities	25% to 35%	44% to 54%
Other	0% to 10%	0% to 5%

Accumulated Pension Benefit Obligation

The accumulated benefit obligation for Entergy's pension plans was $2.3 billion and $2.1 billion at December 31, 2004 and 2003, respectively.

Estimated Future Benefit Payments

Based upon the assumptions used to measure the company's pension and postretirement benefit obligation at December 31, 2004, and including pension and postretirement benefits attributable to estimated future employee service, Entergy expects that benefits to be paid over the next ten years will be as follows:

	Estimated Future Benefits Payments
	Pension	Postretirement
	(In Thousands)
Year(s)
2005	$115,203	$60,932
2006	$116,894	$59,761
2007	$119,092	$62,392
2008	$122,728	$64,381
2009	$127,877	$66,444
2010 - 2014	$780,295	$360,191

Contributions

Entergy expects to contribute $185.9 million (excluding about $1.2 million in employee contributions) to its pension plans and $63.3 million to other postretirement plans in 2005.

Additional Information

The change in the minimum pension liability included in other comprehensive income and regulatory assets was as follows for 2004 and 2003:

	2004	2003
	(In Thousands)
Increase/(decrease) in the minimum pension liability included in:
Other comprehensive income	($4,578)	($1,639)
Regulatory assets	$73,311	($23,768)

Actuarial Assumptions

The assumed health care cost trend rate used in measuring the APBO of Entergy was 10% for 2005, gradually decreasing each successive year until it reaches 4.5% in 2011 and beyond. The assumed health care cost trend rate used in measuring the Net Other Postretirement Benefit Cost of Entergy was 10% for 2004, gradually decreasing each successive year until it reaches 4.5% in 2010 and beyond. A one percentage point change in the assumed health care cost trend rate for 2004 would have the following effects:

	1 Percentage Point Increase		1 Percentage Point Decrease
2004	Impact on the APBO	Impact on the sum of service costs and interest cost	Impact on the APBO	Impact on the sum of service costs and interest cost
	Increase (Decrease) (In Thousands)
Entergy Corporation	$99,271	$11,587	($89,801)	($10,061)

The significant actuarial assumptions used in determining the pension PBO and the SFAS 106 APBO for 2004, 2003, and 2002 were as follows:

	2004	2003	2002
Weighted-average discount rate:
Pension	6.00%	6.25%	6.75%
Other postretirement	6.00%	6.71%	6.75%
Weighted-average rate of increase  in future compensation levels	3.25%	3.25%	3.25%
Expected long-term rate of  return on plan assets:
Taxable assets	5.50%	5.50%	5.50%
Non-taxable assets	8.50%	8.75%	8.75%

The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2004, 2003, and 2002 were as follows:

.	2004	2003	2002
Weighted-average discount rate
Pension	6.25%	6.75%	7.50%
Other postretirement	6.71%	6.75%	7.50%
Weighted-average rate of increase  in future compensation levels	3.25%	3.25%	4.60%
Expected long-term rate of  return on plan assets:
Taxable assets	5.50%	5.50%	5.50%
Non-taxable assets	8.75%	8.75%	9.00%

Entergy's remaining pension transition assets are being amortized over the greater of the remaining service period of active participants or 15 years ending in 2005, and its SFAS 106 transition obligations are being amortized over 20 years ending in 2012.

Voluntary Severance Program

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

Medicare Prescription Drug, Improvement and Modernization Act of 2003

In December 2003, the President signed the Medicare Prescription Drug, Improvement and Modernization Act of 2003 into law. The Act introduces a prescription drug benefit cost under Medicare (Part D), starting in 2006, as well as federal subsidy to employers who provide a retiree prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

At December 2003, specific authoritative guidance on the accounting for the federal subsidy was pending. As allowed by Financial Accounting Standards Board Staff Position No. FAS 106-1, Entergy elected to record an estimate of the effects of the Act in accounting for its postretirement benefit plans at December 31, 2003, under SFAS 106 and in providing disclosures required by SFAS No. 132 (revised 2003), Employers' Disclosures about Pensions and Other Postretirement Benefits. At December 31, 2003, based on actuarial analysis of prescription drug benefits, estimated future Medicare subsidies were expected to reduce the December 31, 2003 Accumulated Postretirement Benefit Obligation by $56 million. For the year ended December 31, 2003, the impact of the Act on net postretirement benefit cost was immaterial, as it reflected only one month's impact of the Act.

In 2004, Entergy continued to record an estimate of the effects the Act in accounting for its postretirement benefit plans. In mid-2004, the Financial Accounting Standards Board issued Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which was effective for Entergy's June 30, 2004 interim reporting.

In August 2004, the Centers for Medicare and Medicaid Services issued proposed regulations to implement the new Medicare law. A ruling from the Centers for Medicare and Medicaid Services was issued in late January 2005 with final guidance expected later this year.

The actuarially estimated effect of future Medicare subsidies reduced the December 31, 2003 and 2004 Accumulated Postretirement Benefit Obligation by $128 million and $161 million, respectively, and reduced the 2004 other postretirement benefit cost by $23.3 million.

Defined Contribution Plans

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

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

Effective February 1, 2004, the employing Entergy subsidiary began making matching contributions for non-bargaining employees to the System Savings Plan in an amount equal to 70% of the participants' basic contributions, up to 6% of their eligible earnings. The 70% match is allocated to investments as directed by the employee.

Entergy also sponsors the Savings Plan of Entergy Corporation and Subsidiaries II (established in 2001), the Savings Plan of Entergy Corporation and Subsidiaries III (established in 2002), and the Savings Plan of Entergy Corporation and Subsidiaries V (established in 2002). The plans are defined contribution plans that cover eligible employees, as defined by each plan, of Entergy and its subsidiaries. The employing Entergy subsidiary makes matching contributions equal to 50% of the participants' participating contributions for each of these plans. Effective September 30, 2004, employees participating in the Savings Plan of Entergy Corporation and Subsidiaries III (Savings Plan III) were transferred into the System Savings Plan and Savings Plan III was terminated.

Entergy's subsidiaries' contributions to defined contribution plans collectively were $32.9 million in 2004, $31.5 million in 2003, and $29.6 million in 2002. The majority of the contributions were to the System Savings Plan.

NOTE 11. BUSINESS SEGMENT INFORMATION

Entergy's reportable segments as of December 31, 2004 are U.S. Utility, Non-Utility Nuclear, and Energy Commodity Services. U.S. Utility generates, transmits, distributes, and sells electric power in portions of Arkansas, Louisiana, Mississippi, and Texas, and provides natural gas utility service in portions of Louisiana. Non-Utility Nuclear owns and operates five nuclear power plants and is primarily focused on selling electric power produced by those plants to wholesale customers. Energy Commodity Services includes Entergy-Koch, LP and Entergy's non-nuclear wholesale assets business. Entergy-Koch engaged in two major businesses: energy commodity marketing and trading through Entergy-Koch Trading, and gas transportation and storage through Gulf South Pipeline. Entergy-Koch sold both of these businesses in the fourth quarter of 2004, and Entergy-Koch is no longer an operating entity. The non-nuclear wholesale assets business sells to wholesale customers the electric power produce d by power plants that it owns while it focuses on improving performance and exploring sales or restructuring opportunities for its power plants. Such opportunities are evaluated consistent with Entergy's market-based point-of-view. Results from Entergy-Koch are reported as equity in earnings of unconsolidated equity affiliates in the financial statements. Entergy's operating segments are strategic business units managed separately due to their different operating and regulatory environments. Entergy's chief operating decision maker is its Office of the Chief Executive, which consists of its highest-ranking officers.

"All Other" includes the parent company, Entergy Corporation, other business activity, including the Competitive Retail Services business, which has higher revenues in 2004 as its number of customers has increased, and earnings on the proceeds of sales of previously-owned businesses.

Entergy's segment financial information is as follows:

2004	U. S. Utility	Non-Utility Nuclear*	Energy Commodity Services *	All Other*	Eliminations	Consolidated
	(In Thousands)
Operating revenues	$8,142,808	$1,341,852	$216,450	$486,804	($64,190)	$10,123,724
Deprec., amort. & decomm.	$915,667	$106,408	$16,311	$6,736	$-	$1,045,122
Interest income	$40,831	$63,569	$17,875	$42,729	($55,195)	$109,809
Equity in loss of unconsolidated equity affiliates	$-	$-	($78,727)	$-	$-	($78,727)
Interest charges	$383,032	$53,657	$15,560	$81,916	($55,142)	$479,023
Income taxes (credits)	$406,864	$142,620	($155,840)	($27,736)	$-	$365,908
Net income	$666,691	$245,029	$3,778	$17,606	($55)	$933,049
Total assets	$22,937,237	$4,531,604	$2,223,961	$199,233	($1,581,258)	$28,310,777
Investment in affiliates - at equity	$207	$-	$512,571	$-	($280,999)	$231,779
Cash paid for long-lived asset additions	$1,152,167	$242,822	$2,022	$13,604	($5)	$1,410,610

2003	U. S. Utility	Non-Utility Nuclear*	Energy Commodity Services *	All Other*	Eliminations	Consolidated
	(In Thousands)
Operating revenues	$7,584,857	$1,274,983	$184,888	$188,228	($38,036)	$9,194,920
Deprec., amort. & decomm.	$890,092	$87,825	$13,681	$5,005	$-	$996,603
Interest income	$43,035	$36,874	$18,128	$27,575	($38,226)	$87,386
Equity in earnings (loss) of unconsolidated equity affiliates	($3)	$-	$271,650	$-	$-	$271,647
Interest charges	$419,111	$34,460	$15,193	$75,787	($38,225)	$506,326
Income taxes (credits)	$341,044	$88,619	$105,903	($45,492)	$-	$490,074
Cumulative effect of accounting change	($21,333)	$154,512	$3,895	$-	$-	$137,074
Net income (loss)	$492,574	$300,799	$180,454	($23,360)	$-	$950,467
Total assets	$22,402,314	$4,171,777	$2,076,921	$1,495,903	($1,619,527)	$28,527,388
Investment in affiliates - at equity	$211	$-	$1,081,462	$-	($28,345)	$1,053,328
Cash paid for long-lived asset additions	$1,233,208	$281,377	$44,284	$10,074	$-	$1,568,943

2002	U. S. Utility	Non-Utility Nuclear*	Energy Commodity Services *	All Other*	Eliminations	Consolidated
	(In Thousands)
Operating revenues	$6,773,509	$1,200,238	$294,670	$40,729	($4,111)	$8,305,035
Deprec., amort. & decomm.	$800,257	$88,733	$21,465	$5,143	$-	$915,598
Interest income	$23,231	$71,262	$26,140	$35,433	($37,741)	$118,325
Equity in earnings (loss) of unconsolidated equity affiliates	($2)	$-	$183,880	$-	$-	$183,878
Interest charges	$465,703	$47,291	$61,632	$35,579	($37,741)	$572,464
Income taxes (credits)	$313,752	$132,726	($141,288)	($11,252)	$-	$293,938
Net income (loss)	$606,963	$200,505	($145,830)	($38,566)	$-	$623,072
Total assets	$21,630,523	$4,482,308	$2,167,472	$1,327,354	($2,103,291)	$27,504,366
Investment in affiliates - at equity	$214	$-	$823,995	$-	$-	$824,209
Cash paid for long-lived asset additions	$1,131,734	$169,756	$210,297	$18,514	$-	$1,530,301

Businesses marked with * are referred to as the "competitive businesses," with the exception of the parent company, Entergy Corporation, which is included in "All Other." Eliminations are primarily intersegment activity. Substantially all of Entergy's recorded asset for goodwill is in its U.S. Utility segment.

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

Energy Commodity Services' net loss for the year ended December 31, 2002 includes net charges of $428.5 million to operating expenses ($238.3 million net-of-tax). These charges reflect the effect of Entergy's decision to discontinue additional greenfield power plant development and the asset impairments resulting from the deteriorating economics of wholesale power markets in the United States and the United Kingdom. The net charges consist of the following:

• The power development business obtained contracts in October 1999 to acquire 36 turbines from General Electric. Entergy's rights and obligations under the contracts for 22 of the turbines were sold to an independent special-purpose entity in May 2001. $178.0 million of the charges, including an offsetting benefit of $28.5 million ($18.5 million net-of-tax) related to the sale of four turbines to a third party, is a provision for the net costs resulting from cancellation or sale of the turbines subject to purchase commitments with the special-purpose entity.
• $204.4 million of the charges result from the write-off of Entergy Power Development Corporation's equity investment in the Damhead Creek project and the impairment of the values of the Warren Power power plant, the Crete project, and the RS Cogen project. This portion of the charges reflects Entergy's estimate of the effects of reduced spark spreads in the United States and the United Kingdom. These estimates are based on various sources of information, including discounted cash flow projections and current market prices.
• $39.1 million of the charges relate to the restructuring of the non-nuclear wholesale assets business, including impairments of administrative fixed assets, estimated sublease losses, and employee-related costs for approximately 135 affected employees. These restructuring costs, which are included in the "Provision for turbine commitments, asset impairments, and restructuring charges" in the accompanying consolidated statement of income, were comprised of the following:

	Restructuring Costs	Paid in Cash through December 2004	Non-Cash Portion	Remaining Accrual as of December 31, 2004
		(In Millions)
Fixed asset impairments	$22.5	$-	$22.5	$-
Sublease losses	10.7	5.6	-	5.1
Severance and related costs	5.9	5.9	-	-
Total	$39.1	$11.5	$22.5	$5.1

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

Geographic Areas

For the years ended December 31, 2004 and 2003, Entergy derived less than 1% of its revenue from outside of the United States. For the year ended December 31, 2002 Entergy derived 3% of its revenue from outside of the United States.

As of December 31, 2004 and 2003 Entergy had almost no long-lived assets located outside of the United States.

NOTE 12. EQUITY METHOD INVESTMENTS

As of December 31, 2004, Entergy owns investments in the following companies that it accounts for under the equity method of accounting:

Company	Ownership	Description
Entergy-Koch, LP	50% partnership interest	Engaged in two major businesses: energy commodity marketing and trading through Entergy-Koch Trading, and gas transportation and storage through Gulf South Pipeline. Entergy-Koch sold both of these businesses in the fourth quarter of 2004, and Entergy-Koch is no longer an operating entity.
RS Cogen LLC	50% member interest	Co-generation project that produces power and steam on an industrial and merchant basis in the Lake Charles, Louisiana area.
Top Deer	50% member interest	Wind-powered electric generation joint venture.

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

	2004	2003	2002
	(In Thousands)
Beginning of year	$1,053,328	$824,209	$766,103
Additional investments	157,020	4,668	36,372
Income (loss) from the investments	(78,727)	271,647	183,878
Other income	6,232	45,583	21,462
Distributions received	(888,260)	(105,142)	(73,902)
Dispositions and other adjustments	(17,814)	12,363	(109,704)
End of year	$231,779	$1,053,328	$824,209

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

	2004	2003	2002
	(In Thousands)
Income Statement Items
Operating revenues	$270,177	$585,404	$551,853
Operating income	($111,535)	$207,301	$159,342
Net income	$739,858 (1)	$172,595	$68,095
Balance Sheet Items
Current assets	$540,386	$2,576,630
Noncurrent assets	$418,038	$1,675,334
Current liabilities	$180,009	$1,757,663
Noncurrent liabilities	$463,899	$1,166,540

(1) Includes gains recorded by Entergy-Koch on the sales of its energy trading and pipeline businesses.

Related-party transactions and guarantees

During 2004, 2003, and 2002, Entergy procured various services from Entergy-Koch consisting primarily of pipeline transportation services for natural gas and risk management services for electricity and natural gas. The total cost of such services in 2004, 2003, and 2002 was approximately $9.5 million, $15.9 million, and $11.2 million, respectively. In 2003, Entergy Louisiana and Entergy New Orleans entered purchase power agreements with RS Cogen, and purchased a total of $26.0 million of capacity and energy from RS Cogen in 2003. In 2004, Entergy Louisiana and Entergy New Orleans purchased a total of $43.6 million of capacity and energy from RS Cogen. Entergy's operating transactions with its other equity method investees were not material in 2004, 2003, or 2002.

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

During the fourth quarter of 2004, an Entergy subsidiary purchased from a commercial bank holder $16.3 million of RS Cogen subordinated indebtedness, due October 2017, bearing interest at LIBOR plus 4.50%.  The debt was purchased at a discount of approximately $2.4 million that will be amortized over the remaining life of the debt.

NOTE 13. ACQUISITIONS AND DISPOSITIONS

Asset Acquisitions

Vermont Yankee

In July 2002, Entergy's Non-Utility Nuclear business purchased the 510 MW Vermont Yankee nuclear power plant located in Vernon, Vermont, from Vermont Yankee Nuclear Power Corporation for $180 million. Entergy received the plant, nuclear fuel, inventories, and related real estate. The liability to decommission the plant, as well as related decommissioning trust funds of approximately $310 million, was also transferred to Entergy. The acquisition included a 10-year power purchase agreement (PPA) under which the former owners will buy the power produced by the plant, which is through the expiration of the current operating license for the plant. The PPA includes an adjustment clause which provides that the prices specified in the PPA will be adjusted downward annually, beginning in December 2005, if power market prices drop below the PPA prices.

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

Asset Dispositions

Entergy-Koch Businesses

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

Other

In January 2004, Entergy sold its 50% interest in the Crete project, which is a 320MW power plant located in Illinois, and realized an insignificant gain on the sale.

In the fourth quarter of 2004, Entergy sold undivided interests in the Warren Power and the Harrison County plants at a price that approximated book value.

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

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

NOTE 14. RISK MANAGEMENT AND FAIR VALUES

Market and Commodity Risks

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

Type of Risk	Primary Affected Segments
Power price risk	All reportable segments
Fuel price risk	All reportable segments
Foreign currency exchange rate risk	All reportable segments
Equity price and interest rate risk - investments	U.S. Utility, Non-Utility Nuclear

Entergy manages these risks through both contractual arrangements and derivatives. Contractual risk management tools include long-term power and fuel purchase agreements, capacity contracts, and tolling agreements. Entergy also uses a variety of commodity and financial derivatives, including natural gas and electricity futures, forwards, swaps, and options; foreign currency forwards; and interest rate swaps as a part of its overall risk management strategy. Except for the energy trading activities conducted through December 2004 by Entergy-Koch, Entergy enters into derivatives only to manage natural risks inherent in its physical or financial assets or liabilities.

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

Hedging Derivatives

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

Instrument	Business Segment
Natural gas and electricity futures and forwards	Non-Utility Nuclear, Energy Commodity Services, Competitive Retail Services
Foreign currency forwards	U.S. Utility, Non-Utility Nuclear

Cash flow hedges with net unrealized losses of approximately $99 million at December 31, 2004 are scheduled to mature during 2005. Net losses totaling approximately $13 million were realized during 2004 on the maturity of cash flow hedges. Unrealized gains or losses result from hedging power output at the Non-Utility Nuclear power stations and foreign currency hedges related to Euro-denominated nuclear fuel acquisitions. The related gains or losses from hedging power are included in revenues when realized. The realized gains or losses from foreign currency transactions are included in the cost of capitalized fuel. The maximum length of time over which Entergy is currently hedging the variability in future cash flows for forecasted transactions at December 31, 2004 is approximately four years. The ineffective portion of the change in the value of Entergy's cash flow hedges during 2004 was insignificant.

Fair Values

Financial Instruments

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

Entergy considers the carrying amounts of most of its financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. Additional information regarding financial instruments and their fair values is included in Notes 5 and 6 to the consolidated financial statements.

NOTE 15. DECOMMISSIONING TRUST FUNDS

Entergy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held at December 31, 2004 and 2003 are summarized as follows:

2004	Fair Value	Total Unrealized Gains	Total Unrealized Losses
	(In Millions)
Equity	$995	$166	$17
Debt Securities	1,457	33	6
Total	$2,452	$199	$23
2003
Equity	$896	$81	$11
Debt Securities	1,383	27	3
Total	$2,279	$108	$14

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows at December 31, 2004:

	Equity Securities		Debt Securities
	Fair Value	Gross Unrealized Losses	Fair Value	Gross Unrealized Losses
	(In Millions)
Less than 12 months	$29	$2	$334	$5
More than 12 months	115	15	37	1
Total	$144	$17	$371	$6

Entergy evaluates these unrealized gains and losses at the end of each period to determine whether an other than temporary impairment has occurred. This analysis considers the length of time that a security has been in a loss position, the current performance of that security, and whether decommissioning costs are recovered in rates. Due to the regulatory treatment of decommissioning collections and trust fund earnings, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, System Energy record regulatory assets or liabilities for unrealized gains and losses on trust investments. For the unregulated portion of River Bend, Entergy Gulf States has recorded an offsetting amount of unrealized gains or losses in other deferred credits. No significant impairments were recorded in 2004 and 2003 as a result of these evaluations.

The fair value of debt securities, summarized by contractual maturities, at December 31, 2004 is as follows:

	Fair Value
	(In Millions)
less than 1 year	$134
1 year - 5 years	592
5 years - 10 years	425
10 years - 15 years	158
15 years - 20 years	60
20 years+	88
Total	$1,457

During the year ended December 31, 2004, the proceeds from the dispositions of securities amounted to $37 million with gross gains of $0.7 million and gross losses of $0.7 million, which were reclassified out of other comprehensive income into earnings during the period.

NOTE 16. QUARTERLY FINANCIAL DATA (UNAUDITED)

Operating results for the four quarters of 2004 and 2003 were:

	Operating Revenues	Operating Income	Net Income (Loss)
	(In Thousands)
2004:
First Quarter	$2,251,549	$378,834	$213,016
Second Quarter	$2,485,097	$494,312	$271,011
Third Quarter	$2,963,581	$571,472	$288,047
Fourth Quarter	$2,423,497	$208,946	$160,975
2003:
First Quarter	$2,037,723	$363,403	$400,923(a)
Second Quarter	$2,353,909	$461,576	$211,517
Third Quarter	$2,700,125	$619,005	$371,650
Fourth Quarter	$2,103,163	$40,571	($33,623)

(a) Net income before the cumulative effect of accounting changes for the first quarter 2003 was $258,001.

Earnings per Average Common Share

	2004		2003
	Basic	Diluted	Basic	Diluted
First Quarter	$0.90	$0.88	$1.77(b)	$1.73(b)
Second Quarter	$1.16	$1.14	$0.91	$0.89
Third Quarter	$1.24	$1.22	$1.60	$1.57
Fourth Quarter	$0.71	$0.69	($0.19)	($0.18)

(b) Basic and diluted earnings per average common share before the cumulative effect of accounting changes for the first quarter of 2003 were $1.13 and $1.10, respectively.

ENTERGY'S BUSINESS (continued)

U.S. Utility

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

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

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

Customers

As of December 31, 2004, Entergy's domestic utility companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:

		Electric Customers		Gas Customers
	Area Served	(In Thousands)	(%)	(In Thousands)	(%)
Entergy Arkansas	Portions of Arkansas	667	25%
Entergy Gulf States	Portions of Texas and Louisiana	724	27%	91	39%
Entergy Louisiana	Portions of Louisiana	662	25%
Entergy Mississippi	Portions of Mississippi	420	16%
Entergy New Orleans	City of New Orleans*	189	7%	145	61%
Total customers		2,662	100%	236	100%

* Excludes the Algiers area of the city, where Entergy Louisiana provides electric service.

Electric Energy Sales

The electric energy sales of Entergy's domestic utility companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On July 15, Entergy reached a 2004 peak demand of 21,174 MW, compared to the 2003 peak of 20,162 MW recorded on August 19 of that year. Selected electric energy sales data is shown in the table below:

Selected 2004 Electric Energy Sales Data

	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy	Entergy (a)
	(In GWh)
Sales to retail   customers	19,735	35,275	28,183	12,978	6,055	- -	102,226
Sales for resale:
Affiliates	7,437	1,528	1,129	305	1,514	9,212	-
Others	4,911	3,172	122	393	25	-	8,623
Total	32,083	39,975	29,434	13,676	7,594	9,212	110,849
Average use per residential customer (kWh)	12,485	15,620	15,359	14,475	12,618	- -	14,384

(a) Includes the effect of intercompany eliminations.

The following table illustrates the domestic utility companies' 2004 combined electric sales volume as a percentage of total electric sales volume, and 2004 combined electric revenues as a percentage of total 2004 electric revenue, each by customer class.

Customer Class	% of Sales Volume	% of Revenue
Residential	29.7	35.2
Commercial	23.9	25.3
Industrial (a)	36.3	28.6
Wholesale	7.8	8.3
Governmental	2.3	2.6

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

See "Selected Financial Data" for each of the domestic utility companies for the detail of their sales by customer class for 2002, 2003, and 2004.

Selected 2004 Natural Gas Sales Data

Entergy New Orleans and Entergy Gulf States provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Gulf States sold 14,803,852 and 6,868,935 Mcf, respectively, of natural gas to retail customers in 2004. In 2004, 98% of Entergy Gulf States' operating revenue was derived from the electric utility business, and only 2% from the natural gas distribution business. For Entergy New Orleans, 80% of operating revenue was derived from the electric utility business and 20% from the natural gas distribution business in 2004. Following is data concerning Entergy New Orleans' 2004 retail operating revenue sources.

	Electric Operating	Natural Gas
Entergy New Orleans	Revenue	Revenue
Residential	40%	50%
Commercial	37%	22%
Industrial	8%	13%
Governmental/Municipal	15%	15%

Retail Rate Regulation

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

The retail regulatory philosophy has shifted in some jurisdictions from traditional, cost-of-service regulation to include performance-based rate elements. Performance-based rate plans are designed to encourage efficiencies and productivity while permitting utilities and their customers to share in the benefits. Entergy Mississippi, Entergy Louisiana, and Entergy New Orleans have implemented performance-based formula rate plans, but Entergy Louisiana's performance-based formula rate plan expired in 2001. As explained below, performance-based formula rate plans currently are under consideration for Entergy Louisiana and for the Louisiana jurisdiction of Entergy Gulf States. Following is a summary of the status of retail open access in the domestic utility companies' retail service territories.

Jurisdiction	Status of Retail Open Access	% of Entergy's 2004 Revenues Derived from Retail Electric Utility Operations in the Jurisdiction
Arkansas	Retail open access was repealed in February 2003.	11.6%
Texas	In July 2004, the PUCT effectively rejected Entergy Gulf States' proposal to implement retail open access in its service territory. In February 2005, bills were submitted in the Texas Legislature that specify that retail open access will not commence in Entergy Gulf States' territory until the PUCT certifies a power region.	11.8%
Louisiana	The LPSC has deferred pursuing retail open access, pending developments at the federal level and in other states. In response to a study submitted to the LPSC that was funded by a group of large industrial customers, the LPSC recently has solicited comments regarding a limited retail access program. It is uncertain what action, if any, the LPSC might take in response to the information it received.	34.1%
Mississippi	The MPSC has recommended not pursuing open access at this time.	10.9%
New Orleans	The Council has taken no action on Entergy New Orleans' proposal filed in 1997.	4.5%

Retail Rate Proceedings

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

Company	Authorized ROE	Pending Proceedings/Events
Entergy Arkansas	11.0%	No base rate cases are pending. Transition cost recovery rider approved to collect $8.5 million effective October 2004 with recovery expected over subsequent 16 months. It is likely that a rate filing will be made in 2005 in connection with the ANO 1 steam generator and reactor vessel head replacement.
Entergy Gulf States    Texas	10.95%	Base rates are currently set at rates approved by the PUCT in June 1999. Entergy Gulf States filed a retail electric rate case with the PUCT in August 2004. In October 2004, the PUCT issued a written order in which it dismissed the rate case indicating that Entergy Gulf States is still subject to a rate freeze based on an agreement, approved by PUCT order in 2001, stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory, unless lifted by the PUCT prior thereto. Entergy Gulf States has appealed this decision and intends to pursue other available remedies, including legislation that would clarify that it is no longer operating under a rate freeze. In February 2005, bills were filed in the Texas legislature that would clarify that Entergy Gulf States is no longer operating under a rate freeze and specify that retail open access will not commence in Entergy Gulf States' territory until the PUCT certifies a power region.
Entergy Gulf States    Louisiana	11.1%	In December 2003, the LPSC staff recommended a $30.6 million rate refund and a prospective rate reduction of approximately $50 million as a result of the ninth post-merger earnings analysis (2002). Hearings concluded in May 2004. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement that would resolve, among other dockets, Entergy Gulf States' ninth post-merger review, and dockets established to consider issues concerning the companies' power purchases for the summers of 2001, 2002, 2003, and 2004. The proposed settlement currently includes an offer to refund $76 million to Entergy Gulf States' Louisiana customers through a credit on bills rendered in March 2005, with no immediate change in the current base rates. The settlement also proposes a formula rate plan with an ROE mid-point of 10.65%. The LPSC has solicited comments on the proposed settlement from the parties to the various proceedings at issue in the settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005.
Entergy Louisiana	9.7%- 11.3%(1)	In January 2004, Entergy Louisiana filed with the LPSC an application for a $167 million base rate increase and an ROE of 11.4%. The currently authorized ROE midpoint is 10.5%. Hearings in this matter concluded in December 2004. Based on the evidence submitted at the hearing, the LPSC staff is recommending approximately a $7 million base rate increase. The LPSC staff proposed the implementation of a formula rate plan that includes a provision for the recovery of incremental capacity costs, including those related to the proposed Perryville acquisition. A decision by the LPSC is expected in mid- to late-March 2005 on these issues. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement with the LPSC that would resolve, among other dockets, dockets established to consider issues concerning the companies' power purchases for the summers of 2001, 2002, 2003, and 2004. The proposed settlement currently includes an offer to refund $14 million to Entergy Louisiana's customers. The LPSC has solicited comments on the proposed settlement from the parties to the various proceedings at issue in the proposed settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005.
Entergy Mississippi	9.3%- 12.2%(2)	An annual formula rate plan is in place. Entergy Mississippi made its annual formula rate plan filing in March 2004 based on a 2003 test year. There was no change in rates based on an adjusted ROE midpoint of 10.77%.
Entergy New Orleans	10.25%- 12.25%(3)	The midpoint ROE of the electric and gas plans is 11.25%, with a target equity component of the capital structure of 42%. Entergy New Orleans made a formula rate plan filing in April 2004. The City Council ordered that electric and gas rates remain unchanged from levels set in 2003. Entergy New Orleans will file its formula rate plan for the year ended December 31, 2004 by May 1, 2005 and also intends to file for an extension of the formula rate plan by September 1, 2005. If the formula rate plan is not extended by the City Council, the rate adjustments in effect based on the December 31, 2004 test year shall continue.
System Energy	10.94%	ROE approved by July 2001 FERC order. No cases pending before FERC.

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

Entergy Arkansas

Fuel Recovery

Entergy Arkansas' rate schedules include an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. Entergy Arkansas' 2004 filing is discussed in Note 2 to the domestic utility companies and System Energy financial statements.

Entergy Gulf States

Louisiana Jurisdiction - Formula Rate Plan

In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement with the LPSC. Included in the settlement is a proposal of a three-year formula rate plan for Entergy Gulf States' Louisiana operations that included a provision for the recovery of incremental capacity costs. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005.

Fuel Recovery

Entergy Gulf States' Texas rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including carrying charges, not recovered in base rates. Under the current methodology, semi-annual revisions of the fixed fuel factor may be made in March and September based on the market price of natural gas. Entergy Gulf States will likely continue to use this methodology until retail open access begins in Texas. To the extent actual costs vary from the fixed fuel factor, refunds or surcharges are required or permitted. The amounts collected under the fixed fuel factor through the start of retail open access are subject to fuel reconciliation proceedings before the PUCT. At the start of retail open access for Entergy Gulf States in Texas, which is currently delayed, fuel and purchased power cost recovery will be subject to the fuel component of the price-to-beat rates approved by the PUCT. The PUCT fuel cost reviews that were resolved during the past year or are cur rently pending are discussed in Note 2 to the domestic utility companies and System Energy financial statements.

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

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

Entergy Louisiana

Formula Rate Plan

The LPSC staff has proposed the implementation of a formula rate plan for Entergy Louisiana that includes a provision for the recovery of incremental capacity costs. A decision from the LPSC is expected in mid- to late-March 2005.

Fuel Recovery

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

In September 2002, Entergy Louisiana settled a proceeding that concerned a contract entered into by Entergy Louisiana to purchase, through 2031, energy generated by a hydroelectric facility known as the Vidalia project. In the settlement, the LPSC approved Entergy Louisiana's proposed treatment of the regulatory impact of a tax accounting election related to that project. In general, the settlement permits Entergy Louisiana to keep a portion of the tax benefit in exchange for bearing the risk associated with sustaining the tax treatment. The LPSC settlement divided the term of the Vidalia contract into two segments: 2002-2012 and 2013-2031. During the first eight years of the 2002-2012 segment, Entergy Louisiana agreed to credit rates by flowing through its fuel adjustment calculation $11 million each year, beginning monthly in October 2002. Entergy Louisiana must credit rates in this way and by this amount even if Entergy Louisiana is unable to sustain the tax deduction. 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 the years 2013-2031, Entergy Louisiana and its ratepayers would share the remaining benefits of this tax accounting election. Note 8 to the domestic utility companies and System Energy financial statements contains further discussion of the obligations related to the Vidalia project.

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

Entergy Mississippi

Performance-Based Formula Rate Plan

Entergy Mississippi files a performance-based formula rate plan every 12 months that compares the annual earned rate of return to, and adjusts it against, a benchmark rate of return. The benchmark is calculated under a separate formula within the formula rate plan. The formula rate plan allows for periodic small adjustments in rates, up to an amount that would produce a change in Entergy Mississippi's overall revenue of almost 2%, based on a comparison of actual earned returns to benchmark returns and upon certain performance factors. Entergy Mississippi filed a formula rate plan in March 2004 for the 2003 test year, and filings are due to continue annually thereafter. The March 2004 formula rate plan filing is discussed in Note 2 to the domestic utility companies and System Energy financial statements.

Fuel Recovery

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

In January 2005, the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Entergy Mississippi's fuel over-recoveries for the third quarter of 2004 will be deferred from the first quarter 2005 energy cost recovery rider adjustment calculation. The deferred amount of $21.3 million plus carrying charges will be refunded through the energy cost recovery rider in the second and third quarters of 2005 at a rate of 45% and 55%, respectively.

Entergy New Orleans

Formula Rate Plans

In May 2003, the City Council approved the implementation of formula rate plans for electric and gas service that will be evaluated annually until 2005. Entergy New Orleans made a filing with the City Council in April 2004 based upon a 2003 test year, which after review, resulted in a City Council resolution approving no change in gas and electric rates. Entergy New Orleans will make a filing in accordance with the formula rate plans by May 1, 2005 based on a 2004 test year. Under the formula rate plans, the midpoint ROE of both plans is 11.25%, with a target equity component of Entergy New Orleans' capital structure of 42%. Any change in rates would be prospective, with the first billing cycle effective after September 1, 2005. Entergy New Orleans' can earn between 10.25% and 12.25% under the electric plan and between 11% and 11.5% under the gas plan, with earnings within those ranges not resulting in a change in rates. Entergy New Orleans' formula rate plan filings are disc ussed in Note 2 to the domestic utility companies and System Energy financial statements.

In May 2003, the City Council approved implementation of a generation performance-based rate calculation in the electric fuel adjustment clause under which Entergy New Orleans receives 10% of calculated fuel and purchased power cost savings in excess of $20 million, based on a defined benchmark, subject to a 13.25% return on equity limitation for electric operations as provided for in the electric formula rate plan. Entergy New Orleans bears 10% of any "negative" fuel and purchased power cost savings. In October 2004, Entergy New Orleans' annual evaluation report was submitted for the period June 2003 through May 2004. Additional savings associated with the first year generation performance-based rate calculation were $71 million of which Entergy New Orleans' share was $5.1 million.

Fuel Recovery

Entergy New Orleans' electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges. The adjustment also includes the difference between non-fuel Grand Gulf costs paid by Entergy New Orleans and the estimate of such costs, which are included in base rates, as provided in Entergy New Orleans' Grand Gulf rate settlements. Entergy New Orleans' gas rate schedules include an adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges. In June and November 2004, the City Council passed resolutions implementing a package of measures developed by Entergy New Orleans and the Council Advisors to protect customers from potential gas price spikes during the 2004 - 2005 winter heating season. These measures include: maintaining Entergy New Orleans' financial hedging plan for its purchase of wholesale gas, and deferral of collection of up to $6.2 million of gas costs associated with a cap on the purchased gas adjustment in November and December 2004 in the event that the average residential customer's gas bill were to exceed a threshold level. The deferrals resulting from these caps will receive accelerated recovery over a seven-month period beginning in April 2005.

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

Franchises

Entergy Arkansas holds exclusive franchises to provide electric service in approximately 307 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are terminable upon breach of the terms of the franchise.

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

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

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

Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to city ordinances (except electric service in Algiers, which is provided by Entergy Louisiana). These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans' electric and gas utility properties.

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

Property and Other Generation Resources

Generating Stations

The total capability of the generating stations owned and leased by the domestic utility companies and System Energy as of December 31, 2004, is indicated below:

	Owned and Leased Capability MW(1)
Company	Total	Gas/Oil	Nuclear	Coal	Hydro
Entergy Arkansas	4,709	1,613	1,837	1,189	70
Entergy Gulf States	6,485	4,890	968	627	-
Entergy Louisiana	5,363	4,276	1,087	-	-
Entergy Mississippi	2,898	2,490	-	408	-
Entergy New Orleans	915	915	-	-	-
System Energy	1,143	-	1,143	-	-
Total	21,513	14,184	5,035	2,224	70

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

Entergy's load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new loads, and economy. Peak load in the U.S. Utility service territory is typically around 21,000 MW, with minimum load typically around 9,000 MW. Allowing for an adequate reserve margin, Entergy has been short approximately 3,000 MW during the summer peak load period. In addition to its net short position at summer peak, Entergy considers its generation in three categories: (1) baseload (e.g. coal and nuclear); (2) load-following (e.g. combined cycle gas-fired); and (3) peaking. The relative supply and demand for these categories of generation vary by region of the Entergy System. For example, the north end of its system has more baseload coal and nuclear generation than regional demand requires, but is short load-followin g or intermediate generation. In the south end of the Entergy system, load would be more effectively served if gas-fired intermediate resources already in place were supplemented with additional solid fuel baseload generation.

Until recently, Entergy covered its short position at summer peak almost entirely with purchases from the spot market. In the fall of 2002, Entergy began a process of issuing requests for proposal to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the domestic utility companies. The first request for proposal sought resources to provide summer 2003 and longer-term resources through a broad range of wholesale power products, including short-term (less than one year), limited-term (1 to 3 years) and long-term contractual products and asset acquisitions. A detailed process which included the involvement of an independent monitor was developed to evaluate submitted bids. The following table illustrates the results of the request for proposal process for limited and short-term products. All of the contracts which were awarded and signed were with non-affiliates, with the exception of the contract covering 185 MW to 206 MW from RS Cogen.

	Selected for Negotiation	Contracts Signed	Notes
Fall 2002	550 MW	425 MW	Limited-term resources contracted. Entergy Services also pursued discussions with several bidders for life-of-unit purchased power agreements or the acquisition of an ownership interest in existing generating facilities. These negotiations resulted in the Perryville acquisition agreement, discussed below.
Supplemental 2002	500 MW	220 MW	Short-term purchase for the summer 2003.
Spring 2003	380 MW	380 MW	Limited-term resources contracted.
Fall 2003	390 MW	390 MW	Two separate resources contracted for a term of three years with deliveries beginning in the summer of 2004.

In January 2004, Entergy Louisiana signed a definitive agreement to acquire the 718 MW Perryville power plant for $170 million. The agreement has subsequently been amended to allow the current plant owner to retain the interconnection facilities associated with the plant, resulting in a decrease in the acquisition price to $162 million. As a result of the amended terms, the FERC issued an order in October 2004 disclaiming jurisdiction over the acquisition. This order currently is subject to rehearing by the FERC. 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-serv ice power purchase agreement. In addition, Entergy Louisiana and Entergy Gulf States executed an interim power purchase agreement with the plant's owner through the date of the acquisition's closing (as long as that occurs by December 2005) for 100 percent of the output of the Perryville power plant. In April 2004, the bankruptcy court approved Entergy Louisiana's agreement to acquire the plant. In March 2004, Entergy Gulf States and Entergy Louisiana filed with the LPSC for its approval of the acquisition and long-term cost-of-service power purchase agreement. Entergy is seeking approval from the LPSC of cost recovery for the acquisition, giving consideration to the need for the power and the prudence of Entergy Louisiana and Entergy Gulf States in engaging in the transaction. Hearings are scheduled for March 2005. Assuming regulatory approval by the LPSC, Entergy Louisiana expects the Perryville acquisition to close in mid-2005.

In addition to the purchases from non-affiliates shown above, Entergy Louisiana, Entergy New Orleans, and Entergy Arkansas made filings with their respective retail regulators seeking approval to enter into transactions with affiliates as shown in the following table:

Company	Proposed Transactions	Status of Approval in Retail Jurisdiction
Entergy Louisiana	Purchased a 140 to 156 MW capacity purchase call option from RS Cogen for June 2003 through April 2006. Entered a life-of-unit purchase power agreement (PPA) to purchase approximately 51MW (increasing to 61 MW in 2010) of output from Entergy Power's share of Independence 2. Enter a life-of-unit PPA with Entergy Gulf States to purchase two-thirds of the output of the 30% of River Bend formerly owned by Cajun (approximately 200 MW). Enter a life-of-resources PPA with Entergy Arkansas to purchase approximately 110 MW of capacity not included in Entergy Arkansas' retail rate base, consisting of a portion of the output from ANO, White Bluff, Independence, and Entergy Arkansas' share of Grand Gulf.	The LPSC found contracts 1) and 2) to be prudent and authorized Entergy Louisiana to execute these contracts. The LPSC has not yet approved the life-of-unit PPAs for proposals 3) and 4); a bridge contract however, is currently in place for contract 3) effective through December 31, 2005. The outcome of the life-of-resources PPAs is still pending FERC approval.
Entergy New Orleans	Purchased a 45 to 50 MW capacity purchase call option from RS Cogen for June 2003 through April 2006. Entered a life-of-unit PPA to purchase approximately 50 MW (increasing to 60 MW in 2010) of output from Entergy Power's share of Independence 2. Entered a life-of-unit PPA with Entergy Gulf States to purchase one-third of the output of the 30% of River Bend formerly owned by Cajun (approximately 100 MW). Entered a life-of-resources PPA with Entergy Arkansas to purchase approximately 110 MW of capacity not included in Entergy Arkansas' retail rate base, consisting of a portion of the output from ANO, White Bluff, Independence, and Entergy Arkansas' share of Grand Gulf.	In May 2003, in connection with a settlement relating to Entergy New Orleans' cost-of-service study and revenue requirement, the City Council authorized Entergy New Orleans to enter into contracts for the proposed transactions.
Entergy Arkansas	Enter into the life-of-resources PPAs to sell power as discussed in both Entergy Louisiana's and Entergy New Orleans' proposal 4) above.	In May 2003, the APSC found the PPAs involving Entergy Arkansas in the public interest.

Entergy also filed with the FERC the affiliate agreements described above. In May 2003, the FERC accepted the agreements for filing, subject to refund, with the contracts becoming effective on June 1, 2003. The FERC also established a hearing process to review the justness and reasonableness of the agreements. Several parties have intervened or filed protests regarding the request-for-proposals process and the agreements filed with the FERC, and the hearings in the proceeding ended in December 2004. An initial decision by the ALJ is still pending and is scheduled for July 2005.

Interconnections

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

Gas Property

As of December 31, 2004, Entergy New Orleans distributed and transported natural gas for distribution solely within New Orleans, Louisiana, through a total of 33 miles of gas transmission pipeline, 1,495 miles of gas distribution pipeline, and 1,029 miles of gas service pipeline from the distribution mains to the customers. As of December 31, 2004, the gas properties of Entergy Gulf States, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Gulf States' financial position.

Titles

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

Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy are subject to the liens of mortgages securing the mortgage bonds of such company. The Lewis Creek generating station is owned by GSG&T, Inc., a subsidiary of Entergy Gulf States, and is not subject to the lien of the Entergy Gulf States mortgage securing its first mortgage bonds. Lewis Creek is leased to and operated by Entergy Gulf States.

Fuel Supply

The generation portfolio of the U.S. Utility contains a high percentage of natural gas and nuclear generation. The sources of generation and average fuel cost per kWh for the domestic utility companies and System Energy for the years 2002-2004 were:

	Natural Gas		Fuel Oil		Nuclear Fuel		Coal
Year	% of Gen	Cents Per kWh	% of Gen	Cents Per kWh	% of Gen	Cents Per kWh	% of Gen	Cents Per kWh
2004	23	7.31	6	5.02	52	.49	19	1.39
2003	26	6.53	4	5.04	52	.48	18	1.26
2002	39	3.88	-	15.78	46	.47	15	1.37

Actual 2004 and projected 2005 sources of generation for the domestic utility companies and System Energy, including proposed power purchases from affiliates under power purchase agreements in 2005, are:

	Natural Gas		Fuel Oil		Nuclear		Coal
	2004	2005	2004	2005	2004	2005	2004	2005
Entergy Arkansas (a)	1%	-	-	-	65%	64%	34%	35%
Entergy Gulf States	41%	36%	1%	-	36%	36%	22%	28%
Entergy Louisiana	38%	40%	8%	8%	52%	50%	2%	2%
Entergy Mississippi	9%	3%	46%	62%	-	-	45%	35%
Entergy New Orleans	55%	55%	-	-	32%	31%	13%	14%
System Energy	-	-	-	-	100%(b)	100%(b)	-	-
U.S. Utility (a)	23%	22%	6%	8%	52%	50%	19%	20%

(a)

Hydroelectric power provided less than 1% of Entergy Arkansas' generation in 2004 and is expected to provide approximately 1% of its generation in 2005.

(b)

Capacity and energy from System Energy's interest in Grand Gulf 1 was historically allocated as follows: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements that are the subject of a pending proceeding at the FERC, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf 1 to Entergy Louisiana and Entergy New Orleans.

Natural Gas

The domestic utility companies have long-term firm and short-term interruptible gas contracts. Long-term firm contracts for power plants comprise less than 15% of the domestic utility companies' total requirements but can be called upon, if necessary, to satisfy a significant percentage of the utility companies' needs. Short-term contracts and spot-market purchases satisfy additional gas requirements. As of January 1, 2005, Entergy Gulf States owns a gas storage facility that provides reliable and flexible natural gas service to certain generating stations.

Entergy Louisiana has a long-term natural gas supply contract, which expires in 2012, in which Entergy Louisiana agreed to purchase natural gas in annual amounts equal to approximately one-third of its projected annual fuel requirements for certain generating units. Annual demand charges associated with this contract are estimated to be $7.2 million. Such charges aggregate $58 million for the years 2005 through 2012.

Many factors, including wellhead deliverability, storage and pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is tied to weather conditions as well as to the prices of other energy sources. Entergy's supplies of natural gas are expected to be adequate in 2005. However, pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the domestic utility companies will use alternate fuels, such as oil, or rely to a larger extent on coal, nuclear generation, and purchased power.

Coal

Entergy Arkansas has a long-term contract for low-sulfur Wyoming coal for Independence. This contract, which expires in 2011, provides for approximately 90% of Independence's expected coal requirements for 2005. Entergy Arkansas has entered into three medium term (three-year) contracts for approximately 67% of White Bluff's coal supply needs. These contracts are staggered in term so that one is renewed every year. Entergy Arkansas has an additional 16% of its 2005 coal requirement committed in a one-year contract. Additional coal requirements for both Independence and White Bluff are satisfied by spot market or over the counter purchases. Entergy Arkansas has a long-term railroad transportation contract for the delivery of coal to both White Bluff and Independence that expires in 2011. A second carrier now delivers a portion of White Bluff's coal requirements under a long-term transportation agreement that expires on December 31, 2006.

Entergy Gulf States has a long-term contract, which contains periodic price re-openers, for the supply of low-sulfur Wyoming coal for Nelson Unit 6. Entergy Gulf States has entered discussions with the supplier regarding the first price re-opener. If a new price is negotiated, the agreement would extend to April 2007. Entergy Gulf States has executed two transportation requirements contracts with railroads to deliver coal to Nelson Unit 6 through 2007. The operator of Big Cajun 2, Unit 3, Louisiana Generating, LLC, has advised Entergy Gulf States that it has coal supply and transportation contracts that should provide an adequate supply of coal for the operation of Big Cajun 2, Unit 3 for the foreseeable future.

Nuclear Fuel

        The nuclear fuel cycle consists of the following:

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

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

Based upon currently planned fuel cycles, Entergy's nuclear units have contracts and inventory that provide adequate materials and services. Existing contracts for uranium concentrate, conversion of the concentrate to uranium hexafluoride, and enrichment of the uranium hexafluoride will provide a significant percentage of these materials and services over the next several years. Uranium market supply became much tighter in 2003 and early 2004 than in previous years. Costs and risks of obtaining supplies have increased for nuclear fuel users. It will be necessary for Entergy to enter into additional arrangements to acquire nuclear fuel in the future. It is not possible to predict the ultimate cost or availability of such arrangements.

Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These arrangements are subject to periodic renewal. See Note 9 to the domestic utility companies and System Energy financial statements for a discussion of nuclear fuel leases.

Natural Gas Purchased for Resale

Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with three interstate and three intrastate pipelines. Entergy New Orleans' primary suppliers currently are Atmos Energy and Louisiana Gas Services. Entergy New Orleans has a "no-notice" service gas purchase contract with Atmos Energy which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The Atmos Energy gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans has firm contracts with its two intrastate suppliers and also makes interruptible spot market purchases. In recent years, natural gas deliveries to Entergy New Orleans have been subject primarily to weather-related curtailments. However, Entergy New Orleans experienced no such curtailments in 20 04.

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

Entergy Gulf States purchases natural gas for resale under a firm contract from Enbridge Marketing (U.S.) Inc. (formerly Mid Louisiana Gas Company) entered into September 2002 for a five-year period. The contract will continue annually at the end of the term unless prior notice is given by Entergy Gulf States.

Federal Regulation

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

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

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

Litigation involving the System Agreement is being pursued by the LPSC at both the FERC and before itself. These proceedings include challenges to the allocation of costs as defined by the System Agreement, raise questions of imprudence by the domestic utility companies in their execution of the System Agreement, and seek support for local regulatory authority over System Agreement issues. Regarding the proceeding at the LPSC, Entergy believes that state and local regulators are preempted by federal law from reviewing and deciding System Agreement issues for themselves. An unrelated case between the LPSC and Entergy Louisiana raised the question of whether a state regulator is preempted by federal law from reviewing and interpreting 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 Suprem e Court affirmed the LPSC's decision. In 2003, the U.S. Supreme Court ruled in Entergy Louisiana's favor and reversed the decisions of the LPSC and the Louisiana Supreme Court.

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

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

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

	Range of Annual Payments or (Receipts)	Average Annual Payments or (Receipts) for 2005-2009 Period
	(In Millions)	(In Millions)
Entergy Arkansas	$154 to $281	$215
Entergy Gulf States	($130) to ($15)	($63)
Entergy Louisiana	($199) to ($98)	($141)
Entergy Mississippi	($16) to $8	$1
Entergy New Orleans	($17) to ($5)	($12)

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

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

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

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

Transmission

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

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

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

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

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

FERC's Supply Margin Assessment

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

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

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

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

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

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

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

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

Interconnection Orders

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

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

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

Available Flowgate Capacity Proceeding

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

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

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

FERC Audits

In August 2002, the FERC initiated audits and reviews of Entergy's compliance with Order Nos. 888 and 889 and Entergy's open access transmission tariff. In March 2004, a separate audit was started concerning Entergy's administration of the Generator Operating Limits ("GOL") processes. Entergy responded to numerous FERC data requests and the FERC Staff members interviewed several employees. In December 2004, the FERC issued the GOL audit report in which it identified certain input and modeling errors in the implementation of the GOL process (which process was replaced in April 2004 with the AFC process). The report recommends that Entergy implement additional quality control and assurance procedures surrounding the processes for granting short term transmission service. Separately, the FERC investigation staff has provided to Entergy its preliminary findings in a non-public draft report identifying certain areas of concern related to Entergy's compliance with provisions of its open acce ss transmission tariff. Entergy has submitted a comprehensive response and rebuttal to the specific concerns identified by the investigation staff but, at this point, believes that it has complied with the provisions of its open access transmission tariff. The draft report is not a final report and may be modified by the FERC staff based on Entergy's responses or otherwise. In addition, Entergy has the ability to appeal the final reports to the full FERC.

The FERC is currently reviewing certain wholesale sales and purchases involving EPMC that occurred during the 1998-2001 time period. EPMC was an Entergy subsidiary engaged in non-regulated wholesale marketing and trading activities prior to the formation of Entergy-Koch. Entergy is working with the FERC investigation staff to provide information regarding these transactions.

Other Customer-initiated Proceedings at FERC

In September 2004, East Texas Electric Cooperative (ETEC), filed a complaint at the FERC against Entergy Arkansas relating to a contract dispute over the pricing of substitute energy at the co-owned coal unit, Independence Steam Electric Station (ISES).  In October 2004 Arkansas Electric Cooperative (AECC) filed a similar complaint at FERC against Entergy Arkansas, addressing the same issue with respect to ISES and another co-owned coal unit, White Bluff Electric Station.  Entergy Arkansas filed answers to these complaints in October 2004 and November 2004.  FERC consolidated the cases, ordered a hearing in the consolidated proceeding, and established refund effective dates.  The main issue in the case relates to the consequences under the governing contracts when the dispatch of the coal units is constrained due to system operating conditions.  Entergy Arkansas believes that the contracts in dispute recognize the effects of dispatch constraints on the co-owned un its and require all of the co-owners, including ETEC and AECC, to bear the burden of the reduced output.  Entergy Arkansas expects an initial decision by a FERC ALJ in October 2005.

On February 17, 2005, ExxonMobil Chemical Company and ExxonMobil Refining & Supply Company (ExxonMobil) filed a complaint with FERC against Entergy Services and the domestic utility companies. The complaint alleges that the Entergy defendants have violated Entergy's open access transmission tariff, as well as its interconnection and operating agreement with ExxonMobil, by not allowing ExxonMobil to net its station power needs at its industrial complex in Baton Rouge, Louisiana. ExxonMobil also alleges that the Entergy defendants have been charging rates that are not on file with the FERC and that the Entergy defendants' monthly facilities charge is contrary to the FERC's current interconnection pricing policy. ExxonMobil states that such violations have resulted in monetary losses to it in excess of $5 million. Entergy believes that it has complied with the provisions of its open access transmission tariff and the provisions of the interconnection and operating agreement.

System Energy and Related Agreements

System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In December 1995, System Energy commenced a rate proceeding at the FERC. In July 2001, the rate proceeding became final, with the FERC approving a prospective 10.94% return on equity. The FERC's decision also affected other aspects of System Energy's charges to the domestic utility companies that it supplies with power. In 1998, the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas' and Entergy Mississippi's acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by FERC.

Unit Power Sales Agreement

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

In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas' cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans pending regulatory approvals that sell a portion of the output of Entergy Arkansas' retained share of Grand Gulf to those companies. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted rate relief with respect to costs associated with Entergy Louisiana's share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers, 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC's approval.

Availability Agreement

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

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

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

System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for its first mortgage bonds and reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 9 to the financial statements under "Sale and Leaseback Transactions - Grand Gulf Lease Obligations." In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allow ed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.

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

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

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

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

Capital Funds Agreement

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

Entergy Corporation has entered into various supplements to the Capital Funds Agreement. System Energy has assigned its rights under such supplements as security for its first mortgage bonds and for reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 9 to the financial statements under "Sale and Leaseback Transactions - Grand Gulf Lease Obligations." Each such supplement provides that permitted indebtedness for borrowed money incurred by System Energy in connection with the financing of Grand Gulf may be secured by System Energy's rights under the Capital Funds Agreement on a pro rata basis (except for the Specific Payments, as defined below). In addition, in the supplements to the Capital Funds Agreement relating to the specific indebtedness being secured, Entergy Corporation has agreed to make cash capital contributions directly to System Energy sufficient to enable System Energy to make payments when due on such indebtedness (Specific Payments). However, if there is an event of default, Entergy Corporation must make those payments directly to the holders of indebtedness benefiting from the supplemental agreements. The payments (other than the Specific Payments) must be made pro rata according to the amount of the respective obligations benefiting from the supplemental agreements.

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

Service Companies

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

Earnings Ratios of Domestic Utility Companies and System Energy

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

	Ratios of Earnings to Fixed Charges Years Ended December 31,
	2004	2003	2002	2001	2000
Entergy Arkansas	3.37	3.17	2.79	3.29	3.01
Entergy Gulf States	3.04	1.51	2.49	2.36	2.60
Entergy Louisiana	3.60	3.93	3.14	2.76	3.33
Entergy Mississippi	3.41	3.06	2.48	2.14	2.33
Entergy New Orleans	3.60	1.73	(b)	(c)	2.66
System Energy	3.95	3.66	3.25	2.12	2.41

	Ratios of Earnings to Combined Fixed Charges and Preferred Dividends Years Ended December 31,
	2004	2003	2002	2001	2000
Entergy Arkansas	2.98	2.79	2.53	2.99	2.70
Entergy Gulf States (a)	2.90	1.45	2.40	2.21	2.39
Entergy Louisiana	3.16	3.46	2.86	2.51	2.93
Entergy Mississippi	3.07	2.77	2.27	1.96	2.09
Entergy New Orleans	3.31	1.59	(b)	(c)	2.43

(a)	"Preferred Dividends" in the case of Entergy Gulf States also include dividends on preference stock, which was redeemed in July 2000.
(b)	For Entergy New Orleans, earnings for the twelve months ended December 31, 2002 were not adequate to cover fixed charges and combined fixed charges and preferred dividends by $0.7 million and $3.4 million, respectively.
(c)	For Entergy New Orleans, earnings for the twelve months ended December 31, 2001 were not adequate to cover fixed charges and combined fixed charges and preferred dividends by $6.6 million and $9.5 million, respectively.

Non-Utility Nuclear

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

Property

Generating Stations

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

Power Plant	Acquired	Location	Maximum Capacity	Reactor Type	License Expiration Date
Pilgrim	July 1999	Plymouth, MA	688 MW	Boiling Water Reactor	2012
FitzPatrick	Nov. 2000	Oswego, NY	838 MW	Boiling Water Reactor	2014
Indian Point 3	Nov. 2000	Westchester County, NY	994 MW	Pressurized Water Reactor	2015
Indian Point 2	Sept. 2001	Westchester County, NY	1,028 MW	Pressurized Water Reactor	2013
Vermont Yankee	July 2002	Vernon, VT	510 MW	Boiling Water Reactor	2012

Non-Utility Nuclear added 57 MW of capacity in 2004 through uprates and plans an additional 142 MW of uprates through 2006. The planned uprates include a total of 95 MW for Vermont Yankee that are currently pending approval by the NRC and the Public Service Board of Vermont.

Interconnections

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

Energy and Capacity Sales

Entergy's Non-Utility Nuclear business has entered into power purchase agreements (PPAs) with creditworthy counterparties to sell the energy produced by its power plants at prices established in the PPAs. Entergy continues to pursue opportunities to extend the existing PPAs and to enter into new PPAs with other parties. Following is a summary of the amount of the Non-Utility Nuclear business' output that is currently sold forward under physical or financial contracts at fixed prices:

		2005	2006	2007	2008	2009
Non-Utility Nuclear:
Percent of planned generation sold forward:
	Unit-contingent	36%	20%	17%	1%	0%
	Unit-contingent with availability guarantees	54%	52%	38%	25%	0%
	Firm liquidated damages	4%	4%	2%	0%	0%
	Total	94%	76%	57%	26%	0%
Planned generation (TWh)		34	35	34	34	35
Average contracted price per MWh		$39	$41	$42	$44	N/A

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

A sale of power on a unit contingent basis coupled with an availability guarantee provides for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. To date, Entergy has not incurred any payment obligation to any power purchaser pursuant to an availability guarantee. All of Entergy's outstanding availability guarantees provide for dollar limits on Entergy's maximum liability under such guarantees.

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

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

		2005	2006	2007	2008	2009
Non-Utility Nuclear:
Percent of capacity sold forward:
	Bundled capacity and energy contracts	13%	13%	13%	13%	13%
	Capacity contracts	58%	67%	36%	22%	10%
	Total	71%	80%	49%	35%	23%
Planned net MW in operation		4,155	4,200	4,200	4,200	4,200
Average capacity contract price per kW per month		$1.2	$1.1	$1.1	$1.0	$0.9
Blended Capacity and Energy (based on revenues)
% of planned generation and capacity sold forward		93%	87%	65%	36%	12%
Average contract revenue per MWh		$40	$42	$43	$44	$43

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

Fuel Supply

Nuclear Fuel

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

Based upon currently planned fuel cycles, Entergy's nuclear units have contracts and inventory that provide adequate materials and services. Existing contracts for uranium concentrate, conversion of the concentrate to uranium hexafluoride, and enrichment of the uranium hexafluoride will provide a significant percentage of these materials and services over the next several years. Uranium market supply became much tighter in recent years. Costs and risks of obtaining supplies have increased for nuclear fuel users. It will be necessary for Entergy to enter into additional arrangements to acquire nuclear fuel in the future. It is not possible to predict the ultimate cost or availability of such arrangements.

Other Business Activities

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

In September 2003, Entergy's Non-Utility Nuclear business agreed to provide administrative support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. The contract is for 10 years, the remaining term of the plant's operating license. Entergy will receive $13 million in 2005, and $14 million in 2006 and each of the remaining years of the contract. Entergy can also receive up to $6 million more per year beginning in 2007 if safety and regulatory goals are met. In addition, Entergy will be reimbursed for all employee-related expenses.

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

Energy Commodity Services

The Energy Commodity Services segment includes Entergy's non-nuclear wholesale assets business and Entergy-Koch, LP. Entergy's non-nuclear wholesale assets business owns power plants capable of generating about 1,500 MW of electricity for sale in the wholesale market. Entergy-Koch, LP is a limited partnership owned 50% each by Entergy and Koch Industries, Inc. through subsidiaries. Entergy-Koch engaged in two major businesses: energy commodity marketing and trading through Entergy-Koch Trading, and gas transportation and storage through Gulf South Pipeline. Entergy-Koch sold both of these businesses in the fourth quarter 2004, and Entergy-Koch is no longer an operating entity. Previously, Entergy's Energy Commodity Services business also engaged in power development activities through Entergy Wholesale Operations, but these activities were discontinued in early 2002.

Non-Nuclear Wholesale Assets Business

Property

Generating Stations

The capacity of the generating stations owned in Entergy's non-nuclear wholesale assets business as of December 31, 2004 is indicated below:

Plant	Location	Ownership	Net Owned Capacity(1)	Type
Ritchie Unit 2, 544 MW	Helena, AR	100%	544 MW	Gas/Oil
Independence Unit 2, 842 MW	Newark, AR	14%	121 MW(2)	Coal
Warren Power, 300 MW	Vicksburg, MS	75%	225 MW(2)	Gas Turbine
Top of Iowa, 80 MW (3)	Worth County, IA	50%	40 MW	Wind
White Deer, 80 MW (3)	Amarillo, TX	50%	40 MW	Wind
RS Cogen, 425 MW (3)	Lake Charles, LA	50%	213 MW	Gas/Steam
Harrison County, 550 MW	Marshall, TX	61%	335 MW(2)	Gas Turbine

(1)	"Net Owned Capacity" refers to the nameplate rating on the generating unit.
(2)	The owned MW capacity is the portion of the plant capacity owned by Entergy's non-nuclear wholesale assets business. For a complete listing of Entergy's joint-owned generating stations, refer to "Jointly-Owned Generating Stations" in Note 1 to the consolidated financial statements.
(3)	Indirectly owned through interests in unconsolidated joint ventures.

In addition to these generating stations, Entergy's non-nuclear wholesale assets business has a contract to take 60MW of the power from a portion of the Nelson 6 coal plant owned by a third party.

Entergy sold its interest in the Crete power plant located in Illinois in January 2004.

Energy and Capacity Sales

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

	2005	2006	2007	2008	2009
Energy Commodity Services:
Capacity
Planned MW in operation	1,578	1,578	1,578	1,578	1,578
% of capacity sold forward	44%	33%	29%	29%	19%
Energy
Planned generation (TWh)	3	3	3	3	4
% of planned generation sold forward	69%	54%	45%	45%	35%
Blended Capacity and Energy (based on revenues)
% of planned energy and capacity sold forward	63%	44%	38%	39%	22%
Average contract revenue per MWh	$24	$24	$28	$28	$21

Entergy-Koch, LP

Entergy-Koch is a limited partnership owned 50% each by Entergy and Koch Industries, Inc, through subsidiaries. Entergy-Koch began operations on February 1, 2001. Entergy contributed most of the assets and trading contracts of its power marketing and trading business and $414 million cash to the venture and Koch contributed its approximately 8,000-mile Koch Gateway Pipeline (renamed Gulf South Pipeline), gas storage facilities, and Koch Energy Trading, which marketed and traded electricity, gas, weather derivatives, and other energy-related commodities and services. As specified in the partnership agreement, Entergy contributed an additional $72.7 million to the partnership in January 2004.

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

Regulation of Entergy's Business

PUHCA

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

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

Entergy continues to support the broad industry effort to pass legislation in the United States Congress to repeal PUHCA and transfer certain aspects of the oversight of public utility holding companies from the SEC to FERC. Entergy believes that PUHCA inhibits its ability to compete in the evolving electric energy marketplace and largely duplicates the oversight activities otherwise performed by FERC, other federal regulators, and state and local regulators.

Federal Power Act

The Federal Power Act regulates:

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

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

Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 70 MW of capacity.

State Regulation

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

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

Entergy Gulf States may be subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Whether such municipal jurisdiction currently exists is the subject of a declaratory judgment proceeding initiated at the PUCT by certain Cities served by Entergy Gulf States in December 2004. Entergy Gulf States' Texas business is also subject to regulation by the PUCT as to:

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

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

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

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

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

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

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

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

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

Regulation of the Nuclear Power Industry

Atomic Energy Act of 1954 and Energy Reorganization Act of 1974

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

Nuclear Waste Policy Act of 1982

Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy's nuclear owner/licensee subsidiaries provide for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE will furnish disposal service at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2004 of $156.3 million for the one-time fee. Entergy's Non-Utility Nuclear business has accepted assignment of the Pilgrim, FitzPatrick, Indian Point 3, Indian Point 2, and Vermont Yankee spent fuel disposal contracts with the DOE held by their previous owners. The previous owners have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the U.S. Utility plants.

The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE will now proceed with the licensing and, if the license is granted by the NRC, eventual construction of the repository will begin and receipt of spent fuel may begin sometime after 2010. Considerable uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy's facilities for storage or disposal. As a result, future expenditures will be required to increase spent fuel storage capacity at Entergy's nuclear plant sites.

As a result of the DOE's failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy's nuclear owner/licensee subsidiaries have incurred and will continue to incur damages.  These subsidiaries in November 2003 began litigation to recover the damages caused by the DOE's delay in performance.  Management cannot predict the timing or amount of any potential recovery.

Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are responsible for their own spent fuel storage.  Current on-site spent fuel storage capacity at Grand Gulf 1, River Bend, and Waterford is estimated to be sufficient until approximately 2007, 2006, and 2012, respectively; dry cask storage facilities are planned to be placed into service at these units in 2007, 2005, and 2011, respectively.  An ANO storage facility using dry casks began operation in 1996 and has been expanded since and will be further expanded as needed.  The spent fuel storage facility at Pilgrim is licensed to provide enough storage capacity until approximately 2012. The first dry spent fuel storage casks were loaded at Fitzpatrick in 2002, and further casks will be loaded there as needed.  Indian Point and Vermont Yankee currently have sufficient spent fuel storage capacity until approximately 2006 and 2007, respectively; dry cask storage facilities are planned to begin operation at both sites in 2006. Implementation of dry cask storage at Vermont Yankee is currently the subject of pending legislative and regulatory proceedings in Vermont.

Nuclear Plant Decommissioning

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

In June 2001, Entergy Arkansas received notification from the NRC of approval for a renewed operating license authorizing operations at ANO 1 through May 2034. In October 2003, a request was filed with the NRC to extend the operating license of ANO 2 for an additional 20 years. The APSC ordered Entergy Arkansas to use a 20-year life extension assumption for ANO 1 and 2, which resulted in the cessation of the collection of funds to decommission ANO 1 and 2 beginning in 2001. Entergy Arkansas' projections show that with the assumption of 20 years of extended operational life for both units, the current fund balance with earnings over the extended life will be sufficient to decommission both units. Every five years, Entergy Arkansas is required by the APSC to update the estimated costs to decommission ANO. In March 2003, Entergy Arkansas filed with the APSC its third five-year estimate of ANO decommissioning costs. The updated estimate indicated the current cost to decommission the two ANO units would be $936 million compared to $813 million in the 1997 estimate. In September 2003, the APSC approved a stipulation between the APSC Staff and Entergy Arkansas resolving issues in the decommissioning cost estimate proceeding. Entergy Arkansas and the APSC Staff agreed to exclude, at this time, certain spent fuel management costs because of uncertainty associated with the responsibility of the DOE for all or a portion of those costs as a result of Entergy Arkansas' contract with the DOE to start taking spent fuel from ANO beginning in 1998. Entergy Arkansas reserves the right to seek a decision from the APSC on this issue prior to the next required decommissioning cost filing should significant changes in relevant facts and circumstances warrant.

In December 2002, the LPSC approved a settlement between Entergy Gulf States and the LPSC staff. The settlement included, among other things, the approval to cease collection of funds to decommission River Bend based on an assumed license extension for River Bend.

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

For the Indian Point 3 and FitzPatrick plants purchased in 2000, NYPA retained the decommissioning trusts and the decommissioning liability. NYPA and Entergy executed decommissioning agreements, which specify their decommissioning obligations. NYPA has the right to require Entergy to assume the decommissioning liability provided that it assigns the corresponding decommissioning trust, up to a specified level, to Entergy. If the decommissioning liability is retained by NYPA, Entergy will perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. Entergy believes that the amounts available to it under either scenario are sufficient to cover the future decommissioning costs without any additional contributions to the trusts. In conjunction with the Pilgrim acquisition, Entergy received Pilgrim's decommissioning trust fund. Entergy believes that Pilgrim's decommissioning fund will be adequate to cover future decommissioning costs for the plant without any additional deposits to the trust. As part of the Indian Point 1 and 2 purchase, Consolidated Edison transferred the decommissioning trust fund and the liability to decommission Indian Point 1 and 2 to Entergy. Entergy also funded an additional $25 million to the decommissioning trust fund and believes that the trust will be adequate to cover future decommissioning costs for Indian Point 1 and 2 without any additional deposits to the trust.

Additional information with respect to decommissioning costs for ANO, River Bend, Waterford 3, Grand Gulf, Pilgrim, Indian Point 1, Indian Point 2, Indian Point 3, and FitzPatrick is found in Note 8 to the financial statements.

Energy Policy Act of 1992

The Energy Policy Act of 1992 requires all electric utilities (including Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy) that purchased uranium enrichment services from the DOE to contribute up to a total of $150 million annually over approximately 15 years (adjusted for inflation, up to a total of $2.25 billion) for decontamination and decommissioning of enrichment facilities. At December 31, 2004, two years of assessments remain. In accordance with the Energy Policy Act of 1992, contributions to decontamination and decommissioning funds are recovered through rates in the same manner as other fuel costs. The estimated annual contributions by Entergy for decontamination and decommissioning fees are discussed in Note 8 to the financial statements. Entergy will oppose any attempts to extend the assessments past this date, but cannot state with certainty that an extension will not be made.

Price-Anderson Act

The Price-Anderson Act limits public liability for a single nuclear incident to approximately $100.6 million per reactor (with currently 104 nuclear industry reactors participating). Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, System Energy, and Entergy's Non-Utility Nuclear business have protection with respect to this liability through a combination of private insurance and an industry assessment program, as well as insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units. Insurance applicable to the nuclear programs of Entergy is discussed in Note 8 to the financial statements.

Environmental Regulation

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

Clean Air Act and Subsequent Amendments

The Clean Air Act and its subsequent Amendments (the Clean Air Act) established several programs that currently or in the future may affect Entergy's fossil-fueled generation facilities:

• New source review and preconstruction permits for new sources of criteria air pollutants and significant modifications to existing facilities;
• Acid rain program for control of sulfur dioxide (SO₂) and nitrogen oxides (NO_x);
• Ozone non-attainment area program for control of NO_x and volatile organic compounds;
• Hazardous air pollutant emissions reduction program;
• Interstate Air Transport; and
• Operating permits program for administration and enforcement of these and other Clean Air Act programs.

New Source Review

Preconstruction permits are required for new facilities and for existing facilities that undergo a modification that is not classified as routine repair, maintenance, or replacement. Units that undergo a non-routine modification must obtain a permit modification and may be required to install additional air pollution control technologies. Entergy has an established process for identifying modifications requiring additional permitting approval and has followed the regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. In recent years, however, EPA has begun an enforcement initiative, aimed primarily at coal plants, to identify modifications that it does not consider routine and that have failed to obtain a permit modification. Entergy to date has not been included in any of these enforcement actions. Nevertheless, various courts and EPA have been inconsistent in their judgmen ts regarding what modifications are considered routine. In 2003, EPA promulgated a rule to attempt to clarify this issue, but the rule has been challenged in the United States Court of Appeals for the District of Columbia Circuit, and its effectiveness has been stayed by the court.  In June 2004, EPA granted a request to reconsider certain aspects of the rule.

Acid Rain Program

The Clean Air Act provides SO₂ allowances to most of the affected Entergy generating units for emissions based upon past emission levels and operating characteristics. Each allowance is an entitlement to emit one ton of SO₂ per year. Plant owners are required to possess allowances for SO₂ emissions from affected generating units. Virtually all Entergy fossil-fueled generating units are subject to SO₂ allowance requirements. Entergy could be required to purchase additional allowances when it generates power using fuel oil. Fuel oil usage is determined by economic dispatch and influenced by the price of natural gas, incremental emission allowance costs, and the availability and cost of purchased power.

Ozone Non-attainment

Entergy Gulf States and Entergy Louisiana each operate fossil-fueled generating units in geographic areas that are not in attainment of the currently-enforced national ambient air quality standards for ozone. Texas non-attainment areas that impact Entergy are the Houston-Galveston and the Beaumont-Port Arthur areas. In Louisiana, Entergy is affected by the non-attainment status of the Baton Rouge area. Areas in non-attainment are classified as "moderate," "serious," or "severe." When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards. Texas and Louisiana submitted plans for the Beaumont-Port Arthur and Baton Rouge areas that included an extension of the regulatory deadline to gain attainment. The EPA initially approved these plans and the deadline extensions, but through litigation and a decision of the United Stat es Court of Appeals for the Fifth Circuit in December 2002, the approval of the state plans has been withdrawn as violating provisions and deadlines required by the Clean Air Act.

The EPA has now reclassified the Beaumont-Port Arthur area from "moderate" to "serious" and has reclassified the Baton Rouge area from "serious" to "severe". These actions will require that Texas and Louisiana adopt plans to restrict the emission of certain air pollutants and to make progress toward eventual attainment of national standards. Texas adopted and forwarded to the EPA for approval revisions to the state implementation plan in December 2004. Based on this submittal, Entergy Gulf States believes that new NO_x control equipment will not be required at the Beaumont-Port Arthur area facilities. The Louisiana plan revisions were due in June 2004; however, due to legal and regulatory disputes over requirements unrelated to Entergy's interests, the state has chosen to delay the submittal. The final content and effect on Entergy of these developing plans is unknown, but Entergy continues to monitor events in these areas.

In April 2004, EPA issued a final rule, effective June 2005, stating that areas designated as non-attainment under a new 8-hour ozone standard shall have one year to adjust to the new requirements. For Louisiana, the Baton Rouge area would be classified as a "marginal" (rather than "severe") non-attainment area under the new standard with an attainment date of June 2007. For Texas, the Beaumont/Port Arthur area would be designated as a "marginal" (rather than "serious") non-attainment area under the new standard with an attainment date of June 2007 and the Houston-Galveston area would be designated as "moderate" non-attainment under the new standard with an attainment date of June 2010.

Hazardous Air Pollutants

In December 2000, the EPA made a determination that coal and oil-fired steam electric generating units should be regulated under the section of the Clean Air Act relating to emissions of hazardous air pollutants (HAPs). The principal HAPs of concern are mercury from coal and nickel from oil. The EPA has proposed regulations for these sources and initially set a deadline of December 2004 for finalizing the rules. Entergy owns units that would be subject to these regulations. The EPA has since postponed finalization of mercury and nickel HAPs regulations until the second quarter of 2005.

The regulations may require coal and oil-fired units to reduce mercury and nickel emissions through various methods, including installation of controls, switching fuels or fuel suppliers, reducing utilization of units, or some combination of these methods. The earliest expected compliance date for this rule would be 2007, and Entergy could begin to incur costs of compliance as early as 2006 with the work taking up to three years to complete. These costs should be offset by advances in control technology or through the implementation of proposed cap and trade provisions which are not final at this time.

Interstate Air Transport

In January 2004, the EPA proposed the Interstate Air Quality Rule, renamed the Clean Air Interstate Rule (CAIR), which intends to reduce SO₂ and NO_x emissions from plants in order to improve air quality in the northeastern United States. The EPA has postponed issuing a final rule until the second quarter of 2005. The rule has the potential to require significant pollution control capital and/or operating costs (including any potential impacts to the value of SO₂ allowances). Entergy's capital investment and annual operation and maintenance allowance purchase costs will depend on the economic assessment of NO_x and SO₂ allowance markets, cost of control technologies, and unit usage as well as other uncertainties described below.

The capital financial impact could be offset by proposed emission markets which would allow operation and maintenance purchases or use of allocated credits; however, the allocation of the emission allowances and the set up of the market will determine the ultimate cost to Entergy. Entergy is concerned that the allocation may be unfairly skewed towards states with relatively higher emissions. Entergy will continue to study the proposed rule's impact to its generation fleet and will work to ensure that all states are treated fairly in the allocation of emission credits.

In May 2004, the EPA re-proposed the Best Retrofit Control Technology (BART) regulations which could potentially result in a requirement to install SO₂ pollution control technology on certain of Entergy's coal and oil generation units. The impact of this proposed rule is unclear, but could result in significant increased capital and operating costs on certain units.

Future Legislative and Regulatory Developments

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

• designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
• EPA initiatives related to regional haze;
• introduction of several bills in Congress proposing further limits on NO_x, SO_2, mercury, or limits on carbon dioxide (CO₂) emissions; and
• pursuit by the Bush administration of a voluntary program intended to reduce CO₂ emissions.

Entergy continues to monitor these actions in order to analyze their potential operational and cost implications. In anticipation of the potential imposition of CO₂ emission limits on the electric industry in the future, Entergy has initiated actions designed to reduce its exposure to potential new governmental requirements related to CO₂ emissions. These actions include establishment of a formal program to stabilize power plant CO₂ emissions at year 2000 levels through 2005 and support for national legislation that would increase planning certainty for electric utilities while addressing emissions in a responsible and flexible manner. By virtue of its proportionally large investment in low or non-emitting gas-fired and nuclear generation technologies, Entergy's overall CO₂ emission "intensity," or rate of CO₂ emitted per kilowatt-hour of electricity generated, is already among the lowest in the industry. To tal CO₂ emissions representing the company's ownership share of power plants in the United States were approximately 53.24 million tons in 2000, 49.58 million tons in 2001, 44.20 million tons in 2002, 36.78 million tons in 2003, and 38.28 million tons in 2004.

Clean Water Act

The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act or CWA) provide the statutory basis for the National Pollutant Discharge Elimination System (NPDES) permit program and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The CWA requires all discharges of pollutants to waters of the United States to be permitted.

316(b) Cooling Water Intake Structures

The EPA finalized new regulations in July 2004 governing the intake of water at large existing power plants that employ cooling water intake structures. The rule seeks to reduce perceived impacts on aquatic resources by requiring covered facilities to implement technology or other measures to meet EPA-targeted reductions in water use and corresponding perceived aquatic impacts. Entergy, other industry members and industry groups, environmental groups, and a coalition of northeastern and mid-Atlantic states have challenged various aspects of the rule. This challenge currently is lodged in the United States Court of Appeals for the Second Circuit in New York City after a motion to transfer from the Ninth Circuit in San Francisco was granted in December 2004.

Entergy's non-utility nuclear generation business is currently in various stages of the data evaluation and discharge permitting process for its generation facilities. Indian Point is involved in an administrative permitting process with the New York environmental authority for renewal of the Indian Point 2 and 3 discharge permits. In November 2003, the New York State Department of Environmental Conservation (NYDEC) issued a draft permit indicating that closed cycle cooling would be considered the "best technology available" for minimizing perceived adverse environmental impacts attributable to the intake and discharge of cooling water at Indian Point 2 and 3. The draft permit would require Entergy to take certain steps to assess the feasibility of retrofitting the site to install cooling towers before re-licensing Indian Point 2 and 3, whose current licenses with the NRC expire in 2013 and 2015. The draft permit could also require, upon its becoming effective, the facilities to take a n annual 42 unit-day outage and provide a payment into a NYDEC account until the start of cooling tower construction. Entergy is participating in the administrative process in order to have the draft permit modified prior to final issuance and opposes any requirement to install cooling towers or to begin annual outages at Indian Point 2 and 3. Accordingly, Entergy also has filed a separate action in New York state court seeking a determination that the state cooling water intake structure regulation underpinning the NYDEC's draft permit for Indian Point 2 and 3 was improperly promulgated and is thus void. The New York trial court dismissed Entergy's claim, and Entergy has appealed to the New York Court of Appeals. Pilgrim received approval from EPA allowing the full 3 1/2-year schedule for compliance demonstration as is outlined in the new rule and will also pursue appropriate supplementation of the existing record regarding perceived impacts, options and costs. Entergy's other Non-Utility Nuclear gener ation facilities are in the process of reviewing data, considering implementation options, providing information required by the current rule to EPA and the affected states, and requesting the 3 1/2-year submission schedule allowed by the rule, where necessary.

Oil Pollution Prevention Regulation

The EPA published a revised Oil Pollution Prevention rule in July 2002. The rule affects Entergy's operation of its approximately 3,500 transmission and distribution electrical equipment installations that are potentially subject to the rule. While the published rule provides a great deal of flexibility to the regulated community insofar as allowable strategies, it also provided the EPA with a great deal of discretion in evaluation of a facility's compliance with the rule. In September 2004, EPA solicited comments on alternative management strategies for oil-filled electrical equipment that were proposed by the Utility Solid Waste Activities Group and Entergy. Entergy is currently in the final stages of revising existing Integrated Response Plans and Spill Prevention, Control and Countermeasures Plans to meet the requirements of the rule and does not expect significant compliance costs.

Comprehensive Environmental Response, Compensation, and Liability Act of 1980

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

Other Environmental Matters

Entergy Gulf States

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

Entergy Gulf States is currently involved in a remedial investigation of the Lake Charles Service Center site, located in Lake Charles, Louisiana. A manufactured gas plant (MGP) is believed to have operated at this site from approximately 1916 to 1931. Coal tar, a by-product of the distillation process employed at MGPs, was apparently routed to a portion of the property for disposal. The same area has also been used as a landfill. In 1999, Entergy Gulf States signed a second Administrative Consent Order with the EPA to perform removal action at the site. In 2002, approximately 7,400 tons of contaminated soil and debris were excavated and disposed of from an area within the service center. In 2003, a cap was constructed over the remedial area to prevent the migration of contamination to the surface. Entergy Gulf States anticipates commencement of a ten-year groundwater monitoring study upon issuance of a negotiated order by the EPA, which is expected to issue the order in early 2 005. Entergy Gulf States believes that its ultimate responsibility for this site will not materially exceed its existing clean-up provision of $1.5 million.

In 1994, Entergy Gulf States performed a site assessment in conjunction with a construction project at the Louisiana Station Generating Plant (Louisiana Station). In 1995, a further assessment confirmed subsurface soil and groundwater impact to three areas on the plant site. After validation, a notification was made to the LDEQ and a phased process was executed to remediate each area of concern. The final phase of groundwater clean-up and monitoring at Louisiana Station is expected to continue through 2005. The remediation cost incurred through December 31, 2004 for this site was $6.7 million. Future costs are not expected to exceed the existing provision of $0.8 million.

Entergy Louisiana and Entergy New Orleans

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

The Southern Transformer Shop located in New Orleans served both Entergy Louisiana and Entergy New Orleans. This transformer shop is now closed and soil and groundwater assessment activities have resumed since the demolition of the onsite buildings and structures was completed in early 2004. Entergy has entered into the Voluntary Remediation Program with the LDEQ and submitted a Site Investigation Workplan. A liability of approximately $350,000 has been established for environmental assessment and remediation costs with estimated completion by the end of 2005.

During 1993, the LDEQ issued new rules for solid waste regulation, including regulation of wastewater impoundments. Entergy Louisiana and Entergy New Orleans have determined that certain of their power plant wastewater impoundments were affected by these regulations and chose to remediate and repair or close them. Completion of this work is pending LDEQ approval. LDEQ has issued notices of deficiencies for certain of these sites. As a result, recorded liabilities in the amounts of $5.8 million for Entergy Louisiana and $0.5 million for Entergy New Orleans existed at December 31, 2004 for wastewater remediation and repairs and closures. Management of Entergy Louisiana and Entergy New Orleans believes these reserves are adequate based on current estimates.

Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana

The Texas Commission on Environmental Quality (Commission) notified Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana in September through November 2003 that the Commission believes those entities are potentially responsible parties (PRPs) concerning contamination existing at the San Angelo Electric Service Company (SESCO) facility in San Angelo, Texas. The facility operated as a transformer repair and scrapping facility from the 1930s until 2003. Both soil and groundwater contamination exists at the site. Entergy Gulf States and Entergy Louisiana sent transformers to this facility during the 1980s. There has been no indication that Entergy Arkansas ever used this facility. Entergy Gulf States, Entergy Louisiana, and Entergy Arkansas have responded to an information request from the Commission and will continue to cooperate in this investigation. It is likely that Entergy Gulf States and Entergy Louisiana will be required to contribute to the remediation of contaminated gr oundwater at the site, but the contributions likely will be less than those of other SESCO customers that continued to use the site long after 1990, and the list of PRPs who likely will share in the cost is long. Based on current information, the estimate of Entergy's portion of the liability is $0.6 million.

Entergy New Orleans

In March 2004, agents of the United States Fish and Wildlife Service conducted an inspection of Entergy New Orleans' Michoud power plant and found a number of dead brown pelicans near the facility's water intake structure and fish-return trough. Brown pelicans are an endangered species in Louisiana. The United States Attorney's Office for the Eastern District of Louisiana (Attorney's Office) issued a grand jury subpoena to an Entergy New Orleans employee in May 2004 to give evidence regarding the cause of death of the pelicans. The Attorney's Office then agreed to meet with Entergy New Orleans rather than requiring the employee to testify. As a result of that meeting, Entergy New Orleans conducted an internal investigation of the matter and submitted a report to the Attorney's Office in August 2004. Entergy New Orleans also constructed an engineered walkway and cover over the intake structure and feeding trough to eliminate pelican access to the area. Entergy New Orleans continues neg otiations with the Attorney's Office regarding final resolution of this matter.

Litigation

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

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

Entergy New Orleans Fuel Clause Lawsuit

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

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

Entergy New Orleans Rate of Return Lawsuit

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

In December 2003, the Council Advisors filed a motion in the Council proceedings to bifurcate the hearing in this matter, such that the effect of the provision of the 1922 Ordinance in setting lawful rates would be considered first. Only if it is determined that this provision establishes a limitation, would the remaining issues be reached. The motion to bifurcate was granted by the City Council in April 2004, and a hearing on the first part of the bifurcated proceeding is currently scheduled to begin in June 2005.

Texas Power Price Lawsuit

In August 2003, a lawsuit was filed in the district court of Chambers County, Texas by Texas residents on behalf of a purported class apparently of the Texas retail customers of Entergy Gulf States who were billed and paid for electric power from January 1, 1994 to the present. The named defendants are Entergy Corporation, Entergy Services, Entergy Power, Entergy Power Marketing Corp., Arkansas Electric Cooperative Corporation and Entergy Arkansas. Entergy Gulf States is not a named defendant, but is alleged to be a co-conspirator. The court has granted the request of Entergy Gulf States to intervene in the lawsuit to protect its interests.

Plaintiffs allege that the defendants implemented a "price gouging accounting scheme" to sell to plaintiffs and similarly situated utility customers higher priced power generated by the defendants while rejecting and/or reselling to off-system utilities, less expensive power offered and/or purchased from off-system suppliers and/or generated by the Entergy system. In particular, plaintiffs allege that the defendants manipulated and continue to manipulate the dispatch of generation so that power is purchased from affiliated expensive resources instead of buying cheaper off-system power.

Plaintiffs estimate that customers in Texas were charged at least $57 million above prevailing market prices for power. Plaintiffs seek actual, consequential and exemplary damages, costs and attorneys' fees, and disgorgement of profits. In September 2003, the Entergy defendants removed the lawsuit to the federal court in Galveston, and in October 2003, filed a pleading seeking dismissal of the plaintiffs' claims. In October 2003, the plaintiffs filed a motion to remand the case to state court. In January 2004, the federal court determined that it did not have jurisdiction over the subject matter of the lawsuit, and remanded the case to the state district court in Chambers County. In November 2004, the state district court dismissed the case based on a lack of jurisdiction. The plaintiffs have initiated appellate proceedings in the Court of Appeals.

Entergy Louisiana Formula Ratemaking Plan Lawsuit

In May 1998, a group of ratepayers filed a complaint against Entergy Louisiana and the LPSC in state court in East Baton Rouge Parish purportedly on behalf of all Entergy Louisiana ratepayers. The plaintiffs allege that the formula ratemaking plan authorized by the LPSC has allowed Entergy Louisiana to earn amounts in excess of a fair return. The plaintiffs seek, among other things, (i) a declaratory judgment that the formula ratemaking plan is an improper ratemaking practice; and (ii) a refund of the amounts allegedly charged in excess of proper ratemaking practices. This case has not been active, and abandonment issues are being evaluated. At this time, management cannot determine the amount of damages being sought.

Murphy Oil Lawsuit (Entergy Corporation and Entergy Louisiana)

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

Murphy Oil and other defendants settled with the plaintiffs for $8.8 million, but Entergy Louisiana did not participate in the settlement. After trial for the remaining parties in the proceeding, the judge issued a decision finding Entergy Louisiana 40% responsible and awarding monetary damages, which total approximately $11 million with interest against Entergy Louisiana. Entergy Louisiana appealed the judgment to the Court of Appeals. Entergy Louisiana has insurance in place for claims of this type, and management does not expect a material adverse financial effect from this decision.

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

In 1998, a group of property owners filed a class action suit against Entergy Corporation, Entergy Gulf States, Entergy Services and Entergy Technology Holding Company in state court in Jefferson County, Texas purportedly on behalf of all property owners in each of the states throughout the Entergy service area who have conveyed easements to the defendants. The lawsuit alleged that Entergy installed fiber optic cable across their property without obtaining appropriate easements. The plaintiffs sought actual damages for the use of the land and a share of the profits made through use of the fiber optic cables and punitive damages. The state court petition was voluntarily dismissed, and the plaintiffs commenced a class action suit with the same claims in the United States District Court in Beaumont, Texas. Both sides have filed motions for summary judgment, which were heard by the court in late 2001. In 2003, the district judge ruled that as a matter of law, all of the Texas easements pe rmit Entergy to utilize the fiber for their own communications. Further, the court ruled that approximately two-thirds of the Texas easements allow Entergy to use the fiber for external or third party communications. Entergy believes that any damages suffered by the remaining one-third plaintiff landowners are negligible and that there is no basis for the claim seeking a share of profits. In April 2004, the trial court entered an order denying the plaintiffs' request that this case be certified as a class. The plaintiffs have appealed this ruling to the United States Court of Appeals for the Fifth Circuit. At this time, management cannot determine the specific amount of damages being sought.

Several property owners have filed a class action suit against Entergy Louisiana, Entergy Services, ETHC, and Entergy Technology Company in state court in St. James Parish, Louisiana purportedly on behalf of all property owners in Louisiana who have conveyed easements to the defendants. The lawsuit alleges that Entergy installed fiber optic cable across their property without obtaining appropriate easements. The plaintiffs seek actual damages for the use of the land and a share of the profits made through use of the fiber optic cables and punitive damages. Entergy removed the case to federal court in New Orleans; however, the District Court remanded the case back to state court.  While Entergy appealed this ruling, recently the United States Court of Appeals for the Fifth Circuit denied this appeal.  In December 2003, the trial court held a hearing to determine if a class should be certified. On February 18, 2004, the trial court entered an order certifying this matter as a c lass. Entergy has appealed this ruling to the Louisiana Fifth Circuit Court of Appeals, and oral arguments have been held. At this time, management cannot determine the specific amount of damages being sought.

Several property owners have filed separate lawsuits against Entergy Corporation, Entergy Mississippi, Entergy Services, ETHC, and ETC in state court in various counties in Mississippi alleging that Entergy Mississippi installed fiber optic cable across their properties without obtaining appropriate easements. The plaintiffs seek actual damages for the use of the land, a share of the profits made through use of the fiber optic cables, and at least $20 million in punitive damages in one case, and an unspecified amount of punitive damages in the other cases.

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

Numerous lawsuits have been filed in federal and state courts in Texas, Louisiana, and Mississippi primarily by contractor employees in the 1950-1980 timeframe against Entergy Gulf States, Entergy Louisiana, Entergy New Orleans, and Entergy Mississippi as premises owners of power plants, for damages caused by alleged exposure to asbestos or other hazardous material. Many other defendants are named in these lawsuits as well. Currently, there are approximately 480 lawsuits involving approximately 10,000 claims. Reserves have been established that should be adequate to cover any exposure. Additionally, negotiations continue with insurers to recover more reimbursement, while new coverage is being secured to minimize anticipated future potential exposures. Management believes that loss exposure has been and will continue to be handled successfully so that the ultimate resolution of these matters will not be material, in the aggregate, to the companies' financial position or results of operation.

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

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

Included in the employment litigation are two cases filed in state court in Claiborne County, Mississippi in December 2002. The two cases were filed by former employees of Entergy Operations who were based at Grand Gulf. Entergy Operations and Entergy employees are named as defendants. The cases make employment-related claims, and seek in total $53 million in alleged actual damages and $168 million in punitive damages. Entergy subsequently removed both proceedings to the federal district in Jackson, Mississippi. Entergy cannot predict the ultimate outcome of this proceeding.

Research Spending

Entergy is a member of the Electric Power Research Institute (EPRI). EPRI conducts a broad range of research in major technical fields related to the electric utility industry. Entergy participates in various EPRI projects based on Entergy's needs and available resources. The domestic utility companies contributed $1.6 million in 2004, $1.5 million in 2003, and $2.1 million in 2002 to EPRI. The Non-Utility Nuclear business contributed $3.2 million in 2004 and $3 million in both 2003 and 2002 to EPRI.

Employees

Employees are an integral part of Entergy's commitment to serving its customers. As of December 31, 2004, Entergy employed 14,425 people.

U.S. Utility:
Entergy Arkansas	1,494
Entergy Gulf States	1,641
Entergy Louisiana	943
Entergy Mississippi	793
Entergy New Orleans	403
System Energy	-
Entergy Operations	2,735
Entergy Services	2,704
Entergy Nuclear Operations	3,245
Other subsidiaries	277
Total Full-time	14,235
Part-time	190
Total Entergy	14,425

Approximately 4,900 employees are represented by the International Brotherhood of Electrical Workers Union, the Utility Workers Union of America, and the International Brotherhood of Teamsters Union.

ENTERGY ARKANSAS, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

2004 Compared to 2003

Net income increased $16.2 million due to lower other operation and maintenance expenses, a lower effective income tax rate for 2004 compared to 2003, and lower interest charges. The increase was partially offset by lower net revenue.

2003 Compared to 2002

 Net income decreased $9.6 million due to lower net revenue, higher depreciation and amortization expenses, and a higher effective income tax rate for 2003 compared to 2002. The decrease was substantially offset by lower other operation and maintenance expenses, higher other income, and lower interest charges.

Net Revenue

2004 Compared to 2003

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

	(In Millions)
2003 net revenue	$998.7
Deferred fuel cost revisions	(16.9)
Other	(3.4)
2004 net revenue	$978.4

Deferred fuel cost revisions includes the difference between the estimated deferred fuel expense and the actual calculation of recoverable fuel expense, which occurs on an annual basis. Deferred fuel cost revisions decreased net revenue due to a revised estimate of fuel costs filed for recovery at Entergy Arkansas in the March 2004 energy cost recovery rider, which reduced net revenue by $11.5 million. The remainder of the variance is due to the 2002 energy cost recovery true-up, made in the first quarter of 2003, which increased net revenue in 2003.

Gross operating revenues, fuel and purchased power expenses, and other regulatory credits

          Gross operating revenues increased primarily due to:

• an increase of $20.7 million in fuel cost recovery revenues due to an increase in the energy cost recovery rider effective April 2004 (fuel cost recovery revenues are discussed in Note 2 to the domestic utility companies and System Energy financial statements);
• an increase of $15.5 million in Grand Gulf revenues due to an increase in the Grand Gulf rider effective January 2004;
• an increase of $13.9 million in gross wholesale revenue primarily due to increased sales to affiliated systems; and
• an increase of $9.5 million due to volume/weather primarily resulting from increased usage during the unbilled sales period, partially offset by the effect of milder weather on billed sales in 2004.

Fuel and purchased power expenses increased primarily due to increased recovery of deferred fuel and purchased power costs primarily due to an increase in April 2004 in the energy cost recovery rider and the true-ups to the 2003 and 2002 energy cost recovery rider filings.

Other regulatory credits decreased primarily due to the over-recovery of Grand Gulf costs due to an increase in the Grand Gulf rider effective January 2004.

2003 Compared to 2002

Net revenue, which is Entergy Arkansas' 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	$1,095.9
March 2002 settlement agreement	(154.0)
Volume/weather	(7.7)
Asset retirement obligation	30.1
Net wholesale revenue	16.6
Deferred fuel cost revisions	10.2
Other	7.6
2003 net revenue	$998.7

The March 2002 settlement agreement resolved a request for recovery of ice storm costs incurred in December 2000 with an offset of those costs for funds contributed to pay for future stranded costs. A 1997 settlement provided for the collection of earnings in excess of an 11% return on equity in a transition cost account (TCA) to offset stranded costs if retail open access were implemented.

In mid- and late December 2000, two separate ice storms left 226,000 and 212,500 Entergy Arkansas customers, respectively, without electric power in its service area. Entergy Arkansas filed a proposal to recover costs plus carrying charges associated with power restoration caused by the ice storms. Entergy Arkansas' final storm damage cost determination reflected costs of approximately $195 million. The APSC approved a settlement agreement submitted in March 2002 by Entergy Arkansas, the APSC staff, and the Arkansas Attorney General. In the March 2002 settlement, the parties agreed that $153 million of the ice storm costs would be classified as incremental ice storm expenses that can be offset against the TCA on a rate class basis, and any excess of ice storm costs over the amount available in the TCA would be deferred and amortized over 30 years, although such excess costs were not allowed to be included as a separate component of rate base. The a llocated ice storm expenses exceeded the available TCA funds by $15.8 million which was recorded as a regulatory asset in June 2002. In accordance with the settlement agreement and following the APSC's approval of the 2001 earnings review related to the TCA, Entergy Arkansas filed to return $18.1 million of the TCA to certain large general service class customers that paid more into the TCA than their allocation of storm costs. The APSC approved the return of funds to the large general service customer class in the form of refund checks in August 2002. As part of the implementation of the March 2002 settlement agreement provisions, the TCA procedure ceased with the 2001 earnings evaluation.

Of the remaining ice storm costs, $32.2 million was addressed through established ratemaking procedures, including $22.2 million classified as capital additions, while $3.8 million of the ice storm costs was not recovered through rates.

The effect on net income of the March 2002 settlement agreement and 2001 earnings review was a $2.2 million increase in 2003, because the decrease in net revenue was offset by the decrease in operation and maintenance expenses discussed below.

The volume/weather variance is the result of less favorable sales volume primarily due to the effect of colder winter weather in December 2002.

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

The net wholesale revenue variance was primarily due to an increase in sales volume to Entergy New Orleans pursuant to a purchased power agreement and also due to higher wholesale prices and volume.

Deferred fuel cost revisions includes the difference between the estimated deferred fuel expense and the actual calculation of recoverable fuel expense, which occurs on an annual basis. In 2002, the deferred fuel expense estimate was larger than the actual recoverable fuel expense, which decreased net revenue. In 2003, the actual recoverable fuel expense was larger than the deferred fuel expense estimate, which increased net revenue.

Gross operating revenues, fuel and purchased power expenses, and other regulatory credits

Gross operating revenues increased primarily due to an increase of $95.7 million in gross wholesale revenue due to the same factors discussed above that increased net wholesale revenue and also due to increased sales to affiliates in addition to the Entergy New Orleans sales mentioned above. The increase was partially offset by a decrease of $74.4 million in fuel cost recovery revenues due to a decrease in the annual recovery rider in October 2002.

Fuel and purchased power expenses decreased primarily due to the displacement of higher-priced natural gas generation by lower-priced purchased power and coal generation.

Other regulatory credits decreased primarily due to the March 2002 settlement agreement and 2001 earnings review mentioned above, which increased other regulatory credits in 2002 to offset $159.9 million in other operation and maintenance expenses related to the December 2000 ice storms. The decrease was partially offset by the asset retirement obligation mentioned above, which increased regulatory credits in 2003 to offset the increase in decommissioning expense.

Other Income Statement Variances

2004 Compared to 2003

Other operation and maintenance expenses decreased primarily due to voluntary severance accruals of $31.8 million in 2003. The decrease was partially offset by the following:

• an increase of $6.6 million in customer service support costs; and
• an increase of $5.1 million in benefits costs.

Interest charges decreased primarily due to the refinancing of First Mortgage Bonds in mid-2003.

2003 Compared to 2002

Other operation and maintenance expenses decreased primarily due to expenses in 2002 of $159.9 million due to the March 2002 settlement agreement and 2001 earnings review which allowed Entergy Arkansas to recover a large majority of 2000 and 2001 ice storm repair expenses through the previously-collected transition cost account amounts (which was offset by a corresponding decrease in other regulatory credits and has no effect on net income). Decreases of $18.7 million in administrative and general expenses and $4.7 million in contract labor costs also contributed to the decrease. The decrease was partially offset by the following:

• voluntary severance accruals of $31.8 million in 2003; and
• an increase of $10.4 million in benefits costs.

Decommissioning expense increased due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations." The increase in decommissioning expense was offset by increases in other regulatory credits and interest and dividend income and has no effect on net income.

Depreciation and amortization expenses increased primarily due to an increase in plant in service.

Other income increased primarily due to:

• an increase of $7.3 million in interest and dividend income due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations." As mentioned above, the increase was offset in decommissioning expense and has no effect on net income; and
• an increase of $4.8 million in the allowance for equity funds used during construction due to an increase in construction work in progress.

Interest charges decreased primarily due to:

• an increase in interest expense in 2002 resulting from a true-up of the annual fuel recovery rider in March 2002 of $4.5 million;
• interest recorded in 2002 of $4.1 million (offset by a corresponding decrease in other regulatory credits and has no effect on net income) on the transition cost account obligation, which was terminated as a result of the March 2002 settlement agreement; and
• an increase in 2003 of $3.0 million in the allowance for borrowed funds used during construction due to an increase in construction work in progress.

Income Taxes

The effective income tax rates for 2004, 2003, and 2002 were 38.5%, 45.5%, and 34.5%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate. The lower effective income tax rate in 2004 compared to 2003 was primarily due to book and tax differences related to utility plant items and flow-through items.  Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued on the balance sheet.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2004, 2003, and 2002 were as follows:

		2004	2003	2002
		(In Thousands)
Cash and cash equivalents at beginning of period		$8,834	$95,513	$103,466
Cash flow provided by (used in):
	Operating activities	446,298	437,520	357,421
	Investing activities	(269,385)	(337,509)	(249,438)
	Financing activities	(96,003)	(186,690)	(115,936)
	Net increase (decrease) in cash and cash equivalents	80,910	(86,679)	(7,953)
Cash and cash equivalents at end of period		$89,744	$8,834	$95,513

Operating Activities

Cash flow from operations increased $8.8 million in 2004 compared to 2003 primarily due to income tax benefits received in 2004, and increased recovery of deferred fuel costs. This increase was substantially offset by money pool activity.

In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $1.171 billion deduction for Entergy Arkansas on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. In 2004, Entergy Arkansas realized $173 million in cash tax benefit from the method change. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit.  As of December 31, 2004, Entergy Arkansas has a net operating loss (NOL) carryforward for tax purposes of $766.9 million, principally resulting from the change in tax accounting method related to cost of goods sold.  If the tax accounting method change is sustained, Entergy Arkansas expects to utilize the NOL carryforward through 2006.

Cash flow from operations increased $80.1 million in 2003 compared to 2002 primarily due to income taxes paid of $2.2 million in 2003 compared to income taxes paid of $83.9 million in 2002, and money pool activity. This increase was partially offset by decreased recovery of deferred fuel costs in 2003.

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

2004	2003	2002	2001
(In Thousands)
$23,561	($69,153)	$4,279	$23,794

Money pool activity used $92.7 million of Entergy Arkansas' operating cash flow in 2004, provided $73.4 million in 2003, and provided $19.5 million in 2002. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.

Investing Activities

The decrease of $68.1 million in net cash used in investing activities in 2004 compared to 2003 was primarily due to a decrease in construction expenditures resulting from less transmission upgrade work requested by merchant generators in 2004 combined with lower spending on customer support projects in 2004.

The increase of $88.1 million in net cash used in investing activities in 2003 compared to 2002 was primarily due to an increase in construction expenditures of $57.4 million and the maturity of $38.4 million of other temporary investments in the first quarter of 2002. Construction expenditures increased in 2003 primarily due to the following:

• a FERC ruling that shifted responsibility for transmission upgrade work performed for independent power producers to Entergy Arkansas; and
• the ANO 1 steam generator, reactor vessel head, and transformer replacement project.

Financing Activities

The decrease of $90.7 million in net cash used in financing activities in 2004 compared to 2003 was primarily due to the net redemption of $2.4 million of long-term debt in 2004 compared to $109.3 million in 2003, partially offset by the payment of $16.2 million more in common stock dividends during the same period.

The increase of $70.8 million in net cash used in financing activities in 2003 compared to 2002 was primarily due to the net redemption of $109.3 million of long-term debt in 2003 compared to the net issuance of $18.4 million in 2002, partially offset by the payment of $56.3 million less in common stock dividends during the same period.

See Note 5 to the domestic utility companies and System Energy financial statements for details on long-term debt.

Uses of Capital

Entergy Arkansas requires capital resources for:

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

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

	2005	2006-2007	2008-2009	after 2009	Total
	(In Millions)
Planned construction and
capital investment (1)	$321	$455	N/A	N/A	$776
Long-term debt	$147	$-	$1	$1,191	$1,339
Capital lease payments	$10	$9	$2	$2	$23
Operating leases	$24	$38	$23	$54	$139
Purchase obligations (2)	$433	$832	$827	$2,840	$4,932
Nuclear fuel lease obligations (3)	$42	$52	N/A	N/A	$94

(1)	Includes approximately $175 to $180 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth.
(2)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Arkansas almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the domestic utility companies and System Energy financial statements.
(3)	It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. If such additional financing cannot be arranged, however, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations.

In addition to these contractual obligations, Entergy Arkansas expects to contribute $20.6 million to its pension plans and $16.1 million to other postretirement plans in 2005.

On July 25, 2002, the Board authorized Entergy Arkansas and Entergy Operations to replace the ANO 1 steam generators and reactor vessel closure head. Entergy management estimates the cost of the fabrication and replacement to be approximately $235 million, of which approximately $96 million has been incurred through 2004. $115 million is expected to be incurred in 2005, with the remainder of the costs expected in 2006. Management expects that the replacement will occur during a planned refueling outage in 2005. Entergy Arkansas filed with the APSC in January 2003 a request for a declaratory order that the investment in the replacement is in the public interest. The APSC issued the requested order in May 2003. This order is analogous to the order received in 1998 prior to the replacement of the ANO 2 steam generators. See ''Nuclear Matters'' below for further discussion of the replacement of the ANO 1 steam generators and reactor vessel closure head.

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

As a wholly-owned subsidiary, Entergy Arkansas pays dividends to Entergy Corporation from its earnings at a percentage determined monthly. Entergy Arkansas' long-term debt indentures restrict the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock. As of December 31, 2004, Entergy Arkansas had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million.

Sources of Capital

Entergy Arkansas' sources to meet its capital requirements include:

• internally generated funds;
• cash on hand;
• debt or preferred stock issuances; and
• bank financing under new or existing facilities (Entergy Arkansas has a 364-day credit facility available with an expiration date of April 2005 in the amount of $85 million, of which none was drawn at December 31, 2004).

Entergy Arkansas issued first mortgage bonds in 2004 as follows:

Issue Date	Description	Maturity	Amount
			(In Thousands)
October 2004	6.38% Series	November 2034	$60,000

The proceeds were used to redeem junior subordinated debentures as follows:

Retirement Date	Description	Maturity	Amount
			(In Thousands)
November 2004	8.50% Series	September 2045	$61,856

Entergy Arkansas may refinance or redeem debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common and preferred stock issuances by Entergy Arkansas require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.

Short-term borrowings by Entergy Arkansas, including borrowings under the money pool, are limited to an amount authorized by the SEC, which is $235 million. Under its SEC Order and without further authorization, Entergy Arkansas cannot incur additional short-term indebtedness unless (a) it and Entergy Corporation maintain a common equity ratio of at least 30% and (b) with the exception of money pool borrowings, the security to be issued (if rated) and all outstanding securities of Entergy Arkansas, as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy Arkansas' short-term borrowing limits.

Significant Factors and Known Trends

Utility Restructuring

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

At FERC, restructuring at the wholesale level has begun but has been delayed. It is too early to predict the ultimate effects of changes in U.S. energy markets. Restructuring issues are complex and are continually affected by events at the national, regional, state, and local levels. However, these changes may result, in the long term, in fundamental changes in the way traditional integrated utilities and holding company systems, like the Entergy system, conduct their business. Some of these changes may be positive for Entergy, while others may not.

System Agreement Proceedings

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

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

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

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

	Range of Annual Payments or (Receipts)	Average Annual Payments or (Receipts) for 2005-2009 Period
	(In Millions)	(In Millions)
Entergy Arkansas	$154 to $281	$215
Entergy Gulf States	($130) to ($15)	($63)
Entergy Louisiana	($199) to ($98)	($141)
Entergy Mississippi	($16) to $8	$1
Entergy New Orleans	($17) to ($5)	($12)

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

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

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

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

Transmission

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

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

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

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

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

Interconnection Orders

The domestic utility companies (except Entergy New Orleans) are currently defendants to several complaints and rehearing requests before the FERC in which independent generation entities (GenCos) are seeking a refund of monies that the GenCos had previously paid to the Entergy companies for facilities necessary to connect their generation facilities to Entergy's transmission system. The FERC has issued initial orders in response to two of the complaints and in certain other dockets ordering Entergy to refund approximately $100 million in expenses and tax obligations previously paid by the GenCos, including $42 million for Entergy Arkansas. The refunds will be in the form of transmission credits that will be utilized over time as the GenCos take transmission service from Entergy. To the extent the Entergy companies are ordered to provide such refunds, these costs will qualify for inclusion in the Entergy companies' rates. The recovery of these costs is not automatic, however, especially at the retail level, where the majority of the cost recovery would occur. Entergy intends to pursue all regulatory and legal avenues available to it in order to ha ve these orders reversed and have the affected interconnection agreements reinstated as agreed to originally by the generators.

Available Flowgate Capacity Proceeding

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

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

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

Market and Credit Risks

Entergy Arkansas has certain market and credit risks inherent in its business operations. Market risks represent the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement.

Interest Rate and Equity Price Risk - Decommissioning Trust Funds

Entergy Arkansas' nuclear decommissioning trust funds are exposed to fluctuations in equity prices and interest rates. The NRC requires Entergy Arkansas to maintain trusts to fund the costs of decommissioning ANO 1 and ANO 2. The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that its exposure to market fluctuations will not affect results of operations for the ANO trust funds because of the application of regulatory accounting principles. The decommissioning trust funds are discussed more thoroughly in Notes 1, 8, and 12 to the domestic utility companies and System Energy financial statements.

State and Local Rate Regulatory Risks

The rates that Entergy Arkansas charges for its services are an important item influencing Entergy Arkansas' financial position, results of operations, and liquidity. Entergy Arkansas is closely regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the APSC, is primarily responsible for approval of the rates charged to customers. Entergy Arkansas' fuel costs recovered from customers are also subject to regulatory scrutiny. Refer to Note 2 to the domestic utility companies and System Energy financial statements for fuel recovery and retail rate proceedings.

Nuclear Matters

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

In August 2001, the NRC issued a bulletin requesting all pressurized water reactor owners and operators to report on the structural integrity of their reactor vessel head penetration nozzles to justify continued operations past December 31, 2001. These types of reactors are susceptible to stress corrosion cracking of the reactor vessel head nozzles. ANO 1 and ANO 2 are pressurized water reactors. In December 2001, Entergy issued a request for proposal to provide replacement steam generators for ANO 1. Entergy subsequently entered a contract for delivery of the replacement generators in August 2005 in time for installation during the scheduled refueling outage. Both the new steam generators and the reactor vessel head will be installed in the fall of 2005. To date, there has been no primary side stress corrosion cracking identified in the ANO 2 reactor vessel head. Inspections of the ANO 2 reactor vessel head will continue during planned refueling outages.

Entergy Arkansas filed with the APSC in January 2003 a request for a declaratory order that the investment in the replacement is in the public interest. The APSC issued the requested order in May 2003. This order is analogous to the order received in 1998 prior to the replacement of the ANO 2 steam generators.

Environmental Risks

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

Critical Accounting Estimates

The preparation of Entergy Arkansas' financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy Arkansas' financial position or results of operations.

Nuclear Decommissioning Costs

Regulations require Entergy Arkansas to decommission the ANO 1 and ANO 2 nuclear power plants after the facilities are taken out of service, and money is collected and deposited in trust funds during the facilities' operating lives in order to provide for this obligation. Entergy Arkansas conducts periodic decommissioning cost studies (typically updated every five years) to estimate the costs that will be incurred to decommission the facilities. The following key assumptions have a significant effect on these estimates:

• Cost Escalation Factors - Entergy Arkansas' decommissioning studies include an assumption that decommissioning costs will escalate over present cost levels by an annual factor approximating CPI-U. A 50 basis point change in this assumption could change the ultimate cost of decommissioning a facility by as much as 11%.
• Timing - The date of the plant's retirement must be estimated and an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in "safestore" status for later decommissioning, as permitted by applicable regulations. While the effect of these assumptions cannot be determined with precision, assuming either license extension or use of a "safestore" status can possibly decrease the present value of these obligations. As discussed in Note 8 to the domestic utility companies and System Energy financial statements, Entergy Arkansas recorded a revision in 2004 to its estimated decommissioning cost liability for ANO 1 and ANO 2 to reflect changes due to a new decommissioning study.  The changes in probability for ANO 1 and ANO 2 had no effect on net income because, as discussed further below, any amounts recorded related to SFAS 143 are offset by the recording of regulatory assets or regulatory liabilities when projected decommissioning costs are collected in rates.
• Spent Fuel Disposal - Federal regulations require the DOE to provide a permanent repository for the storage of spent nuclear fuel, and legislation has been passed by Congress to develop this repository at Yucca Mountain, Nevada. Until this site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities can have a significant effect (as much as 16% of estimated decommissioning costs). These estimates could change in the future based on the timing of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors.
• Technology and Regulation - To date, there is limited practical experience in the United States with actual decommissioning of large nuclear facilities. As experience is gained and technology changes, cost estimates could also change. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant effect on cost estimates. The effect of these potential changes is not presently determinable. Entergy Arkansas' decommissioning cost studies assume current technologies and regulations.

Through 2001, Entergy Arkansas collected the projected costs of decommissioning ANO 1 and ANO 2 through rates charged to customers. Now, based on assumptions approved by the APSC, including an assumed license extension for ANO 2 (ANO 1's license has already been extended), which significantly extends the earnings period, and the sufficiency of previously collected funds, Entergy Arkansas is not collecting additional funds to decommission ANO 1 and ANO 2 in its current rates. The assumptions will be reviewed annually and reflected in Entergy Arkansas' filing of its annual determination of the nuclear decommissioning rate rider. The amounts that were collected through rates, which were based upon decommissioning cost studies, were deposited in decommissioning trust funds.

SFAS 143

Entergy Arkansas implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs comprise substantially all of Entergy Arkansas' asset retirement obligations, and the measurement and recording of Entergy Arkansas' decommissioning obligations outlined above 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 of Entergy Arkansas to increase significantly, as Entergy Arkansas had previously only recorded this obligation as the related costs were collected from customers, and as earnings were recorded on the related trust funds.
• Fair value approach - SFAS 143 requires that these obligations be measured using a fair value approach. Among other things, this entails the assumption that the costs will be incurred by a third party and will therefore include appropriate profit margins and risk premiums. Entergy Arkansas' decommissioning studies to date have been based on Entergy Arkansas performing the work, and have not included any such margins or premiums. Inclusion of these items increases cost estimates.
• Discount rate - SFAS 143 requires that these obligations be discounted using a credit-adjusted risk-free rate.

The net effect of implementing this standard for Entergy Arkansas was recorded as a regulatory asset, with no resulting impact on Entergy Arkansas' net income. Entergy Arkansas recorded this regulatory asset because its existing rate mechanism is based on the original or historical cost standard that allows Entergy Arkansas to recover all ultimate costs of decommissioning existing assets from current and future customers. Upon implementation, assets and liabilities increased by $532 million in 2003 as a result of recording the asset retirement obligation at its fair value as determined under SFAS 143, increasing total utility plant by $106 million, reducing accumulated depreciation by $252 million, and recording the related regulatory asset of $174 million.

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

Unbilled Revenue

As discussed in Note 1 to the domestic utility companies and System Energy financial statements, Entergy Arkansas records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation including changes to estimates such as line loss, which affects the estimate of unbilled customer usage, and assumptions regarding price such as the fuel cost recovery mechanism.

Pension and Other Postretirement Benefits

Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 10 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.

Assumptions

Key actuarial assumptions utilized in determining these costs include:

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

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

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

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

Cost Sensitivity

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

Actuarial Assumption	Change in Assumption	Impact on 2004 Pension Cost	Impact on Projected Benefit Obligation
	Increase/(Decrease)
Discount rate	(0.25%)	$2,001	$20,608
Rate of return on plan assets	(0.25%)	$1,055	-
Rate of increase in compensation	0.25%	$907	$5,200

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

Actuarial Assumption	Change in Assumption	Impact on 2004 Postretirement Benefit Cost	Impact on Accumulated Postretirement Benefit Obligation
	Increase/(Decrease)
Health care cost trend	0.25%	$557	$3,633
Discount rate	(0.25%)	$342	$4,623

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

Accounting Mechanisms

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

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

Costs and Funding

Total pension cost for Entergy Arkansas in 2004 was $16.5 million. Entergy Arkansas anticipates 2005 pension cost to increase to $21.8 million due to decrease in the discount rate (from 6.25% to 6.00%) and the expected rate of return (from 8.75% to 8.5%) used to calculate benefit obligations. Entergy Arkansas contributed $5.3 million to its pension plan in 2004, and anticipates making $20.6 million in contributions in 2005. The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, partially offset by the Pension Funding Equity Act relief passed in April 2004.

Entergy Arkansas' accumulated benefit obligation at December 31, 2004, 2003, and 2002 exceeded plan assets. As a result, Entergy Arkansas was required to recognize an additional minimum liability as prescribed by SFAS 87 at December 31, 2004, 2003, and 2002. At December 31, 2004, Entergy Arkansas increased its additional minimum liability to $81.2 million from $54.9 million at December 31, 2003. Entergy Arkansas decreased its intangible asset for the unrecognized prior service cost to $10.3 million at December 31, 2004 from $13.3 million at December 31, 2003. Entergy Arkansas also increased the regulatory asset to $70.8 million at December 31, 2004 from $41.6 million at December 31, 2003. Net income for 2004, 2003, and 2002 was not impacted.

Total postretirement health care and life insurance benefit costs for Entergy Arkansas in 2004 were $12.8 million, including $5 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Arkansas expects 2005 postretirement health care and life insurance benefit costs to approximate $13.7 million, including $5.8 million in savings due to the estimated effect of future Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the decrease in the discount rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate used to calculate benefit obligations.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Entergy Arkansas, Inc.:

We have audited the accompanying balance sheets of Entergy Arkansas, Inc. as of December 31, 2004 and 2003, and the related statements of income, retained earnings, and cash flows (pages 165 through 170 and applicable items in pages 284 through 348) for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Arkansas, Inc. as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 5 and Note 8 to the notes to respective financial statements, in 2003 Entergy Arkansas, Inc. adopted the provisions of Statement of Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, and Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

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

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 8, 2005

ENTERGY ARKANSAS, INC.
INCOME STATEMENTS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
OPERATING REVENUES
Domestic electric	$1,653,145	$1,589,670	$1,561,110
OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and
gas purchased for resale	210,394	153,866	294,244
Purchased power	484,849	476,447	355,211
Nuclear refueling outage expenses	24,568	23,638	24,387
Other operation and maintenance	384,424	402,108	543,677
Decommissioning	32,902	35,887	- -
Taxes other than income taxes	35,848	37,385	38,127
Depreciation and amortization	206,926	202,497	187,525
Other regulatory credits - net	(20,501)	(39,347)	(184,270)
TOTAL	1,359,410	1,292,481	1,258,901
OPERATING INCOME	293,735	297,189	302,209
OTHER INCOME
Allowance for equity funds used during construction	11,737	12,153	7,324
Interest and dividend income	10,298	9,790	2,467
Miscellaneous - net	(6,354)	(4,332)	(6,442)
TOTAL	15,681	17,611	3,349
INTEREST AND OTHER CHARGES
Interest on long-term debt	79,521	87,666	89,923
Other interest - net	4,909	3,555	13,287
Allowance for borrowed funds used during construction	(6,288)	(7,726)	(4,699)
TOTAL	78,142	83,495	98,511
INCOME BEFORE INCOME TAXES	231,274	231,305	207,047
Income taxes	89,064	105,296	71,404
NET INCOME	142,210	126,009	135,643
Preferred dividend requirements and other	7,776	7,776	7,776
EARNINGS APPLICABLE TO
COMMON STOCK	$134,434	$118,233	$127,867
See Notes to Respective Financial Statements.

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ENTERGY ARKANSAS, INC.
STATEMENTS OF CASH FLOWS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
OPERATING ACTIVITIES
Net income	$142,210	$126,009	$135,643
Adjustments to reconcile net income to net cash flow provided by operating activities:
Reserve for regulatory adjustments	3,099	1,739	- -
Other regulatory credits - net	(20,501)	(39,347)	(184,270)
Depreciation, amortization, and decommissioning	239,828	238,384	187,525
Deferred income taxes and investment tax credits	65,847	48,357	54,955
Changes in working capital:
Receivables	(86,564)	(29,616)	50,898
Fuel inventory	2,424	4,159	(6,509)
Accounts payable	(40,871)	40,615	39,077
Taxes accrued	137,767	48,791	(69,812)
Interest accrued	(48)	(6,348)	(2,772)
Deferred fuel costs	6,880	(46,333)	59,849
Other working capital accounts	4,753	(79,331)	(33,698)
Provision for estimated losses and reserves	(5,172)	8,686	(9,952)
Changes in other regulatory assets	37,668	(54,745)	182,244
Other	(41,022)	176,500	(45,757)
Net cash flow provided by operating activities	446,298	437,520	357,421
INVESTING ACTIVITIES
Construction expenditures	(270,427)	(334,556)	(277,189)
Allowance for equity funds used during construction	11,737	12,153	7,324
Nuclear fuel purchases	(8,101)	(60,685)	(68,127)
Proceeds from sale/leaseback of nuclear fuel	8,101	60,685	68,127
Decommissioning trust contributions and realized
change in trust assets	(8,860)	(8,279)	(17,970)
Changes in other investments - net	1,856	- -	38,397
Other regulatory investments	(3,691)	(6,827)	- -
Net cash flow used in investing activities	(269,385)	(337,509)	(249,438)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	59,429	361,726	188,407
Retirement of long-term debt	(61,856)	(471,040)	(170,000)
Changes in short-term borrowings	- -	- -	(667)
Dividends paid:
Common stock	(85,800)	(69,600)	(125,900)
Preferred stock	(7,776)	(7,776)	(7,776)
Net cash flow used in financing activities	(96,003)	(186,690)	(115,936)
Net increase (decrease) in cash and cash equivalents	80,910	(86,679)	(7,953)
Cash and cash equivalents at beginning of period	8,834	95,513	103,466
Cash and cash equivalents at end of period	$89,744	$8,834	$95,513
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid/(received) during the period for:
Interest - net of amount capitalized	$78,144	$91,142	$100,965
Income taxes	($103,476)	$2,177	$83,911
Noncash investing and financing activities:
Long-term debt refunded with proceeds from
long-term debt issued in prior periods	- -	- -	($47,000)
See Notes to Respective Financial Statements.

ENTERGY ARKANSAS, INC.
BALANCE SHEETS
ASSETS
	December 31,
	2004	2003
	(In Thousands)
CURRENT ASSETS
Cash and cash equivalents:
Cash	$7,133	$8,834
Temporary cash investments - at cost,
which approximates market	82,611	- -
Total cash and cash equivalents	89,744	8,834
Accounts receivable:
Customer	87,131	69,036
Allowance for doubtful accounts	(11,039)	(9,020)
Associated companies	72,472	50,390
Other	72,425	30,930
Accrued unbilled revenues	71,643	64,732
Total accounts receivable	292,632	206,068
Deferred fuel costs	7,368	10,557
Accumulated deferred income taxes	27,306	18,362
Fuel inventory - at average cost	4,298	6,722
Materials and supplies - at average cost	85,076	80,506
Deferred nuclear refueling outage costs	16,485	19,793
Prepayments and other	6,154	23,938
TOTAL	529,063	374,780
OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity	11,208	11,212
Decommissioning trust funds	383,784	360,485
Non-utility property - at cost (less accumulated depreciation)	1,453	1,456
Other	2,976	4,832
TOTAL	399,421	377,985
UTILITY PLANT
Electric	6,124,359	5,948,090
Property under capital lease	17,500	24,047
Construction work in progress	226,172	238,807
Nuclear fuel under capital lease	93,855	102,691
Nuclear fuel	12,201	7,466
TOTAL UTILITY PLANT	6,474,087	6,321,101
Less - accumulated depreciation and amortization	2,753,525	2,627,441
UTILITY PLANT - NET	3,720,562	3,693,660
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
SFAS 109 regulatory asset - net	101,658	128,311
Other regulatory assets	400,174	437,544
Other	42,514	45,798
TOTAL	544,346	611,653
TOTAL ASSETS	$5,193,392	$5,058,078
See Notes to Respective Financial Statements.
ENTERGY ARKANSAS, INC.
BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
	December 31,
	2004	2003
	(In Thousands)
CURRENT LIABILITIES
Currently maturing long-term debt	$147,000	$ -
Accounts payable:
Associated companies	68,829	106,958
Other	89,896	92,638
Customer deposits	41,639	37,693
Taxes accrued	35,874	- -
Interest accrued	21,376	21,424
Obligations under capital leases	49,816	59,089
Other	19,648	16,924
TOTAL	474,078	334,726
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	1,121,623	996,455
Accumulated deferred investment tax credits	68,452	73,280
Obligations under capital leases	61,538	67,648
Other regulatory liabilities	67,362	52,923
Decommissioning	492,745	567,546
Accumulated provisions	34,977	40,149
Long-term debt	1,191,763	1,338,378
Other	237,447	192,200
TOTAL	3,275,907	3,328,579
Commitments and Contingencies
SHAREHOLDERS' EQUITY
Preferred stock without sinking fund	116,350	116,350
Common stock, $0.01 par value, authorized 325,000,000
shares; issued and outstanding 46,980,196 shares in 2004
and 2003	470	470
Paid-in capital	591,127	591,127
Retained earnings	735,460	686,826
TOTAL	1,443,407	1,394,773
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$5,193,392	$5,058,078
See Notes to Respective Financial Statements.

ENTERGY ARKANSAS, INC.
STATEMENTS OF RETAINED EARNINGS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
Retained Earnings, January 1	$686,826	$638,193	$636,226
Add:
Net income	142,210	126,009	135,643
Deduct:
Dividends declared:
Preferred stock	7,776	7,776	7,776
Common stock	85,800	69,600	125,900
Total	93,576	77,376	133,676
Retained Earnings, December 31	$735,460	$686,826	$638,193
See Notes to Respective Financial Statements.

ENTERGY ARKANSAS, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
	2004	2003	2002	2001	2000
	(In Thousands)
Operating revenues	$1,653,145	$1,589,670	$1,561,110	$1,776,776	$1,762,635
Net Income	$142,210	$126,009	$135,643	$178,185	$137,047
Total assets	$5,193,392	$5,058,078	$4,569,511	$4,451,580	$4,228,211
Long-term obligations (1)	$1,253,301	$1,406,026	$1,246,567	$1,417,262	$1,401,062
(1) Included long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations.
	2004	2003	2002	2001	2000
	(Dollars In Millions)
Electric Operating Revenues:
Residential	$539	$526	$556	$586	$561
Commercial	305	291	304	330	307
Industrial	318	305	330	371	353
Governmental	16	15	15	16	15
Total retail	1,178	1,137	1,205	1,303	1,236
Sales for resale:
Associated companies	250	234	165	240	246
Non-associated companies	186	188	164	201	235
Other	39	31	27	33	46
Total	$1,653	$1,590	$1,561	$1,777	$1,763
Billed Electric Energy Sales (GWh):
Residential	7,028	7,057	7,050	6,918	6,791
Commercial	5,428	5,328	5,221	5,162	5,063
Industrial	7,004	6,999	7,074	7,052	7,240
Governmental	275	266	255	245	239
Total retail	19,735	19,650	19,600	19,377	19,333
Sales for resale:
Associated companies	7,437	7,036	6,811	7,217	6,513
Non-associated companies	4,911	5,399	5,069	4,909	5,537
Total	32,083	32,085	31,480	31,503	31,383

ENTERGY GULF STATES, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

2004 Compared to 2003

Net income increased $149.7 million primarily due to the following:

• the $107.7 million accrual ($65.6 million net-of-tax) in June 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 domestic utility companies and System Energy financial statements for more details regarding the River Bend abeyed plant costs;
• the $21.3 million net-of-tax cumulative effect of accounting change in 2003 due to the implementation of SFAS 143. See "Critical Accounting Estimates" below for more information on the implementation of SFAS 143;
• an increase if $39.7 million (pre-tax) in net revenue, as discussed below;
• miscellaneous income of $27.7 million (pre-tax) resulting from a revision of the decommissioning liability for River Bend and of $10 million (pre-tax) resulting from a reduction in the loss provision for an environmental clean-up site, both of which occurred in 2004 and are discussed below;
• a decrease of $23.2 million (pre-tax) in interest charges on long-term debt, as discussed below; and
• a decrease of $12.0 million (pre-tax) in other operation and maintenance expenses, as discussed below.

The increase was partially offset by a higher effective income tax rate.

2003 Compared to 2002

Entergy Gulf States experienced a significant decline in net income in 2003 compared to 2002 primarily due to the following:

• the $107.7 million accrual ($65.6 million net-of-tax) for the loss that would be associated with a final, nonappealable decision disallowing abeyed River Bend plant costs. See Note 2 to the domestic utility companies and System Energy financial statements for more details regarding the River Bend abeyed plant costs;
• the $21.3 million net-of-tax cumulative effect of accounting change due to the implementation of SFAS 143. See "Critical Accounting Estimates" below for more information on the implementation of SFAS 143;
• a decrease of $20.6 million (pre-tax) in net revenue, as discussed below; and
• an increase of $19.2 million (pre-tax) in other operation and maintenance expenses, as discussed below.

The decrease was partially offset by a lower effective income tax rate.

Net Revenue

2004 Compared to 2003

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

	(In Millions)
2003 net revenue	$1,110.1
Volume/weather	26.7
Net wholesale revenue	13.0
Summer capacity charges	5.5
Price applied to unbilled sales	4.8
Fuel recovery revenues	(14.2)
Other	3.9
2004 net revenue	$1,149.8

The volume/weather variance resulted primarily from an increase of 1,179 GWh in electricity usage in the industrial sector. Billed usage also increased a total of 291 GWh in the residential, commercial, and governmental sectors.

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

Summer capacity charges variance is due to the amortization in 2003 of deferred capacity charges for the summer of 2001 compared to the absence of the amortization in 2004. The amortization of these capacity charges began in June 2002 and ended in May 2003.

The price applied to unbilled sales variance resulted primarily from an increase in the fuel price applied to unbilled sales.

Fuel recovery revenues represent an under-recovery of fuel charges that are recovered in base rates.

Entergy Gulf States recorded $22.6 million of provisions in 2004 for potential rate refunds. These provisions are not included in the Net Revenue table above because they are more than offset by provisions recorded in 2003.

Gross operating revenues, fuel and purchased power expenses, and other regulatory credits

Gross operating revenues increased primarily due to an increase of $187.8 million in fuel cost recovery revenues as a result of higher fuel rates in both the Louisiana and Texas jurisdictions. The increases in volume/weather and wholesale revenue, discussed above, also contributed to the increase.

Fuel and purchased power expenses increased primarily due to:

• increased recovery of deferred fuel costs due to higher fuel rates;
• increases in the market prices of natural gas, coal, and purchased power; and
• an increase in electricity usage, discussed above.

Other regulatory credits increased primarily due to the amortization in 2003 of deferred capacity charges for the summer of 2001 compared to the absence of amortization in 2004. The amortization of these charges began in June 2002 and ended in May 2003.

2003 Compared to 2002

Net revenue, which is Entergy Gulf States' 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	$1,130.7
Volume/weather	17.8
Fuel write-offs in 2002	15.3
Net wholesale revenue	10.2
Base rate decreases	(23.3)
NISCO gain recognized in 2002	(15.2)
Rate refund provisions	(11.3)
Other	(14.1)
2003 net revenue	$1,110.1

The volume/weather variance was due to higher electric sales volume in the service territory. Billed usage increased a total of 517 GWh in the residential and commercial sectors. The increase was partially offset by a decrease in industrial usage of 470 GWh due to the loss of two large industrial customers to cogeneration. The customers accounted for approximately 1% of Entergy Gulf States' net revenue in 2002.

In 2002, deferred fuel costs of $8.9 million related to a Texas fuel reconciliation case were written off and $6.5 million in expense resulted from an adjustment in the deregulated asset plan percentage as the result of a power uprate at River Bend.

The increase in net wholesale revenue was primarily due to an increase in sales volume to municipal and co-op customers and also to affiliated systems related to Entergy's generation resource planning.

The base rate decreases were effective June 2002 and January 2003, both in the Louisiana jurisdiction. The January 2003 base rate decrease of $22.1 million had a minimal impact on net income due to a corresponding reduction in nuclear depreciation and decommissioning expenses associated with the change in accounting to reflect an assumed extension of River Bend's useful life.

In 2002, a gain of $15.2 million was recognized for the Louisiana portion of the 1988 Nelson Units 1 and 2 sale. Entergy Gulf States received approval from the LPSC to discontinue applying amortization of the gain against recoverable fuel, resulting in the recognition of the deferred gain in income.

Rate refund provisions caused a decrease in net revenue due to additional provisions recorded in 2003 compared to 2002 for potential rate actions and refunds.

Gross operating revenues and fuel and purchased power expenses

Gross operating revenues increased primarily due to an increase of $440.2 million in fuel cost recovery revenues as a result of higher fuel rates in both the Louisiana and Texas jurisdictions.

Fuel and purchased power expenses increased $471.1 million due to an increase in the market prices of natural gas and purchased power.

Other Income Statement Variances

2004 Compared to 2003

Other operation and maintenance expenses decreased primarily due to:

• voluntary severance program accruals of $22.5 million in 2003; and
• a decrease of $4.3 million in nuclear material and labor costs due to reduced staff in 2004.

The decrease was partially offset by the following:

• an increase of $8.5 million in benefit costs; and
• an increase of $5 million in customer service support costs.

Miscellaneous income - net increased $145.6 million primarily due to:

• the $107.7 million accrual in June 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 domestic utility companies and System Energy financial statements for more details regarding the River Bend abeyed plant costs;
• the River Bend decommissioning cost liability revision made in accordance with a new decommissioning cost study that reflected an expected life extension for the plant. For the portion of River Bend not subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous income of $27.7 million; and
• a reduction of approximately $10 million in the loss provision related to an environmental clean-up site.

Interest on long-term debt decreased $23.2 million primarily due to the financing and debt restructuring program implemented in 2003, which resulted in extended maturities and lower interest rates in Entergy Gulf States' debt portfolio.

2003 Compared to 2002

Other operation and maintenance expenses increased primarily due to voluntary severance accruals of $22.5 million in 2003.

Decommissioning expense increased primarily due to the implementation of SFAS 143. The increase in decommissioning expense was offset by increases in other regulatory credits and interest and dividend income and has no effect on net income.

Depreciation and amortization expenses decreased primarily due to decreased rates associated with the assumed life extension of River Bend, partially offset by higher depreciation due to an increase in plant in service. The decrease in depreciation related to the assumed license extension of River Bend has a minimal impact on net income because it was offset by the January 2003 base rate decrease discussed in "Net Revenue" above.

Other income decreased primarily due to the abeyed River Bend plant cost accrual discussed above.

Interest expense on long-term debt increased primarily due to the issuance of $340 million of First Mortgage Bonds in November 2002, $600 million in June 2003, and $440 million in July 2003, partially offset by the retirement of $293 million of First Mortgage Bonds in March 2003 and $745 million in the third quarter of 2003.

Income Taxes

The effective income tax rates for 2004, 2003, and 2002 were 36.0%, 21.3%, and 27.5%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rate.  Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued on the balance sheet.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2004, 2003, and 2002 were as follows:

		2004	2003	2002
		(In Thousands)
Cash and cash equivalents at beginning of period		$206,030	$318,404	$123,728
Cash flow provided by (used in):
	Operating activities	649,458	425,963	500,654
	Investing activities	(389,344)	(446,639)	(351,456)
	Financing activities	(459,170)	(91,698)	45,478
	Net increase (decrease) in cash and cash equivalents	(199,056)	(112,374)	194,676
Cash and cash equivalents at end of period		$6,974	$206,030	$318,404

Operating Activities

Cash flow from operations increased $223.5 million in 2004 compared to 2003 primarily due to money pool activity. Decreased vendor payments, increased recovery of deferred fuel costs, and lower interest payments also contributed to the increase.

In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $674 million deduction for Entergy Gulf States on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. In 2004 Entergy Gulf States realized $69 million in cash tax benefit from the method change. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit.  As of December 31, 2004, Entergy Gulf States has a net operating loss (NOL) carryforward for tax purposes of $447.5 million, principally resulting from the change in tax accounting method related to cost of goods sold.  If the tax accounting method change is sustained, Entergy Gulf States expects to utilize the NOL carryforward through 2006.

Cash flow from operations decreased $74.7 million in 2003 compared to 2002 primarily due to money pool activity, higher working capital needs, and increased vendor payments in 2003 relating to storm expense accruals in late-2002. The decrease was partially offset by lower income tax payments.

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

2004	2003	2002	2001
(In Thousands)
($59,720)	$69,354	$18,131	$27,665

Money pool activity provided $129.1 million of Entergy Gulf States' operating cash flows in 2004, used $51.2 million in 2003, and provided $9.5 million in 2002. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.

Investing Activities

Net cash used in investing activities decreased $57.3 million in 2004 compared to 2003 primarily due to the maturity in 2004 of $23.6 million of other temporary investments that had been made in 2003, which provided cash in 2004. Also contributing to the decrease was a $27.2 million decrease in under-recovered fuel and purchased power expenses in Texas that have been deferred and are expected to be collected over a period greater than twelve months. See Note 1 to the domestic utility companies and System Energy financial statements for further discussion of the accounting for fuel costs.

Net cash used in investing activities increased $95.2 million in 2003 compared to 2002 primarily due to an increase of $23.6 million in other temporary investments in 2003 compared to the maturity of $44.6 million of other temporary investments that provided cash in 2002. The increase was also due to an increase of $37.7 million in under-recovered fuel and purchased power expenses in Texas that have been deferred and are expected to be collected over a period greater than twelve months. See Note 1 to the domestic utility companies and System Energy financial statements for further discussion of the accounting for fuel costs.

Financing Activities

Net cash used in financing activities increased $367.5 million in 2004 compared to 2003 primarily due to the net reduction of $357 million of long-term debt in 2004 compared to $15.4 million in 2003 as well as an increase of $26.2 million in common stock dividends paid.

Entergy Gulf States used $91.7 million of cash in financing activities in 2003 compared to providing $45.5 million of cash in 2002 primarily due to the net reduction of $15.4 million of long-term debt in 2003 compared to the net issuance of $143.4 million of long-term debt in 2002. The increase in cash used in financing activities was partially offset by a decrease of $23.1 million in common stock dividends paid.

See Note 5 to the domestic utility companies and System Energy financial statements for details on long-term debt.

Uses of Capital

Entergy Gulf States requires capital resources for:

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

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

	2005	2006-2007	2008-2009	after 2009	Total
	(In Millions)
Planned construction and
capital investment (1)	$275	$505	N/A	N/A	$780
Long-term debt	$98	-	$550	$1,341	$1,989
Operating leases	$27	$41	$19	$115	$202
Purchase obligations (2)	$164	$78	$6	$21	$269
Other long-term liabilities	$3	$7	$7	-	$17
Nuclear fuel lease obligations (3)	$33	$38	N/A	N/A	$71

(1)	Includes approximately $210 to $220 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth.
(2)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Gulf States it primarily includes unconditional fuel and purchased power obligations.
(3)	It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. If such additional financing cannot be arranged, however, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations.

In addition to these contractual obligations, Entergy Gulf States expects to contribute $18.9 million to its pension plans and $14.3 million to other postretirement plans in 2005.

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

In addition to the purchase obligations presented in the table above, Entergy Gulf States expects to have an obligation to purchase power from the Perryville power plant. In January 2004, Entergy Louisiana signed a definitive agreement to acquire the 718 MW Perryville power plant for $170 million. The agreement has subsequently been amended to allow the current plant owner to retain the interconnection facilities associated with the plant, resulting in a decrease in the acquisition price to $162 million. As a result of the amended terms, the FERC issued an order in October 2004 disclaiming jurisdiction over the acquisition. This order currently is subject to rehearing by the FERC. 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 power purchase agreement. In addition, Entergy Louisiana and Entergy Gulf States executed an interim power purchase agreement with the plant's owner through the date of the acquisition's closing (as long as that occurs by December 2005) for 100 percent of the output of the Perryville power plant. In April 2004, the bankruptcy court approved Entergy Louisiana's agreement to acquire the plant. In March 2004, Entergy Gulf States and Entergy Louisiana filed with the LPSC for its approval of the acquisition and long-term cost-of-service power purchase agreement. Entergy is seeking approval from the LPSC of cost recovery for the acquisition, giving consideration to the need for the power and the prudence of Entergy Louisiana and Entergy Gulf States in engaging in the transaction. Hearings are scheduled for March 2005. Assuming regulato ry approval by the LPSC, Entergy Louisiana expects the Perryville acquisition to close in mid-2005.

As a wholly-owned subsidiary, Entergy Gulf States pays dividends to Entergy Corporation from its earnings at a percentage determined monthly. Entergy Gulf States is restricted by long-term debt indentures in the payment of cash dividends or other distributions on its common and preferred stock. Currently, all of Entergy Gulf States' retained earnings are available for distribution.

Sources of Capital

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

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

The following table lists First Mortgage Bonds issued by Entergy Gulf States in 2004:

Issue Date	Description	Maturity	Amount
			(In Thousands)
October 2004	4.875% Series	November 2011	$200,000
November 2004	Libor + 0.4% Series	December 2009	225,000
November 2004	5.6% Series	December 2014	50,000
			$475,000

The following table lists First Mortgage Bonds retired by Entergy Gulf States in 2004:

Retirement Date	Description	Maturity	Amount
			(In Thousands)
April 2004	8.25% Series	April 2004	$292,000
December 2004	Libor + 0.9% Series	June 2007	275,000
December 2004	5.2% Series	December 2007	200,000
			$767,000

Entergy Gulf States may refinance or redeem debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

In addition, in September 2004, Entergy Gulf States purchased its $62 million 5.65% Series tax-exempt bonds from the holders, pursuant to a mandatory tender provision, and has not remarketed the bonds at this time.

All debt and common and preferred stock issuances by Entergy Gulf States require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in its corporate charter, bond indentures, and other agreements. Entergy Gulf States has sufficient capacity under these tests to meet its foreseeable capital needs.

Borrowings and securities issuances by Entergy Gulf States are limited to amounts authorized by the SEC. The current short-term borrowing limitation, including borrowings under the money pool, is $340 million. Under its SEC Orders and without further SEC authorization, Entergy Gulf States cannot incur additional indebtedness or issue other securities unless (a) it and Entergy Corporation maintain a common equity ratio of at least 30% and (b) with the exception of money pool borrowings, the security to be issued (if rated) and all outstanding securities of Entergy Gulf States (other than its preferred stock), as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy Gulf States' short-term borrowing limits.

Significant Factors and Known Trends

Transition to Retail Competition

Texas

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

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

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

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

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

Louisiana

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

Jurisdictional Separation Plan

Pursuit of Entergy Gulf States' business separation plan mandated by Texas law in connection with retail open access in the Texas service territory has been complicated by the existence of retail operations in Louisiana subject to the jurisdiction of the LPSC. During the course of Entergy Gulf States' retail open access proceedings with the PUCT, the LPSC has been holding independent proceedings concerning the proposed separation of Entergy Gulf States' business. Unlike the plan filed with the PUCT in 2000 (and amended through 2001), discussed below, to separate Entergy Gulf States' Texas generation, transmission, distribution, and retail electric functions into separate companies, the investigation recently initiated in the LPSC proceedings is evaluating a jurisdictional split of Entergy Gulf States into a Louisiana company and a Texas company. In a status conference held in September 2004 before an ALJ, the LPSC staff asserted that uncertainty with respect to retail open access in Texas should not control whether or when the LPSC should require the jurisdictional separation of Entergy Gulf States and recommended that an investigation concerning the proposed jurisdictional separation proceed. Entergy Gulf States submitted a preliminary methodology developed by Entergy for the jurisdictional separation of Entergy Gulf States if the regulators should determine that a jurisdictional separation is in the public interest. Although it contains many components that are similar to those set forth in the business separation plan filed with the PUCT, the preliminary methodology filed with the LPSC provides for the separation of Entergy Gulf States into a Louisiana vertically integrated utility company and a Texas vertically integrated utility company; rather than the separation of Entergy Gulf States' Texas generation, transmission, distribution, and retail electric functions into separate companies as is envisioned in the plan filed with the PUCT. A procedural schedule was established in the status conference that sets discovery through February 2005, testimony through the first half of June 2005, and a hearing beginning later in June 2005. Approvals of the FERC, the SEC, the PUCT, and the NRC may also be required for certain matters before any implementation of the jurisdictional separation of Entergy Gulf States.

Business Separation Plan under the Texas Retail Open Access Law

Entergy Gulf States' business separation plan for Texas retail open access developed pursuant to the Texas restructuring law provides for the separation of its generation, transmission, distribution, and retail electric functions into separate companies. It has been amended during the course of various PUCT and LPSC proceedings and is subject to further change and regulatory proceedings. Entergy Gulf States filed the business separation plan with the PUCT in January 2000 and amended that plan in June and November 2000 and January 2001. In July 2000, the PUCT approved the amended business separation plan in an interim order. In December 2001, the PUCT abated the proceeding and indicated it will consider a final order in a timely manner consistent with a settlement agreement delaying retail open access. The outcome of the LPSC proceedings described below, which have resulted in amendments to the plan beyond what was approved by the PUCT, have been and will continue to be reported to the PUCT and the Office of Public Utility Counsel and may require additional PUCT action before the business separation plan could become final.

The LPSC opened a docket to identify the changes in corporate structure and operations of Entergy Gulf States, and their potential impact on Louisiana retail ratepayers, resulting from restructuring in Texas. In those proceedings, Entergy Gulf States and the LPSC staff reached a settlement on certain Texas business separation plan issues, and after a May 2001 hearing, the LPSC issued an interim order in July 2001 approving the settlement. In July 2001, Entergy Gulf States and the LPSC Staff completed an additional settlement on business separation plan issues relating to the separation of Texas distribution and transmission. A hearing on the distribution and transmission settlement was held and the LPSC approved the settlement in September 2001. Issues related to the separation of generation are still unresolved.

The plan approved by the LPSC in September 2001 provides that Entergy Gulf States will be separated into the following principal companies if retail open access were to commence in Texas:

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

Pursuant to the LPSC-approved plan, Entergy Gulf States-Louisiana would:

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

System Agreement Proceedings

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.

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

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

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

	Range of Annual Payments or (Receipts)	Average Annual Payments or (Receipts) for 2005-2009 Period
	(In Millions)	(In Millions)
Entergy Arkansas	$154 to $281	$215
Entergy Gulf States	($130) to ($15)	($63)
Entergy Louisiana	($199) to ($98)	($141)
Entergy Mississippi	($16) to $8	$1
Entergy New Orleans	($17) to ($5)	($12)

Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers. Although the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy Gulf States does not believe that the ultimate resolution of these proceedings will have a material effect on its financial condition or results of operation.

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

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

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

The LPSC instituted a companion ex-parte System Agreement investigation to litigate several of the System Agreement issues that the LPSC is litigating before the FERC in the previously discussed System Agreement proceeding. This companion proceeding will require the LPSC to interpret various provisions of the System Agreement, including those relating to minimum-run and must-run units, the propriety of the methods used for billing and dispatch on the Entergy System, and the use of a rolling, twelve-month average of system peaks for allocating certain costs. In addition, by this companion proceeding the LPSC is questioning whether Entergy Louisiana and Entergy Gulf States were prudent for not seeking changes to the System Agreement previously, so as to lower costs imposed upon their ratepayers and to increase costs imposed upon ratepayers of other domestic utility companies. The LPSC staff has filed testimony suggesting that the remedy for the alleged imprudence of Entergy Louisiana and Entergy Gulf States should be a reduction in allowed rate of return on common equity of 100 basis points. The domestic utility companies have challenged the propriety of the LPSC's litigating System Agreement issues. Nevertheless, on January 16, 2002 the LPSC affirmed a decision of its ALJ upholding the LPSC staff's right to litigate System Agreement issues at the LPSC, rather than before the FERC. The procedural schedule is suspended at this time and an evidentiary hearing is not scheduled. An unrelated case between the LPSC and Entergy Louisiana raised the question of whether a state regulator is preempted by federal law from reviewing and interpreting 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 reve rsed the decisions of the LPSC and the Louisiana Supreme Court.

Transmission

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

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

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

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

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

Interconnection Orders

The domestic utility companies (except Entergy New Orleans) are currently defendants to several complaints and rehearing requests before the FERC in which independent generation entities (GenCos) are seeking a refund of monies that the GenCos had previously paid to the Entergy companies for facilities necessary to connect their generation facilities to Entergy's transmission system. The FERC has issued initial orders in response to two of the complaints and in certain other dockets ordering Entergy to refund approximately $100 million in expenses and tax obligations previously paid by the GenCos, including $28 million for Entergy Gulf States. The refunds will be in the form of transmission credits that will be utilized over time as the GenCos take transmission service from Entergy. To the extent the Entergy companies are ordered to provide such refunds, these costs will qualify for inclusion in the Entergy companies' rates. The recovery of these costs is not automatic, however, especially at the retail level, where the majority of the cost recovery would occur. Entergy intends to pursue all regulatory and legal avenues available to it in order to have these orders reversed and have the affected interconnection agreements reinstated as agreed to originally by the generators.

Available Flowgate Capacity Proceeding

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

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

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

State and Local Rate Regulatory Risks

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

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

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

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

Dismissal of Entergy Gulf States' rate case does not preclude it from seeking recovery of the transition to competition costs when the rate freeze is no longer in effect. Similarly, the dismissal of the rate case does not preclude Entergy Gulf States from seeking the reconciliation of fuel and purchased power costs of $288 million for the period September 2003 through March 2004 when, at the appropriate time, similar costs are reconciled in the future. As discussed above, in February 2005, bills were submitted in the Texas Legislature that would clarify that Entergy Gulf States is no longer subject to a rate freeze and specify that retail open access will not commence in Entergy Gulf States' Texas service territory until the PUCT certifies a power region.

In September 2004, the LPSC consolidated various dockets that were the subject of settlement discussions between the LPSC staff and Entergy Gulf States and Entergy Louisiana. The LPSC directed its staff to continue the settlement discussions and submit any proposed settlement to the LPSC for its consideration. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement that currently includes an offer to refund $76 million to Entergy Gulf States' Louisiana customers, with no immediate change in current base rates. If the LPSC approves the proposed settlement, Entergy Gulf States will be regulated under a three-year formula rate plan that, among other provisions, establishes a ROE mid-point of 10.65% and permits Entergy Gulf States to recover incremental capacity costs without filing a traditional base rate proceeding. The settlement resolves all issues in, and will result in the dismissal of, Entergy Gulf States' four th, fifth, sixth, seventh, and eighth annual earnings reviews, Entergy Gulf States' ninth post-merger earnings review and revenue requirement analysis, a fuel review for Entergy Gulf States, dockets established to consider issues concerning power purchases for both Entergy Gulf States and Entergy Louisiana for the summers of 2001, 2002, 2003, and 2004, and a docket concerning retail issues arising under the Entergy System Agreement. The settlement does not include the System Agreement case pending at FERC. The LPSC has solicited comments on the proposed settlement from the parties to the various proceedings at issue in the proposed settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005. Refer to Note 2 to the domestic utility and System Entergy financial statements for details of the proceedings included in the proposed settlement.

In July 2004, Entergy Gulf States filed with the LPSC an application for a change in its gas base rates and charges seeking an increase of $9.1 million. Entergy Gulf States also is seeking approval of certain proposed rate design, rate schedule, and policy changes. Discovery is underway, and a decision is expected during the third quarter of 2005.

In addition to rate proceedings, Entergy Gulf States' fuel costs recovered from customers are subject to regulatory scrutiny. Entergy Gulf States' retail rate matters and proceedings, including fuel cost recovery-related issues, are discussed in Note 2 to the domestic utility companies and System Energy financial statements.

Industrial, Commercial, and Wholesale Customers

Entergy Gulf States' large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Gulf States' industrial customer base. Entergy Gulf States responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that match specific customer needs and load profiles. Despite these actions, Entergy Gulf States expects to lose one large industrial customer to cogeneration in 2005. Current sales to that customer account for approximately $12 million of Entergy Gulf States' net revenue annually. Entergy Gulf States actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers. Entergy Gulf States does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Gulf States' marketing efforts in retaining industrial customers.

Market and Credit Risks

Entergy Gulf States has certain market and credit risks inherent in its business operations. Market risks represent the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement.

Interest Rate and Equity Price Risk - Decommissioning Trust Funds

Entergy Gulf States' nuclear decommissioning trust funds expose it to fluctuations in equity prices and interest rates. The NRC requires Entergy Gulf States to maintain trusts to fund the costs of decommissioning River Bend. The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that its exposure to market fluctuations will not affect results of operations for the River Bend trust funds because of the application of regulatory accounting principles. The decommissioning trust funds are discussed more thoroughly in Notes 1, 8, and 12 to the domestic utility companies and System Energy financial statements.

Nuclear Matters

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

Environmental Risks

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

Litigation Risks

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

Critical Accounting Estimates

The preparation of Entergy Gulf States' financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy Gulf States' financial position or results of operations.

Nuclear Decommissioning Costs

Regulations require Entergy Gulf States to decommission the River Bend nuclear power plant after the facility is taken out of service, and money is collected and deposited in trust funds during the facility's operating life in order to provide for this obligation. Entergy Gulf States conducts periodic decommissioning cost studies (typically updated every three to five years) to estimate the costs that will be incurred to decommission the facility. The following key assumptions have a significant effect on these estimates:

• Cost Escalation Factors - Entergy Gulf States' decommissioning study includes an assumption that decommissioning costs will escalate over present cost levels by an annual factor averaging approximately CPI-U to 4.5%. A 50 basis point change in this assumption could change the ultimate cost of decommissioning a facility by as much as 11%.
• Timing - The date of the plant's retirement must be estimated and an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in "safestore" status for later decommissioning, as permitted by applicable regulations. While the effect of these assumptions cannot be determined with precision, assuming either license extension or use of a "safestore" status can possibly decrease the present value of these obligations. As discussed in Note 8 to the domestic utility companies and System Energy financial statements, Entergy Gulf States recorded revisions in 2004 to its estimated decommissioning cost liability for River Bend to reflect changes in assumptions regarding license renewal. Under these license renewal assumptions, decommissioning of nuclear plants is assumed to occur at a date later than the original license expiration, thereby lowering the estimate of the decommissioning cost liability. The revised license renewal assump tions for the unregulated portion of Entergy Gulf States increased income in 2004 by $17 million net-of-tax for the excess of the reduction in the liability over the amount of undepreciated asset retirement cost at the time of adoption of SFAS 143. For the regulated portion of Entergy Gulf States, the revised assumptions had no effect on net income because, as discussed further below, any amounts recorded related to SFAS 143 are offset by the recording of regulatory assets or regulatory liabilities when projected decommissioning costs are collected in rates. Future revisions to appropriately reflect changes needed to the estimate of decommissioning costs will affect net income for the unregulated portion of Entergy Gulf States. Any increase in the liability recorded due to such changes are capitalized and depreciated over the asset's remaining economic life in accordance with SFAS 143.
• Spent Fuel Disposal - Federal regulations require the DOE to provide a permanent repository for the storage of spent nuclear fuel, and legislation has been passed by Congress to develop this repository at Yucca Mountain, Nevada. Until this site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities can have a significant effect (as much as 16% of estimated decommissioning costs). Entergy Gulf States' decommissioning studies include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors.
• Technology and Regulation - To date, there is limited practical experience in the United States with actual decommissioning of large nuclear facilities. As experience is gained and technology changes, cost estimates could also change. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant effect on cost estimates. The effect of these potential changes is not presently determinable. Entergy Gulf States' decommissioning cost studies assume current technologies and regulations.

Entergy Gulf States collects the projected costs of decommissioning River Bend through rates charged to customers for the portion of the plant subject to cost-based ratemaking. The amounts collected through rates, which are based upon decommissioning cost studies, are deposited in decommissioning trust funds. In December 2002, decommissioning collections from customers for the Louisiana-regulated portion of River Bend were suspended as a result of the settlement with the LPSC of Entergy Gulf States' fourth through eighth earnings reviews. If decommissioning cost study estimates are changed and approved by regulators, collections from customers would also change.

Approximately half of River Bend is not subject to cost-based ratemaking. When Entergy Gulf States acquired 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 $158 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.

SFAS 143

Entergy Gulf States implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs comprise substantially all of Entergy Gulf States' asset retirement obligations, and the measurement and recording of Entergy Gulf States' decommissioning obligations 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 of Entergy Gulf States to increase significantly, as Entergy Gulf States had previously only recorded this obligation as the related costs were collected from customers, and as earnings were recorded on the related trust funds.
• Fair value approach - SFAS 143 requires that these obligations be measured using a fair value approach. Among other things, this entails the assumption that the costs will be incurred by a third party and will therefore include appropriate profit margins and risk premiums. Entergy Gulf States' decommissioning studies had been based on Entergy Gulf States performing the work and did not include any such margins or premiums.
• Discount rate - SFAS 143 requires that these obligations be discounted using a credit-adjusted risk-free rate.

The net effect of implementing SFAS 143 for the portion of River Bend subject to cost-based ratemaking was recorded as a regulatory asset, with no resulting impact on Entergy Gulf States' net income. Entergy Gulf States recorded this regulatory asset because its existing rate mechanism is based on the original or historical cost standard that allows Entergy Gulf States to recover all ultimate costs of decommissioning existing assets from current and future customers. Upon implementation of SFAS 143 in 2003, assets and liabilities increased as a result of increasing the asset retirement obligation by $129 million to its fair value as determined under SFAS 143, reducing accumulated depreciation by $63 million, and recording the related regulatory asset of $32 million. The net effect of implementing SFAS 143 for the portion of River Bend not subject to cost-based ratemaking resulted in an earnings decrease of $21 million net-of-tax as a result of a one-time cumulative effect of accounting change.

In the third quarter of 2004, Entergy Gulf States recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for River Bend that reflected an expected life extension for the plant. The revised estimate resulted in a $166.4 million reduction in decommissioning liability, along with a $31.3 million reduction in utility plant, a $49.6 million reduction in non-utility property, a $40.1 million reduction in the related regulatory asset, and a regulatory liability of $17.7 million. For the portion of River Bend not subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous income of $27.7 million.

Application of SFAS 71

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

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

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

Unbilled Revenue

As discussed in Note 1 to the domestic utility companies and System Energy financial statements, Entergy Gulf States records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month, including fuel price in Entergy Gulf States' Louisiana jurisdiction. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period and fuel price fluctuations, in addition to changes in certain components of the calculation including changes to estimates such as line loss, which affects the estimate of unbilled customer usage, and assumptions regarding price such as the fuel cost recovery mechanism.

Pension and Other Postretirement Benefits

Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 10 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.

Assumptions

Key actuarial assumptions utilized in determining these costs include:

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

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

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

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

Cost Sensitivity

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

Actuarial Assumption	Change in Assumption	Impact on 2004 Pension Cost	Impact on Projected Benefit Obligation
	Increase/(Decrease)
Discount rate	(0.25%)	$1,994	$16,385
Rate of return on plan assets	(0.25%)	$1,134	-
Rate of increase in compensation	0.25%	$726	$4,157

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

Actuarial Assumption	Change in Assumption	Impact on 2004 Postretirement Benefit Cost	Impact on Accumulated Postretirement Benefit Obligation
	Increase/(Decrease)
Health care cost trend	0.25%	$847	$4,751
Discount rate	(0.25%)	$510	$5,677

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

Accounting Mechanisms

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

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

Costs and Funding

Total pension cost for Entergy Gulf States in 2004 was $0.4 million. Entergy Gulf States anticipates 2005 pension cost to increase to $7.3 million due to decrease in the discount rate (from 6.25% to 6.00%) and the expected rate of return (from 8.75% to 8.5%) used to calculate benefit obligations. Entergy Gulf States contributed $17 thousand to its pension plan in 2004, and anticipates making $18.9 million in contributions in 2005. The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, partially offset by the Pension Funding Equity Act relief passed in April 2004.

At December 31, 2003 and 2004, Entergy Gulf States' accumulated benefit obligation was less than plan assets, therefore there was no additional minimum pension liability required to be recognized. Net income for 2004, 2003, and 2002 was not impacted.

Total postretirement health care and life insurance benefit costs for Entergy Gulf States in 2004 were $17.6 million, including $4.4 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Gulf States expects 2005 postretirement health care and life insurance benefit costs to be approximately $19.6 million, including $5.1 million in savings due to the estimated effect of future Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the decrease in the discount rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate used to calculate benefit obligations.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Entergy Gulf States, Inc.:

We have audited the accompanying balance sheets of Entergy Gulf States, Inc. as of December 31, 2004 and 2003, and the related statements of income, retained earnings and comprehensive income, and cash flows (pages 194 through 198 and applicable items in pages 284 through 348) for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Gulf States, Inc. as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 5 and Note 8 to the notes to respective financial statements, in 2003 Entergy Gulf States, Inc. adopted the provisions of Statement of Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, and Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

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

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 8, 2005

ENTERGY GULF STATES, INC.
INCOME STATEMENTS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
OPERATING REVENUES
Domestic electric	$2,821,296	$2,579,916	$2,141,873
Natural gas	61,088	59,821	42,006
TOTAL	2,882,384	2,639,737	2,183,879
OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and
gas purchased for resale	772,914	693,612	692,901
Purchased power	969,779	838,498	368,140
Nuclear refueling outage expenses	15,969	14,045	12,190
Other operation and maintenance	445,413	457,428	438,259
Decommissioning	13,645	14,268	3,980
Taxes other than income taxes	118,081	117,009	120,295
Depreciation and amortization	197,234	199,583	204,202
Other regulatory credits - net	(10,070)	(2,476)	(7,818)
TOTAL	2,522,965	2,331,967	1,832,149
OPERATING INCOME	359,419	307,770	351,730
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	13,027	15,855	11,010
Interest and dividend income	15,753	17,902	8,866
Miscellaneous - net	36,180	(109,389)	3,560
TOTAL	64,960	(75,632)	23,436
INTEREST AND OTHER CHARGES
Interest on long-term debt	125,356	148,516	139,343
Other interest - net	8,242	8,827	5,497
Allowance for borrowed funds used during construction	(9,771)	(13,349)	(9,749)
TOTAL	123,827	143,994	135,091
INCOME BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE	300,552	88,144	240,075
Income taxes	108,288	24,249	65,997
INCOME BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGE	192,264	63,895	174,078
CUMULATIVE EFFECT OF ACCOUNTING
CHANGE (net of income taxes of $12,713)	- -	(21,333)	- -
NET INCOME	192,264	42,562	174,078
Preferred dividend requirements and other	4,472	4,701	4,888
EARNINGS APPLICABLE TO
COMMON STOCK	$187,792	$37,861	$169,190
See Notes to Respective Financial Statements.

ENTERGY GULF STATES, INC.
STATEMENTS OF CASH FLOWS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
OPERATING ACTIVITIES
Net income	$192,264	$42,562	$174,078
Adjustments to reconcile net income to net cash flow provided by operating activities:
Reserve for regulatory adjustments	24,112	12,605	11,147
Other regulatory credits - net	(10,070)	(2,476)	(7,818)
Depreciation, amortization, and decommissioning	210,879	213,851	208,182
Deferred income taxes and investment tax credits	57,908	24,574	(11,576)
Cumulative effect of accounting change	-	21,333	-
Changes in working capital:
Receivables	14,774	(96,409)	18,155
Fuel inventory	1,205	(1,469)	4,617
Accounts payable	59,846	(17,013)	83,428
Taxes accrued	99,955	12,618	(24,740)
Interest accrued	(3,834)	(1,900)	(4,544)
Deferred fuel costs	78,200	59,165	65,556
Other working capital accounts	7,426	11,874	(19,551)
Provision for estimated losses and reserves	(13,844)	115,878	1,478
Changes in other regulatory assets	(10,060)	3,983	(51,490)
Other	(59,303)	26,787	53,732
Net cash flow provided by operating activities	649,458	425,963	500,654
INVESTING ACTIVITIES
Construction expenditures	(357,720)	(348,507)	(355,334)
Allowance for equity funds used during construction	13,027	15,855	11,010
Nuclear fuel purchases	(45,085)	(39,959)	(21,820)
Proceeds from sale/leaseback of nuclear fuel	38,800	38,029	21,923
Decommissioning trust contributions and realized
change in trust assets	(12,070)	(11,428)	(12,488)
Changes in other temporary investments - net	23,579	(23,579)	44,643
Other regulatory investments	(49,875)	(77,050)	(39,390)
Net cash flow used in investing activities	(389,344)	(446,639)	(351,456)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	472,039	1,032,682	337,481
Retirement of long-term debt	(829,000)	(1,048,129)	(194,057)
Redemption of preferred stock	(3,450)	(3,450)	(1,858)
Dividends paid:
Common stock	(94,300)	(68,100)	(91,200)
Preferred stock	(4,459)	(4,701)	(4,888)
Net cash flow provided by (used in) financing activities	(459,170)	(91,698)	45,478
Net increase (decrease) in cash and cash equivalents	(199,056)	(112,374)	194,676
Cash and cash equivalents at beginning of period	206,030	318,404	123,728
Cash and cash equivalents at end of period	$6,974	$206,030	$318,404
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid/(received) during the period for:
Interest - net of amount capitalized	$130,491	$152,655	$143,961
Income taxes	($28,169)	($30,987)	$98,734
See Notes to Respective Financial Statements.

ENTERGY GULF STATES, INC.
BALANCE SHEETS
ASSETS
	December 31,
	2004	2003
	(In Thousands)
CURRENT ASSETS
Cash and cash equivalents:
Cash	$5,627	$20,754
Temporary cash investments - at cost,
which approximates market	1,347	185,276
Total cash and cash equivalents	6,974	206,030
Other temporary investments	- -	23,579
Accounts receivable:
Customer	124,801	115,729
Allowance for doubtful accounts	(2,687)	(4,856)
Associated companies	13,980	76,726
Other	40,697	27,243
Accrued unbilled revenues	137,719	114,442
Total accounts receivable	314,510	329,284
Deferred fuel costs	90,124	118,449
Accumulated deferred income taxes	14,339	6,116
Fuel inventory - at average cost	49,658	50,863
Materials and supplies - at average cost	101,922	99,357
Prepayments and other	20,556	51,236
TOTAL	598,083	884,914
OTHER PROPERTY AND INVESTMENTS
Decommissioning trust funds	290,952	267,917
Non-utility property - at cost (less accumulated depreciation)	94,052	139,911
Other	22,012	21,852
TOTAL	407,016	429,680
UTILITY PLANT
Electric	8,418,119	8,208,394
Property under capital lease	- -	11,009
Natural gas	78,627	69,180
Construction work in progress	331,703	325,888
Nuclear fuel under capital lease	71,279	63,684
TOTAL UTILITY PLANT	8,899,728	8,678,155
Less - accumulated depreciation and amortization	4,047,182	3,953,275
UTILITY PLANT - NET	4,852,546	4,724,880
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
SFAS 109 regulatory asset - net	444,799	442,062
Other regulatory assets	285,017	320,363
Long-term receivables	23,228	19,375
Other	44,713	33,588
TOTAL	797,757	815,388
TOTAL ASSETS	$6,655,402	$6,854,862
See Notes to Respective Financial Statements.
ENTERGY GULF STATES, INC.
BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
	December 31,
	2004	2003
	(In Thousands)
CURRENT LIABILITIES
Currently maturing long-term debt	$98,000	$354,000
Accounts payable:
Associated companies	153,069	84,394
Other	147,337	156,166
Customer deposits	53,229	47,044
Taxes accrued	22,882	- -
Nuclear refueling outage costs	- -	8,238
Interest accrued	32,742	36,576
Obligations under capital leases	33,518	34,075
Other	19,912	14,755
TOTAL	560,689	735,248
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	1,533,804	1,422,776
Accumulated deferred investment tax credits	138,616	144,323
Obligations under capital leases	37,711	40,618
Other regulatory liabilities	34,009	13,885
Decommissioning and retirement cost liabilities	152,095	298,785
Transition to competition	79,098	79,098
Regulatory reserves	81,455	57,343
Accumulated provisions	66,875	75,868
Long-term debt	1,891,478	1,989,613
Preferred stock with sinking fund	17,400	20,852
Other	229,408	233,985
TOTAL	4,261,949	4,377,146
Commitments and Contingencies
SHAREHOLDERS' EQUITY
Preferred stock without sinking fund	47,327	47,327
Common stock, no par value, authorized 200,000,000
shares; issued and outstanding 100 shares in 2004 and 2003	114,055	114,055
Paid-in capital	1,157,486	1,157,484
Retained earnings	513,182	419,690
Accumulated other comprehensive income	714	3,912
TOTAL	1,832,764	1,742,468
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$6,655,402	$6,854,862
See Notes to Respective Financial Statements.

ENTERGY GULF STATES, INC.
STATEMENTS OF RETAINED EARNINGS AND COMPREHENSIVE INCOME
	For the Years Ended December 31,
	2004		2003		2002
	(In Thousands)
RETAINED EARNINGS
Retained Earnings - Beginning of period	$419,690		$449,929		$371,939
Add - Net Income	192,264	$192,264	42,562	$42,562	174,078	$174,078
Deduct:
Dividends declared on common stock	94,300		68,100		91,200
Preferred dividend requirements and other	4,472	4,472	4,701	4,701	4,888	4,888
Total	98,772		72,801		96,088
Retained Earnings - End of period	$513,182		$419,690		$449,929
ACCUMULATED OTHER COMPREHENSIVE
INCOME (Net of Taxes):
Balance at beginning of period:
Accumulated derivative instrument fair value changes	$3,912		$3,286		$ -
Net derivative instrument fair value changes
arising during the period	(3,198)	(3,198)	626	626	3,286	3,286
Balance at end of period:
Accumulated derivative instrument fair value changes	$714		$3,912		$3,286
Comprehensive Income		$184,594		$38,487		$172,476
See Notes to Respective Financial Statements.

ENTERGY GULF STATES, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
	2004	2003	2002	2001	2000
	(In Thousands)
Operating revenues	$2,882,384	$2,639,737	$2,183,879	$2,648,560	$2,511,240
Net Income	$192,264	$45,262	$174,078	$179,444	$180,343
Total assets	$6,655,402	$6,854,862	$6,599,533	$6,209,741	$6,134,017
Long-term obligations (1)	$1,946,589	$2,051,083	$2,096,329	$2,130,245	$1,978,149
(1) Included long-term debt (excluding currently maturing debt), preferred stock with sinking fund, and noncurrent capital lease obligations.
	2004	2003	2002	2001	2000
	(Dollars In Millions)
Electric Operating Revenues:
Residential	$881	$829	$700	$788	$717
Commercial	672	614	502	587	505
Industrial	976	853	695	946	871
Governmental	37	39	34	38	33
Total retail	2,566	2,335	1,931	2,359	2,126
Sales for resale:
Associated companies	52	42	28	73	94
Non-associated companies	160	150	139	146	113
Other	43	53	44	13	138
Total	$2,821	$2,580	$2,142	$2,591	$2,471
Billed Electric Energy Sales (GWh):
Residential	9,803	9,739	9,502	9,059	9,405
Commercial	8,444	8,174	7,894	7,668	7,660
Industrial	16,596	15,417	15,887	16,658	17,960
Governmental	432	475	477	452	450
Total retail	35,275	33,805	33,760	33,837	35,475
Sales for resale:
Associated companies	1,528	1,185	708	1,087	1,381
Non-associated companies	3,172	3,358	4,391	3,305	3,248
Total	39,975	38,348	38,859	38,229	40,104

ENTERGY LOUISIANA, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

2004 Compared to 2003

Net income decreased $18.7 million primarily due to lower net revenue, partially offset by lower other operation and maintenance expenses.

2003 Compared to 2002

Net income increased slightly primarily due to higher net revenue and lower interest charges, almost entirely offset by higher other operation and maintenance expenses, higher depreciation and amortization expenses, and higher taxes other than income taxes.

Net Revenue

2004 Compared to 2003

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

	(In Millions)
2003 net revenue	$973.7
Price applied to unbilled sales	(31.9)
Deferred fuel cost revisions	(29.4)
Rate refund provisions	(12.2)
Volume/weather	17.0
Summer capacity charges	11.8
Other	2.3
2004 net revenue	$931.3

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

The deferred fuel cost revisions variance resulted from a revised unbilled sales pricing estimate made in the first quarter of 2003 to more closely align the fuel component of that pricing with expected recoverable fuel costs.

Rate refund provisions caused a decrease in net revenue due to additional provisions recorded in 2004 compared to 2003 for potential rate actions and refunds.

The volume/weather variance is due to a total increase of 620 GWh in weather-adjusted usage in all sectors, partially offset by the effect of milder weather on billed sales in the residential and commercial sectors.

The summer capacity charges variance is due to the amortization in 2003 of deferred capacity charges for the summer of 2001 compared to the absence of the amortization in 2004. The amortization of these capacity charges began in August 2002 and ended in July 2003.

Gross operating revenues, fuel and purchased power expenses, and other regulatory credits

Gross operating revenues increased primarily due to:

• an increase of $98.0 million in fuel cost recovery revenues due to higher fuel rates; and
• an increase due to volume/weather, as discussed above.

The increase was partially offset by the following:

• a decrease of $31.9 million in the price applied to unbilled sales, as discussed above;
• a decrease of $12.2 million in rate refund provisions, as discussed above; and
• a decrease of $5.2 million in gross wholesale revenue due to decreased sales to affiliated systems.

Fuel and purchased power expenses increased primarily due to:

• an increase in the recovery from customers of deferred fuel costs; and
• an increase in the market price of natural gas.

Other regulatory credits increased primarily due to:

• the deferral in 2004 of $14.3 million of capacity charges related to generation resource planning as allowed by the LPSC;
• the amortization in 2003 of $11.8 million of deferred capacity charges, as discussed above; and
• the deferral in 2004 of $11.4 million related to Entergy's voluntary severance program, in accordance with a proposed stipulation with the LPSC staff.

2003 Compared to 2002

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

	(In Millions)
2002 net revenue	$922.9
Deferred fuel cost revisions	59.1
Asset retirement obligation	8.2
Volume	(16.2)
Vidalia settlement	(9.2)
Other	8.9
2003 net revenue	$973.7

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

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

The volume variance was due to a decrease in electricity usage in the service territory. Billed usage decreased 1,868 GWh in the industrial sector including the loss of a large industrial customer to cogeneration.

See "Liquidity and Capital Resources" below for more details regarding the September 2002 settlement related to the Vidalia contract.

Gross operating revenues, fuel and purchased power expenses, and other regulatory charges (credits)

Gross operating revenues increased primarily due to:

• an increase of $277.2 million in fuel cost recovery revenues due to higher fuel rates; and
• an increase of $94.7 million in gross wholesale revenue due to increased sales to affiliated systems.

Fuel and purchased power expenses increased primarily due to an increase in the market prices of natural gas and purchased power.

Other regulatory credits increased primarily due to:

• an increase of $8.2 million due to the change in accounting for asset retirement obligations in compliance with SFAS 143, adopted in January 2003. This increase has no effect on net income; and
• an increase of $5.9 million due to the deferral of capacity charges in the third quarter of 2003 as allowed by the LPSC related to generation resource planning.

Other Income Statement Variances

2004 Compared to 2003

Other operation and maintenance expenses decreased primarily due to voluntary severance program accruals of $19.7 million in 2003, partially offset by an increase of $9.1 million in customer service support costs.

2003 Compared to 2002

Other operation and maintenance expenses increased primarily due to:

• voluntary severance program accruals of $19.7 million; and
• an increase of $13.4 million in benefit costs.

Decommissioning expenses increased $10.1 million primarily 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 in decommissioning expense was offset by regulatory credits and interest and dividend income and had no effect on net income.

Taxes other than income taxes increased primarily due to the franchise tax adjustments of $10.8 million recorded in 2002 as a result of a favorable court decision that allowed Entergy Louisiana to receive a refund for certain franchise taxes previously expensed and paid under protest.

Depreciation and amortization expenses increased primarily due to an increase in plant in service.

Interest charges decreased primarily due to decreased interest on long-term debt of $25.5 million due to the redemption of $150 million of First Mortgage Bonds in June 2003 and the redemption of $187 million of First Mortgage Bonds from April through December of 2002, partially offset by the issuance of $150 million of First Mortgage Bonds in March 2002.

Income Taxes

The effective income tax rates for 2004, 2003, and 2002 were 38.4%, 40.0%, and 36.9%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate.  Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued on the balance sheet.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2004, 2003, and 2002 were as follows:

		2004	2003	2002
		(In Thousands)
Cash and cash equivalents at beginning of period		$8,787	$311,800	$42,408
Cash flow provided by (used in):
	Operating activities	424,718	413,939	1,035,777
	Investing activities	(243,231)	(268,372)	(212,333)
	Financing activities	(44,225)	(448,580)	(554,052)
	Net increase (decrease) in cash and cash equivalents	137,262	(303,013)	269,392
Cash and cash equivalents at end of period		$146,049	$8,787	$311,800

Operating Activities

Cash flow from operations increased $10.8 million in 2004 primarily due to the increased collection of deferred fuel costs and the receipt of an income tax payment through Entergy's inter-company tax allocation process. The increase was almost entirely offset by money pool activity.

In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $505 million deduction for Entergy Louisiana on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. In 2004 Entergy Louisiana realized $100 million in cash tax benefit from the method change. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit.  As of December 31, 2004, Entergy Louisiana has a net operating loss (NOL) carryforward for tax purposes of $195.7 million, principally resulting from the change in tax accounting method related to cost of goods sold.  If the tax accounting method change is sustained, Entergy Louisiana expects to utilize the NOL carryforward through 2005.

Cash flow from operations decreased $621.8 million in 2003 as a result of Entergy Louisiana changing its method of accounting for tax purposes related to its wholesale electric power contracts, includingthe contract to purchase power from the Vidalia project (the contract is discussed in Note 8 to the domestic utility companies and System Energy financial statements). The new tax accounting method provided a cumulative cash flow benefit of approximately $790 million through 2004, which is expected to reverse in the years 2005 through 2031. The election did not reduce book income tax expense. The timing of the reversal of this benefit depends on several variables, including the price of power. In a settlement approved by the LPSC, Entergy Louisiana will keep a portion of the benefit in exchange for crediting customer rates. The credit will be $11 million annually through at least 2010. See Part I, Item 1 for additional details concerning the settl ement.

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

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

2004	2003	2002	2001
(In Thousands)
$40,549	($41,317)	$18,854	$3,812

Money pool activity used $81.9 million of Entergy Louisiana's operating cash flow in 2004, provided $60.2 million in 2003, and used $15.0 million in 2002. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.

Investing Activities

The decrease of $25.1 million in net cash used by investing activities in 2004 was primarily due to decreased spending on customer service projects, partially offset by increases in spending on transmission projects and fossil plant projects.

The increase of $56.0 million in net cash used by investing activities in 2003 was primarily due to increased spending on customer service, transmission, and nuclear projects.

Financing Activities

The decrease of $404.4 million in net cash used by financing activities in 2004 was primarily due to:

• the net issuance of $98.0 million of long-term debt in 2004 compared to the retirement of $261.0 million in 2003;
• a principal payment of $14.8 million in 2004 for the Waterford Lease Obligation compared to a principal payment of $35.4 million in 2003; and
• a decrease of $29.0 million in common stock dividends paid.

The decrease of $105.5 million in net cash used by financing activities in 2003 was primarily due to:

• a decrease of $125.9 million in common stock dividends paid; and
• the repurchase of $120 million of common stock from Entergy Corporation in 2002.

The decrease in net cash used in 2003 was partially offset by the following:

• the retirement in 2003 of $150 million of 8.5% Series First Mortgage Bonds compared to the net retirement of $134.6 million of First Mortgage Bonds in 2002; and
• principal payments of $35.4 million in 2003 for the Waterford 3 Lease Obligation compared to principal payments of $15.9 million in 2002.

See Note 5 to the domestic utility companies and System Energy financial statements for details of long-term debt.

Uses of Capital

Entergy Louisiana requires capital resources for:

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

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

	2005	2006-2007	2008-2009	After 2009	Total
	(In Millions)
Planned construction and
capital investment (1)	$455	$472	N/A	N/A	$927
Long-term debt	$55	$-	$7	$924	$986
Operating leases	$10	$11	$6	$2	$29
Purchase obligations (2)	$639	$1,120	$980	$4,691	$7,430
Nuclear fuel lease obligations (3)	$23	$9	N/A	N/A	$32

(1)	Includes approximately $130 to $160 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth.
(2)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Louisiana almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Vidalia purchased power agreement and the Unit Power Sales Agreement, both of which are discussed in Note 8 to the domestic utility companies and System Energy financial statements.
(3)	It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. If such additional financing cannot be arranged, however, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations.

In addition to these contractual obligations, Entergy Louisiana expects to contribute $2.6 million to its pension plans and $8.5 million to other postretirement plans in 2005.

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

In January 2004, Entergy Louisiana signed a definitive agreement to acquire the 718 MW Perryville power plant for $170 million. The agreement has subsequently been amended to allow the current plant owner to retain the interconnection facilities associated with the plant, resulting in a decrease in the acquisition price to $162 million. As a result of the amended terms, the FERC issued an order in October 2004 disclaiming jurisdiction over the acquisition. This order currently is subject to rehearing by the FERC. 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-serv ice power purchase agreement. In addition, Entergy Louisiana and Entergy Gulf States executed an interim power purchase agreement with the plant's owner through the date of the acquisition's closing (as long as that occurs by December 2005) for 100 percent of the output of the Perryville power plant. In April 2004, the bankruptcy court approved Entergy Louisiana's agreement to acquire the plant. In March 2004, Entergy Gulf States and Entergy Louisiana filed with the LPSC for its approval of the acquisition and long-term cost-of-service power purchase agreement. Entergy is seeking approval from the LPSC of cost recovery for the acquisition, giving consideration to the need for the power and the prudence of Entergy Louisiana and Entergy Gulf States in engaging in the transaction. Hearings are scheduled for March 2005. Assuming regulatory approval by the LPSC, Entergy Louisiana expects the Perryville acquisition to close in mid-2005.

As a wholly-owned subsidiary, Entergy Louisiana dividends its earnings to Entergy Corporation at a percentage determined monthly. In addition, all of Entergy Louisiana's retained earnings are currently available for distribution.

Sources of Capital

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

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

Entergy Louisiana issued $285 million of first mortgage bonds in 2004 as follows:

Issue Date	Description	Maturity	Amount
			(In Thousands)
March 2004	5.50% Series	April 2019	$100,000
October 2004	6.40% Series	October 2034	70,000
October 2004	5.09% Series	November 2014	115,000
			$285,000

Entergy Louisiana retired $187.2 million of long-term debt in 2004 as follows:

Retirement Date	Description	Maturity	Amount
			(In Thousands)
November 2004	6.50% Series	March 2008	$115,000
November 2004	9.00% Series	September 2045	72,165
			$187,165

Entergy Louisiana may refinance or redeem debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common and preferred stock issuances by Entergy Louisiana require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs.

In July 2004, Entergy Louisiana renewed its 364-day credit facility and Entergy New Orleans entered into a separate credit facility with the same lender. Both facilities will expire in April 2005. Entergy Louisiana can borrow up to $15 million and Entergy New Orleans can borrow up to $14 million under their respective credit facilities, but at no time can the total amount borrowed under these facilities by the two companies combined exceed $15 million. As of December 31, 2004, no borrowings were outstanding under these facilities. Borrowings and securities issuances by Entergy Louisiana are limited to amounts authorized by the SEC. The current short-term borrowing limitation, including borrowings under the money pool, is $225 million. Under its SEC Orders and without further SEC authorization, Entergy Louisiana cannot incur additional indebtedness or issue other securities unless (a) it and Entergy Corporation maintain a common equity ratio of at least 30% and (b) with the except ion of money pool borrowings, the security to be issued (if rated) and all outstanding securities of Entergy Louisiana, as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy Louisiana's short-term borrowing limits.

Significant Factors and Known Trends

Utility Restructuring

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

At FERC, the pace of restructuring at the wholesale level has begun but has been delayed. It is too early to predict the ultimate effects of changes in United States energy markets. Restructuring issues are complex and are continually affected by events at the national, regional, state, and local levels. However, these changes may result, in the long-term, in fundamental changes in the way traditional integrated utilities and holding company systems, like the Entergy system, conduct their business. Some of these changes may be positive for Entergy, while others may not.

State Rate Regulation

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

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

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

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

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

System Agreement Proceedings

The 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.

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

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

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

	Range of Annual Payments or (Receipts)	Average Annual Payments or (Receipts) for 2005-2009 Period
	(In Millions)	(In Millions)
Entergy Arkansas	$154 to $281	$215
Entergy Gulf States	($130) to ($15)	($63)
Entergy Louisiana	($199) to ($98)	($141)
Entergy Mississippi	($16) to $8	$1
Entergy New Orleans	($17) to ($5)	($12)

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

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

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

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

The LPSC instituted a companion ex-parte System Agreement investigation to litigate several of the System Agreement issues that the LPSC is litigating before the FERC in the previously discussed System Agreement proceeding. This companion proceeding will require the LPSC to interpret various provisions of the System Agreement, including those relating to minimum-run and must-run units, the propriety of the methods used for billing and dispatch on the Entergy System, and the use of a rolling, twelve-month average of system peaks for allocating certain costs. In addition, by this companion proceeding the LPSC is questioning whether Entergy Louisiana and Entergy Gulf States were prudent for not seeking changes to the System Agreement previously, so as to lower costs imposed upon their ratepayers and to increase costs imposed upon ratepayers of other domestic utility companies. The LPSC staff has filed testimony suggesting that the remedy for the alleged imprudence of Entergy Louisiana and Entergy Gulf States should be a reduction in allowed rate of return on common equity of 100 basis points. The domestic utility companies have challenged the propriety of the LPSC's litigating System Agreement issues. Nevertheless, on January 16, 2002 the LPSC affirmed a decision of its ALJ upholding the LPSC staff's right to litigate System Agreement issues at the LPSC, rather than before the FERC. The procedural schedule is suspended at this time and an evidentiary hearing is not scheduled. An unrelated case between the LPSC and Entergy Louisiana raised the question of whether a state regulator is preempted by federal law from reviewing and interpreting 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.

Transmission

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

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

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

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

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

Interconnection Orders

The domestic utility companies (except Entergy New Orleans) are currently defendants to several complaints and rehearing requests before the FERC in which independent generation entities (GenCos) are seeking a refund of monies that the GenCos had previously paid to the Entergy companies for facilities necessary to connect their generation facilities to Entergy's transmission system. The FERC has issued initial orders in response to two of the complaints and in certain other dockets ordering Entergy to refund approximately $100 million in expenses and tax obligations previously paid by the GenCos, including $3 million for Entergy Louisiana. The refunds will be in the form of transmission credits that will be utilized over time as the GenCos take transmission service from Entergy.

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

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

Available Flowgate Capacity Proceeding

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

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

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

Industrial and Commercial Customers

Entergy Louisiana's large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Louisiana's industrial customer base. Entergy Louisiana responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that match specific customer needs and load profiles. Despite these actions, Entergy Louisiana lost a large industrial customer to cogeneration in late 2002. The customer accounted for approximately 2% of its net revenue in 2001. Entergy Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial energy demand, from both existing and new customers. Entergy Louisiana does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Louisiana's market ing efforts in retaining industrial customers.

Market and Credit Risks

Entergy Louisiana has certain market and credit risks inherent in its business operations. Market risks represent the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement.

Interest Rate and Equity Price Risk - Decommissioning Trust Funds

Entergy Louisiana's nuclear decommissioning trust funds expose it to fluctuations in equity prices and interest rates. The NRC requires Entergy Louisiana to maintain trusts to fund the costs of decommissioning Waterford 3. The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that its exposure to market fluctuations will not affect results of operations for the Waterford 3 trust funds because of the application of regulatory accounting principles. The decommissioning trust funds are discussed more thoroughly in Notes 1, 8, and 12 to the domestic utility companies and System Energy financial statements.

Nuclear Matters

Entergy Louisiana owns and operates, through an affiliate, the Waterford 3 nuclear power plant. Entergy Louisiana is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.

In August 2001, the NRC issued a bulletin requesting all pressurized water reactor owners and operators to report on the structural integrity of their reactor vessel head penetration nozzles to justify continued operations past December 31, 2001. These types of reactors are susceptible to stress corrosion cracking of the reactor vessel head nozzles. Waterford is a pressurized water reactor. To date, there has been no primary side stress corrosion cracking identified in the Waterford reactor vessel head. Inspections of the Waterford reactor vessel head will continue during planned refueling outages.

Environmental Risks

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

Litigation Risks

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

Critical Accounting Estimates

The preparation of Entergy Louisiana's financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy Louisiana's financial position or results of operations.

Nuclear Decommissioning Costs

Regulations require Entergy Louisiana to decommission the Waterford 3 nuclear power plant after the facility is taken out of service, and money is collected and deposited in trust funds during the facility's operating life in order to provide for this obligation. Entergy Louisiana conducts periodic decommissioning cost studies (typically updated every three to five years) to estimate the costs that will be incurred to decommission the facility. The following key assumptions have a significant effect on these estimates:

• Cost Escalation Factors - Entergy Louisiana's decommissioning studies include an assumption that decommissioning costs will escalate over present cost levels by an annual factor averaging approximately 4.4%. A 50 basis point change in this assumption could change the ultimate cost of decommissioning a facility by as much as 11%.
• Timing - The date of the plant's retirement must be estimated and an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in "safestore" status for later decommissioning, as permitted by applicable regulations. While the effect of these assumptions cannot be determined with precision, assuming either license extension or use of a "safestore" status can possibly decrease the present value of these obligations.
• Spent Fuel Disposal - Federal regulations require the DOE to provide a permanent repository for the storage of spent nuclear fuel, and legislation has been passed by Congress to develop this repository at Yucca Mountain, Nevada. Until this site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities can have a significant effect (as much as 16% of estimated decommissioning costs). Entergy Louisiana's decommissioning studies include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors.
• Technology and Regulation - To date, there is limited practical experience in the United States with actual decommissioning of large nuclear facilities. As experience is gained and technology changes, cost estimates could also change. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant effect on cost estimates. The effect of these potential changes is not presently determinable. Entergy Louisiana's decommissioning cost studies assume current technologies and regulations.

Entergy Louisiana collects substantially all of the projected costs of decommissioning Waterford 3 through rates charged to customers. The amounts collected through rates, which are based upon decommissioning cost studies, are deposited in decommissioning trust funds. These collections plus earnings on the trust fund investments are estimated to be sufficient to fund the future decommissioning costs. If decommissioning cost study estimates are changed and approved by regulators, collections from customers would also change.

SFAS 143

Entergy Louisiana implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs comprise substantially all of Entergy Louisiana's asset retirement obligations, and the measurement and recording of Entergy Louisiana's decommissioning obligations 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 of Entergy Louisiana to increase significantly, as Entergy Louisiana had previously only recorded this obligation as the related costs were collected from customers, and as earnings were recorded on the related trust funds.
• Fair value approach - SFAS 143 requires that these obligations be measured using a fair value approach. Among other things, this entails the assumption that the costs will be incurred by a third party and will therefore include appropriate profit margins and risk premiums. Entergy Louisiana's decommissioning studies had been based on Entergy Louisiana performing the work, and did not include any such margins or premiums.
• Discount rate - SFAS 143 requires that these obligations be discounted using a credit-adjusted risk-free rate.

The net effect of implementing SFAS 143 for Entergy Louisiana was recorded as a regulatory asset, with no resulting impact on Entergy Louisiana's net income. Entergy Louisiana recorded this regulatory asset because its existing rate mechanism is based on the original or historical cost standard that allows Entergy Louisiana to recover all ultimate costs of decommissioning existing assets from current and future customers. Upon implementation of SFAS 143 in 2003, assets and liabilities increased by $305 million as a result of recording the asset retirement obligation at its fair value of $305 million as determined under SFAS 143, increasing total utility plant by $99 million, reducing accumulated depreciation by $82 million, and recording the related regulatory asset of $124 million.

Unbilled Revenue

As discussed in Note 1 to the domestic utility companies and System Energy financial statements, Entergy Louisiana records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month, including fuel price. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period and fuel price fluctuations, in addition to changes in certain components of the calculation including changes to estimates such as line loss, which affects the estimate of unbilled customer usage, and assumptions regarding price such as the fuel cost recovery mechanism.

Pension and Other Postretirement Benefits

Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 10 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.

Assumptions

Key actuarial assumptions utilized in determining these costs include:

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

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

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

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

Cost Sensitivity

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

Actuarial Assumption	Change in Assumption	Impact on 2004 Pension Cost	Impact on Projected Benefit Obligation
	Increase/(Decrease)
Discount rate	(0.25%)	$1,061	$12,385
Rate of return on plan assets	(0.25%)	$786	-
Rate of increase in compensation	0.25%	$523	$3,018

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

Actuarial Assumption	Change in Assumption	Impact on 2004 Postretirement Benefit Cost	Impact on Accumulated Postretirement Benefit Obligation
	Increase/(Decrease)
Health care cost trend	0.25%	$416	$2,407
Discount rate	(0.25%)	$234	$3,033

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

Accounting Mechanisms

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

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

Costs and Funding

Total pension cost for Entergy Louisiana in 2004 was $3.3 million. Entergy Louisiana anticipates 2005 pension cost to increase to $6.8 million due to decrease in the discount rate (from 6.25% to 6.00%) and the expected rate of return (from 8.75% to 8.5%) used to calculate benefit obligations. Entergy Louisiana contributed $3.9 million to its pension plan in 2004 and anticipates making $2.6 million in contributions in 2005. The decrease in pension funding requirements is due to the Pension Funding Equity Act relief passed in April 2004, partially offset by declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002.

Entergy Louisiana's accumulated benefit obligation at December 31, 2004, and 2002 exceeded plan assets. As a result, Entergy Louisiana was required to recognize an additional minimum liability as prescribed by SFAS 87 in those years. At December 31, 2003, Entergy Louisiana's accumulated benefit obligation was less than plan assets, therefore there was no additional minimum pension liability required to be recognized. At December 31, 2004, Entergy Louisiana recorded an additional pension minimum liability of $38.9 million; an offsetting intangible asset of $4.8 million, and a regulatory asset of $34.1 million. Net income for 2004, 2003, and 2002 was not impacted by the additional minimum pension liability.

Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 2004 were $12.3 million, including $2.8 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Louisiana expects 2005 postretirement health care and life insurance benefit costs to approximate $12.7 million, including $3.2 million in savings due to the estimated effect of future Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the decrease in the discount rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate used to calculate benefit obligations.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Entergy Louisiana, Inc.:

We have audited the accompanying balance sheets of Entergy Louisiana, Inc. as of December 31, 2004 and 2003, and the related statements of income, retained earnings, and cash flows (pages 219 through 224 and applicable items in pages 284 through 348) for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Louisiana, Inc. as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 5 and Note 8 to the notes to respective financial statements, in 2003 Entergy Louisiana, Inc. adopted the provisions of Statement of Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, and Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

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

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 8, 2005

ENTERGY LOUISIANA, INC.
INCOME STATEMENTS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
OPERATING REVENUES
Domestic electric	$2,226,986	$2,165,570	$1,815,352
OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and
gas purchased for resale	671,549	525,645	436,568
Purchased power	667,893	668,337	438,627
Nuclear refueling outage expenses	13,633	11,130	11,502
Other operation and maintenance	367,824	376,770	340,803
Decommissioning	21,958	20,569	10,422
Taxes other than income taxes	68,999	70,084	60,698
Depreciation and amortization	197,380	192,972	182,871
Other regulatory charges (credits) - net	(43,765)	(2,160)	17,219
TOTAL	1,965,471	1,863,347	1,498,710
OPERATING INCOME	261,515	302,223	316,642
OTHER INCOME
Allowance for equity funds used during construction	7,494	6,900	5,195
Interest and dividend income	8,209	8,820	7,668
Miscellaneous - net	(929)	(3,100)	(3,244)
TOTAL	14,774	12,620	9,619
INTEREST AND OTHER CHARGES
Interest on long-term debt	70,210	73,227	98,242
Other interest - net	3,931	3,529	2,425
Allowance for borrowed funds used during construction	(4,822)	(5,475)	(3,880)
TOTAL	69,319	71,281	96,787
INCOME BEFORE INCOME TAXES	206,970	243,562	229,474
Income taxes	79,475	97,408	84,765
NET INCOME	127,495	146,154	144,709
Preferred dividend requirements and other	6,714	6,714	6,714
EARNINGS APPLICABLE TO
COMMON STOCK	$120,781	$139,440	$137,995
See Notes to Respective Financial Statements.

ENTERGY LOUISIANA, INC.
STATEMENTS OF CASH FLOWS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
OPERATING ACTIVITIES
Net income	$127,495	$146,154	$144,709
Adjustments to reconcile net income to net cash flow provided by operating activities:
Reserve for regulatory adjustments	14,076	1,858	-
Other regulatory charges (credits) - net	(43,765)	(2,160)	17,219
Depreciation, amortization, and decommissioning	219,338	213,541	193,293
Deferred income taxes and investment tax credits	75,078	859,157	39,849
Changes in working capital:
Receivables	(36,185)	(4,418)	(68,936)
Accounts payable	(36,862)	49,028	7,370
Taxes accrued	89,079	(804,805)	779,590
Interest accrued	(1,791)	(10,324)	(3,971)
Deferred fuel costs	21,955	(56,211)	(41,891)
Other working capital accounts	20,693	10,395	(118,718)
Provision for estimated losses and reserves	6,119	12,194	5,818
Changes in other regulatory assets	(14,456)	59,169	(23,879)
Other	(16,056)	(59,639)	105,324
Net cash flow provided by operating activities	424,718	413,939	1,035,777
INVESTING ACTIVITIES
Construction expenditures	(240,283)	(257,754)	(209,826)
Allowance for equity funds used during construction	7,494	6,900	5,195
Nuclear fuel purchases	-	(41,525)	(50,473)
Proceeds from the sale/leaseback of nuclear fuel	-	41,525	50,473
Decommissioning trust contributions and realized
change in trust assets	(12,615)	(17,506)	(13,854)
Changes in other investments - net	2,173	(12)	6,152
Net cash flow used in investing activities	(243,231)	(268,372)	(212,333)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	282,745	-	144,679
Retirement of long-term debt	(203,756)	(296,366)	(300,617)
Repurchase of common stock	-	-	(120,000)
Dividends paid:
Common stock	(116,500)	(145,500)	(271,400)
Preferred stock	(6,714)	(6,714)	(6,714)
Net cash flow used in financing activities	(44,225)	(448,580)	(554,052)
Net increase (decrease) in cash and cash equivalents	137,262	(303,013)	269,392
Cash and cash equivalents at beginning of period	8,787	311,800	42,408
Cash and cash equivalents at end of period	$146,049	$8,787	$311,800
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid/(received) during the period for:
Interest - net of amount capitalized	$73,170	$84,089	$99,998
Income taxes	($70,650)	$35,128	($781,540)
See Notes to Respective Financial Statements.

ENTERGY LOUISIANA, INC.
BALANCE SHEETS
ASSETS
	December 31,
	2004	2003
	(In Thousands)
CURRENT ASSETS
Cash and cash equivalents:
Cash	$3,875	$8,787
Temporary cash investments - at cost,
which approximates market	142,174	-
Total cash and cash equivalents	146,049	8,787
Accounts receivable:
Customer	88,154	93,393
Allowance for doubtful accounts	(3,135)	(4,487)
Associated companies	43,121	9,074
Other	13,070	12,334
Accrued unbilled revenues	143,453	138,164
Total accounts receivable	284,663	248,478
Deferred fuel costs	8,654	30,609
Accumulated deferred income taxes	12,712	-
Materials and supplies - at average cost	77,665	74,349
Deferred nuclear refueling outage costs	5,605	19,226
Prepayments and other	6,861	67,623
TOTAL	542,209	449,072
OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity	14,230	14,230
Decommissioning trust funds	172,083	151,996
Non-utility property - at cost (less accumulated depreciation)	21,176	21,307
Other	4	2,177
TOTAL	207,493	189,710
UTILITY PLANT
Electric	5,985,889	5,836,914
Property under capital lease	250,964	250,102
Construction work in progress	188,848	172,405
Nuclear fuel under capital lease	31,655	65,066
TOTAL UTILITY PLANT	6,457,356	6,324,487
Less - accumulated depreciation and amortization	2,799,936	2,686,778
UTILITY PLANT - NET	3,657,420	3,637,709
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
SFAS 109 regulatory asset - net	132,686	156,111
Other regulatory assets	302,456	217,689
Long-term receivables	10,736	1,511
Other	25,994	22,737
TOTAL	471,872	398,048
TOTAL ASSETS	$4,878,994	$4,674,539
See Notes to Respective Financial Statements.
ENTERGY LOUISIANA, INC.
BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
	December 31,
	2004	2003
	(In Thousands)
CURRENT LIABILITIES
Currently maturing long-term debt	$55,000	$14,809
Accounts payable:
Associated companies	57,681	101,191
Other	128,523	121,875
Customer deposits	66,963	61,215
Accumulated deferred income taxes	-	566
Taxes accrued	7,268	-
Interest accrued	18,438	20,229
Obligations under capital leases	22,753	35,506
Other	10,428	5,110
TOTAL	367,054	360,501
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	1,805,410	1,728,156
Accumulated deferred investment tax credits	96,130	101,258
Obligations under capital leases	8,903	29,560
Other regulatory liabilities	51,260	39,026
Decommissioning liabilities	347,255	325,298
Accumulated provisions	92,653	86,534
Long-term debt	930,695	887,687
Other	106,815	47,981
TOTAL	3,439,121	3,245,500
Commitments and Contingencies
SHAREHOLDERS' EQUITY
Preferred stock without sinking fund	100,500	100,500
Common stock, no par value, authorized 250,000,000
shares; issued 165,173,180 shares in 2004 and 2003	1,088,900	1,088,900
Capital stock expense and other	(1,718)	(1,718)
Retained earnings	5,137	856
Less - treasury stock, at cost (18,202,573 shares in 2004 and 2003)	120,000	120,000
TOTAL	1,072,819	1,068,538
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$4,878,994	$4,674,539
See Notes to Respective Financial Statements.

ENTERGY LOUISIANA, INC.
STATEMENTS OF RETAINED EARNINGS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
Retained Earnings, January 1	$856	$6,916	$140,321
Add:
Net income	127,495	146,154	144,709
Deduct:
Dividends declared:
Preferred stock	6,714	6,714	6,714
Common stock	116,500	145,500	271,400
Total	123,214	152,214	278,114
Retained Earnings, December 31	$5,137	$856	$6,916
See Notes to Respective Financial Statements.

ENTERGY LOUISIANA, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
	2004	2003	2002	2001	2000
	(In Thousands)
Operating revenues	$2,226,986	$2,165,570	$1,815,352	$1,901,913	$2,062,437
Net Income	$127,495	$146,154	$144,709	$132,550	$162,679
Total assets	$4,878,994	$4,674,539	$4,753,704	$4,149,701	$4,289,409
Long-term obligations (1)	$939,598	$917,247	$919,319	$1,197,473	$1,411,345
(1) Included long-term debt (excluding currently maturing debt), preferred stock with sinking fund (for the year 2000 only), and noncurrent capital lease obligations.
	2004	2003	2002	2001	2000
	(Dollars In Millions)
Electric Operating Revenues:
Residential	$770	$739	$638	$658	$717
Commercial	501	473	403	429	441
Industrial	779	723	637	760	767
Governmental	38	41	36	39	39
Total retail	2,088	1,976	1,714	1,886	1,964
Sales for resale:
Associated companies	96	102	8	25	21
Non-associated companies	13	12	11	23	40
Other	30	76	82	(32)	38
Total	$2,227	$2,166	$1,815	$1,902	$2,063
Billed Electric Energy Sales (GWh):
Residential	8,842	8,795	8,780	8,255	8,648
Commercial	5,762	5,622	5,538	5,369	5,367
Industrial	13,140	12,870	14,738	14,402	15,184
Governmental	439	491	510	498	481
Total retail	28,183	27,778	29,566	28,524	29,680
Sales for resale:
Associated companies	1,129	1,344	146	381	228
Non-associated companies	122	132	139	334	554
Total	29,434	29,254	29,851	29,239	30,462

ENTERGY MISSISSIPPI, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

2004 Compared to 2003

Net income increased $6.4 million primarily due to higher net revenue, partially offset by higher other operation and maintenance expenses and higher taxes other than income taxes.

2003 Compared to 2002

Net income increased $14.7 million primarily due to higher net revenue, partially offset by higher other operation and maintenance expenses and depreciation and amortization expenses, and lower interest income.

Net Revenue

2004 Compared to 2003

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

	(In Millions)
2003 net revenue	$426.6
Volume/weather	6.4
Net wholesale revenue	5.0
Other	5.5
2004 net revenue	$443.5

The volume/weather variance resulted from an increase of 247 GWh in weather-adjusted usage, partially offset by the effect of milder weather on billed sales.

The net wholesale revenue variance resulted from an increase in energy available for resale sales, partially offset by a decrease in the average price of energy supplied for affiliated sales.

Gross operating revenues, fuel and purchased power expenses, and other regulatory charges (credits)

Gross operating revenues increased primarily due to an increase of $174.0 million in fuel cost recovery revenues due to higher fuel rates and an increase of $26.3 million in gross wholesale revenue. The increase was partially offset by a decrease of $37.6 million in Grand Gulf revenue as a result of the cessation of the Grand Gulf Accelerated Tariff in July 2003.

Fuel and purchased power expenses increased primarily due to the over-recovery of fuel and purchased power costs as a result of higher fuel rates. Entergy Mississippi's fuel rates include an energy cost recovery rider to recover projected energy costs. Actual fuel and purchased power costs were lower than those projected in the computation of the energy cost factors for the third quarter of 2004 which contributed to the over-recovery of fuel and purchased power costs. The MPSC has allowed Entergy Mississippi to refund these over-recoveries in the second and third quarters of 2005. The energy cost recovery rider is discussed in more detail in Note 2 to the domestic and System Energy financial statements.

Other regulatory charges (credits) have no material effect on net income due to recovery and/or refund of such expenses. Other regulatory credits increased primarily due to the under-recovery through the Grand Gulf rider of Grand Gulf capacity charges.

2003 Compared to 2002

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

	(In Millions)
2002 net revenue	$380.2
Base rates	48.3
Other	(1.9)
2003 net revenue	$426.6

The increase in base rates was effective January 2003 as approved by the MPSC.

Gross operating revenue, fuel and purchased power expenses, and other regulatory charges (credits)

Gross operating revenues increased primarily due to an increase in base rates effective January 2003 and an increase of $29.7 million in fuel cost recovery revenues due to quarterly changes in the fuel factor resulting from the increases in market prices of natural gas and purchased power. This increase was partially offset by a decrease of $35.9 million in gross wholesale revenue as a result of decreased generation and purchases that resulted in less energy available for resale sales.

Fuel and fuel-related expenses decreased primarily due to the decreased recovery of fuel and purchased power costs and decreased generation, partially offset by an increase in the market price of purchased power.

Other regulatory charges increased primarily due to over-recovery of capacity charges related to the Grand Gulf rate rider and the cessation of the Grand Gulf Accelerated Recovery Tariff that was suspended in July 2003.

Other Income Statement Variances

2004 Compared to 2003

Other operation and maintenance expenses increased primarily due to:

• an increase of $6.6 million in customer service support costs; and
• an increase of $3.7 million in benefit costs.

The increase was partially offset by the absence of the voluntary severance program accruals of $7.1 million that occurred in 2003.

Taxes other than income taxes increased primarily due to a higher assessment of ad valorem and franchise taxes compared to the same period in 2003.

2003 Compared to 2002

Other operation and maintenance expenses increased primarily due to:

• voluntary severance program accruals of $7.1 million; and
• an increase of $4.4 million in benefit costs.

The increases were partially offset by a decrease of $4.0 million in plant maintenance expense due to outage costs at a fossil plant in 2002.

Depreciation and amortization expense increased due to an increase in plant in service.

Interest and dividend income decreased as result of carrying charges associated with under-recovery of fuel and purchased power costs during 2002.

Income Taxes

The effective income tax rates for 2004, 2003, and 2002 were 33.5%, 33.9%, and 25.4%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate.  Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued on the balance sheet.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2004, 2003, and 2002 were as follows:

		2004	2003	2002
		(In Thousands)
Cash and cash equivalents at beginning of period		$63,838	$147,721	$54,048
Cash flow provided by (used in):
	Operating activities	258,179	253,288	156,868
	Investing activities	(151,505)	(264,495)	(135,122)
	Financing activities	(90,116)	(72,676)	71,927
	Net increase (decrease) in cash and cash equivalents	16,558	(83,883)	93,673
Cash and cash equivalents at end of period		$80,396	$63,838	$147,721

Operating Activities

Cash flow from operations increased by $4.9 million in 2004 primarily due to money pool activity and an increase in recovery of deferred fuel and purchased power costs, partially offset by an $12 million income tax payment in 2004 compared to a $78 million income tax refund in 2003 and an increase in the account receivable balance as a result of the timing of customer collections.

Cash flow from operations increased by $96.4 million in 2003 primarily due to a $78 million income tax refund and increased net income, partially offset by money pool activity.

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

2004	2003	2002	2001
(In Thousands)
$21,584	$22,076	$8,702	$11,505

Money pool activity provided $0.5 million of Entergy Mississippi's operating cash flows in 2004, used $13.4 million of its operating cash flows in 2003, and provided $2.8 million of its operating cash flows in 2002. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.

Investing Activities

Net cash used in investing activities decreased $113.0 million in 2004 primarily due to:

• cash used in 2003 for other regulatory investments of $72.6 million as a result of under-recovered fuel and purchased power costs;
• a decrease of $25.6 million in capital expenditures in 2004 due to decreased spending on customer care projects and less transmission upgrade work requested by merchant generators; and
• the maturity in 2004 of $7.5 million of other temporary investments that had been made in 2003, which provided cash in 2004.

Net cash used in investing activities increased $129.4 in 2003 primarily due to cash used for other regulatory investments of $72.6 million as a result of under-recovered fuel and purchased power costs and other temporary cash investments of $18.6 million that provided cash in 2002 upon maturity.

In May 2003, Entergy Mississippi filed and the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Under the MPSC's order, Entergy Mississippi deferred until 2004 the collection of fuel under-recoveries for the first and second quarters of 2003 that would have been collected in the third and fourth quarters of 2003, respectively. The deferred amount of $77.6 million plus carrying charges was collected over a twelve-month period that began in January 2004.

Financing Activities

Net cash used in financing activities increased $17.4 million in 2004 primarily due to an increase of $15.1 million in dividends paid.

Net cash used in financing activities increased $144.6 million in 2003 primarily due to a decrease in net issuances of long-term debt.

See Note 5 to the domestic utility companies and System Energy financial statements for details on long-term debt.

Uses of Capital

Entergy Mississippi requires capital resources for:

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

Following are the amounts of Entergy Mississippi's planned construction and other capital investments, and existing debt obligations:

	2005	2006-2007	2008-2009	After 2009	Total
	(In Millions)
Planned construction and
capital investment (1)	$147	$381	N/A	N/A	$528
Long-term debt	-	-	$100	$595	$695
Operating leases	$7	$10	$6	$11	$34
Purchase obligations (2)	$190	$361	$336	$2,059	$2,946

(1)

Includes approximately $120 to $140 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems, and to support normal customer growth.

(2)

Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Mississippi almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the domestic utility companies and System Energy financial statements.

In addition to these contractual obligations, Entergy Mississippi expects to contribute $3.4 million to its pension plans and $4.2 million to other postretirement plans in 2005.

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

As a wholly-owned subsidiary, Entergy Mississippi dividends its earnings to Entergy Corporation at a percentage determined monthly. Entergy Mississippi's long-term debt indentures restrict the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock. As of December 31, 2004, Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $68.5 million.

Sources of Capital

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

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

The following table lists First Mortgage Bonds issued by Entergy Mississippi in 2004:

Issue Date	Description	Maturity	Amount
			(In Thousands)
April 2004	6.25% Series	April 2034	$100,000
April 2004	4.65% Series	May 2011	80,000
			$180,000

The following table lists First Mortgage Bonds retired by Entergy Mississippi in 2004:

Retirement Date	Description	Maturity	Amount
			(In Thousands)
May 2004	6.20% Series	May 2004	$75,000
May 2004	6.45% Series	April 2008	80,000
May 2004	7.70% Series	July 2023	60,000
			$215,000

In September 2004, Entergy Mississippi arranged the issuance of $16 million of Mississippi Business Finance Corporation 4.60% Series Pollution Control Revenue Refunding Bonds (Entergy Mississippi, Inc. Project) Series 2004 due April 2022. The proceeds from this issuance were used to redeem prior to maturity, $7.9 million of 7.0% Series Washington County Bonds due April 2022 and $8.1 million of 7.0% Series Warren County, Mississippi Bonds due April 2022.

Entergy Mississippi may refinance or redeem debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common and preferred stock issuances by Entergy Mississippi require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy Mississippi has sufficient capacity under these tests to meet its foreseeable capital needs.

Entergy Mississippi has a 364-day credit facility available expiring May 2005 in the amount of $25 million of which none was drawn at December 31, 2004. Borrowings and securities issuances by Entergy Mississippi are limited to amounts authorized by the SEC. The current short-term borrowing limitation, including borrowings under the money pool, is $160 million. Under its SEC Orders and without further SEC authorization, Entergy Mississippi cannot incur additional indebtedness or issue other securities unless (a) it and Entergy Corporation maintain a common equity ratio of at least 30% and (b) with the exception of money pool borrowings, the security to be issued (if rated) and all outstanding securities of Entergy Mississippi, as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy Mississippi's short-term borrowing l imits.

Significant Factors and Known Trends

Utility Restructuring

The MPSC has recommended not pursuing open access at this time. At FERC, the pace of restructuring at the wholesale level has begun but has been delayed. It is too early to predict the ultimate effects of changes in U.S. energy markets. Restructuring issues are complex and are continually affected by events at the national, regional, state, and local levels. However, these changes may result, in the long-term, in fundamental changes in the way traditional integrated utilities and holding company systems, like the Entergy system, conduct their business. Some of these changes may be positive for Entergy, while others may not be.

State and Local Rate Regulation

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

As discussed in Note 2 to the domestic utility companies and System Energy financial statements, Entergy Mississippi made its annual formula rate plan filing with the MPSC in March 2004 based on a 2003 test year. In April 2004, the MPSC approved a joint stipulation entered into between the Mississippi Public Utilities Staff and Entergy Mississippi that provides for no change in rates based on an adjusted return on common equity mid-point of 10.77%, establishing an allowed annual regulatory earnings range of 9.3% to 12.2%.

In December 2002, the MPSC issued a final order approving a joint stipulation entered into by Entergy Mississippi and the Mississippi Public Utilities Staff in October 2002. The final order resulted in a $48.2 million rate increase effective January 2003.

Entergy Mississippi's fuel costs recovered from customers are subject to regulatory scrutiny. Entergy Mississippi's retail rate matters and proceedings, including fuel cost recovery-related issues are discussed more thoroughly in Note 2 to the domestic utility companies and System Energy financial statements.

System Agreement Proceedings

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

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

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

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

	Range of Annual Payments or (Receipts)	Average Annual Payments or (Receipts) for 2005-2009 Period
	(In Millions)	(In Millions)
Entergy Arkansas	$154 to $281	$215
Entergy Gulf States	($130) to ($15)	($63)
Entergy Louisiana	($199) to ($98)	($141)
Entergy Mississippi	($16) to $8	$1
Entergy New Orleans	($17) to ($5)	($12)

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

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

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

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

Transmission

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

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

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

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

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

Interconnection Orders

The domestic utility companies (except Entergy New Orleans) are currently defendants to several complaints and rehearing requests before the FERC in which independent generation entities (GenCos) are seeking a refund of monies that the GenCos had previously paid to the Entergy companies for facilities necessary to connect their generation facilities to Entergy's transmission system. The FERC has issued initial orders in response to two of the complaints and in certain other dockets ordering Entergy to refund approximately $100 million in expenses and tax obligations previously paid by the GenCos, including $27 million for Entergy Mississippi. The refunds will be in the form of transmission credits that will be utilized over time as the GenCos take transmission service from Entergy. To the extent the Entergy companies are ordered to provide such refunds, these costs will qualify for inclusion in the Entergy companies' rates. The recovery of these costs is not automatic, however, especially at the retail level, where the majority of the cost recovery would occur. Entergy intends to pursue all regulatory and legal avenues available to it in order to have these orders reversed and have the affected interconnection agreements reinstated as agreed to originally by the generators.

Available Flowgate Capacity Proceeding

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

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

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

Market and Credit Risks

Entergy Mississippi has certain market and credit risks inherent in its business operations. Market risks represent the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement.

Critical Accounting Estimates

The preparation of Entergy Mississippi's financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements could produce estimates that would have a material impact on the presentation of Entergy Mississippi's financial position or results of operations.

Unbilled Revenue

As discussed in Note 1 to the domestic utility companies and System Energy financial statements, Entergy Mississippi records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation including changes to estimates such as line loss, which affects the estimate of unbilled customer usage, and assumptions regardi ng price such as the fuel cost recovery mechanism.

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 10 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.

Assumptions

Key actuarial assumptions utilized in determining these costs include:

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

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

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

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

Cost Sensitivity

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

Actuarial Assumption	Change in Assumption	Impact on 2004 Pension Cost	Impact on Projected Benefit Obligation
	Increase/(Decrease)
Discount rate	(0.25%)	$598	$6,213
Rate of return on plan assets	(0.25%)	$420	-
Rate of increase in compensation	0.25%	$271	$1,463

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

Actuarial Assumption	Change in Assumption	Impact on 2004 Postretirement Benefit Cost	Impact on Accumulated Postretirement Benefit Obligation
	Increase/(Decrease)
Health care cost trend	0.25%	$174	$1,161
Discount rate	(0.25%)	$110	$1,519

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

Accounting Mechanisms

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

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

Costs and Funding

Total pension cost for Entergy Mississippi in 2004 was $2.1 million. Entergy anticipates 2005 pension cost to increase to $4.4 million due to decrease in the discount rate (from 6.25% to 6.00%) and the expected rate of return (from 8.75% to 8.5%) used to calculate benefit obligations. Entergy Mississippi contributed $1.8 million to its pension plan in 2004, and anticipates making $3.4 million in contributions in 2005. The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, partially offset by the Pension Funding Equity Act relief passed in April 2004.

Entergy Mississippi's accumulated benefit obligation at December 31, 2004, 2003, and 2002 exceeded plan assets. As a result, Entergy Mississippi was required to recognize an additional minimum liability as prescribed by SFAS 87. At December 31, 2004, Entergy Mississippi increased its additional minimum liability to $23.5 million from $7.3 million at December 31, 2003. Entergy Mississippi increased its intangible asset for the unrecognized prior service cost to $3.3 million at December 31, 2004 from $0.9 million at December 31, 2003. Entergy Mississippi also increased the regulatory asset to $20.2 million at December 31, 2004 from $6.4 million at December 31, 2003. Net income for 2004, 2003, and 2002 was not impacted.

Total postretirement health care and life insurance benefit costs for Entergy Mississippi in 2004 were $3.8 million, including $1.7 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Mississippi expects 2005 postretirement health care and life insurance benefit costs to approximate $4.2 million, including $1.9 million in savings due to the estimated effect of future Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the decrease in the discount rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate used to calculate benefit obligations.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Entergy Mississippi, Inc.:

We have audited the accompanying balance sheets of Entergy Mississippi, Inc. as of December 31, 2004 and 2003, and the related statements of income, retained earnings, and cash flows (pages 240 through 244 and applicable items in pages 284 through 348) for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Mississippi, Inc. as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.

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

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 8, 2005

ENTERGY MISSISSIPPI, INC.
INCOME STATEMENTS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
OPERATING REVENUES
Domestic electric	$1,213,629	$1,035,360	$991,095
OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and
gas purchased for resale	335,271	155,168	318,350
Purchased power	436,013	449,971	315,963
Other operation and maintenance	178,007	174,192	170,052
Taxes other than income taxes	53,443	47,734	47,993
Depreciation and amortization	65,452	62,984	55,409
Other regulatory charges (credits) - net	(1,171)	3,664	(23,438)
TOTAL	1,067,015	893,713	884,329
OPERATING INCOME	146,614	141,647	106,766
OTHER INCOME
Allowance for equity funds used during construction	4,402	4,576	3,844
Interest and dividend income	2,550	1,030	4,213
Miscellaneous - net	(1,508)	(2,242)	(2,572)
TOTAL	5,444	3,364	5,485
INTEREST AND OTHER CHARGES
Interest on long-term debt	41,681	43,879	42,580
Other interest - net	2,956	3,585	2,884
Allowance for borrowed funds used during construction	(3,116)	(3,942)	(3,467)
TOTAL	41,521	43,522	41,997
INCOME BEFORE INCOME TAXES	110,537	101,489	70,254
Income taxes	37,040	34,431	17,846
NET INCOME	73,497	67,058	52,408
Preferred dividend requirements and other	3,369	3,369	3,369
EARNINGS APPLICABLE TO
COMMON STOCK	$70,128	$63,689	$49,039
See Notes to Respective Financial Statements.

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ENTERGY MISSISSIPPI, INC.
STATEMENTS OF CASH FLOWS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
OPERATING ACTIVITIES
Net income	$73,497	$67,058	$52,408
Adjustments to reconcile net income to net cash flow provided by operating activities:
Other regulatory charges (credits) - net	(1,171)	3,664	(23,438)
Depreciation and amortization	65,452	62,984	55,409
Deferred income taxes and investment tax credits	61,829	34,836	(7,940)
Changes in working capital:
Receivables	(14,894)	(23,179)	(2,000)
Fuel inventory	940	575	(828)
Accounts payable	432	1,244	16,736
Taxes accrued	(27,759)	74,487	(2,670)
Interest accrued	(1,285)	(5,922)	2,027
Deferred fuel costs	111,871	21,669	67,981
Other working capital accounts	2,684	11,255	(22,897)
Provision for estimated losses and reserves	2,789	(1,137)	386
Changes in other regulatory assets	9,401	(9,061)	(6,028)
Other	(25,607)	14,815	27,722
Net cash flow provided by operating activities	258,179	253,288	156,868
INVESTING ACTIVITIES
Construction expenditures	(163,413)	(188,995)	(157,532)
Allowance for equity funds used during construction	4,402	4,576	3,844
Changes in other temporary investments - net	7,506	(7,506)	18,566
Other regulatory investments	-	(72,570)	- -
Net cash flow used in investing activities	(151,505)	(264,495)	(135,122)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	178,510	292,393	167,596
Retirement of long-term debt	(218,457)	(330,000)	(65,000)
Dividends paid:
Common stock	(46,800)	(31,700)	(27,300)
Preferred stock	(3,369)	(3,369)	(3,369)
Net cash flow provided by (used in) financing activities	(90,116)	(72,676)	71,927
Net increase (decrease) in cash and cash equivalents	16,558	(83,883)	93,673
Cash and cash equivalents at beginning of period	63,838	147,721	54,048
Cash and cash equivalents at end of period	$80,396	$63,838	$147,721
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid/(received) during the period for:
Interest - net of amount capitalized	$43,824	$51,126	$40,572
Income taxes	$11,995	($78,091)	$28,440

ENTERGY MISSISSIPPI, INC.
BALANCE SHEETS
ASSETS
	December 31,
	2004	2003
	(In Thousands)
CURRENT ASSETS
Cash and cash equivalents:
Cash	$4,716	$6,381
Temporary cash investment - at cost,
which approximates market	75,680	57,457
Total cash and cash equivalents	80,396	63,838
Other temporary investments	- -	7,506
Accounts receivable:
Customer	68,821	59,729
Allowance for doubtful accounts	(1,126)	(1,375)
Associated companies	22,616	25,935
Other	12,133	6,400
Accrued unbilled revenues	34,348	31,209
Total accounts receivable	136,792	121,898
Deferred fuel costs	- -	89,078
Accumulated deferred income taxes	27,924	- -
Fuel inventory - at average cost	4,137	5,077
Materials and supplies - at average cost	18,414	17,682
Prepayments and other	15,413	9,583
TOTAL	283,076	314,662
OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity	5,531	5,531
Non-utility property - at cost (less accumulated depreciation)	6,465	6,466
TOTAL	11,996	11,997
UTILITY PLANT
Electric	2,385,465	2,243,852
Property under capital lease	95	136
Construction work in progress	89,921	108,829
TOTAL UTILITY PLANT	2,475,481	2,352,817
Less - accumulated depreciation and amortization	870,188	837,492
UTILITY PLANT - NET	1,605,293	1,515,325
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
SFAS 109 regulatory asset - net	17,628	28,964
Other regulatory assets	82,674	58,287
Long-term receivable	4,510	- -
Other	31,009	23,117
TOTAL	135,821	110,368
TOTAL ASSETS	$2,036,186	$1,952,352
See Notes to Respective Financial Statements.
ENTERGY MISSISSIPPI, INC.
BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
	December 31,
	2004	2003
	(In Thousands)
CURRENT LIABILITIES
Currently maturing long-term debt	$ -	$75,000
Accounts payable:
Associated companies	65,806	62,705
Other	25,543	28,212
Customer deposits	37,333	33,861
Taxes accrued	40,106	39,041
Accumulated deferred income taxes	- -	7,120
Interest accrued	12,487	13,772
Deferred fuel costs	22,793	- -
Obligations under capital leases	43	41
Other	8,341	2,567
TOTAL	212,452	262,319
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	438,321	385,395
Accumulated deferred investment tax credits	13,687	15,092
Obligations under capital leases	52	95
Accumulated provisions	12,718	9,929
Long-term debt	695,073	654,956
Other	76,071	60,082
TOTAL	1,235,922	1,125,549
Commitments and Contingencies
SHAREHOLDERS' EQUITY
Preferred stock without sinking fund	50,381	50,381
Common stock, no par value, authorized 15,000,000
shares; issued and outstanding 8,666,357 shares in 2004 and 2003	199,326	199,326
Capital stock expense and other	(59)	(59)
Retained earnings	338,164	314,836
TOTAL	587,812	564,484
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$2,036,186	$1,952,352
See Notes to Respective Financial Statements.

ENTERGY MISSISSIPPI, INC.
STATEMENTS OF RETAINED EARNINGS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
Retained Earnings, January 1	$314,836	$282,847	$261,108
Add:
Net income	73,497	67,058	52,408
Deduct:
Dividends declared:
Preferred stock	3,369	3,369	3,369
Common stock	46,800	31,700	27,300
Total	50,169	35,069	30,669
Retained Earnings, December 31	$338,164	$314,836	$282,847
See Notes to Respective Financial Statements.

ENTERGY MISSISSIPPI, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
	2004	2003	2002	2001	2000
	(In Thousands)
Operating revenues	$1,213,629	$1,035,360	$991,095	$1,093,741	$937,371
Net Income	$73,497	$67,058	$52,408	$39,620	$38,973
Total assets	$2,036,186	$1,952,352	$1,832,372	$1,683,026	$1,683,939
Long-term obligations (1)	$695,125	$655,051	$510,240	$589,937	$584,678
(1) Included long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations.
	2004	2003	2002	2001	2000
	(Dollars In Millions)
Electric Operating Revenues:
Residential	$467	$410	$375	$391	$341
Commercial	397	342	310	328	275
Industrial	204	174	165	191	161
Governmental	38	32	29	31	26
Total retail	1,106	958	879	941	803
Sales for resale:
Associated companies	39	21	63	111	83
Non-associated companies	30	21	15	21	27
Other	39	35	34	22	25
Total	$1,214	$1,035	$991	$1,095	$938
Billed Electric Energy Sales (GWh):
Residential	5,085	5,092	5,092	4,867	4,976
Commercial	4,518	4,476	4,445	4,322	4,307
Industrial	2,977	2,939	2,910	3,051	3,188
Governmental	398	384	382	381	376
Total retail	12,978	12,891	12,829	12,621	12,847
Sales for resale:
Associated companies	305	112	1,123	1,728	1,276
Non-associated companies	393	331	197	289	313
Total	13,676	13,334	14,149	14,638	14,436

ENTERGY NEW ORLEANS, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income (Loss)

2004 Compared to 2003

Net income increased $20.2 million primarily due to higher net revenue.

2003 Compared to 2002

Entergy New Orleans had net income of $7.9 million in 2003 compared to a net loss in 2002. The increase was due to higher net revenue and lower interest expense, partially offset by higher other operation and maintenance expenses and depreciation and amortization expenses.

Net Revenue

2004 Compared to 2003

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

	(In Millions)
2003 net revenue	$208.3
Base rates	10.6
Volume/weather	8.3
2004 deferrals	7.5
Price applied to unbilled electric sales	3.7
Other	0.6
2004 net revenue	$239.0

The increase in base rates was effective June 2003. The rate increase is discussed in Note 2 to the domestic utility companies and System Energy financial statements.

The volume/weather variance is primarily due to increased billed electric usage of 162 GWh in the industrial service sector. The increase was partially offset by milder weather in the residential and commercial sectors.

The 2004 deferrals variance is due to the deferral of voluntary severance plan and fossil plant maintenance expenses in accordance with a stipulation approved by the City Council in August 2004. The stipulation allows for the recovery of these costs through amortization of a regulatory asset. The voluntary severance plan and fossil plant maintenance expenses are being amortized over a five-year period that became effective January 2004 and January 2003, respectively. The formula rate plan is discussed in Note 2 to the domestic utility companies and System Energy financial statements.

The price applied to unbilled electric sales variance is due to an increase in the fuel price applied to unbilled sales.

Gross operating revenues, fuel and purchased power expenses, and other regulatory credits

Gross operating revenues increased primarily due to an increase in gross wholesale revenue as a result of an increase of $32.4 million in sales to affiliates and an increase of $28.7 million in fuel revenues due to higher fuel rates, in addition to the net revenue items mentioned above.

Fuel and purchased power expenses increased primarily due to an increase in electricity generated and power purchased coupled with an increase in the market prices of natural gas and purchased power.

Other regulatory credits increased primarily due to a stipulation approved by the City Council in August 2004, as discussed above.

2003 Compared to 2002

Net revenue, which is Entergy New Orleans' 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	$183.7
Base rates	15.9
Rate refund provisions	9.1
Other	(0.4)
2003 net revenue	$208.3

The increase in base rates was effective June 2003. The rate increase is discussed in Note 2 to the domestic utility companies and System Energy financial statements.

Rate refund provisions increased net revenue due to larger accruals for potential rate actions and refunds in 2002.

Gross operating revenues and fuel and purchased power expenses

Gross operating revenues increased primarily due to an increase of $78.4 million in sales to affiliates. The increase was also attributable to a base rate increase and an increase in the market price of natural gas.

Fuel and purchased power expenses increased primarily due to an increase in the market price of natural gas.

Other Income Statement Variances

2004 Compared to 2003

Other operation and maintenance expenses decreased slightly primarily due to the $4.7 million voluntary severance program accruals in 2003. The decrease was offset by increases in customer service support costs and maintenance and outage costs at fossil plants.

The increase in miscellaneous income is primarily due to an asbestos insurance settlement in April 2004.

Interest on long-term debt decreased primarily due to long-term debt refinancing in the third quarter of 2003.

2003 Compared to 2002

Other operation and maintenance expenses increased primarily due to the following:

• voluntary severance program accruals of $4.7 million;
• an increase of $2.7 million in benefit costs;
• an increase of $2.2 million in billing, customer inquiry, and collection costs; and
• an increase of $2.0 million in fossil plant maintenance outage costs.

Depreciation and amortization expenses increased due to an increase in plant in service.

Miscellaneous income decreased primarily due to a gain on the sale of property at a non-operating plant site in 2002.

Other interest decreased primarily due to interest accrued in 2002 for potential rate actions and refunds and a true-up of those accruals in May 2003.

Income Taxes

The effective income tax rates for 2004, 2003, and 2002 were 37.5%, 42.8%, and 64.7%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rate.  Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued on the balance sheet.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2004, 2003, and 2002 were as follows:

		2004	2003	2002
		(In Thousands)
Cash and cash equivalents at beginning of period		$4,669	$66,247	$38,184
Cash flow provided by (used in):
	Operating activities	63,577	7,194	72,143
	Investing activities	(49,280)	(64,806)	(41,647)
	Financing activities	(11,012)	(3,966)	(2,433)
	Net increase (decrease) in cash and cash equivalents	3,285	(61,578)	28,063
Cash and cash equivalents at end of period		$7,954	$4,669	$66,247

Operating Activities

Cash flow from operations increased $56.4 million in 2004 primarily due to increased net income and the timing of collections of receivables.

Cash flow from operations decreased $64.9 million in 2003 primarily due to decreased fuel cost recoveries and the timing of collection of receivables due to an increase in retail customer receivable days outstanding.

Entergy New Orleans' receivables from the money pool were as follows as of December 31 for each of the following years:

2004	2003	2002	2001
(In Thousands)
$1,413	$1,783	$3,500	$9,208

Money pool activity provided $0.4 million of Entergy New Orleans' operating cash flow in 2004, provided $1.7 million in 2003, and provided $5.7 million in 2002. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.

Investing Activities

Net cash used in investing activities decreased $15.5 million in 2004 primarily due to capital expenditures related to a turbine inspection project at a fossil plant in 2003 and decreased customer service spending.

Net cash used in investing activities increased $23.2 million in 2003 compared to 2002 primarily due to the maturity of $14.9 million of other temporary investments in 2002 and increased construction expenditures due to increased customer service spending.

Financing Activities

Net cash used in financing activities increased $7.0 million in 2004 primarily due to the costs and expenses related to refinancing $75 million of long-term debt in 2004 and an increase of $2.2 million in common stock dividends paid.

Net cash used in financing activities increased $1.5 million in 2003 primarily due to additional common stock dividends paid of $2.2 million.

In July 2003, Entergy New Orleans issued $30 million of 3.875% Series First Mortgage Bonds due August 2008 and $70 million of 5.25% Series First Mortgage Bonds due August 2013. The proceeds from these issuances were used to redeem, prior to maturity, $30 million of 7% Series First Mortgage Bonds due July 2008, $40 million of 8% Series bonds due March 2006, and $30 million of 6.65% Series First Mortgage Bonds due March 2004. The issuances and redemptions are not shown on the cash flow statement because the proceeds from the issuances were placed in a trust for use in the redemptions and never held as cash by Entergy New Orleans.

See Note 5 to the domestic utility companies and System Energy financial statements for details on long-term debt.

Uses of Capital

Entergy New Orleans requires capital resources for:

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

Following are the amounts of Entergy New Orleans' planned construction and other capital investments and existing debt obligations:

	2005	2006-2007	2008-2009	After 2009	Total
	(In Millions)
Planned construction and
capital investment (1)	$47	$96	N/A	N/A	$143
Long-term debt	$30	$-	$30	$170	$230
Purchase obligations (2)	$182	$346	$200	$1,215	$1,943

(1)

Consists almost entirely of maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth.

(2)

Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy New Orleans almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the domestic utility companies and System Energy financial statements.

In addition to these contractual obligations, Entergy New Orleans expects to contribute $15.7 million to its pension plans and $4.4 million to other postretirement plans in 2005.

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

As a wholly-owned subsidiary, Entergy New Orleans dividends its earnings to Entergy Corporation at a percentage determined monthly. In addition, all of Entergy New Orleans' retained earnings are currently available for distribution.

Sources of Capital

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

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

Entergy New Orleans issued $75 million of First Mortgage Bonds in 2004 as follows:

Issue Date	Description	Maturity	Amount
			(In Thousands)
August 2004	5.60% Series	September 2024	$35,000
August 2004	5.65% Series	September 2029	40,000
			$75,000

Proceeds from the issuances in August 2004 were used to retire or redeem the following First Mortgage Bonds:

Retirement Date	Description	Maturity	Amount
			(In Thousands)
September 2004	7.55% Series	September 2023	$30,000
September 2004	8.00% Series	March 2023	45,000
			$75,000

In July 2004, Entergy New Orleans entered into a credit facility and Entergy Louisiana renewed its credit facility with the same lender. Both facilities will expire in April 2005. Entergy New Orleans can borrow up to $14 million and Entergy Louisiana can borrow up to $15 million under their respective credit facilities, but at no time can the total amount borrowed by the two companies combined exceed $15 million. As of December 31, 2004, no borrowings were outstanding under the facilities.

Entergy New Orleans may refinance or redeem debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common and preferred stock issuances by Entergy New Orleans require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy New Orleans has sufficient capacity under these tests to meet its foreseeable capital needs.

Short-term borrowings by Entergy New Orleans, including borrowings under the money pool, are limited to an amount authorized by the SEC, $100 million. Under restrictions contained in its articles of incorporation, Entergy New Orleans could incur approximately $40 million of new unsecured debt as of December 31, 2004. Under its SEC Order and without further SEC authorization, Entergy New Orleans cannot incur additional short-term indebtedness unless (a) it and Entergy Corporation maintain a common equity ratio of at least 30% and (b) with the exception of money pool borrowings, the security to be issued (if rated) and all outstanding securities of Entergy New Orleans (other than preferred stock), as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy New Orleans' short-term borrowing limits.

Significant Factors and Known Trends

State and Local Rate Regulatory Risks

The rates that Entergy New Orleans charges for electricity and natural gas significantly influence its financial position, results of operations, and liquidity. Entergy New Orleans is closely regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the City Council, is primarily responsible for approval of the rates charged to customers.

In May 2003, the City Council approved a resolution allowing for a total increase of $30.2 million in electric and gas base rates effective June 1, 2003.  In April 2004, Entergy New Orleans made filings with the City Council as required by the earnings review process prescribed by the Gas and Electric Formula Rate Plans approved by the City Council in 2003. The filings sought an increase in Entergy New Orleans' electric revenues of $1.2 million and an increase in Entergy New Orleans' gas revenues of $32,000. The Council Advisors and intervenors reviewed the filings, and filed their recommendations in July 2004. In August 2004, in accordance with the City Council's requirements for the formula rate plans, Entergy New Orleans made a filing with the City Council reflecting the parties' concurrence that no change in Entergy New Orleans' electric or gas rates is warranted. Later in August 2004, the City Council approved an unopposed settlement among Entergy New Orleans, the Council Advisors, and the intervenors in connection with the Gas and Electric Formula Rate Plans. In accordance with the resolution approving the settlement agreement, Entergy New Orleans' gas and electric base rates remain unchanged from levels set in May 2003. The resolution ordered Entergy New Orleans to defer $3.9 million relating to voluntary severance plan costs allocated to its electric operations and $1.0 million allocated to its gas operations, which amounts were accrued on its books in 2003, and to record on its books regulatory assets in those amounts to be amortized over five years effective January 2004. Entergy New Orleans also was ordered to defer $6.0 million of fossil plant maintenance expense incurred in 2003 and to record on its books a regulatory asset in that amount to be amortized over a five-year period effective January 2003.

Entergy New Orleans will file its formula rate plan for the year ended December 31, 2004 by May 1, 2005 and also intends to file for an extension of the formula rate plan by September 1, 2005. If the formula rate plan is not extended by the City Council, the rate adjustments in effect based on the December 31, 2004 test year shall continue.

In May 2003, the City Council approved implementation of a generation performance-based rate calculation in the electric fuel adjustment clause under which Entergy New Orleans receives 10% of calculated fuel and purchased power cost savings in excess of $20 million, based on a defined benchmark, subject to a 13.25% return on equity limitation for electric operations as provided for in the electric formula rate plan. Entergy New Orleans bears 10% of any "negative" fuel and purchased power cost savings. In October 2004, Entergy New Orleans' annual evaluation report was submitted for the period June 2003 through May 2004. Additional savings associated with the first year generation performance-based rate calculation was $71 million of which Entergy New Orleans' share was $5.1 million.

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

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

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

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

System Agreement Proceedings

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

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

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

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

	Range of Annual Payments or (Receipts)	Average Annual Payments or (Receipts) for 2005-2009 Period
	(In Millions)	(In Millions)
Entergy Arkansas	$154 to $281	$215
Entergy Gulf States	($130) to ($15)	($63)
Entergy Louisiana	($199) to ($98)	($141)
Entergy Mississippi	($16) to $8	$1
Entergy New Orleans	($17) to ($5)	($12)

Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers. Although the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy New Orleans does not believe that the ultimate resolution of these proceedings will have a material effect on its financial condition or results of operation.

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

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

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

Transmission

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

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

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

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

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

Available Flowgate Capacity Proceeding

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

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

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

Market and Credit Risks

Entergy New Orleans has certain market and credit risks inherent in its business. Market risks represent the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement.

Environmental Risks

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

Litigation Risks

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

Critical Accounting Estimates

The preparation of Entergy New Orleans' financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements could produce estimates that would have a material impact on the presentation of Entergy New Orleans' financial position or results of operations.

Unbilled Revenue

As discussed in Note 1 to the domestic utility companies and System Energy financial statements, Entergy New Orleans records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month, including fuel price. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period and fuel price fluctuations, in addition to changes in certain components of the calculation including changes to estimates such as line loss, which affects the estimate o f unbilled customer usage, and assumptions regarding price such as the fuel cost recovery mechanism.

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 10 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.

Assumptions

Key actuarial assumptions utilized in determining these costs include:

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

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

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

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

Cost Sensitivity

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

Actuarial Assumption	Change in Assumption	Impact on 2004 Pension Cost	Impact on Projected Benefit Obligation
	Increase/(Decrease)
Discount rate	(0.25%)	$227	$2,694
Rate of return on plan assets	(0.25%)	$73	-
Rate of increase in compensation	0.25%	$113	$718

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

Actuarial Assumption	Change in Assumption	Impact on 2004 Postretirement Benefit Cost	Impact on Accumulated Postretirement Benefit Obligation
	Increase/(Decrease)
Health care cost trend	0.25%	$157	$973
Discount rate	(0.25%)	$50	$1,279

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

Accounting Mechanisms

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

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

Costs and Funding

Total pension cost for Entergy New Orleans in 2004 was $4.6 million. Entergy New Orleans anticipates 2005 pension cost to decrease to $4.2 million. Entergy New Orleans contributed $2.1 million to its pension plan in 2004, and anticipates making $15.7 million in contributions in 2005. The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, partially offset by the Pension Funding Equity Act relief passed in April 2004.

Entergy New Orleans' accumulated benefit obligation at December 31, 2004, 2003 and 2002 exceeded plan assets. As a result, Entergy New Orleans was required to recognize an additional minimum liability as prescribed by SFAS 87. At December 31, 2004 Entergy New Orleans increased its additional minimum liability to $16.9 million from $13.1 million at December 31, 2003. Entergy New Orleans decreased its intangible asset for the unrecognized prior service cost to $1.7 million at December 31, 2004 from $2.8 million at December 31, 2003. Entergy New Orleans increased the regulatory asset to $15.2 million at December 31, 2004 from $10.3 million at December 31, 2003. Net income for 2004, 2003, and 2002 were not impacted.

Total postretirement health care and life insurance benefit costs for Entergy New Orleans in 2004 were $4.3 million, including $1.3 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy New Orleans expects 2005 postretirement health care and life insurance benefit costs to approximate $4.2 million, including $1.4 million in savings due to the estimated effect of future Medicare Part D subsidies.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Entergy New Orleans, Inc.:

We have audited the accompanying balance sheets of Entergy New Orleans, Inc. as of December 31, 2004 and 2003, and the related statements of operations, retained earnings, and cash flows (pages 261 through 266 and applicable items in pages 284 through 348) for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy New Orleans, Inc. as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.

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

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 8, 2005

ENTERGY NEW ORLEANS, INC.
STATEMENTS OF OPERATIONS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
OPERATING REVENUES
Domestic electric	$588,457	$527,660	$424,527
Natural gas	147,411	126,356	83,347
TOTAL	735,868	654,016	507,874
OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and
gas purchased for resale	245,301	214,735	163,323
Purchased power	256,190	231,787	158,191
Other operation and maintenance	107,874	108,217	98,511
Taxes other than income taxes	43,577	42,198	40,099
Depreciation and amortization	29,657	30,004	27,699
Other regulatory charges (credits) - net	(4,670)	(843)	2,701
TOTAL	677,929	626,098	490,524
OPERATING INCOME	57,939	27,918	17,350
OTHER INCOME
Allowance for equity funds used during construction	1,378	2,085	1,835
Interest and dividend income	720	825	689
Miscellaneous - net	270	(1,453)	584
TOTAL	2,368	1,457	3,108
INTEREST AND OTHER CHARGES
Interest on long-term debt	15,357	17,436	18,011
Other interest - net	1,253	350	4,939
Allowance for borrowed funds used during construction	(1,243)	(2,145)	(1,840)
TOTAL	15,367	15,641	21,110
INCOME (LOSS) BEFORE INCOME TAXES	44,940	13,734	(652)
Income taxes	16,868	5,875	(422)
NET INCOME (LOSS)	28,072	7,859	(230)
Preferred dividend requirements and other	965	965	965
EARNINGS (LOSS) APPLICABLE TO
COMMON STOCK	$27,107	$6,894	($1,195)
See Notes to Respective Financial Statements.

ENTERGY NEW ORLEANS, INC.
STATEMENTS OF CASH FLOWS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
OPERATING ACTIVITIES
Net income (loss)	$28,072	$7,859	($230)
Adjustments to reconcile net income to net cash flow provided by operating activities:
Other regulatory charges (credits) - net	(4,670)	(843)	2,701
Depreciation and amortization	29,657	30,004	27,699
Deferred income taxes and investment tax credits	39,782	15,401	6,729
Changes in working capital:
Receivables	9,162	(41,308)	10,540
Fuel inventory	1,399	(2,296)	(203)
Accounts payable	(3,014)	17,817	18,070
Taxes accrued	(13,056)	1,372	5,603
Interest accrued	(1,455)	(276)	(544)
Deferred fuel costs	(5,279)	(12,162)	4,686
Other working capital accounts	2,121	(7,553)	(4,971)
Provision for estimated losses and reserves	(1,305)	(1,634)	(3,348)
Changes in other regulatory assets	(5,380)	(9,473)	(3,061)
Other	(12,457)	10,286	8,472
Net cash flow provided by operating activities	63,577	7,194	72,143
INVESTING ACTIVITIES
Construction expenditures	(51,264)	(66,285)	(58,341)
Allowance for equity funds used during construction	1,378	2,085	1,835
Changes in other temporary investments - net	606	(606)	14,859
Net cash flow used in investing activities	(49,280)	(64,806)	(41,647)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	72,640	- -	24,332
Retirement of long-term debt	(77,487)	- -	(25,000)
Dividends paid:
Common stock	(5,200)	(3,001)	(800)
Preferred stock	(965)	(965)	(965)
Net cash flow used in financing activities	(11,012)	(3,966)	(2,433)
Net increase (decrease) in cash and cash equivalents	3,285	(61,578)	28,063
Cash and cash equivalents at beginning of period	4,669	66,247	38,184
Cash and cash equivalents at end of period	$7,954	$4,669	$66,247
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid/(received) during the period for:
Interest - net of amount capitalized	$16,172	$17,427	$19,961
Income taxes	($5,736)	($13,530)	($37,929)
See Notes to Respective Financial Statements.

ENTERGY NEW ORLEANS, INC.
BALANCE SHEETS
ASSETS
	December 31,
	2004	2003
	(In Thousands)
CURRENT ASSETS
Cash and cash equivalents:
Cash	$2,998	$28
Temporary cash investments - at cost,
which approximates market	4,956	4,641
Total cash and cash equivalents	7,954	4,669
Other temporary investments	- -	606
Accounts receivable:
Customer	47,356	44,663
Allowance for doubtful accounts	(3,492)	(3,104)
Associated companies	12,223	24,697
Other	7,329	10,057
Accrued unbilled revenues	24,848	21,113
Total accounts receivable	88,264	97,426
Deferred fuel	2,559	- -
Accumulated deferred income taxes	- -	460
Fuel inventory - at average cost	4,181	5,580
Materials and supplies - at average cost	9,150	8,660
Prepayments and other	3,467	8,050
TOTAL	115,575	125,451
OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity	3,259	3,259
UTILITY PLANT
Electric	699,072	666,122
Natural gas	183,728	167,011
Construction work in progress	33,273	45,061
TOTAL UTILITY PLANT	916,073	878,194
Less - accumulated depreciation and amortization	435,519	420,745
UTILITY PLANT - NET	480,554	457,449
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Other regulatory assets	40,354	27,222
Long term receivables	2,492	-
Other	20,540	16,246
TOTAL	63,386	43,468
TOTAL ASSETS	$662,774	$629,627
See Notes to Respective Financial Statements.
ENTERGY NEW ORLEANS, INC.
BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
	December 31,
	2004	2003
	(In Thousands)
CURRENT LIABILITIES
Currently maturing long-term debt	$30,000	$ -
Accounts payable:
Associated companies	30,563	35,008
Other	44,149	42,718
Customer deposits	17,187	15,575
Taxes accrued	2,592	- -
Accumulated deferred income taxes	1,906	- -
Interest accrued	4,757	6,212
Deferred fuel costs	- -	2,720
Energy Efficiency Program provision	6,611	6,356
Other	3,477	2,088
TOTAL	141,242	110,677
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	47,062	39,486
Accumulated deferred investment tax credits	3,997	4,441
SFAS 109 regulatory liability - net	46,406	40,543
Other regulatory liabilities	- -	954
Accumulated provisions	9,323	10,628
Pension liability	36,845	30,585
Long-term debt	199,902	229,217
Other	3,755	10,761
TOTAL	347,290	366,615
Commitments and Contingencies
SHAREHOLDERS' EQUITY
Preferred stock without sinking fund	19,780	19,780
Common stock, $4 par value, authorized 10,000,000
shares; issued and outstanding 8,435,900 shares in 2004
and 2003	33,744	33,744
Paid-in capital	36,294	36,294
Retained earnings	84,424	62,517
TOTAL	174,242	152,335
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$662,774	$629,627
See Notes to Respective Financial Statements.

ENTERGY NEW ORLEANS, INC.
STATEMENTS OF RETAINED EARNINGS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
Retained Earnings, January 1	$62,517	$58,624	$60,619
Add:
Net income (loss)	28,072	7,859	(230)
Deduct:
Dividends declared:
Preferred stock	965	965	965
Common stock	5,200	3,001	800
Total	6,165	3,966	1,765
Retained Earnings, December 31	$84,424	$62,517	$58,624
See Notes to Respective Financial Statements.

ENTERGY NEW ORLEANS, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
	2004	2003	2002	2001	2000
	(In Thousands)
Operating revenues	$735,868	$654,016	$507,874	$630,850	$640,290
Net Income (loss)	$28,072	$7,859	($230)	($2,195)	$16,518
Total assets	$662,774	$629,627	$584,705	$566,037	$559,231
Long-term obligations (1)	$199,902	$229,217	$229,191	$299,097	$199,031
(1) Includes long-term debt (excluding currently maturing debt).
	2004	2003	2002	2001	2000
	(Dollars In Millions)
Electric Operating Revenues:
Residential	$184	$178	$170	$190	$188
Commercial	171	162	154	186	171
Industrial	34	27	25	32	25
Governmental	70	68	66	81	73
Total retail	459	435	415	489	457
Sales for resale:
Associated companies	118	85	7	10	32
Non-associated companies	2	2	2	3	9
Other	9	6	1	1	17
Total	$588	$528	$425	$503	$515
Billed Electric Energy Sales (GWh):
Residential	2,139	2,133	2,158	1,981	2,178
Commercial	2,316	2,262	2,255	2,185	2,260
Industrial	575	413	409	414	384
Governmental	1,025	1,036	1,053	1,017	1,058
Total retail	6,055	5,844	5,875	5,597	5,880
Sales for resale:
Associated companies	1,514	1,312	144	115	570
Non-associated companies	25	28	32	59	141
Total	7,594	7,184	6,051	5,771	6,591

SYSTEM ENERGY RESOURCES, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

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

Results of Operations

Net Income

2004 Compared to 2003

Net income remained relatively unchanged, decreasing $0.06 million in 2004.

2003 Compared to 2002

Net income increased $2.7 million in 2003 primarily due to lower interest charges primarily resulting from lower interest expense associated with the Grand Gulf sale-leaseback. This increase was partially offset by a decrease in rate base in 2003 resulting in lower operating income. The decrease in rate base was due to the normal depreciation of Grand Gulf.

Income Taxes

The effective income tax rates for 2004, 2003, and 2002 were 42.4%, 41.7%, and 42.4%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate.  Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued on the balance sheet.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2004, 2003, and 2002 were as follows:

		2004	2003	2002
		(In Thousands)
Cash and cash equivalents at beginning of period		$52,536	$113,159	$49,579
Cash flow provided by (used in):
	Operating activities	332,928	100,817	225,639
	Investing activities	(45,053)	(45,065)	(28,873)
	Financing activities	(124,056)	(116,375)	(133,186)
	Net increase (decrease) in cash and cash equivalents	163,819	(60,623)	63,580
Cash and cash equivalents at end of period		$216,355	$52,536	$113,159

Operating Activities

Cash flow from operations increased by $232.1 million in 2004 primarily due to income tax refunds of $70.6 million in 2004 compared to income tax payments of $230.9 million in 2003. The increase was partially offset by money pool activity, as discussed below.

In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $430 million deduction for System Energy on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. In 2004 System Energy realized $144 million in cash tax benefit from the method change. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit.

Cash flow from operations decreased by $124.8 million in 2003 primarily due to the following:

• an increase in federal income taxes paid of $74.0 million in 2003 compared to 2002;
• the cessation of the Entergy Mississippi GGART. System Energy collected $21.7 million in 2003 and $40.8 million in 2002 from Entergy Mississippi in conjunction with the GGART, which provided for the acceleration of Entergy Mississippi's Grand Gulf purchased power obligation. The MPSC authorized cessation of the GGART effective July 1, 2003. See Note 2 to the domestic utility companies and System Energy financial statements for further discussion of the GGART; and
• money pool activity, as discussed below.

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

2004	2003	2002	2001
(In Thousands)
$61,592	$19,064	$7,046	$13,853

Money pool activity used $42.5 million of System Energy's operating cash flows in 2004, used $12.0 million in 2003, and provided $6.8 million in 2002. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.

Investing Activities

Net cash used for investing activities was practically unchanged in 2004 compared to 2003 primarily because an increase in construction expenditures caused by a reclassification of inventory items to capital was significantly offset by the maturity of $6.5 million of other temporary investments that had been made in 2003, which provided cash in 2004.

The increase of $16.2 million in net cash used in investing activities in 2003 was primarily due to the following:

• the maturity in 2002 of $22.4 million of other temporary investments that had been made in 2001, which provided cash in 2002;
• an increase in decommissioning trust contributions and realized change in trust assets of $8.2 million in 2003 compared to 2002; and
• other temporary investments of $6.5 million made in 2003.

Partially offsetting the increases in net cash used in investing activities was a decrease in construction expenditures of $22.1 million in 2003 compared to 2002 primarily due to the power uprate project in 2002.

Financing Activities

The increase of $7.7 million in net cash used in financing activities in 2004 was primarily due to $5.5 million in costs related to System Energy refunding bonds associated with its Grand Gulf Lease Obligation in May 2004 and the retirement of $ 7.6 million of long-term debt 2004. The increase was partially offset by a decrease of $5.0 million in the January 2004 principal payment made on the Grand Gulf sale-leaseback compared to the January 2003 principal payment .

The decrease of $16.8 million in net cash used in financing activities in 2003 was primarily due to a decrease of $19.5 million in the January 2003 principal payment made on the Grand Gulf sale-leaseback compared to the January 2002 principal payment.

See Note 5 to the domestic utility companies and System Energy financial statements for details of long-term debt.

Uses of Capital

System Energy requires capital resources for:

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

Following are the amounts of System Energy's planned construction and other capital investments, existing debt and lease obligations, and other purchase obligations:

	2005	2006-2007	2008-2009	After 2009	Total
	(In Millions)
Planned construction and
capital investment	$38	$81	N/A	N/A	$119
Long-term debt	$29	$125	$62	$659	$875
Nuclear fuel lease obligations (1)	$28	$38	N/A	N/A	$66

(1) It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. If such additional financing cannot be arranged, however, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations.

System Energy expects to contribute $9.3 million to pension plans and $1.7 million to other postretirement plans in 2005.

The planned capital investment estimate for System Energy reflects capital required to support the existing business of System Energy. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the domestic utility companies and System Energy financial statements.

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

Sources of Capital

System Energy's sources to meet its capital requirements include:

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

System Energy had three-year letters of credit in place that were scheduled to expire in March 2003 securing certain of its obligations related to the sale-leaseback of a portion of Grand Gulf. System Energy replaced the letters of credit before their expiration with new three-year letters of credit totaling approximately $198 million that were backed by cash collateral. In December 2003, System Energy replaced the cash-backed letters of credit with syndicated bank letters of credit. In December 2004 System Energy amended these letters of credit and they now expire in May 2009.

System Energy may refinance or redeem debt prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common stock issuances by System Energy require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in bond indentures and other agreements. System Energy has sufficient capacity under these tests to meet its foreseeable capital needs.

Borrowings and securities issuances by System Energy are limited to amounts authorized by the SEC. The current short-term borrowing limitation, including borrowings under the money pool, is $140 million. Under its SEC Orders and without further SEC authorization, System Energy cannot incur additional short-term indebtedness unless (a) it and Entergy Corporation maintain a common equity ratio of at least 30% and (b) with the exception of money pool borrowings, the security to be issued (if rated) and all outstanding securities of System Energy, as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of System Energy's short-term borrowing limits.

Significant Factors and Known Trends

Market Risks

Interest Rate and Equity Price Risk - Decommissioning Trust Funds

System Energy's nuclear decommissioning trust funds expose it to fluctuations in equity prices and interest rates. The NRC requires System Energy to maintain trusts to fund the costs of decommissioning Grand Gulf. The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that its exposure to market fluctuations will not affect results of operations for the Grand Gulf trust funds because of the application of regulatory accounting principles. The decommissioning trust funds are discussed more thoroughly in Notes 1, 8, and 12 to the domestic utility companies and System Energy financial statements.

Nuclear Matters

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

Litigation Risks

The states in which System Energy's customers operate have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. System Energy uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment poses a significant business risk.

Environmental Risks

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

Critical Accounting Estimates

The preparation of System Energy's financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements could produce estimates that would have a material impact on the presentation of System Energy's financial position or results of operations.

Nuclear Decommissioning Costs

Regulations require that Grand Gulf be decommissioned after the facility is taken out of service, and funds are collected and deposited in trust funds during the facility's operating life in order to provide for this obligation. System Energy conducts periodic decommissioning cost studies (typically updated every three to five years) to estimate the costs that will be incurred to decommission the facility. See Note 8 to the domestic utility companies and System Energy financial statements for details regarding System Energy's most recent study and the obligations recorded by System Energy related to decommissioning. The following key assumptions have a significant effect on these estimates:

• Cost Escalation Factors - System Energy's decommissioning studies include an assumption that decommissioning costs will escalate over present cost levels by an annual factor averaging approximately 5.5%. A 50 basis point change in this assumption could change the ultimate cost of decommissioning a facility by as much as 11%.
• Timing - The date of the plant's retirement must be estimated and an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in "safestore" status for later decommissioning, as permitted by applicable regulations. System Energy's decommissioning studies for Grand Gulf assume immediate decommissioning upon expiration of the original plant license. While the impact of these assumptions cannot be determined with precision, assuming either license extension or use of a "safestore" status can possibly decrease the present value of these obligations.
• Spent Fuel Disposal - Federal regulations require the DOE to provide a permanent repository for the storage of spent nuclear fuel, and legislation has been passed by Congress to develop this repository at Yucca Mountain, Nevada. However, until this site is available, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities can have a significant impact (as much as 16% of estimated decommissioning costs). System Energy's decommissioning studies include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors.
• Technology and Regulation - To date, there is limited practical experience in the United States with actual decommissioning of large nuclear facilities. As experience is gained and technology changes, cost estimates could also change. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant impact on cost estimates. The impact of these potential changes is not presently determinable. System Energy's decommissioning cost studies assume current technologies and regulations.

System Energy collects the costs of decommissioning Grand Gulf through rates charged to its customers. The amounts collected through rates, which are based upon decommissioning cost studies, are deposited in decommissioning trust funds. These collections plus earnings on the trust fund investments are estimated to be sufficient to fund the future decommissioning costs.

The obligation recorded by System Energy for decommissioning costs is reported in the line item entitled "Decommissioning." Prior to the implementation of SFAS 143, the amount recorded for this obligation was comprised of collections from customers and earnings on the trust funds.

SFAS 143

System Energy implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs are System Energy's only asset retirement obligations, and the measurement and recording of System Energy's decommissioning obligations outlined above 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 of System Energy to increase significantly, as System Energy had previously only recorded this obligation as the related costs were collected from customers, and as earnings were recorded on the related trust funds.
• Fair value approach - SFAS 143 requires that these obligations be measured using a fair value approach. Among other things, this entails the assumption that the costs will be incurred by a third party and will therefore include appropriate profit margins and risk premiums. System Energy's decommissioning studies to date have been based on System Energy performing the work, and have not included any such margins or premiums. Inclusion of these items increases cost estimates.
• Discount rate - SFAS 143 requires that these obligations be discounted using a credit-adjusted risk-free rate.

The net effect of implementing this standard for System Energy was recorded as a regulatory asset, with no resulting impact on System Energy's net income. System Energy recorded this regulatory asset because its existing rate mechanism is based on a cost standard that allows System Energy to recover all ultimate costs of decommissioning from its customers. Upon implementation, assets and liabilities increased by $138 million in 2003 as a result of recording the asset retirement obligation at its fair value of $292 million as determined under SFAS 143, reversing the previously recorded decommissioning liability of $154 million, increasing utility plant by $82 million, increasing accumulated depreciation by $36 million, and recording the related regulatory asset of $92 million.

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 10 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.

Assumptions

Key actuarial assumptions utilized in determining these costs include:

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

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

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

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

Cost Sensitivity

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

Actuarial Assumption	Change in Assumption	Impact on 2004 Pension Cost	Impact on Projected Benefit Obligation
	Increase/(Decrease)
Discount rate	(0.25%)	$433	$4,249
Rate of return on plan assets	(0.25%)	$130	-
Rate of increase in compensation	0.25%	$204	$1,421

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

Actuarial Assumption	Change in Assumption	Impact on 2004 Postretirement Benefit Cost	Impact on Accumulated Postretirement Benefit Obligation
	Increase/(Decrease)
Health care cost trend	0.25%	$154	$756
Discount rate	(0.25%)	$111	$866

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

Accounting Mechanisms

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

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

Costs and Funding

Total pension cost for System Energy in 2004 was $4.6 million. System Energy anticipates 2005 pension cost to increase to $4.8 million due to decrease in the discount rate (from 6.25% to 6.00%) and the expected rate of return (from 8.75% to 8.5%) used to calculate benefit obligations. System Energy contributed $3.7 million to its pension plan in 2004, and anticipates making $9.2 million in contributions in 2005. The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, offset by the Pension Funding Equity Act relief passed in April 2004.

System Energy's accumulated benefit obligation at December 31, 2004, 2003, and 2002 exceeded plan assets. As a result, System Energy was required to recognize an additional minimum liability as prescribed by SFAS 87. At December 31, 2004 System Energy increased its additional minimum liability to $7.7 million from $7.4 million at December 31, 2003. System Energy decreased its intangible asset to $0.2 million at December 31, 2004 from $0.4 million at December 31, 2003. System Energy increased its regulatory asset to $15.2 million at December 31, 2004, from $7.0 million at December 31, 2003. Net income for 2004, 2003, and 2002 was not impacted.

Total postretirement health care and life insurance benefit costs for System Energy in 2004 were $1.5 million, including $0.8 million in savings due to the estimated effect of future Medicare Part D subsidies. System Energy expects 2005 postretirement health care and life insurance benefit costs to approximate $1.7 million, including $1 million in savings due to the estimated effect of future Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the decrease in the discount rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate used to calculate benefit obligations.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying balance sheets of System Energy Resources, Inc. as of December 31, 2004 and 2003, and the related statements of income, retained earnings, and cash flows (pages 277 through 282 and applicable items in pages 284 through 348) for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material respects, the financial position of System Energy Resources, Inc. as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 8 to the notes to respective financial statements, in 2003 System Energy Resources, Inc. adopted the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

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

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 8, 2005

SYSTEM ENERGY RESOURCES, INC.
INCOME STATEMENTS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
OPERATING REVENUES
Domestic electric	$545,381	$583,820	$602,486
OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and
gas purchased for resale	38,337	43,132	36,456
Nuclear refueling outage expenses	12,655	12,695	10,723
Other operation and maintenance	96,809	105,333	98,264
Decommissioning	23,434	21,799	16,055
Taxes other than income taxes	24,364	25,521	25,992
Depreciation and amortization	127,081	109,528	112,093
Other regulatory charges (credits) - net	(10,433)	27,400	53,769
TOTAL	312,247	345,408	353,352
OPERATING INCOME	233,134	238,412	249,134
OTHER INCOME
Allowance for equity funds used during construction	1,544	1,140	2,449
Interest and dividend income	6,870	7,556	2,857
Miscellaneous - net	841	(1,194)	826
TOTAL	9,255	7,502	6,132
INTEREST AND OTHER CHARGES
Interest on long-term debt	58,561	62,802	73,891
Other interest - net	367	1,818	2,748
Allowance for borrowed funds used during construction	(500)	(554)	(902)
TOTAL	58,428	64,066	75,737
INCOME BEFORE INCOME TAXES	183,961	181,848	179,529
Income taxes	78,013	75,845	76,177
NET INCOME	$105,948	$106,003	$103,352
See Notes to Respective Financial Statements.

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SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF CASH FLOWS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
OPERATING ACTIVITIES
Net income	$105,948	$106,003	$103,352
Adjustments to reconcile net income to net cash flow provided by operating activities:
Other regulatory charges (credits) - net	(10,433)	27,400	53,769
Depreciation, amortization, and decommissioning	150,515	131,327	128,148
Deferred income taxes and investment tax credits	(178,535)	(35,207)	(38,246)
Changes in working capital:
Receivables	(41,067)	(8,025)	5,719
Accounts payable	(5,324)	(1,232)	14,767
Taxes accrued	328,617	(123,317)	(43,112)
Interest accrued	13,375	(12,904)	(4,568)
Other working capital accounts	2,763	1,463	(6,108)
Provision for estimated losses and reserves	(1,404)	2,914	163
Changes in other regulatory assets	31,453	26,307	52,448
Other	(62,980)	(13,912)	(40,693)
Net cash flow provided by operating activities	332,928	100,817	225,639
INVESTING ACTIVITIES
Construction expenditures	(32,303)	(18,195)	(40,306)
Allowance for equity funds used during construction	1,544	1,140	2,449
Nuclear fuel purchases	(45,497)	-	(43,140)
Proceeds from sale/leaseback of nuclear fuel	45,677	-	43,140
Decommissioning trust contributions and realized
change in trust assets	(20,956)	(21,528)	(13,370)
Changes in other temporary investments - net	6,482	(6,482)	22,354
Net cash flow used in investing activities	(45,053)	(45,065)	(28,873)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	-	-	69,505
Retirement of long-term debt	(13,973)	(11,375)	(100,891)
Other financing activities	(5,483)	-	-
Dividends paid:
Common stock	(104,600)	(105,000)	(101,800)
Net cash flow used in financing activities	(124,056)	(116,375)	(133,186)
Net increase (decrease) in cash and cash equivalents	163,819	(60,623)	63,580
Cash and cash equivalents at beginning of period	52,536	113,159	49,579
Cash and cash equivalents at end of period	$216,355	$52,536	$113,159
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid/(received) during the period for:
Interest - net of amount capitalized	$40,000	$73,636	$77,190
Income taxes	($70,595)	$230,919	$156,957
See Notes to Respective Financial Statements.

SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
ASSETS
	December 31,
	2004	2003
	(In Thousands)
CURRENT ASSETS
Cash and cash equivalents:
Cash	$399	$2,918
Temporary cash investments - at cost,
which approximates market	215,956	49,618
Total cash and cash equivalents	216,355	52,536
Other temporary investments	-	6,482
Accounts receivable:
Associated companies	111,588	72,477
Other	3,733	1,777
Total accounts receivable	115,321	74,254
Materials and supplies - at average cost	53,427	63,047
Deferred nuclear refueling outage costs	9,510	2,979
Prepayments and other	1,007	1,031
TOTAL	395,620	200,329
OTHER PROPERTY AND INVESTMENTS
Decommissioning trust funds	205,083	172,916
UTILITY PLANT
Electric	3,232,314	3,205,895
Property under capital lease	469,993	466,521
Construction work in progress	28,743	31,344
Nuclear fuel under capital lease	65,572	47,242
TOTAL UTILITY PLANT	3,796,622	3,751,002
Less - accumulated depreciation and amortization	1,780,450	1,672,658
UTILITY PLANT - NET	2,016,172	2,078,344
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
SFAS 109 regulatory asset - net	96,047	115,633
Other regulatory assets	296,305	301,233
Other	19,578	12,269
TOTAL	411,930	429,135
TOTAL ASSETS	$3,028,805	$2,880,724
See Notes to Respective Financial Statements.
SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
LIABILITIES AND SHAREHOLDER'S EQUITY
	December 31,
	2004	2003
	(In Thousands)
CURRENT LIABILITIES
Currently maturing long-term debt	$25,266	$6,348
Accounts payable:
Associated companies	3,880	-
Other	21,051	30,255
Taxes accrued	46,468	55,585
Accumulated deferred income taxes	3,477	942
Interest accrued	42,998	29,623
Obligations under capital leases	27,716	31,266
Other	1,621	1,971
TOTAL	172,477	155,990
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	421,466	290,964
Accumulated deferred investment tax credits	75,612	79,088
Obligations under capital leases	37,855	15,976
Other regulatory liabilities	210,863	213,093
Decommissioning	335,893	312,459
Accumulated provisions	2,378	3,782
Long-term debt	849,593	882,401
Other	28,084	33,735
TOTAL	1,961,744	1,831,498
Commitments and Contingencies
SHAREHOLDER'S EQUITY
Common stock, no par value, authorized 1,000,000 shares;
issued and outstanding 789,350 shares in 2004 and 2003	789,350	789,350
Retained earnings	105,234	103,886
TOTAL	894,584	893,236
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$3,028,805	$2,880,724
See Notes to Respective Financial Statements.

SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF RETAINED EARNINGS
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
Retained Earnings, January 1	$103,886	$102,883	$101,331
Add:
Net income	105,948	106,003	103,352
Deduct:
Dividends declared	104,600	105,000	101,800
Retained Earnings, December 31	$105,234	$103,886	$102,883
See Notes to Respective Financial Statements.

SYSTEM ENERGY RESOURCES, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON
	2004	2003	2002	2001	2000
	(Dollars In Thousands)
Operating revenues	$545,381	$583,820	$602,486	$535,027	$620,032
Net Income	$105,948	$106,003	$103,352	$116,355	$82,372
Total assets	$3,028,805	$2,880,724	$2,915,898	$2,964,041	$3,369,048
Long-term obligations (1)	$887,448	$898,377	$942,701	$865,439	$1,122,178
Electric energy sales (GWh)	9,212	9,812	9,053	8,921	7,567
(1) Included long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations.

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

NOTES TO RESPECTIVE FINANCIAL STATEMENTS

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

The accompanying separate financial statements of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (the "domestic utility companies") and System Energy are included in this document and result from these companies having registered securities with the SEC. These companies maintain accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications, with no effect on net income or shareholders' equity.

Use of Estimates in the Preparation of Financial Statements

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

Revenues and Fuel Costs

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

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

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

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

Property, Plant, and Equipment

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

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

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

2004	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Millions)
Production
Nuclear	$951	$1,627	$1,543	$-	$-	$1,866
Other	269	529	197	221	12	-
Transmission	646	708	385	406	29	8
Distribution	1,283	1,339	1,000	713	337	-
Other	216	247	269	175	70	16
Construction work in progress	226	332	189	90	33	29
Nuclear fuel (leased and owned)	106	71	32	-	-	66
Asset retirement obligation	24	-	42	-	-	31
Property, plant, and equipment - net	$3,721	$4,853	$3,657	$1,605	$481	$2,016

2003	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Millions)
Production
Nuclear	$940	$1,638	$1,593	$-	$-	$1,941
Other	326	583	205	228	17	-
Transmission	636	647	369	380	26	9
Distribution	1,184	1,197	923	632	294	-
Other	214	238	266	166	75	17
Construction work in progress	239	326	172	109	45	31
Nuclear fuel (leased and owned)	110	64	65	-	-	47
Asset retirement obligation	45	32	45	-	-	33
Property, plant, and equipment - net	$3,694	$4,725	$3,638	$1,515	$457	$2,078

Depreciation is computed on the straight-line basis at rates based on the estimated service lives of the various classes of property. Depreciation rates on average depreciable property are shown below:

	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
2004	3.2%	2.1%	2.9%	2.5%	2.8%	2.9%
2003	3.2%	2.2%	3.0%	2.5%	3.1%	2.8%
2002	3.2%	2.4%	3.0%	2.5%	3.1%	2.8%

Non-utility property - at cost (less accumulated depreciation) for Entergy Gulf States is reported net of accumulated depreciation of $125.1 million and $122.7 million as of December 31, 2004 and 2003, respectively.

Jointly-Owned Generating Stations

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

Generating Stations		Fuel-Type	Total Megawatt Capability (1)	Ownership	Investment	Accumulated Depreciation
					(In Millions)
Entergy Arkansas -
Independence	Unit 1	Coal	815	31.50%	$117	$73
	Common Facilities	Coal		15.75%	$31	$18
White Bluff	Units 1 and 2	Coal	1,635	57.00%	$428	$264
Entergy Gulf States -
Roy S. Nelson	Unit 6	Coal	550	60.90%	$403	$241
Big Cajun 2	Unit 3	Coal	575	42.00%	$233	$128
Entergy Mississippi -
Independence	Units 1 and 2 and Common Facilities	Coal	1,630	25.00%	$232	$116
System Energy -
Grand Gulf	Unit 1	Nuclear	1,270	90.00%(2)	$3,702	$1,780

(1)	"Total Megawatt Capability" is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
(2)	Includes an 11.5% leasehold interest held by System Energy. System Energy's Grand Gulf lease obligations are discussed in Note 9 to the domestic utility companies and System Energy financial statements.

Nuclear Refueling Outage Costs

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

Allowance for Funds Used During Construction (AFUDC)

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

Income Taxes

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

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

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

Application of SFAS 71

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

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

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

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

Cash and Cash Equivalents

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

Investments

Entergy applies the provisions of SFAS 115, "Accounting for Investments for Certain Debt and Equity Securities," in accounting for investments in decommissioning trust funds. As a result, Entergy records the decommissioning trust funds at their fair value on the consolidated balance sheet. Because of the ability of the domestic utility companies and System Energy to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, Entergy Arkansas, Entergy Gulf States (for the regulated portion of River Bend), Entergy Louisiana, and System Energy have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets. For the nonregulated portion of River Bend, Entergy Gulf States has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. See Note 12 to the domestic utility companies and System Energy financial statements for details on the de commissioning trust funds.

Derivatives and Hedging

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

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

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

Fair Values

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

The domestic utility companies and System Energy consider the carrying amounts of most of their financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. Additional information regarding financial instruments and their fair values is included in Notes 5 and 6 to the domestic utility companies and System Energy financial statements.

Impairment of Long-Lived Assets

The domestic utility companies and System Energy periodically review their long-lived assets whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the net cash flows expected to result from such operations and assets. Projected net cash flows depend on the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy over the remaining life of the assets.

River Bend AFUDC

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

Transition to Competition Liabilities

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

Reacquired Debt

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

Entergy Gulf States' Deregulated Operations

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

The results of these deregulated operations before interest charges for the years ended December 31, 2004, 2003, and 2002 are as follows:

	2004	2003	2002
	(In Thousands)
Operating revenues	$280,279	$273,150	$209,752
Operating expenses
Fuel, operation, and maintenance	197,275	177,385	158,927
Depreciation and accretion	30,653	47,566	40,092
Total operating expense	227,928	224,951	199,019
Operating income	52,351	48,199	10,733
Income tax expense	20,414	17,722	4,503
Net income from deregulated utility operations	$31,937	$30,477	$6,230

The net investment associated with these deregulated operations as of December 31, 2004 and 2003 was approximately $830 and $838 million, respectively.

New Accounting Pronouncements

During 2004, Entergy adopted the provisions of FSP 106-2, "Accounting and Disclosure Requirements Related to Medicare Prescription Drug, Improvement and Modernization Act of 2003," which is discussed further in Note 10 to the domestic utility companies and System Energy financial statements.

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

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

During 2003, Entergy also adopted the provisions of the following accounting standards: SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" and related interpretations by the Derivatives Implementation Group, and FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees Including Indirect Guarantees of Indebtedness of Others". The adoption of these standards did not have a material effect on Entergy's financial statements.

NOTE 2. RATE AND REGULATORY MATTERS

Electric Industry Restructuring and the Continued Application of SFAS 71

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

Arkansas

(Entergy Arkansas)

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

Texas

(Entergy Gulf States)

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

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

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

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

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

Louisiana

(Entergy Gulf States and Entergy Louisiana)

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

Mississippi

(Entergy Mississippi)

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

New Orleans

(Entergy New Orleans)

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

Regulatory Assets

Other Regulatory Assets

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

2004	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 8)	$141.2	$-	$141.6	$-	$-	$97.3
Deferred distribution expenses - recovered through May 2008	- -	- -	- -	- -	4.9	- -
Deferred fossil plant maintenance expenses - recovered through December 2007 (Note 2)	- -	- -	- -	- -	3.6	- -
Deferred fuel - non-current - recovered through rate riders when rates are redetermined annually	13.7	- -	- -	8.1	- -	- -
Depreciation re-direct - recovery begins at start of retail open access (Note 1)	- -	79.1	- -	- -	- -	- -
DOE Decom. and Decontamination Fees - recovered through fuel rates until December 2006 (Note 8)	13.1	2.3	5.0	- -	- -	4.9
Incremental ice storm costs - recovered until 2032	14.2	- -	- -	- -	- -	- -
Low-level radwaste - recovery timing dependent upon pending lawsuit	16.2	3.1	- -	- -	- -	- -
Pension costs (Note 10)	70.8	-	34.1	20.2	15.2	7.4
Postretirement benefits - recovered through 2013 (Note 10)	19.1	- -	- -	- -	- -	- -
Provision for storm damages - recovered through cost of service	29.0	57.1	41.7	- -	- -	- -
Removal costs - recovered through depreciation rates (Note 8)	34.9	0.9	- -	32.7	1.3	17.1
Resource planning - recovery timing will be determined by the LPSC in a base rate proceeding (Note 2)	- -	- -	25.4	- -	- -	- -
River Bend AFUDC - recovered through August 2025 (Note 1)	- -	37.5	- -	- -	- -	- -
Sale-leaseback deferral - recovered through June 2014 (Note 9)	- -	- -	-	- -	- -	127.3
Spindletop gas storage facility - recovered through 2032	- -	42.3	- -	- -	- -	- -
Unamortized loss on reaquired debt - recovered over term of debt	37.0	43.4	27.4	15.6	4.6	41.8
Other - various	11.0	19.3	27.3	6.1	10.8	0.5
Total	$400.2	$285.0	$302.5	$82.7	$40.4	$296.3

2003	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
Asset Retirement Obligation (Note 8)	$203.7	$36.2	$132.3	$-	$-	$92.7
Deferred fuel - non-current	17.1	-	-	11.1	-	-
Depreciation re-direct (Note 1)	-	79.1	-	-	-	-
DOE Decom. and Decontamination Fees (Note 8)	17.1	3.0	6.5	- -	- -	6.4
Incremental ice storm costs	14.7	-	-	-	-	-
Low-level radwaste	16.2	3.1	-	-	-	-
Pension costs (Note 10)	41.7	-	-	6.4	10.4	7.1
Postretirement benefits (Note 10)	21.5	-	-	-	-	-
Provision for storm damages	25.3	57.4	40.9	3.5	-	-
Removal costs (Note 8)	26.6	4.2	-	24.4	2.1	15.1
Resource planning (Note 2)	-	-	5.8	-	-	-
River Bend AFUDC (Note 1)	-	39.4	-	-	-	-
Sale-leaseback deferral (Note 9)	-	-	-	-	-	131.7
Spindletop gas storage facility	-	38.0	-	-	-	-
Unamortized loss on reaquired debt	38.3	46.6	24.0	11.8	1.7	41.9
1994 FERC Settlement (Note 2)	-	-	-	-	-	4.0
Other	15.3	13.4	8.2	1.1	13.0	2.3
Total	$437.5	$320.4	$217.7	$58.3	$27.2	$301.2

Deferred fuel costs

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

	2004	2003
	(In Millions)
Entergy Arkansas	$7.4	$10.6
Entergy Gulf States	$90.1	$118.4
Entergy Louisiana	$8.7	$30.6
Entergy Mississippi	($22.8)	$89.1
Entergy New Orleans	$2.6	($2.7)

Entergy Arkansas

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

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

Entergy Gulf States (Texas)

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

	Amount
	(In Millions)
Under-recovered fuel costs for the period 9/03 - - 7/04 to be recovered through an interim fuel surcharge over a six-month period beginning in January 2005	$27.8
Items to be addressed as part of unbundling	$29.0
Imputed capacity charges	$ 9.3
Other	$12.5

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

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

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

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

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

Entergy Gulf States (Louisiana) and Entergy Louisiana

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

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

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

Entergy Mississippi

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

In January 2005, the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Entergy Mississippi's fuel over-recoveries for the third quarter of 2004 of $21.3 million will be deferred from the first quarter 2005 energy cost recovery rider adjustment calculation. The deferred amount of $21.3 million plus carrying charges will be refunded through the energy cost recovery rider in the second and third quarters of 2005 at a rate of 45% and 55%, respectively.

Entergy New Orleans

Entergy New Orleans' electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations, including carrying charges. Entergy New Orleans' gas rate schedules include estimates for the billing month adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations, including carrying charges.

In June and November 2004, the City Council passed resolutions implementing a package of measures developed by Entergy New Orleans and the Council Advisors to protect customers from potential gas price spikes during the 2004 - 2005 winter heating season. These measures include: maintaining Entergy New Orleans' financial hedging plan for its purchase of wholesale gas, and deferral of collection of up to $6.2 million of gas costs associated with a cap on the purchased gas adjustment in November and December 2004 and in the event that the average residential customer's gas bill were to exceed a threshold level. The deferrals resulting from these caps will receive accelerated recovery over a seven-month period beginning in April 2005.

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

Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

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

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

Retail Rates

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

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

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

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

Recovery of River Bend Costs

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

Filings with the LPSC

Proposed Settlement (Entergy Gulf States and Entergy Louisiana)

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

Annual Earnings Reviews (Entergy Gulf States)

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

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

Retail Rates

(Entergy Gulf States)

In July 2004, Entergy Gulf States filed with the LPSC an application for a change in its rates and charges seeking an increase of $9.1 million in gas base rates in order to allow Entergy Gulf States an opportunity to earn a fair and reasonable rate of return. Entergy Gulf States also is seeking approval of certain proposed rate design, rate schedule, and policy changes. Discovery is underway, and a decision is expected during the third quarter of 2005.

(Entergy Louisiana)

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

Filings with the MPSC (Entergy Mississippi)

Formula Rate Plan Filings

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

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

Grand Gulf Accelerated Recovery Tariff (GGART)

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

Filings with the City Council (Entergy New Orleans)

Formula Rate Plans

In May 2003, the City Council approved a resolution allowing for a total increase of $30.2 million in electric and gas base rates effective June 1, 2003.  In April 2004, Entergy New Orleans made filings with the City Council as required by the earnings review process prescribed by the Gas and Electric Formula Rate Plans approved by the City Council in 2003. The filings sought an increase in Entergy New Orleans' electric revenues of $1.2 million and an increase in Entergy New Orleans' gas revenues of $32,000. The Council Advisors and intervenors reviewed the filings, and filed their recommendations in July 2004. In August 2004, in accordance with the City Council's requirements for the formula rate plans, Entergy New Orleans made a filing with the City Council reflecting the parties' concurrence that no change in Entergy New Orleans' electric or gas rates is warranted. Later in August 2004, the City Council approved an unopposed settlement among Entergy New Orleans, the Council Advisors, and the intervenors in connection with the Gas and Electric Formula Rate Plans. In accordance with the resolution approving the settlement agreement, Entergy New Orleans' gas and electric base rates remain unchanged from levels set in May 2003. The resolution ordered Entergy New Orleans to defer $3.9 million relating to voluntary severance plan costs allocated to its electric operations and $1.0 million allocated to its gas operations, which amounts were accrued on its books in 2003, and to record on its books regulatory assets in those amounts to be amortized over five years effective January 2004. Entergy New Orleans also was ordered to defer $6.0 million of fossil plant maintenance expense incurred in 2003 and to record on its books a regulatory asset in that amount to be amortized over a five-year period effective January 2003.

Entergy New Orleans will file its formula rate plan for the year ended December 31, 2004 by May 31, 2005 and also intends to file for an extension of the formula rate plan by September 1, 2005. If the formula rate plan is not extended by the City Council, the rate adjustments in effect based on the December 31, 2004 test year shall continue.

In May 2003, the City Council approved implementation of a generation performance-based rate calculation in the electric fuel adjustment clause under which Entergy New Orleans receives 10% of calculated fuel and purchased power cost savings in excess of $20 million, based on a defined benchmark, subject to a 13.25% return on equity limitation for electric operations as provided for in the electric formula rate plan. Entergy New Orleans bears 10% of any "negative" fuel and purchased power cost savings. In October 2004, Entergy New Orleans' annual evaluation report was submitted for the period June 2003 through May 2004. Savings associated with the first year generation performance-based rate calculation was $71 million of which Entergy New Orleans' share was $5.1 million.

Fuel Adjustment Clause Litigation

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

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

Purchased Power for Summer 2001, 2002 and 2003 (Entergy Gulf States and Entergy Louisiana)

In March 2001, Entergy Louisiana and Entergy Gulf States filed applications with the LPSC for authorization to participate in contracts that would be executed by the Entergy System to meet the summer peak load requirements for the summer of 2001. In May 2001, the LPSC determined that 24% of Entergy Louisiana's and Entergy Gulf States' costs relating to summer 2001 purchases should be categorized as capacity charges. Subsequently, the LPSC raised certain prudence issues related to the 2001 purchases. The administrative law judge (ALJ) presiding over the case issued a Preliminary Recommendation regarding prudence issues primarily associated with the power uprates at the Waterford 3 and Grand Gulf nuclear units. In the event that such decision becomes final, additional calculations would be required to determine the potential refund obligation for the periods 2001, 2002 and 2003. The ALJ also concluded that Entergy should be permitted the opportunity to recover the expenses of the uprate s through appropriate rate proceedings.

In March 2002 and 2003, Entergy Louisiana and Entergy Gulf States filed an application with the LPSC for the approval of capacity and energy purchases for the summers of 2002 and 2003, respectively, similar to the applications filed for the summers of 2000 and 2001. The LPSC ordered that 14% of Entergy Louisiana's and Entergy Gulf States' costs relating to summer 2002 purchases be categorized as capacity charges, and that 11% of Entergy Louisiana's and Entergy Gulf States' costs relating to summer 2003 power purchases, the price of which was stated on the basis of $/MWh, be categorized as capacity charges. The LPSC did not allow the capacity charges to be set up as a regulatory asset, but authorized Entergy Louisiana and Entergy Gulf States to include these costs in any base rate case for their respective test years. Prudence issues relating to summer 2002 and 2003 purchases were resolved in subsequent settlements approved by the LPSC. In the event that the LPSC adopts the ALJ's recomm endation relating to potential uprates at nuclear facilities in the summer 2001 case, and such decision becomes final following an appeal or the expiration of appeal delays, these settlements reserve the LPSC's right to propose in a future case disallowances relating to the effect that such uprates would have had on the summer 2002 and summer 2003 firm energy contracts, while Entergy Gulf States and Entergy Louisiana reserve their right to oppose any such proposal.

No refunds were ordered in the summer 2002 settlement, although with respect to the capacity costs to be incurred pursuant to a particular purchased power contract, Entergy Louisiana agreed in the settlement to forgo recovery of approximately $0.8 million in 2002, $1.3 million in 2003, and $1.0 million in 2004, and Entergy Gulf States agreed to forgo recovery of approximately $0.5 million in 2002, $0.9 million in 2003, and $0.7 million in 2004. All other purchases for the summers of 2002 and 2003 were found to be prudent. Issues relating to the reasonableness of the long-term planning process were moved from the summer 2002 case into a separate sub-docket. In the summer 2003 settlement, the LPSC also reserved its right to investigate any alleged imprudence regarding the System's decision to spin off the ISES and Ritchie generating units to an unregulated affiliate, Entergy Power, Inc.

Should the LPSC approve the proposed settlement discussed above, all issues arising out of the purchased power cases for the summers of 2001, 2002, and 2003 would be resolved.

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

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

NOTE 3. INCOME TAXES

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

	Entergy	Entergy	Entergy	Entergy	Entergy	System
2004	Arkansas	Gulf States	Louisiana	Mississippi	New Orleans	Energy
	(In Thousands)
Current:
Federal (a)(b)	$14,490	$42,436	$2,439	($23,568)	($19,259)	$222,622
State (a)(b)	8,727	7,944	1,957	(1,221)	(3,655)	33,926
Total (a)(b)	23,217	50,380	4,396	(24,789)	(22,914)	256,548
Deferred -- net	70,674	63,615	80,207	63,234	40,226	(175,059)
Investment tax credit
adjustments -- net	(4,827)	(5,707)	(5,128)	(1,405)	(444)	(3,476)
Recorded income tax expense	$89,064	$108,288	$79,475	$37,040	$16,868	$78,013

	Entergy	Entergy	Entergy	Entergy	Entergy	System
2003	Arkansas	Gulf States	Louisiana	Mississippi	New Orleans	Energy
	(In Thousands)
Current:
Federal (a)	$40,632	($11,535)	($745,724)	($2,969)	($7,655)	$95,670
State (a)	16,306	(1,503)	(16,243)	2,565	(1,871)	15,382
Total (a)	56,938	(13,038)	(761,967)	(404)	(9,526)	111,052
Deferred -- net	53,309	36,652	864,656	36,240	15,853	(31,731)
Investment tax credit
adjustments -- net	(4,951)	(12,078)	(5,281)	(1,405)	(452)	(3,476)
Recorded income tax expense	$105,296	$11,536	$97,408	$34,431	$5,875	$75,845

	Entergy	Entergy	Entergy	Entergy	Entergy	System
2002	Arkansas	Gulf States	Louisiana	Mississippi	New Orleans	Energy
	(In Thousands)
Current:
Federal (a)	$13,206	$66,227	$43,048	$21,817	($7,103)	$99,429
State (a)	3,243	11,345	1,867	3,969	(47)	14,994
Total (a)	16,449	77,572	44,915	25,786	(7,150)	114,423
Deferred -- net	59,963	(4,210)	45,253	(6,529)	7,196	(34,770)
Investment tax credit
adjustments -- net	(5,008)	(7,365)	(5,403)	(1,411)	(468)	(3,476)
Recorded income tax expense	$71,404	$65,997	$84,765	$17,846	($422)	$76,177

(a)

Entergy Louisiana's actual cash taxes paid/(refunded) were $(70,650) in 2004, $35,128 in 2003, and $(781,540) in 2002. Entergy Louisiana's mark-to-market tax accounting election significantly reduced taxes paid in 2002. In 2001, Entergy Louisiana changed its method of accounting for tax purposes related to its wholesale electric power contracts. The most significant of these is the contract to purchase power from the Vidalia project (the contract is discussed in Note 8 to the domestic utility companies and System Energy financial statements). The new tax accounting method has provided a cumulative cash flow benefit of approximately $790 million through 2004, which is expected to reverse in the years 2005 through 2031. The election did not reduce book income tax expense. The timing of the reversal of this benefit depends on several variables, including the price of power. Approximately half of the consolidated cash flow benefit of the election occurred in 2001 and the remainder occurred in 2002. In accordance with Entergy's intercompany tax allocation agreement, the cash flow benefit for Entergy Louisiana occurred in the fourth quarter of 2002.

(b)

In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $1.171 billion deduction for Entergy Arkansas, a $674 million deduction for Entergy Gulf States, a $505 million deduction for Entergy Louisiana, a $145 million deduction for Entergy Mississippi, a $31 million deduction for Entergy New Orleans, and a $430 million deduction for System Energy on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. In 2004, Entergy Arkansas realized $173 million, Entergy Gulf States realized $69 million, Entergy Louisiana realized $100 million, Entergy Mississippi realized $36 million, and System Energy realized $144 million in cash tax benefit from the method change. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit. Entergy believes that its contingency provision established in its financial statements will sufficiently cover its risk associated with this issue.

Total income taxes differ from the amounts computed by applying the statutory income tax rate to income before taxes. The reasons for the differences for the years 2004, 2003, and 2002 are:

	Entergy	Entergy	Entergy	Entergy	Entergy	System
2004	Arkansas	Gulf States	Louisiana	Mississippi	New Orleans	Energy
	(In Thousands)
Computed at statutory rate (35%)	$80,946	$105,194	$72,440	$38,688	$15,729	$64,386
Increases (reductions) in tax
resulting from:
State income taxes net of
federal income tax effect	12,204	8,289	6,411	3,845	1,158	7,665
Regulatory differences -
utility plant items	13,775	6,951	10,052	(1,482)	1,373	10,528
Amortization of investment
tax credits	(4,827)	(5,316)	(5,128)	(1,405)	(444)	(3,476)
Flow-through/permanent
differences	(9,127)	(7,080)	(3,576)	(2,114)	(878)	(993)
Other -- net	(3,907)	250	(724)	(492)	(70)	(97)
Total income taxes	$89,064	$108,288	$79,475	$37,040	$16,868	$78,013
Effective Income Tax Rate	38.5%	36.0%	38.4%	33.5%	37.5%	42.4%

	Entergy	Entergy	Entergy	Entergy	Entergy	System
2003	Arkansas	Gulf States	Louisiana	Mississippi	New Orleans	Energy
	(In Thousands)
Computed at statutory rate (35%)	$80,957	$18,934	$85,247	$35,522	$4,807	$63,647
Increases (reductions) in tax
resulting from:
State income taxes net of
federal income tax effect	12,987	473	7,764	3,000	21	7,765
Regulatory differences -
utility plant items	15,994	13,260	10,568	(930)	2,045	11,530
Amortization of investment
tax credits	(4,951)	(8,797)	(5,281)	(1,404)	(452)	(3,476)
Flow-through/permanent
differences	1,090	(10,625)	(2,012)	(1,112)	(625)	(420)
Benefit of Entergy Corp. expenses	(1,145)	(888)	-	-	-	(3,408)
Other -- net	364	(821)	1,122	(645)	79	207
Total income taxes	$105,296	$11,536	$97,408	$34,431	$5,875	$75,845
Effective Income Tax Rate	45.5%	21.3%	40.0%	33.9%	42.8%	41.7%

	Entergy	Entergy	Entergy	Entergy	Entergy	System
2002	Arkansas	Gulf States	Louisiana	Mississippi	New Orleans	Energy
	(In Thousands)
Computed at statutory rate (35%)	$72,467	$84,064	$80,317	$24,589	($228)	$62,836
Increases (reductions) in tax
resulting from:
State income taxes net of
federal income tax effect	8,784	6,401	6,065	2,069	551	7,049
Regulatory differences -
utility plant items	10,615	2,738	6,875	(3,032)	1,125	11,453
Amortization of investment
tax credits	(5,008)	(6,528)	(5,403)	(1,411)	(468)	(3,476)
Flow-through/permanent
differences	(10,687)	(15,000)	(1,878)	(1,453)	(538)	(1,183)
Benefit of Entergy Corp. expenses	(3,428)	(3,830)	(180)	(2,331)	(434)	(191)
Other -- net	(1,339)	(1,848)	(1,031)	(585)	(430)	(311)
Total income taxes	$71,404	$65,997	$84,765	$17,846	($422)	$76,177
Effective Income Tax Rate	34.5%	27.5%	36.9%	25.4%	64.7%	42.4%

Significant components of net deferred and long-term accrued tax liabilities as of December 31, 2004 and 2003 are as follows:

	Entergy	Entergy	Entergy	Entergy	Entergy	System
2004	Arkansas	Gulf States	Louisiana	Mississippi	New Orleans	Energy
	(In Thousands)
Deferred and Long-term Accrued Tax Liabilities:
Net regulatory assets/(liabilities)	($128,594)	($479,158)	($169,675)	($22,864)	$44,867	($223,391)
Plant-related basis differences - net	(1,237,303)	(1,388,391)	(921,976)	(389,558)	(103,733)	(471,026)
Power purchase agreements	-	-	(971,676)	-	-	-
Rate refunds	(39,163)	-	(17,736)	(49,124)	(14,375)	-
Deferred fuel	(2,899)	(36,017)	(1,286)	(6,424)	(3,873)	-
Other reserves	2,686	(33,916)	27,421	5,856	(323)	(80,597)
Other	(80,980)	(20,781)	(68,381)	(16,516)	(2,982)	(11,851)
Total	(1,486,253)	(1,958,263)	(2,123,309)	(478,630)	(80,419)	(786,865)
Deferred Tax Assets:
Accumulated deferred investment
tax credit	26,936	34,359	36,989	5,235	1,538	28,922
Sale and leaseback	-	-	82,410	-	-	144,745
NOL carryforward	300,249	164,749	164,840	34,642	18,973	-
Unbilled/Deferred revenues	-	17,001	-	10,193	-	-
Pension-related items	-	14,499	13,039	-	10,656	6,737
Reserve for regulatory adjustments	-	131,112	-	-	-	-
Rate refund	-	32,932	-	-	-	170,222
Customer deposits	40,880	33,425	17,479	15,777	91	-
Nuclear decommissioning	12,070	-	2,833	-	-	-
Other	11,801	10,721	13,021	2,386	193	11,296
Total	391,936	438,798	330,611	68,233	31,451	361,922
Net deferred tax liability	($1,094,317)	($1,519,465)	($1,792,698)	($410,397)	($48,968)	($424,943)

	Entergy	Entergy	Entergy	Entergy	Entergy	System
2003	Arkansas	Gulf States	Louisiana	Mississippi	New Orleans	Energy
	(In Thousands)
Deferred and Long-term Accrued Tax Liabilities:
Net regulatory assets/(liabilities)	($157,147)	($478,254)	($195,074)	($34,738)	$38,834	($246,519)
Plant-related basis differences, net	(798,641)	(1,095,206)	(806,955)	(284,550)	(74,041)	(332,197)
Power purchase agreements	-	-	(945,495)	-	-	-
Deferred fuel	(4,154)	(45,762)	-	(40,091)	(1,109)	-
Long term taxes accrued	(26,611)	(55,155)	-	(52,646)	(17,491)	(57,239)
Other	(85,528)	(26,012)	(67,272)	(21,806)	(1,728)	(11,497)
Total	(1,072,081)	(1,700,389)	(2,014,796)	(433,831)	(55,535)	(647,452)
Deferred Tax Assets:
Accumulated deferred investment
tax credit	28,836	36,192	38,962	5,773	1,709	30,251
Sale and leaseback	-	-	83,539	-	-	139,595
NOL carryforward	-	-	104,489	-	-	-
Unbilled/Deferred revenues	-	11,959	-	7,357	-	-
Pension-related items	5,453	11,474	12,562	-	9,324	7,354
Reserve for regulatory adjustments	-	138,933	-	-	-	-
Rate refund	2,351	23,184	789	379	3,977	170,222
Customer deposits	37,778	35,840	16,804	18,085	84	-
Nuclear decommissioning	13,171	-	2,833	-	-	-
Other	6,399	26,147	26,096	9,722	1,415	8,124
Total	93,988	283,729	286,074	41,316	16,509	355,546
Net deferred tax liability	($978,093)	($1,416,660)	($1,728,722)	($392,515)	($39,026)	($291,906)

As of December 31, 2004, federal net operating loss carryforwards were $766.9 million for Entergy Arkansas, $447.5 million for Entergy Gulf States, $195.7 million for Entergy Louisiana, $40.9 million for Entergy Mississippi, and $54.9 million for Entergy New Orleans. If the federal net operating loss carryforwards are not utilized, they will expire in the year 2023.

As of December 31, 2004, state net operating loss carryforwards were $1.9 billion for Entergy Louisiana, $278 million for Entergy Gulf States, $11 million for Entergy New Orleans, and $638 million for Entergy Arkansas. If the state net operating loss carryforwards are not utilized, they will expire in the years 2016 through 2018 for Entergy Louisiana, 2018 for Entergy Gulf States, 2018 for Entergy New Orleans, and 2008 for Entergy Arkansas.

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

The short-term borrowings of Entergy's subsidiaries are limited to amounts authorized by the SEC. The current limits authorized are effective through November 30, 2007. In addition to borrowing from commercial banks, Entergy's subsidiaries are authorized under the SEC order to borrow from Entergy's money pool. The money pool is an inter-company borrowing arrangement designed to reduce Entergy's subsidiaries' dependence on external short-term borrowings. Borrowings from the money pool and external borrowings combined may not exceed the SEC authorized limits. Under the SEC Order and without further SEC authorization, the domestic utility companies and System Energy cannot incur additional short-term indebtedness unless (a) the issuer and Entergy Corporation maintain a common equity ratio of at least 30% and (b) with the exception of money pool borrowings, the security to be issued (if rated) and all outstanding securities of the issuer (other than preferred stock of Entergy Gulf States and Entergy New Orleans), as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade.

The following are the SEC authorized limits for short-term borrowings and the outstanding short-term borrowings from the money pool for the domestic utility companies and System Energy as of December 31, 2004:

	Authorized	Borrowings
	(In Millions)
Entergy Arkansas	$235	-
Entergy Gulf States	$340	$59.7
Entergy Louisiana	$225	-
Entergy Mississippi	$160	-
Entergy New Orleans	$100	-
System Energy	$140	-

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

Company	Expiration Date	Amount of Facility	Amount Drawn as of Dec. 31, 2004
Entergy Arkansas	April 2005	$85 million	-
Entergy Louisiana	April 2005	$15 million(a)	-
Entergy Mississippi	May 2005	$25 million	-
Entergy New Orleans	April 2005	$14 million(a)	-

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

The 364-day credit facilities have variable interest rates and the average commitment fee is 0.13%. The Entergy Arkansas facility requires it to maintain total shareholder's equity of at least 25% of its total assets.

NOTE 5. LONG - TERM DEBT (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

Long-term debt as of December 31, 2004 and 2003 consisted of:

	2004	2003
	(In Thousands)
Entergy Arkansas
Mortgage Bonds:
6.125% Series due July 2005	$100,000	$100,000
5.4% Series due May 2018	150,000	150,000
5.0% Series due July 2018	115,000	115,000
7.0% Series due October 2023	175,000	175,000
6.7% Series due April 2032	100,000	100,000
6.0% Series due November 2032	100,000	100,000
5.9% Series due June 2033	100,000	100,000
6.38% Series due November 2034	60,000	-
Total mortgage bonds	900,000	840,000
Governmental Bonds (a):
6.3% Series due 2016, Pope County (h)	19,500	19,500
5.6% Series due 2017, Jefferson County	45,500	45,500
6.3% Series due 2018, Jefferson County (h)	9,200	9,200
6.3% Series due 2020, Pope County	120,000	120,000
6.25% Series due 2021, Independence County (h)	45,000	45,000
5.05% Series due 2028, Pope County (b)	47,000	47,000
Total governmental bonds	286,200	286,200
Other Long-Term Debt
Long-term DOE Obligation (c)	156,332	154,409
8.5% Junior Subordinated Deferrable Interest Debentures	-	61,856
Unamortized Premium and Discount - - Net	(4,390)	(4,708)
Other	621	621
Total Long-Term Debt	1,338,763	1,338,378
Less Amount Due Within One Year	147,000	-
Long-Term Debt Excluding Amount Due Within One Year	$1,191,763	$1,338,378
Fair Value of Long-Term Debt (d)	$1,224,942	$1,235,278

	2004	2003
	(In Thousands)
Entergy Gulf States
Mortgage Bonds:
8.25% Series due April 2004	$-	$292,000
6.77% Series due August 2005	98,000	98,000
Libor + 0.9% Series due June 2007	-	275,000
5.2% Series due December 2007	-	200,000
3.6% Series due June 2008	325,000	325,000
Libor + 0.4% Series due December 2009	225,000	-
4.875% Series due November 2011	200,000	-
6.0% Series due December 2012	140,000	140,000
5.6% Series due December 2014	50,000	-
5.25% Series due August 2015	200,000	200,000
6.2% Series due July 2033	240,000	240,000
Total mortgage bonds	1,478,000	1,770,000
Governmental Bonds (a):
5.45% Series due 2010, Calcasieu Parish	22,095	22,095
6.75% Series due 2012, Calcasieu Parish	48,285	48,285
6.7% Series due 2013, Pointe Coupee Parish	17,450	17,450
5.7% Series due 2014, Iberville Parish	21,600	21,600
7.7% Series due 2014, West Feliciana Parish	94,000	94,000
5.8% Series due 2015, West Feliciana Parish	28,400	28,400
7.0% Series due 2015, West Feliciana Parish	39,000	39,000
7.5% Series due 2015, West Feliciana Parish	41,600	41,600
9.0% Series due 2015, West Feliciana Parish	45,000	45,000
5.8% Series due 2016, West Feliciana Parish	20,000	20,000
5.65% Series due 2028, West Feliciana Parish (e)	-	62,000
6.6% Series due 2028, West Feliciana Parish	40,000	40,000
Total governmental bonds	417,430	479,430
Other Long-Term Debt
8.75% Junior Subordinated Deferrable Interest Debentures	87,629	87,629
Unamortized Premium and Discount - - Net	(2,397)	(2,596)
Other	8,816	9,150
Total Long-Term Debt	1,989,478	2,343,613
Less Amount Due Within One Year	98,000	354,000
Long-Term Debt Excluding Amount Due Within One Year	$1,891,478	$1,989,613
Fair Value of Long-Term Debt (d)	$1,999,249	$2,438,997

	2004	2003
	(In Thousands)
Entergy Louisiana
Mortgage Bonds:
6.5% Series due March 2008	$-	$115,000
5.09% Series due November 2014	115,000	-
5.5% Series due April 2019	100,000	-
7.6% Series due April 2032	150,000	150,000
6.4% Series due October 2034	70,000	-
Total mortgage bonds	435,000	265,000
Governmental Bonds (a):
7.5% Series due 2021, St. Charles Parish (h)	50,000	50,000
7.0% Series due 2022, St. Charles Parish (h)	24,000	24,000
7.05% Series due 2022, St. Charles Parish (h)	20,000	20,000
5.95% Series due 2023, St. Charles Parish (h)	25,000	25,000
6.2% Series due 2023, St. Charles Parish (h)	33,000	33,000
6.875% Series due 2024, St. Charles Parish (h)	20,400	20,400
6.375% Series due 2025, St. Charles Parish	16,770	16,770
5.35% Series due 2029, St. Charles Parish (i)	-	-
Auction Rate due 2030, St. Charles Parish (h)	60,000	60,000
4.9% Series due 2030, St. Charles Parish (f) (g)	55,000	55,000
Total governmental bonds	304,170	304,170
Other Long-Term Debt:
Waterford 3 Lease Obligation 7.45% (Note 9)	247,725	262,534
9.0% Junior Subordinated Deferrable Interest Debentures	-	72,165
Unamortized Premium and Discount - Net	(1,200)	(1,373)
Total Long-Term Debt	985,695	902,496
Less Amount Due Within One Year	55,000	14,809
Long-Term Debt Excluding Amount Due Within One Year	$930,695	$887,687
Fair Value of Long-Term Debt (d)	$762,782	$668,700

	2004	2003
	(In Thousands)
Entergy Mississippi
Mortgage Bonds:
6.2% Series due May 2004	$-	$75,000
6.45% Series due April 2008	-	80,000
4.35% Series due April 2008	100,000	100,000
4.65% Series due May 2011	80,000	-
5.15% Series due February 2013	100,000	100,000
4.95% Series due June 2018	95,000	95,000
7.7% Series due July 2023	-	60,000
6.0% Series due November 2032	75,000	75,000
7.25% Series due December 2032	100,000	100,000
6.25% Series due April 2034	100,000	-
Total mortgage bonds	650,000	685,000
Governmental Bonds (a):
7.0% Series due 2022, Warren County	-	8,095
7.0% Series due 2022, Washington County	-	7,935
4.60% Series due 2022, Mississippi Business Finance Corp.	16,030	-
Auction Rate due 2022, Independence County (h)	30,000	30,000
Total governmental bonds	46,030	46,030
Other Long-Term Debt:
Unamortized Premium and Discount - Net	(957)	(1,074)
Total Long-Term Debt	695,073	729,956
Less Amount Due Within One Year	-	75,000
Long-Term Debt Excluding Amount Due Within One Year	$695,073	$654,956
Fair Value of Long-Term Debt (d)	$716,201	$771,402

	2004	2003
	(In Thousands)
Entergy New Orleans
Mortgage Bonds:
8.125% Series due July 2005	$30,000	$30,000
3.875% Series due August 2008	30,000	30,000
5.25% Series due August 2013	70,000	70,000
6.75% Series due October 2017	25,000	25,000
8.0% Series due March 2023	-	45,000
7.55% Series due September 2023	-	30,000
5.6% Series due September 2024	35,000	-
5.65% Series due September 2029	40,000	-
Total mortgage bonds	230,000	230,000
Other Long-Term Debt:
Unamortized Premium and Discount - Net	(98)	(783)
Total Long-Term Debt	229,902	229,217
Less Amount Due Within One Year	30,000	-
Long-Term Debt Excluding Amount Due Within One Year	$199,902	$229,217
Fair Value of Long-Term Debt (d)	$231,957	$239,816

	2004	2003
	(In Thousands)
System Energy
Mortgage Bonds:
4.875% Series due October 2007	$70,000	$70,000
Total mortgage bonds	70,000	70,000
Governmental Bonds (a):
5.875% Series due 2022, Mississippi Business Finance Corp.	216,000	216,000
5.9% Series due 2022, Mississippi Business Finance Corp.	102,975	102,975
7.3% Series due 2025, Claiborne County	-	7,625
6.2% Series due 2026, Claiborne County	90,000	90,000
Total governmental bonds	408,975	416,600
Other Long-Term Debt:
Grand Gulf Lease Obligation 5.01% (Note 9)	397,119	403,468
Unamortized Premium and Discount - Net	(1,235)	(1,319)
Total Long-Term Debt	874,859	888,749
Less Amount Due Within One Year	25,266	6,348
Long-Term Debt Excluding Amount Due Within One Year	$849,593	$882,401
Fair Value of Long-Term Debt (d)	$470,187	$489,436

(a)	Consists of pollution control revenue bonds and environmental revenue bonds.
(b)	The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on September 1, 2005 and can then be remarketed.
(c)	Pursuant to the Nuclear Waste Policy Act of 1982, Entergy's nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service. The contracts include a one-time fee for generation prior to April 7, 1983. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt.
(d)	The fair value excludes lease obligations and long-term DOE obligations, and includes debt due within one year. It is determined using bid prices reported by dealer markets and by nationally recognized investment banking firms.
(e)	The bonds had a mandatory tender date of September 1, 2004. Entergy Gulf States purchased the bonds from the holders, pursuant to the mandatory tender provision, and has not remarketed the bonds at this time.
(f)	On June 1, 2002, Entergy Louisiana remarketed $55 million St. Charles Parish Pollution Control Revenue Refunding Bonds due 2030, resetting the interest rate to 4.9% through May 2005.
(g)	The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on June 1, 2005 and can then be remarketed.
(h)	The bonds are secured by a series of collateral first mortgage bonds.
(i)	The bonds in the principal amount of $110.95 million had a mandatory tender date of October 1, 2003. Entergy Louisiana purchased the bonds from the holders, pursuant to the mandatory tender provision, and has not remarketed the bonds at this time.

The annual long-term debt maturities (excluding lease obligations) for debt outstanding as of December 31, 2004, for the next five years are as follows:

	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
2005	$147,000	$98,000	$55,000	-	$30,000	-
2006	-	-	-	-	-	-
2007	-	-	-	-	-	$70,000
2008	$621	$325,000	-	$100,000	$30,000	-
2009	-	$225,000	-	-	-	-

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

Junior Subordinated Deferrable Interest Debentures and Implementation of FIN 46 (Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana)

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

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

Tax Exempt Bond Audit (Entergy Louisiana)

In November 2000, the Internal Revenue Service (IRS) began an audit of certain Tax Exempt Bonds issued by St. Charles Parish, State of Louisiana (the Issuer). The Bonds were issued to finance previously unfinanced acquisition costs expended by Entergy Louisiana to acquire certain radioactive solid waste disposal facilities (the Facilities) at the Waterford Steam Electric Generating Station. In January 2002, the IRS issued a preliminary adverse determination that the Bonds were not tax exempt. The stated basis for this determination was that radioactive waste did not constitute "solid waste" within the provisions of the Internal Revenue Code and therefore the Facilities did not qualify as solid waste disposal facilities. In a "technical advice memorandum," issued in October 2004 to the parish, the IRS National Office concurred with the preliminary adverse determination. The Issuer and Entergy Louisiana intend to continue to vigorously contest this matter.

NOTE 6. PREFERRED STOCK (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans)

The number of shares authorized and outstanding and dollar value of preferred stock for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans as of December 31, 2004 and 2003 are presented below. Only the two Entergy Gulf States series "with sinking fund" contain mandatory redemption requirements. All other series of the U.S. Utilities are redeemable at Entergy's option at the call prices presented. Dividends paid on all of Entergy's preferred stock series are eligible for the dividends received deduction.The dividends received deduction is limited by Internal Revenue Code section 244 for the following preferred stock series: Entergy Arkansas 4.72%, Entergy Gulf States 4.40%, Entergy Louisiana 4.96%, Entergy Mississippi 4.56%, and Entergy New Orleans 4.75%.

	Shares Authorized and Outstanding		Dollars (In Thousands)		Call Price Per Share as of December 31,
	2004	2003	2004	2003	2004
Entergy Arkansas Preferred Stock
Without sinking fund:
Cumulative, $100 par value:
4.32% Series	70,000	70,000	$7,000	$7,000	$103.65
4.72% Series	93,500	93,500	9,350	9,350	$107.00
4.56% Series	75,000	75,000	7,500	7,500	$102.83
4.56% 1965 Series	75,000	75,000	7,500	7,500	$102.50
6.08% Series	100,000	100,000	10,000	10,000	$102.83
7.32% Series	100,000	100,000	10,000	10,000	$103.17
7.80% Series	150,000	150,000	15,000	15,000	$103.25
7.40% Series	200,000	200,000	20,000	20,000	$102.80
7.88% Series	150,000	150,000	15,000	15,000	$103.00
Cumulative, $0.01 par value:
$1.96 Series (a)	600,000	600,000	15,000	15,000	$25.00
Total without sinking fund	1,613,500	1,613,500	$116,350	$116,350

	Shares Authorized and Outstanding		Dollars (In Thousands)		Call Price Per Share as of December 31,
	2004	2003	2004	2003	2004
Entergy Gulf States Preferred Stock
Preferred Stock
Authorized 6,000,000 shares,     $100 par value, cumulative
Without sinking fund:
4.40% Series	51,173	51,173	$5,117	$5,117	$108.00
4.50% Series	5,830	5,830	583	583	$105.00
4.40% 1949 Series	1,655	1,655	166	166	$103.00
4.20% Series	9,745	9,745	975	975	$102.82
4.44% Series	14,804	14,804	1,480	1,480	$103.75
5.00% Series	10,993	10,993	1,099	1,099	$104.25
5.08% Series	26,845	26,845	2,685	2,685	$104.63
4.52% Series	10,564	10,564	1,056	1,056	$103.57
6.08% Series	32,829	32,829	3,283	3,283	$103.34
7.56% Series	308,830	308,830	30,883	30,883	$101.80
Total without sinking fund	473,268	473,268	$47,327	$47,327
With sinking fund:
Adjustable Rate-A, 7.0% (b)	84,000	96,020	$8,400	$9,602	$100.00
Adjustable Rate-B, 7.0% (b)	90,000	112,500	9,000	11,250	$100.00
Total with sinking fund	174,000	208,520	$17,400	$20,852
Fair Value of Preferred Stock with Sinking Fund (c)			$15,286	$15,354

	Shares Authorized and Outstanding		Dollars (In Thousands)		Call Price Per Share as of December 31,
	2004	2003	2004	2003	2004
Entergy Louisiana Preferred Stock
Without sinking fund:
Cumulative, $100 par value:
4.96% Series	60,000	60,000	$6,000	$6,000	$104.25
4.16% Series	70,000	70,000	7,000	7,000	$104.21
4.44% Series	70,000	70,000	7,000	7,000	$104.06
5.16% Series	75,000	75,000	7,500	7,500	$104.18
5.40% Series	80,000	80,000	8,000	8,000	$103.00
6.44% Series	80,000	80,000	8,000	8,000	$102.92
7.84% Series	100,000	100,000	10,000	10,000	$103.78
7.36% Series	100,000	100,000	10,000	10,000	$103.36
Cumulative, $25 par value:
8.00% Series	1,480,000	1,480,000	37,000	37,000	$25.00
Total without sinking fund	2,115,000	2,115,000	$100,500	$100,500

	Shares Authorized and Outstanding		Dollars (In Thousands)		Call Price Per Share as of December 31,
	2004	2003	2004	2003	2004
Entergy Mississippi Preferred Stock
Without sinking fund:
Cumulative, $100 par value:
4.36% Series	59,920	59,920	$5,992	$5,992	$103.86
4.56% Series	43,887	43,887	4,389	4,389	$107.00
4.92% Series	100,000	100,000	10,000	10,000	$102.88
7.44% Series	100,000	100,000	10,000	10,000	$102.81
8.36% Series	200,000	200,000	20,000	20,000	$100.00
Total without sinking fund	503,807	503,807	$50,381	$50,381

	Shares Authorized and Outstanding		Dollars (In Thousands)		Call Price Per Share as of December 31,
	2004	2003	2004	2003	2004
Entergy New Orleans Preferred Stock
Without sinking fund:
Cumulative, $100 par value:
4.75% Series	77,798	77,798	$7,780	$7,780	$105.00
4.36% Series	60,000	60,000	6,000	6,000	$104.58
5.56% Series	60,000	60,000	6,000	6,000	$102.59
Total without sinking fund	197,798	197,798	$19,780	$19,780

(a)	The total dollar value represents the liquidation value of $25 per share.
(b)	Represents weighted-average annualized rates for 2004 and 2003.
(c)	Fair values were determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. There is an additional disclosure of fair value of financial instruments in Note 11 to the domestic utility companies and System Energy financial statements.

Entergy Gulf States' preferred stock with sinking fund retirements were 34,500 shares in 2004 and 2003, and 18,579 shares in 2002.

Entergy Gulf States has annual sinking fund requirements of $3.45 million through 2009 for its preferred stock outstanding. Entergy Gulf States has the annual non-cumulative option to redeem, at par, additional amounts of certain series of its outstanding preferred stock.

NOTE 7. COMMON EQUITY (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans

Dividend Restrictions

Provisions within the Articles of Incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of the domestic utility companies and System Energy restrict the payment of cash dividends or other distributions on their common and preferred stock. Additionally, PUHCA prohibits Entergy Corporation's subsidiaries from making loans or advances to Entergy Corporation. As of December 31, 2004, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively.

NOTE 8. COMMITMENTS AND CONTINGENCIES

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

Vidalia Purchased Power Agreement (Entergy Louisiana)

Entergy Louisiana has an agreement extending through the year 2031 to purchase energy generated by a hydroelectric facility known as the Vidalia project. Entergy Louisiana made payments under the contract of approximately $147.7 million in 2004, $112.6 million in 2003, and $104.2 million in 2002. If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $125.3 million in 2005, and a total of $3.5 billion for the years 2006 through 2031. Entergy Louisiana currently recovers the costs of the purchased energy through its fuel adjustment clause. In an LPSC-approved settlement related to tax benefits from the tax treatment of the Vidalia contract, Entergy Louisiana agreed to credit rates by $11 million each year for up to ten years, beginning in October 2002.  The provisions of the settlement also provide that the LPSC shall not recognize or use Entergy Louisiana's use of the cash benefits from the tax treatment in setting any of Entergy Louisiana's rates.  Therefore, to the extent Entergy Louisiana's use of the proceeds would ordinarily have reduced its rate base, no change in rate base shall be reflected for ratemaking purposes.

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

The domestic utility companies that are owners of System Fuels have made loans to System Fuels to finance its fuel procurement, delivery, and storage activities. The following loans outstanding to System Fuels as of December 31, 2004 mature in 2008:

Owner	Ownership Percentage	Loan Outstanding at December 31, 2004
Entergy Arkansas	35%	$11.0 million
Entergy Louisiana	33%	$14.2 million
Entergy Mississippi	19%	$5.5 million
Entergy New Orleans	13%	$3.3 million

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

Third Party Liability Insurance

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

1.

The primary level is private insurance underwritten by American Nuclear Insurers and provides liability insurance coverage of $300 million. If this amount is not sufficient to cover claims arising from the accident, the second level, Secondary Financial Protection, applies. An industry-wide aggregate limitation of $300 million exists for domestically-sponsored terrorist acts. There is no limitation for foreign-sponsored terrorist acts.

2.

Within the Secondary Financial Protection level, each nuclear plant must pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary level, up to a maximum of $100.6 million per reactor per incident. This consists of a $95.8 million maximum retrospective premium plus a five percent surcharge that may be applied, if needed, at a rate that is presently set at $10 million per year per nuclear power reactor. There are no domestically- or foreign-sponsored terrorism limitations.

Currently, 104 nuclear reactors are participating in the Secondary Financial Protection program - 103 operating reactors and one closed reactor that still stores used nuclear fuel on site. The product of the maximum retrospective premium assessment to the nuclear power industry and the number of nuclear power reactors provides over $10 billion in insurance coverage to compensate the public in the event of a nuclear power reactor accident.

Entergy Arkansas has two licensed reactors and Entergy Gulf States, Entergy Louisiana, and System Energy each have one licensed reactor (10% of Grand Gulf is owned by a non-affiliated company (SMEPA), which would share on a pro-rata basis in any retrospective premium assessment under the Price-Anderson Act).

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

Property Insurance

Entergy's nuclear owner/licensee subsidiaries are members of certain mutual insurance companies that provide property damage coverage, including decontamination and premature decommissioning expense, to the members' nuclear generating plants. These programs are underwritten by Nuclear Electric Insurance Limited (NEIL). As of December 31, 2004, the domestic utility companies and System Energy were insured against such losses per the following structures:

ANO 1 and 2, Grand Gulf, River Bend, and Waterford 3

• Primary Layer (per plant) - $500 million per occurrence
• Excess Layer (per plant) - $100 million per occurrence
• Blanket Layer (shared among all plants) - $1.0 billion per occurrence
• Total limit - $1.6 billion per occurrence
• Deductibles:

• $5.0 million per occurrence - Turbine/generator damage
• $5.0 million per occurrence - Other than turbine/generator damage

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

In addition, Waterford 3 and Grand Gulf are also covered under NEIL's Accidental Outage Coverage program. This coverage provides certain fixed indemnities in the event of an unplanned outage that results from a covered NEIL property damage loss, subject to a deductible. The following summarizes this coverage as of December 31, 2003:

Waterford 3

• $2.95 million weekly indemnity
• $413 million maximum indemnity
• Deductible: 26 week waiting period

Grand Gulf

• $100,000 weekly indemnity
• $14 million maximum indemnity
• Deductible: 26 week waiting period

Under the property damage and accidental outage insurance programs, Entergy's nuclear plants could be subject to assessments should losses exceed the accumulated funds available from NEIL. As of December 31, 2004, the maximum amount of such possible assessments per occurrence were $15.1 million for Entergy Arkansas, $11.1 million for Entergy Gulf States, $13.0 million for Entergy Louisiana, $0.06 million for Entergy Mississippi, $0.06 million for Entergy New Orleans, and $11.5 million for System Energy.

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

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

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

SFAS 143, "Accounting for Asset Retirement Obligations," which was implemented effective January 1, 2003, requires the recording of liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of those assets.

These liabilities are recorded at their fair values (which is the present values of the estimated future cash outflows) in the period in which they are incurred, with an accompanying addition to the recorded cost of the long-lived asset. The asset retirement obligation is accreted each year through a charge to expense, to reflect the time value of money for this present value obligation. The amounts added to the carrying amounts of the long-lived assets are depreciated over the useful lives of the assets. The net effect of implementing this standard for the rate-regulated business of the domestic utility companies and System Energy was recorded as a regulatory asset, with no resulting impact on Entergy's net income. Entergy recorded these regulatory assets because existing rate mechanisms in each jurisdiction are based on the principle that Entergy will recover all ultimate costs of decommissioning from customers. As a result of this treatment, SFAS 143 is expected to be earnings neut ral to the rate-regulated business of the domestic utility companies and System Energy.

Upon implementation of SFAS 143 in 2003, assets and liabilities increased $1.1 billion for the U.S. Utility segment as a result of recording the asset retirement obligations at their fair values of $1.1 billion as determined under SFAS 143, increasing utility plant by $287 million, reducing accumulated depreciation by $361 million and recording the related regulatory assets of $422 million. The implementation of SFAS 143 for the portion of River Bend not subject to cost-based ratemaking decreased earnings in the first quarter of 2003 by $21 million net-of-tax as a result of a cumulative effect of accounting change. In accordance with ratemaking treatment and as required by SFAS 71, the depreciation provisions for the domestic utility companies and System Energy include a component for removal costs that are not asset retirement obligations under SFAS 143. In accordance with regulatory accounting principles, the domestic utility companies and System Energy have recorded regulatory as sets (liabilities) in the following amounts to reflect their estimates of the difference between estimated incurred removal costs and estimated removal costs recovered in rates previously recorded as a component of accumulated depreciation:

	December 31,
	2004	2003
	(In Millions)
Entergy Arkansas	$34.9	$26.6
Entergy Gulf States	$0.9	$4.2
Entergy Louisiana	($34.6)	($26.8)
Entergy Mississippi	$32.7	$24.4
Entergy New Orleans	$1.3	$2.1
System Energy	$17.1	$15.1

The cumulative decommissioning liabilities and expenses recorded in 2004 by Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy were as follows:

	Liabilities as of December 31, 2003	Accretion	Change in Cash Flow Estimate	Liabilities as of December 31, 2004
	(In Thousands)
ANO 1 and ANO 2	$567.5	$32.9	($107.7)		$492.7
River Bend	$298.8	$19.7	($166.4)		$152.1
Waterford 3	$325.3	$22.0	-		$347.3
Grand Gulf	$312.5	$23.4	-		$335.9

Entergy periodically reviews and updates estimated decommissioning costs. The actual decommissioning costs may vary from the estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment.

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

In the third quarter of 2004, Entergy Gulf States recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for River Bend that reflected an expected life extension for the plant. The revised estimate resulted in a $166.4 million reduction in decommissioning liability, along with a $31.3 million reduction in utility plant, a $49.6 million reduction in non-utility property, a $40.1 million reduction in the related regulatory asset, and a regulatory liability of $17.7 million. For the portion of River Bend not subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous other income of $27.7 million.

If SFAS 143 had been applied by Entergy Gulf States for the portion of River Bend not subject to cost-based ratemaking during prior periods, the following impacts would have resulted:

	Year Ended December 31, 2002
Entergy Gulf States
Earnings applicable to common stock - as reported	$169,190
Pro forma effect of SFAS 143	($2,227)
Earnings applicable to common stock - pro forma	$166,963

Entergy maintains decommissioning trust funds that are committed to meeting the costs of decommissioning the nuclear power plants. The fair values of the decommissioning trust funds and asset retirement obligation-related regulatory assets of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy as of December 31, 2004 are as follows:

	Decommissioning Trust Fair Values	Regulatory Assets
	(In Millions)
ANO 1 & ANO 2	$383.8	$141.2
River Bend	$291.0	-
Waterford 3	$172.1	$141.6
Grand Gulf	$205.1	$97.3

The Energy Policy Act of 1992 contains a provision that assesses domestic nuclear utilities with fees for the decontamination and decommissioning (D&D) of the DOE's past uranium enrichment operations. Annual assessments in 2004 were $4.4 million for Entergy Arkansas, $1.1 million for Entergy Gulf States, $1.6 million for Entergy Louisiana, and $1.8 million for System Energy 2004. The Energy Policy Act calls for cessation of annual D&D assessments not later than October 24, 2007. At December 31, 2004, two years of assessments were remaining. D&D fees are included in other current liabilities and other non-current liabilities and, as of December 31, 2004, recorded liabilities were $8.8 million for Entergy Arkansas, $1.9 million for Entergy Gulf States, $3.3 million for Entergy Louisiana, and $3.3 million for System Energy. Regulatory assets in the financial statements offset these liabilities, with the exception of Entergy Gulf States' 30% non-regulated portion. These a ssessments are recovered through rates in the same manner as fuel costs.

Income Taxes

Entergy is currently under audit by the IRS with respect to tax returns for tax periods subsequent to 1995 and through 2001, and is subject to audit by the IRS and other taxing authorities for subsequent tax periods.  The amount and timing of any tax assessments resulting from these audits are uncertain, and could have a material effect on Entergy's financial position and results of operations.  Entergy believes that the contingency provisions established in its financial statements will sufficiently cover the risk associated with tax matters.  Certain material audit matters as to which management believes there is a reasonable possibility of a future tax assessment are discussed below.  See Note 3 to the domestic utility companies and System Energy financial statements for additional discussion of income taxes.

Depreciable Property Lives

During the years 1997 through 2004, Entergy subsidiaries, Entergy Services, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy Resources reflected changes in tax depreciation methods with respect to certain types of depreciable property (e.g. street lighting, billing meters, and various generation plant equipment). As of December 31, 2004, the cumulative effect of these changes results in additional depreciation deductions generating a cash flow benefit of $45 million for Entergy Arkansas, $38 million for Entergy Gulf States, $32 million for Entergy Louisiana, $19 million for Entergy Mississippi, $6 million for Entergy New Orleans, and $12 million for System Energy. As of December 31, 2004, the related IRS interest exposure if the deduction is ultimately disallowed is $13 million for Entergy Arkansas, $11 million for Entergy Gulf States, $9 million for Entergy Louisiana, $6 million for Entergy Mississippi, $2 million for Entergy New Orleans, and $3 million for System Energy. This benefit reverses over time and will also fluctuate with each year's addition to those types of assets. Due to the temporary nature of the tax benefit, the potential interest charge represents the total net exposure of the domestic utility companies and System Energy.

For the years under audit, 1996-2001, the IRS challenged Entergy's classification of these assets and proposed adjustments to the depreciation deductions taken. Entergy disagrees with the position of the IRS and has protested the disallowance of these deductions to the Office of IRS Appeals. Entergy expects to receive a Notice of Deficiency in 2005 for this item, and plans to vigorously contest this matter. Entergy believes that the contingency provision established in its financial statements sufficiently covers the risk associated with this item.

Mark to Market of Certain Power Contracts

In 2001, Entergy Louisiana changed its method of accounting for tax purposes related to its wholesale electric power contracts.  The most significant of these is the contract to purchase power from the Vidalia hydroelectric project.  The new tax accounting method has provided a cumulative cash flow benefit of approximately $790 million as of December 31, 2004.  The related IRS interest exposure is $93 million at December 31, 2004.   This benefit 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.  Due to the temporary nature of the tax benefit, the potential interest charge represents Entergy's net earnings exposure.  Entergy Louisiana's 2001 tax return is currently under examination by the IRS, though no adjustments have yet been proposed with respect to the mark to market election.  Entergy believes that the contingency provision established in its financial statements will sufficiently cover the risk associated with this issue.

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

In 2003 the domestic utility companies entered an agreement with CashPoint Network Services (CashPoint) under which CashPoint was to manage a network of payment agents through which Entergy's utility customers could pay their bills. The payment agent system allows customers to pay their bills at various commercial or governmental locations, rather than sending payments by mail. Approximately one-third of Entergy's utility customers use payment agents.

On April 19, 2004, CashPoint failed to pay funds due to the domestic utility companies that had been collected through payment agents. The domestic utility companies then obtained a temporary restraining order from the Civil District Court for the Parish of Orleans, State of Louisiana, enjoining CashPoint from distributing funds belonging to Entergy, except by paying those funds to Entergy. On April 22, 2004, a petition for involuntary Chapter 7 bankruptcy was filed against CashPoint by other creditors in the United States Bankruptcy Court for the Southern District of New York. In response to these events, the domestic utility companies expanded an existing contract with another company to manage all of their payment agents. The domestic utility companies filed proofs of claim in the CashPoint bankruptcy proceeding in September 2004. Although Entergy cannot precisely determine at this time the amount that CashPoint owes to the domestic utility companies that may not be repaid, it has accrued an estim ate of loss based on current information. If no cash is repaid to the domestic utility companies, an event Entergy does not believe is likely, the current estimates of maximum exposure to loss are approximately as follows:

	Amount
	(In Millions)
Entergy Arkansas	$1.8
Entergy Gulf States	$7.7
Entergy Louisiana	$8.8
Entergy Mississippi	$4.3
Entergy New Orleans	$2.4

Environmental Issues (Entergy Gulf States)

Entergy Gulf States has been designated as a PRP for the cleanup of certain hazardous waste disposal sites. As of December 31, 2004, Entergy Gulf States does not expect the remaining clean-up costs to exceed its recorded liability of $1.5 million for the remaining sites at which the EPA has designated Entergy Gulf States as a PRP.

City Franchise Ordinances (Entergy New Orleans)

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

Waterford 3 Lease Obligations (Entergy Louisiana)

On September 28, 1989, Entergy Louisiana entered into three identical transactions for the sale and leaseback of undivided interests (aggregating approximately 9.3%) in Waterford 3. In July 1997, Entergy Louisiana caused the lessors to issue $307.6 million aggregate principal amount of Waterford 3 Secured Lease Obligation Bonds, 8.09% Series due 2017, to refinance the outstanding bonds originally issued to finance the purchase of the undivided interests by the lessors. The lease payments were reduced to reflect the lower interest costs. Upon the occurrence of certain events, Entergy Louisiana may be obligated to pay amounts sufficient to permit the termination of the lease transactions and may be required to assume the outstanding bonds issued to finance, in part, the lessors' acquisition of the undivided interests in Waterford 3.

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

Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy New Orleans, System Energy, or their affiliates, are defendants in numerous lawsuits filed by former employees asserting that they were wrongfully terminated and/or discriminated against on the basis of age, race, sex, and/or other protected characteristics. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, System Energy, and their affiliates are vigorously defending these suits and deny any liability to the plaintiffs. Nevertheless, no assurance can be given as to the outcome of these cases.

Asbestos and Hazardous Material Litigation (Entergy Gulf States, Entergy Louisiana, Entergy New Orleans)

Numerous lawsuits have been filed in federal and state courts in Texas, Louisiana, and Mississippi primarily by contractor employees in the 1950-1980 timeframe against Entergy Gulf States, Entergy Louisiana, and Entergy New Orleans, and Entergy Mississippi as premises owners of power plants, for damages caused by alleged exposure to asbestos or other hazardous material. Many other defendants are named in these lawsuits as well. Presently, there are approximately 480 lawsuits involving approximately 10,000 claims. Management believes that adequate provisions have been established to cover any exposure. Additionally, negotiations continue with insurers to recover more reimbursement, while new coverage is being secured to minimize anticipated future potential exposures. Management believes that loss exposure has been and will continue to be handled successfully so that the ultimate resolution of these matters will not be material, in the aggregate, to its financial position or result s of operation.

Grand Gulf - Related Agreements

Capital Funds Agreement (System Energy)

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

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

System Energy has agreed to sell all of its 90% share of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans in accordance with specified percentages (Entergy Arkansas-36%, Entergy Louisiana-14%, Entergy Mississippi-33%, and Entergy New Orleans-17%) as ordered by FERC. Charges under this agreement are paid in consideration for the purchasing companies' respective entitlement to receive capacity and energy and are payable irrespective of the quantity of energy delivered so long as the unit remains in commercial operation. The agreement will remain in effect until terminated by the parties and the termination is approved by FERC, most likely upon Grand Gulf's retirement from service. Monthly obligations are based on actual capacity and energy costs. The average monthly payments for 2004 under the agreement are approximately $16.6 million for Entergy Arkansas, $6.7 million for Entergy Louisiana, $13.7 million for Ent ergy Mississippi, and $8.1 million for Entergy New Orleans.

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

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans are individually obligated to make payments or subordinated advances to System Energy in accordance with stated percentages (Entergy Arkansas-17.1%, Entergy Louisiana-26.9%, Entergy Mississippi-31.3%, and Entergy New Orleans-24.7%) in amounts that, when added to amounts received under the Unit Power Sales Agreement or otherwise, are adequate to cover all of System Energy's operating expenses as defined, including an amount sufficient to amortize the cost of Grand Gulf 2 over 27 years. (See Reallocation Agreement terms below.) System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Since commercial operation of Grand Gulf 1, payments under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Accordingly, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments.

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

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

Reimbursement Agreement (System Energy)

In December 1988, System Energy entered into two separate, but identical, arrangements for the sale and leaseback of an approximate aggregate 11.5% ownership interest in Grand Gulf. In connection with the equity funding of the sale and leaseback arrangements, letters of credit are required to be maintained to secure certain amounts payable for the benefit of the equity investors by System Energy under the leases. The current letters of credit are effective until May 29, 2009.

Under the provisions of the reimbursement agreement relating to the letters of credit, System Energy has agreed to a number of covenants regarding the maintenance of certain capitalization and fixed charge coverage ratios.  System Energy agreed, during the term of the reimbursement agreement, to maintain a ratio of debt to total liabilities and equity less than or equal to 70%. In addition, System Energy must maintain, with respect to each fiscal quarter during the term of the reimbursement agreement, a ratio of adjusted net income to interest expense of at least 1.50 times earnings.  As of December 31, 2004, System Energy's debt ratio was approximately 32.5%, and its fixed charge coverage ratio for 2004 was approximately 4.12, calculated, in each case, as prescribed in the reimbursement agreement.

NOTE 9. LEASES (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and System Energy)

General

As of December 31, 2004 the domestic utility companies had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities (excluding nuclear fuel leases and the sale and leaseback transactions) with minimum lease payments as follows:

Capital Leases
Year	Entergy Arkansas	Entergy Mississippi
	(In Thousands)
2005	$9,610	$50
2006	5,682	42
2007	3,427	11
2008	1,754	-
2009	237	-
Years thereafter	2,606	-
Minimum lease payments	23,316	103
Less: Amount representing interest	3,386	2
Present value of net minimum lease payments	$19,930	$101

Operating Leases
Year	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi
	(In Thousands)
2005	$23,743	$26,744	$9,974	$7,421
2006	20,029	23,942	5,647	6,596
2007	17,563	17,223	5,109	3,552
2008	14,977	9,742	3,546	3,039
2009	8,622	9,108	2,346	2,676
Years thereafter	54,339	115,216	2,524	11,068
Minimum lease payments	$139,273	$201,975	$29,146	$34,352

Rental Expense
Year	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi
	(In Millions)
2004	$17.4	$24.4	$11.9	$3.4
2003	$19.4	$26.5	$13.8	$5.4
2002	$20.8	$25.8	$13.6	$5.4

In addition to the above rental expense, railcar operating lease payments and oil tank facilities lease payments are recorded in fuel expense in accordance with regulatory treatment. Railcar operating lease payments were $9.3 million in 2004, $6.8 million in 2003, and $8.3 million in 2002 for Entergy Arkansas and $2.0 million in 2004, $1.8 million in 2003, and $2.0 million in 2002 for Entergy Gulf States. Oil tank facilities lease payments for Entergy Mississippi were $3.2 million for 2004 and $3.1 million for each of the years 2003 and 2002.

Nuclear Fuel Leases

As of December 31, 2004, arrangements to lease nuclear fuel existed in an aggregate amount up to $150 million for Entergy Arkansas, $105 million for Entergy Gulf States, $80 million for Entergy Louisiana, and $110 million for System Energy. As of December 31, 2004, the unrecovered cost base of nuclear fuel leases amounted to approximately $93.9 million for Entergy Arkansas, $71.2 million for Entergy Gulf States, $31.7 million for Entergy Louisiana, and $65.6 million for System Energy. The lessors finance the acquisition and ownership of nuclear fuel through loans made under revolving credit agreements, the issuance of commercial paper, and the issuance of intermediate-term notes. The credit agreements for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy each have a termination date of October 30, 2006. The termination dates may be extended from time to time with the consent of the lenders. The intermediate-term notes issued pursuant to these fuel lease a rrangements have varying maturities through February 15, 2009. It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. However, if such additional financing cannot be arranged, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations in accordance with the fuel lease.

Lease payments are based on nuclear fuel use. The table below represents the total nuclear fuel lease payments (principal and interest) as well as the separate interest component charged to operations in 2004, 2003, and 2002:

	2004		2003		2002
	Lease Payments	Interest	Lease Payments	Interest	Lease Payments	Interest
	(In Millions)
Entergy Arkansas	$53.0	$4.3	$49.9	$3.3	$49.6	$3.2
Entergy Gulf States	29.7	3.2	27.8	3.0	29.2	3.0
Entergy Louisiana	36.1	2.5	32.3	2.4	32.9	2.6
System Energy	27.8	2.8	32.0	3.1	26.1	2.5
Total	$146.6	$12.8	$142.0	$11.8	$137.8	$11.3

Sale and Leaseback Transactions

Waterford 3 Lease Obligations (Entergy Louisiana)

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

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

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

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

As of December 31, 2004, Entergy Louisiana's total equity capital (including preferred stock) was 51.33% of adjusted capitalization and its fixed charge coverage ratio for 2004 was 3.76.

As of December 31, 2004, Entergy Louisiana had future minimum lease payments (reflecting an overall implicit rate of 7.45%) in connection with the Waterford 3 sale and leaseback transactions, which are recorded as long-term debt, as follows:

	(In Thousands)
2005	$14,554
2006	18,261
2007	18,754
2008	22,606
2009	32,452
Years thereafter	334,062
Total	440,689
Less: Amount representing interest	192,964
Present value of net minimum lease payments	$247,725

Grand Gulf Lease Obligations (System Energy)

In December 1988, System Energy sold 11.5% of its undivided ownership interest in Grand Gulf for the aggregate sum of $500 million. Subsequently, System Energy leased back its interest in the unit for a term of 26 1/2 years. System Energy has the option of terminating the lease and repurchasing the 11.5% interest in the unit at certain intervals during the lease. Furthermore, at the end of the lease term, System Energy has the option of renewing the lease or repurchasing the 11.5% interest in Grand Gulf.

In May 2004 System Energy caused the Grand Gulf lessors to refinance the outstanding bonds that they had issued to finance the purchase of their undivided interest in Grand Gulf. The refinancing is at a lower interest rate, and System Energy's lease payments have been reduced to reflect the lower interest costs.

System Energy is required to report the sale-leaseback as a financing transaction in its financial statements. For financial reporting purposes, System Energy expenses the interest portion of the lease obligation and the plant depreciation. However, operating revenues include the recovery of the lease payments because the transactions are accounted for as a sale and leaseback for ratemaking purposes. Consistent with a recommendation contained in a FERC audit report, System Energy recorded as a net regulatory asset the difference between the recovery of the lease payments and the amounts expensed for interest and depreciation and is recording this difference as a regulatory asset or liability on an ongoing basis, resulting in a zero net balance at the end of the lease term. The amount of this net regulatory asset was $75.4 million and $83.2 million as of December 31, 2004 and 2003, respectively.

As of December 31, 2004, System Energy had future minimum lease payments (reflecting an implicit rate of 5.01%), which are recorded as long-term debt as follows:

	(In Thousands)
2005	$45,423
2006	46,019
2007	46,552
2008	47,128
2009	47,760
Years thereafter	302,402
Total	535,284
Less: Amount representing interest	138,165
Present value of net minimum lease payments	$397,119

NOTE 10. RETIREMENT AND OTHER POSTRETIREMENT BENEFITS (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

Pension Plans

Entergy's domestic utility companies and System Entergy participate in two of Entergy's pension plans: "Entergy Corporation Retirement Plan for Non-Bargaining Employees" and "Entergy Corporation Retirement Plan for Bargaining Employees." Entergy Corporation and its subsidiaries fund pension costs in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the plans include common and preferred stocks, fixed-income securities, interest in a money market fund, and insurance contracts. As of December 31, 2004 and 2003, Entergy's domestic utility companies and System Energy recognized an additional minimum pension liability for the excess of the accumulated benefit obligation over the fair market value of plan assets. In accordance with SFAS 87, an offsetting intangible asset, up to the amount of any unrecognized prior service cost, was also recorded, with the remaining offset to the liability recorded as a regulatory asset, reflective of the recovery mechanism for pension costs in Entergy's jurisdictions. Entergy's domestic utility companies' and System Energy's pension costs are recovered from customers as a component of cost of service in each of its jurisdictions. Entergy uses a December 31 measurement date for its pension plans.

Components of Net Pension Cost

Total 2004, 2003, and 2002 pension cost of the domestic utility companies and System Energy, including amounts capitalized, included the following components:

2004	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
Service cost - benefits earned   during the period	$11,941	$9,693	$7,009	$3,615	$1,569	$3,386
Interest cost on projected   benefit obligation	35,846	28,471	21,790	11,915	4,465	5,189
Expected return on assets	(36,913)	(39,682)	(27,510)	(14,716)	(2,568)	(4,556)
Amortization of transition asset	-	-	-	-	-	(319)
Amortization of prior service cost	1,662	1,511	650	513	226	67
Recognized net loss	3,952	405	1,344	794	898	788
Net pension cost	$16,488	$398	$3,283	$2,121	$4,590	$4,555

2003	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
Service cost - benefits earned   during the period	$11,156	$8,788	$6,369	$3,411	$1,539	$3,142
Interest cost on projected   benefit obligation	33,009	27,708	20,028	11,339	3,958	4,200
Expected return on assets	(38,712)	(41,784)	(28,919)	(15,434)	(2,616)	(3,944)
Amortization of transition asset	-	-	-	-	-	(319)
Amortization of prior service cost	1,737	1,931	789	584	236	73
Recognized net loss	256	150	-	83	-	27
Curtailment loss	5,305	2,133	2,748	1,065	129	944
Special termination benefits	5,543	2,857	2,619	811	367	1,720
Net pension cost	$18,294	$1,783	$3,634	$1,859	$3,613	$5,843

2002	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
Service cost - benefits earned   during the period	$9,787	$7,391	$5,901	$2,971	$1,414	$2,616
Interest cost on projected   benefit obligation	31,058	27,737	19,747	11,013	4,126	3,735
Expected return on assets	(40,514)	(43,827)	(30,300)	(16,197)	(2,763)	(3,775)
Amortization of transition asset	-	-	-	-	-	(319)
Amortization of prior service cost	1,743	1,923	744	705	269	72
Net pension cost (income)	$2,074	($6,776)	($3,908)	($1,508)	$3,046	$2,329

Pension Obligations, Plan Assets, Funded Status, and Amounts Not Yet Recognized and Recognized in the Balance Sheet as of December 31, 2004 and 2003

2004	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
Change in Projected Benefit
Obligation (PBO)
Balance at 12/31/03	$565,004	$467,707	$340,212	$190,184	$67,866	$79,033
Service cost	11,941	9,693	7,009	3,615	1,569	3,386
Interest cost	35,846	28,471	21,790	11,915	4,465	5,189
Actuarial loss	46,590	17,687	32,309	13,200	8,169	9,175
Benefits paid	(34,565)	(27,348)	(22,218)	(12,771)	(3,719)	(1,784)
Balance at 12/31/04	$624,816	$496,210	$379,102	$206,143	$78,350	$94,999
Change in Plan Assets
Fair value of assets at 12/31/03	$423,214	$448,490	$316,669	$169,958	$29,565	$45,375
Actual return on plan assets	39,265	42,380	31,046	16,268	2,849	8,667
Employer contributions	5,342	17	3,907	1,823	2,118	3,742
Benefits paid	(34,565)	(27,348)	(22,218)	(12,771)	(3,719)	(1,784)
Fair value of assets at 12/31/04	$433,256	$463,539	$329,404	$175,278	$30,813	$56,000
Funded status	($191,560)	($32,671)	($49,698)	($30,865)	($47,537)	($38,999)
Amounts not yet recognized
in the balance sheet
Unrecognized transition asset	-	-	-	-	-	(277)
Unrecognized prior service cost	8,177	5,938	3,762	2,692	1,263	286
Unrecognized net loss	133,821	38,628	75,962	36,825	26,357	20,298
Prepaid/(accrued) pension cost
recognized in the balance sheet	($49,562)	$11,895	$30,026	$8,652	($19,917)	($18,692)
Amounts recognized in
the balance sheet
Prepaid/(accrued) pension liability	($49,562)	$11,895	$30,026	$8,652	($19,917)	($18,692)
Additional minimum pension liability	(81,161)	-	(38,871)	(23,492)	(16,928)	(7,678)
Intangible asset	10,313	-	4,759	3,308	1,698	247
Regulatory asset	70,848	-	34,112	20,184	15,230	7,431
Net amount recognized	($49,562)	$11,895	$30,026	$8,652	($19,917)	($18,692)

2003		Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
Change in Projected Benefit
Obligation (PBO)
Balance at 12/31/02		$476,276	$420,644	$297,144	$167,175	$57,085	$59,418
Service cost		11,156	8,788	6,369	3,411	1,539	3,142
Interest cost		33,009	27,708	20,028	11,339	3,958	4,200
Amendment		121	96	-	5	-	5
Actuarial loss		62,444	31,342	30,844	17,133	7,417	9,984
Benefits paid		(28,445)	(25,611)	(19,332)	(10,634)	(2,559)	(366)
Curtailment loss		4,900	1,883	2,540	944	59	930
Special termination benefits		5,543	2,857	2,619	811	367	1,720
Balance at 12/31/03		$565,004	$467,707	$340,212	$190,184	$67,866	$79,033
Change in Plan Assets
Fair value of assets at 12/31/02		$367,080	$380,999	$261,785	$144,947	$32,384	$34,041
Actual return on plan assets		84,579	93,102	74,216	35,645	(260)	11,700
Benefits paid		(28,445)	(25,611)	(19,332)	(10,634)	(2,559)	(366)
Fair value of assets at 12/31/03		$423,214	$448,490	$316,669	$169,958	$29,565	$45,375
Funded status		($141,790)	($19,217)	($23,543)	($20,226)	($38,301)	($33,658)
Amounts not yet recognized
in the balance sheet
Unrecognized transition asset		-	-	-	-	-	(596)
Unrecognized prior service cost		9,839	7,449	4,412	3,206	1,489	353
Unrecognized net loss		93,535	24,044	48,533	25,970	19,367	16,021
Prepaid/(accrued) pension cost
recognized in the balance sheet		($38,416)	$12,276	$29,402	$8,950	($17,445)	($17,880)
Amounts recognized in
the balance sheet:
Prepaid/(accrued) pension liability		($38,416)	$12,276	$29,402	$8,950	($17,445)	($17,880)
Additional minimum pension liability		(54,948)	-	-	(7,301)	(13,140)	(7,426)
Intangible asset		13,291	-	-	937	2,774	365
Regulatory asset		41,657	-	-	6,364	10,366	7,061
Net amount recognized		($38,416)	$12,276	$29,402	$8,950	($17,445)	($17,880)

Other Postretirement Benefits

The domestic utility companies and System Energy also currently provide health care and life insurance benefits for retired employees. Substantially all employees may become eligible for these benefits if they reach retirement age while still working for Entergy. Entergy uses a December 31 measurement date for its postretirement benefit plans.

Effective January 1, 1993, Entergy adopted SFAS 106, which required a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. At January 1, 1993, the actuarially determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be approximately $241.4 million for Entergy (other than Entergy Gulf States) and $128 million for Entergy Gulf States. Such obligations are being amortized over a 20-year period that began in 1993.

Entergy Arkansas, the portion of Entergy Gulf States regulated by the PUCT, Entergy Mississippi, and Entergy New Orleans have received regulatory approval to recover SFAS 106 costs through rates. Entergy Arkansas began recovery in 1998, pursuant to an APSC order. This order also allowed Entergy Arkansas to amortize a regulatory asset (representing the difference between SFAS 106 costs and cash expenditures for other postretirement benefits incurred for a five-year period that began January 1, 1993) over a 15-year period that began in January 1998.

The LPSC ordered the portion of Entergy Gulf States regulated by the LPSC and Entergy Louisiana to continue the use of the pay-as-you-go method for ratemaking purposes for postretirement benefits other than pensions. However, the LPSC retains the flexibility to examine individual companies' accounting for postretirement benefits to determine if special exceptions to this order are warranted.

Pursuant to regulatory directives, Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, the portion of Entergy Gulf States regulated by the PUCT, and System Energy fund postretirement benefit obligations collected in rates. System Energy is funding, on behalf of Entergy Operations, postretirement benefits associated with Grand Gulf. Entergy Louisiana and Entergy Gulf States continue to recover a portion of these benefits regulated by the LPSC and FERC on a pay-as-you-go basis.

Components of Net Other Postretirement Benefit Cost

Total 2004, 2003, and 2002 other postretirement benefit costs of the domestic utility companies and System Energy, including amounts capitalized and deferred, included the following components:

2004	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
Service cost - benefits earned   during the period	$3,860	$5,328	$2,371	$1,213	$662	$1,389
Interest cost on APBO	10,075	11,050	6,641	3,222	3,204	1,430
Expected return on assets	(6,210)	(4,995)	-	(2,554)	(2,263)	(1,362)
Amortization of transition   obligation	1,068	4,589	1,202	431	2,121	15
Amortization of prior service cost	27	-	98	16	38	(361)
Recognized net loss	3,937	1,620	2,003	1,503	522	358
Net other postretirement benefit   cost	$12,757	$17,592	$12,315	$3,831	$4,284	$1,469

2003	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
Service cost - benefits earned   during the period	$6,560	$5,701	$3,322	$1,866	$948	$1,553
Interest cost on APBO	10,637	11,314	6,780	3,459	3,436	1,352
Expected return on assets	(4,859)	(4,349)	-	(2,186)	(2,010)	(1,088)
Amortization of transition   obligation	3,327	5,307	2,238	1,301	2,449	135
Amortization of prior service cost	143	163	82	51	52	(140)
Recognized net loss	3,497	1,575	1,496	1,160	475	350
Curtailment loss	9,276	6,301	5,041	1,259	996	2,524
Special termination benefits	794	512	452	73	28	284
Net other postretirement benefit   cost	$29,375	$26,524	$19,411	$6,983	$6,374	$4,970

2002	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
Service cost - benefits earned   during the period	$5,429	$4,153	$3,137	$1,513	$889	$1,300
Interest cost on APBO	9,448	9,734	6,242	3,099	3,264	1,150
Expected return on assets	(3,889)	(4,232)	-	(2,088)	(1,959)	(1,023)
Amortization of transition   obligation	3,954	5,803	2,971	1,502	2,678	220
Amortization of prior service cost	245	278	141	87	89	24
Recognized net (gain)/loss	873	135	75	335	(55)	11
Net other postretirement benefit   cost	$16,060	$15,871	$12,566	$4,448	$4,906	$1,682

Other Postretirement Benefit Obligations, Plan Assets, Funded Status, and Amounts Not Yet Recognized and Recognized in the Balance Sheet as of December 31, 2004 and 2003:

2004	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
Change in APBO
Balance at 12/31/03	$187,259	$194,205	$112,675	$57,786	$55,062	$25,466
Service cost	3,860	5,328	2,371	1,213	662	1,389
Interest cost	10,075	11,050	6,641	3,222	3,204	1,430
Actuarial loss	10,714	9,086	8,175	6,787	3,624	1,441
Benefits paid	(15,964)	(13,832)	(9,843)	(5,307)	(5,967)	(1,719)
Plan amendments (a)	(18,279)	(6,406)	(5,546)	(6,894)	(2,582)	(1,125)
Plan participant contributions	1,693	1,833	1,323	771	846	20
Balance at 12/31/04	179,358	201,264	115,796	57,578	54,849	26,902
Change in Plan Assets
Fair value of assets at 12/31/03	$68,876	$59,511	$-	$28,932	$33,158	$16,821
Actual return on plan assets	5,657	4,773	-	2,154	2,340	1,495
Employer contributions	16,729	14,540	8,520	5,521	4,870	4,691
Plan participant contributions	1,693	1,833	1,323	771	846	20
Benefits paid	(15,964)	(13,832)	(9,843)	(5,307)	(5,967)	(1,719)
Fair value of assets at 12/31/04	$76,991	$66,825	$-	$32,071	$35,247	$21,308
Funded status	($102,367)	($134,439)	($115,796)	($25,507)	($19,602)	($5,594)
Amounts not yet recognized
in the balance sheet
Unrecognized transition obligation	6,567	30,310	3,057	2,810	13,929	119
Unrecognized prior service cost	(4,013)	-	919	(1,015)	418	(2,805)
Unrecognized net loss	79,185	57,089	44,723	28,429	15,620	9,699
Prepaid/(accrued) postretirement benefit cost recognized in the balance sheet	($20,628)	($47,040)	($67,097)	$4,717	$10,365	$1,419

(a) Reflects plan design changes, including a change in participation assumption for certain bargaining employees at Entergy Arkansas and Entergy Mississippi, effective January 1, 2004.

2003	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
Change in APBO
Balance at 12/31/02	$164,258	$167,678	$107,398	$53,398	$54,646	$21,410
Service cost	6,560	5,701	3,322	1,866	948	1,553
Interest cost	10,637	11,314	6,780	3,459	3,436	1,352
Actuarial loss	20,340	24,731	13,445	6,004	4,536	3,104
Benefits paid	(11,523)	(11,411)	(7,816)	(4,040)	(4,761)	(616)
Plan amendments (a)	(14,561)	(11,479)	(16,862)	(4,659)	(5,146)	(4,260)
Plan participant contributions	1,905	1,663	1,126	604	750	78
Curtailment loss	8,849	5,496	4,830	1,081	625	2,561
Special termination benefits	794	512	452	73	28	284
Balance at 12/31/03	$187,259	$194,205	$112,675	$57,786	$55,062	$25,466
Change in Plan Assets
Fair value of assets at 12/31/02	$49,076	$50,001	$-	$23,420	$28,490	$13,569
Actual return on plan assets	6,290	6,587	-	2,979	2,614	1,475
Benefits paid	(11,523)	(11,411)	(7,816)	(4,040)	(4,761)	(616)
Employer contributions	23,128	12,671	6,690	5,969	6,065	2,315
Plan participant contributions	1,905	1,663	1,126	604	750	78
Fair value of assets at 12/31/03	$68,876	$59,511	$-	$28,932	$33,158	$16,821
Funded status	($118,383)	($134,694)	($112,675)	($28,854)	($21,904)	($8,645)
Amounts not yet recognized
in the balance sheet
Unrecognized transition obligation	21,928	41,305	10,822	9,136	19,088	134
Unrecognized prior service cost	-	-	-	-	-	(2,040)
Unrecognized net loss	71,855	49,401	38,551	22,745	12,595	8,748
Prepaid/(accrued) postretirement
benefit cost recognized in the
balance sheet	($24,600)	($43,988)	($63,302)	$3,027	$9,779	($1,803)

(a) Reflects plan design changes, including a change in the participation assumption for non-bargaining employees effective August 1, 2003.

Pension and Other Postretirement Plans' Assets

Entergy's pension and postretirement plans weighted-average asset allocations by asset category at December 31, 2004 and 2003 are as follows:

	Pension		Postretirement
	2004	2003	2004	2003
Domestic Equity Securities	46%	56%	38%	37%
International Equity Securities	21%	14%	14%	0%
Fixed Income Securities	31%	28%	47%	60%
Other	2%	2%	1%	3%

Entergy's trust asset investment strategy is to invest the assets in a manner whereby long-term earnings on the assets (plus cash contributions) provide adequate funding for retiree benefit payments. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense.

In the optimization study, Entergy formulates assumptions (or hires a consultant to provide such analysis) about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes. The future market assumptions used in the optimization study are determined by examining historical market characteristics of the various asset classes, and making adjustments to reflect future conditions expected to prevail over the study period.

The optimization analysis utilized in Entergy's latest study produced the following approved asset class target allocations.

	Pension	Postretirement
Domestic Equity Securities	45%	37%
International Equity Securities	20%	14%
Fixed Income Securities	31%	49%
Other (Cash and GACs)	4%	0%

These allocation percentages combined with each asset class' expected investment return produced an aggregate return expectation for the five years following the study of 7.6% for pension assets, 5.4% for taxable postretirement assets, and 7.2% for non-taxable postretirement assets. These returns are not inconsistent with Entergy's disclosed expected pre-tax return on assets of 8.5% over the life of the respective liabilities.

Since precise allocation targets are inefficient to manage security investments, the following ranges were established to produce an acceptable economically efficient plan to manage to targets:

	Pension	Postretirement
Domestic Equity Securities	45% to 55%	32% to 42%
International Equity Securities	15% to 25%	9% to 19%
Fixed Income Securities	25% to 35%	44% to 54%
Other	0% to 10%	0% to 5%

Accumulated Pension Benefit Obligation

The accumulated benefit obligation for the domestic utility companies and System Entergy as December 31, 2004 and 2003 was:

	December 31,
	2004	2003
	(In Thousands)
Entergy Arkansas	$558,283	$509,382
Entergy Gulf States	$449,986	$426,320
Entergy Louisiana	$341,681	$309,066
Entergy Mississippi	$189,119	$174,245
Entergy New Orleans	$69,202	$59,610
System Energy	$79,641	$64,661

Estimated Future Benefit Payments

Based upon the assumptions used to measure the company's pension and postretirement benefit obligation at December 31, 2004, and including pension and postretirement benefits attributable to estimated future employee service, Entergy expects that benefits to be paid over the next ten years will be as follows:

Estimated Future Pension Benefits Payments	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
Year(s)
2005	$34,240	$26,852	$21,707	$12,630	$3,634	$1,764
2006	$34,660	$27,037	$21,790	$12,771	$3,648	$1,783
2007	$35,332	$27,358	$21,956	$13,000	$3,676	$1,814
2008	$36,266	$27,885	$22,290	$13,326	$3,731	$1,859
2009	$37,674	$28,718	$22,840	$13,821	$3,823	$1,927
2010 - 2014	$227,605	$167,679	$130,644	$82,964	$21,870	$11,552

Estimated Future Other Postretirement Benefits Payments	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
Year(s)
2005	$13,588	$12,638	$8,528	$4,127	$4,565	$1,311
2006	$12,989	$12,280	$8,182	$3,849	$4,162	$1,390
2007	$13,362	$12,901	$8,402	$3,993	$4,268	$1,464
2008	$13,500	$13,381	$8,545	$4,095	$4,353	$1,522
2009	$13,707	$13,808	$8,642	$4,133	$4,443	$1,620
2010 - 2014	$67,855	$74,755	$43,297	$22,011	$21,774	$9,788

Contributions

The domestic utility companies and System Energy expect to contribute the following to the pension and other postretirement plans in 2005:

	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
Pension Contributions	$20,560	$18,948	$2,622	$3,416	$15,667	$9,266
Other Postretirement   Contributions	$16,063	$14,317	$8,528	$4,159	$4,436	$1,732

Additional Information

The change in the minimum pension liability had no effect on other comprehensive income at the domestic utility companies and System Energy in 2004 or 2003. The change in the minimum pension liability included in regulatory assets at each of the domestic utility companies and System Energy was as follows for 2004 and 2003:

	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
2004	$29,191	$-	$34,112	$13,820	$4,865	$370
2003	$22,600	$-	($38,755)	($3,446)	$7,395	$7,061

Actuarial Assumptions

The assumed health care cost trend rate used in measuring the APBO of the domestic utility companies and System Energy was 10% for 2005, gradually decreasing each successive year until it reaches 4.5% in 2011 and beyond. The assumed health care cost trend rate used in measuring the Net Other Postretirement Benefit Cost of the domestic utility companies and System Energy was 10% for 2004, gradually decreasing each successive year until it reaches 4.5% in 2010 and beyond. A one percentage point change in the assumed health care cost trend rate for 2004 would have the following effects:

	1 Percentage Point Increase		1 Percentage Point Decrease
2004	Impact on the APBO	Impact on the sum of service costs and interest cost	Impact on the APBO	Impact on the sum of service costs and interest cost
	Increase (Decrease) (In Thousands)
Entergy Arkansas	$14,980	$1,548	($13,825)	($1,378)
Entergy Gulf States	$19,685	$2,205	($17,932)	($1,918)
Entergy Louisiana	$9,930	$1,021	($9,146)	($907)
Entergy Mississippi	$4,785	$479	($4,418)	($428)
Entergy New Orleans	$3,998	$362	($3,726)	($327)
System Energy	$3,152	$448	($2,821)	($384)

The significant actuarial assumptions used in determining the pension PBO and the SFAS 106 APBO for 2004, 2003, and 2002 were as follows:

	2004	2003	2002
Weighted-average discount rate:
Pension	6.00%	6.25%	6.75%
Other postretirement	6.00%	6.71%	6.75%
Weighted-average rate of increase   in future compensation levels	3.25%	3.25%	3.25%
Expected long-term rate of   return on plan assets:
Taxable assets	5.50%	5.50%	5.50%
Non-taxable assets	8.50%	8.75%	8.75%

The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2004, 2003, and 2002 were as follows:

	2004	2003	2002
Weighted-average discount rate
Pension	6.25%	6.75%	7.50%
Other postretirement	6.71%	6.75%	7.50%
Weighted-average rate of increase   in future compensation levels	3.25%	3.25%	4.60%
Expected long-term rate of   return on plan assets:
Taxable assets	5.50%	5.50%	5.50%
Non-taxable assets	8.75%	8.75%	9.00%

The domestic utility companies' and System Energy's remaining pension transition assets are being amortized over the greater of the remaining service period of active participants or 15 years ending in 2005, and their SFAS 106 transition obligations are being amortized over 20 years ending in 2012.

Voluntary Severance Program

In the second half of 2003, the domestic utility companies and System Energy offered a voluntary severance program to certain groups of employees. As a result of this program, in the fourth quarter 2003 the domestic utility companies and System Energy recorded additional pension and postretirement costs (including amounts capitalized) of $53.9 million for special termination benefits and plan curtailment charges. These amounts are included in the net pension cost and net postretirement benefit cost for the year ended December 31, 2003.

Medicare Prescription Drug, Improvement and Modernization Act of 2003

In December 2003, the President signed the Medicare Prescription Drug, Improvement and Modernization Act of 2003 into law. The Act introduces a prescription drug benefit under Medicare (Part D), starting in 2006, 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. At December 2003, specific authoritative guidance on the accounting for the federal subsidy was pending. As allowed by Financial Accounting Standards Board Staff Position No. FAS 106-1, Entergy elected to record an estimate of the effects of the Act in accounting for its postretirement benefit plans at December 31, 2003, under SFAS 106 and in providing disclosures required by SFAS No. 132 (revised 2003), Employers' Disclosures about Pensions and Other Postretirement Benefits. At December 31, 2003, based on actuarial analysis of prescription drug benefits, estimated future Medicare subsidies were expected to reduce the Dec ember 31, 2003 Accumulated Postretirement Benefit Obligation by $56 million. For the year ended December 31, 2003 the impact of the Act on net postretirement benefit cost was immaterial, as it reflected only one month's impact of the Act.

In 2004, Entergy continued to record the expected effects of the Act in accounting for its postretirement benefit plans. In mid-2004, the Financial Accounting Standards Board issued Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which was effective for Entergy's June 30, 2004 interim reporting.

In August 2004, the Centers for Medicare and Medicaid Services issued proposed regulations to implement the new Medicare law. A ruling from the Centers for Medicare and Medicaid Services was issued in late January 2005 with final guidance expected later this year.

The actuarially estimated effect of future Medicare subsidies was as follows:

	Entergy	Entergy	Entergy	Entergy	Entergy	System
	Arkansas	Gulf States	Louisiana	Mississippi	New Orleans	Energy
	Increase (Decrease) (In Thousands)
Impact on 12/31/2003 APBO	($28,824)	($25,603)	($16,194)	($9,888)	($8,035)	($3,811)
Impact on 12/31/2004 APBO	($35,928)	($31,846)	($20,085)	($12,227)	($9,742)	($4,982)
Impact on 2004 other postretirement benefit cost	($4,999)	($4,405)	($2,752)	($1,657)	($1,248)	($815)

NOTE 11. RISK MANAGEMENT AND DERIVATIVES

Market and Commodity Risks

In the normal course of business, the domestic utility companies and System Energy are exposed to a number of market and commodity risks including power price risk, fuel price risk, foreign currency exchange rate risk, and equity price and interest rate risks. Market risk is the potential loss that the domestic utility companies and System Energy may incur as a result of changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.

The domestic utility companies and System Energy manage these risks through both contractual arrangements and derivatives. Contractual risk management tools include long-term power and fuel purchase agreements. The domestic utility companies and System Energy also use a variety of commodity and financial derivatives, including natural gas and electricity futures, forwards and options, and foreign currency forwards to manage the following risks:

• power price risk resulting from Entergy's short position during the summer months;
• fuel price risk for spot market gas purchases; and
• foreign currency exchange rate risk resulting from Euro-denominated nuclear fuel acquisition contracts.

Gains and losses realized from derivative transactions used to manage power and fuel price risk are included in fuel costs recovered through rates. Accordingly, these gains and losses are accounted for as regulatory assets and liabilities prior to transaction maturity. Power price risk is managed primarily through the purchase of short-term forward contracts that are accounted for as normal purchases. Any option premiums paid to manage power price risk are booked with an offsetting regulatory asset or liability. The volume of these purchases is based on Entergy's demand forecast.

Entergy manages fuel price risk for its Louisiana jurisdictions (Entergy Louisiana, Entergy New Orleans, and the Louisiana portion of Entergy Gulf States) and Entergy Mississippi primarily through the purchase of short-term swaps. These swaps are marked-to-market with offsetting regulatory assets or liabilities. The notional volumes of these swaps are based on a portion of projected purchases of gas for the summer (electric generation) and winter (gas distribution at Entergy Gulf States and Entergy New Orleans) peak seasons.

Entergy Gulf States manages foreign currency exchange rate risk associated with the acquisition of nuclear fuel through the purchase of forwards that are accounted for as cash flow hedges. The notional volumes of these forwards are based on forecasted purchases and the realized gain or loss from these forwards is included in the capitalized cost of the applicable batches of nuclear fuel. Gains totaling approximately $6.4 million were realized during 2004 on the maturity of cash flow hedges. These realized gains resulted from foreign currency hedges related to Euro-denominated nuclear fuel acquisition contracts, and related gains or losses, when realized, are included in the capitalized cost of nuclear fuel. The ineffective portion of the change in the value of Entergy Gulf States' cash flow hedges during 2004 was insignificant. Entergy Gulf States has no outstanding cash flow hedges as of December 31, 2004.

NOTE 12. DECOMMISSIONING TRUST FUNDS

Entergy Arkansas

Entergy Arkansas holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held at December 31, 2004 and 2003 are summarized as follows:

2004	Fair Value	Total Unrealized Gains	Total Unrealized Losses
	(In Millions)
Equity	$189.5	$66.6	$1.6
Debt Securities	194.3	4.3	1.9
Total	$383.8	$70.9	$3.5
2003
Equity	$168.3	$47.2	$-
Debt Securities	192.2	7.0	1.2
Total	$360.5	$54.2	$1.2

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows at December 31, 2004:

	Equity Securities		Debt Securities
	Fair Value	Gross Unrealized Losses	Fair Value	Gross Unrealized Losses
	(In Millions)
Less than 12 months	$0.7	$-	$87.4	$1.6
More than 12 months	12.2	1.6	12.2	0.3
Total	$12.9	$1.6	$99.6	$1.9

The fair value of debt securities, summarized by contractual maturities, at December 31, 2004 is as follows:

	Fair Value
	(In Millions)
less than 1 year	$32.5
1 year - 5 years	128.3
5 years - 10 years	30.2
10 years - 15 years	3.3
15 years - 20 years	-
20 years+	-
Total	$194.3

During the year ended December 31, 2004, the proceeds from the dispositions of securities amounted to $1.7 million with gross gains of $17,098 and gross losses of $18,274.

Entergy Gulf States

Entergy Gulf States holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held at December 31, 2004 and 2003 are summarized as follows:

2004	Fair Value	Total Unrealized Gains	Total Unrealized Losses
	(In Millions)
Equity	$138.1	$20.4	$0.8
Debt Securities	152.9	8.8	0.2
Total	$291.0	$29.2	$1.0
2003
Equity	$119.4	$8.0	$0.2
Debt Securities	148.5	10.4	1.0
Total	$267.9	$18.4	$1.2

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows at December 31, 2004:

	Equity Securities		Debt Securities
	Fair Value	Gross Unrealized Losses	Fair Value	Gross Unrealized Losses
	(In Millions)
Less than 12 months	$0.6	$-	$10.0	$0.1
More than 12 months	10.5	0.8	2.3	0.1
Total	$11.1	$0.8	$12.3	$0.2

The fair value of debt securities, summarized by contractual maturities, at December 31, 2004 is as follows:

	Fair Value
	(In Millions)
less than 1 year	$8.7
1 year - 5 years	42.0
5 years - 10 years	51.3
10 years - 15 years	37.7
15 years - 20 years	11.0
20 years+	2.2
Total	$152.9

During the year ended December 31, 2004, the proceeds from the dispositions of securities amounted to $2.9 million with gross gains of $790 and gross losses of $98,852.

Entergy Louisiana

Entergy Louisiana holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held at December 31, 2004 and 2003 are summarized as follows:

2004	Fair Value	Total Unrealized Gains	Total Unrealized Losses
	(In Millions)
Equity	$92.5	$17.1	$2.5
Debt Securities	79.6	2.8	0.8
Total	$172.1	$19.9	$3.3
2003
Equity	$74.6	$6.0	$-
Debt Securities	77.4	3.3	0.1
Total	$152.0	$9.3	$0.1

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows at December 31, 2004:

	Equity Securities		Debt Securities
	Fair Value	Gross Unrealized Losses	Fair Value	Gross Unrealized Losses
	(In Millions)
Less than 12 months	$0.3	$-	$28.9	$0.6
More than 12 months	15.5	2.5	8.2	0.2
Total	$15.8	$2.5	$37.1	$0.8

The fair value of debt securities, summarized by contractual maturities, at December 31, 2004 is as follows:

	Fair Value
	(In Millions)
less than 1 year	$38.8
1 year - 5 years	17.6
5 years - 10 years	12.4
10 years - 15 years	4.8
15 years - 20 years	6.0
20 years+	-
Total	$79.6

During the year ended December 31, 2004, the proceeds from the dispositions of securities amounted to $4.3 million with gross gains of $244,250 and gross losses of $25,882.

System Energy

System Energy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held at December 31 2004 and 2003 are summarized as follows:

2004	Fair Value	Total Unrealized Gains	Total Unrealized Losses
	(In Millions)
Equity	$127.0	$15.0	$7.2
Debt Securities	78.1	1.9	0.6
Total	$205.1	$16.9	$7.8
2003
Equity	$103.4	$5.5	$9.9
Debt Securities	69.5	2.6	0.3
Total	$172.9	$8.1	$10.2

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows at December 31, 2004:

	Equity Securities		Debt Securities
	Fair Value	Gross Unrealized Losses	Fair Value	Gross Unrealized Losses
	(In Millions)
Less than 12 months	$0.4	$-	$40.4	$0.5
More than 12 months	50.4	7.2	2.0	0.1
Total	$50.8	$7.2	$42.4	$0.6

The fair value of debt securities, summarized by contractual maturities, at December 31, 2004 is as follows:

	Fair Value
	(In Millions)
less than 1 year	$4.8
1 year - 5 years	22.4
5 years - 10 years	30.0
10 years - 15 years	7.9
15 years - 20 years	6.9
20 years+	6.1
Total	$78.1

During the year ended December 31, 2004, the proceeds from the dispositions of securities amounted to $7.5 million and gross gains of $32,362 and gross losses of $58,755.

Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, System Energy

Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, System Energy evaluate unrealized gains and losses at the end of each period to determine whether an other than temporary impairment has occurred. This analysis considers the length of time that a security has been in a loss position, the current performance of that security, and whether decommissioning costs are recovered in rates. No significant impairments were recorded in 2004 and 2003 as a result of these evaluations.

Due to the regulatory treatment of decommissioning collections and trust fund earnings, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, System Energy record regulatory assets or liabilities for unrealized gains and losses on trust investments. For the unregulated portion of River Bend, Entergy Gulf States has recorded an offsetting amount of unrealized gains or losses in other deferred credits.

NOTE 13. TRANSACTIONS WITH AFFILIATES (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

Each domestic utility company purchases electricity from and sells electricity to the other domestic utility companies, and System Energy under rate schedules filed with FERC. The domestic utility companies and System Energy purchase fuel from System Fuels; receive management, technical, advisory, operating, and administrative services from Entergy Services; and receive management, technical, and operating services from Entergy Operations. Pursuant to SEC rules under PUHCA and the Federal Power Act, these transactions are on an "at cost" basis. In addition, Entergy Power sells electricity to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans, and RS Cogen sells electricity to Entergy Louisiana and Entergy New Orleans.

As described in Note 1 to the domestic utility companies and System Energy financial statements, all of System Energy's operating revenues consist of billings to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

Additionally, as described in Note 4 to the domestic utility companies and System Energy financial statements, the domestic utility companies and System Energy participate in the Entergy's money pool and earn interest income from the money pool. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also receive interest income from System Fuels, Inc.

The tables below contain the various affiliate transactions of the domestic utility companies, System Energy, and other Entergy affiliates.

Intercompany Revenues

	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Millions)
2004	$256.8	$52.5	$96.6	$47.6	$117.8	$545.4
2003	$242.3	$42.8	$102.4	$27.6	$85.5	$583.8
2002	$172.6	$28.8	$8.8	$70.6	$7.1	$602.5

Intercompany Operating Expenses

	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
		(In Millions)
	(1)		(2)		(3)
2004	$467.5	$558.2	$491.8	$484.4	$228.4	$109.4
2003	$460.6	$438.6	$444.6	$458.6	$211.2	$118.0
2002	$456.7	$321.2	$389.7	$298.6	$166.7	$109.0

(1)	Includes $2.3 million in 2004, $0.1 million in 2003, and $0.7 million in 2002 for power purchased from Entergy Power.
(2)	Includes power purchased from Entergy Power and RS Cogen LLC in 2004 of $9.1 million and $33.0 million, respectively, and in 2003 of $5.9 million and $19.1 million, respectively.
(3)	Includes power purchased from Entergy Power and RS Cogen LLC in 2004 of $9.0 million and $10.6 million, respectively, and in 2003 of $5.7 million and $6.9 million, respectively.

Intercompany Interest Income

	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Millions)
2004	$0.6	$0.4	$1.1	$0.6	$0.2	$0.6
2003	$0.6	$0.4	$1.2	$0.3	$0.2	$0.1
2002	$1.0	$0.3	$0.7	$0.4	$0.2	$0.9

NOTE 14. QUARTERLY FINANCIAL DATA (UNAUDITED) (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

The business of the domestic utility companies and System Energy is subject to seasonal fluctuations with the peak periods occurring during the third quarter. Operating results for the four quarters of 2004 and 2003 were:

Operating Revenue

	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
2004:
First Quarter	$363,461	$638,996	$488,046	$236,829	$169,767	$127,168
Second Quarter	$405,509	$685,313	$555,511	$289,573	$186,337	$132,720
Third Quarter	$481,103	$840,630	$668,240	$390,337	$200,036	$144,052
Fourth Quarter	$403,072	$717,445	$515,189	$296,890	$179,728	$141,441
2003:
First Quarter	$362,749	$584,354	$462,361	$227,369	$140,907	$141,985
Second Quarter	$394,884	$700,635	$569,580	$261,899	$154,065	$144,764
Third Quarter	$469,925	$777,182	$646,503	$309,739	$203,751	$141,239
Fourth Quarter	$362,112	$577,566	$487,126	$236,353	$155,293	$155,832

Operating Income (Loss)

	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
2004:
First Quarter	$48,566	$88,312	$48,318	$22,724	$15,487	$57,767
Second Quarter	$80,669	$101,832	$84,357	$42,157	$22,880	$59,585
Third Quarter	$123,910	$127,838	$87,130	$52,003	$24,450	$59,601
Fourth Quarter	$40,590	$41,437	$41,710	$29,730	($4,878)	$56,181
2003:
First Quarter	$67,130	$75,693	$89,362	$30,096	($1,887)	$55,739
Second Quarter	$92,939	$99,150	$91,304	$44,625	$17,311	$54,029
Third Quarter	$135,790	$146,063	$108,232	$53,173	$28,230	$65,791
Fourth Quarter	$1,330	($13,136)	$13,325	$13,753	($15,736)	$62,853

Net Income (Loss)

	Entergy Arkansas	Entergy Gulf States	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	System Energy
	(In Thousands)
2004:
First Quarter	$19,276	$41,728	$21,211	$8,637	$7,114	$24,664
Second Quarter	$43,277	$55,591	$43,713	$20,808	$12,319	$25,532
Third Quarter	$67,944	$82,456	$45,496	$27,873	$13,189	$27,505
Fourth Quarter	$11,713	$12,489	$17,075	$16,179	($4,550)	$28,247
2003:
First Quarter	$27,145	$11,792(a)	$43,807	$12,316	($4,327)	$23,735
Second Quarter	$47,537	($20,124)	$45,713	$22,350	$9,580	$22,820
Third Quarter	$69,319	$82,283	$57,863	$25,804	$14,118	$28,515
Fourth Quarter	($17,992)	($31,389)	($1,229)	$6,588	($11,512)	$30,933

(a) Entergy Gulf States' net income before the cumulative effect of accounting change for the first quarter of 2003 was $33,125.

Item 2. Properties

            Information regarding the registrant's properties is included in Part I. Item 1. - Business under the sections titled "Property" in this report.

Item 3. Legal Proceedings

            Details of the registrant's material environmental regulation and proceedings and other regulatory proceedings and litigation that are pending or those terminated in the fourth quarter of 2004 are discussed in Part I. Item 1. - Business under the sections titled "Retail Rate Regulation", "Wholesale Rate Matters", "Environmental Regulation", and "Litigation" in this report.

Item 4. Submission of Matters to a Vote of Security Holders

            During the fourth quarter of 2004, no matters were submitted to a vote of the security holders of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy Resources.

DIRECTORS AND EXECUTIVE OFFICERS OF ENTERGY CORPORATION

Directors

            Information required by this item concerning directors of Entergy Corporation is set forth under the heading "Proposal 1--Election of Directors" contained in the Proxy Statement of Entergy Corporation, (the "Proxy Statement"), to be filed in connection with its Annual Meeting of Stockholders to be held May 13, 2005, ("Annual Meeting"), and is incorporated herein by reference. Information required by this item concerning officers and directors of the remaining registrants is reported in Part III of this document.

Executive Officers

Name	Age	Position	Period
J. Wayne Leonard (a)	54	Chief Executive Officer and Director of Entergy Corporation	1999-Present
Richard J. Smith (a)	53	Group President, Utility Operations of Entergy Corporation,   Entergy Arkansas, Entergy Gulf States, Entergy Louisiana,   Entergy Mississippi, and Entergy New Orleans	2001-Present
		Director of Entergy Arkansas, Entergy Gulf States, Entergy   Louisiana, Entergy Mississippi and Entergy New Orleans	2001-Present
		Senior Vice President, Transition Management of Entergy   Corporation	2000-2001
Leo P. Denault (a)	45	Executive Vice President and Chief Financial Officer of   Entergy Corporation	2004-Present
		Director of Entergy Arkansas, Entergy Gulf States, Entergy   Louisiana, Entergy Mississippi, Entergy New Orleans, and   System Energy	2004-Present
		Vice President , Corporate Development and Strategic   Planning of Entergy Services, Inc.	1999-2004
Curtis L. Hebert, Jr. (a)	42	Executive Vice President, External Affairs of Entergy   Corporation	2001-Present
		Chairman and Commissioner of the Federal Energy   Regulatory Commission	1997-2001

Mark T. Savoff (a)	48	Executive Vice President of Entergy Corporation	2004-Present
		Director of Entergy Arkansas, Entergy Gulf States, Entergy   Louisiana, Entergy Mississippi, and Entergy New Orleans	2004-Present
		Executive Vice President of Entergy Services, Inc.	2003-Present
		President, General Electric Power Systems - GE Nuclear   Energy, San Jose, CA	2000-2003
Robert D. Sloan (a)	57	Executive Vice President, General Counsel and Secretary of   Entergy Corporation, Entergy Arkansas, Entergy Gulf   States, Entergy Louisiana, Entergy Mississippi, Entergy   New Orleans, and System Energy	2004-Present
		Senior Vice President, General Counsel and Secretary of   Entergy Corporation, Entergy Arkansas, Entergy Gulf   States, Entergy Louisiana, Entergy Mississippi, and   Entergy New Orleans	2003-2004
		Vice President, General Counsel of GE Industrial Systems,   Plainville, CT	1998-2003
Gary J. Taylor (a)	51	Executive Vice President and Chief Nuclear Officer of   Entergy Corporation	2004-Present
		Director, President and Chief Executive Officer of System   Energy	2003-Present
		Senior Vice President and Chief Operating Officer of   Entergy Operations, Inc.	2000-2003
Nathan E. Langston (a)	56	Senior Vice President and Chief Accounting Officer of   Entergy Corporation, Entergy Arkansas, Entergy Gulf   States, Entergy Louisiana, Entergy Mississippi, Entergy   New Orleans, and System Energy	2001-Present
		Vice President and Chief Accounting Officer of Entergy   Corporation, Entergy Arkansas, Entergy Gulf States,   Entergy Louisiana, Entergy Mississippi, Entergy New   Orleans, and System Energy	1998-2001
William E. Madison (a)	58	Senior Vice President - Human Resources and   Administration of Entergy Corporation	2002-Present
		Senior Vice President - Human Resources and   Administration of Entergy Arkansas, Entergy Gulf States,   Entergy Louisiana, Entergy Mississippi, and Entergy New   Orleans	2001-Present
		Senior Vice President & Chief Human Resources Officer,   Avis Group Holdings, Inc. - Garden City, New York	2000-2001
		President, US Region and Vice President, Global Human   Resource Strategy, E.I. DuPont de Nemours, Wilmington,   Delaware	1997-2000

(a) In addition, this officer is an executive officer and/or director of various other wholly owned subsidiaries of Entergy Corporation and its operating companies.

            Each officer of Entergy Corporation is elected yearly by the Board of Directors.

PART II

Item 5. Market for Registrants' Common Equity and Related Stockholder Matters

Entergy Corporation

            The shares of Entergy Corporation's common stock are listed on the New York Stock, Chicago Stock, and Pacific Exchanges under the ticker symbol ETR.

            Entergy Corporation's stock price as of February 28, 2005 was $69.12. The high and low prices of Entergy Corporation's common stock for each quarterly period in 2004 and 2003 were as follows:

	2004		2003
	High	Low	High	Low
	(In Dollars)
First	60.20	56.01	49.55	42.26
Second	59.92	50.64	54.38	45.90
Third	61.98	54.43	54.99	47.75
Fourth	68.67	60.08	57.24	51.06

            Consecutive quarterly cash dividends on common stock were paid to stockholders of Entergy Corporation in 2004 and 2003. In 2004, dividends of $0.45 per share were paid in the first three quarters, and a dividend of $0.54 per share was paid in the fourth quarter. In 2003, dividends of $0.35 per share were paid in the first and second quarters, and dividends of $0.45 per share were paid in the third and fourth quarters.

            As of February 28, 2005, there were 51,561 stockholders of record of Entergy Corporation.

            Entergy Corporation's future ability to pay dividends is discussed in Note 7 to the consolidated financial statements. In addition to the restrictions described in Note 7, PUHCA provides that, without approval of the SEC, the unrestricted, undistributed retained earnings of any Entergy Corporation subsidiary are not available for distribution to Entergy Corporation's common stockholders until such earnings are made available to Entergy Corporation through the declaration of dividends by such subsidiaries.

Unregistered Sales of Equity Securities and Use Of Proceeds

Issuer Purchases of Equity Securities (1)

Period	Total Number of Shares Purchased	Average Price Paid per Share	Total Number of Shares Purchased as Part of a Publicly Announced Plan	Maximum $ Amount of Shares that May Yet to be Purchased Under the Plan
10/01/2004-10/31/2004	2,135,000	$62.05	2,135,000	$1,293,054,803
11/01/2004-11/30/2004	2,931,000	$65.55	2,931,000	$1,124,355,785
12/01/2004-12/31/2004	4,183,800	$66.24	4,183,800	$999,999,962(2)
Total	9,249,800	$65.04	9,249,800

(1)

In accordance with Entergy's stock-based compensation 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. See Note 7 to the consolidated financial statements for additional discussion of the stock-based compensation plan. 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, and this authorization does not have an expiration date. In August 2004, Entergy announced a program under which Entergy Corporation will repurchase up to $1.5 billion of its common stock. The program extends through the end of 2006. This repurchase program is incremental to the existing authority to repurchase shares to fund the exercise of employee stock options. The amount of repurchases under the program may vary as a result of material changes in business results or capital spending, or as a result of material new investment opportunities.

(2)

Maximum amount of shares that may yet be repurchased relates only to the $1.5 billion plan and does not include an estimate of the amount of shares that may be purchased to fund the exercise of grants under the stock-based compensation plans.

Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy

            There is no market for the common stock of Entergy Corporation's wholly owned subsidiaries. Cash dividends on common stock paid by the domestic utility companies and System Energy to Entergy Corporation during 2004 and 2003, were as follows:

	2004	2003
	(In Millions)
Entergy Arkansas	$85.8	$69.6
Entergy Gulf States	$94.3	$68.1
Entergy Louisiana	$116.5	$145.5
Entergy Mississippi	$46.8	$31.7
Entergy New Orleans	$5.2	$3.0
System Energy	$104.6	$105.0

            Information with respect to restrictions that limit the ability of the domestic utility companies and System Energy to pay dividends is presented in Note 7 to the domestic utility companies and System Energy financial statements.

Item 6. Selected Financial Data

            Refer to "SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC., ENTERGY GULF STATES, INC., ENTERGY LOUISIANA, INC., ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., and SYSTEM ENERGY RESOURCES, INC." which follow each company's financial statements in this report, for information with respect to selected financial data and certain operating statistics.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

            Refer to "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC., ENTERGY GULF STATES, INC., ENTERGY LOUISIANA, INC., ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., and SYSTEM ENERGY RESOURCES, INC."

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

            Refer to "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Significant Factors and Known Trends - Market and Credit Risks OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC., ENTERGY GULF STATES, INC., ENTERGY LOUISIANA, INC., ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., and SYSTEM ENERGY RESOURCES, INC."

Item 8. Financial Statements and Supplementary Data

            Refer to "TABLE OF CONTENTS - Entergy Corporation, Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc., and System Energy Resources, Inc."

Item 9. Changes In and Disagreements With Accountants On Accounting and Financial Disclosure.

            No event that would be described in response to this item has occurred with respect to Entergy, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, or System Energy.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

            As of December 31, 2004, evaluations were performed under the supervision and with the participation of Entergy, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy (individually "Registrant" and collectively the "Registrants") management, including their respective Chief Executive Officers (CEO) and Chief Financial Officers (CFO). The evaluations assessed the effectiveness of the Registrants' disclosure controls and procedures. Based on the evaluations, each CEO and CFO has concluded that, as to the Registrant or Registrants for which they serve as CEO or CFO, the Registrants' disclosure controls and procedures are effective to ensure that information required to be disclosed by each Registrant in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specif ied in Securities and Exchange Commission rules and forms.

Internal Control Over Financial Reporting

            The managements of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy Resources (individually "Registrant" and collectively the "Registrants") are responsible for establishing and maintaining adequate internal control over financial reporting for the Registrants. Each Registrant's internal control system is designed to provide reasonable assurance regarding the preparation and fair presentation of each Registrant's financial statements presented in accordance with generally accepted accounting principles.

            All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

            Each Registrant's management assessed the effectiveness of each Registrant's internal control over financial reporting as of December 31, 2004. In making this assessment, each management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework.

            Based on each management's assessment and the criteria set forth by COSO, each Registrant's management believes that each Registrant maintained effective internal control over financial reporting as of December 31, 2004.

            The Registrants' registered public accounting firm has issued an attestation report on each management's assessment of each Registrant's internal control over financial reporting.

Attestation Report of Registered Public Accounting Firm

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Entergy Corporation and Subsidiaries
New Orleans, Louisiana

We have audited management's assessment, included in the accompanying Internal Control over Financial Reporting, that Entergy Corporation and Subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that Entergy Corporation and Subsidiaries maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, Entergy Corporation and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 8, 2005 expressed an unqualified opinion on those financial statements.

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 8, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Entergy Arkansas, Inc.
New Orleans, Louisiana

We have audited management's assessment, included in the accompanying Internal Control over Financial Reporting, that Entergy Arkansas, Inc. (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that Entergy Arkansas, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, Entergy Arkansas, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 8, 2005 expressed an unqualified opinion on those financial statements.

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 8, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Entergy Gulf States, Inc.
New Orleans, Louisiana

We have audited management's assessment, included in the accompanying Internal Control over Financial Reporting, that Entergy Gulf States, Inc. (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that Entergy Gulf States, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, Entergy Gulf States, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 8, 2005 expressed an unqualified opinion on those financial statements.

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 8, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Entergy Louisiana, Inc.
New Orleans, Louisiana

We have audited management's assessment, included in the accompanying Internal Control over Financial Reporting, that Entergy Louisiana, Inc. (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that Entergy Louisiana, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, Entergy Louisiana, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 8, 2005 expressed an unqualified opinion on those financial statements.

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 8, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Entergy Mississippi, Inc.
New Orleans, Louisiana

We have audited management's assessment, included in the accompanying Internal Control over Financial Reporting, that Entergy Mississippi, Inc. (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that Entergy Mississippi, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, Entergy Mississippi, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 8, 2005 expressed an unqualified opinion on those financial statements.

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 8, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Entergy New Orleans, Inc.
New Orleans, Louisiana

We have audited management's assessment, included in the accompanying Internal Control over Financial Reporting, that Entergy New Orleans, Inc. (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that Entergy New Orleans, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, Entergy New Orleans, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 8, 2005 expressed an unqualified opinion on those financial statements.

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 8, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
System Energy Resources, Inc.
New Orleans, Louisiana

We have audited management's assessment, included in the accompanying Internal Control over Financial Reporting, that System Energy Resources, Inc. (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that System Energy Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, System Energy Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 8, 2005 expressed an unqualified opinion on those financial statements.

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 8, 2005

Item 9B. Other Information

            On March 9, 2005 Entergy Corporation borrowed $15 million under its $965 million, 3-year credit facility, dated as of May 13, 2004, among Entergy Corporation, Citibank, N.A., as Administrative Agent and LC Issuing Bank, ABN AMRO Bank, N.V., as LC Issuing Bank, and several banks party thereto (the 3-Year Facility).  Entergy Corporation described material terms of the 3-Year Facility in its Report on Form 10-Q for the quarterly period ended June 30, 2004, and filed the agreement as Exhibit 4(d).

            In addition to the 3-Year Facility, Entergy Corporation also maintains (i) a $500 million, 5-year credit facility, dated as of December 14, 2004, among Entergy Corporation, Citibank, N.A., as bank and administrative agent, and several banks party thereto (the 5-Year Facility); and (ii) Credit Agreements, dated as of May 31, 2002 and November 24, 2003, among Entergy Corporation, Bayerische Hypo-und Vereinsbank AG, New York Branch, as Bank, and Bayerische Hypo-und Vereinsbank AG, New York Branch, as Administrative Agent (the Hypo Term Loans).  The table below includes the borrowings outstanding and capacity available under these facilities as of March 7, 2005.

Facility	Capacity	Borrowings	Letters of Credit	Capacity Available
	(In Millions)
3-Year Facility	$965	$403	$50	$512
5-Year Facility	$500	$75	-	$425
Hypo Term Loans	$95	$95	-	-

PART III

Item 10. Directors and Executive Officers of the Registrants (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

            All officers and directors listed below held the specified positions with their respective companies as of the date of filing this report, unless otherwise noted.

Name	Age		Position	Period
ENTERGY ARKANSAS, INC.
Directors
Hugh T. McDonald		46	President and Chief Executive Officer of Entergy Arkansas	2000-Present
			Director of Entergy Arkansas	2000-Present
			Senior Vice President, Retail of Entergy Services, Inc.	1999-2000
Leo P. Denault			See information under the Entergy Corporation Officers Section in Part I.
Mark T. Savoff			See information under the Entergy Corporation Officers Section in Part I.
Richard J. Smith			See information under the Entergy Corporation Officers Section in Part I.
Officers
Jay A. Lewis		43	Vice President and Chief Financial Officer - Utility Operations Group  of  Entergy Arkansas, Entergy Gulf States, Entergy Louisiana,  Entergy Mississippi, and Entergy New Orleans	2004-Present
			Director, Accounting Policy and Research of Entergy Services, Inc.	1999 - 2004
Leo P. Denault			See information under the Entergy Corporation Officers Section in Part I.
Curtis L. Hebert, Jr.			See information under the Entergy Corporation Officers Section in Part I.
Nathan E. Langston			See information under the Entergy Corporation Officers Section in Part I.
J. Wayne Leonard			See information under the Entergy Corporation Officers Section in Part I.
William E. Madison			See information under the Entergy Corporation Officers Section in Part I.
Hugh T. McDonald			See information under the Entergy Arkansas Directors Section above.
Mark T. Savoff			See information under the Entergy Corporation Officers Section in Part I.
Robert D. Sloan			See information under the Entergy Corporation Officers Section in Part I.
Richard J. Smith			See information under the Entergy Corporation Officers Section in Part I.
Gary J. Taylor			See information under the Entergy Corporation Officers Section in Part I.

ENTERGY GULF STATES, INC.
Directors
E. Renae Conley	47	Director of Entergy Gulf States and Entergy Louisiana	2000-Present
		President and Chief Executive Officer - LA of Entergy Gulf States and Entergy Louisiana	2000-Present
		Vice President, Investor Relations of Entergy Services	1999-2000
Joseph F. Domino	56	Director of Entergy Gulf States	1999-Present
		President and Chief Executive Officer - TX of Entergy Gulf States	1998-Present
Leo P. Denault		See information under the Entergy Corporation Officers Section in Part I.
Mark T. Savoff		See information under the Entergy Corporation Officers Section in Part I.
Richard J. Smith		See information under the Entergy Corporation Officers Section in Part I.
Officers
E. Renae Conley		See information under the Entergy Gulf States Directors Section above.
Leo P. Denault		See information under the Entergy Corporation Officers Section in Part I.
Joseph F. Domino		See information under the Entergy Gulf States Directors Section above.
Curtis L. Hebert, Jr.		See information under the Entergy Corporation Officers Section in Part I.
Nathan E. Langston		See information under the Entergy Corporation Officers Section in Part I.
J. Wayne Leonard		See information under the Entergy Corporation Officers Section in Part I.
Jay A. Lewis		See information under the Entergy Arkansas Officers Section above.
William E. Madison		See information under the Entergy Corporation Officers Section in Part I.
Mark T. Savoff		See information under the Entergy Corporation Officers Section in Part I.
Robert D. Sloan		See information under the Entergy Corporation Officers Section in Part I.
Richard J. Smith		See information under the Entergy Corporation Officers Section in Part I.
Gary J. Taylor		See information under the Entergy Corporation Officers Section in Part I.

ENTERGY LOUISIANA, INC.
Directors
E. Renae Conley	See information under the Entergy Gulf States Directors Section above.
Leo P. Denault	See information under the Entergy Corporation Officers Section in Part I.
Mark T. Savoff	See information under the Entergy Corporation Officers Section in Part I.
Richard J. Smith	See information under the Entergy Corporation Officers Section in Part I.
Officers
E. Renae Conley	See information under the Entergy Gulf States Directors Section above.
Leo P. Denault	See information under the Entergy Corporation Officers Section in Part I.
Curtis L. Hebert, Jr.	See information under the Entergy Corporation Officers Section in Part I.
Nathan E. Langston	See information under the Entergy Corporation Officers Section in Part I.
J. Wayne Leonard	See information under the Entergy Corporation Officers Section in Part I.
Jay A. Lewis	See information under the Entergy Arkansas Officers Section above.
William E. Madison	See information under the Entergy Corporation Officers Section in Part I.
Mark T. Savoff	See information under the Entergy Corporation Officers Section in Part I.
Robert D. Sloan	See information under the Entergy Corporation Officers Section in Part I.
Richard J. Smith	See information under the Entergy Corporation Officers Section in Part I.
Gary J. Taylor	See information under the Entergy Corporation Officers Section in Part I.

ENTERGY MISSISSIPPI, INC.
Directors
Carolyn C. Shanks	43	President and Chief Executive Officer of Entergy Mississippi	1999-Present
		Director of Entergy Mississippi	1999-Present
Leo P. Denault		See information under the Entergy Corporation Officers Section in Part I.
Mark T. Savoff		See information under the Entergy Corporation Officers Section in Part I.
Richard J. Smith		See information under the Entergy Corporation Officers Section in Part I.
Officers
Leo P. Denault		See information under the Entergy Corporation Officers Section in Part I.
Curtis L. Hebert, Jr.		See information under the Entergy Corporation Officers Section in Part I.
Nathan E. Langston		See information under the Entergy Corporation Officers Section in Part I.
J. Wayne Leonard		See information under the Entergy Corporation Officers Section in Part I.
Jay A. Lewis		See information under the Entergy Arkansas Officers Section above.
William E. Madison		See information under the Entergy Corporation Officers Section in Part I.
Mark T. Savoff		See information under the Entergy Corporation Officers Section in Part I.
Carolyn C. Shanks		See information under the Entergy Mississippi Directors Section above.
Robert D. Sloan		See information under the Entergy Corporation Officers Section in Part I.
Richard J. Smith		See information under the Entergy Corporation Officers Section in Part I.
Gary J. Taylor		See information under the Entergy Corporation Officers Section in Part I.

ENTERGY NEW ORLEANS, INC.
Directors
Daniel F. Packer	57	Chief Executive Officer Entergy New Orleans	1998-Present
		President of Entergy New Orleans	1997-Present
		Director of Entergy New Orleans	1996-Present
Leo P. Denault		See information under the Entergy Corporation Officers Section in Part I.
Mark T. Savoff		See information under the Entergy Corporation Officers Section in Part I.
Richard J. Smith		See information under the Entergy Corporation Officers Section in Part I.
Officers
Leo P. Denault		See information under the Entergy Corporation Officers Section in Part I.
Curtis L. Hebert, Jr.		See information under the Entergy Corporation Officers Section in Part I.
Nathan E. Langston		See information under the Entergy Corporation Officers Section in Part I.
J. Wayne Leonard		See information under the Entergy Corporation Officers Section in Part I.
Jay A. Lewis		See information under the Entergy Arkansas Officers Section above.
William E. Madison		See information under the Entergy Corporation Officers Section in Part I.
Daniel F. Packer		See information under the Entergy New Orleans Directors Section above.
Mark T. Savoff		See information under the Entergy Corporation Officers Section in Part I.
Robert D. Sloan		See information under the Entergy Corporation Officers Section in Part I.
Richard J. Smith		See information under the Entergy Corporation Officers Section in Part I.
Gary J. Taylor		See information under the Entergy Corporation Officers Section in Part I.

SYSTEM ENERGY RESOURCES, INC.
Directors
Gary J. Taylor		See information under the Entergy Corporation Officers Section in Part I.
Leo P. Denault		See information under the Entergy Corporation Officers Section in Part I.
Steven C. McNeal		Director of System Energy	2004-Present
		Vice President and Treasurer of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi,  Entergy New Orleans, and System Energy	1998-Present
Officers
Theodore Bunting	46	Vice President and Chief Financial Officer - Nuclear Operations of System Energy	2004 - Present
		Vice President and Chief Financial Officer of Entergy Arkansas,   Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and    Entergy New Orleans	2002 - 2004
		Vice President and Chief Financial Officer - Operations of Entergy Services	2000 - 2002
		Director, Utility Operations of Entergy Services	1999 - 2000
Leo P. Denault		See information under the Entergy Corporation Officers Section in Part I.
Curtis L. Hebert, Jr.		See information under the Entergy Corporation Officers Section in Part I.
Nathan E. Langston		See information under the Entergy Corporation Officers Section in Part I.
J. Wayne Leonard		See information under the Entergy Corporation Officers Section in Part I.
William E. Madison		See information under the Entergy Corporation Officers Section in Part I.
Mark T. Savoff		See information under the Entergy Corporation Officers Section in Part I.
Robert D. Sloan		See information under the Entergy Corporation Officers Section in Part I.
Richard J. Smith		See information under the Entergy Corporation Officers Section in Part I.
Gary J. Taylor		See information under the Entergy Corporation Officers Section in Part I.

            Each director and officer of the applicable Entergy company is elected yearly to serve by the unanimous consent of the sole stockholder, Entergy Corporation, at its annual meeting.

Corporate Governance Guidelines and Committee Charters

            Each of the Audit, Corporate Governance and Personnel Committees of Entergy Corporation's Board of Directors operates under a written charter. In addition, the full Board has adopted Corporate Governance Guidelines. Each charter and the guidelines are available through Entergy's website (www.entergy.com) or upon written request.

Audit Committee of the Entergy Corporation Board

            The following directors are members of the Audit Committee of Entergy Corporation's Board of Directors:

Steven V. Wilkinson (Chairman)
Kathleen A. Murphy
James R. Nichols
William A. Percy, II
Bismark A. Steinhagen

All Audit Committee members are independent. For purposes of independence of members of the Audit Committee, an independent director also may not accept directly or indirectly any consulting, advisory or other compensatory fee from Entergy or be affiliated with Entergy as defined in SEC rules. All Audit Committee members possess the level of financial literacy and accounting or related financial management expertise required by the NYSE rules. Steven V. Wilkinson qualifies as an "audit committee financial expert," as that term is defined in the SEC rules.

Code of Ethics

            The Board of Directors has adopted a Code of Business Conduct and Ethics for Members of the Board of Directors. The code is available through Entergy's website (www.entergy.com) or upon written request. The Board has also adopted a Code of Business Conduct and Ethics for Employees, that includes Special Provision Relating to Principal Executive Officer and Senior Financial Officers. The Code of Business Conduct and Ethics for Employees is to be read in conjunction with Entergy's omnibus code of integrity under which Entergy operates called the Code of Entegrity as well as system policies. All employees are required to abide by the Codes. Non-bargaining employees are required to acknowledge annually that they understand and abide by the Code of Entegrity. The Code of Business Conduct and Ethics for Employees and the Code of Entegrity are available through Entergy's website (www.entergy.com) or upon written requ est.

Source of Nominations to the Board of Directors; Nominating Procedure

            The Corporate Governance Committee has adopted a policy on consideration of potential director nominees. The Committee will consider nominees from a variety of sources, including nominees suggested by shareholders, executive officers, fellow board members, or a third party firm retained for that purpose. It applies the same procedures to all nominees regardless of the source of the nomination.

            Any party wishing to make a nomination should provide a written resume of the proposed candidate, detailing relevant experience and qualifications, as well as a list of references. The Committee will review the resume and may contact references. It will decide based on the resume and references whether to proceed to a more detailed investigation. If the Committee determines that a more detailed investigation of the candidate is warranted, it will invite the candidate for a personal interview, conduct a background check on the candidate, and assess the ability of the candidate to provide any special skills or characteristics identified by the Committee or the Board.

Section 16(a) Beneficial Ownership Reporting Compliance

            Information called for by this item concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held on May 13, 2005, under the heading "Section 16(a) Beneficial Ownership Reporting Compliance", which information is incorporated herein by reference.

Item 11. Executive Compensation

ENTERGY CORPORATION

            Information called for by this item concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement under the headings "Executive Compensation Tables", "General Information About Nominees", "Director Compensation", and "Comparison of Five Year Cumulative Total Return", all of which information is incorporated herein by reference.

ENTERGY ARKANSAS, ENTERGY GULF STATES, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND SYSTEM ENERGY

Summary Compensation Table

            The following table includes the Chief Executive Officer, the four other most highly compensated executive officers in office as of December 31, 2004, and two additional executive officers who would have been included in the table but retired or resigned during the year at Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy (collectively, the "Named Executive Officers"). This determination was based on total annual base salary and bonuses from all Entergy sources earned by each officer for the year 2004. See Item 10, "Directors and Executive Officers of the Registrants," for information on the principal positions of the Named Executive Officers in the table below.

Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy

            As shown in Item 10, most Named Executive Officers are employed by several Entergy companies. Because it would be impracticable to allocate such officers' salaries among the various companies, the table below includes the aggregate compensation paid by all Entergy companies.

					Long-Term Compensation
		Annual Compensation			Awards		Payouts
Name	Year	Salary	Bonus	(a) Other Annual Comp.	Restricted Stock Awards	Securities Underlying Options	(d) LTIP Payouts	(e) All Other Comp.
E. Renae Conley	2004	$345,912	$272,220	$18,867	(b)	18,400 shares	$724,200	$30,537
CEO-Entergy Louisiana	2003	334,453	200,000	31,087	(b)	33,092	460,088	15,413
CEO-LA-Entergy Gulf  States	2002	321,500	320,000	88,946	(b)	40,000	331,114	15,211
Leo P. Denault	2004	$463,631	$490,000	$15,330	(b)	40,000 shares	$557,634	$29,518
	2003	286,824	217,402	4,551	(b)	30,600	190,170	13,308
	2002	275,834	210,000	15,750	(b)	20,500	153,202	13,041
Joseph F. Domino	2004	$274,242	$172,813	$28,787	(b)	18,189 shares	$304,164	$12,214
CEO-TX-Entergy Gulf  States	2003	265,626	200,765	46,480	(b)	10,500	190,170	11,912
	2002	255,295	210,070	63,361	(b)	22,000	153,202	13,568
Donald C. Hintz (f)	2004	$348,847	$236,798	$204,941	(b)	20,000 shares	$2,136,390	$8,465,499
	2003	660,793	605,115	80,295	(b)	140,000	1,748,333	33,797
	2002	629,423	754,800	206,963	(b)	160,000	1,408,470	34,318
J. Wayne Leonard	2004	$1,088,769	$1,540,000	$46,344	(b)	220,000 shares	$4,634,880	$48,199
	2003	1,038,461	1,197,800	26,152	(b)	195,000	2,944,560	73,639
	2002	962,500	1,450,400	5,257	(b)	330,600	2,372,160	20,517
Hugh T. McDonald	2004	$288,847	$197,400	$25,927	(b)	10,000 shares	$304,164	$12,596
CEO-Entergy Arkansas	2003	264,201	195,000	32,276	(b)	21,199	190,170	12,134
	2002	247,373	185,000	56,295	(b)	22,000	182,854	14,867
Daniel F. Packer	2004	$260,748	$164,375	$27,090	(b)	10,000 shares	$304,164	$11,122
CEO-Entergy New Orleans	2003	253,628	190,000	58,519	(b)	8,000	190,170	3,204
	2002	244,776	95,000	17,705	(b)	20,000	153,202	13,469
Mark T. Savoff	2004	$500,001	$490,000	$24,607	(b)	31,800 shares	$405,552	$21,293
	2003	19,231	-	51,485	(b)	-	-	865
Carolyn C. Shanks	2004	$283,885	$213,900	$14,297	(b)	10,000 shares	$304,164	$11,800
CEO-Entergy Mississippi	2003	263,758	195,000	92,825	$152,160 (b)(c)	14,000	190,170	12,132
	2002	252,478	200,000	77,460	(b)	20,000	153,202	14,138
Richard J. Smith	2004	$494,806	$490,000	$11,840	(b)	63,600 shares	$1,231,140	$56,186
	2003	473,019	380,867	64,371	(b)	72,777	674,795	23,128
	2002	443,269	466,200	28,862	(b)	95,000	454,664	20,699
Gary J. Taylor	2004	$414,356	$411,600	$29,170	(b)	40,000 shares	$1,013,880	$9,987
CEO-System Energy	2003	394,615	316,400	78,575	(b)	26,900	539,836	7,240
	2002	342,788	277,925	48,892	(b)	34,600	336,056	16,156
C. John Wilder (f)	2004	$106,174	$ -	$5,358	(b)	- shares	$ -	$5,171
	2003	568,731	461,153	153,373	(b)	80,000	779,082	51,614
	2002	521,923	549,080	156,683	(b)	131,366	627,634	24,459

(a) 2004 Other Annual Compensation includes the following:

(1)	Payments for personal financial counseling as follows: Ms. Conley $10,000; Mr. Denault $7,615; Mr. Domino $7,725; Mr. Hintz $10,643; Mr. Leonard $15,000; Mr. McDonald $4,500; Mr. Packer $7,871; Ms. Shanks $3,500; Mr. Smith $7,800; Mr. Taylor $9,762; and Mr. Wilder $1,856.
(2)	Payments for annual physical exams as follows: Ms. Conley $2,319; Mr. Denault $2,729; Mr. Domino $2,729; Mr. Hintz $1,404; Mr. Leonard $7,389; Mr. Packer $4,161; Mr. Savoff $3,681; Mr. Smith $1,594; and Mr. Taylor $2,246.
(3)	Personal use of company aircraft as follows: Mr. Domino $1,210; Mr. Hintz $2,442; Mr. Leonard $8,473; Mr. McDonald $1,176; Mr. Packer $855; Ms. Shanks $1,694; Mr. Smith $924; Mr. Taylor $6,203; and Mr. Wilder $1,178.
(4)	Payments for club dues as follows: Mr. Domino $5,056; Mr. Hintz $2,165; Mr. Leonard $68; Mr. McDonald $9,621; Mr. Packer $5,130; Ms. Shanks $4,708; Mr. Taylor $938; and Mr. Wilder $204.
(5)	A relocation payment to Mr. Savoff for $20,926.
(6)	Travel expenses related to volunteer service to Mr. Domino for $3,727.
(7)	Home security monitoring to Ms. Shanks for $180.
(8)	Tax gross up payments as follows: Ms. Conley $6,548; Mr. Denault $4,986; Mr. Domino $8,140; Mr. Hintz $188,287; Mr. Leonard $15,414; Mr. McDonald $10,630; Mr. Packer $9,073; Ms. Shanks $4,215; Mr. Smith $1,522; Mr. Taylor $10,021; and Mr. Wilder $2,120.

(b)	Performance unit (equivalent to shares of Entergy common stock) awards in 2004 are reported under the "Long-Term Incentive Plan Awards" table, and reference is made to this table for information on the aggregate number of performance units awarded during 2004 and the vesting schedule for such units. At December 31, 2004, the number and value of the aggregate performance unit holdings were as follows: Ms. Conley 19,600 units, $1,324,764; Mr. Denault 33,400 units, $2,257,506; Mr. Domino 10,000 units, $675,900; Mr. Hintz 25,500 units, $1,723,545; Mr. Leonard 165,600 units, $11,192,904; Mr. McDonald 10,000 units, $675,900; Mr. Packer 10,000 units, $675,900; Mr. Savoff 33,100 units, $2,237,229; Ms. Shanks 13,000 units, $878,670; Mr. Smith 41,500 units, $2,804,985; and Mr. Taylor 40,300 units, $2,723,877. Accumulated dividends are paid on performance units when vested. The value of performance unit holdings as of December 31, 2004 is determined by multiplying the total number of units held by the closing market price of Entergy common stock on the New York Stock Exchange Composite Transactions on December 31, 2004 ($67.59 per share). The value of units for which restrictions were lifted in 2004, 2003 and 2002, and the applicable portion of accumulated cash dividends, are reported in the LTIP payouts column in the above table.
(c)	In addition to the performance units granted under the Equity Ownership Plan, Ms. Shanks was granted 3,000 restricted units in 2003. Restrictions will be lifted on 1,200 units in 2006 and the remaining 1,800 units in 2011, based on continued service with Entergy. Accumulated dividends will not be paid. The value Ms. Shanks may realize is dependent upon both the number of units that vest and the future market price of Entergy common stock.
(d)	Amounts include the value of performance units that vested in 2004, 2003 and 2002 (see note (b) above) under Entergy's Equity Ownership Plan.
(e)	All Other Compensation includes the following:

(1)	2004 benefit accruals under the Defined Contribution Restoration Plan as follows: Ms. Conley $21,930; Mr. Denault $20,808; Mr. Domino $3,511; Mr. Hintz $3,535; Mr. Leonard $39,222; Mr. McDonald $3,898; Mr. Packer $2,865; Mr. Savoff $12,510; Ms. Shanks $3,098; Mr. Smith $47,409; Mr. Taylor $5,091; and Mr. Wilder $956.
(2)	2004 employer contributions to the System Savings Plan as follows: Ms. Conley $8,607; Mr. Denault $8,710; Mr. Domino $8,703; Mr. Hintz $7,994; Mr. Leonard $8,977; Mr. McDonald $8,698; Mr. Packer $8,257; Mr. Savoff $8,783; Ms. Shanks $8,702; Mr. Smith $8,777; Mr. Taylor $4,896; and Mr. Wilder $4,215.
(3)	A 2004 lump sum award made under the System Executive Retirement Plan to Mr. Hintz in the amount of $8,453,970. For a description of the System Executive Retirement Plan, see the discussion under "Executive Retirement and Benefit Plans - - System Executive Retirement Plan."

(f) Mr. Hintz retired in April 2004. Mr. Wilder resigned in February 2004.

Option Grants in 2004

            The following table summarizes option grants during 2004 to the Named Executive Officers. The absence, in the table below, of any Named Executive Officer indicates that no options were granted to such officer.

Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy

					Potential Realizable
	Individual Grants				Value
	Number of	% of Total			at Assumed Annual
	Securities	Options			Rates of Stock
	Underlying	Granted to	Exercise		Price Appreciation
	Options	Employees	Price (per	Expiration	for Option Term(b)
Name	Granted (a)	in 2004	share) (a)	Date	5%	10%
E. Renae Conley	18,400	1.0%	$58.60	3/02/14	$678,099	$1,718,437
Leo P. Denault	40,000	2.1%	58.60	3/02/14	1,474,129	3,735,732
Joseph F. Domino	10,000	0.5%	58.60	3/02/14	368,532	933,933
	4,610 (c)	0.2%	59.02	1/28/09	73,874	162,917
	1,601 (c)	0.1%	65.22	1/28/09	24,022	52,055
	1,308 (c)	0.1%	65.26	1/28/09	19,637	42,554
	670 (c)	0.1%	65.25	1/25/11	15,546	35,490
Donald C. Hintz	20,000	1.1%	58.60	3/02/14	737,065	1,867,866
J. Wayne Leonard	220,000	11.6%	58.60	3/02/14	8,107,710	20,546,528
Hugh T. McDonald	10,000	0.5%	58.60	3/02/14	368,532	933,933
Daniel F. Packer	10,000	0.5%	58.60	3/02/14	368,532	933,933
Mark T. Savoff	31,800	1.7%	58.60	3/02/14	1,171,933	2,969,907
Carolyn C. Shanks	10,000	0.5%	58.60	3/02/14	368,532	933,933
Richard J. Smith	63,600	3.4%	58.60	3/02/14	2,343,865	5,939,814
Gary J. Taylor	40,000	2.1%	58.60	3/02/14	1,474,129	3,735,732

(a)	Options were granted on March 2, 2004, pursuant to the Equity Ownership Plan. All options granted on this datehave an exercise price equal to the closing price of Entergy common stock on the New York Stock Exchange Composite Transactions on March 2, 2004. These options will vest in equal increments, annually, over a three-year period beginning in 2005, based on continued service with Entergy.
(b)	Calculation based on the market price of the underlying securities assuming the market price increases over the option period and assuming annual compounding. The column presents estimates of potential values based on simple mathematical assumptions. The actual value, if any, a Named Executive Officer may realize is dependent upon the market price on the date of option exercise.
(c)	During 2004, Mr. Domino converted presently exercisable stock options into Entergy stock and reload stock options. He accomplished this by exercising stock options, paying the exercise price and all applicable taxes for these shares by surrendering shares of Entergy stock. Additional options, as indicated above, were granted pursuant to the reload feature of this "stock for stock" exercise method. Under the reload mechanism, eligible participants are granted an additional number of options equal to the number of shares surrendered to pay the exercise price. The reloaded stock options vest immediately and have an exercise price equal to the price of Entergy common stock on the New York Stock Exchange Composite Transactions on the date of exercise of the original options. The reloaded options retain the original grant's expiration date. The reload feature was removed from the Equity Ownership Plan as approved by the Stockholders in May 2003. Reloads are no longer availabl e for options granted after February 13, 2003.

Aggregated Option Exercises in 2004 and December 31, 2004 Option Values

The following table summarizes the number and value of all unexercised options held by the Named Executive Officers. The absence, in the table below, of any Named Executive Officer indicates that no options are held by such officer.

			Number of
			Securities Underlying		Value of Unexercised
			Unexercised Options		In-the-Money Options
	Shares Acquired	Value	as of December 31, 2004		as of December 31, 2004 (b)
Name	on Exercise	Realized (a)	Exercisable	Unexercisable	Exercisable	Unexercisable
E. Renae Conley	-	$ -	85,858	47,734	$2,376,930	$881,007
Leo P. Denault	-	-	42,322	53,368	896,883	687,797
Joseph F. Domino	14,667	464,974	39,975	24,334	925,393	441,831
Donald C. Hintz	147,588	4,552,699	630,000	-	17,776,875	-
J. Wayne Leonard	-	-	1,201,600	460,200	41,668,356	7,840,180
Hugh T. McDonald	-	-	42,665	25,334	1,128,347	464,971
Daniel F. Packer	-	-	30,799	22,001	859,748	386,004
Mark T. Savoff	-	-	-	31,800	-	285,882
Carolyn C. Shanks	21,467	572,052	17,999	26,001	453,296	478,564
Richard J. Smith	-	-	150,537	120,268	3,720,385	1,947,463
Gary J. Taylor	13,333	293,326	58,699	69,468	1,620,626	1,073,323
C. John Wilder	222,430	3,649,306	-	-	-	-

(a)	Based on the difference between the closing price of Entergy's common stock on the New York Stock Exchange Composite Transactions on the exercise date and the option exercise price.
(b)	Based on the difference between the closing price of Entergy's common stock on the New York Stock Exchange Composite Transactions on December 31, 2004, and the option exercise price.

Long-Term Incentive Plan Awards in 2004

The following table summarizes the awards of performance units (equivalent to shares of Entergy common stock) granted under the Equity Ownership Plan in 2004 to the Named Executive Officers.

			Estimated Future Payouts Under Non-Stock Price-Based Plans (# of units) (a) (b)
Name	Number of Units	Performance Period Until Maturation or Payout	Threshold	Target	Maximum
E. Renae Conley	8,000	1/1/04-12/31/06	400	3,200	8,000
Leo P. Denault	15,800	1/1/04-12/31/06	700	6,322	15,800
Joseph F. Domino	4,000	1/1/04-12/31/06	200	1,600	4,000
Donald C. Hintz	3,600	1/1/04-12/31/06	200	1,456	3,600
J. Wayne Leonard	85,200	1/1/04-12/31/06	3,500	34,100	85,200
Hugh T. McDonald	4,000	1/1/04-12/31/06	200	1,600	4,000
Daniel F. Packer	4,000	1/1/04-12/31/06	200	1,600	4,000
Mark T. Savoff	16,500	1/1/04-12/31/06	700	6,600	16,500
Carolyn C. Shanks	4,000	1/1/04-12/31/06	200	1,600	4,000
Richard J. Smith	16,500	1/1/04-12/31/06	700	6,600	16,500
Gary J. Taylor	16,500	1/1/04-12/31/06	700	6,600	16,500

(a)

Performance units awarded will vest at the end of a three-year period, subject to the attainment of approved performance goals for Entergy. Actual awards are based upon the achievement of the cumulative result of these goals for the performance period. The value any Named Executive Officer may realize is dependent upon the number of units that vest, the future market price of Entergy common stock, and the dividends paid during the performance period.

(b)

The threshold, target, and maximum levels correspond to the achievement of 10%, 100%, and 250%, respectively, of Equity Ownership Plan goals. Achievement of a threshold, target, or maximum level would result in the award of the number of units indicated in the respective column. Achievement of a level between these three specified levels would result in the award of a number of units calculated by means of interpolation.

Executive Retirement and Benefit Plans

Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy

            The Named Executive Officers are eligible to participate in three types of non-qualified retirement benefit plans. The first type of plan is one that provides retirement income, and includes the qualified retirement plan combined with the Pension Equalization Plan, the Supplemental Retirement Plan, and the System Executive Retirement Plan. In these plans, an executive is typically enrolled in one or more plans but only paid the amount due under the plan that provides the highest benefit, except that participants in the Supplemental Retirement Plan are also eligible for benefits under the Pension Equalization Plan. The second type of plan provides for payments in the event of a change in control, and includes the System Executive Continuity Plans. Finally, the Executive Deferred Compensation Plan and the Equity Ownership Plan allow for deferral of earned income.

Qualified Retirement Plan Combined with Pension Equalization Plan. Entergy Corporation has a tax-qualified defined benefit plan, which, combined with a non-qualified Pension Equalization Plan (PEP), provides for a retirement benefit calculated by multiplying the number of years of employment by 1.5%, which is then multiplied by the final average pay as defined in the plans, and currently includes base salary plus annual bonus. The normal form of benefit for a single executive employee is a lifetime annuity and for a married executive employee is a reduced benefit with a 50% surviving spouse annuity. Retirement benefits are not subject to any deduction for social security.

            The maximum benefit under the qualified pension plan is limited by Sections 401 and 415 of the Internal Revenue Code of 1986, as amended; however, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy have elected to participate in the PEP sponsored by Entergy Corporation. Under the PEP, certain executives, including the Named Executive Officers, would receive an additional amount to compensate for the benefit that would have been payable under the qualified pension plan, except for the Internal Revenue Code Sections 401 and 415 limitations discussed above. The PEP also includes as earnings for purposes of calculating PEP benefits a Named Executive Officer's Executive Annual Incentive Plan bonus and any base salary or bonus the Named Executive Officer elects to defer.

            As of December 31, 2004, the credited actual years of service under the combined plans were for Ms. Conley (5), Mr. Denault (5), Mr. Domino (34), Mr. Leonard (6), Mr. McDonald (22), Mr. Packer (22), Mr. Savoff (1), Ms. Shanks (21), Mr. Smith (5), and Mr. Taylor (4). Because they entered into PEP agreements granting additional years of service, the total credited years of service under the PEP were for Ms. Conley (22), Mr. Smith (28), and Mr. Taylor (23). Mr. Hintz retired during 2004 with 32 years of service.

            The following table shows the annual retirement benefits that would be paid at normal retirement (age 65 or later) and includes covered compensation for the executive officers included in the salary column of the Summary Compensation Table above.

Retirement Income Plan Table

Annual
Covered	Years of Service
Compensation	15	20	25	30	35
$200,000	$45,000	$60,000	$75,000	$90,000	$105,000
300,000	67,500	90,000	112,500	135,000	157,500
400,000	90,000	120,000	150,000	180,000	210,000
500,000	112,500	150,000	187,500	225,000	262,500
750,000	168,750	225,000	281,250	337,500	393,750
1,000,000	225,000	300,000	375,000	450,000	525,000
1,250,000	281,250	375,000	468,750	562,500	656,250
1,500,000	337,500	450,000	562,500	675,000	787,500

Supplemental Retirement Plan (SRP). Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy participate in the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries. Executives may participate in the SRP, which is an unfunded defined benefit plan, at the invitation of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy. Mr. Packer is the only named executive officer who is currently a participant in the plan. The SRP provides that, under certain circumstances, a participant may receive a monthly retirement benefit payment for 120 months. The amount of monthly payment shall not exceed 2.5% of the participant's average basic annual pay (as defined in the SRP).

System Executive Retirement Plan (SERP). This executive plan is an unfunded defined benefit plan for participating executives, including all of the executive officers named in the Summary Compensation Table (except for Mr. Leonard, who receives non-qualified supplemental retirement benefits under the terms of his retention contract, which are described below). Executive officers can choose, at retirement, between the retirement benefits paid under the SERP or those payable under the non-qualified supplemental retirement plans discussed above, and in which they participate. SERP benefits are calculated by multiplying the covered pay times the maximum pay replacement ratios of 55%, 60% or 65% (dependent on job rating at retirement) that are attained at 30 years of credited service. The current maximum pay replacement ratio at 20 years of credited service for Ms. Conley, Mr. Denault, Mr. Savoff, Mr. Smith and Mr. Taylor is 50%. The current maximum pay replacement rat io at 20 years of credited service for Mr. Domino, Mr. McDonald, Mr. Packer and Ms. Shanks is 45%. The ratios are reduced for each year of employment below 30 years. The normal form of benefit for a single employee is a lifetime annuity, and for a married employee is a reduced benefit with a 50% surviving spouse annuity. These retirement payments may be offset by any and all defined benefit plan payments from the Company and from prior employers. These payments are not subject to social security offsets.

            Receipt of benefits under any of the supplemental retirement plans described above is contingent upon several factors. The participant must agree, without the specific consent of the Entergy company for which such participant was last employed, not to take employment after retirement with any entity that is in competition with, or similar in nature to, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy or any affiliate thereof. Eligibility for benefits is forfeitable for various reasons, including violation of an agreement with Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, or for resignation or termination of employment for any reason before or after normal retirement age and without the employer's permission.

            The credited years of service for the Named Executive Officers under the SERP are as follows: Ms. Conley (5), Mr. Denault (5), Mr. Domino (34), Mr. McDonald (22), Mr. Packer (22), Mr. Savoff (1), Ms. Shanks (21), Mr. Smith (5), and Mr. Taylor (14). Mr. Hintz retired in 2004 with 32 credited years of service under the SERP.

            Upon retirement, and subject to existing deferral elections and the provisions of Internal Revenue Code Section 409A, executives are able to receive the value of their SERP, SRP, or PEP benefit paid either as a lump sum or a series of annual payments. The following table shows the annual retirement benefits that would be paid at normal retirement (age 65 or later) under the SERP.

System Executive Retirement Plan Table (1)

Annual
Covered	Years of Service
Compensation	10	15	20	25	30+
$250,000	$75,000	$112,500	$125,000	$137,500	$150,000
500,000	150,000	225,000	250,000	275,000	300,000
750,000	225,000	337,500	375,000	412,500	450,000
1,000,000	300,000	450,000	500,000	550,000	600,000
1,500,000	450,000	675,000	750,000	825,000	900,000
2,000,000	600,000	900,000	1,000,000	1,100,000	1,200,000
2,500,000	750,000	1,125,000	1,250,000	1,375,000	1,500,000
3,000,000	900,000	1,350,000	1,500,000	1,650,000	1,800,000

(1) Covered pay includes the average of the highest three years of annual base pay and incentive awards earned by the executive during the ten years immediately preceding his retirement. Benefits shown are based on a target replacement ratio of 50% based on the years of service and covered compensation shown. The benefits for 10, 15, and 20 or more years of service at the 45% and 55% replacement levels would decrease (in the case of 45%) or increase (in the case of 55%) by the following percentages: 3.0%, 4.5%, and 5.0%, respectively.

System Executive Continuity Plans. All Named Executive Officers participate in one of Entergy's two System Executive Continuity Plans. However, if Mr. Leonard receives benefits under the change in control protections of his retention contract, which is described below, he will not also receive benefits under the Continuity Plans. Each plan provides severance pay and benefits under specified circumstances following a change in control. In the event a participant's employment is involuntarily terminated without cause or if a participant terminates for good reason during the change in control period, the named executive officers will be entitled to:

• a cash severance payment equal to one to three times base salary and target bonus payable in a single sum distribution. The precise level of payment is determined by the participant's management level. The cash severance payment under the Continuity Plans is limited to 2.99 times base salary and applicable annual incentive bonus, except for participants (other than Mr. Leonard and Mr. Denault) who were entitled to receive a three times severance payment prior to March of 2004;

 
• continued medical and dental insurance coverage for one to three years, but subject to offset for any similar coverage provided by the participant's new employer;

 
• immediate vesting of performance awards, based upon an assumed achievement of applicable performance targets; and

 
• payment of a "gross-up" payment to compensate for any excise taxes the participant might incur.

Participants in the Continuity Plans are subject to post-employment restrictive covenants, including noncompetition provisions that run for two years for Named Executive Officers but extend to three years if permissible under applicable law.

Deferred Compensation Plans. Executives are eligible to defer earned income through participation in Entergy's Executive Deferred Compensation Plan ("EDCP") or by purchasing phantom units of Entergy stock at fair market value under the Equity Ownership Plan ("EOP"). Executives may under the EDCP defer receipt of base salary, amounts due under the executive plans described above, annual bonuses, performance units, and approved incentive compensation such as restricted units and signing bonuses. The investment options available to executives under the EDCP are similar to those currently available under the Savings Plan of Entergy Corporation and Subsidiaries, except that executives may not invest in Entergy stock under the EDCP. Executives may under the EOP defer receipt of annual bonuses, performance units, restricted units, and pre-2003 option gains.

Compensation of Directors

            For information regarding compensation of the directors of Entergy Corporation, see the Proxy Statement under the heading "Director Compensation", which information is incorporated herein by reference. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy currently have no non-employee directors, and none of the current directors of these companies are compensated for their responsibilities as director.

            Retired non-employee directors of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans with a minimum of five years of service on the respective Boards of Directors are paid $200 a month for a term of years corresponding to the number of years of active service as directors. Retired non-employee directors with over ten years of service receive a lifetime benefit of $200 a month. Years of service as an advisory director are included in calculating this benefit. System Energy has no retired non-employee directors.

            Retired non-employee directors of Entergy Gulf States receive retirement benefits under a plan in which all directors who served continuously for a period of years will receive a percentage of their retainer fee in effect at the time of their retirement for life. The retirement benefit is 30 percent of the retainer fee for service of not less than five nor more than nine years, 40 percent for service of not less than ten nor more than fourteen years, and 50 percent for fifteen or more years of service. For those directors who retired prior to the retirement age, their benefits are reduced. The plan also provides disability retirement and optional hospital and medical coverage if the director has served at least five years prior to the disability. The retired director pays one-third of the premium for such optional hospital and medical coverage and Entergy Gulf States pays the remaining two-thirds. Years of service as a n advisory director are included in calculating this benefit.

Executive Employment Contracts and Retention Agreements

Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy

            Upon completion of a transaction resulting in a change-in-control of Entergy (a "Merger"), benefits already accrued under Entergy's System Executive Retirement Plan, Supplemental Retirement Plan and Pension Equalization Plan, and awards granted under the EOP, will become fully vested if the participant is involuntarily terminated without "cause" or terminates employment for "good reason" (as such terms are defined in such plans).

Retention Agreement with Mr. Leonard - Mr. Leonard's retention agreement provides that if he terminates his employment following his attainment of age 55, with or without "good reason" and except for "cause," he will be entitled to a non-qualified supplemental retirement benefit in lieu of participation in the Company's non-qualified supplemental retirement plans such as the SERP, the SRP, or the PEP. Mr. Leonard will reach age 55 during the 2005 calendar year. If Mr. Leonard's employment is terminated by Entergy for "cause" at any time, before or after his attainment of age 55, he will forfeit his non-qualified supplemental retirement benefit. However, if Mr. Leonard were to leave without "cause" on or after his attainment of age 55, he would be entitled to receive this benefit, plus:

• previously vested stock options (with 248,533 options vesting during 2005 in addition to those described in the "December 31, 2004 Option Values" table above), which must be exercised within 90 days of termination;

 
• income earned in prior periods and deferred into available investment options, subject to his deferral elections and the provisions of Internal Revenue Code Section 409A. As of December 31, 2004, Mr. Leonard had credited to his deferral accounts 150,731 phantom units of Entergy Company stock and $146,250 in other deemed investment funds; and

 
• other broad-based compensation and benefits generally available to terminated employees under plans or arrangements in which Mr. Leonard participates, in accordance with the terms and conditions of those plans and arrangements.

            Mr. Leonard's non-qualified supplemental retirement benefit is calculated as a single life annuity equal to 60% of his final monthly compensation (as defined under the SERP), reduced to account for benefits payable to Mr. Leonard under the Company's and a former employer's qualified pension plans. As of December 31, 2004, his final monthly compensation was $191,228 which amount would provide for a single life annuity of approximately $1,376,842 per year as his non-qualified supplemental retirement benefit, subject to the offsets described above. The benefit is payable in a single lump sum, or as periodic payments, at his discretion. If elected, periodic payments will be due for Mr. Leonard's life, and then a reduced benefit of 50% will be due for the life of his spouse.

            Upon attainment of 10 years of service with the Company, which will occur in 2008, Mr. Leonard would qualify for retirement under certain Company plans. At this point, he would become eligible to receive additional benefits comparable to those available to other retirees of the Company, such as accelerated vesting of stock options, an extended period to exercise those options, pro-rated payment of annual and long-term incentive awards, and continued health and welfare coverage to the extent available.

The retention agreement with Mr. Leonard further provides that, subject to certain forfeiture provisions, upon a termination of employment while a Merger is pending (a) by Entergy without "cause" or by Mr. Leonard for "good reason", as such terms are defined in the agreement, or (b) by reason of Mr. Leonard's death or disability:

• Entergy will pay to him a lump sum cash severance payment equal to 2.99 times the sum of Mr. Leonard's base salary plus the lesser of (i) his target annual incentive award, or (ii) his applicable annual incentive award, each subject to the provisions of Internal Revenue Code Section 409A;
   
• Entergy will pay to him a pro rata annual incentive award, based on an assumed maximum annual achievement of applicable performance goals;
   
• his non-qualified supplemental retirement benefit will fully vest, will be determined as if he had remained employed with Entergy until the attainment of age 55, and will commence upon his attainment of age 55, with certain adjustments in the case of death or disability;
   
• he will be entitled to immediate payment of performance awards, based upon an assumed target achievement of applicable performance goals under most circumstances and an assumed maximum achievement of applicable performance goals in the case of a merger-related termination, as defined in the agreement;
   
• all of his previously granted stock options will become fully vested and will remain outstanding for their full ten-year term; and
   
• Entergy will pay to him a "gross-up" payment to compensate him for any excise taxes he might incur.

Employment Agreement with Ms. Shanks - The employment agreement with Ms. Shanks provides for her continued employment until 2011. During this period, Ms. Shanks will continue to participate in all executive plans, programs, and arrangements for which she is eligible. In October of 2011, Ms. Shanks will become a special project coordinator of Entergy Mississippi or another Entergy System company until 2016. During her tenure as special project coordinator, Ms. Shanks will continue to receive her same rate of annual base salary in effect immediately prior to her assumption of this post, but will forfeit an amount sufficient to fund this salary from amounts that would otherwise be credited to her non-qualified deferral accounts. Commencing in October of 2016, Ms. Shanks will be eligible to retire with all of the post-retirement compensation and benefits for which she is eligible.

            During the term of the agreement, Ms. Shanks may resign, or Entergy may terminate her for "cause," as defined in the agreement. In either of those events, Ms. Shanks is due no additional compensation or benefits under the agreement. If there is a "change in control" before October of 2011, she remains eligible for benefits under the System Executive Continuity Plan. If the change in control occurs while Ms. Shanks is a special project coordinator, and Entergy's obligations under this agreement are breached, she receives:

• a cash payment equal to her remaining unpaid base salary;
   
• all other benefits to which she would be entitled had she remained employed until the conclusion of the term of the agreement; and
   
• all legal fees and expenses incurred in disputing in good faith any term of the agreement.

Retention agreement with Mr. Smith - The retention agreement with Mr. Smith provides that Mr. Smith will be paid a retention payment of approximately $525,000 on each of the first three anniversaries of the date on which a Merger is completed, if he remains employed on each of those dates. The agreement also provides that upon termination of employment while a Merger is pending and for three years after completion (a) by Mr. Smith for "good reason" or by Entergy without "cause", as such terms are defined in the agreement or (b) by reason of Mr. Smith's death or disability:

• Entergy will pay to him a lump sum cash severance payment equal to the unpaid installments, if any, of the retention payments described above;
   
• he will be entitled to immediate payment of performance awards based upon an assumed target achievement of applicable performance goals;
   
• all of his stock options will become fully vested and will remain outstanding for their full ten-year term;
   
• Entergy will pay to him a "gross-up" payment to compensate him for any excise taxes he might incur.

Personnel Committee Interlocks and Insider Participation

            The compensation of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy executive officers was set by the Personnel Committee of Entergy Corporation's Board of Directors, composed solely of Directors of Entergy Corporation.

Item 12. Security Ownership of Certain Beneficial Owners and Management

            Entergy Corporation owns 100% of the outstanding common stock of registrants Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy. The information with respect to persons known by Entergy Corporation to be beneficial owners of more than 5% of Entergy Corporation's outstanding common stock is included under the heading "Stockholders Who Own at Least Five Percent" in the Proxy Statement, which information is incorporated herein by reference. The registrants know of no contractual arrangements that may, at a subsequent date, result in a change in control of any of the registrants.

            As of December 31, 2004, the directors, the Named Executive Officers, and the directors and officers as a group for Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, respectively, beneficially owned directly or indirectly common stock of Entergy Corporation as indicated:

	Entergy Corporation Common Stock
	Amount of Nature of Beneficial Ownership (a)
Name	Sole Voting and Investment Power	Other Beneficial Ownership(b)	Entergy Corporation Stock Equivalent Units (c)
Entergy Corporation
Maureen S. Bateman*	2,700	-	3,200
W. Frank Blount*	9,384	-	13,600
Simon D. deBree*	1,442	-	2,400
Claiborne P. Deming*	6,700	-	1,600
Leo P. Denault**	951	52,423	48,924
Alexis Herman*	900	-	800
Donald C. Hintz***	4,963	630,000	87,605
J. Wayne Leonard***	13,433	1,376,800	150,731
Robert v.d. Luft*	24,472	285,667	9,600
Kathleen A. Murphy* (e)	2,700	1,000	3,200
Dr. Paul W. Murrill* (d)	2,915	-	14,400
James R. Nichols* (e)	8,910	3,684	14,400
William A. Percy, II*	2,950	-	3,200
Dennis H. Reilley* (d)	600	-	4,000
Mark T. Savoff**	174	-	207
Robert D. Sloan**	309	4,033	217
Richard J. Smith**	1,658	190,538	56,875
Wm. Clifford Smith*	12,988	-	16,800
Bismark A. Steinhagen* (e)	9,424	2,623	24,000
C. John Wilder**	-	-	-
Steven V. Wilkinson*	750	-	800
All directors and executive
officers	118,815	2,979,314	537,451

	Entergy Corporation Common Stock
	Amount of Nature of Beneficial Ownership (a)
Name	Sole Voting and Investment Power	Other Beneficial Ownership(b)	Entergy Corporation Stock Equivalent Units (c)
Entergy Arkansas
Leo P. Denault***	951	52,423	48,924
Donald C Hintz**	4,963	630,000	87,605
J. Wayne Leonard**	13,433	1,376,800	150,731
Hugh T. McDonald***	4,733	53,999	25,967
Mark T. Savoff***	174	-	207
Richard J. Smith***	1,658	190,538	56,875
C. John Wilder**	-	-	-
All directors and executive
officers	37,483	2,759,540	451,418
Entergy Gulf States
E. Renae Conley***	1,843	107,192	40,402
Leo P. Denault***	951	52,423	48,924
Joseph F. Domino***	8,125	50,809	24,377
Donald C. Hintz**	4,963	630,000	87,605
J. Wayne Leonard**	13,433	1,376,800	150,731
Mark T. Savoff***	174	-	207
Richard J. Smith***	1,658	190,538	56,875
C. John Wilder**	-	-	-
All directors and executive
officers	42,718	2,863,542	490,230
Entergy Louisiana
E. Renae Conley***	1,843	107,192	40,402
Leo P. Denault***	951	52,423	48,924
Donald C. Hintz**	4,963	630,000	87,605
J. Wayne Leonard**	13,433	1,376,800	150,731
Mark T. Savoff***	174	-	207
Richard J. Smith***	1,658	190,538	56,875
C. John Wilder**	-	-	-
All directors and executive
officers	34,593	2,812,733	465,853
Entergy Mississippi
Leo P. Denault***	951	52,423	48,924
Donald C. Hintz**	4,963	630,000	87,605
J. Wayne Leonard**	13,433	1,376,800	150,731
Mark T. Savoff***	174	-	207
Carolyn C. Shanks***	4,999	29,333	15,698
Richard J. Smith***	1,658	190,538	56,875
C. John Wilder**	-	-	-
All directors and executive
officers	37,749	2,734,874	441,149

	Entergy Corporation Common Stock
	Amount of Nature of Beneficial Ownership (a)
Name	Sole Voting and Investment Power	Other Beneficial Ownership(b)	Entergy Corporation Stock Equivalent Units (c)
Entergy New Orleans
Leo P. Denault***	951	52,423	48,924
Donald C. Hintz**	4,963	630,000	87,605
J. Wayne Leonard**	13,433	1,376,800	150,731
Daniel F. Packer***	543	40,133	5,446
Mark T. Savoff***	174	-	207
Richard J. Smith***	1,658	190,538	56,875
C. John Wilder**	-	-	-
All directors and executive
officers	33,293	2,745,674	430,897
System Energy
Leo P. Denault***	951	52,423	48,924
Donald C. Hintz**	4,963	630,000	87,605
J. Wayne Leonard**	13,433	1,376,800	150,731
Steven C. McNeal*	5,237	19,000	3,624
Mark T. Savoff**	174	-	207
Richard J. Smith**	1,658	190,538	56,875
Gary J. Taylor***	1,198	79,200	12,094
C. John Wilder**	-	-	-
All directors and executive
officers	38,307	2,727,108	429,075

*	Director of the respective Company
**	Named Executive Officer of the respective Company
***	Director and Named Executive Officer of the respective Company

(a)	Based on information furnished by the respective individuals. Except as noted, each individual has sole voting and investment power. The number of shares of Entergy Corporation common stock owned by each individual and by all directors and executive officers as a group does not exceed one percent of the outstanding Entergy Corporation common stock.
(b)	Other Beneficial Ownership includes, for the Named Executive Officers, shares of Entergy Corporation common stock that may be acquired within 60 days after December 31, 2004, in the form of unexercised stock options awarded pursuant to the Equity Ownership Plan.
(c)	Represents the balances of stock equivalent units each executive holds under the deferral provisions of the Equity Ownership Plan and the Defined Contribution Restoration Plan. These units will be paid out in a combination of Entergy Corporation Common Stock and cash based on the value of Entergy Corporation Common Stock on the date of payout. The deferral period is determined by the individual and is at least two years from the award of the bonus. For directors of Entergy Corporation the stock equivalent units are part of the Service Award for Directors. All non-employee directors are credited with units for each year of service on the Board.
(d)	Dr. Murrill and Mr. Reilley have deferred receipt of an additional 5,100 shares and 2,100 shares, respectively.
(e)	Includes 1,000 shares in which Ms. Murphy has joint ownership, 2,623 shares for Mr. Steinhagen that are in his wife's name, and 3,684 shares for Mr. Nichols that are owned by a charitable foundation that he controls.

Equity Compensation Plan Information

Entergy has two plans that grant stock options, equity awards, and incentive awards to key employees of the Entergy subsidiaries. The Equity Ownership Plan is a shareholder-approved stock-based compensation plan. The Equity Awards Plan is a Board-approved stock-based compensation plan. The following table summarizes information about Entergy's stock options awarded under these plans as of December 31, 2004.

Plan	Number of Securities to be Issued Upon Exercise of Outstanding Options	Weighted Average Exercise Price	Number of Securities Remaining Available for Future Issuance (a)
Equity compensation plans approved by security holders	5,327,272	$45.64	5,582,403
Equity compensation plans not approved by security holders	6,982,805	$39.02	- -
Total	12,310,077	$41.88	5,582,403

(a) Effective upon the May 9, 2003 stockholder re-approval of the Equity Ownership Plan, the Board directed that no further awards be issued under the Equity Awards Plan. As of May 9, 2003, 4,076,628 shares were available for issuance under the Equity Awards Plan.

Item 13. Certain Relationships and Related Transactions

            During 2004, T. Baker Smith & Son, Inc. performed land-surveying services for, and received payments of approximately $735,856 from Entergy companies. Mr. Wm. Clifford Smith, a director of Entergy Corporation, is Chairman of the Board of T. Baker Smith & Son, Inc. Mr. Smith's children own 100% of the voting stock of T. Baker Smith & Son, Inc.

            See Item 10, "Directors and Executive Officers of the Registrants," for information on certain relationships and transactions required to be reported under this item.

            Entergy's Code of Business Conduct and Ethics for Employees provides that any waiver of that Code for executive officers, including a waiver of a conflict of interest, can be made only by the Board, or if the Board so chooses, by a committee of independent directors, and must be promptly disclosed to Entergy's shareholders. Entergy's Code of Business Conduct and Ethics for Members of the Board of Directors provides that any waiver of that Code, including any waiver of a conflict of interest, can be made only by the Board, following a recommendation by the Corporate Governance Committee, and must be promptly disclosed to Entergy's shareholders.

Item 14. Principal Accountant Fees and Services (Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

            Aggregate fees billed to Entergy Corporation (consolidated), Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy for the years ended December 31, 2004 and 2003 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, "Deloitte & Touche"), which includes Deloitte Consulting were as follows:

	2004	2003
Entergy Corporation (consolidated)
Audit Fees	$6,289,500	$3,244,750
Audit-Related Fees (a)	950,900	690,665
Total audit and audit-related fees	7,240,400	3,935,415
Tax Fees (b)	62,820	119,802
All Other Fees (c)	-	5,000
Total Fees (d)	$7,303,220	$4,060,217
Entergy Arkansas
Audit Fees	$673,875	$402,200
Audit-Related Fees (a)	110,810	68,963
Total audit and audit-related fees	784,685	471,163
Tax Fees	-	-
All Other Fees (c)	-	-
Total Fees (d)	784,685	$471,163
Entergy Gulf States
Audit Fees	$1,403,875	$432,050
Audit-Related Fees (a)	110,810	79,026
Total audit and audit-related fees	1,514,685	511,076
Tax Fees	-	-
All Other Fees	-	-
Total Fees (d)	$1,514,685	$511,076
Entergy Louisiana
Audit Fees	$718,875	$355,800
Audit-Related Fees (a)	110,810	69,617
Total audit and audit-related fees	829,685	425,417
Tax Fees	-	-
All Other Fees	-	-
Total Fees (d)	$829,685	$425,417

	2004	2003
Entergy Mississippi
Audit Fees	$708,875	$413,300
Audit-Related Fees (a)	110,810	53,204
Total audit and audit-related fees	819,685	466,504
Tax Fees	-	-
All Other Fees	-	-
Total Fees (d)	$819,685	$466,504
Entergy New Orleans
Audit Fees	$708,875	$365,800
Audit-Related Fees (a)	183,710	147,855
Total audit and audit-related fees	892,585	513,655
Tax Fees	-	-
All Other Fees (c)	-	-
Total Fees (d)	$892,585	$513,655
System Energy
Audit Fees	$598,750	$350,200
Audit-Related Fees (a)	38,500	8,800
Total audit and audit-related fees	637,250	359,000
Tax Fees	-	-
All Other Fees	-	-
Total Fees (d)	$637,250	$359,000

(a)	Includes fees for employee benefit plan audits, consultation on financial accounting and reporting, and other attestation services.
(b)	Includes fees for tax return review and tax compliance assistance.
(c)	Includes fees for assistance on regulatory matters. During 2003 the fees for other services were approved under the de minimis provision.
(d)	100% of fees paid in 2004 and 2003 were pre-approved by the Entergy Corporation Audit Committee.

Entergy Audit Committee Guidelines for Pre-approval of Independent Auditor Services

            The Audit Committee has adopted the following guidelines regarding the engagement of Entergy's independent auditor to perform services for Entergy:

1.	The independent auditor will provide the Audit Committee, for approval, an annual engagement letter outlining the scope of services proposed to be performed during the fiscal year, including audit services and other permissible non-audit services (e.g. audit related services, tax services, and all other services).
2.	For other permissible services not included in the engagement letter, Entergy management will submit a description of the proposed service, including a budget estimate, to the Audit Committee for pre-approval. Management and the independent auditor must agree that the requested service is consistent with the SEC's rules on auditor independence prior to submission to the Audit Committee. The Audit Committee, at its discretion, will pre-approve permissible services and has established the following additional guidelines for permissible non-audit services provided by the independent auditor: Aggregate non-audit service fees are targeted at fifty percent or less of the approved audit service fee. All other services should only be provided by the independent auditor if it is the only qualified provider of that service or if the Audit Committee specifically requests the service.
3.	The Audit Committee will be informed quarterly as to the status of pre-approved services actually provided by the independent auditor.
4.	To ensure prompt handling of unexpected matters, the Audit Committee delegates to the Audit Committee Chair or its designee the authority to approve permissible services and fees. The Audit Committee Chair or designee will report action taken to the Audit Committee at the next scheduled Audit Committee meeting.
5.	The Vice President, Risk Management and General Auditor will be responsible for tracking all independent auditor fees and will report quarterly to the Audit Committee.

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)1.	Financial Statements and Independent Auditors' Reports for Entergy, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy are listed in the Table of Contents.
(a)2.	Financial Statement Schedules Independent Auditor's Report on Financial Statement Schedules (see page 400) Financial Statement Schedules are listed in the Index to Financial Statement Schedules (see page S-1)
(a)3.	Exhibits Exhibits for Entergy, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy are listed in the Exhibit Index (see page E-1). Each management contract or compensatory plan or arrangement required to be filed as an exhibit hereto is identified as such by footnote in the Exhibit Index.

ENTERGY CORPORATION

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

ENTERGY CORPORATION


By /s/ Nathan E. Langston
Nathan E. Langston, Senior Vice President
and Chief Accounting Officer

Date: March 9, 2005

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	Title	Date
/s/ Nathan E. Langston Nathan E. Langston	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 9, 2005

J. Wayne Leonard (Chief Executive Officer and Director; Principal Executive Officer); Robert v.d. Luft (Chairman of the Board and Director); Leo P. Denault (Executive Vice President and Chief Financial Officer; Principal Financial Officer); Maureen S. Bateman, W. Frank Blount, Simon deBee, Claiborne P. Deming, Alexis M. Herman, Donald C. Hintz, Kathleen A. Murphy, Paul W. Murrill, James R. Nichols, William A. Percy, II, Dennis H. Reilley, Wm. Clifford Smith, Bismark A. Steinhagen, and Steven V. Wilkinson (Directors).

By: /s/ Nathan E. Langston
(Nathan E. Langston, Attorney-in-fact) March 9, 2005

ENTERGY ARKANSAS, INC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

ENTERGY ARKANSAS, INC.


By /s/ Nathan E. Langston
Nathan E. Langston, Senior Vice President
and Chief Accounting Officer

Date: March 9, 2005

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	Title	Date
/s/ Nathan E. Langston Nathan E. Langston	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 9, 2005

Hugh T. McDonald (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Jay A. Lewis (Vice President, Chief Financial Officer - - Utility Operations Group; Principal Financial Officer); Leo P. Denault, Mark T. Savoff, and Richard J. Smith (Directors).

By: /s/ Nathan E. Langston
(Nathan E. Langston, Attorney-in-fact) March 9, 2005

ENTERGY GULF STATES, INC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

ENTERGY GULF STATES, INC.


By /s/ Nathan E. Langston
Nathan E. Langston, Senior Vice President
and Chief Accounting Officer

Date: March 9, 2005

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	Title	Date
/s/ Nathan E. Langston Nathan E. Langston	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 9, 2005

Joseph F. Domino (Chairman of the Board, President, Chief Executive Officer-Texas, and Director; Principal Executive Officer); E. Renae Conley (President, Chief Executive Officer-Louisiana, and Director; Principal Executive Officer); Jay A. Lewis (Vice President, Chief Financial Officer - - Utility Operations Group; Principal Financial Officer); Leo P. Denault, Mark T. Savoff, and Richard J. Smith (Directors).

By: /s/ Nathan E. Langston
(Nathan E. Langston, Attorney-in-fact) March 9, 2005

ENTERGY LOUISIANA, INC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

ENTERGY LOUISIANA, INC.


By /s/ Nathan E. Langston
Nathan E. Langston, Senior Vice President
and Chief Accounting Officer

Date: March 9, 2005

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	Title	Date
/s/ Nathan E. Langston Nathan E. Langston	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 9, 2005

E. Renae Conley (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Jay A. Lewis (Vice President, Chief Financial Officer - - Utility Operations Group; Principal Financial Officer); Leo P. Denault, Mark T. Savoff, and Richard J. Smith (Directors).

By: /s/ Nathan E. Langston
(Nathan E. Langston, Attorney-in-fact) March 9, 2005

ENTERGY MISSISSIPPI, INC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

ENTERGY MISSISSIPPI, INC.


By /s/ Nathan E. Langston
Nathan E. Langston, Senior Vice President
and Chief Accounting Officer

Date: March 9, 2005

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	Title	Date
/s/ Nathan E. Langston Nathan E. Langston	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 9, 2005

Carolyn C. Shanks (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Jay A. Lewis (Vice President, Chief Financial Officer - - Utility Operations Group; Principal Financial Officer); Leo P. Denault, Mark T. Savoff, and Richard J. Smith (Directors).

By: /s/ Nathan E. Langston
(Nathan E. Langston, Attorney-in-fact) March 9, 2005

ENTERGY NEW ORLEANS, INC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

ENTERGY NEW ORLEANS, INC.


By /s/ Nathan E. Langston
Nathan E. Langston, Senior Vice President
and Chief Accounting Officer

Date: March 9, 2005

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	Title	Date
/s/ Nathan E. Langston Nathan E. Langston	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 9, 2005

Daniel F. Packer (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Jay A. Lewis (Vice President, Chief Financial Officer - - Utility Operations Group; Principal Financial Officer); Leo P. Denault, Mark T. Savoff, and Richard J. Smith (Directors).

By: /s/ Nathan E. Langston
(Nathan E. Langston, Attorney-in-fact) March 9, 2005

SYSTEM ENERGY RESOURCES, INC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

SYSTEM ENERGY RESOURCES, INC.


By /s/ Nathan E. Langston
Nathan E. Langston, Senior Vice President
and Chief Accounting Officer

Date: March 9, 2005

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	Title	Date
/s/ Nathan E. Langston Nathan E. Langston	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 9, 2005

Gary J. Taylor (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Theodore H. Bunting, Jr. (Vice President, Chief Financial Officer - Nuclear Operations; Principal Financial Officer); Leo P. Denault and Steven C. McNeal (Directors).

By: /s/ Nathan E. Langston
(Nathan E. Langston, Attorney-in-fact) March 9, 2005

EXHIBIT 23(a)

CONSENTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Post-Effective Amendments No. 3 and 5A on Form S-8 and their related prospectuses to Registration Statement No. 33-54298 of Entergy Corporation on Form S-4, Registration Statements No. 333-02503 and 333-22007 of Entergy Corporation on Form S-3 and Registration Statements No. 333-55692, 333-68950, 333-75097, 333-90914, and 333-98179 of Entergy Corporation on Form S-8 of our reports dated March 8, 2005, relating to the financial statements (which report expresses an unqualified opinion and includes an explanatory paragraph regarding Entergy Corporation's change in 2003 in the method of accounting for asset retirement obligations and for consolidation of variable interest entities and the change in 2002 in the method of accounting for goodwill and intangible assets), financial statement schedules, and to management's report on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Corporation for the year ended December 31, 2004.

We consent to the incorporation by reference in Registration Statements No. 333-00103, 333-05045, and 333-109453 of Entergy Arkansas, Inc. on Form S-3 of our reports dated March 8, 2005, relating to the financial statements of Entergy Arkansas, Inc. (which report includes an explanatory paragraph regarding Entergy Arkansas, Inc.'s change in 2003 in the method of accounting for asset retirement obligations and for consolidation of variable interest entities), financial statement schedules, and to management's report on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Arkansas, Inc. for the year ended December 31, 2004.

We consent to the incorporation by reference in Registration Statements No. 33-49739, 33-51181, 333-60957, and 333-109923 of Entergy Gulf States, Inc. on Form S-3 of our reports dated March 8, 2005, relating to the financial statements of Entergy Gulf States, Inc. (which report includes an explanatory paragraph regarding Entergy Gulf States, Inc.'s change in 2003 in the method of accounting for asset retirement obligations and for consolidation of variable interest entities), financial statement schedules, and to management's report on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Gulf States, Inc. for the year ended December 31, 2004.

We consent to the incorporation by reference in Registration Statements No. 333-00105, 333-01329, 333-03567, and 333-114174 of Entergy Louisiana, Inc. on Form S-3 of our reports dated March 8, 2005, relating to the financial statements of Entergy Louisiana, Inc. (which report includes an explanatory paragraph regarding Entergy Louisiana, Inc.'s change in 2003 in the method of accounting for asset retirement obligations and for consolidation of variable interest entities), financial statement schedules, and to management's report on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Louisiana, Inc. for the year ended December 31, 2004.

We consent to the incorporation by reference in Registration Statement No. 333-110675 of Entergy Mississippi, Inc. on Form S-3 of our reports dated March 8, 2005, relating to the financial statements of Entergy Mississippi, Inc., financial statement schedules, and to management's report on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Mississippi, Inc. for the year ended December 31, 2004.

We consent to the incorporation by reference in Registration Statement No. 333-113586 of Entergy New Orleans, Inc. on Form S-3 of our reports dated March 8, 2005, relating to the financial statements of Entergy New Orleans, Inc., financial statement schedules, and to management's report on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy New Orleans, Inc. for the year ended December 31, 2004.

We consent to the incorporation by reference in Registration Statements No. 33-47662, 33-61189, and 333-06717 of System Energy Resources, Inc. on Form S-3 of our reports dated March 8, 2005, relating to the financial statements of System Energy Resources, Inc. (which report includes an explanatory paragraph regarding System Energy Resources, Inc.'s change in 2003 in the method of accounting for asset retirement obligations) and to management's report on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of System Energy Resources, Inc. for the year ended December 31, 2004.

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 10, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Entergy Corporation:

We have audited the consolidated financial statements of Entergy Corporation (the "Corporation") and we have also audited the financial statements of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc. (collectively the "Companies"), as of December 31, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, management's assessment of the effectiveness of the Corporation's and the respective Companies' internal control over financial reporting as of December 31, 2004, and the effectiveness of the Corporation's and the respective Companies' internal control over financial reporting as of December 31, 2004, and have issued our reports thereon dated March 8, 2005. Our report on the consolidated financial statements of the Corporation expresses an unqualified opinion and includes an explanatory paragraph regarding its change in 2003 in the method of accounting for a sset retirement obligations and for consolidation of variable interest entities, and its change in 2002 in the method of accounting for goodwill and intangible assets. Our reports on the financial statements of Entergy Arkansas, Inc., Entergy Gulf States, Inc., and Entergy Louisiana, Inc., each express an unqualified opinion and include an explanatory paragraph regarding their change in 2003 in the method of accounting for asset retirement obligations and for consolidation of variable interest entities. The financial statements described above, and our respective reports thereon are included elsewhere in this 2004 Annual Report to Shareholders. Our audits also included the consolidated financial statement schedules of Entergy Corporation and the financial statement schedules of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc., listed in Item 15. These financial statement schedules are the responsibility of the Corporation' s and the respective Companies' managements. Our responsibility is to express an opinion based on our audits. (We did not audit the financial statements of Entergy-Koch, LP, the Corporation's investment in which is accounted for by use of the equity method. The Corporation's equity in earnings of unconsolidated equity affiliates for the year ended December 31, 2003 includes $180,110,000 for Entergy-Koch, LP, which earnings were audited by other auditors whose report, which as to 2003 included an explanatory paragraph concerning a change in accounting for inventory held for trading purposes and energy trading contracts not qualifying as derivatives, has been furnished to us, and our opinion, 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.) In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the i nformation set forth therein.

DELOITTE & TOUCHE LLP

New Orleans, Louisiana
March 8, 2005

INDEX TO FINANCIAL STATEMENT SCHEDULES

Schedule		Page
I	Financial Statements of Entergy Corporation:
	Statements of Income - For the Years Ended December 31, 2004, 2003, and 2002	S-2
	Statements of Cash Flows - For the Years Ended December 31, 2004, 2003, and 2002	S-3
	Balance Sheets, December 31, 2004 and 2003	S-4
	Statements of Retained Earnings, Comprehensive Income, and Paid-In Capital for the Years Ended December 31, 2004, 2003, and 2002	S-5
II	Valuation and Qualifying Accounts 2004, 2003 and 2002:
	Entergy Corporation and Subsidiaries	S-6
	Entergy Arkansas, Inc.	S-7
	Entergy Gulf States, Inc.	S-8
	Entergy Louisiana, Inc.	S-9
	Entergy Mississippi, Inc.	S-10
	Entergy New Orleans, Inc.	S-11

    Schedules other than those listed above are omitted because they are not required, not applicable, or the required information is shown in the financial statements or notes thereto.

    Columns have been omitted from schedules filed because the information is not applicable.

ENTERGY CORPORATION
SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION
STATEMENTS OF INCOME
	For the Years Ended December 31,
	2004	2003	2002
	(In Thousands)
Income:
Equity in income of subsidiaries	$936,961	$945,514	$629,367
Interest on temporary investments	37,859	36,400	46,964
Total	974,820	981,914	676,331
Other Expenses (Income) and Deductions:
Administrative and general expenses	23,643	16,844	41,126
Reimbursement on Subsidiary Stock Option Expenses	(49,481)	(14,419)	- -
Income taxes (credit)	16,544	(7,916)	6,948
Taxes other than income	1,754	753	588
Interest	72,836	59,709	28,309
Total	65,296	54,971	76,971
Net Income	$909,524	$926,943	$599,360
See Entergy Corporation and Subsidiaries Notes to Financial
Statements in Part II, Item 8.

ENTERGY CORPORATION
SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION
STATEMENTS OF CASH FLOWS
	Year to Date December 31,
	2004	2003	2002
	(In Thousands)
Operating Activities:
Net income	$909,524	$926,943	$599,360
Noncash items included in net income:
Equity in earnings of subsidiaries	(936,961)	(945,514)	(629,367)
Deferred income taxes	32,316	(2,811)	(4,803)
Depreciation	237	591	912
Changes in working capital:
Receivables	38,007	(878)	1,430
Payables	(678)	(9,258)	4,898
Other working capital accounts	(237,727)	145,014	(480,711)
Common stock dividends received from subsidiaries	825,022	424,993	618,400
Other	55,811	95,388	68,981
Net cash flow provided by operating activities	685,551	634,468	179,100
Investing Activities:
Investment in subsidiaries	(99,502)	(254,894)	(256,212)
Capital expenditures	(460)	874	(768)
Changes in other temporary investments	10,328	(10,328)	4,782
Other	59,719	(59,719)	103
Net cash flow used in investing activities	(29,915)	(324,067)	(252,095)
Financing Activities:
Changes in credit line borrowings	50,000	(499,975)	245,000
Advances to subsidiaries	(13,312)	(7,254)	(6,460)
Common stock dividends paid	(427,901)	(362,814)	(298,991)
Repurchase of common stock	(1,017,996)	(8,135)	(118,499)
Notes receivable to/from associated companies	510,113	(111,595)	(146,380)
Issuance of common stock	170,237	217,521	130,061
Issuance of long-term debt	- -	534,362	265,330
Net cash flow provided by (used in) financing activities	(728,859)	(237,890)	70,061
Net increase (decrease) in cash and cash equivalents	(73,223)	72,511	(2,934)
Cash and cash equivalents at beginning of period	80,398	7,887	10,821
Cash and cash equivalents at end of period	$7,175	$80,398	$7,887
See Entergy Corporation and Subsidiaries Notes to Financial Statements
in Part II, Item 8.

ENTERGY CORPORATION
SCHEDULE I - FINANCIAL STATEMENTS OF ENTERGY CORPORATION
BALANCE SHEETS
	December 31,
	2004	2003
ASSETS	(In Thousands)
Current Assets:
Cash and cash equivalents:
Temporary cash investments - at cost,
which approximates market	$7,175	$80,398
Total cash and cash equivalents	7,175	80,398
Other temporary investments	-	10,328
Notes receivable - associated companies	116,855	626,968
Accounts receivable - associated companies	8,506	44,639
Other	62,017	53,549
Total	194,553	815,882
Investment in Wholly-owned Subsidiaries	8,734,507	8,607,556
Deferred Debits and Other Assets	556,643	606,760
Total	$9,485,703	$10,030,198
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable:
Associated companies	$2,190	$2,433
Other	1,308	745
Other current liabilities	11,536	188,779
Total	15,034	191,957
Deferred Credits and Noncurrent Liabilities	223,982	234,558
Long-term debt	950,000	900,025
Shareholders' Equity:
Common stock, $.01 par value, authorized
500,000,000 shares; issued 248,174,087 shares
in 2004 and in 2003	2,482	2,482
Paid-in capital	4,835,375	4,767,615
Retained earnings	4,984,302	4,502,508
Accumulated other comprehensive loss	(93,453)	(7,795)
Less cost of treasury stock (31,345,028 shares in
2004 and 19,276,445 shares in 2003)	1,432,019	561,152
Total common shareholders' equity	8,296,687	8,703,658
Total	$9,485,703	$10,030,198
See Entergy Corporation and Subsidiaries Notes to Financial Statements in Part II, Item 8.

ENTERGY CORPORATION
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS, COMPREHENSIVE INCOME, AND PAID-IN CAPITAL
	For the Years Ended December 31,
	2004		2003		2002
	(In Thousands)
RETAINED EARNINGS
Retained Earnings - Beginning of period	$4,502,508		$3,938,693		$3,638,448
Add: Earnings applicable to common stock	909,524	$909,524	926,943	$926,943	599,360	$599,360
Deduct:
Dividends declared on common stock	427,740		362,941		299,031
Capital stock and other expenses	(10)		187		84
Total	427,730		363,128		299,115
Retained Earnings - End of period	$4,984,302		$4,502,508		$3,938,693
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Net of taxes):
Balance at beginning of period:
Accumulated derivative instrument fair value changes	($25,811)		$17,313		($17,973)
Other accumulated comprehensive (loss) items	18,016		(39,673)		(70,821)
Total	(7,795)		(22,360)		(88,794)
Net derivative instrument fair value changes
arising during the period	(115,600)	(115,600)	(43,124)	(43,124)	35,286	35,286
Foreign currency translation adjustments	1,882	1,882	4,169	4,169	65,948	(15,487)
Minimum pension liability adjustment	2,762	2,762	1,153	1,153	(10,489)	(10,489)
Net unrealized investment gains (losses)	25,298	25,298	52,367	52,367	(24,311)	(24,311)
Balance at end of period:
Accumulated derivative instrument fair value changes	($141,411)		($25,811)		17,313
Other accumulated comprehensive (loss) items	47,958		18,016		(39,673)
Total	($93,453)		($7,795)		($22,360)
Comprehensive Income		$823,866		$941,508		$584,359
PAID-IN CAPITAL
Paid-in Capital - Beginning of period	$4,767,615		$4,666,753		$4,662,704
Add:
Common stock issuances related to stock plans	67,760		100,862		4,049
Paid-in Capital - End of period	$4,835,375		$4,767,615		$4,666,753
See Entergy Corporation and Subsidiaries Notes to Financial
Statements in Part II, Item 8.

ENTERGY CORPORATION
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2004, 2003, and 2002
(In Thousands)
Column A	Column B	Column C	Column D	Column E
			Other
		Additions	Changes
			Deductions
	Balance at		from	Balance
	Beginning	Charged to	Provisions	at End
Description	of Period	Income	(Note 1)	of Period
Year ended December 31, 2004
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$25,976	$5,479	$7,697	$23,758
Accumulated Provisions Not
Deducted from Assets:
Property insurance	($123,313)	$49,950	$50,762	($124,125)
Injuries and damages (Note 2)	34,189	667,983	88,739	613,433
Environmental	26,514	26,653	35,729	17,438
Total	($62,610)	$744,586	$175,230	$506,746
Year ended December 31, 2003
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$27,285	$12,598	$13,907	$25,976
Accumulated Provisions Not
Deducted from Assets:
Property insurance	($93,941)	$108,221	$137,593	($123,313)
Injuries and damages (Note 2)	30,629	29,255	25,695	34,189
Environmental	26,488	11,621	11,595	26,514
Total	($36,824)	$149,097	$174,883	($62,610)
Year ended December 31, 2002
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$28,355	$13,024	$14,094	$27,285
Accumulated Provisions Not
Deducted from Assets:
Property insurance	($203,537)	$211,210	$101,614	($93,941)
Injuries and damages (Note 2)	29,385	26,667	25,423	30,629
Environmental	34,802	39,368	47,682	26,488
Total	($139,350)	$277,245	$174,719	($36,824)
___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off.
(2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages.

ENTERGY ARKANSAS, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2004, 2003, and 2002
(In Thousands)
Column A	Column B	Column C	Column D	Column E
			Other
		Additions	Changes
			Deductions
	Balance at		from	Balance
	Beginning	Charged to	Provisions	at End
Description	of Period	Income	(Note 1)	of Period
Year ended December 31, 2004
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$9,020	$3,030	$1,011	$11,039
Accumulated Provisions Not
Deducted from Assets:
Property insurance	($25,283)	$10,476	$14,220	($29,027)
Injuries and damages (Note 2)	3,353	2,849	3,589	2,613
Environmental	1,729	1,761	1,925	1,565
Total	($20,201)	$15,086	$19,734	($24,849)
Year ended December 31, 2003
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$8,031	$2,626	$1,637	$9,020
Accumulated Provisions Not
Deducted from Assets:
Property insurance	($13,789)	$31,452	$42,946	($25,283)
Injuries and damages (Note 2)	2,700	2,950	2,297	3,353
Environmental	1,624	2,280	2,175	1,729
Total	($9,465)	$36,682	$47,418	($20,201)
Year ended December 31, 2002
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$5,837	$2,194	$-	$8,031
Accumulated Provisions Not
Deducted from Assets:
Property insurance	($178,715)	$183,438	$18,512	($13,789)
Injuries and damages (Note 2)	2,890	3,129	3,319	2,700
Environmental	6,910	1,999	7,285	1,624
Total	($168,915)	$188,566	$29,116	($9,465)
___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off.
(2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages.

ENTERGY GULF STATES, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2004, 2003, and 2002
(In Thousands)
Column A	Column B	Column C	Column D	Column E
			Other
		Additions	Changes
			Deductions
	Balance at		from	Balance
	Beginning	Charged to	Provisions	at End
Description	of Period	Income	(Note 1)	of Period
Year ended December 31, 2004
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$4,856	$889	$3,058	$2,687
Accumulated Provisions
Not Deducted from Assets--
Property insurance	($57,353)	$7,673	$7,453	($57,133)
Injuries and damages (Note 2)	11,554	12,288	14,872	8,970
Environmental	14,711	20,201	30,430	4,482
Total	($31,088)	$40,162	$52,755	($43,681)
Year ended December 31, 2003
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$5,893	$4,484	$5,521	$4,856
Accumulated Provisions
Not Deducted from Assets--
Property insurance	($45,287)	$26,988	$39,054	($57,353)
Injuries and damages (Note 2)	8,284	8,805	5,535	11,554
Environmental	15,417	3,319	4,025	14,711
Total	($21,586)	$39,112	$48,614	($31,088)
Year ended December 31, 2002
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$3,696	$3,961	$1,764	$5,893
Accumulated Provisions
Not Deducted from Assets--
Property insurance	($8,721)	$4,486	$41,052	($45,287)
Injuries and damages (Note 2)	6,773	7,684	6,173	8,284
Environmental	18,716	34,296	37,595	15,417
Total	$16,768	$46,466	$84,820	($21,586)
___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off.
(2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages.

ENTERGY LOUISIANA, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2004, 2003, and 2002
(In Thousands)
Column A	Column B	Column C	Column D	Column E
			Other
		Additions	Changes
			Deductions
	Balance at		from	Balance
	Beginning	Charged to	Provisions	at End
Description	of Period	Income	(Note 1)	of Period
Year ended December 31, 2004
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$4,487	$473	$1,825	$3,135
Accumulated Provisions Not
Deducted from Assets:
Property insurance	($40,878)	$20,146	$20,973	($41,705)
Injuries and damages (Note 2)	8,537	6,188	4,329	10,396
Environmental	7,245	2,589	1,770	8,064
Total	($25,096)	$28,923	$27,072	($23,245)
Year ended December 31, 2003
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$4,090	$2,152	$1,755	$4,487
Accumulated Provisions Not
Deducted from Assets:
Property insurance	($39,048)	$36,691	$38,521	($40,878)
Injuries and damages (Note 2)	9,114	5,256	5,833	8,537
Environmental	8,157	2,441	3,353	7,245
Total	($21,777)	$44,388	$47,707	($25,096)
Year ended December 31, 2002
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$2,909	$1,181	$-	$4,090
Accumulated Provisions Not
Deducted from Assets:
Property insurance	($26,575)	$14,064	$26,537	($39,048)
Injuries and damages (Note 2)	9,829	4,750	5,465	9,114
Environmental	8,127	1,843	1,813	8,157
Total	($8,619)	$20,657	$33,815	($21,777)
___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off.
(2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages.

ENTERGY MISSISSIPPI, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2004, 2003, and 2002
(In Thousands)
Column A	Column B	Column C	Column D	Column E
			Other
		Additions	Changes
			Deductions
	Balance at		from	Balance
	Beginning	Charged to	Provisions	at End
Description	of Period	Income	(Note 1)	of Period
Year ended December 31, 2004
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$1,375	$357	$606	$1,126
Accumulated Provisions Not
Deducted from Assets:
Property insurance	($3,481)	$10,916	$4,962	$2,473
Injuries and damages (Note 2)	5,414	2,938	2,803	5,549
Environmental	495	1,236	841	890
Total	$2,428	$15,090	$8,606	$8,912
Year ended December 31, 2003
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$1,633	$587	$845	$1,375
Accumulated Provisions Not
Deducted from Assets:
Property insurance	($2,937)	$12,323	$12,867	($3,481)
Injuries and damages (Note 2)	7,928	7,410	9,924	5,414
Environmental	667	1,482	1,654	495
Total	$5,658	$21,215	$24,445	$2,428
Year ended December 31, 2002
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$1,232	$1,063	$662	$1,633
Accumulated Provisions Not
Deducted from Assets:
Property insurance	$1,279	$8,882	$13,098	($2,937)
Injuries and damages (Note 2)	6,306	5,526	3,904	7,928
Environmental	487	886	706	667
Total	$8,072	$15,294	$17,708	$5,658
___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off.
(2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages.

ENTERGY NEW ORLEANS, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2004, 2003, and 2002
(In Thousands)
Column A	Column B	Column C	Column D	Column E
			Other
		Additions	Changes
			Deductions
	Balance at		from	Balance
	Beginning	Charged to	Provisions	at End
Description	of Period	Income	(Note 1)	of Period
Year ended December 31, 2004
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$3,104	$612	$224	$3,492
Accumulated Provisions Not
Deducted from Assets:
Property insurance	$3,682	$739	$3,154	$1,267
Injuries and damages (Note 2)	4,077	3,231	2,043	5,265
Environmental	663	866	763	766
Total	$8,422	$4,836	$5,960	$7,298
Year ended December 31, 2003
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$4,774	$2,479	$4,149	$3,104
Accumulated Provisions Not
Deducted from Assets:
Property insurance	$7,120	$767	$4,205	$3,682
Injuries and damages (Note 2)	2,603	2,514	1,040	4,077
Environmental	623	428	388	663
Total	$10,346	$3,709	$5,633	$8,422
Year ended December 31, 2002
Accumulated Provisions
Deducted from Assets--
Doubtful Accounts	$4,273	$501	$-	$4,774
Accumulated Provisions Not
Deducted from Assets:
Property insurance	$9,195	$340	$2,415	$7,120
Injuries and damages (Note 2)	3,587	5,578	6,562	2,603
Environmental	562	344	283	623
Total	$13,344	$6,262	$9,260	$10,346
___________
Notes:
(1) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries of amounts previously written off.
(2) Injuries and damages provision is provided to absorb all current expenses as appropriate and for the estimated cost of settling claims for injuries and damages.

EXHIBIT INDEX

The following exhibits indicated by an asterisk preceding the exhibit number are filed herewith. The balance of the exhibits have heretofore been filed with the SEC, respectively, as the exhibits and in the file numbers indicated and are incorporated herein by reference. The exhibits marked with a (+) are management contracts or compensatory plans or arrangements required to be filed herewith and required to be identified as such by Item 14 of Form 10-K. Reference is made to a duplicate list of exhibits being filed as a part of this Form 10-K, which list, prepared in accordance with Item 102 of Regulation S-T of the SEC, immediately precedes the exhibits being physically filed with this Form 10-K.

(3) (i) Articles of Incorporation

Entergy Corporation

(a) -- Certificate of Incorporation of Entergy Corporation dated December 31, 1993 (A-1(a) to Rule 24 Certificate in 70-8059).

System Energy

(b) -- Amended and Restated Articles of Incorporation of System Energy and amendments thereto through April 28, 1989 (A-1(a) to Form U-1 in 70-5399).

Entergy Arkansas

(c) -- Amended and Restated Articles of Incorporation of Entergy Arkansas effective November 12, 1999 (3(i)(c)1 to Form 10-K for the year ended December 31, 1999 in 1-10764).

Entergy Gulf States

(d) -- Restated Articles of Incorporation of Entergy Gulf States effective November 17, 1999 (3(i)(d)1 to Form 10-K for the year ended December 31, 1999 in 1-27031).

Entergy Louisiana

(e) -- Amended and Restated Articles of Incorporation of Entergy Louisiana effective November 15, 1999 (3(a) to Form S-3 in 333-93683).

Entergy Mississippi

(f) -- Amended and Restated Articles of Incorporation of Entergy Mississippi effective November 12, 1999 (3(i)(f)1 to Form 10-K for the year ended December 31, 1999 in 0-320).

Entergy New Orleans

(g) -- Amended and Restated Articles of Incorporation of Entergy New Orleans effective November 15, 1999 (3(a) to Form S-3 in 333-95599).

(3) (ii) By-Laws

(a) --	By-Laws of Entergy Corporation as amended May 13, 2004, and as presently in effect (3(ii)(a) to Form 10-Q for the quarter ended June 30, 2004 in 1-11299).
(b) --	By-Laws of System Energy effective July 6, 1998, and as presently in effect (3(f) to Form 10-Q for the quarter ended June 30, 1998 in 1-9067).
(c) --	By-Laws of Entergy Arkansas effective November 26, 1999, and as presently in effect (3(ii)(c) to Form 10-K for the year ended December 31, 1999 in 1-10764).
(d) --	By-Laws of Entergy Gulf States effective November 26, 1999, and as presently in effect (3(ii)(d) to Form 10-K for the year ended December 31, 19991-27031).
(e) --	By-Laws of Entergy Louisiana effective November 26, 1999, and as presently in effect (3(b) to Form S-3 in File No. 333-93683).
(f) --	By-Laws of Entergy Mississippi effective November 26, 1999, and as presently in effect (3(ii)(f) to Form 10-K for the year ended December 31, 1999 in 0-320).
(g) --	By-Laws of Entergy New Orleans effective November 30, 1999, and as presently in effect (3(b) to Form S-3 in File No. 333-95599).

(4) Instruments Defining Rights of Security Holders, Including Indentures

Entergy Corporation

(a) 1 --	See (4)(b) through (4)(g) below for instruments defining the rights of holders of long-term debt of System Energy, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans.
*(a) 2 --	Credit Agreement, dated as of May 31, 2002, among Entergy Corporation, as Borrower, Bayerische Hypo- und Vereinsbank AG, New York Branch, as Bank, and Bayerische Hypo-und Vereinsbank AG, New York Branch, as Administrative Agent.
*(a) 3 --	First Amendment dated as of June 6, 2003, to the Credit Agreement dated May 31, 2002.
(a) 4 --	Credit Agreement, dated as of November 24, 2003, among Entergy Corporation, as Borrower, Bayerische Hypo-und Vereinsbank AG, New York Branch, as Bank, and Bayerische Hypo-und Vereinsbank AG, New York Branch, as Administrative Agent (4(a)11 to Form 10-K for the year ended December 31, 2003 1-11299).
(a) 5 --	Credit Agreement, dated as of May 13, 2004, among Entergy Corporation, the Banks (Citibank, N.A., ABN AMRO Bank N.V., BNP Paribas, J. P. Morgan Chase Bank, The Royal Bank of Scotland plc, Barclays Bank PLC, Calyon New York Branch, KeyBank National Association, Morgan Stanley Bank, The Bank of New York, Wachovia Bank, N.A., Credit Suisse First Boston (Cayman Islands Branch), Mellon Bank, N.A., Regions Bank, Societe Generale, Union Bank of California, N.A., Bayerische Hypo-und Vereinsbank AG (New York Branch), Deutsche Bank AG New York Branch, KBC Bank N.V., Lehman Brothers Bank, FSB, Mizuho Corporate Bank Limited, The Bank of Nova Scotia, UFJ Bank Limited, and West LB AG, New York Branch, Citibank, N.A., as Administrative Agent and LC Issuing Bank, and ABN AMRO Bank, N.V., as LC Issuing Bank (4(d) to Form 10-Q for the quarter ended June 30, 2004 in 1-11299).
(a) 6 --	Credit Agreement, dated as of December 14, 2004, among Entergy Corporation, the Banks (Citibank, N.A., ABN AMRO Bank N.V., BNP Paribas, J. P. Morgan Chase Bank, The Royal Bank of Scotland plc, Barclays Bank PLC, Calyon New York Branch, KeyBank National Association, Morgan Stanley Bank, The Bank of New York, Wachovia Bank, N.A., Credit Suisse First Boston (Cayman Islands Branch), Mellon Bank, N.A., Regions Bank, Societe Generale, Union Bank of California, N.A., Bayerische Hypo-und Vereinsbank AG (New York Branch), Deutsche Bank AG New York Branch, KBC Bank N.V., Lehman Brothers Bank, FSB, Mizuho Corporate Bank Limited, The Bank of Nova Scotia, and West LB AG, New York Branch, Citibank, N.A., as Administrative Agent and LC Issuing Bank, and ABN AMRO Bank, N.V., as LC Issuing Bank (99 to Form 8-K dated December 20, 2004 in 1-11299).
(a) 7 --	Indenture, dated as of December 1, 2002, between Entergy Corporation and Deutsche Bank Trust Company Americas, as Trustee (10(a)4 to Form 10-K for the year ended December 31, 2002 in 1-11299).
(a) 8 --	Officer' Certificate for Entergy Corporation relating to 7.75% Senior Notes due December 15, 2009 (10(a)5 to Form 10-K for the year ended December 31, 2002 in 1-11299).
(a) 9 --	Officer' Certificate for Entergy Corporation relating to 6.17% Senior Notes due March 15, 2008 (4(c) to Form 10-Q for the quarter ended March 31, 2003 in 1-11299).
(a) 10 --	Officer' Certificate for Entergy Corporation relating to 7.06% Senior Notes due March 15, 2011 (4(d) to Form 10-Q for the quarter ended March 31, 2003 in 1-11299).
(a) 11 --	Officer' Certificate for Entergy Corporation relating to 6.58% Senior Notes due May 15, 2010 (4(d) to Form 10-Q for the quarter ended June 30, 2003 in 1-11299).
(a) 12 --	Officer' Certificate for Entergy Corporation relating to 6.13% Senior Notes due September 15, 2008 (4(a) to Form 10-Q for the quarter ended September 30, 2003 in 1-11299).
(a) 13 --	Officer' Certificate for Entergy Corporation relating to 6.23% Senior Notes due March 15, 2008 (4(a)9 to Form 10-K for the year ended December 31, 2003 in 1-11299).
(a) 14 --	Officer' Certificate for Entergy Corporation relating to 6.90% Senior Notes due November 15, 2010 (4(a)10 to Form 10-K for the year ended December 31, 2003 in 1-11299).

System Energy

(b) 1 --	Mortgage and Deed of Trust, dated as of June 15, 1977, as amended by twenty-two Supplemental Indentures (A-1 in 70-5890 (Mortgage); B and C to Rule 24 Certificate in 70-5890 (First); B to Rule 24 Certificate in 70-6259 (Second); 20(a)-5 to Form 10-Q for the quarter ended June 30, 1981 in 1-3517 (Third); A-1(e)-1 to Rule 24 Certificate in 70-6985 (Fourth); B to Rule 24 Certificate in 70-7021 (Fifth); B to Rule 24 Certificate in 70-7021 (Sixth); A-3(b) to Rule 24 Certificate in 70-7026 (Seventh); A-3(b) to Rule 24 Certificate in 70-7158 (Eighth); B to Rule 24 Certificate in 70-7123 (Ninth); B-1 to Rule 24 Certificate in 70-7272 (Tenth); B-2 to Rule 24 Certificate in 70-7272 (Eleventh); B-3 to Rule 24 Certificate in 70-7272 (Twelfth); B-1 to Rule 24 Certificate in 70-7382 (Thirteenth); B-2 to Rule 24 Certificate in 70-7382 (Fourteenth); A-2(c) to Rule 24 Certificate in 70-7946 (Fifteenth); A-2(c) to Rule 24 Certificate in 70-7946 (Sixteenth); A-2(d) to Rule 24 Certificate in 70-7946 (Seventeenth); A-2(e) to Rule 24 Certificate dated May 4, 1993 in 70-7946 (Eighteenth); A-2(g) to Rule 24 Certificate dated May 6, 1994 in 70-7946 (Nineteenth); A-2(a)(1) to Rule 24 Certificate dated August 8, 1996 in 70-8511 (Twentieth); A-2(a)(2) to Rule 24 Certificate dated August 8, 1996 in 70-8511 (Twenty-first); and A-2(a) to Rule 24 Certificate dated October 4, 2002 in 70-9753 (Twenty-second)).
(b) 2 --	Facility Lease No. 1, dated as of December 1, 1988, between Meridian Trust Company and Stephen M. Carta (Steven Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (1) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-3(d) to Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-3(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182).
(b) 3 --	Facility Lease No. 2, dated as of December 1, 1988 between Meridian Trust Company and Stephen M. Carta (Steven Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (2) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-4(d) Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-4(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182).

Entergy Arkansas

*(c) 1 -- Mortgage and Deed of Trust, dated as of October 1, 1944, as amended by sixty-three Supplemental Indentures (7(d) in 2-5463 (Mortgage); 7(b) in 2-7121 (First); 7(c) in 2-7605 (Second); 7(d) in 2-8100 (Third); 7(a)-4 in 2-8482 (Fourth); 7(a)-5 in 2-9149 (Fifth); 4(a)-6 in 2-9789 (Sixth); 4(a)-7 in 2-10261 (Seventh); 4(a)-8 in 2-11043 (Eighth); 2(b)-9 in 2-11468 (Ninth); 2(b)-10 in 2-15767 (Tenth); D in 70-3952 (Eleventh); D in 70-4099 (Twelfth); 4(d) in 2-23185 (Thirteenth); 2(c) in 2-24414 (Fourteenth); 2(c) in 2-25913 (Fifteenth); 2(c) in 2-28869 (Sixteenth); 2(d) in 2-28869 (Seventeenth); 2(c) in 2-35107 (Eighteenth); 2(d) in 2-36646 (Nineteenth); 2(c) in 2-39253 (Twentieth); 2(c) in 2-41080 (Twenty-first); C-1 to Rule 24 Certificate in 70-5151 (Twenty-second); C-1 to Rule 24 Certificate in 70-5257 (Twenty-third); C to Rule 24 Certificate in 70-5343 (Twenty-fourth); C-1 to Rule 24 Certificate in 70-5404 (Twenty-fifth); C to Rule 24 Certificate in 70-5502 (Twenty-sixth); C-1 to Rule 24 Certificate in 70-5556 (Twenty-seventh); C-1 to Rule 24 Certificate in 70-5693 (Twenty-eighth); C-1 to Rule 24 Certificate in 70-6078 (Twenty-ninth); C-1 to Rule 24 Certificate in 70-6174 (Thirtieth); C-1 to Rule 24 Certificate in 70-6246 (Thirty-first); C-1 to Rule 24 Certificate in 70-6498 (Thirty-second); A-4b-2 to Rule 24 Certificate in 70-6326 (Thirty-third); C-1 to Rule 24 Certificate in 70-6607 (Thirty-fourth); C-1 to Rule 24 Certificate in 70-6650 (Thirty-fifth); C-1 to Rule 24 Certificate dated December 1, 1982 in 70-6774 (Thirty-sixth); C-1 to Rule 24 Certificate dated February 17, 1983 in 70-6774 (Thirty-seventh); A-2(a) to Rule 24 Certificate dated December 5, 1984 in 70-6858 (Thirty-eighth); A-3(a) to Rule 24 Certificate in 70-7127 (Thirty-ninth); A-7 to Rule 24 Certificate in 70-7068 (Fortieth); A-8(b) to Rule 24 Certificate dated July 6, 1989 in 70-7346 (Forty-first); A-8(c) to Rule 24 Certificate dated February 1, 1990 in 70-7346 (Forty-second); 4 to Form 10-Q for the quarter ended September 30, 1990 in 1-10764 (Forty-third); A-2(a) to Rule 24 Certificate dated November 30, 1990 in 70-7802 (Forty-fourth); A-2(b) to Rule 24 Certificate dated January 24, 1991 in 70-7802 (Forty-fifth); 4(d)(2) in 33-54298 (Forty-sixth); 4(c)(2) to Form 10-K for the year ended December 31, 1992 in 1-10764 (Forty-seventh); 4(b) to Form 10-Q for the quarter ended June 30, 1993 in 1-10764 (Forty-eighth); 4(c) to Form 10-Q for the quarter ended June 30, 1993 in 1-10764 (Forty-ninth); 4(b) to Form 10-Q for the quarter ended September 30, 1993 in 1-10764 (Fiftieth); 4(c) to Form 10-Q for the quarter ended September 30, 1993 in 1-10764 (Fifty-first); 4(a) to Form 10-Q for the quarter ended June 30, 1994 in 1-10764 (Fifty-second); C-2 to Form U5S for the year ended December 31, 1995 (Fifty-third); C-2(a) to Form U5S for the year ended December 31, 1996 (Fifty-fourth); 4(a) to Form 10-Q for the quarter ended March 31, 2000 in 1-10764 (Fifty-fifth); 4(a) to Form 10-Q for the quarter ended September 30, 2001 in 1-10764 (Fifty-sixth); C-2(a) to Form U5S for the year ended December 31, 2001 (Fifty-seventh); 4(c)1 to Form 10-K for the year December 31, 2002 in 1-10764 (Fifty-eighth); 4(a) to Form 10-Q for the quarter ended June 30, 2003 in 1-10764 (Fifty-ninth); 4(f) to Form 10-Q for the quarter ended June 30, 2003 in 1-10764 (Sixtieth); 4(h) to Form 10-Q for the quarter ended June 30, 2003 in 1-10764 (Sixty-first); 4(e) to Form 10-Q for the quarter ended September 30, 2004 in 1-10764 (Sixty-second); and (Sixty-third)).

Entergy Gulf States

(d) 1 --	Indenture of Mortgage, dated September 1, 1926, as amended by certain Supplemental Indentures (B-a-I-1 in Registration No. 2-2449 (Mortgage); 7-A-9 in Registration No. 2-6893 (Seventh); B to Form 8-K dated September 1, 1959 (Eighteenth); B to Form 8-K dated February 1, 1966 (Twenty-second); B to Form 8-K dated March 1, 1967 (Twenty-third); C to Form 8-K dated March 1, 1968 (Twenty-fourth); B to Form 8-K dated November 1, 1968 (Twenty-fifth); B to Form 8-K dated April 1, 1969 (Twenty-sixth); 2-A-8 in Registration No. 2-66612 (Thirty-eighth); 4-2 to Form 10-K for the year ended December 31, 1984 in 1-27031 (Forty-eighth); 4-2 to Form 10-K for the year ended December 31, 1988 in 1-27031 (Fifty-second); 4 to Form 10-K for the year ended December 31, 1991 in 1-27031 (Fifty-third); 4 to Form 8-K dated July 29, 1992 in 1-27031 (Fifth-fourth); 4 to Form 10-K dated December 31, 1992 in 1-27031 (Fifty-fifth); 4 to Form 10-Q for the quarter ended March 31, 1993 in 1-27031 (Fifty-sixth); 4-2 to Amendment No. 9 to Registration No. 2-76551 (Fifty-seventh); 4(b) to Form 10-Q for the quarter ended March 31,1999 in 1-27031 (Fifty-eighth); A-2(a) to Rule 24 Certificate dated June 23, 2000 in 70-8721 (Fifty-ninth); A-2(a) to Rule 24 Certificate dated September 10, 2001 in 70-9751 (Sixtieth); A-2(b) to Rule 24 Certificate dated November 18, 2002 in 70-9751 (Sixty-first); A-2(c) to Rule 24 Certificate dated December 6, 2002 in 70-9751 (Sixty-second); A-2(d) to Rule 24 Certificate dated June 16, 2003 in 70-9751 (Sixty-third); A-2(e) to Rule 24 Certificate dated June 27, 2003 in 70-9751 (Sixty-fourth); A-2(f) to Rule 24 Certificate dated July 11, 2003 in 70-9751 (Sixty-fifth); A-2(g) to Rule 24 Certificate dated July 28, 2003 in 70-9751 (Sixty-sixth); A-3(i) to Rule 24 Certificate dated November 4, 2004 in 70-10158 (Sixty-seventh); A-3(ii) to Rule 24 Certificate dated November 23, 2004 in 70-10158 (Sixty-eighth); and A-3(iii) to Rule 24 Certificate dated February 16, 2005 in 70-10158 (Sixty-ninth)).
(d) 2 --	Indenture, dated March 21, 1939, accepting resignation of The Chase National Bank of the City of New York as trustee and appointing Central Hanover Bank and Trust Company as successor trustee (B-a-1-6 in Registration No. 2-4076).
(d) 3 --	Indenture for Unsecured Subordinated Debt Securities relating to Trust Securities, dated as of January 15, 1997 (A-11(a) to Rule 24 Certificate dated February 6, 1997 in 70-8721).
(d) 4 --	Amended and Restated Trust Agreement of Entergy Gulf States Capital I dated January 28, 1997 of Series A Preferred Securities (A-13(a) to Rule 24 Certificate dated February 6, 1997 in 70-8721).
(d) 5 --	Guarantee Agreement between Entergy Gulf States, Inc. (as Guarantor) and The Bank of New York (as Trustee) dated as of January 28, 1997 with respect to Entergy Gulf States Capital I's obligation on its 8.75% Cumulative Quarterly Income Preferred Securities, Series A (A-14(a) to Rule 24 Certificate dated February 6, 1997 in 70-8721).

Entergy Louisiana

(e) 1 --	Mortgage and Deed of Trust, dated as of April 1, 1944, as amended by fifty-nine Supplemental Indentures (7(d) in 2-5317 (Mortgage); 7(b) in 2-7408 (First); 7(c) in 2-8636 (Second); 4(b)-3 in 2-10412 (Third); 4(b)-4 in 2-12264 (Fourth); 2(b)-5 in 2-12936 (Fifth); D in 70-3862 (Sixth); 2(b)-7 in 2-22340 (Seventh); 2(c) in 2-24429 (Eighth); 4(c)-9 in 2-25801 (Ninth); 4(c)-10 in 2-26911 (Tenth); 2(c) in 2-28123 (Eleventh); 2(c) in 2-34659 (Twelfth); C to Rule 24 Certificate in 70-4793 (Thirteenth); 2(b)-2 in 2-38378 (Fourteenth); 2(b)-2 in 2-39437 (Fifteenth); 2(b)-2 in 2-42523 (Sixteenth); C to Rule 24 Certificate in 70-5242 (Seventeenth); C to Rule 24 Certificate in 70-5330 (Eighteenth); C-1 to Rule 24 Certificate in 70-5449 (Nineteenth); C-1 to Rule 24 Certificate in 70-5550 (Twentieth); A-6(a) to Rule 24 Certificate in 70-5598 (Twenty-first); C-1 to Rule 24 Certificate in 70-5711 (Twenty-second); C-1 to Rule 24 Certificate in 70-5919 (Twenty-third); C-1 to Rule 24 Certificate in 70-6102 (Twenty-fourth); C-1 to Rule 24 Certificate in 70-6169 (Twenty-fifth); C-1 to Rule 24 Certificate in 70-6278 (Twenty-sixth); C-1 to Rule 24 Certificate in 70-6355 (Twenty-seventh); C-1 to Rule 24 Certificate in 70-6508 (Twenty-eighth); C-1 to Rule 24 Certificate in 70-6556 (Twenty-ninth); C-1 to Rule 24 Certificate in 70-6635 (Thirtieth); C-1 to Rule 24 Certificate in 70-6834 (Thirty-first); C-1 to Rule 24 Certificate in 70-6886 (Thirty-second); C-1 to Rule 24 Certificate in 70-6993 (Thirty-third); C-2 to Rule 24 Certificate in 70-6993 (Thirty-fourth); C-3 to Rule 24 Certificate in 70-6993 (Thirty-fifth); A-2(a) to Rule 24 Certificate in 70-7166 (Thirty-sixth); A-2(a) in 70-7226 (Thirty-seventh); C-1 to Rule 24 Certificate in 70-7270 (Thirty-eighth); 4(a) to Quarterly Report on Form 10-Q for the quarter ended June 30, 1988 in 1-8474 (Thirty-ninth); A-2(b) to Rule 24 Certificate in 70-7553 (Fortieth); A-2(d) to Rule 24 Certificate in 70-7553 (Forty-first); A-3(a) to Rule 24 Certificate in 70-7822 (Forty-second); A-3(b) to Rule 24 Certificate in 70-7822 (Forty-third); A-2(b) to Rule 24 Certificate in 70-7822 (Forty-fourth); A-3(c) to Rule 24 Certificate in 70-7822 (Forty-fifth); A-2(c) to Rule 24 Certificate dated April 7, 1993 in 70-7822 (Forty-sixth); A-3(d) to Rule 24 Certificate dated June 4, 1993 in 70-7822 (Forth-seventh); A-3(e) to Rule 24 Certificate dated December 21, 1993 in 70-7822 (Forty-eighth); A-3(f) to Rule 24 Certificate dated August 1, 1994 in 70-7822 (Forty-ninth); A-4(c) to Rule 24 Certificate dated September 28, 1994 in 70-7653 (Fiftieth); A-2(a) to Rule 24 Certificate dated April 4, 1996 in 70-8487 (Fifty-first); A-2(a) to Rule 24 Certificate dated April 3, 1998 in 70-9141 (Fifty-second); A-2(b) to Rule 24 Certificate dated April 9, 1999 in 70-9141 (Fifty-third); A-3(a) to Rule 24 Certificate dated July 6, 1999 in 70-9141 (Fifty-fourth); A-2(c) to Rule 24 Certificate dated June 2, 2000 in 70-9141 (Fifty-fifth); A-2(d) to Rule 24 Certificate dated April 4, 2002 in 70-9141 (Fifty-sixth); A-3(a) to Rule 24 Certificate dated March 30, 2004 in 70-10086 (Fifty-seventh); A-3(b) to Rule 24 Certificate dated October 15, 2004 in 70-10086 (Fifty-eighth); and A-3(c) to Rule 24 Certificate dated October 26, 2004 in 70-10086 (Fifty-ninth)).
(e) 2 --	Facility Lease No. 1, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-1 in Registration No. 33-30660), as supplemented by Lease Supplement No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 1, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 2 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474).
(e) 3 --	Facility Lease No. 2, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-2 in Registration No. 33-30660), as supplemented by Lease Supplemental No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 2, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 3 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474).
(e) 4 --	Facility Lease No. 3, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-3 in Registration No. 33-30660), as supplemented by Lease Supplemental No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 3, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 4 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474).

Entergy Mississippi

(f) 1 -- Mortgage and Deed of Trust, dated as of February 1, 1988, as amended by twenty-four Supplemental Indentures (A-2(a)-2 to Rule 24 Certificate in 70-7461 (Mortgage); A-2(b)-2 in 70-7461 (First); A-5(b) to Rule 24 Certificate in 70-7419 (Second); A-4(b) to Rule 24 Certificate in 70-7554 (Third); A-1(b)-1 to Rule 24 Certificate in 70-7737 (Fourth); A-2(b) to Rule 24 Certificate dated November 24, 1992 in 70-7914 (Fifth); A-2(e) to Rule 24 Certificate dated January 22, 1993 in 70-7914 (Sixth); A-2(g) to Form U-1 in 70-7914 (Seventh); A-2(i) to Rule 24 Certificate dated November 10, 1993 in 70-7914 (Eighth); A-2(j) to Rule 24 Certificate dated July 22, 1994 in 70-7914 (Ninth); (A-2(l) to Rule 24 Certificate dated April 21, 1995 in 70-7914 (Tenth); A-2(a) to Rule 24 Certificate dated June 27, 1997 in 70-8719 (Eleventh); A-2(b) to Rule 24 Certificate dated April 16, 1998 in 70-8719 (Twelfth); A-2(c) to Rule 24 Certificate dated May 12, 1999 in 70-8719 (Thirteenth); A-3(a) to Rule 24 Certificate dated June 8, 1999 in 70-8719 (Fourteenth); A-2(d) to Rule 24 Certificate dated February 24, 2000 in 70-8719 (Fifteenth); A-2(a) to Rule 24 Certificate dated February 9, 2001 in 70-9757 (Sixteenth); A-2(b) to Rule 24 Certificate dated October 31, 2002 in 70-9757 (Seventeenth); A-2(c) to Rule 24 Certificate dated December 2, 2002 in 70-9757 (Eighteenth); A-2(d) to Rule 24 Certificate dated February 6, 2003 in 70-9757 (Nineteenth); A-2(e) to Rule 24 Certificate dated April 4, 2003 in 70-9757 (Twentieth); A-2(f) to Rule 24 Certificate dated June 6, 2003 in 70-9757 (Twenty-first); A-3(a) to Rule 24 Certificate dated April 8, 2004 in 70-10157 (Twenty-second); A-3(b) to Rule 24 Certificate dated April 29, 2004 in 70-10157 (Twenty-third); and A-3(c) to Rule 24 Certificate dated October 4, 2004 in 70-10157 (Twenty-fourth)).

Entergy New Orleans

(g) 1 -- Mortgage and Deed of Trust, dated as of May 1, 1987, as amended by thirteen Supplemental Indentures (A-2(c) to Rule 24 Certificate in 70-7350 (Mortgage); A-5(b) to Rule 24 Certificate in 70-7350 (First); A-4(b) to Rule 24 Certificate in 70-7448 (Second); 4(f)4 to Form 10-K for the year ended December 31, 1992 in 0-5807 (Third); 4(a) to Form 10-Q for the quarter ended September 30, 1993 in 0-5807 (Fourth); 4(a) to Form 8-K dated April 26, 1995 in 0-5807 (Fifth); 4(a) to Form 8-K dated March 22, 1996 in 0-5807 (Sixth); 4(b) to Form 10-Q for the quarter ended June 30, 1998 in 0-5807 (Seventh); 4(d) to Form 10-Q for the quarter ended June 30, 2000 in 0-5807 (Eighth); C-5(a) to Form U5S for the year ended December 31, 2000 (Ninth); 4(b) to Form 10-Q for the quarter ended September 30, 2002 in 0-5807 (Tenth); 4(k) to Form 10-Q for the quarter ended June 30, 2003 in 0-5807 (Eleventh); 4(a) to Form 10-Q for the quarter ended September 30, 2004 in 0-5807 (Twelfth); and 4(b) to Form 10-Q for the quarter ended September 30, 2004 in 0-5807 (Thirteenth)).

(10) Material Contracts

Entergy Corporation

(a) 1 --	Agreement, dated April 23, 1982, among certain System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(a) 2 --	Middle South Utilities (now Entergy Corporation) System Agency Agreement, dated December 11, 1970 (5(a)2 in 2-41080).
(a) 3 --	Amendment, dated February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)4 in 2-41080).
(a) 4 --	Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)4 in 2-41080).
(a) 5 --	Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080).
(a) 6 --	Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)5 in 2-41080).
(a) 7 --	Amendment, dated April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517).
(a) 8 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(a)12 for the year ended December 31, 2001 in 1-11299).
*(a) 9 --	Amendment, dated March 1, 2004, to Service Agreement with Entergy Services.
(a) 10 --	Availability Agreement, dated June 21, 1974, among System Energy and certain other System companies (B to Rule 24 Certificate dated June 24, 1974 in 70-5399).
(a) 11 --	First Amendment to Availability Agreement, dated as of June 30, 1977 (B to Rule 24 Certificate dated June 24, 1977 in 70-5399).
(a) 12 --	Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate dated July 1, 1981 in 70-6592).
(a) 13 --	Third Amendment to Availability Agreement, dated as of June 28, 1984 (B-13(a) to Rule 24 Certificate dated July 6, 1984 in 70-6985).
(a) 14 --	Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate dated June 8, 1989 in 70-5399).
(a) 15 --	Eighteenth Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-2 to Rule 24 Certificate dated October 1, 1986 in 70-7272).
(a) 16 --	Nineteenth Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-3 to Rule 24 Certificate dated October 1, 1986 in 70-7272).
(a) 17 --	Twenty-sixth Assignment of Availability Agreement, Consent and Agreement, dated as of October 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(c) to Rule 24 Certificate dated November 2, 1992 in 70-7946).
(a) 18 --	Twenty-seventh Assignment of Availability Agreement, Consent and Agreement, dated as of April 1, 1993, with United States Trust Company of New York and Gerard F. Ganey as Trustees (B-2(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946).
(a) 19 --	Twenty-ninth Assignment of Availability Agreement, Consent and Agreement, dated as of April 1, 1994, with United States Trust Company of New York and Gerard F. Ganey as Trustees (B-2(f) to Rule 24 Certificate dated May 6, 1994 in 70-7946).
(a) 20 --	Thirtieth Assignment of Availability Agreement, Consent and Agreement, dated as of August 1, 1996, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans, and United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(a) to Rule 24 Certificate dated August 8, 1996 in 70-8511).
(a) 21 --	Thirty-first Assignment of Availability Agreement, Consent and Agreement, dated as of August 1, 1996, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, and United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to Rule 24 Certificate dated August 8, 1996 in 70-8511).
(a) 22 --	Thirty-fourth Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 2002, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, The Bank of New York and Douglas J. MacInnes (B-2(a)(1) to Rule 24 Certificate dated October 4, 2001 in 70-9753).
(a) 23 --	Thirty-fifth Assignment of Availability Agreement, Consent and Agreement, dated as of December 22, 2003, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, and Union Bank of California, N.A (10(a)25 to Form 10-K for the year ended December 31, 2003 in 1-11299).
*(a) 24 --	First Amendment to Thirty-fifth Assignment of Availability Agreement, Consent and Agreement, dated as of December 17, 2004.
(a) 25 --	Capital Funds Agreement, dated June 21, 1974, between Entergy Corporation and System Energy (C to Rule 24 Certificate dated June 24, 1974 in 70-5399).
(a) 26 --	First Amendment to Capital Funds Agreement, dated as of June 1, 1989 (B to Rule 24 Certificate dated June 8, 1989 in 70-5399).
(a) 27 --	Eighteenth Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (D-2 to Rule 24 Certificate dated October 1, 1986 in 70-7272).
(a) 28 --	Nineteenth Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (D-3 to Rule 24 Certificate dated October 1, 1986 in 70-7272).
(a) 29 --	Twenty-sixth Supplementary Capital Funds Agreement and Assignment, dated as of October 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(c) to Rule 24 Certificate dated November 2, 1992 in 70-7946).
(a) 30 --	Twenty-seventh Supplementary Capital Funds Agreement and Assignment, dated as of April 1, 1993, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946).
(a) 31 --	Twenty-ninth Supplementary Capital Funds Agreement and Assignment, dated as of April 1, 1994, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(f) to Rule 24 Certificate dated May 6, 1994 in 70-7946).
(a) 32 --	Thirtieth Supplementary Capital Funds Agreement and Assignment, dated as of August 1, 1996, among Entergy Corporation, System Energy and United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(a) to Rule 24 Certificate dated August 8, 1996 in 70-8511).
(a) 33 --	Thirty-first Supplementary Capital Funds Agreement and Assignment, dated as of August 1, 1996, among Entergy Corporation, System Energy and United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(b) to Rule 24 Certificate dated August 8, 1996 in 70-8511).
(a) 34 --	Thirty-fourth Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 2002, among Entergy Corporation, System Energy, The Bank of New York and Douglas J. MacInnes (B-3(a)(1) to Rule 24 Certificate dated October 4, 2002 in 70-9753).
(a) 35 --	Thirty-fifth Supplementary Capital Funds Agreement and Assignment, dated as of December 22, 2003, among Entergy Corporation, System Energy, and Union Bank of California, N.A (10(a)38 to Form 10-K for the year ended December 31, 2003 in 1-11299).
(a) 36 --	First Amendment to Supplementary Capital Funds Agreements and Assignments, dated as of June 1, 1989, by and between Entergy Corporation, System Energy, Deposit Guaranty National Bank, United States Trust Company of New York and Gerard F. Ganey (C to Rule 24 Certificate dated June 8, 1989 in 70-7026).
(a) 37 --	First Amendment to Supplementary Capital Funds Agreements and Assignments, dated as of June 1, 1989, by and between Entergy Corporation, System Energy, United States Trust Company of New York and Gerard F. Ganey (C to Rule 24 Certificate dated June 8, 1989 in 70-7123).
(a) 38 --	First Amendment to Supplementary Capital Funds Agreement and Assignment, dated as of June 1, 1989, by and between Entergy Corporation, System Energy and Chemical Bank (C to Rule 24 Certificate dated June 8, 1989 in 70-7561).
(a) 39 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
(a) 40 --	Joint Construction, Acquisition and Ownership Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B-1(a) in 70-6337), as amended by Amendment No. 1, dated as of May 1, 1980 (B-1(c) in 70-6337) and Amendment No. 2, dated as of October 31, 1980 (1 to Rule 24 Certificate dated October 30, 1981 in 70-6337).
(a) 41 --	Operating Agreement dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337).
(a) 42 --	Assignment, Assumption and Further Agreement No. 1, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561).
(a) 43 --	Assignment, Assumption and Further Agreement No. 2, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561).
(a) 44 --	Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B(3)(a) in 70-6337).
(a) 45 --	Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033).
(a) 46 --	Compromise and Settlement Agreement, dated June 4, 1982, between Texaco, Inc. and Entergy Louisiana (28(a) to Form 8-K dated June 4, 1982 in 1-3517).
(a) 47 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(a) 48 --	First Amendment to Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
(a) 49 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(a) 50 --	Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
(a) 51 --	First Amendment, dated January 1, 1990, to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).
(a) 52 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
(a) 53 --	Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
(a) 54 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
(a) 55 --	Guaranty Agreement between Entergy Corporation and Entergy Arkansas, dated as of September 20, 1990 (B-1(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).
(a) 56 --	Guarantee Agreement between Entergy Corporation and Entergy Louisiana, dated as of September 20, 1990 (B-2(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).
(a) 57 --	Guarantee Agreement between Entergy Corporation and System Energy, dated as of September 20, 1990 (B-3(a) to Rule 24 Certificate dated September 27, 1990 in 70- 7757).
(a) 58 --	Loan Agreement between Entergy Operations and Entergy Corporation, dated as of September 20, 1990 (B-12(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679).
(a) 59 --	Loan Agreement between Entergy Power and Entergy Corporation, dated as of August 28, 1990 (A-4(b) to Rule 24 Certificate dated September 6, 1990 in 70-7684).
(a) 60 --	Loan Agreement between Entergy Corporation and Entergy Systems and Service, Inc., dated as of December 29, 1992 (A-4(b) to Rule 24 Certificate in 70-7947).
+(a) 61 --	Executive Financial Counseling Program of Entergy Corporation and Subsidiaries (10(a)64 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 62 --	Amended and Restated Executive Annual Incentive Plan of Entergy Corporation and Subsidiaries, effective January 1, 2003 (10(b) to Form 10-Q for the quarter ended March 31, 2003 in 1-11299).
+(a) 63 --	Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate dated May 24, 1991 in 70-7831).
+(a) 64 --	Amendment No. 1 to the Equity Ownership Plan of Entergy Corporation and Subsidiaries (10(a)71 to Form 10-K for the year ended December 31, 1992 in 1-3517).
+(a) 65 --	Amended and Restated 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries (10(a) to Form 10-Q for the quarter ended March 31, 2003 in 1-11299).
+(a) 66 --	Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)70 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 67 --	Amendment, effective December 28, 2001, to the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries (10(a)71 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 68 --	Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)72 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 69 --	Amendment, effective December 28, 2001, to the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries (10(a)73 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 70 --	Executive Disability Plan of Entergy Corporation and Subsidiaries (10(a)74 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 71 --	Amended and Restated Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, dated June 10, 2003 (10(d) to Form 10-Q for the quarter ended June 30, 2003 in 1-11299).
+(a) 72 --	Equity Awards Plan of Entergy Corporation and Subsidiaries, effective as of August 31, 2000 (10(a)77 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 73 --	Amendment, effective December 7, 2001, to the Equity Awards Plan of Entergy Corporation and Subsidiaries (10(a)78 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 74 --	Amendment, effective December 10, 2001, to the Equity Awards Plan of Entergy Corporation and Subsidiaries (10(b) to Form 10-Q for the quarter ended March 31, 2002 in 1-11299).
+(a) 75 --	Restatement of System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective as of March 8, 2004 (10(d) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).
*+(a) 76 --	First Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective December 29, 2004.
+(a) 77 --	System Executive Continuity Plan II of Entergy Corporation and Subsidiaries, effective March 8, 2004 (10(e) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).
*+(a) 78 --	First Amendment of the System Executive Continuity Plan II of Entergy Corporation and Subsidiaries, effective December 29, 2004.
+(a) 79 --	Post-Retirement Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)80 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 80 --	Amendment, effective December 28, 2001, to the Post-Retirement Plan of Entergy Corporation and Subsidiaries (10(a)81 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 81 --	Pension Equalization Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)82 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 82 --	Amendment, effective December 28, 2001, to the Pension Equalization Plan of Entergy Corporation and Subsidiaries (10(a)83 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 83 --	Service Recognition Program for Non-Employee Outside Directors of Entergy Corporation and Subsidiaries, effective January 1, 2000 (10(a)84 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 84 --	Executive Income Security Plan of Gulf States Utilities Company, as amended effective March 1, 1991 (10(a)86 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 85 --	System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 1, 2000 (10(a)87 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 86 --	Amendment, effective December 28, 2001, to the System Executive Retirement Plan of Entergy Corporation and Subsidiaries (10(a)88 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 87 --	Retention Agreement effective October 27, 2000 between J. Wayne Leonard and Entergy Corporation (10(a)81 to Form 10-K for the year ended December 31, 2000 in 1-11299).
+(a) 88 --	Amendment to Retention Agreement effective March 8, 2004 between J. Wayne Leonard and Entergy Corporation (10(c) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).
+(a) 89 --	Retention Agreement effective January 22, 2001 between Richard J. Smith and Entergy Services, Inc (10(a)87 to Form 10-K for the year ended December 31, 2000 in 1-11299).
+(a) 90 --	Employment Agreement effective August 7, 2001 between Curt L. Hebert and Entergy Corporation (10(a)97 to Form 10-K for the year ended December 31, 2001 in 1-11299).
+(a) 91 --	Agreement of Limited Partnership of Entergy-Koch, LP among EKLP, LLC, EK Holding I, LLC, EK Holding II, LLC and Koch Energy, Inc. dated January 31, 2001 (10(a)94 to Form 10-K/A for the year ended December 31, 2000 in 1-11299).
+(a) 92 --	Employment Agreement effective April 15, 2003 between Robert D. Sloan and Entergy Services (10(c) to Form 10-Q for the quarter ended June 30, 2003 in 1-11299).
+(a) 93 --	Employment Agreement effective November 24, 2003 between Mark T. Savoff and Entergy Services (10(a)99 to Form 10-K for the year ended December 31, 2003 in 1-11299).
+(a) 94 --	Employment Agreement effective February 9, 1999 between Leo P. Denault and Entergy Services (10(a) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).
+(a) 95 --	Amendment to Employment Agreement effective March 5, 2004 between Leo P. Denault and Entergy Corporation (10(b) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).
+(a) 96 --	Shareholder Approval of Future Severance Agreements Policy, effective March 8, 2004 (10(f) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).
(a) 97 --	Consulting Agreement effective May 4, 2004 between Hintz & Associates, LLC and Entergy Services, Inc. (10(d) to Form 10-Q for the quarter ended June 30, 2004 in 1-11299).
+(a) 98 --	Form of Stock Option Grant Agreement Letter, as of December 31, 2004 (99.1 to Form 8-K dated January 26, 2005 in 1-11299).
+(a) 99 --	Form of Long Term Incentive Plan Performance Unit Grand Letter, as of December 31, 2004 (99.2 to Form 8-K dated January 26, 2005 in 1-11299).
*+(a) 100 --	Summary of Executive Officer and Director Compensation.
*+(a) 101 --	Terms of Restricted Stock Grants for Outside Directors.

System Energy

(b) 1 through (b) 15 -- See 10(a)10 through 10(a)24 above.
(b) 16 through (b) 29 -- See 10(a)25 through 10(a)38 above.
(b) 30 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
(b) 31 --	Joint Construction, Acquisition and Ownership Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B-1(a) in 70-6337), as amended by Amendment No. 1, dated as of May 1, 1980 (B-1(c) in 70-6337) and Amendment No. 2, dated as of October 31, 1980 (1 to Rule 24 Certificate dated October 30, 1981 in 70-6337).
(b) 32 --	Operating Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337).
(b) 33 --	Amended and Restated Installment Sale Agreement, dated as of February 15, 1996, between System Energy and Claiborne County, Mississippi (B-6(a) to Rule 24 Certificate dated March 4, 1996 in 70-8511).
(b) 34 --	Loan Agreement, dated as of October 15, 1998, between System Energy and Mississippi Business Finance Corporation (B-6(b) to Rule 24 Certificate dated November 12, 1998 in 70-8511).
(b) 35 --	Loan Agreement, dated as of May 15, 1999, between System Energy and Mississippi Business Finance Corporation (B-6(c) to Rule 24 Certificate dated June 8, 1999 in 70-8511).
(b) 36 --	Facility Lease No. 1, dated as of December 1, 1988, between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (1) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-3(d) to Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-3(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182).
(b) 37 --	Facility Lease No. 2, dated as of December 1, 1988 between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (2) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-4(d) Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-4(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182).
(b) 38 --	Assignment, Assumption and Further Agreement No. 1, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561).
(b) 39 --	Assignment, Assumption and Further Agreement No. 2, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561).
(b) 40 --	Collateral Trust Indenture, dated as of May 1, 2004, among GG1C Funding Corporation, System Energy, and Deutsche Bank Trust Company Americas, as Trustee (A-3(a) to Rule 24 Certificate dated June 4, 2004 in 70-10182), as supplemented by Supplemental Indenture No. 1 dated May 1, 2004, (A-4(a) to Rule 24 Certificate dated June 4, 2004 in 70-10182).
(b) 41 --	Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B(3)(a) in 70-6337).
(b) 42 --	Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033).
(b) 43 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(b) 44 --	First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
(b) 45 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(b) 46 --	Fuel Lease, dated as of February 24, 1989, between River Fuel Funding Company #3, Inc. and System Energy (B-1(b) to Rule 24 Certificate dated March 3, 1989 in 70-7604).
(b) 47 --	System Energy's Consent, dated January 31, 1995, pursuant to Fuel Lease, dated as of February 24, 1989, between River Fuel Funding Company #3, Inc. and System Energy (B-1(c) to Rule 24 Certificate dated February 13, 1995 in 70-7604).
(b) 48 --	Sales Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (D to Rule 24 Certificate dated June 26, 1974 in 70-5399).
(b) 49 --	Service Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (E to Rule 24 Certificate dated June 26, 1974 in 70-5399).
(b) 50 --	Partial Termination Agreement, dated as of December 1, 1986, between System Energy and Entergy Mississippi (A-2 to Rule 24 Certificate dated January 8, 1987 in 70-5399).
(b) 51 --	Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
(b) 52 --	First Amendment, dated January 1, 1990 to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).
(b) 53 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
(b) 54 --	Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
(b) 55 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
(b) 56 --	Service Agreement with Entergy Services, dated as of July 16, 1974, as amended (10(b)43 to Form 10-K for the year ended December 31, 1988 in 1-9067).
*(b) 57 --	Amendment, dated January 1, 2004, to Service Agreement with Entergy Services.
*(b) 58 --	Amendment, dated March 1, 2004, to Service Agreement with Entergy Services.
(b) 59 --	Operating Agreement between Entergy Operations and System Energy, dated as of June 6, 1990 (B-3(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679).
(b) 60 --	Guarantee Agreement between Entergy Corporation and System Energy, dated as of September 20, 1990 (B-3(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).
(b) 61 --	Letter of Credit and Reimbursement Agreement, dated as of December 22, 2003, among System Energy Resources, Inc., Union Bank of California, N.A., as administrating bank and funding bank, Keybank National Association, as syndication agent, Banc One Capital Markets, Inc., as documentation agent, and the Banks named therein, as Participating Banks (10(b)63 to Form 10-K for the year ended December 31, 2003 in 1-9067).
*(b) 62 --	Amendment to Letter of Credit and Reimbursement Agreement, dated as of December 22, 2003
*(b) 63 --	First Amendment and Consent, dated as of May 3, 2004, to Letter of Credit and Reimbursement Agreement.
(b) 64 --	Second Amendment and Consent, dated as of December 17, 2004, to Letter of Credit and Reimbursement Agreement (99 to Form 8-K dated December 22, 2004 in 1-9067).

Entergy Arkansas

(c) 1 --	Agreement, dated April 23, 1982, among Entergy Arkansas and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a) 1 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(c) 2 --	Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)2 in 2-41080).
(c) 3 --	Amendment, dated February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)4 in 2-41080).
(c) 4 --	Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)4 in 2-41080).
(c) 5 --	Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080).
(c) 6 --	Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)5 in 2-41080).
(c) 7 --	Amendment, dated April 27, 1984, to Service Agreement, with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517).
(c) 8 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(a)12 to Form 10-K for the year ended December 31, 2002 in 1-10764).
*(c) 9 --	Amendment, dated March 1, 2004, to Service Agreement with Entergy Services.
(c) 10 through (c) 24 -- See 10(a)10 through 10(a)24 above.
(c) 25 --	Agreement, dated August 20, 1954, between Entergy Arkansas and the United States of America (SPA)(13(h) in 2-11467).
(c) 26 --	Amendment, dated April 19, 1955, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)2 in 2-41080).
(c) 27 --	Amendment, dated January 3, 1964, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)3 in 2-41080).
(c) 28 --	Amendment, dated September 5, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)4 in 2-41080).
(c) 29 --	Amendment, dated November 19, 1970, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)5 in 2-41080).
(c) 30 --	Amendment, dated July 18, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)6 in 2-41080).
(c) 31 --	Amendment, dated December 27, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)7 in 2-41080).
(c) 32 --	Amendment, dated January 25, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)8 in 2-41080).
(c) 33 --	Amendment, dated October 14, 1971, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)9 in 2-43175).
(c) 34 --	Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)10 in 2-60233).
(c) 35 --	Agreement, dated May 14, 1971, between Entergy Arkansas and the United States of America (SPA) (5(e) in 2-41080).
(c) 36 --	Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated May 14, 1971 (5(e)1 in 2-60233).
(c) 37 --	Contract, dated May 28, 1943, Amendment to Contract, dated July 21, 1949, and Supplement to Amendment to Contract, dated December 30, 1949, between Entergy Arkansas and McKamie Gas Cleaning Company; Agreements, dated as of September 30, 1965, between Entergy Arkansas and former stockholders of McKamie Gas Cleaning Company; and Letter Agreement, dated June 22, 1966, by Humble Oil & Refining Company accepted by Entergy Arkansas on June 24, 1966 (5(k)7 in 2-41080).
(c) 38 --	Fuel Lease, dated as of December 22, 1988, between River Fuel Trust #1 and Entergy Arkansas (B-1(b) to Rule 24 Certificate in 70-7571).
(c) 39 --	White Bluff Operating Agreement, dated June 27, 1977, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas (B-2(a) to Rule 24 Certificate dated June 30, 1977 in 70-6009).
(c) 40 --	White Bluff Ownership Agreement, dated June 27, 1977, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas (B-1(a) to Rule 24 Certificate dated June 30, 1977 in 70-6009).
(c) 41 --	Agreement, dated June 29, 1979, between Entergy Arkansas and City of Conway, Arkansas (5(r)3 in 2-66235).
(c) 42 --	Transmission Agreement, dated August 2, 1977, between Entergy Arkansas and City Water and Light Plant of the City of Jonesboro, Arkansas (5(r)3 in 2-60233).
(c) 43 --	Power Coordination, Interchange and Transmission Service Agreement, dated as of June 27, 1977, between Arkansas Electric Cooperative Corporation and Entergy Arkansas (5(r)4 in 2-60233).
(c) 44 --	Independence Steam Electric Station Operating Agreement, dated July 31, 1979, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas and City of Conway, Arkansas (5(r)6 in 2-66235).
(c) 45 --	Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c)51 to Form 10-K for the year ended December 31, 1984 in 1-10764).
(c) 46 --	Independence Steam Electric Station Ownership Agreement, dated July 31, 1979, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas and City of Conway, Arkansas (5(r)7 in 2-66235).
(c) 47 --	Amendment, dated December 28, 1979, to the Independence Steam Electric Station Ownership Agreement (5(r)7(a) in 2-66235).
(c) 48 --	Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c)54 to Form 10-K for the year ended December 31, 1984 in 1-10764).
(c) 49 --	Owner's Agreement, dated November 28, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station (10(c)55 to Form 10-K for the year ended December 31, 1984 in 1-10764).
(c) 50 --	Consent, Agreement and Assumption, dated December 4, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station and United States Trust Company of New York, as Trustee (10(c)56 to Form 10-K for the year ended December 31, 1984 in 1-10764).
(c) 51 --	Power Coordination, Interchange and Transmission Service Agreement, dated as of July 31, 1979, between Entergy Arkansas and City Water and Light Plant of the City of Jonesboro, Arkansas (5(r)8 in 2-66235).
(c) 52 --	Power Coordination, Interchange and Transmission Agreement, dated as of June 29, 1979, between City of Conway, Arkansas and Entergy Arkansas (5(r)9 in 2-66235).
(c) 53 --	Agreement, dated June 21, 1979, between Entergy Arkansas and Reeves E. Ritchie (10(b)90 to Form 10-K for the year ended December 31, 1980 in 1-10764).
(c) 54 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
(c) 55 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(c) 56 --	First Amendment to Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
(c) 57 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(c) 58 --	Contract For Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste, dated June 30, 1983, among the DOE, System Fuels and Entergy Arkansas (10(b)57 to Form 10-K for the year ended December 31, 1983 in 1-10764).
(c) 59 --	Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
(c) 60 --	First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).
(c) 61 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
(c) 62 --	Third Amendment dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
(c) 63 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
(c) 64 --	Assignment of Coal Supply Agreement, dated December 1, 1987, between System Fuels and Entergy Arkansas (B to Rule 24 letter filing dated November 10, 1987 in 70-5964).
(c) 65 --	Coal Supply Agreement, dated December 22, 1976, between System Fuels and Antelope Coal Company (B-1 in 70-5964), as amended by First Amendment (A to Rule 24 Certificate in 70-5964); Second Amendment (A to Rule 24 letter filing dated December 16, 1983 in 70-5964); and Third Amendment (A to Rule 24 letter filing dated November 10, 1987 in 70-5964).
(c) 66 --	Operating Agreement between Entergy Operations and Entergy Arkansas, dated as of June 6, 1990 (B-1(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679).
(c) 67 --	Guaranty Agreement between Entergy Corporation and Entergy Arkansas, dated as of September 20, 1990 (B-1(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).
(c) 68 --	Agreement for Purchase and Sale of Independence Unit 2 between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-3(c) to Rule 24 Certificate dated September 6, 1990 in 70-7684).
(c) 69 --	Agreement for Purchase and Sale of Ritchie Unit 2 between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-4(d) to Rule 24 Certificate dated September 6, 1990 in 70-7684).
(c) 70 --	Ritchie Steam Electric Station Unit No. 2 Operating Agreement between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-5(a) to Rule 24 Certificate dated September 6, 1990 in 70-7684).
(c) 71 --	Ritchie Steam Electric Station Unit No. 2 Ownership Agreement between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-6(a) to Rule 24 Certificate dated September 6, 1990 in 70-7684).
(c) 72 --	Power Coordination, Interchange and Transmission Service Agreement between Entergy Power and Entergy Arkansas, dated as of August 28, 1990 (10(c)71 to Form 10-K for the year ended December 31, 1990 in 1-10764).
(c) 73 --	Loan Agreement dated June 15, 1993, between Entergy Arkansas and Independence Country, Arkansas (B-1(a) to Rule 24 Certificate dated July 9, 1993 in 70-8171).
(c) 74 --	Loan Agreement dated June 15, 1994, between Entergy Arkansas and Jefferson County, Arkansas (B-1(a) to Rule 24 Certificate dated June 30, 1994 in 70-8405).
(c) 75 --	Loan Agreement dated June 15, 1994, between Entergy Arkansas and Pope County, Arkansas (B-1(b) to Rule 24 Certificate in 70-8405).
(c) 76 --	Loan Agreement dated November 15, 1995, between Entergy Arkansas and Pope County, Arkansas (10(c)96 to Form 10-K for the year ended December 31, 1995 in 1-10764).
(c) 77 --	Loan Agreement dated December 1, 1997, between Entergy Arkansas and Jefferson County, Arkansas (10(c)100 to Form 10-K for the year ended December 31, 1997 in 1-10764).
(c) 78 --	Refunding Agreement, dated December 1, 2001, between Entergy Arkansas and Pope Country, Arkansas (10(c)81 to Form 10-K for the year ended December 31, 2001 in 1-10764).

Entergy Gulf States

(d) 1 --	Guaranty Agreement, dated August 1, 1992, between Entergy Gulf States and Hibernia National Bank, relating to Pollution Control Revenue Refunding Bonds of the Industrial Development Board of the Parish of Calcasieu, Inc. (Louisiana) (10-1 to Form 10-K for the year ended December 31, 1992 in 1-27031).
(d) 2 --	Guaranty Agreement, dated January 1, 1993, between Entergy Gulf States and Hancock Bank of Louisiana, relating to Pollution Control Revenue Refunding Bonds of the Parish of Pointe Coupee (Louisiana) (10-2 to Form 10-K for the year ended December 31, 1992 in 1-27031).
(d) 3 --	Deposit Agreement, dated as of December 1, 1983 between Entergy Gulf States, Morgan Guaranty Trust Co. as Depositary and the Holders of Depository Receipts, relating to the Issue of 900,000 Depositary Preferred Shares, each representing 1/2 share of Adjustable Rate Cumulative Preferred Stock, Series E-$100 Par Value (4-17 to Form 10-K for the year ended December 31, 1983 in 1-27031).
(d) 4 --	Agreement effective February 1, 1964, between Sabine River Authority, State of Louisiana, and Sabine River Authority of Texas, and Entergy Gulf States, Central Louisiana Electric Company, Inc., and Louisiana Power & Light Company, as supplemented (B to Form 8-K dated May 6, 1964, A to Form 8-K dated October 5, 1967, A to Form 8-K dated May 5, 1969, and A to Form 8-K dated December 1, 1969 in 1-27031).
(d) 5 --	Joint Ownership Participation and Operating Agreement regarding River Bend Unit 1 Nuclear Plant, dated August 20, 1979, between Entergy Gulf States, Cajun, and SRG&T; Power Interconnection Agreement with Cajun, dated June 26, 1978, and approved by the REA on August 16, 1979, between Entergy Gulf States and Cajun; and Letter Agreement regarding CEPCO buybacks, dated August 28, 1979, between Entergy Gulf States and Cajun (2, 3, and 4, respectively, to Form 8-K dated September 7, 1979 in 1-27031).
(d) 6 --	Ground Lease, dated August 15, 1980, between Statmont Associates Limited Partnership (Statmont) and Entergy Gulf States, as amended (3 to Form 8-K dated August 19, 1980 and A-3-b to Form 10-Q for the quarter ended September 30, 1983 in 1-27031).
(d) 7 --	Lease and Sublease Agreement, dated August 15, 1980, between Statmont and Entergy Gulf States, as amended (4 to Form 8-K dated August 19, 1980 and A-3-c to Form 10-Q for the quarter ended September 30, 1983 in 1-27031).
(d) 8 --	Lease Agreement, dated September 18, 1980, between BLC Corporation and Entergy Gulf States (1 to Form 8-K dated October 6, 1980 in 1-27031).
(d) 9 --	Joint Ownership Participation and Operating Agreement for Big Cajun, between Entergy Gulf States, Cajun Electric Power Cooperative, Inc., and Sam Rayburn G&T, Inc, dated November 14, 1980 (6 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 1, dated December 12, 1980 (7 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 2, dated December 29, 1980 (8 to Form 8-K dated January 29, 1981 in 1-27031).
(d) 10 --	Agreement of Joint Ownership Participation between SRMPA, SRG&T and Entergy Gulf States, dated June 6, 1980, for Nelson Station, Coal Unit #6, as amended (8 to Form 8-K dated June 11, 1980, A-2-b to Form 10-Q for the quarter ended June 30, 1982; and 10-1 to Form 8-K dated February 19, 1988 in 1-27031).
(d) 11 --	Agreements between Southern Company and Entergy Gulf States, dated February 25, 1982, which cover the construction of a 140-mile transmission line to connect the two systems, purchase of power and use of transmission facilities (10-31 to Form 10-K for the year ended December 31, 1981 in 1-27031).
(d) 12 --	Transmission Facilities Agreement between Entergy Gulf States and Mississippi Power Company, dated February 28, 1982, and Amendment, dated May 12, 1982 (A-2-c to Form 10-Q for the quarter ended March 31, 1982 in 1-27031) and Amendment, dated December 6, 1983 (10-43 to Form 10-K for the year ended December 31, 1983 in 1-27031).
(d) 13 --	First Amended Power Sales Agreement, dated December 1, 1985 between Sabine River Authority, State of Louisiana, and Sabine River Authority, State of Texas, and Entergy Gulf States, Central Louisiana Electric Co., Inc., and Louisiana Power and Light Company (10-72 to Form 10-K for the year ended December 31, 1985 in 1-27031).
+(d) 14 --	Deferred Compensation Plan for Directors of Entergy Gulf States and Varibus Corporation, as amended January 8, 1987, and effective January 1, 1987 (10-77 to Form 10-K for the year ended December 31, 1986 in 1-27031). Amendment dated December 4, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551).
+(d) 15 --	Trust Agreement for Deferred Payments to be made by Entergy Gulf States pursuant to the Executive Income Security Plan, by and between Entergy Gulf States and Bankers Trust Company, effective November 1, 1986 (10-78 to Form 10-K for the year ended December 31, 1986 in 1-27031).
+(d) 16 --	Trust Agreement for Deferred Installments under Entergy Gulf States' Management Incentive Compensation Plan and Administrative Guidelines by and between Entergy Gulf States and Bankers Trust Company, effective June 1, 1986 (10-79 to Form 10-K for the year ended December 31, 1986 in 1-27031).
+(d) 17 --	Nonqualified Deferred Compensation Plan for Officers, Nonemployee Directors and Designated Key Employees, effective December 1, 1985, as amended, continued and completely restated effective as of March 1, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551).
+(d) 18 --	Trust Agreement for Entergy Gulf States' Nonqualified Directors and Designated Key Employees by and between Entergy Gulf States and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective July 1, 1991 (10-4 to Form 10-K for the year ended December 31, 1992 in 1-27031).
(d) 19 --	Lease Agreement, dated as of June 29, 1987, among GSG&T, Inc., and Entergy Gulf States related to the leaseback of the Lewis Creek generating station (10-83 to Form 10-K for the year ended December 31, 1988 in 1-27031).
(d) 20 --	Nuclear Fuel Lease Agreement between Entergy Gulf States and River Bend Fuel Services, Inc. to lease the fuel for River Bend Unit 1, dated February 7, 1989 (10-64 to Form 10-K for the year ended December 31, 1988 in 1-27031).
(d) 21 --	Trust and Investment Management Agreement between Entergy Gulf States and Morgan Guaranty and Trust Company of New York (the "Decommissioning Trust Agreement) with respect to decommissioning funds authorized to be collected by Entergy Gulf States, dated March 15, 1989 (10-66 to Form 10-K for the year ended December 31, 1988 in 1-27031).
(d) 22 --	Amendment No. 2 dated November 1, 1995 between Entergy Gulf States and Mellon Bank to Decommissioning Trust Agreement (10(d)31 to Form 10-K for the year ended December 31, 1995 in 1-27031).
*(d) 23 --	Amendment No. 3 dated March 5, 1998 between Entergy Gulf States and Mellon Bank to Decommissioning Trust Agreement.
*(d) 24 --	Amendment No. 4 dated December 17, 2003 between Entergy Gulf States and Mellon Bank to Decommissioning Trust Agreement.
(d) 25 --	Partnership Agreement by and among Conoco Inc., and Entergy Gulf States, CITGO Petroleum Corporation and Vista Chemical Company, dated April 28, 1988 (10-67 to Form 10-K for the year ended December 31, 1988 in 1-27031).
+(d) 26 --	Gulf States Utilities Company Executive Continuity Plan, dated January 18, 1991 (10-6 to Form 10-K for the year ended December 31, 1990 in 1-27031).
+(d) 27 --	Trust Agreement for Entergy Gulf States' Executive Continuity Plan, by and between Entergy Gulf States and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective May 20, 1991 (10-5 to Form 10-K for the year ended December 31, 1992 in 1-27031).
+(d) 28 --	Gulf States Utilities Board of Directors' Retirement Plan, dated February 15, 1991 (10-8 to Form 10-K for the year ended December 31, 1990 in 1-27031).
(d) 29 --	Operating Agreement between Entergy Operations and Entergy Gulf States, dated as of December 31, 1993 (B-2(f) to Rule 24 Certificate in 70-8059).
(d) 30 --	Guarantee Agreement between Entergy Corporation and Entergy Gulf States, dated as of December 31, 1993 (B-5(a) to Rule 24 Certificate in 70-8059).
(d) 31 --	Service Agreement with Entergy Services, dated as of December 31, 1993 (B-6(c) to Rule 24 Certificate in 70-8059).
(d) 32 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(d)31 to Form 10-K for the year ended December 31, 2002 in 1-27031).
*(d) 33 --	Amendment, dated March 1, 2004, to Service Agreement with Entergy Services.
(d) 34 --	Third Amendment, dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
(d) 35 --	Fourth Amendment, dated April 1, 1997, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
(d) 36 --	Agreement as to Expenses and Liabilities between Entergy Gulf States and Entergy Gulf States Capital I, dated as of January 28, 1997 (10(d)52 to Form 10-K for the year ended December 31, 1996 in 1-27031).
(d) 37 --	Refunding Agreement dated as of May 1, 1998 between Entergy Gulf States and Parish of Iberville, State of Louisiana (B-3(a) to Rule 24 Certificate dated May 29, 1998 in 70-8721).
(d) 38 --	Refunding Agreement dated as of May 1, 1998 between Entergy Gulf States and Industrial Development Board of the Parish of Calcasieu, Inc. (B-3(b) to Rule 24 Certificate dated January 29, 1999 in 70-8721).
(d) 39 --	Refunding Agreement (Series 1999-A) dated as of September 1, 1999 between Entergy Gulf States and Parish of West Feliciana, State of Louisiana (B-3(c) to Rule 24 Certificate dated October 8, 1999 in 70-8721).
(d) 40 --	Refunding Agreement (Series 1999-B) dated as of September 1, 1999 between Entergy Gulf States and Parish of West Feliciana, State of Louisiana (B-3(d) to Rule 24 Certificate dated October 8, 1999 in 70-8721).

Entergy Louisiana

(e) 1 --	Agreement, dated April 23, 1982, among Entergy Louisiana and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982, in 1-3517).
(e) 2 --	Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)2 in 2-41080).
(e) 3 --	Amendment, dated as of February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)4 in 2-41080).
(e) 4 --	Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)4 in 2-41080).
(e) 5 --	Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080).
(e) 6 --	Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)5 in 2-42523).
(e) 7 --	Amendment, dated as of April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517).
(e) 8 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(e)12 to Form 10-K for the year ended December 31, 2002 in 1-8474).
*(e) 9 --	Amendment, dated March 1, 2004, to Service Agreement with Entergy Services.
(e) 10 through (e) 24 -- See 10(a)10 through 10(a)24 above.
(e) 25 --	Fuel Lease, dated as of January 31, 1989, between River Fuel Company #2, Inc., and Entergy Louisiana (B-1(b) to Rule 24 Certificate in 70-7580).
(e) 26 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
(e) 27 --	Compromise and Settlement Agreement, dated June 4, 1982, between Texaco, Inc. and Entergy Louisiana (28(a) to Form 8-K dated June 4, 1982 in 1-8474).
(e) 28 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(e) 29 --	First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
(e) 30 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(e) 31 --	Middle South Utilities, Inc. and Subsidiary Companies Intercompany Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
(e) 32 --	First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated January 1, 1990 (D-2 to Form U5S for the year ended December 31, 1989).
(e) 33 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
(e) 34 --	Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
(e) 35 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
(e) 36 --	Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste, dated February 2, 1984, among DOE, System Fuels and Entergy Louisiana (10(d)33 to Form 10-K for the year ended December 31, 1984 in 1-8474).
(e) 37 --	Operating Agreement between Entergy Operations and Entergy Louisiana, dated as of June 6, 1990 (B-2(c) to Rule 24 Certificate dated June 15, 1990 in 70-7679).
(e) 38 --	Guarantee Agreement between Entergy Corporation and Entergy Louisiana, dated as of September 20, 1990 (B-2(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).
(e) 39 --	Installment Sale Agreement, dated July 20, 1994, between Entergy Louisiana and St. Charles Parish, Louisiana (B-6(e) to Rule 24 Certificate dated August 1, 1994 in 70-7822).
(e) 40 --	Installment Sale Agreement, dated November 1, 1995, between Entergy Louisiana and St. Charles Parish, Louisiana (B-6(a) to Rule 24 Certificate dated December 19, 1995 in 70-8487).
(e) 41 --	Refunding Agreement (Series 1999-A), dated as of June 1, 1999, between Entergy Louisiana and Parish of St. Charles, State of Louisiana (B-6(a) to Rule 24 Certificate dated July 6, 1999 in 70-9141).
(e) 42 --	Refunding Agreement (Series 1999-B), dated as of June 1, 1999, between Entergy Louisiana and Parish of St. Charles, State of Louisiana (B-6(b) to Rule 24 Certificate dated July 6, 1999 in 70-9141).
(e) 43 --	Refunding Agreement (Series 1999-C), dated as of October 1, 1999, between Entergy Louisiana and Parish of St. Charles, State of Louisiana (B-11(a) to Rule 24 Certificate dated October 15, 1999 in 70-9141).

Entergy Mississippi

(f) 1 --	Agreement dated April 23, 1982, among Entergy Mississippi and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(f) 2 --	Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)2 in 2-41080).
(f) 3 --	Amendment, dated February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)4 in 2-41080).
(f) 4 --	Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)4 in 2-41080).
(f) 5 --	Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080).
(f) 6 --	Service Agreement with Entergy Services, dated as of April 1, 1963 (D in 37-63).
(f) 7 --	Amendment, dated April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517).
(f) 8 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(f)12 to Form 10-K for the year ended December 31, 2002 in 1-31508).
*(f) 9 --	Amendment, dated March 1, 2004, to Service Agreement with Entergy Services.
(f) 10 through (f) 24 -- See 10(a)10 through 10(a)24 above.
(f) 25 --	Loan Agreement, dated as of September 1, 2004, between Entergy Mississippi and Mississippi Business Finance Corporation (B-3(a) to Rule 24 Certificate dated October 4, 2004 in 70-10157).
(f) 26 --	Refunding Agreement, dated as of May 1, 1999, between Entergy Mississippi and Independence County, Arkansas (B-6(a) to Rule 24 Certificate dated June 8, 1999 in 70-8719).
(f) 27 --	Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B-3(a) in 70-6337).
(f) 28 --	Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c)51 to Form 10-K for the year ended December 31, 1984 in 0-375).
(f) 29 --	Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c)54 to Form 10-K for the year ended December 31, 1984 in 0-375).
(f) 30 --	Owners Agreement, dated November 28, 1984, among Entergy Arkansas, Entergy Mississippi and other co-owners of the Independence Station (10(c)55 to Form 10-K for the year ended December 31, 1984 in 0-375).
(f) 31 --	Consent, Agreement and Assumption, dated December 4, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station and United States Trust Company of New York, as Trustee (10(c)56 to Form 10-K for the year ended December 31, 1984 in 0-375).
(f) 32 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
+(f) 33 --	Post-Retirement Plan (10(d)24 to Form 10-K for the year ended December 31, 1983 in 0-320).
(f) 34 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(f) 35 --	First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
(f) 36 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(f) 37 --	Sales Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (D to Rule 24 Certificate dated June 26, 1974 in 70-5399).
(f) 38 --	Service Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (E to Rule 24 Certificate dated June 26, 1974 in 70-5399).
(f) 39 --	Partial Termination Agreement, dated as of December 1, 1986, between System Energy and Entergy Mississippi (A-2 to Rule 24 Certificate dated January 8, 1987 in 70-5399).
(f) 40 --	Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
(f) 41 --	First Amendment dated January 1, 1990 to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).
(f) 42 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
(f) 43 --	Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
(f) 44 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).
+(f) 45 --	Employment Agreement effective July 24, 2003 between Carolyn C. Shanks and Entergy Mississippi (10(f)48 to Form 10-K for the year ended December 31, 2003 in 1-31508).

Entergy New Orleans

(g) 1 --	Agreement, dated April 23, 1982, among Entergy New Orleans and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(g) 2 --	Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)2 in 2-41080).
(g) 3 --	Amendment dated as of February 10, 1971, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)4 in 2-41080).
(g) 4 --	Amendment, dated May 12, 1988, to Middle South Utilities System Agency Agreement, dated December 11, 1970 (5(a)4 in 2-41080).
(g) 5 --	Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080).
(g) 6 --	Service Agreement with Entergy Services dated as of April 1, 1963 (5(a)5 in 2-42523).
(g) 7 --	Amendment, dated as of April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517).
(g) 8 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(g)12 to Form 10-K for the year ended December 31, 2002 in 0-5807).
*(g) 9 --	Amendment, dated March 1, 2004, to Service Agreement with Entergy Services.
(g) 10 through (g) 24 -- See 10(a)10 through 10(a)24 above.
(g) 25 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).
(g) 26 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).
(g) 27 --	First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).
(g) 28 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).
(g) 29 --	Transfer Agreement, dated as of June 28, 1983, among the City of New Orleans, Entergy New Orleans and Regional Transit Authority (2(a) to Form 8-K dated June 24, 1983 in 1-1319).
(g) 30 --	Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).
(g) 31 --	First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).
(g) 32 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).
(g) 33 --	Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).
(g) 34 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).

(12) Statement Re Computation of Ratios

*(a)	Entergy Arkansas' Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.
*(b)	Entergy Gulf States' Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.
*(c)	Entergy Louisiana's Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.
*(d)	Entergy Mississippi's Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.
*(e)	Entergy New Orleans' Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.
*(f)	System Energy's Computation of Ratios of Earnings to Fixed Charges, as defined.

*(21) Subsidiaries of the Registrants

(23) Consents of Experts and Counsel

*(a)	The consent of Deloitte & Touche LLP is contained herein at page 398.
*(b)	Consent of Ernst & Young LLP.

*(24) Powers of Attorney

(31) Rule 13a-14(a)/15d-14(a) Certifications

*(a)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation.
*(b)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation.
*(c)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas.
*(d)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Gulf States.
*(e)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Gulf States and Entergy Louisiana.
*(f)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi.
*(g)	Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans.
*(h)	Rule 13a-14(a)/15d-14(a) Certification for System Energy.
*(i)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans.
*(j)	Rule 13a-14(a)/15d-14(a) Certification for System Energy.

(32) Section 1350 Certifications

*(a)	Section 1350 Certification for Entergy Corporation.
*(b)	Section 1350 Certification for Entergy Corporation.
*(c)	Section 1350 Certification for Entergy Arkansas.
*(d)	Section 1350 Certification for Entergy Gulf States.
*(e)	Section 1350 Certification for Entergy Gulf States and Entergy Louisiana.
*(f)	Section 1350 Certification for Entergy Mississippi.
*(g)	Section 1350 Certification for Entergy New Orleans.
*(h)	Section 1350 Certification for System Energy.
*(i)	Section 1350 Certification for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans.
*(j)	Section 1350 Certification for System Energy.

(99) Additional Exhibits

*(a) Entergy-Koch, LP Financial Statements for the years 2004, 2003, and 2002.

_________________
* Filed herewith.
+ Management contracts or compensatory plans or arrangements.

EX-4

Exhibit 4(a)2

U.S. $60,000,000

CREDIT AGREEMENT

Dated as May 31, 2002

Among

ENTERGY CORPORATION

as Borrower

THE BANKS NAMED HEREIN

as Banks

BAYERISCHE HYPO- UND VEREINSBANK AG, NEW YORK BRANCH

as Administrative Agent

BAYERISCHE HYPO- UND VEREINSBANK AG, NEW YORK BRANCH

as Arranger

CREDIT AGREEMENT

Dated as of May 31, 2002

ENTERGY CORPORATION, a Delaware corporation (the "Borrower"), the banks (the "Banks") listed on the signature pages hereof and Bayerische Hypo- und Vereinsbank AG, New York Branch ("HypoVereinsbank"), as administrative agent (the "Administrative Agent") for the Lenders hereunder, agree as follows:

ARTICLE I
DEFINITIONS AND ACCOUNTING TERMS

SECTION 1.01.  Certain Defined Terms.

As used in this Agreement, the following terms shall have the following meanings (such meanings to be equally applicable to both the singular and plural forms of the terms defined):

"Advance" means an advance by a Lender to the Borrower as part of a Borrowing and refers to a Base Rate Advance or a Eurodollar Rate Advance, each of which shall be a "Type" of Advance.

"Affiliate" means, as to any Person, any other Person that, directly or indirectly, controls, is controlled by or is under common control with such Person or is a director or officer of such Person.

"Agreement" means this Credit Agreement, as amended, supplemented or modified from time to time.

"Applicable Lending Office" means, with respect to each Lender, such Lender's Domestic Lending Office in the case of a Base Rate Advance and such Lender's Eurodollar Lending Office in the case of a Eurodollar Rate Advance.

"Applicable Margin" means, (i) for any Base Rate Advance, the Base Rate Margin interest rate per annum set forth below in the columns identified as Level 1, Level 2, Level 3, Level 4 and Level 5, and (ii) for any Eurodollar Rate Advance, the Eurodollar Margin interest rate per annum set forth below in the columns identified as Level 1, Level 2, Level 3, Level 4 and Level 5, in each case, determined by reference to the Relevant Rating.

	Level 1	Level 2	Level 3	Level 4	Level 5
S&P Moody's	Relevant Ratings A- or better and A3 or better	Relevant Ratings Less than Level 1 and BBB+ or better and Baa1 or better	Relevant Ratings Less than Level 2 and BBB or better and Baa2 or better	Relevant Ratings Less than Level 3 and BBB- or better And Baa3 or better	Relevant Ratings below BBB-* or below Baa3*
Interest Rate Per Annum
Eurodollar Margin	1.000%	1.125%	1.375%	1.500%	2.500%
Base Rate Margin	0.000%	0.000%	0.000%	0.000%	1.000%

                                                                                                                                                                         ;        *or unrated

Any change in the Applicable Margin will be effective as of the date on which S&P or Moody's, as the case may be, announces the applicable change in any Senior Debt Rating.

"Approved Fund" means, with respect to any Lender that is a fund that invests in bank loans, any other fund that invests in commercial loans and is managed or advised by the same investment advisor as such Lender or by an Affiliate of such investment advisor.

"Assignment and Acceptance" means an assignment and acceptance entered into by a Lender and an assignee of that Lender, and accepted by the Administrative Agent, in substantially the form of Exhibit B hereto.

"Available Commitment" means, as to any Lender at any time of determination, an amount equal to the excess of (a) such Lender's Commitment over (b) the aggregate principal amount of such Lender's Advances then outstanding.

"Base Rate" means, for any period, a fluctuating interest rate per annum at all times equal to the higher of:

1. the rate of interest announced publicly by HypoVereinsbank in New York, New York, from time to time, as HypoVereinsbank's base rate; and

 
2. 1/2 of 1% per annum above the Federal Funds Rate in effect from time to time.

"Base Rate Advance" means an Advance that bears interest as provided in Section 2.05(a).

"Borrowing" means a borrowing consisting of simultaneous Advances of the same Type made by each of the Lenders pursuant to Section 2.01 or Converted pursuant to Section 2.07 or 2.08.

"Business Day" means a day of the year on which banks are not required or authorized to close in New York City and, if the applicable Business Day relates to any Eurodollar Rate Advances, on which dealings are carried on in the London interbank market.

"Capitalization" means, as of any date of determination, with respect to the Borrower and its subsidiaries determined on a consolidated basis, an amount equal to the sum of (i) the total principal amount of all Debt of the Borrower and its subsidiaries outstanding on such date, (ii) Consolidated Net Worth as of such date and (iii) to the extent not otherwise included in Capitalization, all preferred stock and other preferred securities of the Borrower and its subsidiaries, including preferred securities issued by any subsidiary trust, outstanding on such date.

"Close", "Closing" means the execution and delivery of this Agreement by the Borrower, Administrative Agent, and the Lenders following the satisfaction or waiver by the Lenders of the conditions precedent set forth in Section 3.01.

"Commitment" has the meaning specified in Section 2.01.

"Commitment Fee" has the meaning specified in Section 2.03.

"Commitment Period" means the period beginning on (and including) the date of this Agreement and ending upon (and including) the date occurring seven calendar days after the date of this Agreement.

"Consolidated Net Worth" means the sum of the capital stock (excluding treasury stock and capital stock subscribed for and unissued) and surplus (including earned surplus, capital surplus and the balance of the current profit and loss account not transferred to surplus) accounts of the Borrower and its subsidiaries appearing on a consolidated balance sheet of the Borrower and its subsidiaries prepared as of the date of determination in accordance with generally accepted accounting principles consistent with those applied in the preparation of the financial statements referred to in Section 4.01(e), after eliminating all intercompany transactions and all amounts properly attributable to minority interests, if any, in the stock and surplus of subsidiaries.

"Convert", "Conversion" and "Converted" each refers to a conversion of Advances of one Type into Advances of another Type or the selection of a new, or the renewal of the same, Interest Period for Eurodollar Rate Advances pursuant to Section 2.07 or 2.08.

"Debt" of any Person means (without duplication) all liabilities, obligations and indebtedness (whether contingent or otherwise) of such Person (i) for borrowed money or evidenced by bonds, debentures, notes, or other similar instruments, (ii) to pay the deferred purchase price of property or services (other than such obligations incurred in the ordinary course of business on customary trade terms, provided that such obligations are not more than 30 days past due), (iii) as lessee under leases which shall have been or should be, in accordance with generally accepted accounting principles, recorded as capital leases, (iv) under reimbursement agreements or similar agreements with respect to the issuance of letters of credit (other than obligations in respect of letters of credit opened to provide for the payment of goods or services purchased in the ordinary course of business), (v) under any Guaranty Obligations and (vi) liabilities in r espect of unfunded vested benefits under plans covered by Title IV of ERISA.

"Domestic Lending Office" means, with respect to any Lender, the office of such Lender specified as its "Domestic Lending Office" opposite its name on Schedule I hereto or in the Assignment and Acceptance pursuant to which it became a Lender, or such other office of such Lender as such Lender may from time to time specify to the Borrower and the Administrative Agent.

"Eligible Assignee" means a Person (a) (i) that is (A) a commercial bank organized under the laws of the United States, or any State thereof, and having total assets in excess of $500,000,000; (B) a commercial bank organized under the laws of any other country which is a member of the OECD, or a political subdivision of any such country, and having total assets in excess of $500,000,000, provided that such bank is acting through a branch or agency located in the United States or another country which is also a member of OECD; or (C) a Lender, a financial institution Affiliate of any Lender or an Approved Fund of any Lender immediately prior to an assignment and (ii) whose long-term public senior debt securities are rated at least "BBB-" by S&P or at least "Baa3" by Moody's; or (b) that is approved by the Borrower (whose approval shall not be unreasonably withheld) and the Administrative Agent.

"Entergy Arkansas" means Entergy Arkansas, Inc., an Arkansas corporation.

"Entergy Gulf States" means Entergy Gulf States, Inc., a Texas corporation.

"Entergy Louisiana" means Entergy Louisiana, Inc., a Louisiana corporation.

"Entergy Mississippi" means Entergy Mississippi, Inc., a Mississippi corporation.

"Entergy New Orleans" means Entergy New Orleans, Inc., a Louisiana corporation.

"Environmental Laws" means any federal, state or local laws, ordinances or codes, rules, orders, or regulations relating to pollution or protection of the environment, including, without limitation, laws relating to hazardous substances, laws relating to reclamation of land and waterways and laws relating to emissions, discharges, releases or threatened releases of pollutants, contaminants, chemicals, or industrial, toxic or hazardous substances or wastes into the environment (including, without limitation, ambient air, surface water, ground water, land surface or subsurface strata) or otherwise relating to the manufacture, processing, distribution, use, treatment, storage, disposal, transport or handling of pollution, contaminants, chemicals, or industrial, toxic or hazardous substances or wastes.

"ERISA" means the Employee Retirement Income Security Act of 1974, as amended from time to time, and the regulations promulgated and rulings issued thereunder, each as amended and modified from time to time.

"ERISA Affiliate" of a Person or entity means any trade or business (whether or not incorporated) that is a member of a group of which such Person or entity is a member and that is under common control with such Person or entity within the meaning of Section 414 of the Internal Revenue Code of 1986, and the regulations promulgated and rulings issued thereunder, each as amended or modified from time to time.

"ERISA Plan" means an employee benefit plan maintained for employees of any Person or any ERISA Affiliate of such Person subject to Title IV of ERISA.

"ERISA Termination Event" means (i) a Reportable Event described in Section 4043 of ERISA and the regulations issued thereunder (other than a Reportable Event not subject to the provision for 30-day notice to PBGC), or (ii) the withdrawal of the Borrower or any of its ERISA Affiliates from an ERISA Plan during a plan year in which the Borrower or any of its ERISA Affiliates was a "substantial employer" as defined in Section 4001(a)(2) of ERISA, or (iii) the filing of a notice of intent to terminate an ERISA Plan or the treatment of an ERISA Plan amendment as a termination under Section 4041 of ERISA, or (iv) the institution of proceedings to terminate an ERISA Plan by the PBGC or to appoint a trustee to administer any ERISA Plan, or (v) any other event or condition that would constitute grounds under Section 4042 of ERISA for the termination of, or the appointment of a trustee to administer any ERISA Plan.

"Eurocurrency Liabilities" has the meaning assigned to that term in Regulation D of the Board of Governors of the Federal Reserve System, as in effect from time to time.

"Eurodollar Lending Office" means, with respect to any Lender, the office of such Lender specified as its "Eurodollar Lending Office" opposite its name on Schedule I hereto or in the Assignment and Acceptance pursuant to which it became a Lender (or, if no such office is specified, its Domestic Lending Office), or such other office of such Lender as such Lender may from time to time specify to the Borrower and the Administrative Agent.

"Eurodollar Rate" means, for the Interest Period for each Eurodollar Rate Advance made as part of the same Borrowing, an interest rate per annum equal to the average (rounded upward to the nearest whole multiple of 1/16 of 1% per annum, if such average is not such a multiple) of the rate per annum at which deposits in U.S. dollars are offered by the principal office of the Reference Bank in London, England, to prime banks in the London interbank market at 11:00 A.M. (London time) two Business Days before the first day of such Interest Period in an amount substantially equal to such Reference Bank's Eurodollar Rate Advance made as part of such Borrowing and for a period equal to such Interest Period. The Eurodollar Rate for the Interest Period for each Eurodollar Rate Advance made as part of the same Borrowing shall be determined by the Administrative Agent on the basis of applicable rates furnished to and received by the Administrative Age nt from the Reference Bank two Business Days before the first day of such Interest Period, subject, however, to the provisions of Section 2.07.

"Eurodollar Rate Advance" means an Advance that bears interest as provided in Section 2.05(b).

"Eurodollar Rate Reserve Percentage" of any Lender for the Interest Period for any Eurodollar Rate Advance means the reserve percentage applicable during such Interest Period (or if more than one such percentage shall be so applicable, the daily average of such percentages for those days in such Interest Period during which any such percentage shall be so applicable) under regulations issued from time to time by the Board of Governors of the Federal Reserve System (or any successor) for determining the maximum reserve requirement (including, without limitation, any emergency, supplemental or other marginal reserve requirement) for such Lender with respect to liabilities or assets consisting of or including Eurocurrency Liabilities having a term equal to such Interest Period.

"Events of Default" has the meaning specified in Section 6.01.

"Federal Funds Rate" means, for any period, a fluctuating interest rate per annum equal for each day during such period to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published for such day (or, if such day is not a Business Day, for the next preceding Business Day) by the Federal Reserve Bank of New York, or, if such rate is not so published for any day which is a Business Day, the average of the quotations for such day on such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by it.

"Fee Letter" means that certain letter agreement, dated as of May 31, 2002, between the Borrower and the Administrative Agent.

"Granting Lender" has the meaning specified in Section 8.07(i).

"Guaranty Obligations" means (i) direct or indirect guaranties in respect of, and obligations to purchase or otherwise acquire, or otherwise to assure a creditor against loss in respect of, Debt of any Person and (ii) other guaranty or similar obligations in respect of the financial obligations of others, including, without limitation, Support Obligations.

"Interest Period" means, for each Advance made as part of the same Borrowing, the period commencing on the date of such Advance or the date of the Conversion of any Advance into such an Advance and ending on the last day of the period selected by the Borrower pursuant to the provisions below and, thereafter, each subsequent period commencing on the last day of the immediately preceding Interest Period and ending on the last day of the period selected by the Borrower pursuant to the provisions below. The duration of each such Interest Period shall be 1, 2, 3 or 6 months (or any period of less than one month that ends on the Maturity Date) in the case of a Eurodollar Rate Advance, as the Borrower may, upon notice received by the Administrative Agent not later than 11:00 A.M. (New York City time) on the third Business Day prior to the first day of such Interest Period, select; provided, however, that:

1. the Borrower may not select any Interest Period that ends after the Maturity Date;

 
2. Interest Periods commencing on the same date for Advances made as part of the same Borrowing shall be of the same duration;

 
3. whenever the last day of any Interest Period would otherwise occur on a day other than a Business Day, the last day of such Interest Period shall be extended to occur on the next succeeding Business Day, provided, in the case of any Interest Period for a Eurodollar Rate Advance, that if such extension would cause the last day of such Interest Period to occur in the next following calendar month, the last day of such Interest Period shall occur on the next preceding Business Day; and

 
4. the Borrower shall select Interest Periods so that at no time shall the Interest Periods for all outstanding Eurodollar Rate Advances end on more than 4 different dates.

"Junior Subordinated Debentures" means any junior subordinated deferrable interest debentures issued by any Significant Subsidiary or Entergy New Orleans from time to time.

"Lenders" means the Banks listed on the signature pages hereof and each Person that shall become a party hereto pursuant to Section 8.07.

"Lien" means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset. For the purposes of this Agreement, a Person or any of its subsidiaries shall be deemed to own, subject to a Lien, any asset that it has acquired or holds subject to the interest of a vendor or lessor under any conditional sale agreement, capital lease or other title retention agreement relating to such asset.

"Majority Lenders" means at any time Lenders to which are owed at least [66-2/3]% of the then aggregate unpaid principal amount of the Advances, or, if no such principal amount is then outstanding, Lenders having at least [66-2/3]% of the Commitments (without giving effect to any termination in whole of the Commitments pursuant to Section 6.02), provided, that for purposes hereof, neither the Borrower, nor any of its Affiliates, if a Lender, shall be included in (i) the Lenders holding such amount of the Advances or having such amount of the Commitments or (ii) determining the aggregate unpaid principal amount of the Advances or the total Commitments.

"Maturity Date" means June 30, 2004.

"Moody's" means Moody's Investors Service, Inc. or any successor thereto.

"Multiemployer Plan" means a "multiemployer plan" as defined in Section 4001(a)(3) of ERISA to which the Borrower or any ERISA Affiliate is making or accruing an obligation to make contributions, or has within any of the preceding three plan years made or accrued an obligation to make contributions.

"Non-Recourse Debt" means any Debt of any subsidiary of the Borrower that does not constitute Debt of the Borrower, any Significant Subsidiary or Entergy New Orleans.

"Notice of Borrowing" has the meaning specified in Section 2.02(a).

"OECD" means the Organization for Economic Cooperation and Development.

"PBGC" means the Pension Benefit Guaranty Corporation and any entity succeeding to any or all of its functions under ERISA.

"Person" means an individual, partnership, corporation (including a business trust), joint stock company, trust, unincorporated association, joint venture or other entity, or a government or any political subdivision or agency thereof.

"Prepayment Event" means the occurrence of any event or the existence of any condition under any agreement or instrument relating to any Debt of the Borrower or of a Significant Subsidiary that, in either case, is outstanding in a principal amount in excess of $50,000,000 in the aggregate, which occurrence or event results in the declaration of such Debt being due and payable, or required to be prepaid (other than by a regularly scheduled required prepayment), prior to the stated maturity thereof.

"Reference Bank" means HypoVereinsbank.

"Register" has the meaning specified in Section 8.07(c).

"Relevant Rating" means the Senior Debt Ratings of the Significant Subsidiary (other than SERI) having the second lowest Senior Debt Ratings from Moody's and S&P of all Significant Subsidiaries (other than SERI).

"Reportable Event" has the meaning assigned to that term in Title IV of ERISA.

"S&P" means Standard & Poor's Ratings Services, a division of The McGraw-Hill Companies, Inc., or any successor thereto.

"SEC" means the United States Securities and Exchange Commission.

"SEC Order" has the meaning specified in Section 3.01(a)(iii).

"Senior Debt Rating" means, as to any Person, the rating assigned by Moody's or S&P to the senior secured long-term debt of such Person.

"SERI" means Systems Energy Resources, Inc., an Arkansas corporation.

"Significant Subsidiary" means Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, SERI and any other domestic regulated utility subsidiary of the Borrower: (i) the total assets (after intercompany eliminations) of which exceed 5% of the total assets of the Borrower and its subsidiaries or (ii) the net worth of which exceeds 5% of the Consolidated Net Worth of the Borrower and its subsidiaries, in each case as shown on the most recent audited consolidated balance sheet of the Borrower and its subsidiaries.

"SPC" has the meaning specified in Section 8.07(i).

"Support Obligations" means any financial obligation, contingent or otherwise, of any Person guaranteeing or otherwise supporting any Debt or other obligation of any other Person in any manner, whether directly or indirectly, and including, without limitation, any obligation of such Person, direct or indirect, (i) to purchase or pay (or advance or supply funds for the purchase or payment of) such Debt or to purchase (or to advance or supply funds for the purchase of) any security for the payment of such Debt, (ii) to purchase property, securities or services for the purpose of assuring the owner of such Debt of the payment of such Debt, (iii) to maintain working capital, equity capital, available cash or other financial statement condition of the primary obligor so as to enable the primary obligor to pay such Debt, (iv) to provide equity capital under or in respect of equity subscription arrangements so as to assure any Person with respect to the payment of such Debt or the performance of such obligation, or (v) to provide financial support for the performance of, or to arrange for the performance of, any non-monetary obligations or non-funded debt payment obligations (including, without limitation, guaranties of payments under power purchase or other similar arrangements) of the primary obligor.

SECTION 1.02.  Computation of Time Periods.

In this Agreement in the computation of periods of time from a specified date to a later specified date, the word "from" means "from and including" and the words "to" and "until" each means "to but excluding".

SECTION 1.03.  Accounting Terms.

All accounting terms not specifically defined herein shall be construed in accordance with generally accepted accounting principles consistent with those applied in the preparation of the financial statements referred to in Section 4.01(e) hereof.

ARTICLE II
AMOUNTS AND TERMS OF THE ADVANCES

SECTION 2.01.  The Advances.

Each Lender severally agrees, on the terms and conditions hereinafter set forth, to make Advances to the Borrower from time to time on any Business Day during the period from the date hereof until the last day of the Commitment Period in an aggregate amount not to exceed at any time outstanding the amount set opposite such Lender's name on Schedule II hereto or, if such Lender has entered into any Assignment and Acceptance, set forth for such Lender in the Register maintained by the Administrative Agent pursuant to Section 8.07(c) (such Lender's "Commitment"). Each Borrowing shall be in an amount not less than $5,000,000 or an integral multiple of $1,000,000 in excess thereof and shall consist of Advances of the same Type and, in the case of Eurodollar Rate Advances, having the same Interest Period made or Converted on the same day by the Lenders ratably according to their respective Commitments. At no time may the principal amount outstanding hereun der exceed the aggregate amount of the Commitments; provided further that, the aggregate amount of the Commitments shall not exceed $60,000,000.

SECTION 2.02.  Making the Advances.

1. Each Borrowing shall be made on notice, given (i) in the case of a Borrowing comprising Eurodollar Rate Advances, not later than 11:00 A.M. (New York City time) on the third Business Day prior to the date of the proposed Borrowing, and (ii) in the case of a Borrowing comprising Base Rate Advances, not later than 11:00 A.M. (New York City time) on the date of the proposed Borrowing, by the Borrower to the Administrative Agent, which shall give to each Lender prompt notice thereof. Each such notice of a Borrowing (a "Notice of Borrowing") shall be transmitted by telecopier, telex or cable, confirmed immediately in writing, in substantially the form of Exhibit A-1 hereto, specifying therein the requested (A) date of such Borrowing, (B) Type of Advances to be made in connection with such Borrowing, (C) aggregate amount of such Borrowing, (D) the Borrower's wire instructions, and (E) in the case of a Borrowing comprising Eurodollar Rate Advances, initial Interest Period for each such Advance. Each Lender shall, before (x) 12:00 noon (New York City time) on the date of any Borrowing comprising Eurodollar Rate Advances, and (y) 1:00 P.M. (New York City time) on the date of any Borrowing comprising Base Rate Advances, make available for the account of its Applicable Lending Office to the Administrative Agent at its address referred to in Section 8.02, in same day funds, such Lender's ratable portion of such Borrowing. After the Administrative Agent's receipt of such funds and upon fulfillment of the applicable conditions set forth in Article III, the Administrative Agent will make such funds available to the Borrower at the Administrative Agent's aforesaid address.
2. Each Notice of Borrowing shall be irrevocable and binding on the Borrower. In the case of any Notice of Borrowing requesting Eurodollar Rate Advances, the Borrower shall indemnify each Lender against any loss, cost or expense in curred by such Lender as a result of any failure to fulfill on or before the date specified in such Notice of Borrowing for such Borrowing the applicable conditions set forth in Article III, including, without limitation, any loss, cost or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by such Lender to fund the Advance to be made by such Lender as part of such Borrowing when such Advance, as a result of such failure, is not made on such date.
3. Unless the Administrative Agent shall have received notice from a Lender prior to the date of any Borrowing that such Lender will not make available to the Administrative Agent such Lender's ratable portion of such Borrowing, the Administrative Agent may assume that such Lender has made such portion available to the Administrative Agent on the date of such Borrowing in accordance with subsection (a) of this Section 2.02 and the Administrative Agent may, in reliance upon such as sumption, make available to the Borrower on such date a corresponding amount. If and to the extent that such Lender shall not have so made such ratable portion available to the Administrative Agent, such Lender and the Borrower (following the Administrative Agent's demand on such Lender for the corresponding amount) severally agree to repay to the Administrative Agent forthwith on demand such corresponding amount together with interest thereon, for each day from the date such amount is made available to the Borrower until the date such amount is repaid to the Administrative Agent, at (i) in the case of the Borrower, the interest rate applicable at the time to Advances made in connection with such Borrowing and (ii) in the case of such Lender, the Federal Funds Rate. If such Lender shall repay to the Administrative Agent such corresponding amount, such amount so repaid shall constitute such Lender's Advance as part of such Borrowing for purposes of this Agreement.
4. The fa ilure of any Lender to make the Advance to be made by it as part of any Borrowing shall not relieve any other Lender of its obligation, if any, hereunder to make its Advance on the date of such Borrowing, but no Lender shall be responsible for the failure of any other Lender to make the Advance to be made by such other Lender on the date of any Borrowing.

SECTION 2.03.  Fees.

The Borrower agrees to pay to the Administrative Agent for the account of each Lender a commitment fee ( the "Commitment Fee") for the period from (and including) the date of this Agreement to (but excluding) the last day of the Commitment Period, computed at the rate of 0.125% per annum on the average daily amount of the Available Commitment of such Lender. Such Commitment Fee shall be payable in arrears on the last day of the Commitment Period.

SECTION 2.04.  Repayment of Advances, Etc.

The Borrower shall repay the principal amount of each Advance made by each Lender on the Maturity Date.

SECTION 20.5.  Interest on Advances.

The Borrower shall pay interest on the unpaid principal amount of each Advance made by each Lender from the date of such Advance until such principal amount shall be paid in full, at the following rates per annum:

1. Base Rate Advances. If such Advance is a Base Rate Advance, a rate per annum equal at all times to the Base Rate in effect from time to time plus the Applicable Margin for such Base Rate Advance in effect from time to time, payable quarterly on the last day of each March, June, September and December and on the date such Base Rate Advance shall be Converted or paid in full.
2. Eurodollar Rate Advances. Subject to Section 2.06, if such Advance is a Eurodollar Rate Advance, a rate per annum equal at all times during the Interest Period for such Advance to the sum of the Eurodollar Rate for such Interest Period plus the Applicable Margin for such Eurodollar Rate Advance in effect from time to time, payable on the last day of each Interest Period for such Eurodollar Rate Advance and on the date such Eurodollar Rate Advance shall be Converted or paid in full and, if such Interest Period has a duration of more than three mon ths, on each day that occurs during such Interest Period every three months from the first day of such Interest Period.

SECTION 2.06.  Additional Interest on Eurodollar Rate Advances.

The Borrower shall pay to each Lender, so long as such Lender shall be required under regulations of the Board of Governors of the Federal Reserve System to maintain reserves with respect to liabilities or assets consisting of or including Eurocurrency Liabilities, additional interest on the unpaid principal amount of each Eurodollar Rate Advance of such Lender, from the date of such Advance until such principal amount is paid in full, at an interest rate per annum equal at all times to the remainder obtained by subtracting (i) the Eurodollar Rate for the Interest Period for such Advance from (ii) the rate obtained by dividing such Eurodollar Rate by a percentage equal to 100% minus the Eurodollar Rate Reserve Percentage of such Lender for such Interest Period, payable on each date on which interest is payable on such Advance. Such additional interest shall be determined by such Lender and notified to the Borrower through the Administrative Agent, and such determi nation shall be conclusive and binding for all purposes, absent manifest error.

SECTION 2.07.  Interest Rate Determination.

1. The Reference Bank agrees to furnish to the Administrative Agent timely information for the purpose of determining each Eurodollar Rate.
2. The Administrative Agent shall give prompt notice to the Borrower and the Lenders of the applicable interest rate determined by the Administrative Agent for purposes of Section 2.05(a).
3. If, with respect to any Eurodollar Rate Advances, the Majority Lenders notify the Administrative Agent that the Eurodollar Rate for any Interest Period for such Advances will not adequately reflect the cost to such Majority Lenders of making, funding or maintaining their respective Eurodollar Rate Advances for such Interest Period, the Administrative Agent shall forthwith so notify the Borrower and the Lenders, whereupon

1. each Eurodollar Rate Advance will automatically, on the last day of the then existing Interest Period therefor, Convert into a Base Rate Advance, and
2. the obligation of the Lenders to make, or to Convert Advances into, Eurodollar Rate Advances shall be suspended until the Administrative Agent shall notify the Borrower and the Lenders that the circumstances causing such suspension no longer exist.
0

SECTION 2.08.  Conversion of Advances.

1. Voluntary. The Borrower may, upon notice given to the Administrative Agent not later than 11:00 A.M. (New York City time) on the third Business Day prior to the date of the proposed Conversion and subject to the provisions of Sections 2.07 and 2.11, on any Business Day, Convert all Advances of one Type made in connection with the same Borrowing into Advances of another Type; provided, however, that any Conversion of, or with respect to, any Eurodollar Rate Advances into Advances of another Type shall be made on, and only on, the last day of an Interest Period for such Eurodollar Rate Advances, unless the Borrower shall also reimburse the Lenders in respect thereof pursuant to Section 8.04(b) on the date of such Conversion. Each such notice of a Conversion (a "Notice of Conversion") shall be by telecopier, telex or cable, confirmed immediately in writing, in substantially the form of Exhibit A-2 hereto, specifying therein (i) the dat e of such Conversion, (ii) the Advances to be Converted, and (iii) if such Conversion is into, or with respect to, Eurodollar Rate Advances, the duration of the Interest Period for each such Advance.
2. Mandatory. If a Borrower shall fail to select the Type of any Advance or the duration of any Interest Period for any Borrowing comprising Eurodollar Rate Advances in accordance with the provisions contained in the definition of "Interest Period" in Section 1.01, or if any proposed Conversion of a Borrowing that is to comprise Eurodollar Rate Advances upon Conversion shall not occur as a result of the circumstances described in paragraph (c) below, the Administrative Agent will forthwith so notify the Borrower and the Lenders, and such Advances will automatically, on the last day of the then existing Interest Period therefor, Convert into Base Rate Advances.
3. Failure to Convert. Each notice of Conversion given pursuant to subsection (a) above shall be irrevocable and binding on the Borrower. In the case of any Borrowing that is to comprise Eurodollar Rate Advances upon Conversion, the Borrower agrees to indemnify each Lender against any loss, cost or expense incurred by such Lender if, as a result of the failure of the Borrower to satisfy any condition to such Conversion (including, without limitation, the occurrence of any Prepayment Event or Event of Default, or any event that would constitute an Event of Default or a Prepayment Event with notice or lapse of time or both), such Conversion does not occur. The Borrower's obligations under this subsection (c) shall survive the repayment of all other amounts owing to the Lenders and the Administrative Agent under this Agreement and the termination of the Commitments.

SECTION 2.09.  Prepayments.

The Borrower may, upon notice received by the Administrative Agent prior to 11:00 A.M. (New York City time) on any Business Day, with respect to Base Rate Advances, and upon at least two Business Days' notice to the Administrative Agent, with respect to Eurodollar Rate Advances, stating the proposed date and aggregate principal amount of the prepayment, and if such notice is given the Borrower shall, prepay the outstanding principal amounts of the Advances made as part of the same Borrowing in whole or ratably in part, together with accrued interest to the date of such prepayment on the principal amount prepaid; provided, however, that (i) each partial prepayment shall be in an aggregate principal amount not less than $1,000,000 or any integral multiple of $100,000 in excess thereof, (ii) in the case of any such prepayment of an Eurodollar Rate Advance, the Borrower shall be obligated to reimburse the Lenders in respect thereof pursuant to Section 8.04(b) on the date of such prepayment, and (iii) in the case of any partial prepayment of the outstanding principal amount of the Advances, the aggregate principal amount of the Advances outstanding after giving effect to any such prepayment shall not be less than $10,000,000.00. Amounts so prepaid under this Section 2.09 may not be reborrowed.

SECTION 2.10.  Increased Costs.

1. If, due to either (i) the introduction of or any change (other than any change by way of imposition or increase of reserve requirements in the case of Eurodollar Rate Advances, included in the Eurodollar Rate Reserve Percentage) in or in the interpretation of any law or regulation or (ii) the compliance with any guideline or request from any central bank or other governmental authority (whether or not having the force of law), there shall be any increase in the cost to any Lender of agreeing to make or making, funding or maintaining Eurodollar Rate Advances, then the Borrower shall from time to time, upon demand by such Lender (with a copy of such demand to the Administrative Agent), pay to the Administrative Agent for the account of such Lender additional amounts sufficient to compensate such Lender for such increased cost. A certificate as to the amount of such increased cost, submitted to the Borrower and the Administrative Agent by such Lender, shall be conclusive and binding for a ll purposes, absent manifest error.
2. If any Lender determines that compliance with any law or regulation or any guideline or request from any central bank or other governmental authority (whether or not having the force of law) affects or would affect the amount of capital required or expected to be maintained by such Lender or any corporation controlling such Lender and that the amount of such capital is increased by or based upon the existence of such Lender's commitment to lend hereunder and other commitments of this type (including such Lender's commitment to lend hereunder) or the Advances, then, upon demand by such Lender (with a copy of such demand to the Administrative Agent), the Borrower shall immediately pay to the Administrative Agent for the account of such Lender, from time to time as specified by such Lender, additional amounts sufficient to compensate such Lender or such corporation in the light of such circumstances, to the extent that such Lender reasonably determines such increase in capital to be allocable to the existen ce of such Lender's commitment to lend hereunder or the Advances made by such Lender. A certificate in reasonable detail as to such amounts submitted to the Borrower and the Administrative Agent by such Lender shall be conclusive and binding for all purposes, absent manifest error.

SECTION 2.11.  Illegality.

Notwithstanding any other provision of this Agreement, if any Lender shall notify the Administrative Agent that the introduction of, any change in or any change in the interpretation of any law or regulation makes it unlawful, or any central bank or other governmental authority asserts that it is unlawful, for any Lender or its Eurodollar Lending Office to perform its obligations hereunder to make Eurodollar Rate Advances or to fund or maintain Eurodollar Rate Advances hereunder, (i) the obligation of the Lenders to make, or to Convert Advances into, Eurodollar Rate Advances shall be suspended until the Administrative Agent shall notify the Borrower and the Lenders that the circumstances causing such suspension no longer exist and (ii) the Borrower shall forthwith prepay in full all Eurodollar Rate Advances of all Lenders then outstanding, together with interest accrued thereon, unless the Borrower, within five Busi ness Days of notice from the Administrative Agent, Converts all Eurodollar Rate Advances of all Lenders then outstanding into Advances of another Type in accordance with Section 2.08.

SECTION 2.12.  Payments and Computations.

1. The Borrower shall make each payment hereunder not later than 12:00 noon (New York City time) on the day when due in U.S. dollars to the Administrative Agent at its address referred to in Section 8.02 in same day funds in accordance with the payment instructions set opposite the name of the Administrative Agent on Schedule I. The Administrative Agent will promptly thereafter cause to be distributed like funds relating to the payment of principal or interest ratably (other than amounts payable pursuant to Section 2.02(c), 2.03, 2.06, 2.10, 2.13 or 8.04(b)) to the Lenders for the account of their respective Applicable Lending Offices, and like funds relating to the payment of any other amount payable to any Lender to such Lender for the account of its Applicable Lending Office, in each case to be applied in accordance with the terms of this Agreement. Upon its acceptance of an Assignment and Acceptance and recording of the information contained therein in the Register pursuant to S ection 8.07(d), from and after the effective date specified in such Assignment and Acceptance, the Administrative Agent shall make all payments hereunder in respect of the interest assigned thereby to the Lender assignee thereunder, and the parties to such Assignment and Acceptance shall make all appropriate adjustments in such payments for periods prior to such effective date directly between themselves.
2. The Borrower hereby authorizes each Lender, if and to the extent payment owed to such Lender is not made when due hereunder, to charge from time to time to the extent permitted by law against any or all of the Borrower's accounts with such Lender any amount so due.
3. All computations of interest based on clause (i) of the definition of "Base Rate" shall be made by the Administrative Agent on the basis of a year of 365 or 366 days, as the case may be, and all computations of interest based on the Eurodollar Rate, the Federal Funds Rate or clause (ii) of the definition of "Base Rate" and the Commitment Fee shall be made by the Administrative Agent, and all computations of interest pursuant to Section 2.07 shall be made by a Lender, on the basis of a year of 360 days, in each case for the actual number of days (including the first day but excluding the last day) occurring in the period for which such interest or Commitment Fee are payable. Each determination by the Administrative Agent (or, in the case of Section 2.07, by a Lender) of an interest rate hereunder shall be conclusive and binding for all purposes, absent manifest error.
4. Whenever any payment hereunder shall be stated to be due on a day other than a Business Day, such payment shall be made on the next succeeding Business Day, and such extension of time shall in such case be included in the computation of payment of interest; provided, however, if such extension would cause payment of interest on or principal of Eurodollar Rate Advances to be made in the next following calendar month, such payment shall be made on the next preceding Business Day.
5. Unless the Administrative Agent shall have received notice from the Borrower prior to the date on which any payment is due to the Lenders hereunder that the Borrower will not make such payment in full, the Administrative Agent may assume that the Borrower has made such payment in full to the Administrative Agent on such date and the Administrative Agent may, in reliance upon such assumption, cause to be distributed to each Lender on such due date an amount equal to the amount then due such Lender. If and to the extent that the Borrower shall not have so made such payment in full to the Administrative Agent, each Lender shall repay to the Administrative Agent forthwith on demand such amount distributed to such Lender together with interest thereon, for each day from the date such amount is distributed to such Lender until the date such Lender repays such amount to the Administrative Agent, at the Federal Funds Rate.
6. Notwithstanding anything to the contrary contained herein, any amount payable by the Borrower hereunder that is not paid when due (whether at stated maturity, by acceleration or otherwise) shall (to the fullest extent permitted by law) bear interest from the date when due until paid in full at a rate per annum equal at all times to the Base Rate plus 2%, payable upon demand.

SECTION 2.13.  Taxes.

1. Any and all payments by the Borrower hereunder shall be made, in accordance with Section 2.12, free and clear of and without deduction for any and all present or future taxes, levies, imposts, deductions, charges or withholdings, and all liabilities with respect thereto, excluding, in the case of each Lender and the Administrative Agent, taxes imposed on its income, and franchise taxes imposed on it, by the jurisdiction under the laws of which such Lender or the Administrative Agent (as the case may be) is organized or any political subdivision thereof and, in the case of each Lender, taxes imposed on its income, and franchise taxes imposed on it, by the jurisdiction of such Lender's Applicable Lending Office or any political subdivision thereof (all such non-excluded taxes, levies, imposts, deductions, charges, withholdings and liabilities being hereinafter referred to as "Taxes"). If the Borrower shall be required by law to deduct any Taxes from or in respec t of any sum payable hereunder to any Lender or the Administrative Agent, (i) the sum payable shall be increased (unless and to the extent that (x) the Borrower is required to deduct such Taxes because any Lender fails to provide the Administrative Agent and the Borrower with the forms described in subsection (d) below and (y) such Lender is entitled to an exemption from United States withholding taxes with respect to such sum payable) as may be necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 2.13) such Lender or the Administrative Agent (as the case may be) receives an amount equal to the sum it would have received had no such deductions been made, (ii) the Borrower shall make such deductions and (iii) the Borrower shall pay the full amount deducted to the relevant taxation authority or other authority in accordance with applicable law.
2. In addition, the Borrower agrees to pay any present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies which arise from any payment made hereunder or from the execution, delivery or registration of, or otherwise with respect to, this Agreement (hereinafter referred to as "Other Taxes").
3. The Borrower will indemnify each Lender and the Administrative Agent for the full amount of Taxes or Other Taxes (including, without limitation, any Taxes or Other Taxes imposed by any jurisdiction on amounts payable under this Section 2.13) paid by such Lender or the Administrative Agent (as the case may be) and any liability (including penalties, interest and expenses) arising therefrom or with respect thereto, whether or not such Taxes or Other Taxes were correctly or legally asserted. This indemnification shall be made within 30 days from the date such Lender or the Administrative Agent (as the case may be) make s written demand therefor. Nothing herein shall preclude the right of the Borrower to contest any such Taxes or Other Taxes so paid, and the Lenders in question or the Administrative Agent (as the case may be) will, following notice from, and at the expense of, the Borrower, take such actions as the Borrower may reasonably request to preserve the Borrower's rights to contest such Taxes or Other Taxes, and, promptly following receipt of any refund of amounts with respect to Taxes or Other Taxes for which such Lenders or the Administrative Agent were previously indemnified under this Section 2.13, pay to the Borrower such refunded amounts (including any interest paid by the relevant taxing authority with respect to such amounts).
4. Prior to the date of the initial Borrowing in the case of each Bank, and on the date of the Assignment and Acceptance pursuant to which it became a Lender in the case of each other Lender, and from time to time thereafter if requested by the Borrower or the Administrative Agent, each Lender organized under the laws of a jurisdiction outside the United States shall provide the Administrative Agent and the Borrower with the forms prescribed by the Internal Revenue Service of the United States certifying that such Lender is exempt from United States withholding taxes with respect to all payments to be made to such Lender hereunder. If for any reason during the term of this Agreement, any Lender becomes unable to submit the forms referred to above or the information or representations contained therein are no longer accurate in any material respect, such Lender shall notify the Administrative Agent and the Borrower in writing to that effect. Unless the Borrower and the Administrative Agent have received fo rms or other documents satisfactory to them indicating that payments hereunder are not subject to United States withholding tax, the Borrower or, if the Borrower fails to do so, the Administrative Agent, shall withhold taxes from such payments at the applicable statutory rate in the case of payments to or for any Lender organized under the laws of a jurisdiction outside the United States.
5. Any Lender claiming any additional amounts payable pursuant to this Section 2.13 shall use its best efforts (consistent with its internal policy and legal and regulatory restrictions) to change the jurisdiction of its Applicable Lending Office or take other actions customary or otherwise reasonable under the circumstances if the making of such a change or the taking of such actions would avoid the need for, or reduce the amount of, any such additional amounts which may thereafter accrue and would not, in the reasonable judgment of such Lender, be otherwise disadvantageous to such Lender.
6. Without prejudice to the survival of any other agreement of the Borrower hereunder, the agreements and obligations of the Borrower contained in this Section 2.13 shall survive the payment in full of principal and interest hereunder.

SECTION 2.14.  Sharing of Payments, Etc.

If any Lender shall obtain any payment (whether voluntary, involuntary, through the exercise of any right of set-off, or otherwise) on account of the Advances made by it (other than pursuant to Section 2.02(c), 2.06, 2.10, 2.13 or 8.04(b)) in excess of its ratable share of payments on account of the Advances obtained by all the Lenders, such Lender shall forthwith purchase from the other Lenders such participations in the Advances made by them as shall be necessary to cause such purchasing Lender to share the excess payment ratably with each of them, provided, however, that if all or any portion of such excess payment is thereafter recovered from such purchasing Lender, such purchase from each Lender shall be rescinded and such Lender shall repay to the purchasing Lender the purchase price to the extent of such recovery together with an amount equal to such Lender's ratable sha re (according to the proportion of (i) the amount of such Lender's required repayment to (ii) the total amount so recovered from the purchasing Lender) of any interest or other amount paid or payable by the purchasing Lender in respect of the total amount so recovered. The Borrower agrees that any Lender so purchasing a participation from another Lender pursuant to this Section 2.14 may, to the fullest extent permitted by law, exercise all its rights of payment (including the right of set-off) with respect to such participation as fully as if such Lender were the direct creditor of the Borrower in the amount of such participation.

SECTION 2.15.  Noteless Agreement; Evidence of Indebtedness.

1. Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of the Borrower to such Lender resulting from each Advance made by such Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time hereunder.
2. The Administrative Agent shall also maintain accounts in which it will record (i) the amount of each Advance made hereunder, the Type thereof and the Interest Period (if any) with respect thereto, (ii) the amount of any principal or interest due and payable or to become due and payable from the Borrower to each Lender hereunder, and (iii) the amount of any sum received by the Administrative Agent hereunder from the Borrower and each Lender's share thereof.
3. The entries maintained in the accounts maintained pursuant to subsections (a) and (b) above shall be prima facie evidence of the existence and amounts of the obligations therein recorded; provided, however, that the failure of the Administrative Agent or any Lender to maintain such accounts or any error therein shall not in any manner affect the obligation of the Borrower to repay such obligations in accordance with their terms.
4. Any Lender may request that its Advances be evidenced by one or more promissory notes. In such event, the Borrower shall prepare, execute and deliver to such Lender one or more promissory notes payable to the order of such Lender and in a form acceptable to the Borrower and the Administrative Agent. Thereafter, the Advances evidenced by such note(s) and interest thereon shall at all times (including after any assignment pursuant to Section 8.07) be represented by notes from the Borrower, payable to the order of the payee named therein or a ny assignee pursuant to Section 8.07, except to the extent that any such Lender or assignee subsequently returns any such notes for cancellation and requests that such Borrowings once again be evidenced as in subsections (a) and (b) above.

ARTICLE III
CONDITIONS OF LENDING

SECTION 3.01.  Conditions Precedent to Closing.

The obligation of each Lender to Close is subject to the conditions precedent that on or before the date of Closing:

1. The Administrative Agent shall have received the following, each dated the same date (except for the financial statements referred to in paragraph (iv) below), in form and substance satisfactory to the Administrative Agent and (except for the notes described in paragraph (i)) with one copy for each Lender:

1. A promissory note payable to the order of each Lender that requests one pursuant to Section 2.15.
2. Certified copies of the resolutions of the Board of Directors of the Borrower approving this Agreement, and of all documents evidencing other necessary corporate action with respect to this Agreement;
3. A certificate of the Secretary or an Assistant Secretary of the Borrower certifying (A) the names and true signatures of the officers of the Borrower authorized to sign this Agreement and the other documents to be delivered hereunder; (B) that attached thereto are true and correct copies of the Certificate of Incorporation and the By Laws of the Borrower, in each case in effect on such date; and (C) that attached thereto are true and correct copies of all governmental and regulatory authorizations and approvals required for the due execution, delivery and performance of this Agreement, including, without limitation, a copy of the order (File N o. 70-9749) of the SEC under the Public Utility Holding Company Act of 1935 authorizing the Borrower's execution, delivery and performance of this Agreement (the "SEC Order");
4. Copies of the consolidated balance sheets of the Borrower and its subsidiaries as of December 31, 2001, and the related consolidated statements of income, retained earnings and cash flows of the Borrower and its subsidiaries for the fiscal year then ended, and copies of the consolidated financial statements of the Borrower and its subsidiaries as of March 31, 2002, in each case certified by a duly authorized officer of the Borrower as having been prepared in accordance with generally accepted accounting principles consistently applied;
5. A favorable opinion of counsel for the Borrower, acceptable to the Administrative Agent, substantially in the form of Exhibit C hereto and as to such other matters as any Lender through the Administrative Ag ent may reasonably request; and
6. A favorable opinion of Piper Rudnick LLP, Special New York counsel for the Administrative Agent, substantially in the form of Exhibit D hereto.

2. The Administrative Agent shall have received the fees payable pursuant to the Fee Letter.

SECTION 3.02.  Conditions Precedent to Each Borrowing.

The obligation of each Lender to make an Advance on the occasion of each Borrowing (including the initial Borrowing) shall be subject to the further conditions precedent that on the date of such Borrowing:

1. the following statements shall be true (and each of the giving of the applicable Notice of Borrowing or Notice of Conversion and the acceptance by the Borrower of any proceeds of a Borrowing shall constitute a representation and warranty by the Borrower that on the date of such Borrowing or Conversion, as applicable, such statements are true):

1. The representations and warranties contained in Section 4.01 (excluding those contained in subsections (e) and (f) thereof if such Borrowing does not increase the aggregate outstanding principal amount of Advances over the aggregate outstanding principal amount of all Advances immediately prior to the making of such Borrowing) are correct on and as of the date of such Borrowing, before and after giving effect to such Borrowing and to the application of the proceeds therefrom, as though made on and as of such date; and
2. No event has occurred and is continuing, or would result from such Borrowing or from the application of the proceeds therefrom, that constitutes a Prepayment Event or an Event of Default or would constitute a Prepayment Event or an Event of Default with notice or lapse of time or both.

2. The Administrative Agent shall have received such other approvals, opinions or documents with respect to the truth of the foregoing statements (i) and (ii) as any Lender through the Administrative Agent may reasonably request.

ARTICLE IV
REPRESENTATIONS AND WARRANTIES

SECTION 4.01.  Representations and Warranties of the Borrower.

The Borrower represents and warrants as follows:

1. The Borrower is a corporation duly organized, validly existing and in good standing under the laws of the jurisdiction of its incorporation and is duly qualified to do business as a foreign corporation in each jurisdiction in which the nature of the business conducted or the property owned, operated or leased by it requires such qualification, except where failure to so qualify would not materially adversely affect its condition (financial or otherwise), operations, business, properties, or prospects.
2. The execution, delivery and performance by the Borrower of this Agreement are within the Borrower's corporate powers, have been duly authorized by all necessary corporate action, and do not contravene (i) the Borrower's charter or by-laws, (ii) law applicable to the Borrower or its properties, or (iii) any contractual or legal restriction binding on or affecting the Borrower or its properties.
3. No authorization or approval or other action b y, and no notice to or filing with, any governmental authority or regulatory body is required for the due execution, delivery and performance by the Borrower of this Agreement, except for the following (each of which has been duly filed or obtained, and is final and in full force and effect): (i) the filing of the Declaration on Form U-1 and amendments and exhibits thereto in File No. 70-9749 and (ii) the SEC Order.
4. This Agreement is the legal, valid and binding obligation of the Borrower enforceable against the Borrower in accordance with its terms, subject, however, to any applicable bankruptcy, reorganization, rearrangement, moratorium or similar laws affecting generally the enforcement of creditors' rights and remedies and to general principles of equity (regardless of whether enforceability is considered in a proceeding in equity or at law).
5. The consolidated financial statements of the Borrower and its subsidiaries as of December 31, 2001 and for the year ended on such date, as set forth in the Borrower's Annual Report on Form 10-K for the fiscal year ended on such date, as filed with the SEC, accompanied by an opinion of Deloitte & Touche LLP, and the consolidated financial statements of the Borrower and its subsidiaries as of March 31, 2002, and for the three-month period ended on such date set forth in the Borrower's Quarterly Report on Form 10-Q for the fiscal quarter ended on such date, as filed with the SEC, copies of each of which have been furnished to each Bank, fairly present (subject, in the case of such statements dated March 31, 2002, to year-end adjustments) the consolidated financial condition of the Borrower and its subsidiaries as at such dates and the consolidated results of the operations of the Borrower and its subsidiaries for the periods ended on such dates, in accordance with generally acce pted accounting principles consistently applied. Except as disclosed in the Borrower's Quarterly Report on Form 10-Q for the fiscal period ended March 31, 2002, since December 31, 2001, there has been no material adverse change in the financial condition or operations of the Borrower.
6. Except as disclosed in the Borrower's Annual Report on Form 10-K for the fiscal year ended December 31, 2001, and the Borrower's Quarterly Report on Form 10-Q for the period ended March 31, 2002, there is no pending or threatened action or proceeding affecting the Borrower or any of its subsidiaries before any court, governmental agency or arbitrator that, if determined adversely, could reasonably be expected to have a material adverse effect upon the condition (financial or otherwise), operations, business, properties or prospects of the Borrower or on its ability to perform its obligations under this Agreement, or that purports to affect the legality, validity, bi nding effect or enforceability of this Agreement. There has been no change in any matter disclosed in such filings that could reasonably be expected to result in such a material adverse effect.
7. No event has occurred and is continuing that constitutes a Prepayment Event or an Event of Default or that would constitute a Prepayment Event or an Event of Default but for the requirement that notice be given or time elapse or both.
8. The Borrower is not engaged in the business of extending credit for the purpose of purchasing or carrying margin stock (within the meaning of Regulation U issued by the Board of Governors of the Federal Reserve System), and not more than 25% of the value of the assets of the Borrower and its subsidiaries subject to the restrictions of Section 5.02(a), (c) or (d) is, on the date hereof, represented by margin stock (within the meaning of Regulation U issued by the Board of Governors of the Federal Reserve System).
9. The Borrower is not an "investment company" or a company "controlled" by an "investment company" within the meaning of the Investment Company Act of 1940, as amended, or an "investment advisor" within the meaning of the Investment Company Act of 1940, as amended. The Borrower is a "holding company" as that term is defined in, and is registered under, the Public Utility Holding Company Act of 1935.
10. No ERISA Termination Event has occurred, or is reasonably expected to occur, with respect to any ERISA Plan that may materially and adversely affect the condition (financial or otherwise), operations, business, properties or prospects of the Borrower and its subsidiaries, taken as a whole.
11. Schedule B (Actuarial Information) to the most recent annual report (Form 5500 Series) with respect to each ERISA Plan, copies of which have been filed with the Internal Revenue Service and furni shed to the Banks, is complete and accurate and fairly presents the funding status of such ERISA Plan, and since the date of such Schedule B there has been no material adverse change in such funding status.
12. The Borrower has not incurred, and does not reasonably expect to incur, any withdrawal liability under ERISA to any Multiemployer Plan.

ARTICLE V
COVENANTS OF THE BORROWER

SECTION 5.01.  Affirmative Covenants.

So long as any amount payable by the Borrower hereunder shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower will, unless the Majority Lenders shall otherwise consent in writing:

1. Keep Books; Corporate Existence; Maintenance of Properties; Compliance with Laws; Insurance; Taxes; Inspection Rights.

1. keep proper books of record and account, all in accordance with generally accepted accounting principles;
2. except as otherwise permitted by Section 5.02(c), preserve and keep in full force and effect its existence and preserve and keep in full force and effect its licenses, rights and franchises to the extent necessary to carry on its business;
3. maintain and keep, or cause to be maintained and kept, its properties in good repair, working order and condition, and from time to time make or cause to be made all needful and proper repairs, renewals, replacements and improvements, in each case to the extent such properties are not obsolete and not necessary to carry on its business;
4. comply in all material respects with all applicable laws, rules, regulations and orders, such compliance to include, without limitation, paying before the same become delinquent all taxes, assessments and governmental charges imposed upon it or its property, except to the extent being contested in good faith by appropriate proceedings, and compliance with ERISA and Environmental Laws;
5. maintain insurance with responsible and reputable insurance companies or associations or through its own program of self-insurance in such amounts and covering such risks as is usually carried by companies engaged in similar businesses and owning similar properties in the same general areas in which it operates and furnish to the Administrative Agent, within a reasonable time after written request therefor, such information as to the insurance carried as any Lender, through the Administrative Agent, may reasonably request;
6. pay and discharge its obligations and liabilities in the ordinary course of business, except to the extent that such obligations and liabilities are being contested in good faith by appropriate proceedings; and
7. from time to time upon reasonable notice, permit or arrange for the Administrative Agent, the Lenders and their respective agents and representatives to inspect the records and books of account of the Borrower and its subsidiaries during regular business hours.

2. Use of Proceeds. The Borrower may use the proceeds of the Borrowings for only (i) general corporate purposes and (ii) subject to the terms and conditions of this Agreement, repurchases of common stock of the Borrower and/or investments in nonregulated and/or nonutility businesses.
3. Reporting Requirements. Furnish to the Lenders:

1. as soon as available and in any event within 60 days after the end of each of the first three quarters of each fiscal year of the Borrower, (A) consolidated balance sheets of the Borrower and its subsidiaries as of the end of such quarter and (B) consolidated statements of income and retained earnings of the Borrower and its subsidiaries for the period commencing at the end of the previous fiscal year and ending with the end of such quarter, each certified by a duly authorized officer of the Borrower as having been prepared in accordance with generally accepted accounting principles, consistently applied;
2. as soon as available and in any event within 120 days after the end of each fiscal year of the Borrower, a copy of the annual report for such year for the Borrower and its subsidiaries, containing consolidated financial statements for such year certified without qualification by Deloitte & Touche LLP (or such other nationally recognized public accounting firm as the Admini strative Agent may approve), and certified by a duly authorized officer of the Borrower as having been prepared in accordance with generally accepted accounting principles, consistently applied;
3. as soon as available and in any event within 60 days after the end of each of the first three quarters of each fiscal year of the Borrower and within 120 days after the end of the fiscal year of the Borrower, a certificate of a duly authorized officer of the Borrower, stating that no Prepayment Event or Event of Default has occurred and is continuing, or if a Prepayment Event or an Event of Default has occurred and is continuing, a statement setting forth details of such Prepayment Event or Event of Default, as the case may be, and the action that the Borrower has taken and proposes to take with respect thereto;
4. as soon as possible and in any event within five days after the Borrower has knowledge of the occurrence of each Prepayment Event, Event of Default and each event that, with the giving of notice or lapse of time or both, would constitute a Prepayment Event or an Event of Default, continuing on the date of such statement, a statement of the duly authorized officer of the Borrower setting forth details of such Prepayment Event or Event of Default or event, as the case may be, and the actions that the Borrower has taken and proposes to take with respect thereto;
5. as soon as possible and in any event within five days after the Borrower receives notice of the commencement of any litigation against, or any arbitration, administrative, governmental or regulatory proceeding involving, the Borrower or any of its subsidiaries, that, if adversely determined, could reasonably be expected to have a material adverse effect on the condition (financial or otherwise), operations, business, prope rties or prospects of the Borrower, notice of such litigation describing in reasonable detail the facts and circumstances concerning such litigation and the Borrower's or such subsidiary's proposed actions in connection therewith;
6. promptly after the sending or filing thereof, copies of all reports that the Borrower sends to any of its securities holders, and copies of all reports and registration statements which the Borrower files with the SEC or any national securities exchange pursuant to the Securities Act of 1933 or the Exchange Act, and of all certificates pursuant to Rule 24 which the Borrower files with the SEC pursuant to the Public Utility Holding Company Act of 1935 in connection with the proceeding of the SEC in File No. 70-9749 related to the SEC Order or any subsequent proceedings related thereto;
7. as soon as possible and in any event (A) within 30 days after the Borrower knows or has reason to know that any ERISA Termination Event descr ibed in clause (i) of the definition of ERISA Termination Event with respect to any ERISA Plan has occurred and (B) within 10 days after the Borrower knows or has reason to know that any other ERISA Termination Event with respect to any ERISA Plan has occurred, a statement of the chief financial officer of the Borrower describing such ERISA Termination Event and the action, if any, that the Borrower proposes to take with respect thereto;
8. promptly and in any event within two Business Days after receipt thereof by the Borrower from the PBGC, copies of each notice received by the Borrower of the PBGC's intention to terminate any ERISA Plan or to have a trustee appointed to administer any ERISA Plan;
9. promptly and in any event within 30 days after the filing thereof with the Internal Revenue Service, copies of each Schedule B (Actuarial Information) to the annual report (Form 5500 Series) with respect to each ERISA Plan;
10. promptly and in any event within five Business Days after receipt thereof by the Borrower from a Multiemployer Plan sponsor, a copy of each notice received by the Borrower concerning the imposition of withdrawal liability pursuant to Section 4202 of ERISA;
11. promptly and in any event within five Business Days after Moody's or S&P has changed any Senior Debt Rating of any Significant Subsidiary, notice of such change; and
12. such other information respecting the condition or operations, financial or otherwise, of the Borrower or any of its subsidiaries as any Lender through the Administrative Agent may from time to time reasonably request.

SECTION 5.02.  Negative Covenants.

So long as any amount payable by the Borrower hereunder shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower will not, without the written consent of the Majority Lenders:

1. Liens, Etc. Create or suffer to exist any Lien upon or with respect to any of its properties (including, without limitation, any shares of any class of equity security of any of its Significant Subsidiaries or of Entergy New Orleans), in each case to secure or provide for the payment of Debt, other than: (i) Liens in existence on the date of this Agreement; (ii) Liens for taxes, assessments or governmental charges or levies to the extent not past due, or which are being contested in good faith in appropriate proceedings diligently conducted and for which the Borrower has provided adequate reserves for the payment thereof in accordance with generally accepted accounting principles; (iii) pledges or deposits in the ordinary course of business to secure obligations under worker's compensation laws or similar legislation; (iv) other pledges or deposits in the ordinary course of business (other than for borrowed monies) that, in the aggregate, are not material to the Borrowe r; (v) purchase money mortgages or other liens or purchase money security interests upon or in any property acquired or held by the Borrower in the ordinary course of business to secure the purchase price of such property or to secure indebtedness incurred solely for the purpose of financing the acquisition of such property; (vi) Liens imposed by law such as materialmen's, mechanics', carriers', workers' and repairmen's Liens and other similar Liens arising in the ordinary course of business for sums not yet due or currently being contested in good faith by appropriate proceedings diligently conducted; (vii) attachment, judgment or other similar Liens arising in connection with court proceedings, provided that such Liens, in the aggregate, shall not exceed $50,000,000 at any one time outstanding, (viii) other Liens not otherwise referred to in the foregoing clauses (i) through (vii) above, provided that such Liens, in the aggregate, shall not exceed $100,000,000 at any one time and (ix) Liens created for the sole purpose of extending, renewing or replacing in whole or in part Debt secured by any Lien referred in the foregoing clauses (i) through (vi) above, provided that the principal amount of indebtedness secured thereby shall not exceed the principal amount of indebtedness so secured at the time of such extension, renewal or replacement and that such extension, renewal or replacement, as the case may be, shall be limited to all or a part of the property or Debt that secured the Lien so extended, renewed or replaced (and any improvements on such property); provided, further, that no Lien permitted under the foregoing clauses (i) through (ix) shall be placed upon any shares of any class of equity security of any Significant Subsidiary or of Entergy New Orleans unless the obligations of the Borrower to the Lenders hereunder are simultaneously and ratably secured by such Lien pursuant to documentation satisfactory to the Lenders.
2. Limitation on Debt. Permit the total principal amount of all Debt of the Borrower and its subsidiaries, determined on a consolidated basis and without duplication of liability therefor, at any time to exceed 65% of Capitalization determined as of the last day of the most recently ended fiscal quarter of the Borrower; provided, however, that for purposes of this Section 5.02(b) "Debt" and "Capitalization" shall not include (i) Junior Subordinated Debentures issued to a subsidiary trust which has issued preferred securities that are included in the calculation of "Capitalization" and (ii) any Debt of any subsidiary of the Borrower that is Non-Recourse Debt.
3. Mergers, Etc. Merge with or into or consolidate with or into any other Person, except that the Borrower may merge with any other Person, provided that, immediately after giving effect to any such merger, (i) the Borrow er is the surviving corporation or (A) the surviving corporation is organized under the laws of one of the states of the United States of America and assumes the Borrower's obligations hereunder in a manner acceptable to the Majority Lenders, and (B) after giving effect to such merger, the senior unsecured long-term debt of such Person shall be at least BBB- and Baa3, (ii) no event shall have occurred and be continuing that constitutes a Prepayment Event or an Event of Default or would constitute an Event of Default but for the requirement that notice be given or time elapse or both, and (iii) the Borrower shall not be liable with respect to any Debt or allow its property to be subject to any Lien which would not be permissible with respect to it or its property under this Agreement on the date of such transaction.
4. Disposition of Assets. Sell, lease, transfer, convey or otherwise dispose of (whether in one transaction or in a series of transactions) an y shares of voting common stock (or of stock or other instruments convertible into voting common stock) of any Significant Subsidiary or of Entergy New Orleans, or permit any Significant Subsidiary or Entergy New Orleans to issue, sell or otherwise dispose of any of its shares of voting common stock (or of stock or other instruments convertible into voting common stock), except to the Borrower or a Significant Subsidiary.

ARTICLE VI
EVENTS OF DEFAULT AND REMEDIES

SECTION 6.01.  Events of Default.

Each of the following events shall constitute an "Event of Default" hereunder:

1. The Borrower shall fail to pay any principal of any Advance when the same becomes due and payable, or shall fail to pay interest thereon or any other amount payable under this Agreement within three Business Days after the same becomes due and payable; or
2. Any representation or warranty made by the Borrower herein or by the Borrower (or any of its officers) in connection with this Agreement shall prove to have been incorrect or misleading in any material respect when made; or
3. The Borrower shall fail to perform or observe (i) any term, covenant or agreement contained in Section 5.01(b) or 5.02 or (ii) any other term, covenant or agreement contained in this Agreement on its part to be performed or observed if the failure to perform or observe such other term, covenant or agreement shall remain unremedied for 30 days after written notice thereof shall have been given to the Borrower by the Administrative Agent or any Lender; or
4. The Borrower shall fail to pay any principal of or premium or interest on any Debt of the Borrower that is outstanding in a principal amount in excess of $50,000,000 in the aggregate (but excluding Debt hereunder) when the same becomes due and payable (whether by scheduled maturity, required prepayment, acceleration, demand or otherwise), and such failure shall continue after the applicable grace period, if any, specified in the agreement or instrument relating to such Debt; or
5. The Borrower, any Significant Subsidiary or Entergy New Orleans shall generally not pay its debts as such debts become due, or shall admit in writing its inability to pay its debts generally, or shall make a general assignment for the benefit of creditors; or any proceeding shall be instituted by or against the Borrower, any Significant Subsidiary or Entergy New Orleans seeking to adjudicate it a bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition of it or its debts under any law relating to bankruptcy, insolvency or reorganization or relief of debtors, or seeking the entry of an order for relief or the appointment of a receiver, trustee, custodian or other similar official for it or for any substantial part of its property and, in the case of any such proceeding instituted against it (but not instituted by it), either such proceeding shall remain undismissed or unstayed for a period of 30 days, or any of the actions sough t in such proceeding (including, without limitation, the entry of an order for relief against, or the appointment of a receiver, trustee, custodian or other similar official for, it or for any substantial part of its property) shall occur; or the Borrower, any Significant Subsidiary or Entergy New Orleans shall take any corporate action to authorize or to consent to any of the actions set forth above in this subsection (e); or
6. Any judgment or order for the payment of money in excess of $25,000,000 shall be rendered against the Borrower and either (i) enforcement proceedings shall have been commenced by any creditor upon such judgment or order or (ii) there shall be any period of 10 consecutive Business Days during which a stay of enforcement of such judgment or order, by reason of a pending appeal or otherwise, shall not be in effect; or
7. (i)  An ERISA Plan of the Borrower or any ERISA Affiliate of the Borrower shall fail to maintain the min imum funding standards required by Section 412 of the Internal Revenue Code of 1986 for any plan year or a waiver of such standard is sought or granted under Section 412(d) of the Internal Revenue Code of 1986, or (ii) an ERISA Plan of the Borrower or any ERISA Affiliate of the Borrower is, shall have been or will be terminated or the subject of termination proceedings under ERISA, or (iii) the Borrower or any ERISA Affiliate of the Borrower has incurred or will incur a liability to or on account of an ERISA Plan under Section 4062, 4063 or 4064 of ERISA and there shall result from such event either a liability or a material risk of incurring a liability to the PBGC or an ERISA Plan, or (iv) any ERISA Termination Event with respect to an ERISA Plan of the Borrower or any ERISA Affiliate of the Borrower shall have occurred, and in the case of any event described in clauses (i) through (iv), (A) such event (if correctable) shall not have been corrected and (B) the then-present value of such ERISA Pla n's vested benefits exceeds the then-current value of assets accumulated in such ERISA Plan by more than the amount of $25,000,000 (or in the case of an ERISA Termination Event involving the withdrawal of a "substantial employer" (as defined in Section 4001(a)(2) of ERISA), the withdrawing employer's proportionate share of such excess shall exceed such amount).

SECTION 6.02.  Remedies.

If any Prepayment Event or Event of Default shall occur and be continuing, then, and in any such event, the Administrative Agent (i) shall at the request, or may with the consent, of the Majority Lenders, by notice to the Borrower, declare the obligation of each Lender to make Advances to be terminated, whereupon the same shall forthwith terminate, and (ii) shall at the request, or may with the consent, of the Majority Lenders, by notice to the Borrower, declare the Advances, all interest thereon and all other amounts payable under this Agreement to be forthwith due and payable, whereupon the Advances, all such interest and all such amounts shall become and be forthwith due and payable, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by the Borrower; provided, however, that in the event of an actual or deemed entry of an order f or relief with respect to the Borrower, any Significant Subsidiary or Entergy New Orleans under the Federal Bankruptcy Code, (A) the obligation of each Lender to make Advances shall automatically be terminated and (B) the Advances, all such interest and all such amounts shall automatically become and be due and payable, without presentment, demand, protest or any notice of any kind, all of which are hereby expressly waived by the Borrower.

ARTICLE VII
THE AGENT

SECTION 7.01.  Authorization and Action.

Each Lender hereby appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers under this Agreement as are delegated to the Administrative Agent by the terms hereof, together with such powers as are reasonably incidental thereto. As to any matters not expressly provided for by this Agreement (including, without limitation, enforcement or collection of the Advances), the Administrative Agent shall not be required to exercise any discretion or take any action, but shall be required to act or to refrain from acting (and shall be fully protected in so acting or refraining from acting) upon the instructions of the Majority Lenders, and such instructions shall be binding upon all Lenders; provided, however, that the Administrative Agent shall not be required to take any action which exposes the Administrative Agent to personal liability or which is contrary to this Agreement or applicable law. The Administrative Agen t agrees to give to each Lender prompt notice of each notice given to it by the Borrower pursuant to the terms of this Agreement.

SECTION 7.02.  Administrative Agent's Reliance, Etc.

Neither the Administrative Agent nor any of its directors, officers, agents or employees shall be liable for any action taken or omitted to be taken by it or them under or in connection with this Agreement, except for its or their own gross negligence or willful misconduct. Without limitation of the generality of the foregoing, the Administrative Agent: (i) may consult with legal counsel (including counsel for the Borrower), independent public accountants and other experts selected by it and shall not be liable for any action taken or omitted to be taken in good faith by it in accordance with the advice of such counsel, accountants or experts; (ii) makes no warranty or representation to any Lender and shall not be responsible to any Lender for any statements, warranties or representations (whether written or oral) made in or in connection with this Agreement; (iii) shall not have any duty to ascertain or to inquire as to the performance or observance of any of the terms, covenants or conditions of this Agreement on the part of the Borrower or to inspect the property (including the books and records) of the Borrower; (iv) shall not be responsible to any Lender for the due execution, legality, validity, enforceability, genuineness, sufficiency or value of, or the perfection or priority of any lien or security interest created or purported to be created under or in connection with, this Agreement or any other instrument or document furnished pursuant hereto; and (v) shall incur no liability under or in respect of this Agreement by acting upon any notice, consent, certificate or other instrument or writing (which may be by telecopier, telegram, cable or telex) believed by it to be genuine and signed or sent by the proper party or parties.

SECTION 7.03.  HypoVereinsbank and Affiliates.

With respect to its Commitment and the Advances made by it, HypoVereinsbank shall have the same rights and powers under this Agreement as any other Lender and may exercise the same as though it were not the Administrative Agent; and the term "Lender" or "Lenders" shall, unless otherwise expressly indicated, include HypoVereinsbank in its individual capacity. HypoVereinsbank and its affiliates may accept deposits from, lend money to, act as trustee under indentures of, and generally engage in any kind of business with, the Borrower, any of its subsidiaries and any Person who may do business with or own securities of the Borrower or any such subsidiary, all as if HypoVereinsbank were not the Administrative Agent and without any duty to account therefor to the Lenders.

SECTION 7.04.  Lender Credit Decision.

Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent or any other Lender and based on the financial statements referred to in Section 4.01(e) and such other documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement.

SECTION 7.05.  Indemnification.

The Lenders agree to indemnify the Administrative Agent (to the extent not reimbursed by the Borrower), ratably according to the respective principal amounts of the Advances then outstanding to each of them (or if no Advances are at the time outstanding, ratably according to the respective amounts of their Commitments), from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever which may be imposed on, incurred by, or asserted against the Administrative Agent in any way relating to or arising out of this Agreement or any action taken or omitted by the Administrative Agent under this Agreement, provided that no Lender shall be liable for any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from the Administrative Agent's gross negligence or willful misconduct. Without limitation of the foregoing, each Lender agrees to reimburse the Administrative Agent promptly upon demand for its ratable share of any out-of-pocket expenses (including reasonable counsel fees) incurred by the Administrative Agent in connection with the preparation, execution, delivery, administration, modification, amendment or enforcement (whether through negotiations, legal proceedings or otherwise) of, or legal advice in respect of rights or responsibilities under, this Agreement, to the extent that such expenses are reimbursable by the Borrower but for which the Administrative Agent is not reimbursed by the Borrower.

SECTION 7.06.  Successor Administrative Agent.

The Administrative Agent may resign at any time by giving written notice thereof to the Lenders and the Borrower and may be removed at any time with or without cause by the Majority Lenders. Upon any such resignation or removal, the Majority Lenders shall have the right to appoint a successor Administrative Agent, which, for so long as no Prepayment Event or Event of Default has occurred and is continuing, shall be a Lender and shall be approved by the Borrower (with such approval not to be unreasonably withheld or delayed). If no successor Administrative Agent shall have been so appointed by the Majority Lenders and approved by the Borrower, and shall have accepted such appointment, within 30 days after the retiring Administrative Agent's giving of notice of resignation or the Majority Lenders' removal of the retiring Administrative Agent, then the retiring Administrative Agent may, on behalf of the Lenders, appoint a successor Administrative Agent, which shall be a commercial b ank organized under the laws of the United States or of any other country that is a member of the OECD having a combined capital and surplus of at least $50,000,000. Upon the acceptance of any appointment as Administrative Agent hereunder by a successor Administrative Agent, such successor Administrative Agent shall thereupon succeed to and become vested with all the rights, powers, privileges and duties of the retiring Administrative Agent, and the retiring Administrative Agent shall be discharged from its duties and obligations under this Agreement. After any retiring Administrative Agent's resignation or removal hereunder as Administrative Agent, the provisions of this Article VII shall inure to its benefit as to any actions taken or omitted to be taken by it while it was Administrative Agent under this Agreement. Notwithstanding the foregoing, if no Prepayment Event or Event of Default, and no event that with the giving of notice or the passage of time, or both, would constitute a Prepayment Event or an Event of Default, shall have occurred and be continuing, then no successor Administrative Agent shall be appointed under this Section 7.06 without the prior written consent of the Borrower, which consent shall not be unreasonably withheld or delayed.

ARTICLE VIII
MISCELLANEOUS

SECTION 8.01.  Amendments, Etc.

No amendment or waiver of any provision of this Agreement, nor consent to any departure by the Borrower therefrom, shall in any event be effective unless the same shall be in writing and signed by the Majority Lenders, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given; provided, however, that no amendment, waiver or consent shall, unless in writing and signed by all the Lenders (other than any Lender that is the Borrower or an Affiliate of the Borrower), do any of the following: (a) waive any of the conditions specified in Section 3.01 or 3.02, (b) increase the Commitments of the Lenders or subject the Lenders to any additional obligations, (c) reduce the principal of, or interest on, the Advances or any fees or other amounts payable hereunder, (d) change the percentage of the Commitments or of the aggregate u npaid principal amount of the Advances, or the number of Lenders that shall be required for the Lenders or any of them to take any action hereunder or (f) amend this Section 8.01; and provided further, that no amendment, waiver or consent shall, unless in writing and signed by the Administrative Agent in addition to the Lenders required above to take such action, affect the rights or duties of the Administrative Agent under this Agreement, and provided further, that this Agreement may be amended and restated without the consent of any Lender or the Administrative Agent if, upon giving effect to such amendment and restatement, such Lender or the Administrative Agent, as the case may be, shall no longer be a party to this Agreement (as so amended and restated) or have any Commitment or other obligation hereunder and shall have been paid in full all amounts payable hereunder to such Lender or the Administrative Agent, as the case may be.

SECTION 8.02.  Notices, Etc.

All notices and other communications provided for hereunder shall be in writing (including telecopier, telegraphic, telex or cable communication) and mailed, telecopied, telegraphed, telexed, cabled or delivered, if to the Borrower, at its address at 639 Loyola Avenue, New Orleans, LA 70113, Attention: Treasurer; if to any Bank, at its Domestic Lending Office specified opposite its name on Schedule I hereto; if to any other Lender, at its Domestic Lending Office specified in the Assignment and Acceptance pursuant to which it became a Lender; and if to the Administrative Agent, at its address at 245 Park Avenue, 32^nd Floor, New York, NY 10167, Attention: Loan Operations, Tina Chung/Mariana Mucenica (Telephone: (212) 672-5688/5811, Facsimile: (212) 672-5691) or, as to each party, at such other address as shall be designated by such party in a written notice to the other parties. All such notices and communications shall, when mailed, telecopied, telegraphed, telexed or ca bled, be effective when deposited in the mails, telecopied, delivered to the telegraph company, confirmed by telex answerback or delivered to the cable company, respectively, except that notices and communications to the Administrative Agent pursuant to Article II or VII shall not be effective until received by the Administrative Agent. Except as otherwise provided in Section 5.01(c), notices and other communications given by the Borrower to the Administrative Agent shall be deemed given to the Lenders.

SECTION 8.03.  No Waiver; Remedies.

No failure on the part of any Lender or the Administrative Agent to exercise, and no delay in exercising, any right hereunder shall operate as a waiver thereof; nor shall any single or partial exercise of any such right preclude any other or further exercise thereof or the exercise of any other right. The remedies herein provided are cumulative and not exclusive of any remedies provided by law.

SECTION 8.04.  Costs and Expenses; Indemnification.

1. The Borrower agrees to pay on demand all costs and expenses incurred by the Administrative Agent in connection with the preparation, execution, delivery, syndication administration, modification and amendment of this Agreement and the other documents to be delivered hereunder, including, without limitation, the reasonable fees and out-of-pocket expenses of counsel for the Administrative Agent with respect thereto and with respect to advising the Administrative Agent as to its rights and responsibilities under this Agreement. Any invoices to the Borrower with respect to the aforementioned expenses shall describe such costs and expenses in reasonable detail. The Borrower further agrees to pay on demand all costs and expenses, if any (including, without limitation, counsel fees and expenses of outside counsel and of internal counsel), incurred by the Administrative Agent and the Lenders in connection with the enforcement (whether through negotiations, legal proceedings or otherwise) of, and the pr otection of the rights of the Lenders under, this Agreement and the other documents to be delivered hereunder, including, without limitation, reasonable counsel fees and expenses in connection with the enforcement of rights under this Section 8.04(a).
2. If any payment of principal of, or Conversion of, any Eurodollar Rate Advance is made other than on the last day of the Interest Period for such Advance, as a result of a payment or Conversion pursuant to Section 2.07(c), 2.08, 2.09 or 2.11, acceleration of the maturity of the Advances pursuant to Section 6.02, assignment to another Lender upon demand of the Borrower pursuant to Section 8.07(g) or (h) or for any other reason, the Borrower shall, upon demand by any Lender (with a copy of such demand to the Administrative Agent), pay to the Administrative Agent for the account of such Lender any amounts required to compensate such Lender for any additional losses, costs or expenses which it may reasonably incur as a result of such payment or Conversion, including, without limitation, any loss (including loss of anticipated profits upon such Lender's representation to the Borrower that it has made reasonable efforts to mitigate such loss), cost or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by any Lender to fund or maintain such Advance. Any Lender making a demand pursuant to this Section 8.04(b) shall provide the Borrower with a written certification of the amounts required to be paid to such Lender, showing in reasonable detail the basis for the Lender's determination of such amounts; provided, however, that no Lender shall be required to disclose any confidential or proprietary information in any certification provided pursuant hereto, and the failure of any Lender to provide such certification shall not affect the obligations of the Borrower hereunder.
3. The Borrower hereby agrees to indemnify and hold each Lender, the Administrative Agent and their respective Affiliates and their respective officers, directors, employees and professional advisors (each, an "Indemnified Person") harmless from and against any and all claims, damages, losses, liabilities, costs or expenses (including reasonable attorney's fees and expenses, whether or not such Indemnified Person is named as a party to any proceeding or is otherwise subjected to judicial or legal process arising from any such proceeding) that any of them may incur or which may be claimed against any of them by any Person or entity by reason of or in connection with the execution, delivery or performance of this Agreement or any transaction contemplated hereby, or the use by the Borrower or any of its subsidiaries of the proceeds of any Advance, except that no Indemnified Person shall be entitled to any indemnification hereunder to the extent that such claims, damag es, losses, liabilities, costs or expenses are finally determined by a court of competent jurisdiction to have resulted from the gross negligence or willful misconduct of such Indemnified Person. The Borrower's obligations under this Section 8.04(c) shall survive the repayment of all amounts owing to the Lenders and the Administrative Agent under this Agreement and the termination of the Commitments. If and to the extent that the obligations of the Borrower under this Section 8.04(c) are unenforceable for any reason, the Borrower agrees to make the maximum contribution to the payment and satisfaction thereof which is permissible under applicable law. The Borrower also agrees not to assert any claim against any Lender, any of such Lender's affiliates, or any of their respective directors, officers, employees, attorneys and agents, on any theory of liability, for special, indirect, consequential or punitive damages arising out of or otherwise relating to this Agreement, any of the transactions contemplated herein or the actual or proposed use of the proceeds of the Advances.

SECTION 8.05.  Right of Set-off.

Upon (i) the occurrence and during the continuance of any Prepayment Event or Event of Default and (ii) the making of the request or the granting of the consent specified by Section 6.02 to authorize the Administrative Agent to declare the Advances due and payable pursuant to the provisions of Section 6.02, each Lender is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by such Lender to or for the credit or the account of the Borrower against any and all of the obligations of the Borrower now or hereafter existing under this Agreement, whether or not such Lender shall have made any demand under this Agreement and although such obligations may be unmatured. Each Lender agrees promptly to notify the Borrower after any such set-off and application made by such Lender, provided that the failure to give such notice shall not affect the validity of such set-off and application. The rights of each Lender under this Section 8.05 are in addition to other rights and remedies (including, without limitation, other rights of set-off) which such Lender may have.

SECTION 8.06.  Binding Effect.

This Agreement shall become effective when it shall have been executed by the Borrower, the Lenders and the Administrative Agent and thereafter shall be binding upon and inure to the benefit of the Borrower, the Administrative Agent and each Lender and their respective successors and assigns, except that the Borrower shall not have the right to assign its rights hereunder or any interest herein without the prior written consent of the Lenders.

SECTION 8.07.  Assignments and Participations.

1. Each Lender may assign to one or more banks or other entities all or a portion of its rights and obligations under this Agreement (including, without limitation, all or a portion of its Commitment and the Advances owing to it); provided, however, that (i) the Borrower (unless a Prepayment Event or an Event of Default shall have occurred and be continuing) and the Administrative Agent shall have consented to such assignment (with each such consent not to be unreasonably withheld or delayed) by signing the Assignment and Acceptance referred to in clause (iv) below; (ii) each such assignment shall be of a constant, and not a varying, percentage of all rights and obligations under this Agreement; (iii) the amount of the Commitment of the assigning Lender being assigned pursuant to each such assignment (determined as of the date of the Assignment and Acceptance with respect to such assignment) shall in no event be less than $10,000,000 and shall be an integral multiple of $1,000,000 (or shall be the total amount of the assigning Lender's Commitment); and (iv) the parties to each such assignment shall execute and deliver to the Administrative Agent, for its acceptance and recording in the Register, an Assignment and Acceptance, together with any promissory notes held by the assigning Lender and a processing and recordation fee of $3,500 (plus an amount equal to out-of-pocket legal expenses of the Administrative Agent, estimated by the Administrative Agent and advised to such parties). Upon such execution, delivery, acceptance and recording, from and after the effective date specified in each Assignment and Acceptance, (x) the assignee thereunder shall be a party hereto and, to the extent that rights and obligations hereunder have been assigned to it pursuant to such Assignment and Acceptance, have the rights and obligations of a Lender hereunder and (y) the Lender assignor thereunder shall, to the extent that rights and obligations hereunder have been assigned by it pursuant to such Assignment and Acceptance, relinquish its rights and be released from its obligations under this Agreement (and, in the case of an Assignment and Acceptance covering all or the remaining portion of an assigning Lender's rights and obligations under this Agreement, such Lender shall cease to be a party hereto). Notwithstanding anything to the contrary contained in this Agreement, any Lender at any time may assign all or any portion of its rights and obligations under this Agreement to any Affiliate or Approved Fund of such Lender.
2. By executing and delivering an Assignment and Acceptance, the Lender assignor thereunder and the assignee thereunder confirm to and agree with each other and the other parties hereto as follows: (i) other than as provided in such Assignment and Acceptance, such assigning Lender makes no representation or warranty and assumes no responsibility with respect to any statements, warranties or representations made in or in connection with this Agreement or the execution, legality, validity, enforceability, genuineness, sufficiency or value of this Agreement or any other instrument or document furnished pursuant hereto; (ii) such assigning Lender makes no representation or warranty and assumes no responsibility with respect to the financial condition of the Borrower or the performance or observance by the Borrower of any of its obligations under this Agreement or any other instrument or document furnished pursuant hereto; (iii) such assignee confirms that it has received a cop y of this Agreement, together with copies of the financial statements referred to in Section 4.01(e) and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into such Assignment and Acceptance; (iv) such assignee will, independently and without reliance upon the Administrative Agent, such assigning Lender or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement; (v) such assignee appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers under this Agreement as are delegated to the Administrative Agent by the terms hereof, together with such powers as are reasonably incidental thereto; and (vi) such assignee agrees that it will perform in accordance with their terms all of the obligations which by the terms of this Agreement a re required to be performed by it as a Lender.
3. The Administrative Agent shall maintain at its address referred to in Section 8.02 a copy of each Assignment and Acceptance delivered to and accepted by it and a register for the recordation of the names and addresses of the Lenders and the Commitment of, and principal amount of the Advances owing to, each Lender from time to time (the "Register"). The entries in the Register shall be conclusive and binding for all purposes, absent manifest error, and the Borrower, the Administrative Agent and the Lenders may treat each Person whose name is recorded in the Register as a Lender hereunder for all purposes of this Agreement. The Register shall be available for inspection by the Borrower or any Lender at any reasonable time and from time to time upon reasonable prior notice.
4. Upon its receipt of an Assignment and Acceptance executed by an assigning Lender and an assignee, together with an y promissory notes held by the assigning Lender, the Administrative Agent shall, if such Assignment and Acceptance has been completed and is in substantially the form of Exhibit B hereto, (i) accept such Assignment and Acceptance, (ii) record the information contained therein in the Register and (iii) give prompt notice thereof to the Borrower.
5. Each Lender may sell participations to one or more banks, financial institutions or other entities in or to all or a portion of its rights and obligations under this Agreement (including, without limitation, all or a portion of its Commitment and the Advances owing to it); provided, however, that (i) such Lender's obligations under this Agreement (including, without limitation, its Commitment to the Borrower hereunder) shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, (iii) such Lender shall remain the maker of any such Advance for all purposes of this Agreement and (iv) the Borrower, the Administrative Agent and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender's rights and obligations under this Agreement.
6. Any Lender may, in connection with any assignment or participation or proposed assignment or participation pursuant to this Section 8.07, disclose to the assignee or participant or proposed assignee or participant, any information relating to the Borrower furnished to such Lender by or on behalf of the Borrower; provided that, prior to any such disclosure, the assignee or participant or proposed assignee or participant shall agree to preserve the confidentiality of any confidential information relating to the Borrower received by it from such Lender.
7. If any Lender shall make any demand for payment under Section 2.10 or 2.13, or if any Lender shall be the subject of any notification or assertion of illegality under Section 2.11, then within 30 days after any such demand (if, but only if, such demanded payment has been made by the Borrower) or notification or assertion, the Borrower may, with the approval of the Administrative Agent (which approval shall not be unreasonably withheld) and provided that no Prepayment Event, Event of Default or event that, with the giving of notice or lapse of time or both, would constitute an Event of Default, shall then have occurred and be continuing, demand that such Lender assign in accordance with this Section 8.07 to one or more assignees designated by the Borrower and acceptable to the Administrative Agent all (but not less than all) of such Lender's Commitment and the Advances owing to it within the period ending on the later to occur of such 30th day and the last day of the longest of the then current Interest Periods for such Advances. If any such assignee designated by the Borrower and approved by the Administrative Agent shall fail to consummate such assignment on terms acceptable to such Lender, or if the Borrower shall fail to designate any such assignees acceptable to the Administrative Agent for all or part of such Lender's Commitment or Advances, then such demand by the Borrower shall become ineffective ; it being understood for purposes of this subsection (h) that such assignment shall be conclusively deemed to be on terms acceptable to such Lender, and such Lender shall be compelled to consummate such assignment to an Eligible Assignee designated by the Borrower, if such Eligible Assignee (A) shall agree to such assignment by entering into an Assignment and Acceptance with such Lender and (B) shall offer compensation to such Lender in an amount equal to all amounts then owing by the Borrower to such Lender hereunder, whether for principal, interest, fees, costs or expenses (other than the demanded payment referred to above and payable by the Borrower as a condition to the Borrower's right to demand such assignment), or otherwise. In addition, in the event that the Borrower shall be entitled to demand the replacement of any Lender pursuant to this subsection (h), the Borrower may, in the case of any such Lender, with the approval of the Administrative Agent (which approval shall not be un reasonably withheld) and provided that no Prepayment Event, Event of Default or event that, with the giving of notice or lapse of time or both, would constitute an Event of Default, shall then have occurred and be continuing, terminate all (but not less than all) such Lender's Commitment and prepay all (but not less than all) such Lender's Advances not so assigned, together with all interest accrued thereon to the date of such prepayment and all fees, costs and expenses and other amounts then owing by the Borrower to such Lender hereunder, at any time from and after such later occurring day in accordance with Section 2.09 hereof (but without the requirement stated therein for ratable treatment of the other Lenders), if and only if, after giving effect to such termination and prepayment, the sum of the aggregate principal amount of the Advances of all Lenders then outstanding does not exceed the then remaining Commitments of the Lenders. Notwithstanding anything set forth above in this subsection (h) to the contrary, the Borrower shall not be entitled to compel the assignment by any Lender demanding payment under Section 2.10(a) of its Commitment and Advances or terminate and prepay the Commitment and Advances of such Lender if, prior to or promptly following any such demand by the Borrower, such Lender shall have changed or shall change, as the case may be, its Applicable Lending Office for its Eurodollar Rate Advances so as to eliminate the further incurrence of such increased cost. In furtherance of the foregoing, any such Lender demanding payment or giving notice as provided above agrees to use reasonable efforts to so change its Applicable Lending Office if, to do so, would not result in the incurrence by such Lender of additional costs or expenses which it deems material or, in the sole judgment of such Lender, be inadvisable for regulatory, competitive or internal management reasons.
8. Anything in this Section 8.07 to the contrary notwithstanding, any Lender may assign and pledge all or any portion of its Commitment and the Advances owing to it to any Federal Reserve Bank (and its transferees) as collateral security pursuant to Regulation A of the Board of Governors of the Federal Reserve System and any Operating Circular issued by such Federal Reserve Bank. No such assignment shall release the assigning Lender from its obligations hereunder.
9. Notwithstanding anything to the contrary contained herein, any Lender (a "Granting Lender") may grant to a special purpose funding vehicle (an "SPC") of such Granting Lender identified as such in writing from time to time by the Granting Lender to the Administrative Agent and the Borrower, the option to provide to the Borrower all or any part of any Advance that such Granting Lender would otherwise be obligated to make to the Borrower pursuant to this Agreement; provided that (i) nothing herein shall constitute a commitment by any such SPC to make any Advance, (ii) if such SPC elects not to exercise such option or otherwise fails to provide all or any part of such Advance, the Granting Lender shall be obligated to make such Advance pursuant to the terms hereof and (iii) no SPC or Granting Lender shall be entitled to receive any greater amount pursuant to Section 2.10 or 8.04(b) than the Granting Lender would have been entitled to receive had the Granting Lender not otherwise granted such SPC the option to provide any Advance to the Borrower. The making of an Advance by an SPC hereunder shall utilize the Commitment of the Granting Lender to the same extent, and as if, such Advance were made by such Granting Lender. Each party hereto hereby agrees that no SPC shall be liable for any indemnity or similar payment obligation under this Agreement for which a Lender would otherwise be liable so long as, and to the extent that, the related Granting Lender provides such indemnity or makes such payment. In furtherance of the foregoing, each party hereto hereby a grees (which agreement shall survive the termination of this Agreement) that, prior to the date that is one year and one day after the payment in full of all outstanding commercial paper or other senior indebtedness of any SPC, it will not institute against or join any other person in instituting against such SPC any bankruptcy, reorganization, arrangement, insolvency or liquidation proceedings under the laws of the United States or any State thereof. Notwithstanding the foregoing, the Granting Lender unconditionally agrees to indemnify the Borrower, the Administrative Agent and each Lender against all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever which may be incurred by or asserted against the Borrower, the Administrative Agent or such Lender, as the case may be, in any way relating to or arising as a consequence of any such forbearance or delay in the initiation of any such proceeding against its SPC. Ea ch party hereto hereby acknowledges and agrees that no SPC shall have the rights of a Lender hereunder, such rights being retained by the applicable Granting Lender. Accordingly, and without limiting the foregoing, each party hereby further acknowledges and agrees that no SPC shall have any voting rights hereunder and that the voting rights attributable to any Advance made by an SPC shall be exercised only by the relevant Granting Lender and that each Granting Lender shall serve as the administrative agent and attorney-in-fact for its SPC and shall on behalf of its SPC receive any and all payments made for the benefit of such SPC and take all actions hereunder to the extent, if any, such SPC shall have any rights hereunder. In addition, notwithstanding anything to the contrary contained in this Agreement any SPC may (i) with notice to, but without the prior written consent of any other party hereto, assign all or a portion of its interest in any Advances to the Granting Lender and (ii) disclose on a confid ential basis any information relating to its Advances to any rating agency, commercial paper dealer or provider of any surety, guarantee or credit or liquidity enhancement to such SPC. This Section 8.07(i) may not be amended without the prior written consent of each Granting Lender, all or any part of whose Advance is being funded by an SPC at the time of such amendment.

SECTION 8.08.  Governing Law.

THIS AGREEMENT AND ANY NOTE ISSUED PURSUANT TO SECTION 2.15 SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

SECTION 8.09.  Consent to Jurisdiction; Waiver of Jury Trial.

1. To the fullest extent permitted by law, the Borrower hereby irrevocably (i) submits to the non-exclusive jurisdiction of any New York State or Federal court sitting in New York City and any appellate court from any thereof in any action or proceeding arising out of or relating to this Agreement and (ii) agrees that all claims in respect of such action or proceeding may be heard and determined in such New York State court or in such Federal court. The Borrower hereby irrevocably waives, to the fullest extent permitted by law, the defense of an inconvenient forum to the maintenance of such action or proceeding. The Borrower also irrevocably consents, to the fullest extent permitted by law, to the service of any and all process in any such action or proceeding by the mailing by certified mail of copies of such process to the Borrower at its address specified in Section 8.02. The Borrower agrees, to the fullest extent permitted by law, that a final judgment in any such action or proceedi ng shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law.
2. THE BORROWER, THE ADMINISTRATIVE AGENT AND THE LENDERS HEREBY IRREVOCABLY WAIVE ALL RIGHT TO TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY INSTRUMENT OR DOCUMENT DELIVERED HEREUNDER.

SECTION 8.10.  Execution in Counterparts.

This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement.

[The remainder of this page intentionally left blank.]

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized, as of the date first above written.

ENTERGY CORPORATION

By                                                                      
    Steven C. McNeal
    Vice President and Treasurer

BAYERISCHE HYPO- UND VEREINSBANK AG,
NEW YORK BRANCH
     as Administrative Agent

By                                                                      
       Name:
       Title:

By                                                                      
       Name:
       Title:

BANKS

BAYERISCHE HYPO- UND VEREINSBANK AG,
NEW YORK BRANCH

By                                                                      
       Name:
       Title:

By                                                                      
       Name:
       Title:

SCHEDULE I

ENTERGY CORPORATION

U.S. $60,000,000 Credit Agreement

Name of Bank	Payment Instructions	Domestic Lending Office	Eurodollar Lending Office
Bayerische Hypo- und Vereinsbank AG, New York Branch	Fedwire: #9; Federal Reserve Bank of New York Favor: Bayerische Hypo- und Vereinsbank AG, New York Branch ABA No.: 026 008 808 A/C#: 594 012 033 405 501 Account Name: Loan Servicing Reference: Entergy Term Loan Attention: Tina Chung Swift: HYVEUS 33	Bayerische Hypo- und Vereinsbank AG, New York Branch 245 Park Avenue 32nd Floor New York, NY 10167	Bayerische Hypo- und Vereinsbank AG, Grand Cayman Branch c/o Bayerische Hypo- und Vereinsbank AG 245 Park Avenue 32nd Floor New York, NY 10167

SCHEDULE II

COMMITMENT SCHEDULE

Name of Lender	Commitment Amount
Bayerische Hypo- und Vereinsbank AG, New York Branch	$60,000,000
Total Commitment:	$60,000,000

EXHIBIT A-1

FORM OF NOTICE OF BORROWING

Bayerische Hypo- und Vereinsbank AG, New York Branch
    as Administrative Agent
            for the Lenders parties
            to the Credit Agreement
            referred to below
245 Park Avenue, 32nd Floor
New York, New York 10167

[Date]

Attention: Bank Loan Syndications

Ladies and Gentlemen:

The undersigned, Entergy Corporation, refers to the Credit Agreement, dated as of May 31, 2002 (the "Credit Agreement", the terms defined therein being used herein as therein defined), among the undersigned, certain Lenders parties thereto and Bayerische Hypo- und Vereinsbank AG, New York Branch, as Administrative Agent for said Lenders, and hereby gives you notice, irrevocably, pursuant to Section 2.02 of the Credit Agreement that the undersigned hereby requests a Borrowing under the Credit Agreement, and in that connection sets forth below the information relating to such Borrowing (the "Proposed Borrowing") as required by Section 2.02(a) of the Credit Agreement:

1. The Business Day of the Proposed Borrowing is , 20   .

 
2. The Type of Advances to be made in connection with the Proposed Borrowing is [Base Rate Advances] [Eurodollar Rate Advances].
3. The aggregate amount of the Proposed Borrowing is $ .
4. The Interest Period for each Eurodollar Rate Advance made as part of the Proposed Borrowing is ___ month[s].¹
5. [ENTERGY WIRE INSTRUCTIONS].

The undersigned hereby certifies that the following statements are true on the date hereof, and will be true on the date of the Proposed Borrowing:

1. the representations and warranties contained in Section 4.01 of the Credit Agreement are correct, before and after giving effect to the Proposed Borrowing and to the application of the proceeds therefrom, as though made on and as of such date; and
2. no event has occurred and is continuing, or would result from such Proposed Borrowing or from the application of the proceeds therefrom, that constitutes a Prepayment Event or an Event of Default or would constitute an Event of Default but for the requirement that notice be given or time elapse or both.

Very truly yours,

ENTERGY CORPORATION
 

By                                                                      
       Name:
       Title:

_________________________
¹ Delete for Base Rate Advances.

EXHIBIT A-2

FORM OF NOTICE OF CONVERSION

Bayerische Hypo- und Vereinsbank AG, New York Branch
    as Administrative Agent
            for the Lenders parties
            to the Credit Agreement
            referred to below
245 Park Avenue, 32nd Floor
New York, New York 10167

[Date]

Attention: Bank Loan Syndications

Ladies and Gentlemen:

The undersigned, Entergy Corporation, refers to the Credit Agreement, dated as of May 31, 2002 (the "Credit Agreement", the terms defined therein being used herein as therein defined), among the undersigned, certain Lenders party thereto and Bayerische Hypo- und Vereinsbank AG, New York Branch, as Administrative Agent for said Lenders, and hereby gives you notice, irrevocably, pursuant to Section 2.08 of the Credit Agreement, that the undersigned hereby requests a Conversion under the Credit Agreement, and in that connection sets forth below the information relating to such Conversion (the "Proposed Conversion") as required by Section 2.08 of the Credit Agreement:

1. The Business Day of the Proposed Conversion is __________, _____.
2. The Type of Advances comprising the Proposed Conversion is [Base Rate Advances] [Eurodollar Rate Advances].
3. The aggregate amount of the Proposed Conversion is $__________.
4. The Type of Advances to which such Advances are proposed to be Converted is [Base Rate Advances] [Eurodollar Rate Advances].
5. The Interest Period for each Advance made as part of the Proposed Conversion is ___ month(s).²

The undersigned hereby represents and warrants that the following statements are true on the date hereof, and will be true on the date of the Proposed Conversion:

1. The Borrower's request for the Proposed Conversion is made in compliance with Section 2.08 of the Credit Agreement; and

 
2. The statements contained in Section 3.02 of the Credit Agreement are true.

Very truly yours,

ENTERGY CORPORATION
 

By                                                                      
       Name:
       Title:

_________________________
² Delete for Base Rate Advances.

EXHIBIT B

FORM OF ASSIGNMENT AND ACCEPTANCE

Dated ___________, 20__

Reference is made to the Credit Agreement, dated as of May 31, 2002 (as amended, modified or supplemented from time to time, the "Credit Agreement"), among Entergy Corporation, a Delaware corporation (the "Borrower"), the Lenders (as defined in the Credit Agreement) and Bayerische Hypo- und Vereinsbank AG, New York Branch, as Administrative Agent for the Lenders (the "Administrative Agent"). Terms defined in the Credit Agreement are used herein with the same meaning.

____________ (the "Assignor") and ___________ (the "Assignee") agree as follows:

1. The Assignor hereby sells and assigns to the Assignee without recourse, and the Assignee hereby purchases and assumes from the Assignor, that interest in and to all of the Assignor's rights and obligations under the Credit Agreement as of the date hereof which represents the percentage interest specified on Schedule 1 of all outstanding rights and obligations under the Credit Agreement, including, without limitation, such interest in the Assignor's Commitment and the Advances owing to the Assignor. After giving effect to such sale and assignment, the Assignee's Commitment and the amount of the Advances owing to the Assignee will be as set forth in Section b of Schedule 1.
2. The Assignor (A) represents and warrants that it is the legal and beneficial owner of the interest being assigned by it hereunder and that such interest is free and clear of any adverse claim; (B) makes no representation or warranty and assumes no responsibility with respect to any statements, warranties or representations made in or in connection with the Credit Agreement or the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Credit Agreement or any other instrument or document furnished pursuant thereto; and (C) makes no representation or warranty and assumes no responsibility with respect to the financial condition of the Borrower or the performance or observance by the Borrower of any of its obligations under the Credit Agreement or any other instrument or document furnished pursuant thereto. Except as specified in this Section b, the assignment hereunder shall be without recourse to the Assignor.
3. The Assignee (A)  confirms that it has received a copy of the Credit Agreement, together with copies of the financial statements referred to in Section 4.01 thereof and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Assignment and Acceptance; (B) agrees that it will, independently and without reliance upon the Administrative Agent, the Assignor or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Credit Agreement; (C) appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers under the Credit Agreement as are delegated to the Administrative Agent by the terms thereof, together with such powers as are reasonably incidental thereto; (D) agrees that it will perform in accordance with their terms all of the obligations which by the te rms of the Credit Agreement are required to be performed by it as a Lender; [and] (E) specifies as its Domestic Lending Office (and address for notices) and Eurodollar Lending Office the offices set forth beneath its name on the signature pages hereof [and (F) attaches the forms prescribed by the Internal Revenue Service of the United States certifying that it is exempt from United States withholding taxes with respect to all payments to be made to the Assignee under the Credit Agreement].¹
4. Following the execution of this Assignment and Acceptance by the Assignor and the Assignee, it will be delivered to the Administrative Agent for acceptance and recording by the Administrative Agent. The effective date of this Assignment and Acceptance shall be the date of acceptance thereof by the Administrative Agent, unless otherwise specified on Schedule 1 hereto (the "Effective Date"); provided, however, that in no event shall this Assignm ent and Acceptance become effective prior to the payment for the processing and recordation fee to the Administrative Agent as provided in Section 8.07(a) of the Credit Agreement.
5. Upon such acceptance and recording by the Administrative Agent, as of the Effective Date, (A) the Assignee shall be a party to the Credit Agreement and, to the extent provided in this Assignment and Acceptance, have the rights and obligations of a Lender thereunder and (B) the Assignor shall, to the extent provided in this Assignment and Acceptance, relinquish its rights and be released from its obligations under the Credit Agreement.
6. Upon such acceptance and recording by the Administrative Agent, from and after the Effective Date, the Administrative Agent shall make all payments under the Credit Agreement in respect of the interest assigned hereby (including, without limitation, all payments of principal and interest with respect thereto) to the Assignee. The Assigno r and Assignee shall make all appropriate adjustments in payments under the Credit Agreement for periods prior to the Effective Date directly between themselves.
7. THIS ASSIGNMENT AND ACCEPTANCE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.
8. This Assignment and Acceptance may be signed in any number of counterparts, each of which shall be deemed an original, with the same effect as if the signatures thereto and hereto were up on the same instrument.

IN WITNESS WHEREOF, the parties hereto have caused this Assignment and Acceptance to be executed by their respective officers thereunto duly authorized, as of the date first above written, such execution being made on Schedule 1 hereto.

[NAME OF ASSIGNOR]
 

By                                                                      
       Name:
       Title:

[NAME OF ASSIGNEE]
 

By                                                                      
       Name:
       Title:

Domestic Lending Office (and
   address for notices):
      [Address]

_________________________
¹ If the Assignee is organized under the laws of a jurisdiction outside the United States.

Eurodollar Lending Office:
[Address]

Accepted this ___ day
of ___________, 20__
 

BAYERISCHE - UND VEREINSBANK AG, NEW YORK BRANCH
        as Administrative Agent

By                                                                      
       Name:
       Title:

By                                                                      
       Name:
       Title:

Schedule 1

to

Assignment and Acceptance

Dated __________, 20__

Section (a)
Percentage Interest:	%
Section (b)
Assignee's Commitment:	$
Aggregate Outstanding Principal
Amount of Advances owing          to the Assignee:	$
Section (c)
Effective Date1: _________, 20__

_________________________
¹ This date should be no earlier than the date of acceptance by the Administrative Agents.

EXHIBIT C

FORM OF OPINION OF
COUNSEL FOR THE BORROWER

[Date]

To each of the Lenders parties to the
    Credit Agreement referred to below,
    and to Bayerische Hypo- und Vereinsbank AG, New York Branch
    as Administrative Agent

Entergy Corporation

Ladies and Gentlemen:

I have acted as counsel to Entergy Corporation, a Delaware corporation (the "Borrower"), in connection with the preparation, execution and delivery of the Credit Agreement, dated as of May 31, 2002, by and among the Borrower, the Banks parties thereto and the other Lenders from time to time parties thereto and Bayerische Hypo- und Vereinsbank AG, New York Branch, as Administrative Agent. This opinion is furnished to you at the request of the Borrower pursuant to Section 3.01(a)(v) of the Credit Agreement. Unless otherwise defined herein or unless the context otherwise requires, terms defined in the Credit Agreement are used herein as therein defined.

In such capacity, I have examined:

1. Counterparts of the Credit Agreement, executed by the Borrower;
2. The Certificate of Incorporation of the Borrower (the "Charter");
3. The Bylaws of the Borrower (the "Bylaws");
4. A certificate of the Secretary of State of the State of Delaware, dated May __, 2002, attesting to the continued corporate existence and good standing of the Borrower in that State;
5. A Certificate of the Secretary of State of the State of Louisiana, dated May __, 2002, attesting that the Borrower is a foreign corporation duly qualified to conduct business in that state;
6. A copy of the Order dated April 3, 2001 of the Securities and Exchange Commission (File No. 70-9749) under the Public Utility Holding Company Act of 1935 (the "SEC Order"); and
7. The other documents furnished by the Borrower to the Administrative Agent pursuant to Section 3.01(a) of the Credit Agreement.

I have also examined such other corporate records of the Borrower, certificates of public officials and of officers of the Borrower, and agreements, instruments and other documents, as I have deemed necessary as a basis for the opinions expressed below.

In my examination, I have assumed the genuineness of all signatures, the legal capacity of natural persons, the authenticity of all documents submitted to me as originals, and the conformity with the originals of all documents submitted to me as copies. In making my examination of documents and instruments executed or to be executed by persons other than the Borrower, I have assumed that each such other person had the requisite power and authority to enter into and perform fully its obligations thereunder, the due authorization by each such other person for the execution, delivery and performance thereof and the due execution and delivery thereof by or on behalf of such person of each such document and instrument. In the case of any such person that is not a natural person, I have also assumed, insofar as it is relevant to the opinions set forth below, that each such other person is duly organized, validly existing and in good standing under the laws of the jurisdiction in which it was c reated, and is duly qualified and in good standing in each other jurisdiction where the failure to be so qualified could reasonably be expected to have a material effect upon its ability to execute, deliver and/or perform its obligations under any such document or instrument. I have further assumed that each document, instrument, agreement, record and certificate reviewed by me for purposes of rendering the opinions expressed below has not been amended by any oral agreement, conduct or course of dealing between the parties thereto.

As to questions of fact material to the opinions expressed herein, I have relied upon certificates and representations of officers of the Borrower (including but not limited to those contained in the Credit Agreement and certificates delivered upon the execution and delivery of the Credit Agreement) and of appropriate public officials, without independent verification of such matters except as otherwise described herein.

Whenever my opinions herein with respect to the existence or absence of facts are stated to be to my knowledge or awareness, it is intended to signify that no information has come to my attention or the attention of other counsel working under my direction in connection with the preparation of this opinion letter that would give me or them actual knowledge of the existence or absence of such facts. However, except to the extent expressly set forth herein, neither I nor they have undertaken any independent investigation to determine the existence or absence of such facts, and no inference as to my or their knowledge of the existence or absence of such facts should be assumed.

On the basis of the foregoing, having regard for such legal consideration as I deem relevant, and subject to the other limitations and qualifications contained in this letter, I am of the opinion that:

1. The Borrower is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware and is duly qualified to do business as a foreign corporation in each jurisdiction in which the nature of the business conducted or the property owned, operated or leased by it requires such qualification.
2. The execution, delivery and performance by the Borrower of the Credit Agreement are within the Borrower's corporate powers, have been duly authorized by all necessary corporate action and do not contravene (i) the Charter or the Bylaws or (ii) law, or (iii) any contractual or legal restriction binding on or affecting the Borrower. The Credit Agreement has been duly executed and delivered on behalf of the Borrower.
3. No authorization, approval or other action by, and no notice to or filing with, any governmental authority or regulatory body, is required for the due execution, delivery and performance by the Borrower of the Credit Agreement, except for the SEC Order, which has been obtained, is final and in full force and effect, and is not the subject of any appeal.
4. Except as disclosed in the Borrower's Annual Report on Form 10-K for the fiscal year ended December 31, 2001, and in the Borrower's Quarterly Report on Form 10-Q for the period ended March&n bsp;31, 2002, there is no pending or, to the best of my knowledge, threatened action or proceeding affecting the Borrower or any of its subsidiaries before any court, governmental agency or arbitrator that reasonably could be expected to affect materially and adversely the condition (financial or otherwise), operations, business, properties or prospects of the Borrower or its ability to perform its obligations under the Credit Agreement, or that purports to affect the legality, validity, binding effect or enforceability of the Credit Agreement. To the best of my knowledge, after inquiry, there has been no change in any matter disclosed in such filings that reasonably could be expected to result in such a material adverse effect.
5. The Borrower is not an "investment company" or a company "controlled" by an "investment company", within the meaning of the Investment Company Act of 1940, as amended, or an "investment adviser" within the meaning of the Investment Advisers Act of 1940, as amended.
6. The Credit Agreement constitutes the legal, valid and binding obligation of the Borrower enforceable against the Borrower in accordance with its terms.

My opinions above are subject to the following qualifications:

1. My opinions are subject, as to enforceability, to (A) bankruptcy, insolvency, reorganization, moratorium and other similar laws affecting creditors rights generally and (B) the application of general principles of equity, including but not limited to the right to have specific performance of contract obligations, regardless of whether considered in a proceeding in equity or at law.
2. My opinion in paragraph (a) above, insofar as it relates to the due incorporation, valid existence and good standing of the Borrower under Delaware law, is given exclusively in reliance upon a certification of the Secretary of State of Delaware, upon which I believe I am justified in relying. A copy of such certification has been provided to you.
3. My opinion set forth in paragraph (c) above as to the obtaining of necessary governmental and regulatory approvals is based solely upon a review of those laws that, in my experience, are normally applicable to the Borrow er in connection with transactions of the type contemplated by the Credit Agreement.
4. My opinion in paragraph (f) above as to the legality, validity, binding nature and enforceability of the Credit Agreement is given in reliance upon a legal opinion of even date herewith of Thelen Reid & Priest LLP, New York counsel to the Borrower, and is subject to the assumptions, limitations and qualifications contained therein. A copy of the legal opinion of Thelen Reid & Priest LLP, is being provided to you contemporaneously herewith.

Notwithstanding the qualifications set forth above, I have no actual knowledge of any matter within the scope of said qualifications that would cause me to change the opinions set forth in this letter.

I am licensed to practice law only in the State of Louisiana and, except as otherwise provided herein, my role as counsel to the Borrower is limited to matters involving the laws of the State of Louisiana and the federal laws of the United States of America. Except to the extent otherwise expressly set forth herein, and except with respect to matters governed by the General Corporation Law of Delaware, I render no opinion on the laws of any other jurisdiction or any subdivision thereof, and have made no independent investigation into any such laws except as specifically provided herein.

My opinions are expressed as of the date hereof, and I do not assume any obligation to update or supplement my opinions to reflect any fact or circumstance that hereafter comes to my attention, or any change in law that hereafter occurs.

This opinion letter is being provided exclusively to and for the benefit of the addressees hereof. It is not to be furnished to or relied upon by any other party for any other purpose, without prior express written authorization from us, except that (A) Thelen Reid & Priest LLP may rely hereon in connection with their opinion to you of even date herewith on behalf of the Borrower as to matters of New York law, (B) Piper Rudnick LLP hereby is authorized to rely on this letter in the rendering of their opinion to the Lenders dated as of the date hereof; and (C) any addressee of this letter may deliver a copy hereof to any person that becomes a Lender under the Credit Agreement after the date hereof, and such person may rely on this opinion as if it had been addressed and delivered to it on the date hereof as an original Bank that was a party to the Credit Agreement.

Very truly yours,
 

Denise C. Redmann
Assistant General Counsel

Bank Addressees:

EXHIBIT D

OPINION OF SPECIAL NEW YORK
COUNSEL TO THE AGENT

[DATE]

To each of the Lenders parties to the
    Credit Agreement referred to below,
    and to Bayerische Hypo- und Vereinsbank AG, New York Branch
    as Administrative Agent

Entergy Corporation

Ladies and Gentlemen:

We have acted as special New York counsel to Bayerische Hypo- und Vereinsbank AG, New York Branch, individually and as Administrative Agent, in connection with the preparation, execution and delivery of the Credit Agreement, dated as of May 31, 2002 (the "Credit Agreement"), among Entergy Corporation, the Banks parties thereto and Bayerische Hypo- und Vereinsbank AG, New York Branch, as Administrative Agent. Terms defined in the Credit Agreement are used herein as therein defined.

In this connection, we have examined the following documents:

1. a counterpart of the Credit Agreement, executed by the parties thereto; and
2. the other documents furnished to the Administrative Agent pursuant to Section 3.01(a) of the Credit Agreement, including (without limitation) the opinion (the "Opinion") of Denise C. Redmann, counsel to the Borrower.

In our examination of the documents referred to above, we have assumed the authenticity of all such documents submitted to us as originals, the genuineness of all signatures, the due authority of the parties executing such documents and the conformity to the originals of all such documents submitted to us as copies. We have also assumed that you have independently evaluated, and are satisfied with, the creditworthiness of the Borrower and the business terms reflected in the Credit Agreement. We have relied, as to factual matters, on the documents we have examined.

To the extent that our opinions expressed below involve conclusions as to matters governed by law other than the law of the State of New York, we have relied upon the Opinion and have assumed without independent investigation the correctness of the matters set forth therein, our opinions expressed below being subject to the assumptions, qualifications and limitations set forth in the Opinion.

Based upon and subject to the foregoing, and subject to the qualifications set forth below, we are of the opinion that the Credit Agreement is the legal, valid and binding obligation of the Borrower, enforceable against the Borrower in accordance with its terms.

Our opinion is subject to the following qualifications:

1. The enforceability of the Borrower's obligations under the Credit Agreement is subject to the effect of any applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium or similar law affecting creditors' rights generally.
2. The enforceability of the Borrower's obligations under the Credit Agreement is subject to the effect of general principles of equity, including (without limitation) concepts of materiality, reasonableness, good faith and fair dealing (regardless of whether considered in a proceeding in equity or at law). Such principles of equity are of general application, and, in applying such principles, a court, among other things, might not allow a contracting party to exercise remedies in respect of a default deemed immaterial, or might decline to order an obligor to perform covenants.
3. We note further that, in addition to the application of equitable principles described above, courts have imposed an obligation on cont racting parties to act reasonably and in good faith in the exercise of their contractual rights and remedies, and may also apply public policy considerations in limiting the right of parties seeking to obtain indemnification under circumstances where the conduct of such parties is determined to have constituted negligence.
4. We express no opinion herein as to (A) Section 8.05 of the Credit Agreement, (B) the enforceability of provisions purporting to grant to a party conclusive rights of determination, (C) the availability of specific performance or other equitable remedies, (D) the enforceability of rights to indemnity under federal or state securities laws or (E) the enforceability of waivers by parties of their respective rights and remedies under law.
5. Our opinions expressed above are limited to the law of the State of New York, and we do not express any opinion herein concerning any other law.

The foregoing opinion is solely for your benefit and may not be relied upon by any other person or entity, other than any Person that may become a Lender under the Credit Agreement after the date hereof.

Very truly yours,

EX-4

Exhibit 4(a)3

FIRST AMENDMENT

THIS FIRST AMENDMENT, dated as of June 6, 2003 ("Amendment"), is among ENTERGY CORPORATION ("Borrower"), the banks party hereto ("Banks") and BAYERISCHE HYPO- UND VEREINSBANK AG, NEW YORK BRANCH ("Agent").

Section 1. The Credit Agreement. The parties to this Amendment entered into a Credit Agreement, dated as of May 31, 2002 ("Agreement"), which they desire to amend. Unless defined otherwise, words capitalized in this Amendment are used with the same meanings as in the Agreement.

Section 2. Representations. Borrower represents and warrants that: (a) Borrower has not made any statement or representation to induce Lenders or Agent to agree to this Amendment that omits any material fact necessary to make it not misleading in light of the circumstances under which it was made; (b) no Prepayment Event or Event of Default has occurred, and no event has occurred which with the passage of time or the giving of notice, or both, would become a Prepayment Event or an Event of Default; (c) Borrower has the power and authority to enter into this Amendment and to perform its obligations under this Amendment and the Agreement, as amended hereby; (d) the representations and warranties set forth in Section 4.01 of the Agreement are correct on and as of the date hereof; and (e) this Amendment and the Agreement, as amended hereby, constitute legal valid and binding obligations of Borrower, enforceable in accordance with their terms.

Section 3. Amendments. The Agreement shall be amended, after satisfaction of the condition set forth in the next Section, as follows:

(a) The definition of "Applicable Margin" in Section 1.01 shall be amended by (i) deleting "1.0000%" in the Level 1 column and inserting "1.475%" in lieu thereof; (ii) deleting "1.125%" in the Level 2 column and inserting "1.600%" in lieu thereof; (iii) deleting "1.375%" in the Level 3 column and inserting "1.850%' in lieu thereof; (iv) deleting "1.500%" in the Level 4 column and inserting 1.975%" in lieu thereof; and (v) deleting "2.500%' in the Level 5 column and inserting "3.100%" in lieu thereof;

(b) The definition of "Majority Lenders" in Section 1.01 shall be amended by deleting the brackets around the number 66-2/3 in the second and third lines thereof;

(c) The definition of "Maturity Date" in Section 1.01 shall be amended by deleting "2004" and inserting "2005" in lieu thereof ;

(d) The following definitions shall be added to Section 1.01 in the correct alphabetical order:

"Consolidated EBITDA" means, for any period, the sum of (i) net income of the Borrower and its subsidiaries for such period, but excluding therefrom (to the extent otherwise included therein) any extraordinary gains or losses, plus (ii) to the extent deducted in determining such net income for such period, Consolidated Interest Expense, income taxes, distributions on preferred securities of subsidiaries, preferred dividend requirements, depreciation and amortization expense and any other non-cash charges constituting operating expense, determined in each case in accordance with generally accepted accounting principles consistently applied.

"Consolidated Interest Expense" means, for any period, the interest expense during such period in respect of Debt of the Borrower and its subsidiaries of the types described in clauses (i) through (iv) of the definition of "Debt", excluding interest in respect of nuclear fuel capital leases.

"Interest Coverage Ratio" means as of any date of determination, the ratio of (i) Consolidated EBITDA for the period of four fiscal quarters ending on such date to (ii) Consolidated Interest Expense for such period.";

(e) Section 5.01 shall be amended by adding the following new subsection at the end thereof:

"(d) As of the end of each fiscal quarter of the Borrower, maintain an Interest Coverage Ratio of not less than 2.0:1.0"; and

(f) Section 6.01(c) shall be amended by inserting ",5.01(d)" after "5.01(b)" in the second line thereof.

Section 4. Conditions to Effectiveness. The amendments set forth in the immediately preceding Section shall be effective upon receipt by Agent of this Amendment duly executed by Borrower, Banks and Agent and payment by Borrower of the fees and expenses of Agent's counsel.

Section 5. Construction. (a) This Amendment constitutes the entire agreement between the parties with respect to its subject matter. It set forth any and all representations relied upon by Borrower in connection herewith. Except as amended by this Amendment, all provisions of the Agreement remain in full force and effect.

(b) This Amendment shall be construed in accordance with and governed by the laws of the State of New York applicable to agreements made and performed wholly in that State.

Section 6. Waiver of Jury Trial. Each party to this Amendment hereby waives its right to trial by jury in any action or proceeding relating to this Amendment or the Agreement.

ENTERGY CORPORATION

By _________________________________
     Steven C. McNeal
     Vice President and Treasurer_________
     Title

BAYERISCHE HYPO- UND
VEREINSBANK AG, NEW YORK
BRANCH, AS BANK AND AGENT

By _________________________________
    
     _________________________________
     Title


By _________________________________
    
     _________________________________
     Title

EX-4

Exhibit 4(c)1

ENTERGY ARKANSAS, INC.

TO

DEUTSCHE BANK TRUST COMPANY AMERICAS

(successor to Guaranty Trust Company of New York)

AND

STANLEY BURG

(successor to Henry A. Theis)

AND

(as to property, real or personal, situated or being in Missouri)

THE BANK OF NEW YORK TRUST COMPANY, NATIONAL ASSOCIATION

AND

JEFFREY SCHROEDER

(successors to Marvin A. Mueller)

As Trustees under Entergy Arkansas, Inc.'s Mortgage and Deed of Trust,
Dated as of October 1, 1944

___________________________

SIXTY-THIRD SUPPLEMENTAL INDENTURE

Providing among other things for
First Mortgage Bonds, 5.66% Series due February 1, 2025 (Seventieth Series)

__________________________

Dated as of January 1, 2005

SIXTY-THIRD SUPPLEMENTAL INDENTURE

INDENTURE, dated as of January 1, 2005, between ENTERGY ARKANSAS, INC., a corporation of the State of Arkansas, whose post office address is 425 West Capitol, Little Rock, Arkansas 72201 (hereinafter sometimes called the "Company"), and DEUTSCHE BANK TRUST COMPANY AMERICAS (successor to Guaranty Trust Company of New York), a New York banking corporation, whose post office address is 60 Wall Street, MS NYC 60-2710, New York, New York 10005 (hereinafter sometimes called the "Corporate Trustee"), and STANLEY BURG (successor to Henry A. Theis) (hereinafter sometimes called the "Co-Trustee"), and (as to property, real or personal, situated or being in Missouri) THE BANK OF NEW YORK TRUST COMPANY, NATIONAL ASSOCIATION (successor to Marvin A. Mueller), whose mailing address is 10161 Centurion Parkway, Jacksonville, Florida 32256 and JEFFREY SCHROEDER (successor to Marvin A. Mueller), whose address is 508 Arborwood Drive, Ballwin, Missouri 63021 (said The Bank of New York Trust Company, National Association and Jeffrey Schroeder each being hereinafter sometimes called a "Missouri Co-Trustee" and collectively, the "Missouri Co-Trustees," and the Corporate Trustee, the Co-Trustee and the Missouri Co-Trustees being hereinafter together sometimes called the "Trustees"), as Trustees under the Mortgage and Deed of Trust, dated as of October 1, 1944 (hereinafter sometimes called the "Mortgage"), which Mortgage was executed and delivered by the Company to secure the payment of bonds issued or to be issued under and in accordance with the provisions of the Mortgage, reference to which Mortgage is hereby made, this indenture (hereinafter called the "Sixty-third Supplemental Indenture") being supplemental thereto.

WHEREAS, the Mortgage was appropriately filed or recorded in various official records in the States of Arkansas, Missouri, Tennessee and Wyoming; and

WHEREAS, an instrument, dated as of July 7, 1949, was executed by the Company appointing Herbert E. Twyeffort as Co-Trustee in succession to Henry A. Theis (resigned) under the Mortgage, and by Herbert E. Twyeffort accepting said appointment, and said instrument was appropriately filed or recorded in various official records in the States of Arkansas, Missouri, Tennessee and Wyoming; and

WHEREAS, an instrument, dated as of March 1, 1960, was executed by the Company appointing Grainger S. Greene as Co-Trustee in succession to Herbert E. Twyeffort (resigned) under the Mortgage, and by Grainger S. Greene accepting said appointment, and said instrument was appropriately filed or recorded in various official records in the States of Arkansas, Missouri, Tennessee and Wyoming; and

WHEREAS, by the Twenty-first Supplemental Indenture mentioned below, the Company, among other things, appointed John W. Flaherty as Co-Trustee in succession to Grainger S. Greene (resigned) under the Mortgage, and John W. Flaherty accepted said appointment; and

WHEREAS, by the Thirty-third Supplemental Indenture mentioned below, the Company, among other things, appointed Marvin A. Mueller as Missouri Co-Trustee under the Mortgage, and Marvin A. Mueller accepted said appointment; and

WHEREAS, by the Thirty-fifth Supplemental Indenture mentioned below, the Company, among other things, appointed The Boatmen's National Bank of St. Louis as Missouri Co-Trustee in succession to Marvin A. Mueller (resigned) under the Mortgage, and The Boatmen's National Bank of St. Louis accepted said appointment; and

WHEREAS, an instrument, dated as of September 1, 1994, was executed by the Company appointing Bankers Trust Company as Trustee, and Stanley Burg as Co-Trustee, in succession to Morgan Guaranty Trust Company of New York (resigned) and John W. Flaherty (resigned), respectively, under the Mortgage and Bankers Trust Company and Stanley Burg accepted said appointments, and said instrument was appropriately filed or recorded in various official records in the States of Arkansas, Missouri, Tennessee and Wyoming; and

WHEREAS, by the Fifty-fifth Supplemental Indenture mentioned below, the Company, among other things, appointed Peter D. Van Cleve as Missouri Co-Trustee in succession to The Boatmen's National Bank of St. Louis (resigned) under the Mortgage, and Peter D. Van Cleve accepted said appointment; and

WHEREAS, by an instrument, dated as of May 31, 2000, the Company appointed BNY Trust Company of Missouri as Missouri Co-Trustee in succession to Peter D. Van Cleve (resigned) under the Mortgage, and BNY Trust Company of Missouri accepted said appointment, and said instrument was appropriately filed or recorded in various official records in the State of Missouri; and

WHEREAS, by an instrument, dated as of April 15, 2002, filed with the Banking Department of the State of New York, Bankers Trust Company, Trustee, effected a corporate name change pursuant to which, effective such date, it is known as Deutsche Bank Trust Company Americas; and

WHEREAS, by an instrument dated November 1, 2004, filed with the Office of the Comptroller of the Currency in Colorado, BNY Trust Company of Missouri merged into BNY Missouri Interim Trust Company, National Association, and by an instrument dated November 1, 2004, filed with the Office of the Comptroller of the Currency in Colorado, BNY Missouri Interim Trust Company, National Association, merged into The Bank of New York Trust Company, National Association; and

WHEREAS, by this Sixty-third Supplemental Indenture, the Company, the Corporate Trustee, Stanley Burg as Co-Trustee, and The Bank of New York Trust Company, National Association, as Missouri Co-Trustee, desire to appoint Jeffrey Schroeder to serve as Missouri Co-Trustee under the Mortgage, and Jeffrey Schroeder desires to accept such appointment; and

WHEREAS, by the Mortgage the Company covenanted that it would execute and deliver such supplemental indenture or indentures and such further instruments and do such further acts as might be necessary or proper to carry out more effectually the purposes of the Mortgage and to make subject to the lien of the Mortgage any property thereafter acquired and intended to be subject to the lien thereof; and

WHEREAS, the Company executed and delivered to the Trustees the following supplemental indentures:

Designation	Dated as of
First Supplemental Indenture	July 1, 1947
Second Supplemental Indenture	August 1, 1948
Third Supplemental Indenture	October 1, 1949
Fourth Supplemental Indenture	June 1, 1950
Fifth Supplemental Indenture	October 1, 1951
Sixth Supplemental Indenture	September 1, 1952
Seventh Supplemental Indenture	June 1, 1953
Eighth Supplemental Indenture	August 1, 1954
Ninth Supplemental Indenture	April 1, 1955
Tenth Supplemental Indenture	December 1, 1959
Eleventh Supplemental Indenture	May 1, 1961
Twelfth Supplemental Indenture	February 1, 1963
Thirteenth Supplemental Indenture	April 1, 1965
Fourteenth Supplemental Indenture	March 1, 1966
Fifteenth Supplemental Indenture	March 1, 1967
Sixteenth Supplemental Indenture	April 1, 1968
Seventeenth Supplemental Indenture	June 1, 1968
Eighteenth Supplemental Indenture	December 1, 1969
Nineteenth Supplemental Indenture	August 1, 1970
Twentieth Supplemental Indenture	March 1, 1971
Twenty-first Supplemental Indenture	August 1, 1971
Twenty-second Supplemental Indenture	April 1, 1972
Twenty-third Supplemental Indenture	December 1, 1972
Twenty-fourth Supplemental Indenture	June 1, 1973
Twenty-fifth Supplemental Indenture	December 1, 1973
Twenty-sixth Supplemental Indenture	June 1, 1974
Twenty-seventh Supplemental Indenture	November 1, 1974
Twenty-eighth Supplemental Indenture	July 1, 1975
Twenty-ninth Supplemental Indenture	December 1, 1977
Thirtieth Supplemental Indenture	July 1, 1978
Thirty-first Supplemental Indenture	February 1, 1979
Thirty-second Supplemental Indenture	December 1, 1980
Thirty-third Supplemental Indenture	January 1, 1981
Thirty-fourth Supplemental Indenture	August 1, 1981
Thirty-fifth Supplemental Indenture	February 1, 1982
Thirty-sixth Supplemental Indenture	December 1, 1982
Thirty-seventh Supplemental Indenture	February 1, 1983
Thirty-eighth Supplemental Indenture	December 1, 1984
Thirty-ninth Supplemental Indenture	December 1, 1985
Fortieth Supplemental Indenture	July 1, 1986
Forty-first Supplemental Indenture	July 1, 1989
Forty-second Supplemental Indenture	February 1, 1990
Forty-third Supplemental Indenture	October 1, 1990
Forty-fourth Supplemental Indenture	November 1, 1990
Forty-fifth Supplemental Indenture	January 1, 1991
Forty-sixth Supplemental Indenture	August 1, 1992
Forty-seventh Supplemental Indenture	November 1, 1992
Forty-eighth Supplemental Indenture	June 15, 1993
Forty-ninth Supplemental Indenture	August 1, 1993
Fiftieth Supplemental Indenture	October 1, 1993
Fifty-first Supplemental Indenture	October 1, 1993
Fifty-second Supplemental Indenture	June 15, 1994
Fifty-third Supplemental Indenture	March 1, 1996
Fifty-fourth Supplemental Indenture	March 1, 1997
Fifty-fifth Supplemental Indenture	March 1, 2000
Fifty-sixth Supplemental Indenture	July 1, 2001
Fifty-seventh Supplemental Indenture	March 1, 2002
Fifty-eighth Supplemental Indenture	November 1, 2002
Fifty-ninth Supplemental Indenture	May 1, 2003
Sixtieth Supplemental Indenture	June 1, 2003
Sixty-first Supplemental Indenture	June 15, 2003
Sixty-second Supplemental Indenture	October 1, 2004

which supplemental indentures were appropriately filed or recorded in various official records in the States of Arkansas, Missouri, Tennessee and Wyoming, as applicable; and

WHEREAS, in addition to the property described in the Mortgage, as heretofore supplemented, the Company has acquired certain other property, rights and interests in property; and

WHEREAS, the Company has heretofore issued, in accordance with the provisions of the Mortgage, as supplemented, the following series of First Mortgage Bonds:

Series	Principal Amount Issued	Principal Amount Outstanding
3 1/8% Series due 1974	$30,000,000	None
2 7/8% Series due 1977	11,000,000	None
3 1/8% Series due 1978	7,500,000	None
2 7/8% Series due 1979	8,700,000	None
2 7/8% Series due 1980	6,000,000	None
3 5/8% Series due 1981	8,000,000	None
3 1/2% Series due 1982	15,000,000	None
4 1/4% Series due 1983	18,000,000	None
3 1/4% Series due 1984	7,500,000	None
3 3/8% Series due 1985	18,000,000	None
5 5/8% Series due 1989	15,000,000	None
4 7/8% Series due 1991	12,000,000	None
4 3/8% Series due 1993	15,000,000	None
4 5/8% Series due 1995	25,000,000	None
5 3/4% Series due 1996	25,000,000	None
5 7/8% Series due 1997	30,000,000	None
7 3/8% Series due 1998	15,000,000	None
9 1/4% Series due 1999	25,000,000	None
9 5/8% Series due 2000	25,000,000	None
7 5/8% Series due 2001	30,000,000	None
8 % Series due August 1, 2001	30,000,000	None
7 3/4% Series due 2002	35,000,000	None
7 1/2% Series due December 1, 2002	15,000,000	None
8 % Series due 2003	40,000,000	None
8 1/8% Series due December 1, 2003	40,000,000	None
10 1/2% Series due 2004	40,000,000	None
9 1/4% Series due November 1, 1981	60,000,000	None
10 1/8% Series due July 1, 2005	40,000,000	None
9 1/8% Series due December 1, 2007	75,000,000	None
9 7/8% Series due July 1, 2008	75,000,000	None
10 1/4% Series due February 1, 2009	60,000,000	None
16 1/8% Series due December 1, 1986	70,000,000	None
4 1/2% Series due September 1, 1983	1,202,000	None
5 1/2% Series due January 1, 1988	598,310	None
5 5/8% Series due May 1, 1990	1,400,000	None
6 1/4% Series due December 1, 1996	3,560,000	None
9 3/4% Series due September 1, 2000	4,600,000	None
8 3/4% Series due March 1, 1998	9,800,000	None
17 3/8% Series due August 1, 1988	75,000,000	None
16 1/2% Series due February 1, 1991	80,000,000	None
13 3/8% Series due December 1, 2012	75,000,000	None
13 1/4% Series due February 1, 2013	25,000,000	None
14 1/8% Series due December 1, 2014	100,000,000	None
Pollution Control Series A	128,800,000	None
10 1/4% Series due July 1, 2016	50,000,000	None
9 3/4% Series due July 1, 2019	75,000,000	None
10% Series due February 1, 2020	150,000,000	None
10 3/8% Series due October 1, 2020	175,000,000	None
Solid Waste Disposal Series A	21,066,667	None
Solid Waste Disposal Series B	28,440,000	None
7 1/2% Series due August 1, 2007	100,000,000	None
7.90% Series due November 1, 2002	25,000,000	None
8.70% Series due November 1, 2022	25,000,000	None
Pollution Control Series B	46,875,000	46,875,000
6.65% Series due August 1, 2005	115,000,000	None
6 % Series due October 1, 2003	155,000,000	None
7 % Series due October 1, 2023	175,000,000	175,000,000
Pollution Control Series C	20,319,000	20,319,000
Pollution Control Series D	9,586,400	9,586,400
8 3/4% Series due March 1, 2026	85,000,000	None
7% Series due March 1, 2002	85,000,000	None
7.72 % Series due March 1, 2003	100,000,000	None
6 1/8 % Series due July 1, 2005	100,000,000	100,000,000
6.70% Series due April 1, 2032	100,000,000	100,000,000
6.00% Series due November 1, 2032	100,000,000	100,000,000
5.40% Series due May 1, 2018	150,000,000	150,000,000
5.90% Series due June 1, 2033	100,000,000	100,000,000
5% Series due July 1, 2018	115,000,000	115,000,000
6.38% Series due November 1, 2034	60,000,000	60,000,000

which bonds are also hereinafter sometimes called bonds of the First through Sixty-ninth Series, respectively; and

WHEREAS, Section 8 of the Mortgage provides that the form of each series of bonds (other than the First Series) issued thereunder and of the coupons to be attached to coupon bonds of such series shall be established by Resolution of the Board of Directors of the Company and that the form of such series, as established by said Board of Directors, shall specify the descriptive title of the bonds and various other terms thereof, and may also contain such provisions not inconsistent with the provisions of the Mortgage as the Board of Directors may, in its discretion, cause to be inserted therein expressing or referring to the terms and conditions upon which such bonds are to be issued and/or secured under the Mortgage; and

WHEREAS, Section 120 of the Mortgage provides, among other things, that any power, privilege or right expressly or impliedly reserved to or in any way conferred upon the Company by any provision of the Mortgage, whether such power, privilege or right is in any way restricted or is unrestricted, may be in whole or in part waived or surrendered or subjected to any restriction if at the time unrestricted or to additional restriction if already restricted, and the Company may enter into any further covenants, limitations or restrictions for the benefit of any one or more series of bonds issued thereunder, or the Company may cure any ambiguity contained therein or in any supplemental indenture, or may establish the terms and provisions of any series of bonds other than said First Series, by an instrument in writing executed and acknowledged by the Company in such manner as would be necessary to entitle a conveyance of real estate to record in all of the states in which any property at the time subject to the lien of the Mortgage shall be situated; and

WHEREAS, the Company now desires to create a new series of bonds, hereinafter referred to as bonds of the Seventieth Series, unless the context otherwise requires, and (pursuant to the provisions of Section 120 of the Mortgage) to add to its covenants and agreements contained in the Mortgage, as heretofore supplemented, certain other covenants and agreements to be observed by it and to alter and amend in certain respects the covenants and provisions contained in the Mortgage, as heretofore supplemented; and

WHEREAS, the execution and delivery by the Company of this Sixty-third Supplemental Indenture, and the terms of the bonds of the Seventieth Series, have been duly authorized by the Board of Directors of the Company by appropriate Resolutions of said Board of Directors.

NOW, THEREFORE, THIS INDENTURE WITNESSETH:

That, pursuant to Section 103 of the Mortgage, the undersigned Entergy Arkansas, Inc., Deutsche Bank Trust Company Americas, Stanley Burg as Co-Trustee, and The Bank of New York Trust Company, National Association, as Missouri Co-Trustee, appoint Jeffrey Schroeder to serve as Missouri Co-Trustee under the Mortgage and Jeffrey Schroeder does hereby accept the appointment as Missouri Co-Trustee under the Mortgage, subject to the conditions in Article XVII thereof expressed, effective as of January 1, 2005.

That the Company, in consideration of the premises and of One Dollar to it duly paid by the Trustees at or before the ensealing and delivery of these presents, the receipt whereof is hereby acknowledged, and in further evidence of assurance of the estate, title and rights of the Trustees and in order further to secure the payment of both the principal of and interest and premium, if any, on the bonds from time to time issued under the Mortgage, according to their tenor and effect and the performance of all the provisions of the Mortgage (including any instruments supplemental thereto and any modifications made as in the Mortgage provided) and of said bonds, hereby grants, bargains, sells, releases, conveys, assigns, transfers, mortgages, hypothecates, affects, pledges, sets over and confirms (subject, however, to Excepted Encumbrances as defined in Section 6 of the Mortgage) unto The Bank of New York Trust Company, National Association and Jeffrey Schroeder (as to property, real or persona l, situated or being in Missouri) and Stanley Burg (but, as to property, real or personal, situated or being in Missouri, only to the extent of his legal capacity to hold the same for the purposes hereof) and (to the extent of its legal capacity to hold the same for the purposes hereof) to Deutsche Bank Trust Company Americas, as Trustees under the Mortgage, and to their successor or successors in said trust, and to them and their successors and assigns forever, all property, real, personal or mixed, of any kind or nature acquired by the Company after the date of the execution and delivery of the Mortgage (except any herein or in the Mortgage, as heretofore supplemented, expressly excepted), now owned or, subject to the provisions of Section 87 of the Mortgage, hereafter acquired by the Company (by purchase, consolidation, merger, donation, construction, erection or in any other way) and wheresoever situated, including (without in anywise limiting or impairing by the enumeration of the same the scope and int ent of the foregoing or of any general description contained in this Sixty-third Supplemental Indenture) all lands, power sites, flowage rights, water rights, water locations, water appropriations, ditches, flumes, reservoirs, reservoir sites, canals, raceways, dams, dam sites, aqueducts, and all other rights or means for appropriating, conveying, storing and supplying water; all rights of way and roads; all plants for the generation of electricity by steam, water and/or other power; all power houses, gas plants, street lighting systems, standards and other equipment incidental thereto; all street and interurban railway and transportation lines and systems, terminal systems and facilities; all bridges, culverts, tracks, railways, sidings, spurs, wyes, roadbeds, trestles and viaducts; all overground and underground trolleys and feeder wires; all telephone, radio and television systems, air-conditioning systems and equipment incidental thereto, water works, water systems, steam heat and hot water plants, subst ations, lines, service and supply systems, ice or refrigeration plants and equipment, offices, buildings and other structures and the equipment thereof, all machinery, engines, boilers, dynamos, electric, gas and other machines, regulators, meters, transformers, generators, motors, electrical, gas and mechanical appliances, conduits, cables, water, steam heat, gas or other pipes, gas mains and pipes, service pipes, fittings, valves and connections, pole and transmission lines, wires, cables, tools, implements, apparatus, furniture and chattels; all municipal and other franchises, consents or permits; all lines for the transmission and distribution of electric current, gas, steam heat or water for any purpose including towers, poles, wires, cables, pipes, conduits, ducts and all apparatus for use in connection therewith; all real estate, lands, easements, servitudes, licenses, permits, franchises, privileges, rights of way and other rights in or relating to real estate or the occupancy of the same and (except as herein or in the Mortgage, as heretofore supplemented, expressly excepted) all the right, title and interest of the Company in and to all other property of any kind or nature appertaining to and/or used and/or occupied and/or enjoyed in connection with any property hereinbefore or in the Mortgage, as heretofore supplemented, described.

TOGETHER WITH all and singular the tenements, hereditaments, prescriptions, servitudes and appurtenances belonging or in anywise appertaining to the aforesaid property or any part thereof, with the reversion and reversions, remainder and remainders and (subject to the provisions of Section 57 of the Mortgage) the tolls, rents, revenues, issues, earnings, income, product and profits thereof and all the estate, right, title and interest and claim whatsoever, at law as well as in equity, which the Company now has or may hereafter acquire in and to the aforesaid property and franchises and every part and parcel thereof.

IT IS HEREBY AGREED by the Company that, subject to the provisions of Section 87 of the Mortgage, all the property, rights and franchises acquired by the Company (by purchase, consolidation, merger, donation, construction, erection or in any other way) after the date hereof, except any herein or in the Mortgage, as heretofore supplemented, expressly excepted, shall be and are as fully granted and conveyed hereby and by the Mortgage and as fully embraced within the lien hereof and the lien of the Mortgage, as heretofore supplemented, as if such property, rights and franchises were now owned by the Company and were specifically described herein or in the Mortgage and conveyed hereby or thereby.

PROVIDED THAT the following are not and are not intended to be now or hereafter granted, bargained, sold, released, conveyed, assigned, transferred, mortgaged, hypothecated, affected, pledged, set over or confirmed hereunder and are hereby expressly excepted from the lien and operation of this Sixty-third Supplemental Indenture and from the lien and operation of the Mortgage, as heretofore supplemented, viz: (1) cash, shares of stock, bonds, notes and other obligations and other securities not hereafter specifically pledged, paid, deposited, delivered or held under the Mortgage or covenanted so to be; (2) merchandise, equipment, materials or supplies held for the purpose of sale in the usual course of business or for the purpose of repairing or replacing (in whole or in part) any street cars, rolling stock, trolley coaches, motor coaches, buses, automobiles or other vehicles or aircraft, and fuel, oil and similar materials and supplies consumable in the operation of any properties of the C ompany; street cars, rolling stock, trolley coaches, motor coaches, buses, automobiles and other vehicles and all aircraft; (3) bills, notes and accounts receivable, judgments, demands and choses in action, and all contracts, leases and operating agreements not specifically pledged under the Mortgage, as heretofore supplemented, or covenanted so to be; the Company's contractual rights or other interest in or with respect to tires not owned by the Company; (4) the last day of the term of any lease or leasehold which may hereafter become subject to the lien of the Mortgage; (5) electric energy, gas, ice, and other materials or products generated, manufactured, produced or purchased by the Company for sale, distribution or use in the ordinary course of its business; all timber, minerals, mineral rights and royalties; (6) the Company's franchise to be a corporation; (7) the properties heretofore sold or in the process of being sold by the Company and heretofore released from the Mortgage and Deed of Trust dated as of October 1, 1926 from Arkansas Power & Light Company to Guaranty Trust Company of New York, trustee, and specifically described in a release instrument executed by Guaranty Trust Company of New York, as trustee, dated October 13, 1938, which release has heretofore been delivered by the said trustee to the Company and recorded by the Company in the office of the Recorder for Garland County, Arkansas, in Record Book 227, Page 1, all of said properties being located in Garland County, Arkansas; and (8) any property heretofore released pursuant to any provisions of the Mortgage and not heretofore disposed of by the Company; provided, however, that the property and rights expressly excepted from the lien and operation of the Mortgage, as heretofore supplemented, and this Sixty-third Supplemental Indenture in the above subdivisions (2) and (3) shall (to the extent permitted by law) cease to be so excepted in the event and as of the date that any or all of the Trustees or a receiver or trustee shall enter upon and take possession of the Mortgaged and Pledged Property in the manner provided in Article XIII of the Mortgage by reason of the occurrence of a Default as defined in Section 65 thereof.

TO HAVE AND TO HOLD all such properties, real, personal and mixed, granted, bargained, sold, released, conveyed, assigned, transferred, mortgaged, hypothecated, affected, pledged, set over or confirmed by the Company as aforesaid, or intended so to be, unto The Bank of New York Trust Company, National Association and Jeffrey Schroeder (as to property, real or personal, situated or being in Missouri), and unto Stanley Burg (but, as to property, real or personal, situated or being in Missouri, only to the extent of his legal capacity to hold the same for the purposes hereof) and (to the extent of its legal capacity to hold the same for the purposes hereof) unto Deutsche Bank Trust Company Americas, as Trustees, and their successors and assigns forever.

IN TRUST NEVERTHELESS, for the same purposes and upon the same terms, trusts and conditions and subject to and with the same provisos and covenants as are set forth in the Mortgage, as heretofore supplemented, this Sixty-third Supplemental Indenture being supplemental to the Mortgage.

AND IT IS HEREBY COVENANTED by the Company that all the terms, conditions, provisos, covenants and provisions contained in the Mortgage, as heretofore supplemented, shall affect and apply to the property hereinbefore described and conveyed and to the estate, rights, obligations and duties of the Company and Trustees and the beneficiaries of the trust with respect to said property, and to the Trustees and their successors in the trust in the same manner and with the same effect as if said property had been owned by the Company at the time of the execution of the Mortgage, and had been specifically and at length described in and conveyed to said Trustees, by the Mortgage as a part of the property therein stated to be conveyed.

The Company further covenants and agrees to and with the Trustees and their successors in said trust under the Mortgage, as follows:
 

ARTICLE I

SEVENTIETH SERIES OF BONDS

SECTION 1.  There shall be a series of bonds designated "5.66% Series due February 1, 2025" (herein sometimes called the "Seventieth Series"), each of which shall also bear the descriptive title "First Mortgage Bond", and the form thereof, which shall be established by Resolution of the Board of Directors of the Company, shall contain suitable provisions with respect to the matters hereinafter in this Section specified. Bonds of the Seventieth Series (which shall be initially issued in the aggregate principal amount of $175,000,000) shall mature on February 1, 2025, shall be issued as fully registered bonds in the denomination of One Thousand Dollars and, at the option of the Company, in any multiple or multiples of One Thousand Dollars (the exercise of such option to be evidenced by the execution and delivery thereof), shall bear interest at the rate of 5.66% per annum, the first interest payment to be made on August 1, 2005, for the period from January 19, 2005 to August 1, 2005 with subsequent interest payments payable semi-annually on February 1 and August 1 of each year (each an "Interest Payment Date"), shall be dated as in Section 10 of the Mortgage provided, and the principal of and interest on each said bond shall be payable at the office or agency of the Company in the Borough of Manhattan, The City of New York, in such coin or currency of the United States of America as at the time of payment is legal tender for public and private debts.

Interest on the bonds of the Seventieth Series will be computed on the basis of a 360-day year of twelve 30-day months. In any case where any Interest Payment Date, redemption date or maturity of any bond of the Seventieth Series shall not be a Business Day, then payment of interest or principal need not be made on such date, but may be made on the next succeeding Business Day, with the same force and effect, and in the same amount, as if made on the corresponding Interest Payment Date or redemption date, or at maturity, as the case may be, and, if such payment is made or duly provided for on such Business Day, no interest shall accrue on the amount so payable for the period from and after such Interest Payment Date, redemption date or maturity, as the case may be, to such Business Day. "Business Day" means any day, other than a Saturday or a Sunday, or a day on which banking institutions in The City of New York are authorized or required by law or executive order to remain closed or a day on which the corporate trust office of the Corporate Trustee is closed for business.

So long as all of the bonds of the Seventieth Series are held by The Depository Trust Company or its nominee, or a successor thereof, the record date for the payment of interest on the bonds of the Seventieth Series shall be the Business Day immediately preceding the corresponding Interest Payment Date; provided, however, that the record date for the payment of interest which is paid after such Interest Payment Date, shall be the Business Day immediately preceding the date on which such interest is paid. Interest on the bonds of the Seventieth Series shall be paid to the Person in whose name such bonds of the Seventieth Series are registered at the close of business on the record date for the corresponding Interest Payment Date.

(I) Form of Bonds of the Seventieth Series.

The Bonds of the Seventieth Series, and the Corporate Trustee's authentication certificate to be executed on the Bonds of the Seventieth Series, shall be in substantially the following forms, respectively:

[FORM OF FACE OF BOND OF THE SEVENTIETH SERIES]

[depository legend]

Unless this Certificate is presented by an authorized representative of The Depository Trust Company, a New York corporation ("DTC"), to the Company or its agent for registration of transfer, exchange, or payment, and any certificate issued is registered in the name of Cede & Co. or in such other name as is requested by an authorized representative of DTC (and any payment is made to Cede & Co. or to such other entity as is requested by an authorized representative of DTC), ANY TRANSFER, PLEDGE, OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL inasmuch as the registered owner hereof, Cede & Co., has an interest herein.

(TEMPORARY REGISTERED BOND)

No. TR-1
$175,000,000                                                                                                                 CUSIP 29364DAL4

ENTERGY ARKANSAS, INC.
FIRST MORTGAGE BOND, 5.66% SERIES
DUE FEBRUARY 1, 2025

ENTERGY ARKANSAS, INC., a corporation of the State of Arkansas (hereinafter called the Company), for value received, hereby promises to pay to CEDE & CO. or registered assigns, on February 1, 2025 at the office or agency of the Company in the Borough of Manhattan, The City of New York,

ONE HUNDRED SEVENTY-FIVE MILLION DOLLARS

in such coin or currency of the United States of America as at the time of payment is legal tender for public and private debts, and to pay to the registered owner hereof interest thereon from January 19, 2005, if the date of this bond is prior to August 1, 2005, or if the date of this bond is on or after August 1, 2005, from the February 1 or August 1 next preceding the date of this bond to which interest has been paid (unless the date hereof is an interest payment date to which interest has been paid, in which case from the date hereof), at the rate of 5.66% per annum in like coin or currency at said office or agency on February 1 and August 1 of each year, commencing August 1, 2005, until the principal of this bond shall have become due and payable, and to pay interest on any overdue principal and (to the extent that payment of such interest is enforceable under the applicable law) on any overdue installment of interest at the rate of 6% per annum. So long as this bond is held by The D epository Trust Company or its nominee, or a successor thereof, the record date for the payment of interest hereon shall be the Business Day (as defined in the Sixty-third Supplemental Indenture referred to below) immediately preceding the date on which interest is due; provided, however, that the record date for the payment of interest which is paid after the date on which such interest is due, shall be the Business Day immediately preceding the date on which such interest is paid. Interest hereon shall be paid to the Person in whose name this bond is registered at the close of business on the record date for the payment of such interest. If any interest payment date for this bond falls on a day that is not a Business Day, the payment of interest will be made on the next succeeding Business Day, and no interest on such payment shall accrue for the period from and after such interest payment date. If the maturity date or any redemption date of this bond falls on a day that is not a Business Day, the payme nt of principal and interest (to the extent payable with respect to the principal being redeemed if on a redemption date) will be made on the next succeeding Business Day, and no interest on such payment shall accrue for the period from and after the maturity date or such redemption date.

This bond is a temporary bond and is one of an issue of bonds of the Company issuable in series and is one of a series known as its First Mortgage Bonds, 5.66% Series due February 1, 2025, all bonds of all series issued and to be issued under and equally secured (except insofar as any sinking or other fund, established in accordance with the provisions of the Mortgage hereinafter mentioned, may afford additional security for the bonds of any particular series) by a Mortgage and Deed of Trust (herein, together with any indenture supplemental thereto, including the Sixty-third Supplemental Indenture dated as of January 1, 2005, called the Mortgage), dated as of October 1, 1944, executed by the Company to Guaranty Trust Company of New York (Deutsche Bank Trust Company Americas, successor) and Henry A. Theis (Stanley Burg, successor) and, as to property, real or personal, situated or being in Missouri, Marvin A. Mueller (The Bank of New York Trust Company, National Association and Jeffrey Schr oeder, successors), as Trustees. Reference is made to the Mortgage for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders of the bonds and of the Trustees in respect thereof, the duties and immunities of the Trustees and the terms and conditions upon which the bonds are and are to be secured and the circumstances under which additional bonds may be issued. With the consent of the Company and to the extent permitted by and as provided in the Mortgage, the rights and obligations of the Company and/or the rights of the holders of the bonds and/or coupons and/or the terms and provisions of the Mortgage may be modified or altered by such affirmative vote or votes of the holders of bonds then outstanding as are specified in the Mortgage.

The principal hereof may be declared or may become due prior to the maturity date hereinbefore named on the conditions, in the manner and at the time set forth in the Mortgage, upon the occurrence of a default as in the Mortgage provided.

In the manner prescribed in the Mortgage, this bond is transferable by the registered owner hereof in person, or by his duly authorized attorney, at the office or agency of the Company in the Borough of Manhattan, The City of New York, upon surrender and cancellation of this bond, together with a written instrument of transfer duly executed by the registered owner or by his duly authorized attorney, and thereupon a new fully registered temporary or definitive bond of the same series for a like principal amount will be issued to the transferee in exchange herefor as provided in the Mortgage. The Company and the Trustees may deem and treat the person in whose name this bond is registered as the absolute owner hereof for the purpose of receiving payment and for all other purposes and neither the Company nor the Trustees shall be affected by any notice to the contrary.

In the manner prescribed in the Mortgage, any bonds of this series, upon surrender thereof for cancellation at the office or agency of the Company in the Borough of Manhattan, The City of New York, are exchangeable for a like aggregate principal amount of bonds of the same series of other authorized denominations.

In the manner prescribed in the Mortgage, this temporary bond is exchangeable at the office or agency of the Company in the Borough of Manhattan, The City of New York, without charge, for a definitive bond or bonds of the same series of a like aggregate principal amount when such definitive bonds are prepared and ready for delivery.

As provided in the Mortgage, the Company shall not be required to make transfers or exchanges of bonds of any series for a period of ten days next preceding any interest payment date for bonds of said series, or next preceding any designation of bonds of said series to be redeemed, and the Company shall not be required to make transfers or exchanges of any bonds designated in whole or in part for redemption.

The bonds of this series are subject to redemption as provided in the Sixty-third Supplemental Indenture.

No recourse shall be had for the payment of the principal of or interest on this bond against any incorporator or any past, present or future subscriber to the capital stock, stockholder, officer or director of the Company or of any predecessor or successor corporation, as such, either directly or through the Company or any predecessor or successor corporation, under any rule of law, statute or constitution or by the enforcement of any assessment or otherwise, all such liability of incorporators, subscribers, stockholders, officers and directors being released by the holder or owner hereof by the acceptance of this bond and being likewise waived and released by the terms of the Mortgage.

This bond shall be construed in accordance with and governed by the laws of the State of New York.

This bond shall not become obligatory until Deutsche Bank Trust Company Americas, the Corporate Trustee under the Mortgage, or its successor thereunder, shall have signed the form of authentication certificate endorsed hereon.

IN WITNESS WHEREOF, ENTERGY ARKANSAS, INC. has caused this bond to be signed in its corporate name by its President or one of its Vice Presidents by his signature or a facsimile thereof, and its corporate seal to be impressed or imprinted hereon and attested by its Secretary or one of its Assistant Secretaries, by his signature or a facsimile thereof, on January 19, 2005.

ENTERGY ARKANSAS, INC.

By_____________________________
    Steven C. McNeal
    Vice President and Treasurer

Attest:

___________________________
Christopher T. Screen
Assistant Secretary

CORPORATE TRUSTEE'S AUTHENTICATION CERTIFICATE

This bond is one of the bonds, of the series herein designated, described or provided for in the within-mentioned Mortgage.

DEUTSCHE BANK TRUST COMPANY AMERICAS,

as Corporate Trustee

By ___________________________
Authorized Officer

(II) The bonds of the Seventieth Series shall be redeemable at the option of the Company, in whole or in part, on not less than 30 days nor more than 60 days notice prior to the date fixed for redemption, (a) at any time prior to February 1, 2015, at a redemption price equal to the greater of (i) 100% of the principal amount of such bonds of the Seventieth Series to be redeemed and (ii) as determined by the Independent Investment Banker, the sum of (x) the present value of the payment on February 1, 2015 of the principal amount of such bonds of the Seventieth Series to be redeemed plus (y) the sum of the present values of the remaining scheduled payments of interest on such bonds of the Seventieth Series to be redeemed to February 1, 2015 (excluding the portion of any such interest accrued to such redemption date), discounted (for purposes of determining such present values) to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Adjusted Treasury Rate plus 0.20%, and (b) at any time on or after February 1, 2015, prior to maturity of the bonds of the Seventieth Series, at a redemption price equal to 100% of the principal amount of such bonds of the Seventieth Series to be redeemed, plus, in each case, accrued and unpaid interest thereon to the redemption date.

As used herein, the following defined terms shall have the respective meanings specified unless the context clearly requires otherwise:

The term "Adjusted Treasury Rate" shall mean, with respect to any redemption date:

(1) the yield, under the heading which represents the average for the immediately preceding week, appearing in the most recently published statistical release designated "H.15(519)" or any successor publication which is published weekly by the Board of Governors of the Federal Reserve System and which establishes yields on actively traded United States Treasury securities adjusted to constant maturity under the caption "Treasury Constant Maturities," for the maturity corresponding to the Comparable Treasury Issue (if no maturity is within three months before or after February 1, 2015, yields for the two published maturities most closely corresponding to the Comparable Treasury Issue shall be determined and the Adjusted Treasury Rate shall be interpolated or extrapolated from such yields on a straight line basis, rounding to the nearest month); or

(2) if such release (or any successor release) is not published during the week preceding the calculation date for the Adjusted Treasury Rate or does not contain such yields, the rate per annum equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, calculated using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date.

The Adjusted Treasury Rate shall be calculated on the third Business Day preceding the redemption date.

The term "Comparable Treasury Issue" shall mean the United States Treasury security selected by the Independent Investment Banker as having a maturity comparable to February 1, 2015 that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to February 1, 2015.

The term "Comparable Treasury Price" shall mean, with respect to any redemption date, (i) the average of five Reference Treasury Dealer Quotations for such redemption date after excluding the highest and lowest such Reference Treasury Dealer Quotations or (ii) if the Independent Investment Banker obtains fewer than five such Reference Treasury Dealer Quotations, the average of all such Reference Treasury Dealer Quotations.

The term "Independent Investment Banker" shall mean one of the Reference Treasury Dealers that the Company appoints to act as the Independent Investment Banker from time to time, or, if any of such firms is unwilling or unable to select the Comparable Treasury Issue, an independent investment banking institution of national standing appointed by the Company.

The term "Reference Treasury Dealer" shall mean (i) Citigroup Global Markets Inc. and Morgan Stanley & Co. Incorporated and their respective successors; provided, however, that if any of the foregoing shall cease to be a primary U.S. Government securities dealer in New York City (a "Primary Treasury Dealer"), the Company shall substitute therefor another Primary Treasury Dealer, and (ii) any other Primary Treasury Dealer selected by the Independent Investment Banker after consultation with the Company.

The term "Reference Treasury Dealer Quotations" shall mean, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Independent Investment Banker, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Independent Investment Banker at 5:00 p.m. on the third Business Day preceding such redemption date.

(III) At the option of the registered owner, any bonds of the Seventieth Series, upon surrender thereof for cancellation at the office or agency of the Company in the Borough of Manhattan, The City of New York, shall be exchangeable for a like aggregate principal amount of bonds of the same series of other authorized denominations.

Bonds of the Seventieth Series shall be transferable, upon the surrender thereof for cancellation, together with a written instrument of transfer in form approved by the registrar duly executed by the registered owner or by his duly authorized attorney, at the office or agency of the Company in the Borough of Manhattan, The City of New York.

Upon any exchange or transfer of bonds of the Seventieth Series, the Company may make a charge therefor sufficient to reimburse it for any tax or taxes or other governmental charge, as provided in Section 12 of the Mortgage, but the Company hereby waives any right to make a charge in addition thereto for any exchange or transfer of bonds of said Series.

Upon the delivery of this Sixty-third Supplemental Indenture and upon compliance with the applicable provisions of the Mortgage, as heretofore supplemented, there shall be an initial issue of bonds of the Seventieth Series for the aggregate principal amount of $175,000,000.

ARTICLE II

DIVIDEND COVENANT

SECTION 2.  The Company covenants that, so long as any of the bonds of the Seventieth Series are Outstanding, it will not declare any dividends on its Common Stock (other than (a) a dividend payable solely in shares of its Common Stock, or (b) a dividend payable in cash in cases where, concurrently with the payment of such dividend, an amount in cash equal to such dividend is received by the Company as a capital contribution or as the proceeds of the issue and sale of shares of its Common Stock) or make any distribution on outstanding shares of its Common Stock or purchase or otherwise acquire for value any outstanding shares of its Common Stock (otherwise than in exchange for or out of the proceeds from the sale of other shares of its Common Stock) if, after such dividend, distribution, purchase or acquisition, the aggregate amount of such dividends, distributions, purchases and acquisitions paid or made subsequent to December 31, 2004 (other than any dividend declared by the Company on or before De cember 31, 2004) exceeds (without giving effect to (i) any of such dividends, distributions, purchases or acquisitions, or (ii) any net transfers from retained earnings to stated capital accounts) the sum of (a) the aggregate amount credited subsequent to December 31, 2004 to retained earnings, (b) $350,000,000 and (c) such additional amount as shall be authorized or approved, upon application by the Company, by the Securities and Exchange Commission, or by any successor commission thereto, under the Public Utility Holding Company Act of 1935.

For the purposes of this Section 2 the aggregate amount credited subsequent to December 31, 2004 to retained earnings shall be determined in accordance with generally accepted accounting principles and practices after making provision for dividends upon any preferred stock of the Company, accumulated subsequent to such date, but in such determination there shall not be considered charges to retained earnings applicable to the period prior to December 31, 2004, including, but not limited to, charges to retained earnings for write-offs or write-downs of book values of assets owned by the Company on December 31, 2004.

ARTICLE III

MISCELLANEOUS PROVISIONS

SECTION 3.  The holders of the bonds of the Seventieth Series shall be deemed to have consented and agreed that the Company may, but shall not be obligated to, fix a record date for the purpose of determining the holders of the bonds of the Seventieth Series entitled to consent to any amendment or supplement to the Mortgage or the waiver of any provision thereof or any act to be performed thereunder. If a record date is fixed, those persons who were holders at such record date (or their duly designated proxies), and only those persons, shall be entitled to consent to such amendment, supplement or waiver or to revoke any consent previously given, whether or not such persons continue to be holders after such record date. No such consent shall be valid or effective for more than 90 days after such record date.

SECTION 4.  Subject to the amendments provided for in this Sixty-third Supplemental Indenture, the terms defined in the Mortgage and the First through Sixty-second Supplemental Indentures shall, for all purposes of this Sixty-third Supplemental Indenture, have the meanings specified in the Mortgage and the First through Sixty-second Supplemental Indentures.

SECTION 5.  The Trustees hereby accept the trusts herein declared, provided, created or supplemented and agree to perform the same upon the terms and conditions herein and in the Mortgage and in the First through Sixty-second Supplemental Indentures set forth and upon the following terms and conditions:

The Trustees shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Sixty-third Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made by the Company solely. In general each and every term and condition contained in Article XVII of the Mortgage, as heretofore amended, shall apply to and form part of this Sixty-third Supplemental Indenture with the same force and effect as if the same were herein set forth in full with such omissions, variations and insertions, if any, as may be appropriate to make the same conform to the provisions of this Sixty-third Supplemental Indenture.

SECTION 6.  Whenever in this Sixty-third Supplemental Indenture either of the parties hereto is named or referred to, this shall, subject to the provisions of Articles XVI and XVII of the Mortgage, as heretofore amended, be deemed to include the successors and assigns of such party, and all the covenants and agreements in this Sixty-third Supplemental Indenture contained by or on behalf of the Company, or by or on behalf of the Trustees, or any of them, shall, subject as aforesaid, bind and inure to the respective benefits of the respective successors and assigns of such parties, whether so expressed or not.

SECTION 7.  Nothing in this Sixty-third Supplemental Indenture, expressed or implied, is intended, or shall be construed, to confer upon, or give to, any person, firm or corporation, other than the parties hereto and the holders of the bonds and coupons Outstanding under the Mortgage, any right, remedy or claim under or by reason of this Sixty-third Supplemental Indenture or any covenant, condition, stipulation, promise or agreement hereof, and all the covenants, conditions, stipulations, promises or agreements in this Sixty-third Supplemental Indenture contained by or on behalf of the Company shall be for the sole and exclusive benefit of the parties hereto, and of the holders of the bonds and of the coupons Outstanding under the Mortgage.

SECTION 8.  This Sixty-third Supplemental Indenture shall be executed in several counterparts, each of which shall be an original and all of which shall constitute but one and the same instrument.

SECTION 9.  This Sixty-third Supplemental Indenture shall be construed in accordance with and governed by the laws of the State of New York.

IN WITNESS WHEREOF, ENTERGY ARKANSAS, INC. has caused its corporate name to be hereunto affixed, and this instrument to be signed and sealed by its President or one of its Vice Presidents, and its corporate seal to be attested by its Secretary or one of its Assistant Secretaries for and in its behalf, and DEUTSCHE BANK TRUST COMPANY AMERICAS has caused its corporate name to be hereunto affixed, and this instrument to be signed and sealed by, one of its Vice Presidents or one of its Assistant Vice Presidents, and its corporate seal to be attested by one of its Associates for and in its behalf, and STANLEY BURG has hereunto set his hand and affixed his seal, and THE BANK OF NEW YORK TRUST COMPANY, NATIONAL ASSOCIATION has caused its corporate name to be hereunto affixed, and this instrument to be signed and sealed by one of its Vice Presidents or one of its Assistant Vice Presidents, and its corporate seal to be attested by one of its Assistant Secretaries or one of its Assistant Treasurers or one of its Assistant Vice Presidents for and in its behalf, and JEFFREY SCHROEDER has hereunto set his hand and affixed his seal, as of the day and year first above written.

ENTERGY ARKANSAS, INC.

By: _ /s/ Steven C. McNeal_ ___________
              Steven C. McNeal
              Vice President and Treasurer

Attest:

__/s/ Christopher T. Screen _____
         Christopher T. Screen
         Assistant Secretary

Executed, sealed and delivered by
ENTERGY ARKANSAS, INC.
in the presence of:

__/s/ Myrna A. Romain_________
        Myrna A. Romain

__/s/ Shannon Ryerson_________
        Shannon Ryerson

DEUTSCHE BANK TRUST COMPANY
AMERICAS,
As Corporate Trustee

By: __/s/ Susan Johnson__________
              Susan Johnson
              Vice President

Attest:

__/s/ Irina Golovashchuk _               
         Irina Golovashchuk
        Associate

STANLEY BURG,
As Co-Trustee

__/s/ Stanley Burg______________[L.S.]

Executed, sealed and delivered by
DEUTSCHE BANK TRUST COMPANY AMERICAS and STANLEY BURG
in the presence of:

/s/ Yana Kalachikova                                
     Yana Kalachikova

/s/ Victor Carneiro                                    
     Victor Carneiro

THE BANK OF NEW YORK TRUST
COMPANY, NATIONAL ASSOCIATION,
As Co-Trustee as to property, real
or personal, situated or being in Missouri

By: /s/ Cynthia M. Moore
           Cynthia M. Moore
           Assistant Vice President

Attest:

___/s/ Robert D. Smith__ ______
          Robert D. Smith
          Assistant Treasurer

Executed, sealed and delivered by
THE BANK OF NEW YORK TRUST COMPANY, NATIONAL ASSOCIATION
in the presence of:

/s/ Sheryl Lear                               
    Sheryl Lear

/s/ Linda Boenish                            
    Linda Boenish

JEFFREY SCHROEDER,
As Co-Trustee as to property, real or personal,
situated or being in Missouri

By: /s/ Jeffrey Schroeder                        [L.S.]

Executed, sealed and delivered by
JEFFREY SCHROEDER
in the presence of:

/s/ Kent Schroeder                                   
    Kent Schroeder

/s/ Belinda Brown                                      
    Belinda Brown
    Vice President

STATE OF LOUISIANA )
                                         ) SS.:
PARISH OF ORLEANS  )

On this 17^th day of January, 2005, before me, Jennifer B. Favalora, a Notary Public duly commissioned, qualified and acting within and for said Parish and State, appeared in person the within named Steven C. McNeal and Christopher T. Screen, to me personally well known, who stated that they were the Vice President and Treasurer and Assistant Secretary, respectively, of ENTERGY ARKANSAS, INC., a corporation, and were duly authorized in their respective capacities to execute the foregoing instrument for and in the name and behalf of said corporation, and further stated and acknowledged that they had so signed, executed and delivered said foregoing instrument for the consideration, uses and purposes therein mentioned and set forth.

On the 17^th day of January, 2005, before me personally came Steven C. McNeal, to me known, who, being by me duly sworn, did depose and say that he resides at 7903 Winner's Circle, Mandeville, Louisiana 70448; that he is the Vice President and Treasurer of ENTERGY ARKANSAS, INC., one of the corporations described in and which executed the above instrument; that he knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by order of the Board of Directors of said corporation, and that he signed his name thereto by like order.

On the 17^th day of January, 2005, before me appeared Christopher T. Screen, to me personally known, who, being by me duly sworn, did say that he is the Assistant Secretary of ENTERGY ARKANSAS, INC., and that the seal affixed to the foregoing instrument is the corporate seal of said corporation, and that said instrument was signed and sealed in behalf of said corporation by authority of its Board of Directors, and he acknowledged said instrument to be the free act and deed of said corporation.

IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal at my office in said Parish and State the day and year last above written.

/s/ Jennifer B. Favalora_____________
Jennifer B. Favalora
Notary Public (ID# 57639)
State of Louisiana, Parish of Orleans
My Commission is Issued For Life

STATE OF New York      )
                                         ) SS.:

COUNTY OF New York )

On this 14^th day of January, 2005, before me, Annie Jaghatspanyan, a Notary Public duly commissioned, qualified and acting within and for said County and State, appeared Susan Johnson and Irina Golovashchuk, to me personally well known, who stated that they were a Vice President and an Associate, respectively, of DEUTSCHE BANK TRUST COMPANY AMERICAS, a corporation, and were duly authorized in their respective capacities to execute the foregoing instrument for and in the name and behalf of said corporation; and further stated and acknowledged that they had so signed, executed and delivered said foregoing instrument for the consideration, uses and purposes therein mentioned and set forth.

On the 14^th day of January, 2005, before me personally came Susan Johnson, to me known, who, being by me duly sworn, did depose and say that she resides at 153 E 46^th Street, Brooklyn, NY 11203; that she is a Vice President of DEUTSCHE BANK TRUST COMPANY AMERICAS, one of the corporations described in and which executed the above instrument; that she knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by authority of the Board of Directors of said corporation, and that she signed her name thereto by like authority.

On the 14^th day of January, 2005, before me appeared Irina Golovashchuk, to me personally known, who, being by me duly sworn, did say that she is an Associate of DEUTSCHE BANK TRUST COMPANY AMERICAS, and that the seal affixed to the foregoing instrument is the corporate seal of said corporation, and that said instrument was signed and sealed in behalf of said corporation by authority of its Board of Directors, and she acknowledged said instrument to be the free act and deed of said corporation.

IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal at my office in said County and State the day and year last above written.

/s/ Annie Jaghatspanyan_________
Annie Jaghatspanyan
Notary Public, State of New York
No 01JA6062022

Qualified in New York County
Commission Expires July 30, 2005

STATE OF New York      )
                                         ) SS.:
COUNTY OF New York )

On this 14^th day of January, 2005, before me, Annie Jaghatspanyan, the undersigned, personally appeared, STANLEY BURG, known to me to be the person whose name is subscribed to the within instrument, and acknowledged that he executed the same for the purposes therein contained.

On the 14^th day of January, 2005, before me personally appeared STANLEY BURG, to me known to be the person described in and who executed the foregoing instrument, and acknowledged that he executed the same as his free act and deed.

IN WITNESS WHEREOF, I hereunto set my hand and official seal.

/s/ Annie Jaghatspanyan_________
Annie Jaghatspanyan
Notary Public, State of New York
No 01JA6062022

Qualified in New York County
Commission Expires July 30, 2005

STATE OF FLORIDA  )
                                      ) SS.:
COUNTY OF DUVAL )

On this 13^th day of January, 2005, before me, Lillie C. Mariano, a Notary Public duly commissioned, qualified and acting within and for said county and state, appeared Cynthia M. Moore and Robert D. Smith, to me personally known, who stated that they were an Assistant Vice President and Assistant Treasurer, respectively, of THE BANK OF NEW YORK TRUST COMPANY, NATIONAL ASSOCIATION, a National Association, and were duly authorized in their respective capacities to execute the foregoing instrument for and in the name and on behalf of said National Association; and further stated that they had so signed, executed and delivered the same for the consideration, uses and purposes therein mentioned and set forth.

On the 13^th day of January, 2005, before me personally appeared Sheryl Lear, to me personally known, who, being by me duly sworn, did depose and say that she resided in Jacksonville, Florida; that she is a Vice President of THE BANK OF NEW YORK TRUST COMPANY, NATIONAL ASSOCIATION, a National Association described in and which executed the above instrument; that she knows the seal of said National Association; that the seal affixed to said instrument is such seal; that it was so affixed by authority of the Board of Directors of said National Association, and that she signed her name thereto by like authority.

On the 13^th day of January, 2005, before me appeared Linda Boenish, to me personally known, who, being by me duly sworn, did say that she is an Assistant Vice President of THE BANK OF NEW YORK TRUST COMPANY, NATIONAL ASSOCIATION, and that the seal affixed to the foregoing instrument is the seal of said National Association, and that said instrument was signed and sealed in behalf of said National Association by authority of its Board of Directors, and she acknowledged said instrument to be the free act and deed of said National Association.

IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal at my office in said County and State the day and year last above written.

                                                                
Lillie C. Mariano
Notary Public, State of Florida
Qualified in Duval County
Commission Expires 09/29/08
DD348019

STATE OF MISSOURI )
                                       ) SS.:
CITY OF ST. LOUIS     )

On this 14^th day of January, 2005, before me, Renee Beard, the undersigned, personally appeared, JEFFREY SCHROEDER, known to me to be the person whose name is subscribed to the within instrument, and acknowledged that he executed the same for the purposes therein contained.

On the 14^th day of January, 2005, before me personally appeared JEFFREY SCHROEDER, to me known to be the person described in and who executed the foregoing instrument, and acknowledged that he executed the same as his free act and deed.

IN WITNESS WHEREOF, I hereunto set my hand and official seal.

/s/ Renee Beard________________
Notary Public, State of Missouri
Qualified in City of St. Louis
Commission Expires 6-22-2006

EX-10

Exhibit 10(a)9

Amendment To

Service Agreement

The parties hereto do hereby stipulate and agree to that the SERVICE AGREEMENT entered into by and between them under date of April 1, 1963, and as heretofore amended on January 1, 1972, April 27, 1984, August 1, 1988, January 28, 1991, January 1, 1992, January 1, 1996, January 1, 1998, January 1, 1999, January 1, 2000, January 1, 2001, April 1, 2002, January 1, 2003 and August 1, 2003 be and the same hereby is further amended by substituting for the Supplement to Exhibit II to the SERVICE AGREEMENT, the attached revised Supplement to Exhibit II. This Amendment is made and entered into as of March 1, 2004.

ENTERGY SERVICES, INC.

By /s/ Nathan E. Langston
     Nathan E. Langston
     Senior Vice President and Chief Accounting Officer

ENTERGY CORPORATION

By /s/ Donald C. Hintz
     Donald C. Hintz
     President

ALLOCATION FORMULAE FOR
GROUPS OF CLIENT COMPANIES

Exhibit II, Supplement

Note: Each allocation formula will be based on data relevant to participating Client Companies to whom the services are provided.

ENERGY SALES

Based on total kilowatt-hours of energy sold to consumers.

Used primarily for the allocation of costs associated with the financial analyses of sales and related items.

CUSTOMERS

Based on a twelve-month average of residential, commercial, industrial, government, and municipal general business electric and gas customers.

Used primarily for the allocation of costs associated with the support of customer based services. Would include customer service and support, marketing, economic forecasts, environmental services, financial and regulatory analyses and customer information systems.

EMPLOYEES

Based on the number of full-time employees at period end.

Used primarily for the allocation of costs associated with the support of employee-based services. Would include administration of employee benefits programs, employee communications, employee training, and various facilities-based benefits and information technology desktop support.

RESPONSIBILITY RATIO

Based on the ratio of the company's load at time of system peak load. The peak load is the average of the twelve monthly highest clock-hour demands in kilowatts of the interconnected system occurring each month coincident with the system peak load.

Used primarily for the allocation of costs incurred in fossil plant support and integrated planning.

TRANSMISSION LINE MILES

Based on the number of miles of transmission lines, weighted for design voltage (Voltage < 400kv = 1; Voltage >=400kv =2).

Used primarily for the allocation of costs associated with project design, maintenance and installation of Entergy transmission lines.

SUBSTATIONS

Based on the number of high voltage substations weighted for Voltage (Voltage < 500kv = 1; Voltage >= 500kv = 2).

Used primarily for the allocation of related engineering and technical support for transmission and distribution substation operations and maintenance as well as for engineering and project management associated with substation construction.

COMPOSITE - TRANSMISSION LINES/SUBSTATIONS

Based on two components: Transmission Line Miles (30% weighting) and the Number of High Voltage Substations (70% weighting).

Used primarily for the allocation of the costs associated with the support of the transmission and distribution function that has both a transmission line component as well as a substation or load component.

GAS CONSUMPTION

Based on the volume of natural gas consumed annually by all gas fired generating units within the Entergy System.

Used for the allocation of costs associated with services in support of gas purchased for generation units.

LEVEL OF ESI SERVICE

Based on ESI total billings to each System company, excluding corporate overhead.

Used for the allocation of costs associated with support of ESI as a legal entity.

SYSTEM CAPACITY (NON-NUCLEAR)

Based on the power level, in kilowatts, that could be achieved if all non-nuclear generating units were operating at maximum capability simultaneously.

Used primarily for the allocation of costs associated with the support of the fossil operations of the System. This would include services provided by plant support, environmental and purchasing.

LABOR DOLLARS BILLED

Based on total labor dollars billed to each company.

Used primarily to allocate the costs associated with employee benefits plans, payroll taxes, departmental indirect costs and performance based compensation plans for ESI employees.

DISTRIBUTION LINE MILES

Based on the number of miles of distribution lines of 34.5kv or less.

Used primarily for the allocation of costs associated with project design, maintenance and installation of Entergy distribution lines.

COAL CONSUMPTION

Based on the quantity of tons of coal delivered for a twelve-month period to each coal plant within the Entergy System.

Used for the allocation of costs associated with services in support of coal purchased for coal generating units.

ACCOUNTS PAYABLE TRANSACTIONS

Based on a twelve-month number of accounts payable transactions processed.

Used for the allocation of costs associated with the support of the accounts payable function.

SQUARE FOOTAGE

Based on square footage occupied by ESI functional business units.

Used primarily to allocate the costs associated with facilities supervision and support.

INSURANCE PREMIUMS (NON-NUCLEAR)

Based on non-nuclear insurance premiums.

Used for the allocation of costs associated with risk management.

ASSET LOCATIONS

Based on the number of asset locations at period end.

Used for the allocation of costs associated with the fixed asset accounting function.

CAPITAL EXPENDITURE AUTHORIZATIONS

Based on a twelve-month average of outstanding Capital Expenditure Authorizations and Storm Job Orders.

Used for the allocation of costs associated with the capital project costing accounting function.

TOTAL ASSETS

Based on total assets at period end.

Used primarily to allocate costs associated with the oversight and safeguarding of corporate assets. This would include services provided by financial management and certain finance functions, among others. Also used when the services provided are driven by the relative size and complexity of the System Companies and there is no functional relationship between the services and any other available allocation formula.

BANK ACCOUNTS

Based on the number of bank accounts at period end.

Used for the allocation of costs associated with daily cash management activities.

SERVER AND MAINFRAME USAGE COMPOSITE

Based on the use of historical expenditures.

Used primarily for the allocation of costs associated with mainframe, unix servers and related database administration.

GENERAL LEDGER TRANSACTIONS

Based on the number of general ledger transactions for the period.

Used primarily for the allocation of costs associated with general ledger activities, including related information systems, and for general accounting activities.

TRANSITION TO COMPETITION

Based on a twelve-month average of residential, commercial, industrial, government, and municipal general business of gas and/or electric customers.

Used primarily for the allocation of costs associated with the management support of the Entergy System's strategy for and transition to competition.

TELEPHONES

Based on the number of telephones within each Legal Entity at period end.

Used for the allocation of costs associated with maintenance and support of telephones.

FIBER

Based on capacity and use of the Entergy System's fiber optic network.

Used primarily for the allocation of fiber optic operations and maintenance expenses.

NUCLEAR UNITS

Based on the number of nuclear units managed and operated by each Entergy System Company.

Used primarily to allocate nuclear fuel-related services.

NUCLEAR SITES

Based on the number of nuclear sites managed and operated by each Entergy System Company.

Used to allocate miscellaneous nuclear-related services.

ACCOUNTS RECEIVABLE INVOICES

Based on a twelve-month number of accounts receivable transactions processed.

Used for the allocation of costs associated with the support of the accounts receivable function.

PAYCHECKS

Based on the number of paychecks issued at each Legal Entity at period end.

Used for the allocation of costs associated with the processing of payroll.

PROPERTY AND LIABILITY PAID LOSSES

Based on a five-year annual average of the property and liability losses paid by the system companies.

Used for the allocation of costs associated with the operation and maintenance of the Risk Information System.

COMPOSITE- SUPPLY CHAIN (Number of Transactions, Stockroom Count and Procurement Total Spending)

Based on three components with weighting to each: number of transactions, stockroom count, and procurement total spending.

Used for the allocation of costs associated with the management and operations of the materials management and work order processing system.

SUPPLY CHAIN - Inventory Management Fossil, Transmission & Distribution Issues, Transfers & Returns

Based on the number of issues, transfer & return transactions for each Legal Entity at period end.

Used for the allocation of costs associated with the management and operations of investment recovery, including Fossil, but excluding Nuclear.

SUPPLY CHAIN - Procurement Total Spending

Based on the dollar amount of procurement spending within each Legal Entity at period end.

Used for the allocation of costs associated with procurement activities for the Entergy System.

SUPPLY CHAIN - Labor Dollars

Based on the labor dollars for the Transformer, Meter, and Light Shops.

Used primarily for the allocation of costs associated with services provided by employees in the supply chain equipment refurbishment and repair department.

DISTRIBUTION SUBSTATIONS TRANSFORMERS

Based on the number of transformers at the Distribution Substations at period end.

Used primarily for the allocation of costs associated with the maintenance, administrative activities, and technical analysis of all Distribution Substations.

REMOTE ACCESS SERVICES (RAS) ID's

Based on the number of RAS ID's within each Legal Entity at period end.

Used for the allocation of costs associated with providing Remote Access Service to Entergy employees and contractors.

VEHICLES

Based on the number of vehicles owned by each Legal Entity.

Used for the allocation of costs associated with the maintenance of company vehicles.

MANAGED ACCOUNTS

Based on the number of industrial and commercial managed accounts.

Used for the allocation of costs associated with the maintenance of Entergy's industrial and commercial customer accounts.

NUMBER OF CALLS - CUSTOMER SERVICE CENTERS

Based on a twenty-four month average of customer calls for each Legal Entity.

Used for the allocation of costs associated with the administration and support of Entergy's Customer Service Centers.

RADIO USAGE

Based on usage of Entergy's 2-way radio system.

Used for the allocation of costs associated with the administration and support of Entergy's 2-way radio system.

TOTAL IT SPEND

Based on the total dollars spent in the Information Technology plan.

Used for the allocation of costs associated with the administration and support of Entergy's IT business planning.

SUPPLY CHAIN MATERIALS TRANSACTIONS

Based on the number of Supply Chain materials transactions for each Legal Entity.

Used for the allocation of costs associated with the support of systems that manage Supply Chain materials.

AVERAGE NUMBER OF CAPITAL EXPENDITURE AUTHORIZATION PROJECTS FOR INFORMATION TECHNOLOGY, CUSTOMER SERVICE, DISTRIBUTION AND TRANSMISSION

Based on a twelve-month average of outstanding Capital Expenditure Authorizations for the Information Technology, Customer Service, Distribution and Transmission organizations.

Used for the allocation of costs associated with the prioritization of capital projects for the Information Technology, Customer Service, Distribution and Transmission organizations.

SECTION 263A TAX BENEFITS

Based on Section 263A tax benefits for each Legal Entity.

Used for the allocation of costs associated with tax administration, planning, and support related to Section 263A tax benefits.

OPEN WORKERS' COMPENSATION CLAIMS

Based on the number of open claims for each Legal Entity.

Used for the allocation of costs associated with managing workers' compensation claims processes and budgets.

UNIT POWER SALES AGREEMENT

Based on fixed allocation percentages under Entergy's Unit Power Sales Agreement.

Used primarily for the allocation of certain Tax Department services in connection with Entergy's Unit Power Sales Agreement.

RECORDS MANAGEMENT

Based on the number of employees at each Legal Entity using records management services.

Used to allocate costs associated with the management and supervision of non-nuclear business unit records management processes.

EX-10

Exhibit 10(a)24

FIRST AMENDMENT TO THE THIRTY-FIFTH ASSIGNMENT OF AVAILABILITY AGREEMENT, CONSENT AND AGREEMENT

This First Amendment, dated as of December 17, 2004 (this "Amendment"), to the Thirty-fifth Assignment of Availability Agreement, Consent and Agreement (hereinafter referred to as the "Assignment"), dated as of December 22, 2003, is made by and among System Energy Resources, Inc. (the "Company"), Entergy Arkansas, Inc. ("EAI") (successor in interest to Arkansas Power & Light Company and Arkansas-Missouri Power Company), Entergy Louisiana, Inc. ("ELI"), Entergy Mississippi, Inc. ("EMI"), and Entergy New Orleans, Inc. ("ENOI") (hereinafter EAI, ELI, EMI and ENOI are called individually a "System Operating Company" and collectively, the "System Operating Companies"), and Union Bank of California, N.A., as Administrating Bank (in such capacity, the "Administrating Ba nk") under the Reimbursement Agreement, dated as of December 22, 2003 (as amended, restated, supplemented or otherwise modified from time to time, the "Reimbursement Agreement"), among the Company, Union Bank of California, N.A., as Funding Bank, the Administrating Bank, KeyBank National Association, as Syndication Agent, BNP Paribas and Wachovia Bank, National Association, as Co-Documentation Agents, and the banks named therein and from time to time parties thereto (the "Participating Banks"). Unless otherwise defined herein, capitalized terms used herein shall have the meaning assigned to such terms in the Assignment.

WHEREAS:

1. The Assignment provides that the Assignment and the Availability Agreement may be amended, waived, modified, discharged or otherwise changed only by a written instrument which has been signed by all the parties to the Assignment, in the case of the Assignment, or by the persons specified in Section 11 of the Availability Agreement, and which has been approved in writing by the LOC Banks or which does not materially adversely affect the rights of the LOC Banks.
2. The Assignment provides that the Administrating Bank shall, at the request of the Company, execute any instrument amending, waiving, modifying, discharging or otherwise changing the Assignment (a) as to which the Administrating Bank shall have received an opinion of counsel to the effect that such instrument has been duly authorized by each person executing the same and is permitted by the provisions of Section 5.1 of the Assignment and that the Assignment, as amended, waived, modified, discharged or otherwise changed by such instrument, constitutes valid, legally binding and enforceable obligations of the Company and each of the System Operating Companies, and (b) which shall have been executed by the Company and each of the System Operating Companies. The Administrating Bank shall be fully protected in relying upon the aforesaid opinion.
3. Pursuant to Section 12(c)(iii) of the Reimbursement Agreement, the Assignment may not be modified without first obtaining the prior written consent of all Participating Banks. Pursuant to Section 2(b) of the Second Amendment and Consent, dated as of the date hereof (the "Second Amendment to Reimbursement Agreement"), among the Company and the Participating Banks, the Participating Banks have consented to this Amendment.
4. The Company, the System Operating Companies and the Administrating Bank, by this instrument, wish to amend the Assignment, as set forth below.
5. All things necessary to make this Amendment the valid, legally binding and enforceable obligation of each of the parties hereto have been done and performed and the execution and performance hereof in all respects have been authorized and approved by all corporate and shareholder action necessary on the part of each thereof.

NOW, THEREFORE, in consideration of the terms and agreements hereinafter set forth and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree with each other as follows:

ARTICLE I.

Amendments

1.1  Amendments.

A. Section 1.5 of the Assignment is hereby amended by (i) deleting the word "and" at the end of subsection (a) thereof, (ii) deleting the period at the end of subsection (b) thereof and substituting therefor a semicolon, and (iii) adding at the end thereof the following new subsections (c), (d) and (e):

"(c) the terms "Common Stock" and "common stock" shall mean the class of stock, shares or other ownership interests in the issuer thereof howsoever evidenced (including, without limitation, limited liability company membership interests) that has ordinary voting power for the election of directors, managers or trustees (or other persons performing similar functions) of the issuer, as applicable, provided that preference stock and preferred stock shall not be considered common stock;

(d) the terms "Corporation" and "corporation" shall mean a corporation, association, company (including, without limitation, limited liability company) or business trust, and references to "corporate" and other derivations of "corporation" herein shall be deemed to include appropriate derivations of such entities; and

(e) the terms "Preferred Stock", "preferred stock", "Preference Stock" and "preference stock" shall mean any class of stock, shares or other ownership interests in the issuer thereof howsoever evidenced (including, without limitation, limited liability company membership interests), whether with or without voting rights, that is entitled to dividends or distributions prior to the payment of dividends or distributions with respect to common stock."

B. The Assignment shall be deemed amended and modified to the extent necessary to give effect to the foregoing. Except as amended and modified hereby, the Assignment shall remain in full force and effect and is hereby in all respects ratified and confirmed.

C. This Amendment shall become effective as of the date hereof when, and only when, (i) the Administrating Bank shall have received counterparts of this Amendment executed by the Company, the System Operating Companies and the Administrating Bank and (ii) the Second Amendment to Reimbursement Agreement shall have become effective pursuant to the terms thereof.

ARTICLE II.

Severability

2.1 Severability. If any provision or provisions of this Amendment shall be held to be invalid, illegal or unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby.

ARTICLE III.

Governing Law

3.1 Governing Law. This Amendment shall be governed by and construed in accordance with the laws of the State of New York.

ARTICLE IV.

Succession

4.1 Succession. This Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

ARTICLE V.

Reference to and Effect on the Assignment Agreement

5.1 Reference to and Effect on the Assignment Agreement. Upon the effectiveness of this Amendment, each reference in the Assignment to "this Assignment", "hereunder", "hereof", "herein" or words of like import referring to the Assignment shall mean and be a reference to the Assignment as amended by this Amendment. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of the LOC Banks under the Assignment or the Availability Agreement, nor constitute a waiver of any provision of the Assignment or the Availability Agreement.

ARTICLE VI.

Counterparts

6.1 Execution in Counterparts. This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed and delivered shall be deemed to be an original and all of which taken together shall constitute but one and the same instrument. In furtherance of the foregoing, it is understood and agreed that signatures hereto submitted by facsimile transmission shall be deemed to be, and shall constitute, original signatures.

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed by their respective officers thereunto duly authorized as of the day and year first above written.

ENTERGY ARKANSAS, INC.
ENTERGY LOUISIANA, INC.
ENTERGY MISSISSIPPI, INC.
ENTERGY NEW ORLEANS, INC.
SYSTEM ENERGY RESOURCES, INC.
 

By:                                                                 
     Name: Steven C. McNeal
     Title: Vice President and Treasurer

UNION BANK OF CALIFORNIA, N.A.,
as Administrating Bank

By:                                                                   
     Name:
     Title:

EX-10

Exhibit 10(a)76

SYSTEM EXECUTIVE CONTINUITY PLAN OF
ENTERGY CORPORATION AND SUBSIDIARIES
(As Amended and Restated Effective March 8, 2004)

Certificate of Amendment
 

Amendment No. 1

THIS INSTRUMENT, executed and made effective this 29th day of December, 2004 ("Effective Date"), constitutes the First Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, as amended and restated effective March 8, 2004 (the "Plan"). All capitalized terms used in this document shall have the meanings assigned to them in the Plan unless otherwise defined in this document.

Pursuant to Section 8.01 of the Plan, the Plan is hereby amended as follows:

1. Plan Section 1.04 is hereby amended in its entirety to read as follows:
4. "Benefit Continuation Period" shall mean:

1. with respect to a Participant at System Management Level 1 or 2, a thirty-six (36) consecutive month period, commencing on the Participant's Date of Termination;
    
2. with respect to a Participant at System Management Level 3, a twenty-four (24) consecutive month period, commencing on the Participant's Date of Termination;
    
3. with respect to a Participant at System Management Level 4, a twelve (12) consecutive month period, commencing on the Participant's Date of Termination.

2. The term "Benefit Continuation Period" shall replace the term "Benefit Pay Continuation Period," wherever such term appears in the Plan.

 
3. Plan Section 4.02 is hereby amended in its entirety to read as follows:

4.02 Cash Payment. A Participant satisfying all of the terms and conditions of this Plan shall be entitled to receive, in lieu of any further salary payments to the Participant for periods subsequent to the Date of Termination, but subject to the forfeiture provisions of Section 6.01, a single-sum cash payment calculated and payable in accordance with the following:

1. If Participant is at System Management Level 1 or 2, the total cash benefit amount payable under this Section 4.02 to the Participant shall be equal to three (3) times the sum of: (1) Participant's Base Salary or, if higher, Participant's annual rate of salary as in effect immediately prior to the first occurrence of an event or circumstance constituting Good Reason and (2) Participant's Target Award for the year in which the Change in Control Period commences or, if higher, the year in which the Date of Termination occurs. The total cash benefit amount computed above shall be paid to Participant as a single-sum distribution not later than the 5^th day following the Participant's Date of Termination.

 
2. If Participant is at System Management Level 3, the total cash benefit amount payable under this Section 4.02 to Participant shall be equal to two (2) times the sum of: (1) Participant's Base Salary or, if higher, Participant's annual rate of salary as in effect immediately prior to the first occurrence of an event or circumstance constituting Good Reason and (2) Participant's Target Award for the year in which the Change in Control Period commences or, if higher, the year in which the Date of Termination occurs. The total cash benefit amount computed above shall be paid to Participant as a single-sum distribution not later than the 5^th day following the Participant's Date of Termination.
3. If Participant is at System Management Level 4, the total cash benefit amount payable under this Section 4.02 to Participant shall be equal to the sum of: (1) Participant's Base Salary or, if higher, Participant's annual rate of salary as in effect immediately prior to the first occurrence of an event or circumstance constituting Good Reason and (2) Participant's Target Award for the year in which the Change in Control Period commences or, if higher, the year in which the Date of Termination occurs. The total cash benefit amount computed above shall be paid to Participant as a single-sum distribution not later than the 5^th day following the Participant's Date of Termination.

4. The second sentence of Plan Section 5.03 is hereby amended in its entirety to read as follows:

Each System Company's contribution shall be in an amount equal to the total amount of additional benefits payable to such System Company's Plan Participants in accordance with the provisions of Section 4.02 of the Plan.
 

5. Subsection 6.01(d) is hereby amended in its entirety to read as follows:

(d) during Participant's employment and thereafter, other than as authorized by a System Company or as required by law or as necessary for the Participant to perform his duties for a System Company employer, Participant shall disclose to any person or entity any non-public data or information concerning any System Company, in which case Participant shall be required to repay any Plan benefits previously received by him. Disclosure of information pursuant to subpoena, judicial process, or request of a governmental authority shall not be deemed a violation of this provision, provided that Participant gives the System Company immediate notice of any such subpoena or request and fully cooperates with any action by System Company to object to, quash, or limit such request; or
 

6. Plan Section 8.01 is hereby amended in its entirety to read as follows:

8.01 General. The Board, or the Personnel Committee of the Board, shall have the right, in its absolute discretion, at any time and from time to time, to modify or amend, in whole or in part, any or all of the provisions of this Plan, or suspend or terminate it entirely, subject to the provisions of Section 8.02 hereof. The provisions of this Article VIII shall survive a termination of the Plan unless such termination is agreed to by the Participants.

IN WITNESS WHEREOF, the Board of Directors of Entergy Corporation has caused this First Amendment to the System Executive Continuity Plan of Entergy Corporation and Subsidiaries to be executed by its duly authorized representative on the day, month, and year above set forth.

ENTERGY CORPORATION
through the undersigned duly authorized representative

 /s/ William E. Madison                        

WILLIAM E. MADISON
Senior Vice-President,
Human Resources and Administration

EX-10

Exhibit 10(a)78

SYSTEM EXECUTIVE CONTINUITY PLAN II
OF ENTERGY CORPORATION AND SUBSIDIARIES

Certificate of Amendment

Amendment No. 1

THIS INSTRUMENT, executed and made effective this 29th day of December, 2004 ("Effective Date"), constitutes the First Amendment of the System Executive Continuity Plan II of Entergy Corporation and Subsidiaries (the "Plan"). All capitalized terms used in this document shall have the meanings assigned to them in the Plan unless otherwise defined in this document.

Pursuant to Section 8.01 of the Plan, the Plan is hereby amended as follows:

1. Plan Section 1.04 is hereby amended in its entirety to read as follows:
4. "Benefit Continuation Period" shall mean:

1. with respect to a Participant at System Management Level 1 or 2, a thirty-six (36) consecutive month period, commencing on the Participant's Date of Termination;
    
2. with respect to a Participant at System Management Level 3, a twenty-four (24) consecutive month period, commencing on the Participant's Date of Termination;
    
3. with respect to a Participant at System Management Level 4, a twelve (12) consecutive month period, commencing on the Participant's Date of Termination.

2. The term "Benefit Continuation Period" shall replace the term "Benefit Pay Continuation Period," wherever such term appears in the Plan.

 
3. Plan Section 4.02 is hereby amended in its entirety to read as follows:

4.02 Cash Payment. A Participant satisfying all of the terms and conditions of this Plan shall be entitled to receive, in lieu of any further salary payments to the Participant for periods subsequent to the Date of Termination, but subject to the limitation provisions of Section 4.09 and the forfeiture provisions of Section 6.01, a single-sum cash payment calculated and payable in accordance with the following:

1. If Participant is at System Management Level 1 or 2, the total cash benefit amount payable under this Section 4.02 to the Participant shall be equal to three (3) times the sum of: (1) Participant's Base Salary or, if higher, Participant's annual rate of salary as in effect immediately prior to the first occurrence of an event or circumstance constituting Good Reason and (2) Participant's Target Award for the year in which the Change in Control Period commences or, if higher, the year in which the Date of Termination occurs. The total cash benefit amount computed above shall be paid to Participant as a single-sum distribution not later than the 5^th day following the Participant's Date of Termination.

 
2. If Participant is at System Management Level 3, the total cash benefit amount payable under this Section 4.02 to Participant shall be equal to two (2) times the sum of: (1) Participant's Base Salary or, if higher, Participant's annual rate of salary as in effect immediately prior to the first occurrence of an event or circumstance constituting Good Reason and (2) Participant's Target Award for the year in which the Change in Control Period commences or, if higher, the year in which the Date of Termination occurs. The total cash benefit amount computed above shall be paid to Participant as a single-sum distribution not later than the 5^th day following the Participant's Date of Termination.
3. If Participant is at System Management Level 4, the total cash benefit amount payable under this Section 4.02 to Participant shall be equal to the sum of: (1) Participant's Base Salary or, if higher, Participant's annual rate of salary as in effect immediately prior to the first occurrence of an event or circumstance constituting Good Reason and (2) Participant's Target Award for the year in which the Change in Control Period commences or, if higher, the year in which the Date of Termination occurs. The total cash benefit amount computed above shall be paid to Participant as a single-sum distribution not later than the 5^th day following the Participant's Date of Termination.

4. The second sentence of Plan Section 5.03 is hereby amended in its entirety to read as follows:

Each System Company's contribution shall be in an amount equal to the total amount of additional benefits payable to such System Company's Plan Participants in accordance with the provisions of Section 4.02 of the Plan.

5. Subsection 6.01(d) is hereby amended in its entirety to read as follows:

(d) during Participant's employment and thereafter, other than as authorized by a System Company or as required by law or as necessary for the Participant to perform his duties for a System Company employer, Participant shall disclose to any person or entity any non-public data or information concerning any System Company, in which case Participant shall be required to repay any Plan benefits previously received by him. Disclosure of information pursuant to subpoena, judicial process, or request of a governmental authority shall not be deemed a violation of this provision, provided that Participant gives the System Company immediate notice of any such subpoena or request and fully cooperates with any action by System Company to object to, quash, or limit such request; or
 

6. Plan Section 8.01 is hereby amended in its entirety to read as follows:

8.01 General. The Board, or the Personnel Committee of the Board, shall have the right, in its absolute discretion, at any time and from time to time, to modify or amend, in whole or in part, any or all of the provisions of this Plan, or suspend or terminate it entirely, subject to the provisions of Section 8.02 hereof. The provisions of this Article VIII shall survive a termination of the Plan unless such termination is agreed to by the Participants.

IN WITNESS WHEREOF, the Board of Directors of Entergy Corporation has caused this First Amendment to the System Executive Continuity Plan II of Entergy Corporation and Subsidiaries to be executed by its duly authorized representative on the day, month, and year above set forth.

ENTERGY CORPORATION
through the undersigned duly authorized representative

   /s/ William E. Madison                     

WILLIAM E. MADISON
Senior Vice-President,
Human Resources and Administration

EX-10

Exhibit 10(a)100

SUMMARY OF EXECUTIVE OFFICER AND DIRECTOR COMPENSATION

The following is a description of certain compensation arrangements of named executive officers and members of the Board of Directors of Entergy Corporation (the "Company") in effect as of December 31, 2004.

Compensation of Executive Officers

Annual Base Salary

As of December 31, 2004, the base salaries for the named executive officers of the Company were:

E Renae Conley	$ 349,000
Leo P Denault	$ 500,000
Joseph F Domino	$ 276,500
J Wayne Leonard	$ 1,100,000
Hugh T McDonald	$ 282,000
Daniel F Packer	$ 263,000
Mark T Savoff	$ 500,000
Carolyn C Shanks	$ 276,000
Robert D Sloan	$ 432,600
Richard J Smith	$ 500,000
Gary J Taylor	$ 420,000

Annual Incentive Bonus

The Company's executive officers participate in the Executive Annual Incentive Plan ("EAIP"). The EAIP is designed to reward management for attainment of short-term performance targets. These include but are not limited to:

• improvement in earnings per share,
• operating cash flows,
• control of operation and maintenance costs,
• safety, and
• customer satisfaction

The measures have varying weights and are specifically tailored to each executive's responsibilities.

Non-Employee Director Compensation

Directors who are Entergy officers do not receive any fixed fee for service as a director. Non-employee directors are compensated through a combination of cash payments such as attendance fees and a stipend for serving as committee chairmen, equity-based compensation, benefits and reimbursements. Entergy's Chairman of the Board also receives compensation for service in this capacity.

Cash Compensation

Attendance Fees Each non-employee director receives a fee of $1,500 for attendance at Board meetings, $1,000 for attendance at committee meetings scheduled in conjunction with Board meetings and $2,000 for attendance at committee meetings not scheduled in conjunction with a Board meeting. If a director attends a meeting of a committee on which that director does not serve as a member, he or she receives one-half of the fee of an attending member. Directors also receive $1,000 for participation in any inspection trip or conference not held in conjunction with a Board or committee meeting. Directors receive only one-half the fees set forth above for telephone attendance at Board or committee meetings.

Chairmanships The committee chairpersons of the Audit Committee and Nuclear Committee are paid an additional $10,000 annually, and the committee chairpersons of the Executive Committee, Personnel Committee, Corporate Governance Committee and Finance Committee are paid an additional $5,000 annually.

Quarterly Payments Each calendar quarter, Entergy makes a cash payment to all non-employee directors equaling the value of 75 shares.

Deferral of Cash Compensation Any director may elect to defer payment of some or all of the cash compensation that would otherwise become due to him or her in a given calendar year. This election must be made in the calendar year preceding the year in which the director is to receive payments. Payment of deferred amounts is made in one or more annual installments as selected in the discretion of the director. All deferrals are subject to applicable deferral elections. Post-2004 deferrals of cash compensation are subject to the requirements of Internal Revenue Code Section 409A.

Benefits

The non-employee Directors have the opportunity to receive annually an executive physical examination either from their local physician or at the Mayo Clinic's Jacksonville, Florida location. The Corporation will pay the cost of the physical examination, and, if at Mayo, travel and living expenses. Non-employee Directors are reimbursed for all normal travel and expenses associated with attending Board and committee meetings as well as inspection trips and conferences associated with their Board duties and spousal travel to certain Board functions, including a "gross up" payment to cover taxes incurred on reimbursement of spousal travel. The Company purchases several types of insurance for the benefit of its non-employee directors, including director and officer liability insurance, life insurance, accidental death and dismemberment insurance, personal accident insurance, and additional coverage if the accident occurs in an aircraft owned by the Company. Outside direct ors are also eligible to purchase, on an after-tax basis, medical coverage comparable to that provided under the Company's Medical Plan.

Compensation for Chairman of Board

In 2004, Robert v.d. Luft was paid $200,000 plus 20,000 stock options (granted at market price) to serve as Chairman of the Board. In addition, the Company provides, at its expense, financial counseling services for Mr. Luft on the same terms and conditions that it provides those services to executive officers of the Company. Finally, as an outside director, Mr. Luft receives the compensation and benefits described above.

EX-10

Exhibit 10(a)101

RESTRICTED STOCK GRANTS FOR OUTSIDE DIRECTORS

1. Definitions

(a) Except as otherwise provided in Section 2 below, the term "Award Date" means the last day of the third, sixth, ninth and twelfth full calendar months following an Outside Director's election (or reelection) to the Board of Directors; provided, however, the fourth and final Award Date in a given Service Year shall not be later than the last day of such Service Year.

(b) The term "Board of Directors" means the Board of Directors of Entergy.

(c) The term "Common Stock" means the common stock of Entergy.

(d) The term "Deferral Election" means an election by a Participant to defer the delivery of shares from a Stock Award to a future date under the provisions of Section 3 hereof.

(e) The term "Entergy" means Entergy Corporation, a Delaware corporation.

(f) The term "Fair Market Value" means the closing price of Common Stock on the New York Stock Exchange Composite Tape on the first business day of the month during which a Stock Award is made.

(g) The term "Outside Director" or "Participant" means a member of a Board of Directors who is not an employee of Entergy or any of its Subsidiaries. A director of Entergy who is also an employee of Entergy or any of its Subsidiaries shall become eligible to receive grants hereunder upon the termination of such employment.

(h) The term "Service" shall mean service as an Outside Director.

(i) The term "Service Year" means the period of Service commencing on the date an Outside Director is elected (or reelected) to the Board of Directors and ending on the date of the next occurring annual meeting of stockholders of Entergy.

(j) The term "Stock Award" means the portion of the compensation paid to an Outside Director in the form of Common Stock for his or her Services on the Board of Directors according to the terms hereof.

(k) The term "Subsidiary" means any corporation with respect to which Entergy owns, or directly or indirectly controls, the majority of the combined voting power.

2. Stock Award

Subject to the provisions of Section 3 hereof regarding Participants who make a Deferral Election, each Outside Director shall receive an award of 150 shares of Common Stock on each Award Date with respect to Services rendered through the respective Award Date. Such shares shall be authorized but unissued shares or open market shares of Common Stock. Shares of Common Stock purchased on the open market shall be purchased and held in such a manner so that such shares are not returned to the status of authorized but unissued shares of Entergy, but are available for Stock Awards hereunder. Certificates representing the shares of Common Stock awarded hereunder shall be delivered to the Outside Director within thirty (30) days after each respective Award Date. Notwithstanding the foregoing, if a Participant has made a timely deferral election pursuant to Section 3 below for any Stock Award granted hereunder, the "Award Date" for that Stock Award shall be the date on which payments or distribution s of that deferred award are fixed under the applicable deferral election.

3. Deferral Election

1. 2004 Deferral Elections. In lieu of receiving shares following each Award Date, a Participant who becomes eligible due to his or her election to the Board of Directors as an Outside Director in 2004 may elect no later than thirty (30) days from the later of (i) his or her election to the Board as an Outside Director and prior to the performance of any services in such capacity, or (ii) the date on which the Participant first becomes eligible to receive grants hereunder, to defer the receipt of shares that would have otherwise been earned after the date of the deferral election, which election shall apply to and remain effective as to all such awards occurring during the remainder of 2004 calendar year and provide that such awards shall be deferred until at least January 2, 2007.

As to all deferral elections made pursuant to this subsection (a) and except as otherwise provided below, any election shall become effective on the date of such election and such election shall be irrevocable and remain in effect until the earliest of (1) the deferral date specified in writing in the Participant's deferral election form (which shall not precede January 2, 2007), and any date specified by a Participant in an deferral election form that is earlier than this date shall be deemed irrevocably reformed and fixed to January 2, 2007, (2) the date on which such Participant terminates his or her Service on the Board of Directors, or (3) subject to regulations or other rules and procedures as may be promulgated by the Treasury Department or the Internal Revenue Service, such date as any amounts deferred hereunder shall be deemed no longer deferred for purposes of the Internal Revenue Code. Notwithstanding anything else stated herein to the contrary, this election for existing Outside Directors ap plies only to forms of awards previously provided under the Stock Plan for Outside Directors.

2. Outside Directors Newly Elected to the Board of Directors after 2004. In lieu of receiving shares following each Award Date, a Participant who becomes eligible due to their election to the Board of Directors as an Outside Director for the first time after 2004, no later than thirty (30) days from his or her election to the Board as an Outside Director and prior to the performance of any services in such capacity, and provided the Participant becomes eligible to receive grants hereunder, may elect to defer the receipt of shares that would have otherwise been earned after the date of the deferral election, which election shall apply to and remain effective as to all such awards occurring during the remainder of the then current calendar year, and such awards shall be deferred until a future date which must be no earlier than two years after January 2 immediately following the end of the calendar year during which such Participant is first elected (that is, as an example, for an Outside Director first elec ted in 2005, the earliest deferral date shall be January 2, 2008). Except as otherwise provided below, any election shall become effective on the date of such election, and such election shall remain in effect and irrevocable until the earliest of (i) the deferral date specified in writing in the Participant's deferral election form (which shall not precede the two year period defined above), and any date specified by a Participant in an deferral election form that is earlier than this earliest deferral date shall be deemed irrevocably reformed and fixed to the earliest deferral date allowed hereunder, (ii) the date on which such Participant terminates his or her Service on the Board of Directors, or (iii) subject to regulations or other rules and procedures as may be promulgated by the Treasury Department or the Internal Revenue Service, such date as any amounts deferred hereunder shall be deemed no longer deferred for purposes of the Internal Revenue Code.
3. Future Deferral Cycles for Participants. Notwithstanding the foregoing, and except as set forth in subsections (a) and (b) above, any election to defer a Stock Award that may be otherwise awarded in the next occurring calendar year must be made in writing and filed with the Administrator no later than June 30 immediately preceding the first day of the next occurring calendar year as to which the deferral election shall apply. Any such deferral election shall apply to and remain effective as to all such awards that would have otherwise occurred during the next occurring calendar year, and such covered awards shall be deferred until a future date which must be no earlier than two years after January 2 immediately following the end of the calendar year as to which such deferral election applies (that is, as an example, for a deferral election made before June 30, 2004, for the 2005 calendar year, the earliest deferral date shall be January 2, 2008). Except as otherwise provided below, any election shall become effective on the date of such election, and such election shall remain in effect and irrevocable until the earliest of (i) the deferral date specified in writing in the Participant's deferral election form (which shall not precede the two year period defined above), and any date specified by a Participant in an deferral election form that is earlier than this earliest deferral date shall be deemed irrevocably reformed and fixed to the earliest deferral date allowed hereunder, (ii) the date on which such Participant terminates his or her Service on the Board of Directors, or (iii) subject to regulations or other rules and procedures as may be promulgated by the Treasury Department or the Internal Revenue Service, such date as any amounts deferred hereunder shall be deemed no longer deferred for purposes of the Internal Revenue Code. If no written election to defer awards made in the next calendar year is timely filed with the Administrator, the Participant shall be deemed not to have deferred awards i n that next calendar year.

(d) For a Participant who elects to defer the receipt of shares in accordance with subsection (a),(b), or (c) above, dividends which would have been paid on a Participant's Stock Award had such Participant not elected to defer receipt of such Stock Award shall be credited as dividend equivalents to an unfunded liability account. Such dividend equivalents shall be payable in cash to the Participant at the same time as the applicable Stock Awards deferred under the Plan are paid. A Participant's dividend equivalents account shall earn interest at an annual rate to be applied during each year based upon the 52 week Treasury Bill rate as in effect on the first business day of each year.

4. Adjustment

If as a result of recapitalization (or other adjustment in the stated capital of Entergy), or as the result of a stock split, merger, consolidation, or other reorganization, the Common Stock of Entergy is increased, reduced, or otherwise changed, the number of shares available to be awarded hereunder shall be appropriately adjusted. The shares that have been deferred pursuant to Participants' Deferral Elections should be treated in an identical manner as outstanding shares of Common Stock are treated.

5. Termination of Service

If an Outside Director terminates his or her Service on the Board of Directors prior to the expiration of a Service Year, such Outside Director shall be entitled to receive, on a pro rata basis, the portion of the Stock Awards attributable to such Outside Director's Service through the date of termination. Such shares and any shares which have not been previously delivered to a Participant pursuant to Deferral Elections shall be delivered to such Outside Director within thirty (30) days following the date of termination.

6. Restrictions

Shares delivered to Participants hereunder shall be subject to such restrictions on transferability and disposition as shall be required by Rule 16b-3 of the Securities Exchange Act of 1934 ("Exchange Act") or any successor rule. Further, each participant subject to Section 16 of the Exchange Act or Section 17 of the Public Utility Holding Company Act of 1935 ("Holding Company Act") concerning transactions regarding the common stock of Entergy Corporation shall not sell or transfer any shares awarded or any shares or other securities issued on account of the shares awarded for at least six (6) months after acquisition except as permitted under the provisions of the Exchange Act, or the Holding Company Act and rules promulgated thereunder.

EX-10

Exhibit 10(b)57

Amendment To

Service Agreement

The parties hereto do hereby stipulate and agree to that the SERVICE AGREEMENT entered into by and between them under date of July 16, 1974, and as heretofore amended on April 27, 1984, August 1, 1988 (effective January 1, 1989), and January 1, 1991 has not been updated by formal signed amendment since January 1, 1991. Whereas it is now necessary to update and amend this agreement to bring it into compliance with Entergy Services, Inc.'s (ESI) other client companies. ESI's service agreements with its client companies, including SERI, were also amended effective January 1, 1992, January 1, 1996, January 1, 1998, January 1, 1999, January 1, 2000, January 1, 2001, April 1, 2002, January 1, 2003 and August 1, 2003. This amendment conforms to these past amendments that have previously been approved by the Securities and Exchange Commission and put into effect by ESI's other client companies. Attached hereto is a complete copy of the original Service Agreement and the current Exhib it I, Exhibit II, and Supplement to Exhibit II to the Service Agreement. This amendment is made an entered into as of January 1, 2004.

ENTERGY SERVICES, INC.

By /s/ Nathan E. Langston

Nathan E. Langston
Senior Vice President,
Chief Accounting Officer

SYSTEM ENERGY RESOURCES, INC.

By /s/ Gary Taylor
Gary Taylor
President and CEO

Exhibit I

DESCRIPTION OF SERVICES WHICH WILL BE PROVIDED BY

MIDDLE SOUTH SERVICES, INC.

UNDER THIS AND SIMILAR SERVICE AGREEMENTS

1. Consultation and advice on financial planning, sale of securities and temporary cash investments, including assistance in connection with the preparation, printing and filing of appropriate documents with regulatory authorities, and provision of liaison with financial community;
2. Consultation and advice on budgeting and preparation of long-range forecasts;
3. Consultation and advice on employee benefit plans;
4. Consultation and advice with respect to regulatory matters, particularly those involving the Securities and Exchange Commission or the Federal Energy Regulatory Commission, and provision of liaison and assistance in processing matters with the staffs of such commissions;
5. Planning assistance and advice in the filed of nuclear activities including coordination or research programs and other activities in such field;
6. Liaison with special counsel representing operating companies in proceedings involving the Middle South System and with consultants retained to prepare testimony and other data for use in such proceedings; Operation of a communications and public relations department and placing of Middle South System national advertising;
7. Tax services relating to preparation and filing of returns for federal and state income taxes and declaration of estimated income taxes; studies of adequacy of tax accruals; and assistance in connection with audit of returns by Internal Revenue Service and State Tax Agencies; Insurance consulting and advisory services relating to fire and allied lines of insurance, casualty and surety insurance, and employee benefit insurance;
8. General consultation on management, business problems and strategic planning;
9. Consultation on special accounting problems;
10. Statistical services, such as study of comparative operating results, and up-dating annually System statistical data;
11. Preparation of maps;
12. General advisory engineering services including system planning, operation, fuel supply and construction management;
13. Operation of a System Operations Center for the control of bulk power supply and load dispatching within the System and with Interconnected systems;
14. Planning assistance and advice with respect to System sales of power under the interconnection agreements among the operating companies and acting on behalf of the operating companies in dealing with other electric utilities with relation to the sale, purchase or exchange of bulk electric power and energy;
15. Operation of a data processing Computer Center to serve the Middle South System;
16. Consultation and advisory services with respect to rate studies, rate design, cost studies, load research, weather analysis, economic studies, forecasts of intra-system transactions, and computer rate analysis programs; and
17. Consultation, advice and services with respect to internal auditing.

Exhibit II

METHODS OF ALLOCATING COSTS AMONG CLIENT COMPANIES RECEIVING SERVICE UNDER THIS AND SIMILAR SERVICE AGREEMENTS WITH ENTERGY SERVICES, INC. (SERVICES)

1. The costs of rendering service by Services will include all costs of doing business including interest on debt but excluding a return for the use of Services' initial equity capital amounting to $20,000.
2. (a) Services will maintain a separate record of the expenses of each department. The expenses of each department will include:

1. those expenses that are directly attributable to such department,
2. an appropriate portion of those office and housekeeping expenses that are not directly attributable to a department but which are necessary to the operation of such department, and
3. an appropriate portion of those expenses of other Services' departments necessary to support the operation of the department.

2. Expenses of the department will include salaries and wages of employees, including social security taxes, vacations, paid absences, sickness, employee disability expenses, and other employee welfare expenses, rent and utilities, desktops, telephones, materials and supplies, and all other expenses attributable to the department.
3. Departmental expense will be categorized into one of three classes:

1. those expenses which are directly attributable to specific services rendered to a Client Company or group of Client Companies (Departmental Direct Costs),
2. those expenses which are attributable to the overall operation of the department and not to a specific service provided to Client Companies (Departmental Indirect Costs) (these expenses include not only the salaries and wages of employees, but also other related employment costs described in Section 2 (b) above), and
3. those expenses which are attributable to the operation of other departments of Services as well as to a specific service provided to the Client Companies (Departmental Support Service Costs).

4. The indirect expenses of the department will not include:

1. those incremental out-of-pocket expenses that are incurred for the direct benefit and convenience of a Client Company or a group of Client Companies and are to be directly charged to such Client Company or group of Client Companies; and
2. Services' overhead expenses that are attributable to maintaining the corporate existence of Services, franchise and other general taxes, and all other incidental overhead expenses including those auditing fees and accounting department expenses attributable to Services (Indirect Corporate Costs).

5. Services will establish annual budgets for controlling the expenses of each service department and those expenses outlined above in Section 2 (d), which are not department specific.

3. Employees in each department will maintain a record of the time they are employed in rendering service to each Client Company or group of Client Companies. The hourly rate for each employee will be determined each pay period.
4. a. The charge to a Client Company or a group of Client Companies for a particular service will be the sum of the figures derived by multiplying the hours reported by each employee in rendering such service by the hourly rate applicable to such employee and other direct allocated expenses.
2. Departmental Indirect Costs as defined in 2(c) (ii) will be loaded onto project codes in proportion to the direct salaries and wages charged to all project codes.
3. Departmental Support Service Costs as defined in 2(c)(iii) will be allocated to other internal Services departments and the Client Companies using consumption-based billing methods, with these costs then distributed by function. Any costs that remain at Services after this initial billing will be loaded onto project codes in proportion to the direct salaries and wages charged to all project codes.

5. Those expenses of Services that are not included in the expenses of a department under Section 2 above will be charged to Client Companies receiving service as follows:

1. Incremental out-of-pocket costs incurred for the direct benefit and convenience of a Client Company or a group of Client Companies will be charged directly to such company or group of companies.
2. The Indirect Corporate Costs of Services referred to above in Section 2(d)(ii) will be allocated among the Client Companies in the same proportion as the charges to the Client Companies, excluding Indirect Corporate Costs.
3. If the method of allocation of Departmental Indirect Costs (Section 4(b)), Departmental Support Service Costs (Section 4(c)), or Indirect Corporate Costs (Section 5(b)), would result in an inequity because of a change in operations or organization of the Client Companies, then Services may adjust the basis to effect an equitable distribution. Any such change in allocation shall be made only after first giving the Commission written notice of such proposed change not less than 60 days prior to the proposed effectiveness of any such change.

6. On the basis of the foregoing, monthly bills will be rendered to Client Company. Billing procedures and amounts will be open to audit by Client Company and by any regulatory authority having jurisdiction in respect of the Client Company.
7. When services are rendered to a group of Client Companies, costs of such service shall be allocated equitably among the Companies based on the nature and scope of the service rendered according to the formulae outlined in Exhibit II, Supplement.

ALLOCATION FORMULAE FOR
GROUPS OF CLIENT COMPANIES

Exhibit II, Supplement

Note: Each allocation formula will be based on data relevant to participating Client Companies to whom the services are provided.

ENERGY SALES

Based on total kilowatt-hours of energy sold to consumers.

Used primarily for the allocation of costs associated with the financial analyses of sales and related items.

CUSTOMERS

Based on a twelve-month average of residential, commercial, industrial, government, and municipal general business electric and gas customers.

Used primarily for the allocation of costs associated with the support of customer based services. Would include customer service and support, marketing, economic forecasts, environmental services, financial and regulatory analyses and customer information systems.

EMPLOYEES

Based on the number of full-time employees at period end.

Used primarily for the allocation of costs associated with the support of employee-based services. Would include administration of employee benefits programs, employee communications, employee training, and various facilities-based benefits and information technology desktop support.

RESPONSIBILITY RATIO

Based on the ratio of the company's load at time of system peak load. The peak load is the average of the twelve monthly highest clock-hour demands in kilowatts of the interconnected system occurring each month coincident with the system peak load.

Used primarily for the allocation of costs incurred in fossil plant support and integrated planning.

TRANSMISSION LINE MILES

Based on the number of miles of transmission lines, weighted for design voltage (Voltage < 400kv = 1; Voltage >=400kv =2).

Used primarily for the allocation of costs associated with project design, maintenance and installation of Entergy transmission lines.

SUBSTATIONS

Based on the number of high voltage substations weighted for Voltage (Voltage < 500kv = 1; Voltage >= 500kv = 2).

Used primarily for the allocation of related engineering and technical support for transmission and distribution substation operations and maintenance as well as for engineering and project management associated with substation construction.

COMPOSITE - TRANSMISSION LINES/SUBSTATIONS

Based on two components: Transmission Line Miles (30% weighting) and the Number of High Voltage Substations (70% weighting).

Used primarily for the allocation of the costs associated with the support of the transmission and distribution function that has both a transmission line component as well as a substation or load component.

GAS CONSUMPTION

Based on the volume of natural gas consumed annually by all gas fired generating units within the Entergy System.

Used for the allocation of costs associated with services in support of gas purchased for generation units.

LEVEL OF ESI SERVICE

Based on ESI total billings to each System company, excluding corporate overhead.

Used for the allocation of costs associated with support of ESI as a legal entity.

SYSTEM CAPACITY (NON-NUCLEAR)

Based on the power level, in kilowatts, that could be achieved if all non-nuclear generating units were operating at maximum capability simultaneously.

Used primarily for the allocation of costs associated with the support of the fossil operations of the System. This would include services provided by plant support, environmental and purchasing.

LABOR DOLLARS BILLED

Based on total labor dollars billed to each company.

Used primarily to allocate the costs associated with employee benefits plans, payroll taxes, departmental indirect costs and performance based compensation plans for ESI employees.

DISTRIBUTION LINE MILES

Based on the number of miles of distribution lines of 34.5kv or less.

Used primarily for the allocation of costs associated with project design, maintenance and installation of Entergy distribution lines.

COAL CONSUMPTION

Based on the quantity of tons of coal delivered for a twelve-month period to each coal plant within the Entergy System.

Used for the allocation of costs associated with services in support of coal purchased for coal generating units.

ACCOUNTS PAYABLE TRANSACTIONS

Based on a twelve-month number of accounts payable transactions processed.

Used for the allocation of costs associated with the support of the accounts payable function.

SQUARE FOOTAGE

Based on square footage occupied by ESI functional business units.

Used primarily to allocate the costs associated with facilities supervision and support.

INSURANCE PREMIUMS (NON-NUCLEAR)

Based on non-nuclear insurance premiums.

Used for the allocation of costs associated with risk management.

ASSET LOCATIONS

Based on the number of asset locations at period end.

Used for the allocation of costs associated with the fixed asset accounting function.

CAPITAL EXPENDITURE AUTHORIZATIONS (CEA)

Based on a twelve-month average of outstanding Capital Expenditure Authorizations and Storm Job Orders.

Used for the allocation of costs associated with the capital project costing accounting function.

TOTAL ASSETS

Based on total assets at period end.

Used primarily to allocate costs associated with the oversight and safeguarding of corporate assets. This would include services provided by financial management and certain finance functions, among others. Also used when the services provided are driven by the relative size and complexity of the System Companies and there is no functional relationship between the services and any other available allocation formula.

BANK ACCOUNTS

Based on the number of bank accounts at period end.

Used for the allocation of costs associated with daily cash management activities.

SERVER AND MAINFRAME USAGE COMPOSITE

Based on the use of historical expenditures.

Used primarily for the allocation of costs associated with mainframe, unix servers and related database administration.

GENERAL LEDGER TRANSACTIONS

Based on the number of general ledger transactions for the period.

Used primarily for the allocation of costs associated with general ledger activities, including related information systems, and for general accounting activities.

TRANSITION TO COMPETITION

Based on a twelve-month average of residential, commercial, industrial, government, and municipal general business of gas and/or electric customers.

Used primarily for the allocation of costs associated with the management support of the Entergy System's strategy for and transition to competition.

TELEPHONES

Based on the number of telephones within each Legal Entity at period end.

Used for the allocation of costs associated with maintenance and support of telephones.

FIBER

Based on capacity and use of the Entergy System's fiber optic network.

Used primarily for the allocation of fiber optic operations and maintenance expenses.

NUCLEAR UNITS

Based on the number of nuclear units managed and operated by each Entergy System Company.

Used primarily to allocate nuclear fuel-related services.

NUCLEAR SITES

Based on the number of nuclear sites managed and operated by each Entergy System Company.

Used to allocate miscellaneous nuclear-related services.

ACCOUNTS RECEIVABLE INVOICES

Based on a twelve-month number of accounts receivable transactions processed.

Used for the allocation of costs associated with the support of the accounts receivable function.

PAYCHECKS

Based on the number of paychecks issued at each Legal Entity at period end.

Used for the allocation of costs associated with the processing of payroll.

PROPERTY AND LIABILITY PAID LOSSES

Based on a five-year annual average of the property and liability losses paid by the system companies.

Used for the allocation of costs associated with the operation and maintenance of the Risk Information System.

COMPOSITE- SUPPLY CHAIN (Number of Transactions, Stockroom Count and Procurement Total Spending)

Based on three components with weighting to each: number of transactions, stockroom count, and procurement total spending.

Used for the allocation of costs associated with the management and operations of the materials management and work order processing system.

SUPPLY CHAIN - Inventory Management Fossil, Transmission & Distribution Issues, Transfers & Returns

Based on the number of issues, transfer & return transactions for each Legal Entity at period end.

Used for the allocation of costs associated with the management and operations of investment recovery, including Fossil, but excluding Nuclear.

SUPPLY CHAIN - Procurement Total Spending

Based on the dollar amount of procurement spending within each Legal Entity at period end.

Used for the allocation of costs associated with procurement activities for the Entergy System.

SUPPLY CHAIN - Labor Dollars

Based on the labor dollars for the Transformer, Meter, and Light Shops.

Used primarily for the allocation of costs associated with services provided by employees in the supply chain equipment refurbishment and repair department.

DISTRIBUTION SUBSTATIONS TRANSFORMERS

Based on the number of transformers at the Distribution Substations at period end.

Used primarily for the allocation of costs associated with the maintenance, administrative activities, and technical analysis of all Distribution Substations.

REMOTE ACCESS SERVICES (RAS) ID's

Based on the number of RAS ID's within each Legal Entity at period end.

Used for the allocation of costs associated with providing Remote Access Service to Entergy employees and contractors.

VEHICLES

Based on the number of vehicles owned by each Legal Entity.

Used for the allocation of costs associated with the maintenance of company vehicles.

MANAGED ACCOUNTS

Based on the number of industrial and commercial managed accounts excluding non-regulated Texas.

Used for the allocation of costs associated with the maintenance of Entergy's industrial and commercial customer accounts.

NUMBER OF CALLS - CUSTOMER SERVICE CENTERS

Based on a twenty-four month average of customer calls for each Legal Entity.

Used for the allocation of costs associated with the administration and support of Entergy's Customer Service Centers.

RADIO USAGE

Based on usage of Entergy's 2-way radio system.

Used for the allocation of costs associated with the administration and support of Entergy's 2-way radio system.

TOTAL IT SPEND

Based on the total dollars spent in the Information Technology plan.

Used for the allocation of costs associated with the administration and support of Entergy's IT business planning.

SUPPLY CHAIN MATERIALS TRANSACTIONS

Based on the number of Supply Chain materials transactions for each Legal Entity.

Used for the allocation of costs associated with the support of systems that manage Supply Chain materials.

AVERAGE NUMBER OF CAPITAL EXPENDITURE AUTHORIZATION PROJECTS FOR INFORMATION TECHNOLOGY, CUSTOMER SERVICE, DISTRIBUTION AND TRANSMISSION

Based on a twelve-month average of outstanding Capital Expenditure Authorizations for the Information Technology, Customer Service, Distribution and Transmission organizations.

Used for the allocation of costs associated with the prioritization of capital projects for the Information Technology, Customer Service, Distribution and Transmission organizations.

SECTION 263A TAX BENEFITS

Based on Section 263A tax benefits for each Legal Entity.

Used for the allocation of costs associated with tax administration, planning, and support related to Section 263A tax benefits.

EX-10

Exhibit 10(b)58

Amendment To

Service Agreement

The parties hereto do hereby stipulate and agree to that the SERVICE AGREEMENT entered into by and between them under date of July 16, 1974, and as heretofore amended on April 27, 1984, August 1, 1988 (effective January 1, 1989), January 1, 1991, January 1, 1992, January 1, 1996, January 1, 1998, January 1, 1999, January 1, 2000, January 1, 2001, April 1, 2002, January 1, 2003, August 1, 2003, and January 1, 2004 be and the same hereby is further amended by substituting for the Supplement to Exhibit II to the SERVICE AGREEMENT, the attached revised Supplement to Exhibit II. This Amendment is made and entered into as of March 1, 2004.

ENTERGY SERVICES, INC.

By/s/ Nathan E. Langston
     Nathan E. Langston
     Senior Vice President and Chief Accounting Officer

SYSTEM ENERGY RESOURCES, INC.

By/s/ Gary Taylor
     Gary Taylor
     President and CEO

ALLOCATION FORMULAE FOR
GROUPS OF CLIENT COMPANIES

Exhibit II, Supplement

Note: Each allocation formula will be based on data relevant to participating Client Companies to whom the services are provided.

ENERGY SALES

Based on total kilowatt-hours of energy sold to consumers.

Used primarily for the allocation of costs associated with the financial analyses of sales and related items.

CUSTOMERS

Based on a twelve-month average of residential, commercial, industrial, government, and municipal general business electric and gas customers.

Used primarily for the allocation of costs associated with the support of customer based services. Would include customer service and support, marketing, economic forecasts, environmental services, financial and regulatory analyses and customer information systems.

EMPLOYEES

Based on the number of full-time employees at period end.

Used primarily for the allocation of costs associated with the support of employee-based services. Would include administration of employee benefits programs, employee communications, employee training, and various facilities-based benefits and information technology desktop support.

RESPONSIBILITY RATIO

Based on the ratio of the company's load at time of system peak load. The peak load is the average of the twelve monthly highest clock-hour demands in kilowatts of the interconnected system occurring each month coincident with the system peak load.

Used primarily for the allocation of costs incurred in fossil plant support and integrated planning.

TRANSMISSION LINE MILES

Based on the number of miles of transmission lines, weighted for design voltage (Voltage < 400kv = 1; Voltage >=400kv =2).

Used primarily for the allocation of costs associated with project design, maintenance and installation of Entergy transmission lines.

SUBSTATIONS

Based on the number of high voltage substations weighted for Voltage (Voltage < 500kv = 1; Voltage >= 500kv = 2).

Used primarily for the allocation of related engineering and technical support for transmission and distribution substation operations and maintenance as well as for engineering and project management associated with substation construction.

COMPOSITE - TRANSMISSION LINES/SUBSTATIONS

Based on two components: Transmission Line Miles (30% weighting) and the Number of High Voltage Substations (70% weighting).

Used primarily for the allocation of the costs associated with the support of the transmission and distribution function that has both a transmission line component as well as a substation or load component.

GAS CONSUMPTION

Based on the volume of natural gas consumed annually by all gas fired generating units within the Entergy System.

Used for the allocation of costs associated with services in support of gas purchased for generation units.

LEVEL OF ESI SERVICE

Based on ESI total billings to each System company, excluding corporate overhead.

Used for the allocation of costs associated with support of ESI as a legal entity.

SYSTEM CAPACITY (NON-NUCLEAR)

Based on the power level, in kilowatts, that could be achieved if all non-nuclear generating units were operating at maximum capability simultaneously.

Used primarily for the allocation of costs associated with the support of the fossil operations of the System. This would include services provided by plant support, environmental and purchasing.

LABOR DOLLARS BILLED

Based on total labor dollars billed to each company.

Used primarily to allocate the costs associated with employee benefits plans, payroll taxes, departmental indirect costs and performance based compensation plans for ESI employees.

DISTRIBUTION LINE MILES

Based on the number of miles of distribution lines of 34.5kv or less.

Used primarily for the allocation of costs associated with project design, maintenance and installation of Entergy distribution lines.

COAL CONSUMPTION

Based on the quantity of tons of coal delivered for a twelve-month period to each coal plant within the Entergy System.

Used for the allocation of costs associated with services in support of coal purchased for coal generating units.

ACCOUNTS PAYABLE TRANSACTIONS

Based on a twelve-month number of accounts payable transactions processed.

Used for the allocation of costs associated with the support of the accounts payable function.

SQUARE FOOTAGE

Based on square footage occupied by ESI functional business units.

Used primarily to allocate the costs associated with facilities supervision and support.

INSURANCE PREMIUMS (NON-NUCLEAR)

Based on non-nuclear insurance premiums.

Used for the allocation of costs associated with risk management.

ASSET LOCATIONS

Based on the number of asset locations at period end.

Used for the allocation of costs associated with the fixed asset accounting function.

CAPITAL EXPENDITURE AUTHORIZATIONS

Based on a twelve-month average of outstanding Capital Expenditure Authorizations and Storm Job Orders.

Used for the allocation of costs associated with the capital project costing accounting function.

TOTAL ASSETS

Based on total assets at period end.

Used primarily to allocate costs associated with the oversight and safeguarding of corporate assets. This would include services provided by financial management and certain finance functions, among others. Also used when the services provided are driven by the relative size and complexity of the System Companies and there is no functional relationship between the services and any other available allocation formula.

BANK ACCOUNTS

Based on the number of bank accounts at period end.

Used for the allocation of costs associated with daily cash management activities.

SERVER AND MAINFRAME USAGE COMPOSITE

Based on the use of historical expenditures.

Used primarily for the allocation of costs associated with mainframe, unix servers and related database administration.

GENERAL LEDGER TRANSACTIONS

Based on the number of general ledger transactions for the period.

Used primarily for the allocation of costs associated with general ledger activities, including related information systems, and for general accounting activities.

TRANSITION TO COMPETITION

Based on a twelve-month average of residential, commercial, industrial, government, and municipal general business of gas and/or electric customers.

Used primarily for the allocation of costs associated with the management support of the Entergy System's strategy for and transition to competition.

TELEPHONES

Based on the number of telephones within each Legal Entity at period end.

Used for the allocation of costs associated with maintenance and support of telephones.

FIBER

Based on capacity and use of the Entergy System's fiber optic network.

Used primarily for the allocation of fiber optic operations and maintenance expenses.

NUCLEAR UNITS

Based on the number of nuclear units managed and operated by each Entergy System Company.

Used primarily to allocate nuclear fuel-related services.

NUCLEAR SITES

Based on the number of nuclear sites managed and operated by each Entergy System Company.

Used to allocate miscellaneous nuclear-related services.

ACCOUNTS RECEIVABLE INVOICES

Based on a twelve-month number of accounts receivable transactions processed.

Used for the allocation of costs associated with the support of the accounts receivable function.

PAYCHECKS

Based on the number of paychecks issued at each Legal Entity at period end.

Used for the allocation of costs associated with the processing of payroll.

PROPERTY AND LIABILITY PAID LOSSES

Based on a five-year annual average of the property and liability losses paid by the system companies.

Used for the allocation of costs associated with the operation and maintenance of the Risk Information System.

COMPOSITE - SUPPLY CHAIN (Number of Transactions, Stockroom Count and Procurement Total Spending)

Based on three components with weighting to each: number of transactions, stockroom count, and procurement total spending.

Used for the allocation of costs associated with the management and operations of the materials management and work order processing system.

SUPPLY CHAIN - Inventory Management Fossil, Transmission & Distribution Issues, Transfers & Returns

Based on the number of issues, transfer & return transactions for each Legal Entity at period end.

Used for the allocation of costs associated with the management and operations of investment recovery, including Fossil, but excluding Nuclear.

SUPPLY CHAIN - Procurement Total Spending

Based on the dollar amount of procurement spending within each Legal Entity at period end.

Used for the allocation of costs associated with procurement activities for the Entergy System.

SUPPLY CHAIN - Labor Dollars

Based on the labor dollars for the Transformer, Meter, and Light Shops.

Used primarily for the allocation of costs associated with services provided by employees in the supply chain equipment refurbishment and repair department.

DISTRIBUTION SUBSTATIONS TRANSFORMERS

Based on the number of transformers at the Distribution Substations at period end.

Used primarily for the allocation of costs associated with the maintenance, administrative activities, and technical analysis of all Distribution Substations.

REMOTE ACCESS SERVICES (RAS) ID's

Based on the number of RAS ID's within each Legal Entity at period end.

Used for the allocation of costs associated with providing Remote Access Service to Entergy employees and contractors.

VEHICLES

Based on the number of vehicles owned by each Legal Entity.

Used for the allocation of costs associated with the maintenance of company vehicles.

MANAGED ACCOUNTS

Based on the number of industrial and commercial managed accounts.

Used for the allocation of costs associated with the maintenance of Entergy's industrial and commercial customer accounts.

NUMBER OF CALLS - CUSTOMER SERVICE CENTERS

Based on a twenty-four month average of customer calls for each Legal Entity.

Used for the allocation of costs associated with the administration and support of Entergy's Customer Service Centers.

RADIO USAGE

Based on usage of Entergy's 2-way radio system.

Used for the allocation of costs associated with the administration and support of Entergy's 2-way radio system.

TOTAL IT SPEND

Based on the total dollars spent in the Information Technology plan.

Used for the allocation of costs associated with the administration and support of Entergy's IT business planning.

SUPPLY CHAIN MATERIALS TRANSACTIONS

Based on the number of Supply Chain materials transactions for each Legal Entity.

Used for the allocation of costs associated with the support of systems that manage Supply Chain materials.

AVERAGE NUMBER OF CAPITAL EXPENDITURE AUTHORIZATION PROJECTS FOR INFORMATION TECHNOLOGY, CUSTOMER SERVICE, DISTRIBUTION AND TRANSMISSION

Based on a twelve-month average of outstanding Capital Expenditure Authorizations for the Information Technology, Customer Service, Distribution and Transmission organizations.

Used for the allocation of costs associated with the prioritization of capital projects for the Information Technology, Customer Service, Distribution and Transmission organizations.

SECTION 263A TAX BENEFITS

Based on Section 263A tax benefits for each Legal Entity.

Used for the allocation of costs associated with tax administration, planning, and support related to Section 263A tax benefits.

OPEN WORKERS' COMPENSATION CLAIMS

Based on the number of open claims for each Legal Entity.

Used for the allocation of costs associated with managing workers' compensation claims processes and budgets.

UNIT POWER SALES AGREEMENT

Based on fixed allocation percentages under Entergy's Unit Power Sales Agreement.

Used primarily for the allocation of certain Tax Department services in connection with Entergy's Unit Power Sales Agreement.

RECORDS MANAGEMENT

Based on the number of employees at each Legal Entity using records management services.

Used to allocate costs associated with the management and supervision of non-nuclear business unit records management processes.

EX-10

Exhibit 10(b)62

AMENDMENT TO LETTER OF CREDIT AND REIMBURSEMENT AGREEMENT

As of December 22, 2003

To the Administrating Bank, the Funding
Bank and the Participating Banks party to the
Reimbursement Agreement referred to below

                    Re: System Energy Resources, Inc.

Ladies and Gentlemen:

            Reference is hereby made to that certain Letter of Credit and Reimbursement Agreement, dated as of December 22, 2003, as amended by the First Amendment and Consent to Letter of Credit and Reimbursement Agreement, dated as of May 3, 2004 (as so amended, the "Reimbursement Agreement"), among System Energy Resources, Inc. (the "Company"), Union Bank of California, N.A., as Administrating Bank and as Funding Bank, Banc One Capital Markets, Inc., as Documentation Agent, KeyBank National Association, as Syndication Agent, and the Participating Banks named therein. Terms used herein without definition shall have the meanings assigned in the Reimbursement Agreement.

            The Company desires to amend Section 3(b)(ii) of the Reimbursement Agreement in order to clarify that the Participation Fee should be calculated based on the Maximum Drawing Amount of each Letter of Credit rather than the Maximum Credit Amount thereof.

            By signing this letter where indicated below, the Company, the Administrating Bank, the Funding Bank and the Participating Banks agree to the following:

            SECTION 1.  Amendment to Reimbursement Agreement. Subject to the satisfaction of the conditions set forth in Section 2 hereof, Section 3(b)(ii) of the Reimbursement Agreement is hereby amended by deleting the phrase "Maximum Credit Amount" in its entirety and substituting therefor the new phrase "Maximum Drawing Amount".

            SECTION 2.  Effectiveness. This Amendment shall become effective as of the date hereof upon the receipt by the Administrating Bank of counterparts of this Amendment executed by the Company, the Participating Banks and the Funding Bank.

            SECTION 3.  Reference to and Effect on Reimbursement Agreement. (a) Upon the effectiveness of this Amendment, each reference in the Reimbursement Agreement to "this Reimbursement Agreement", "hereunder", "hereof", "herein" or words of like import referring to the Reimbursement Agreement shall mean and be a reference to the Reimbursement Agreement as amended hereby.

            (b) Except as specifically amended above, the Reimbursement Agreement remains in full force and effect and is hereby in all respects ratified and confirmed.

            SECTION 4. Execution in Counterparts. This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed and delivered shall be deemed to be an original and all of which taken together shall constitute but one and the same instrument. In furtherance of the foregoing, it is understood and agreed that signatures hereto submitted by facsimile transmission shall be deemed to be, and shall constitute, original signatures.

            SECTION 5. Governing Law. This Amendment shall be governed by and construed in accordance with the laws of the State of New York.

Very truly yours,

SYSTEM ENERGY RESOURCES, INC.

By                                                                  
     Name:
     Title:

Agreed to as of the 22^nd
day of December, 2003:

UNION BANK OF CALIFORNIA, N.A.,
as Administrating Bank, as Funding Bank
and as a Participating Bank

By                                                                  
     Name:
     Title:

BANK ONE, NA (MAIN OFFICE-
CHICAGO), as a Participating Bank

By                                                                  
     Name:
     Title:

KEYBANK NATIONAL
ASSOCIATION, as a Participating Bank

By                                                                  
     Name:
     Title:

BNP PARIBAS, as a Participating Bank

By                                                                  
     Name:
     Title:

MIZUHO CORPORATE BANK, LTD.,
as a Participating Bank

By                                                                  
     Name:
     Title:

WACHOVIA BANK, NATIONAL
ASSOCIATION, as a Participating Bank

By                                                                  
     Name:
     Title:

THE BANK OF NOVA SCOTIA,
as a Participating Bank

By                                                                  
     Name:
     Title:

UFJ BANK LIMITED, NEW YORK
BRANCH, as a Participating Bank

By                                                                  
     Name:
     Title:

BANK HAPOALIM B.M., as a
Participating Bank

By                                                                  
     Name:
     Title:

EX-10

Exhibit 10(b)63

FIRST AMENDMENT AND CONSENT TO LETTER OF CREDIT AND
REIMBURSEMENT AGREEMENT

            This FIRST AMENDMENT AND CONSENT, dated as of May 3, 2004 (this "Amendment"), is made by and among SYSTEM ENERGY RESOURCES, INC., an Arkansas corporation (the "Company"), and the banks listed on the signature pages of this Amendment as "Participating Banks" (such banks, together with their respective permitted assignees from time to time, being referred to herein, collectively, as the "Participating Banks").

PRELIMINARY STATEMENTS:

                1.     The Company, Union Bank of California, N.A., as Administrating Bank and as Funding Bank, Banc One Capital Markets, Inc., as Documentation Agent, KeyBank National Association, as Syndication Agent, and the Participating Banks previously entered into that certain Letter of Credit and Reimbursement Agreement, dated as of December 22, 2003 (the "Existing Agreement", and as amended by this Amendment, the "Amended Agreement", and as the Amended Agreement may hereafter be amended, supplemented or otherwise modified from time to time, the "Reimbursement Agreement").

                2.     The Company and the Required Banks now wish to amend the Existing Agreement in certain particulars. The Company and the Required Banks have agreed to such amendment, on the terms and conditions set forth herein. The parties hereto therefore agree as follows (capitalized terms used but not defined herein having the meanings assigned to such terms in the Existing Agreement):

            SECTION 1.  Amendment to Existing Agreement. Subject to the satisfaction of the conditions precedent set forth in Section 3 hereof, and effective as of the date hereof, Section 1(b) of the Existing Agreement is hereby amended by adding the following new sentence at the end thereof:

"In this Agreement, unless otherwise expressly provided herein, references to agreements (including this Agreement) and other contractual instruments shall be deemed to include all subsequent amendments, supplements and other modifications thereto, but only to the extent such amendments, supplements and other modifications are not prohibited by the terms of this Agreement or any other Transaction Document."

                SECTION 2.  Consent to Amendment to Letters of Credit. Subject to the satisfaction of the conditions precedent set forth in Section 3 hereof, the Company and the Required Banks hereby consent to, and authorize the Funding Bank to execute and deliver to the applicable Owner Participant, an amendment to each Letter of Credit in substantially the form of Exhibit A attached hereto.

                SECTION 3.  Conditions of Effectiveness. This Amendment shall become effective as of the date hereof upon the receipt by the Administrating Bank of counterparts of this Amendment executed by the Company and the Required Banks. This Amendment is subject to the provisions of Section 14 of the Existing Agreement.

                SECTION 4.  Representations and Warranties of the Company. The Company represents and warrants as follows:

                (a)     The execution and delivery of this Amendment, and the performance by the Company of this Amendment and the Amended Agreement, have been duly authorized by all necessary corporate action on its part and do not, and will not, require the consent or approval of its shareholders, or any trustee or holder of any Indebtedness or other obligation of it.

                (b)     The execution and delivery of this Amendment, and the performance by the Company of this Amendment and the Amended Agreement, do not conflict with, or result in a breach or contravention of any of the provisions of, its charter or by-laws or any Applicable Law, or any indenture, mortgage, lease or any other agreement or instrument to which it or any of its Affiliates is a party or by which its property or the property of any of its Affiliates is bound, or result in the creation or imposition of any Lien (other than Liens permitted under Section 12(e) of the Reimbursement Agreement) upon any of its property or the property of any of its Affiliates. This Amendment has been duly executed and delivered by the Company.   

                (c)     No Governmental Action is or will be required in connection with the execution, delivery or performance by the Company of this Amendment, except such Governmental Actions as have been duly obtained, given or accomplished.

                (d)     Each of this Amendment and the Amended Agreement is the legal, valid and binding obligation of the Company, enforceable against the Company in accordance with its terms, subject, however, to the application by a court of general principles of equity and to the effect of any applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditors' or lessors' rights generally.

                (e)     The representations and warranties contained in Section 10 of the Existing Agreement are true and correct in all material respects on and as of the date hereof, before and after giving effect to this Amendment, as though made on and as of such date.

                (f)     No event has occurred and is continuing, or would result from the execution and delivery of this Amendment, that constitutes an Event of Default, Reimbursement Default, Prepayment Event or Indenture Event of Default.

                SECTION 5.  Reference to and Effect on the Reimbursement Agreement. (a) Upon the effectiveness of this Amendment, each reference in the Existing Agreement to "this Agreement", "hereunder", "hereof", "herein" or words of like import referring to the Existing Agreement shall mean and be a reference to the Amended Agreement.

                (b)     Except as specifically amended above, the Existing Agreement shall continue to be in full force and effect and is hereby in all respects ratified and confirmed.

                (c)    The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of the Administrating Bank, the Funding Bank or the Participating Banks under the Existing Agreement or any other Transaction Document, nor constitute a waiver of any provision of the Existing Agreement or any other Transaction Document.

                SECTION 6.  Execution in Counterparts. This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed and delivered shall be deemed to be an original and all of which taken together shall constitute but one and the same instrument. In furtherance of the foregoing, it is understood and agreed that signatures hereto submitted by facsimile transmission shall be deemed to be, and shall constitute, original signatures.

                SECTION 7.  Governing Law. This Amendment shall be governed by, and construed in accordance with, the laws of the State of the New York.

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]

                    IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective officers thereunto duly authorized, as of the date first above written.

SYSTEM ENERGY RESOURCES , INC.

By                                                                  
     Name:
     Title:

Participating Banks

UNION BANK OF CALIFORNIA, N.A.

By                                                                  
     Name:
     Title:

BANK ONE, NA (MAIN OFFICE-CHICAGO)

By                                                                  
     Name:
     Title:

KEYBANK NATIONAL ASSOCIATION

By                                                                  
     Name:
     Title:

BNP PARIBAS

By                                                                  
     Name:
     Title:

By                                                                  
     Name:
     Title:

MIZUHO CORPORATE BANK, LTD.

By                                                                  
     Name:
     Title:

WACHOVIA BANK, NATIONAL ASSOCIATION

By                                                                  
     Name:
     Title:

THE BANK OF NOVA SCOTIA

By                                                                  
     Name:
     Title:

UFJ BANK LIMITED, NEW YORK BRANCH

By                                                                  
     Name:
     Title:

BANK HAPOALIM B.M.

By                                                                  
     Name:
     Title:

EXHIBIT A

FORM OF AMENDMENT TO LETTERS OF CREDIT

AMENDMENT NO. 1 TO IRREVOCABLE TRANSFERABLE

LETTER OF CREDIT NO.

May [__], 2004

[RCMC I, Inc.
1300 Market Street, Suite 400
Wilmington, Delaware 19801
Attn: Ms. Eileen A. Moran, President]
 

[Textron Financial Corporation
40 Westminster Street
Providence, Rhode Island 02940
Attn: General Counsel]

Ladies and Gentlemen:

At the request and on the instructions of our customer, System Energy Resources, Inc., an Arkansas corporation, we hereby amend our Irrevocable Transferable Letter of Credit No. [306S235347] [306S235348], dated December 22, 2003, established in your favor (the "Letter of Credit"), as follows:

1.     The third sentence of the first paragraph of the Letter of Credit is hereby amended in its entirety to read as follows:

"This Letter of Credit is issued in connection with the leasing of an undivided interest in Unit No. 1 of the Grand Gulf Nuclear Station to the Company pursuant to the Facility Lease."

2.     The following defined term is hereby added to Schedule I to the Letter of Credit in the appropriate alphabetical order:

"Casualty Value" has the meaning assigned to it in the Participation Agreement.

                This Amendment shall become effective upon your delivery to us of your written acceptance of this Amendment.

                Upon the effectiveness of this Amendment, each reference in the Letter of Credit to "this Letter of Credit", "hereof", "herein" or words of like import referring to the Letter of Credit shall mean and be a reference to the Letter of Credit as amended by this Amendment.

                All other terms and conditions set forth in the Letter of Credit remain unchanged. This letter forms an integral part of the Letter of Credit and is to be attached to the original Letter of Credit.

                This Amendment shall be governed by the Uniform Customs and Practice for Documentary Credits (revision effective January 1, 1994), International Chamber of Commerce Publication No. 500, and, as to matters not covered therein, be governed by the laws of the State of New York, including without limitation the Uniform Commercial Code as in effect in such State.

Very truly yours,

UNION BANK OF CALIFORNIA, N.A.

By                                                                  
     Name:
     Title:

The undersigned hereby consents
to the foregoing Amendment No. 1
as of the date first above written:
 

[RCMC I, INC.] [TEXTRON FINANCIAL CORPORATION]

By                                                                  
     Name:
     Title:

EX-10

Exhibit 10(c)9

Amendment To

Service Agreement

The parties hereto do hereby stipulate and agree to that the SERVICE AGREEMENT entered into by and between them under date of April 1, 1963, and as heretofore amended on January 1, 1972, April 27, 1984, August 1, 1988, January 28, 1991, January 1, 1992, January 1, 1996, January 1, 1998, January 1, 1999, January 1, 2000, January 1, 2001, April 1, 2002, January 1, 2003 and August 1, 2003 be and the same hereby is further amended by substituting for the Supplement to Exhibit II to the SERVICE AGREEMENT, the attached revised Supplement to Exhibit II. This Amendment is made and entered into as of March 1, 2004.

ENTERGY SERVICES, INC.

By /s/ Nathan E. Langston
     Nathan E. Langston
     Senior Vice President and Chief Accounting Officer

ENTERGY ARKANSAS, INC.

By /s/ Hugh T. McDonald
     Hugh T. McDonald
     President and CEO

ALLOCATION FORMULAE FOR
GROUPS OF CLIENT COMPANIES

Exhibit II, Supplement

Note: Each allocation formula will be based on data relevant to participating Client Companies to whom the services are provided.

ENERGY SALES

Based on total kilowatt-hours of energy sold to consumers.

Used primarily for the allocation of costs associated with the financial analyses of sales and related items.

CUSTOMERS

Based on a twelve-month average of residential, commercial, industrial, government, and municipal general business electric and gas customers.

Used primarily for the allocation of costs associated with the support of customer based services. Would include customer service and support, marketing, economic forecasts, environmental services, financial and regulatory analyses and customer information systems.

EMPLOYEES

Based on the number of full-time employees at period end.

Used primarily for the allocation of costs associated with the support of employee-based services. Would include administration of employee benefits programs, employee communications, employee training, and various facilities-based benefits and information technology desktop support.

RESPONSIBILITY RATIO

Based on the ratio of the company's load at time of system peak load. The peak load is the average of the twelve monthly highest clock-hour demands in kilowatts of the interconnected system occurring each month coincident with the system peak load.

Used primarily for the allocation of costs incurred in fossil plant support and integrated planning.

TRANSMISSION LINE MILES

Based on the number of miles of transmission lines, weighted for design voltage (Voltage < 400kv = 1; Voltage >=400kv =2).

Used primarily for the allocation of costs associated with project design, maintenance and installation of Entergy transmission lines.

SUBSTATIONS

Based on the number of high voltage substations weighted for Voltage (Voltage < 500kv = 1; Voltage >= 500kv = 2).

Used primarily for the allocation of related engineering and technical support for transmission and distribution substation operations and maintenance as well as for engineering and project management associated with substation construction.

COMPOSITE - TRANSMISSION LINES/SUBSTATIONS

Based on two components: Transmission Line Miles (30% weighting) and the Number of High Voltage Substations (70% weighting).

Used primarily for the allocation of the costs associated with the support of the transmission and distribution function that has both a transmission line component as well as a substation or load component.

GAS CONSUMPTION

Based on the volume of natural gas consumed annually by all gas fired generating units within the Entergy System.

Used for the allocation of costs associated with services in support of gas purchased for generation units.

LEVEL OF ESI SERVICE

Based on ESI total billings to each System company, excluding corporate overhead.

Used for the allocation of costs associated with support of ESI as a legal entity.

SYSTEM CAPACITY (NON-NUCLEAR)

Based on the power level, in kilowatts, that could be achieved if all non-nuclear generating units were operating at maximum capability simultaneously.

Used primarily for the allocation of costs associated with the support of the fossil operations of the System. This would include services provided by plant support, environmental and purchasing.

LABOR DOLLARS BILLED

Based on total labor dollars billed to each company.

Used primarily to allocate the costs associated with employee benefits plans, payroll taxes, departmental indirect costs and performance based compensation plans for ESI employees.

DISTRIBUTION LINE MILES

Based on the number of miles of distribution lines of 34.5kv or less.

Used primarily for the allocation of costs associated with project design, maintenance and installation of Entergy distribution lines.

COAL CONSUMPTION

Based on the quantity of tons of coal delivered for a twelve-month period to each coal plant within the Entergy System.

Used for the allocation of costs associated with services in support of coal purchased for coal generating units.

ACCOUNTS PAYABLE TRANSACTIONS

Based on a twelve-month number of accounts payable transactions processed.

Used for the allocation of costs associated with the support of the accounts payable function.

SQUARE FOOTAGE

Based on square footage occupied by ESI functional business units.

Used primarily to allocate the costs associated with facilities supervision and support.

INSURANCE PREMIUMS (NON-NUCLEAR)

Based on non-nuclear insurance premiums.

Used for the allocation of costs associated with risk management.

ASSET LOCATIONS

Based on the number of asset locations at period end.

Used for the allocation of costs associated with the fixed asset accounting function.

CAPITAL EXPENDITURE AUTHORIZATIONS

Based on a twelve-month average of outstanding Capital Expenditure Authorizations and Storm Job Orders.

Used for the allocation of costs associated with the capital project costing accounting function.

TOTAL ASSETS

Based on total assets at period end.

Used primarily to allocate costs associated with the oversight and safeguarding of corporate assets. This would include services provided by financial management and certain finance functions, among others. Also used when the services provided are driven by the relative size and complexity of the System Companies and there is no functional relationship between the services and any other available allocation formula.

BANK ACCOUNTS

Based on the number of bank accounts at period end.

Used for the allocation of costs associated with daily cash management activities.

SERVER AND MAINFRAME USAGE COMPOSITE

Based on the use of historical expenditures.

Used primarily for the allocation of costs associated with mainframe, unix servers and related database administration.

GENERAL LEDGER TRANSACTIONS

Based on the number of general ledger transactions for the period.

Used primarily for the allocation of costs associated with general ledger activities, including related information systems, and for general accounting activities.

TRANSITION TO COMPETITION

Based on a twelve-month average of residential, commercial, industrial, government, and municipal general business of gas and/or electric customers.

Used primarily for the allocation of costs associated with the management support of the Entergy System's strategy for and transition to competition.

TELEPHONES

Based on the number of telephones within each Legal Entity at period end.

Used for the allocation of costs associated with maintenance and support of telephones.

FIBER

Based on capacity and use of the Entergy System's fiber optic network.

Used primarily for the allocation of fiber optic operations and maintenance expenses.

NUCLEAR UNITS

Based on the number of nuclear units managed and operated by each Entergy System Company.

Used primarily to allocate nuclear fuel-related services.

NUCLEAR SITES

Based on the number of nuclear sites managed and operated by each Entergy System Company.

Used to allocate miscellaneous nuclear-related services.

ACCOUNTS RECEIVABLE INVOICES

Based on a twelve-month number of accounts receivable transactions processed.

Used for the allocation of costs associated with the support of the accounts receivable function.

PAYCHECKS

Based on the number of paychecks issued at each Legal Entity at period end.

Used for the allocation of costs associated with the processing of payroll.

PROPERTY AND LIABILITY PAID LOSSES

Based on a five-year annual average of the property and liability losses paid by the system companies.

Used for the allocation of costs associated with the operation and maintenance of the Risk Information System.

COMPOSITE- SUPPLY CHAIN (Number of Transactions, Stockroom Count and Procurement Total Spending)

Based on three components with weighting to each: number of transactions, stockroom count, and procurement total spending.

Used for the allocation of costs associated with the management and operations of the materials management and work order processing system.

SUPPLY CHAIN - Inventory Management Fossil, Transmission & Distribution Issues, Transfers & Returns

Based on the number of issues, transfer & return transactions for each Legal Entity at period end.

Used for the allocation of costs associated with the management and operations of investment recovery, including Fossil, but excluding Nuclear.

SUPPLY CHAIN - Procurement Total Spending

Based on the dollar amount of procurement spending within each Legal Entity at period end.

Used for the allocation of costs associated with procurement activities for the Entergy System.

SUPPLY CHAIN - Labor Dollars

Based on the labor dollars for the Transformer, Meter, and Light Shops.

Used primarily for the allocation of costs associated with services provided by employees in the supply chain equipment refurbishment and repair department.

DISTRIBUTION SUBSTATIONS TRANSFORMERS

Based on the number of transformers at the Distribution Substations at period end.

Used primarily for the allocation of costs associated with the maintenance, administrative activities, and technical analysis of all Distribution Substations.

REMOTE ACCESS SERVICES (RAS) ID's

Based on the number of RAS ID's within each Legal Entity at period end.

Used for the allocation of costs associated with providing Remote Access Service to Entergy employees and contractors.

VEHICLES

Based on the number of vehicles owned by each Legal Entity.

Used for the allocation of costs associated with the maintenance of company vehicles.

MANAGED ACCOUNTS

Based on the number of industrial and commercial managed accounts.

Used for the allocation of costs associated with the maintenance of Entergy's industrial and commercial customer accounts.

NUMBER OF CALLS - CUSTOMER SERVICE CENTERS

Based on a twenty-four month average of customer calls for each Legal Entity.

Used for the allocation of costs associated with the administration and support of Entergy's Customer Service Centers.

RADIO USAGE

Based on usage of Entergy's 2-way radio system.

Used for the allocation of costs associated with the administration and support of Entergy's 2-way radio system.

TOTAL IT SPEND

Based on the total dollars spent in the Information Technology plan.

Used for the allocation of costs associated with the administration and support of Entergy's IT business planning.

SUPPLY CHAIN MATERIALS TRANSACTIONS

Based on the number of Supply Chain materials transactions for each Legal Entity.

Used for the allocation of costs associated with the support of systems that manage Supply Chain materials.

AVERAGE NUMBER OF CAPITAL EXPENDITURE AUTHORIZATION PROJECTS FOR INFORMATION TECHNOLOGY, CUSTOMER SERVICE, DISTRIBUTION AND TRANSMISSION

Based on a twelve-month average of outstanding Capital Expenditure Authorizations for the Information Technology, Customer Service, Distribution and Transmission organizations.

Used for the allocation of costs associated with the prioritization of capital projects for the Information Technology, Customer Service, Distribution and Transmission organizations.

SECTION 263A TAX BENEFITS

Based on Section 263A tax benefits for each Legal Entity.

Used for the allocation of costs associated with tax administration, planning, and support related to Section 263A tax benefits.

OPEN WORKERS' COMPENSATION CLAIMS

Based on the number of open claims for each Legal Entity.

Used for the allocation of costs associated with managing workers' compensation claims processes and budgets.

UNIT POWER SALES AGREEMENT

Based on fixed allocation percentages under Entergy's Unit Power Sales Agreement.

Used primarily for the allocation of certain Tax Department services in connection with Entergy's Unit Power Sales Agreement.

RECORDS MANAGEMENT

Based on the number of employees at each Legal Entity using records management services.

Used to allocate costs associated with the management and supervision of non-nuclear business unit records management processes.

EX-10

Exhibit 10(d)23

Third Amendment To

Decommissioning Trust Agreement

This THIRD AMENDMENT TO DECOMMISSIONING TRUST AGREEMENT ("Third Amendment") made effective as of the 5th day of March, 1998 by and between Entergy Gulf States, Inc. (the "Company"), and Mellon Bank, N.A. (the "Successor Trustee").

WHEREAS, on March IS, 1989, the Company and Morgan Guaranty Trust Company of New York (the "Trustee") entered into a Decommissioning Trust Agreement (the "Trust Agreement"), which provided for the establishment and maintenance of a nuclear decommissioning reserve fund (the "Trust Fund") to hold and invest revenues collected by the company for the decommissioning of Unit No.1 of the River Bend Steam Electric Generating Station; and

WHEREAS, as of April 8, 1992, in connection with the promulgation of certain rules by the Public Utility Commission of Texas applicable to the investment or reinvestment of funds held under the Trust Agreement, the Company and the Trustee entered into Amendment No.1 to Decommissioning Trust Agreement (the "First Amendment") adding Section 2.11, "Additional Regulatory Requirements," to the Trust Agreement; and

WHEREAS, as of November 1, 1995, in connection with the appointment of Mellon Bank, N.A. as Successor Trustee, the Company and the Successor Trustee entered into the Second Amendment to Decommissioning Trust Agreement (the "Second Amendment"); and

WHEREAS, Section 2.08 of the Trust Agreement authorizes the Company with the consent of the Trustee to make amendments to the Trust Agreement from time to time to effectuate the purposes of the Trust Agreement and to comply with any order or requirement of a regulatory authority having jurisdiction over the Company's nuclear decommissioning reserve funds; and

WHEREAS, the Public Utility Commission of Texas has promulgated certain additional rules which, among other things, require that the Trust Agreement be further amended to expressly provide that the Trust Agreement will comply with all applicable requirements of the Nuclear Regulatory Commission.

NOW THEREFORE, the Company and Successor Trustee agree as follows:

1. Section 2.11 of the Trust Agreement, as heretofore amended by the First Amendment and the Second Amendment, is further amended and restated, as of the Effective Date, to read in its entirety as follows:

2.11 Additional Regulatory Requirements. (a) If and to the extent the Trustee or an Investment Manager is responsible for investment of assets comprising a part of this Trust, then the Trustee or the Investment Manager, as appropriate, shall have a continuing duty to review the portfolio of investments of those assets for compliance with the terms of this Agreement and the written investment guidelines furnished to the Trustee or the Investment Manager by the Company.

(b) The Trustee shall not lend funds from the Trust to itself, its officers or directors.

(c) Neither the Trustee nor any Investment Manager shall invest or reinvest funds held under the Trust in instruments issued by the Trustee or the Investment Manager, respectively, except for time deposits, demand deposits or money market accounts of the Trustee or the Investment Manager, as appropriate, and then only if permitted by written investment guidelines furnished by the Company.

(d) The assets held under this Trust shall be invested with a goal of earning a reasonable return commensurate with the need to preserve the value of the assets of the Trust. Subject to the provision of the Internal Revenue Code of 1986, as amended, regarding Qualified Subaccounts, the Company agrees to provide the Trustee and any Investment Manager with written investment guidelines directing the Trustee and any Investment Manager to invest the assets of the Trust in accordance with the governing regulations promulgated from time to time by any applicable regulatory authority.

(e) The Agreement shall comply with all applicable requirements of the Nuclear Regulatory Commission.

2. Except as otherwise expressly modified herein, the Trust Agreement, as previously amended, shall remain in full force and effect.

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective duly authorized officers as of the day and year first above written.

ENTERGY GULF STATES, INC.

By: /s/ S. G. Cunningham
Title: Vice President - Entergy Gulf States, Inc.
Date: February 26, 1998

MELLON BANK, N.A.

By: /s/ Richard J. Thomas
Title:  First Vice President
Date: March 2, 1998

STATE OF LOUISIANA

PARISH OF ORLEANS

Personally came and appeared before me, the undersigned authority, in and for the jurisdiction aforesaid, Shelton G. Cunningham, Jr., who acknowledged to me that he is Vice President of Entergy Gulf States, Inc., and that he signed and delivered the foregoing instrument on the day and year therein mentioned as the act and deed of said corporation, having been duly authorized to do so.

Given under my hand and seal of office on this the 26th day of February, 1998.

________________________________
NOTARY PUBLIC

My Commission is issued for life.

COMMONWEALTH OF PENNSYLVANIA

COUNTY OF ALLEGHENY

Personally came and appeared before me, the undersigned authority, in and for the jurisdiction aforesaid, Richard J. Thomas, who acknowledged to me that he is First Vice President of Mellon Bank, N.A. and that he signed and delivered the foregoing instrument on the day and year therein mentioned as the act and deed of said corporation, having been duly authorized to do so.

Given under my hand and seal of office on this the 2^nd day of March, 1998.

/s/ Denise A. Fuhrer
NOTARY PUBLIC

My Commission Expires: December 3, 1998

EX-10

Exhibit 10(d)24

FOURTH AMENDMENT TO

DECOMMISSIONING TRUST FUND AGREEMENT

This Fourth Amendment to Decommissioning Trust Agreement ("Fourth Amendment") made effective as of the 17^th day of December, 2003, by and between Entergy Gulf States, Inc. (the "Company") and Mellon Bank, N.A. (the "Successor Trustee").

WHEREAS, on March 15, 1989, the Company and Morgan Guaranty Trust Company of New York (the "Trustee") entered into a Decommissioning Trust Agreement (the "Trust Agreement"), which provided for the establishment and maintenance of a nuclear decommissioning reserve fund (the "Trust Fund") to hold and invest revenues collected by the Company for the decommissioning of Unit No. 1 of the River Bend Steam Electric Generating Station; and

WHEREAS, as of April 8, 1992, in connection with the promulgation of certain rules by the Public Utility Commission of Texas applicable to the investment or reinvestment of funds held under the Trust Agreement, the Company and Trustee entered into Amendment No. 1 to Decommissioning Trust Agreement (the "First Amendment"), adding Section 2.11, "Additional Regulatory Requirements," to the Trust Agreement; and

WHEREAS, as of November 1, 1995, in connection with the appointment of Mellon Bank, N.A. as Successor Trustee, the Company and the Successor Trustee entered into the Second Amendment to Decommissioning Trust Agreement (the "Second Amendment); and

WHEREAS, effective as of March 5, 1998, in connection with the promulgation of certain rules by the Public Utility Commission of Texas, the Company and the Successor Trustee entered in the Third Amendment to Decommissioning Trust Agreement ("Third Amendment"); and

WHEREAS, Section 2.08 of the Trust Agreement authorizes the Company with the consent of the Trustee to make amendments to the Trust Agreement from time to time to effectuate the purposes of the Trust Agreement and to comply with any order or requirement of a regulatory authority having jurisdiction over the Company's nuclear decommissioning reserve funds; and

WHEREAS, the Company and the Successor Trustee wish to amend the Agreement in order to comply with certain changes in applicable regulations of the Nuclear Regulatory Commission ("NRC"); and

WHEREAS, the parties hereby each warrant and represent to the other that it has full authority to enter into this Fourth Amendment upon the terms and conditions hereof and that the individual executing this Fourth Amendment on its behalf has the requisite authority to bind the parties to the Agreement.

NOW, THEREFORE, the Company and the Successor Trustee agree as follows:

1. The representations set forth above are incorporated herein by this reference thereto.
2. The following Section 4.06 shall be added:

Notice Regarding Disbursements or Payments. Notwithstanding anything to the contrary in this Agreement, except for (i) payments of ordinary administrative costs (including taxes) and other incidental expenses of the Trust Fund (including legal, accounting, actuarial, and Successor Trustee expenses) in connection with the operation of the Trust Fund, (ii) withdrawals being made under 10 CFR 50.82(a)(8), and (iii) transfers between Qualified and Nonqualified Funds in accordance with the provisions of this Agreement, no disbursement or payment may be made from the Trust Fund until written notice of the intention to make a disbursement or payment has been given to the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, at least 30 working days before the date of the intended disbursement or payment. The disbursement or payment from the Trust Fund, if it is otherwise in compliance with the terms and conditions of this Agree ment, may be made following the 30-working day notice period if no written notice of objection from the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, is received by the Successor Trustee or the Company within the notice period. The required notice may be made by the Successor Trustee or on the Successor Trustee's behalf. This Section 4.05 is intended to qualify each and every provision of this Trust Agreement allowing distributions from the Trust Fund, and in the event of any conflict between any such provision and this Section, this Section shall control.

IN WITNESS WHEREOF, the parties hereto have caused this Fourth Amendment to be duly executed by their respective authorized officers as of the effective date indicated on the first page hereof.

Authorized Signer of:                                                             Authorized Officer of:

MELLON BANK, N.A.                                                         ENTERGY GULF STATES, INC.

By: /s/ Joyce L. Root                                                             By: /s/ Steven C. McNeal
Name: Joyce L. Root                                                            Name: Steven C. McNeal
Title: Vice President                                                             Title: V P and Treasurer
Date:  December 17, 2003                                                    Date:  December 15, 2003

EX-10

Exhibit 10(d)33

Amendment To

Service Agreement

The parties hereto do hereby stipulate and agree to that the SERVICE AGREEMENT entered into by and between them under date of December 31, 1993, and as heretofore amended on January 1, 1996, January 1, 1998, January 1, 1999, January 1, 2000, January 1, 2001, April 1, 2002, January 1, 2003 and August 1, 2003 be and the same hereby is further amended by substituting for the Supplement to Exhibit II to the SERVICE AGREEMENT, the attached revised Supplement to Exhibit II. This Amendment is made and entered into as of March 1, 2004.

ENTERGY SERVICES, INC.

By /s/ Nathan E. Langston
     Nathan E. Langston
     Senior Vice President and Chief Accounting Officer

ENTERGY GULF STATES, INC.

By /s/ Joseph F. Domino
    Joseph F. Domino
    President and CEO - Texas

Amendment To

Service Agreement

The parties hereto do hereby stipulate and agree to that the SERVICE AGREEMENT entered into by and between them under date of December 31, 1993, and as heretofore amended on January 1, 1996, January 1, 1998, January 1, 1999, January 1, 2000, January 1, 2001, April 1, 2002, January 1, 2003 and August 1, 2003 be and the same hereby is further amended by substituting for the Supplement to Exhibit II to the SERVICE AGREEMENT, the attached revised Supplement to Exhibit II. This Amendment is made and entered into as of March 1, 2004.

ENTERGY SERVICES, INC.

By /s/ Nathan E. Langston
     Nathan E. Langston
     Senior Vice President and Chief Accounting Officer

ENTERGY GULF STATES, INC.

By /s/ Renae Conley
    Renae Conley
    President and CEO - Louisiana

ALLOCATION FORMULAE FOR
GROUPS OF CLIENT COMPANIES

Exhibit II, Supplement

Note: Each allocation formula will be based on data relevant to participating Client Companies to whom the services are provided.

ENERGY SALES

Based on total kilowatt-hours of energy sold to consumers.

Used primarily for the allocation of costs associated with the financial analyses of sales and related items.

CUSTOMERS

Based on a twelve-month average of residential, commercial, industrial, government, and municipal general business electric and gas customers.

Used primarily for the allocation of costs associated with the support of customer based services. Would include customer service and support, marketing, economic forecasts, environmental services, financial and regulatory analyses and customer information systems.

EMPLOYEES

Based on the number of full-time employees at period end.

Used primarily for the allocation of costs associated with the support of employee-based services. Would include administration of employee benefits programs, employee communications, employee training, and various facilities-based benefits and information technology desktop support.

RESPONSIBILITY RATIO

Based on the ratio of the company's load at time of system peak load. The peak load is the average of the twelve monthly highest clock-hour demands in kilowatts of the interconnected system occurring each month coincident with the system peak load.

Used primarily for the allocation of costs incurred in fossil plant support and integrated planning.

TRANSMISSION LINE MILES

Based on the number of miles of transmission lines, weighted for design voltage (Voltage < 400kv = 1; Voltage >=400kv =2).

Used primarily for the allocation of costs associated with project design, maintenance and installation of Entergy transmission lines.

SUBSTATIONS

Based on the number of high voltage substations weighted for Voltage (Voltage < 500kv = 1; Voltage >= 500kv = 2).

Used primarily for the allocation of related engineering and technical support for transmission and distribution substation operations and maintenance as well as for engineering and project management associated with substation construction.

COMPOSITE - TRANSMISSION LINES/SUBSTATIONS

Based on two components: Transmission Line Miles (30% weighting) and the Number of High Voltage Substations (70% weighting).

Used primarily for the allocation of the costs associated with the support of the transmission and distribution function that has both a transmission line component as well as a substation or load component.

GAS CONSUMPTION

Based on the volume of natural gas consumed annually by all gas fired generating units within the Entergy System.

Used for the allocation of costs associated with services in support of gas purchased for generation units.

LEVEL OF ESI SERVICE

Based on ESI total billings to each System company, excluding corporate overhead.

Used for the allocation of costs associated with support of ESI as a legal entity.

SYSTEM CAPACITY (NON-NUCLEAR)

Based on the power level, in kilowatts, that could be achieved if all non-nuclear generating units were operating at maximum capability simultaneously.

Used primarily for the allocation of costs associated with the support of the fossil operations of the System. This would include services provided by plant support, environmental and purchasing.

LABOR DOLLARS BILLED

Based on total labor dollars billed to each company.

Used primarily to allocate the costs associated with employee benefits plans, payroll taxes, departmental indirect costs and performance based compensation plans for ESI employees.

DISTRIBUTION LINE MILES

Based on the number of miles of distribution lines of 34.5kv or less.

Used primarily for the allocation of costs associated with project design, maintenance and installation of Entergy distribution lines.

COAL CONSUMPTION

Based on the quantity of tons of coal delivered for a twelve-month period to each coal plant within the Entergy System.

Used for the allocation of costs associated with services in support of coal purchased for coal generating units.

ACCOUNTS PAYABLE TRANSACTIONS

Based on a twelve-month number of accounts payable transactions processed.

Used for the allocation of costs associated with the support of the accounts payable function.

SQUARE FOOTAGE

Based on square footage occupied by ESI functional business units.

Used primarily to allocate the costs associated with facilities supervision and support.

INSURANCE PREMIUMS (NON-NUCLEAR)

Based on non-nuclear insurance premiums.

Used for the allocation of costs associated with risk management.

ASSET LOCATIONS

Based on the number of asset locations at period end.

Used for the allocation of costs associated with the fixed asset accounting function.

CAPITAL EXPENDITURE AUTHORIZATIONS

Based on a twelve-month average of outstanding Capital Expenditure Authorizations and Storm Job Orders.

Used for the allocation of costs associated with the capital project costing accounting function.

TOTAL ASSETS

Based on total assets at period end.

Used primarily to allocate costs associated with the oversight and safeguarding of corporate assets. This would include services provided by financial management and certain finance functions, among others. Also used when the services provided are driven by the relative size and complexity of the System Companies and there is no functional relationship between the services and any other available allocation formula.

BANK ACCOUNTS

Based on the number of bank accounts at period end.

Used for the allocation of costs associated with daily cash management activities.

SERVER AND MAINFRAME USAGE COMPOSITE

Based on the use of historical expenditures.

Used primarily for the allocation of costs associated with mainframe, unix servers and related database administration.

GENERAL LEDGER TRANSACTIONS

Based on the number of general ledger transactions for the period.

Used primarily for the allocation of costs associated with general ledger activities, including related information systems, and for general accounting activities.

TRANSITION TO COMPETITION

Based on a twelve-month average of residential, commercial, industrial, government, and municipal general business of gas and/or electric customers.

Used primarily for the allocation of costs associated with the management support of the Entergy System's strategy for and transition to competition.

TELEPHONES

Based on the number of telephones within each Legal Entity at period end.

Used for the allocation of costs associated with maintenance and support of telephones.

FIBER

Based on capacity and use of the Entergy System's fiber optic network.

Used primarily for the allocation of fiber optic operations and maintenance expenses.

NUCLEAR UNITS

Based on the number of nuclear units managed and operated by each Entergy System Company.

Used primarily to allocate nuclear fuel-related services.

NUCLEAR SITES

Based on the number of nuclear sites managed and operated by each Entergy System Company.

Used to allocate miscellaneous nuclear-related services.

ACCOUNTS RECEIVABLE INVOICES

Based on a twelve-month number of accounts receivable transactions processed.

Used for the allocation of costs associated with the support of the accounts receivable function.

PAYCHECKS

Based on the number of paychecks issued at each Legal Entity at period end.

Used for the allocation of costs associated with the processing of payroll.

PROPERTY AND LIABILITY PAID LOSSES

Based on a five-year annual average of the property and liability losses paid by the system companies.

Used for the allocation of costs associated with the operation and maintenance of the Risk Information System.

COMPOSITE- SUPPLY CHAIN (Number of Transactions, Stockroom Count and Procurement Total Spending)

Based on three components with weighting to each: number of transactions, stockroom count, and procurement total spending.

Used for the allocation of costs associated with the management and operations of the materials management and work order processing system.

SUPPLY CHAIN - Inventory Management Fossil, Transmission & Distribution Issues, Transfers & Returns

Based on the number of issues, transfer & return transactions for each Legal Entity at period end.

Used for the allocation of costs associated with the management and operations of investment recovery, including Fossil, but excluding Nuclear.

SUPPLY CHAIN - Procurement Total Spending

Based on the dollar amount of procurement spending within each Legal Entity at period end.

Used for the allocation of costs associated with procurement activities for the Entergy System.

SUPPLY CHAIN - Labor Dollars

Based on the labor dollars for the Transformer, Meter, and Light Shops.

Used primarily for the allocation of costs associated with services provided by employees in the supply chain equipment refurbishment and repair department.

DISTRIBUTION SUBSTATIONS TRANSFORMERS

Based on the number of transformers at the Distribution Substations at period end.

Used primarily for the allocation of costs associated with the maintenance, administrative activities, and technical analysis of all Distribution Substations.

REMOTE ACCESS SERVICES (RAS) ID's

Based on the number of RAS ID's within each Legal Entity at period end.

Used for the allocation of costs associated with providing Remote Access Service to Entergy employees and contractors.

VEHICLES

Based on the number of vehicles owned by each Legal Entity.

Used for the allocation of costs associated with the maintenance of company vehicles.

MANAGED ACCOUNTS

Based on the number of industrial and commercial managed accounts.

Used for the allocation of costs associated with the maintenance of Entergy's industrial and commercial customer accounts.

NUMBER OF CALLS - CUSTOMER SERVICE CENTERS

Based on a twenty-four month average of customer calls for each Legal Entity.

Used for the allocation of costs associated with the administration and support of Entergy's Customer Service Centers.

RADIO USAGE

Based on usage of Entergy's 2-way radio system.

Used for the allocation of costs associated with the administration and support of Entergy's 2-way radio system.

TOTAL IT SPEND

Based on the total dollars spent in the Information Technology plan.

Used for the allocation of costs associated with the administration and support of Entergy's IT business planning.

SUPPLY CHAIN MATERIALS TRANSACTIONS

Based on the number of Supply Chain materials transactions for each Legal Entity.

Used for the allocation of costs associated with the support of systems that manage Supply Chain materials.

AVERAGE NUMBER OF CAPITAL EXPENDITURE AUTHORIZATION PROJECTS FOR INFORMATION TECHNOLOGY, CUSTOMER SERVICE, DISTRIBUTION AND TRANSMISSION

Based on a twelve-month average of outstanding Capital Expenditure Authorizations for the Information Technology, Customer Service, Distribution and Transmission organizations.

Used for the allocation of costs associated with the prioritization of capital projects for the Information Technology, Customer Service, Distribution and Transmission organizations.

SECTION 263A TAX BENEFITS

Based on Section 263A tax benefits for each Legal Entity.

Used for the allocation of costs associated with tax administration, planning, and support related to Section 263A tax benefits.

OPEN WORKERS' COMPENSATION CLAIMS

Based on the number of open claims for each Legal Entity.

Used for the allocation of costs associated with managing workers' compensation claims processes and budgets.

UNIT POWER SALES AGREEMENT

Based on fixed allocation percentages under Entergy's Unit Power Sales Agreement.

Used primarily for the allocation of certain Tax Department services in connection with Entergy's Unit Power Sales Agreement.

RECORDS MANAGEMENT

Based on the number of employees at each Legal Entity using records management services.

Used to allocate costs associated with the management and supervision of non-nuclear business unit records management processes.

EX-10

Exhibit 10(e)9

Amendment To

Service Agreement

The parties hereto do hereby stipulate and agree to that the SERVICE AGREEMENT entered into by and between them under date of April 1, 1963, and as heretofore amended on January 1, 1972, April 27, 1984, August 1, 1988, January 28, 1991, January 1, 1992, January 1, 1996, January 1, 1998, January 1, 1999, January 1, 2000, January 1, 2001, April 1, 2002, January 1, 2003 and August 1, 2003 be and the same hereby is further amended by substituting for the Supplement to Exhibit II to the SERVICE AGREEMENT, the attached revised Supplement to Exhibit II. This Amendment is made and entered into as of March 1, 2004.

ENTERGY SERVICES, INC.

By /s/ Nathan E. Langston
     Nathan E. Langston
     Senior Vice President and Chief Accounting Officer

ENTERGY LOUISIANA, INC.

By /s/ Renae Conley
     Renae Conley
     President and CEO

ALLOCATION FORMULAE FOR
GROUPS OF CLIENT COMPANIES

Exhibit II, Supplement

Note: Each allocation formula will be based on data relevant to participating Client Companies to whom the services are provided.

ENERGY SALES

Based on total kilowatt-hours of energy sold to consumers.

Used primarily for the allocation of costs associated with the financial analyses of sales and related items.

CUSTOMERS

Based on a twelve-month average of residential, commercial, industrial, government, and municipal general business electric and gas customers.

Used primarily for the allocation of costs associated with the support of customer based services. Would include customer service and support, marketing, economic forecasts, environmental services, financial and regulatory analyses and customer information systems.

EMPLOYEES

Based on the number of full-time employees at period end.

Used primarily for the allocation of costs associated with the support of employee-based services. Would include administration of employee benefits programs, employee communications, employee training, and various facilities-based benefits and information technology desktop support.

RESPONSIBILITY RATIO

Based on the ratio of the company's load at time of system peak load. The peak load is the average of the twelve monthly highest clock-hour demands in kilowatts of the interconnected system occurring each month coincident with the system peak load.

Used primarily for the allocation of costs incurred in fossil plant support and integrated planning.

TRANSMISSION LINE MILES

Based on the number of miles of transmission lines, weighted for design voltage (Voltage < 400kv = 1; Voltage >=400kv =2).

Used primarily for the allocation of costs associated with project design, maintenance and installation of Entergy transmission lines.

SUBSTATIONS

Based on the number of high voltage substations weighted for Voltage (Voltage < 500kv = 1; Voltage >= 500kv = 2).

Used primarily for the allocation of related engineering and technical support for transmission and distribution substation operations and maintenance as well as for engineering and project management associated with substation construction.

COMPOSITE - TRANSMISSION LINES/SUBSTATIONS

Based on two components: Transmission Line Miles (30% weighting) and the Number of High Voltage Substations (70% weighting).

Used primarily for the allocation of the costs associated with the support of the transmission and distribution function that has both a transmission line component as well as a substation or load component.

GAS CONSUMPTION

Based on the volume of natural gas consumed annually by all gas fired generating units within the Entergy System.

Used for the allocation of costs associated with services in support of gas purchased for generation units.

LEVEL OF ESI SERVICE

Based on ESI total billings to each System company, excluding corporate overhead.

Used for the allocation of costs associated with support of ESI as a legal entity.

SYSTEM CAPACITY (NON-NUCLEAR)

Based on the power level, in kilowatts, that could be achieved if all non-nuclear generating units were operating at maximum capability simultaneously.

Used primarily for the allocation of costs associated with the support of the fossil operations of the System. This would include services provided by plant support, environmental and purchasing.

LABOR DOLLARS BILLED

Based on total labor dollars billed to each company.

Used primarily to allocate the costs associated with employee benefits plans, payroll taxes, departmental indirect costs and performance based compensation plans for ESI employees.

DISTRIBUTION LINE MILES

Based on the number of miles of distribution lines of 34.5kv or less.

Used primarily for the allocation of costs associated with project design, maintenance and installation of Entergy distribution lines.

COAL CONSUMPTION

Based on the quantity of tons of coal delivered for a twelve-month period to each coal plant within the Entergy System.

Used for the allocation of costs associated with services in support of coal purchased for coal generating units.

ACCOUNTS PAYABLE TRANSACTIONS

Based on a twelve-month number of accounts payable transactions processed.

Used for the allocation of costs associated with the support of the accounts payable function.

SQUARE FOOTAGE

Based on square footage occupied by ESI functional business units.

Used primarily to allocate the costs associated with facilities supervision and support.

INSURANCE PREMIUMS (NON-NUCLEAR)

Based on non-nuclear insurance premiums.

Used for the allocation of costs associated with risk management.

ASSET LOCATIONS

Based on the number of asset locations at period end.

Used for the allocation of costs associated with the fixed asset accounting function.

CAPITAL EXPENDITURE AUTHORIZATIONS

Based on a twelve-month average of outstanding Capital Expenditure Authorizations and Storm Job Orders.

Used for the allocation of costs associated with the capital project costing accounting function.

TOTAL ASSETS

Based on total assets at period end.

Used primarily to allocate costs associated with the oversight and safeguarding of corporate assets. This would include services provided by financial management and certain finance functions, among others. Also used when the services provided are driven by the relative size and complexity of the System Companies and there is no functional relationship between the services and any other available allocation formula.

BANK ACCOUNTS

Based on the number of bank accounts at period end.

Used for the allocation of costs associated with daily cash management activities.

SERVER AND MAINFRAME USAGE COMPOSITE

Based on the use of historical expenditures.

Used primarily for the allocation of costs associated with mainframe, unix servers and related database administration.

GENERAL LEDGER TRANSACTIONS

Based on the number of general ledger transactions for the period.

Used primarily for the allocation of costs associated with general ledger activities, including related information systems, and for general accounting activities.

TRANSITION TO COMPETITION

Based on a twelve-month average of residential, commercial, industrial, government, and municipal general business of gas and/or electric customers.

Used primarily for the allocation of costs associated with the management support of the Entergy System's strategy for and transition to competition.

TELEPHONES

Based on the number of telephones within each Legal Entity at period end.

Used for the allocation of costs associated with maintenance and support of telephones.

FIBER

Based on capacity and use of the Entergy System's fiber optic network.

Used primarily for the allocation of fiber optic operations and maintenance expenses.

NUCLEAR UNITS

Based on the number of nuclear units managed and operated by each Entergy System Company.

Used primarily to allocate nuclear fuel-related services.

NUCLEAR SITES

Based on the number of nuclear sites managed and operated by each Entergy System Company.

Used to allocate miscellaneous nuclear-related services.

ACCOUNTS RECEIVABLE INVOICES

Based on a twelve-month number of accounts receivable transactions processed.

Used for the allocation of costs associated with the support of the accounts receivable function.

PAYCHECKS

Based on the number of paychecks issued at each Legal Entity at period end.

Used for the allocation of costs associated with the processing of payroll.

PROPERTY AND LIABILITY PAID LOSSES

Based on a five-year annual average of the property and liability losses paid by the system companies.

Used for the allocation of costs associated with the operation and maintenance of the Risk Information System.

COMPOSITE- SUPPLY CHAIN (Number of Transactions, Stockroom Count and Procurement Total Spending)

Based on three components with weighting to each: number of transactions, stockroom count, and procurement total spending.

Used for the allocation of costs associated with the management and operations of the materials management and work order processing system.

SUPPLY CHAIN - Inventory Management Fossil, Transmission & Distribution Issues, Transfers & Returns

Based on the number of issues, transfer & return transactions for each Legal Entity at period end.

Used for the allocation of costs associated with the management and operations of investment recovery, including Fossil, but excluding Nuclear.

SUPPLY CHAIN - Procurement Total Spending

Based on the dollar amount of procurement spending within each Legal Entity at period end.

Used for the allocation of costs associated with procurement activities for the Entergy System.

SUPPLY CHAIN - Labor Dollars

Based on the labor dollars for the Transformer, Meter, and Light Shops.

Used primarily for the allocation of costs associated with services provided by employees in the supply chain equipment refurbishment and repair department.

DISTRIBUTION SUBSTATIONS TRANSFORMERS

Based on the number of transformers at the Distribution Substations at period end.

Used primarily for the allocation of costs associated with the maintenance, administrative activities, and technical analysis of all Distribution Substations.

REMOTE ACCESS SERVICES (RAS) ID's

Based on the number of RAS ID's within each Legal Entity at period end.

Used for the allocation of costs associated with providing Remote Access Service to Entergy employees and contractors.

VEHICLES

Based on the number of vehicles owned by each Legal Entity.

Used for the allocation of costs associated with the maintenance of company vehicles.

MANAGED ACCOUNTS

Based on the number of industrial and commercial managed accounts.

Used for the allocation of costs associated with the maintenance of Entergy's industrial and commercial customer accounts.

NUMBER OF CALLS - CUSTOMER SERVICE CENTERS

Based on a twenty-four month average of customer calls for each Legal Entity.

Used for the allocation of costs associated with the administration and support of Entergy's Customer Service Centers.

RADIO USAGE

Based on usage of Entergy's 2-way radio system.

Used for the allocation of costs associated with the administration and support of Entergy's 2-way radio system.

TOTAL IT SPEND

Based on the total dollars spent in the Information Technology plan.

Used for the allocation of costs associated with the administration and support of Entergy's IT business planning.

SUPPLY CHAIN MATERIALS TRANSACTIONS

Based on the number of Supply Chain materials transactions for each Legal Entity.

Used for the allocation of costs associated with the support of systems that manage Supply Chain materials.

AVERAGE NUMBER OF CAPITAL EXPENDITURE AUTHORIZATION PROJECTS FOR INFORMATION TECHNOLOGY, CUSTOMER SERVICE, DISTRIBUTION AND TRANSMISSION

Based on a twelve-month average of outstanding Capital Expenditure Authorizations for the Information Technology, Customer Service, Distribution and Transmission organizations.

Used for the allocation of costs associated with the prioritization of capital projects for the Information Technology, Customer Service, Distribution and Transmission organizations.

SECTION 263A TAX BENEFITS

Based on Section 263A tax benefits for each Legal Entity.

Used for the allocation of costs associated with tax administration, planning, and support related to Section 263A tax benefits.

OPEN WORKERS' COMPENSATION CLAIMS

Based on the number of open claims for each Legal Entity.

Used for the allocation of costs associated with managing workers' compensation claims processes and budgets.

UNIT POWER SALES AGREEMENT

Based on fixed allocation percentages under Entergy's Unit Power Sales Agreement.

Used primarily for the allocation of certain Tax Department services in connection with Entergy's Unit Power Sales Agreement.

RECORDS MANAGEMENT

Based on the number of employees at each Legal Entity using records management services.

Used to allocate costs associated with the management and supervision of non-nuclear business unit records management processes.

EX-10

Exhibit 10(f)9

Amendment To

Service Agreement

The parties hereto do hereby stipulate and agree to that the SERVICE AGREEMENT entered into by and between them under date of April 1, 1963, and as heretofore amended on January 1, 1972, April 27, 1984, August 1, 1988, January 28, 1991, January 1, 1992, January 1, 1996, January 1, 1998, January 1, 1999, January 1, 2000, January 1, 2001, April 1, 2002, January 1, 2003 and August 1, 2003 be and the same hereby is further amended by substituting for the Supplement to Exhibit II to the SERVICE AGREEMENT, the attached revised Supplement to Exhibit II. This Amendment is made and entered into as of March 1, 2004.

ENTERGY SERVICES, INC.

By /s/ Nathan E. Langston
     Nathan E. Langston
     Senior Vice President and Chief Accounting Officer

ENTERGY MISSISSIPPI, INC.

By /s/ Carolyn C. Shanks
    Carolyn C. Shanks
    President and CEO

ALLOCATION FORMULAE FOR
GROUPS OF CLIENT COMPANIES

Exhibit II, Supplement

Note: Each allocation formula will be based on data relevant to participating Client Companies to whom the services are provided.

ENERGY SALES

Based on total kilowatt-hours of energy sold to consumers.

Used primarily for the allocation of costs associated with the financial analyses of sales and related items.

CUSTOMERS

Based on a twelve-month average of residential, commercial, industrial, government, and municipal general business electric and gas customers.

Used primarily for the allocation of costs associated with the support of customer based services. Would include customer service and support, marketing, economic forecasts, environmental services, financial and regulatory analyses and customer information systems.

EMPLOYEES

Based on the number of full-time employees at period end.

Used primarily for the allocation of costs associated with the support of employee-based services. Would include administration of employee benefits programs, employee communications, employee training, and various facilities-based benefits and information technology desktop support.

RESPONSIBILITY RATIO

Based on the ratio of the company's load at time of system peak load. The peak load is the average of the twelve monthly highest clock-hour demands in kilowatts of the interconnected system occurring each month coincident with the system peak load.

Used primarily for the allocation of costs incurred in fossil plant support and integrated planning.

TRANSMISSION LINE MILES

Based on the number of miles of transmission lines, weighted for design voltage (Voltage < 400kv = 1; Voltage >=400kv =2).

Used primarily for the allocation of costs associated with project design, maintenance and installation of Entergy transmission lines.

SUBSTATIONS

Based on the number of high voltage substations weighted for Voltage (Voltage < 500kv = 1; Voltage >= 500kv = 2).

Used primarily for the allocation of related engineering and technical support for transmission and distribution substation operations and maintenance as well as for engineering and project management associated with substation construction.

COMPOSITE - TRANSMISSION LINES/SUBSTATIONS

Based on two components: Transmission Line Miles (30% weighting) and the Number of High Voltage Substations (70% weighting).

Used primarily for the allocation of the costs associated with the support of the transmission and distribution function that has both a transmission line component as well as a substation or load component.

GAS CONSUMPTION

Based on the volume of natural gas consumed annually by all gas fired generating units within the Entergy System.

Used for the allocation of costs associated with services in support of gas purchased for generation units.

LEVEL OF ESI SERVICE

Based on ESI total billings to each System company, excluding corporate overhead.

Used for the allocation of costs associated with support of ESI as a legal entity.

SYSTEM CAPACITY (NON-NUCLEAR)

Based on the power level, in kilowatts, that could be achieved if all non-nuclear generating units were operating at maximum capability simultaneously.

Used primarily for the allocation of costs associated with the support of the fossil operations of the System. This would include services provided by plant support, environmental and purchasing.

LABOR DOLLARS BILLED

Based on total labor dollars billed to each company.

Used primarily to allocate the costs associated with employee benefits plans, payroll taxes, departmental indirect costs and performance based compensation plans for ESI employees.

DISTRIBUTION LINE MILES

Based on the number of miles of distribution lines of 34.5kv or less.

Used primarily for the allocation of costs associated with project design, maintenance and installation of Entergy distribution lines.

COAL CONSUMPTION

Based on the quantity of tons of coal delivered for a twelve-month period to each coal plant within the Entergy System.

Used for the allocation of costs associated with services in support of coal purchased for coal generating units.

ACCOUNTS PAYABLE TRANSACTIONS

Based on a twelve-month number of accounts payable transactions processed.

Used for the allocation of costs associated with the support of the accounts payable function.

SQUARE FOOTAGE

Based on square footage occupied by ESI functional business units.

Used primarily to allocate the costs associated with facilities supervision and support.

INSURANCE PREMIUMS (NON-NUCLEAR)

Based on non-nuclear insurance premiums.

Used for the allocation of costs associated with risk management.

ASSET LOCATIONS

Based on the number of asset locations at period end.

Used for the allocation of costs associated with the fixed asset accounting function.

CAPITAL EXPENDITURE AUTHORIZATIONS

Based on a twelve-month average of outstanding Capital Expenditure Authorizations and Storm Job Orders.

Used for the allocation of costs associated with the capital project costing accounting function.

TOTAL ASSETS

Based on total assets at period end.

Used primarily to allocate costs associated with the oversight and safeguarding of corporate assets. This would include services provided by financial management and certain finance functions, among others. Also used when the services provided are driven by the relative size and complexity of the System Companies and there is no functional relationship between the services and any other available allocation formula.

BANK ACCOUNTS

Based on the number of bank accounts at period end.

Used for the allocation of costs associated with daily cash management activities.

SERVER AND MAINFRAME USAGE COMPOSITE

Based on the use of historical expenditures.

Used primarily for the allocation of costs associated with mainframe, unix servers and related database administration.

GENERAL LEDGER TRANSACTIONS

Based on the number of general ledger transactions for the period.

Used primarily for the allocation of costs associated with general ledger activities, including related information systems, and for general accounting activities.

TRANSITION TO COMPETITION

Based on a twelve-month average of residential, commercial, industrial, government, and municipal general business of gas and/or electric customers.

Used primarily for the allocation of costs associated with the management support of the Entergy System's strategy for and transition to competition.

TELEPHONES

Based on the number of telephones within each Legal Entity at period end.

Used for the allocation of costs associated with maintenance and support of telephones.

FIBER

Based on capacity and use of the Entergy System's fiber optic network.

Used primarily for the allocation of fiber optic operations and maintenance expenses.

NUCLEAR UNITS

Based on the number of nuclear units managed and operated by each Entergy System Company.

Used primarily to allocate nuclear fuel-related services.

NUCLEAR SITES

Based on the number of nuclear sites managed and operated by each Entergy System Company.

Used to allocate miscellaneous nuclear-related services.

ACCOUNTS RECEIVABLE INVOICES

Based on a twelve-month number of accounts receivable transactions processed.

Used for the allocation of costs associated with the support of the accounts receivable function.

PAYCHECKS

Based on the number of paychecks issued at each Legal Entity at period end.

Used for the allocation of costs associated with the processing of payroll.

PROPERTY AND LIABILITY PAID LOSSES

Based on a five-year annual average of the property and liability losses paid by the system companies.

Used for the allocation of costs associated with the operation and maintenance of the Risk Information System.

COMPOSITE- SUPPLY CHAIN (Number of Transactions, Stockroom Count and Procurement Total Spending)

Based on three components with weighting to each: number of transactions, stockroom count, and procurement total spending.

Used for the allocation of costs associated with the management and operations of the materials management and work order processing system.

SUPPLY CHAIN - Inventory Management Fossil, Transmission & Distribution Issues, Transfers & Returns

Based on the number of issues, transfer & return transactions for each Legal Entity at period end.

Used for the allocation of costs associated with the management and operations of investment recovery, including Fossil, but excluding Nuclear.

SUPPLY CHAIN - Procurement Total Spending

Based on the dollar amount of procurement spending within each Legal Entity at period end.

Used for the allocation of costs associated with procurement activities for the Entergy System.

SUPPLY CHAIN - Labor Dollars

Based on the labor dollars for the Transformer, Meter, and Light Shops.

Used primarily for the allocation of costs associated with services provided by employees in the supply chain equipment refurbishment and repair department.

DISTRIBUTION SUBSTATIONS TRANSFORMERS

Based on the number of transformers at the Distribution Substations at period end.

Used primarily for the allocation of costs associated with the maintenance, administrative activities, and technical analysis of all Distribution Substations.

REMOTE ACCESS SERVICES (RAS) ID's

Based on the number of RAS ID's within each Legal Entity at period end.

Used for the allocation of costs associated with providing Remote Access Service to Entergy employees and contractors.

VEHICLES

Based on the number of vehicles owned by each Legal Entity.

Used for the allocation of costs associated with the maintenance of company vehicles.

MANAGED ACCOUNTS

Based on the number of industrial and commercial managed accounts.

Used for the allocation of costs associated with the maintenance of Entergy's industrial and commercial customer accounts.

NUMBER OF CALLS - CUSTOMER SERVICE CENTERS

Based on a twenty-four month average of customer calls for each Legal Entity.

Used for the allocation of costs associated with the administration and support of Entergy's Customer Service Centers.

RADIO USAGE

Based on usage of Entergy's 2-way radio system.

Used for the allocation of costs associated with the administration and support of Entergy's 2-way radio system.

TOTAL IT SPEND

Based on the total dollars spent in the Information Technology plan.

Used for the allocation of costs associated with the administration and support of Entergy's IT business planning.

SUPPLY CHAIN MATERIALS TRANSACTIONS

Based on the number of Supply Chain materials transactions for each Legal Entity.

Used for the allocation of costs associated with the support of systems that manage Supply Chain materials.

AVERAGE NUMBER OF CAPITAL EXPENDITURE AUTHORIZATION PROJECTS FOR INFORMATION TECHNOLOGY, CUSTOMER SERVICE, DISTRIBUTION AND TRANSMISSION

Based on a twelve-month average of outstanding Capital Expenditure Authorizations for the Information Technology, Customer Service, Distribution and Transmission organizations.

Used for the allocation of costs associated with the prioritization of capital projects for the Information Technology, Customer Service, Distribution and Transmission organizations.

SECTION 263A TAX BENEFITS

Based on Section 263A tax benefits for each Legal Entity.

Used for the allocation of costs associated with tax administration, planning, and support related to Section 263A tax benefits.

OPEN WORKERS' COMPENSATION CLAIMS

Based on the number of open claims for each Legal Entity.

Used for the allocation of costs associated with managing workers' compensation claims processes and budgets.

UNIT POWER SALES AGREEMENT

Based on fixed allocation percentages under Entergy's Unit Power Sales Agreement.

Used primarily for the allocation of certain Tax Department services in connection with Entergy's Unit Power Sales Agreement.

RECORDS MANAGEMENT

Based on the number of employees at each Legal Entity using records management services.

Used to allocate costs associated with the management and supervision of non-nuclear business unit records management processes.

EX-10

Exhibit 10(g)9

Amendment To

Service Agreement

The parties hereto do hereby stipulate and agree to that the SERVICE AGREEMENT entered into by and between them under date of April 1, 1963, and as heretofore amended on January 1, 1972, April 27, 1984, August 1, 1988, January 28, 1991, January 1, 1992, January 1, 1996, January 1, 1998, January 1, 1999, January 1, 2000, January 1, 2001, April 1, 2002, January 1, 2003 and August 1, 2003 be and the same hereby is further amended by substituting for the Supplement to Exhibit II to the SERVICE AGREEMENT, the attached revised Supplement to Exhibit II. This Amendment is made and entered into as of March 1, 2004.

ENTERGY SERVICES, INC.

By /s/ Nathan E. Langston
     Nathan E. Langston
     Senior Vice President and Chief Accounting Officer

ENTERGY NEW ORLEANS, INC.

By /s/ Daniel F. Packer
    Daniel F. Packer
    President and CEO

ALLOCATION FORMULAE FOR
GROUPS OF CLIENT COMPANIES

Exhibit II, Supplement

Note: Each allocation formula will be based on data relevant to participating Client Companies to whom the services are provided.

ENERGY SALES

Based on total kilowatt-hours of energy sold to consumers.

Used primarily for the allocation of costs associated with the financial analyses of sales and related items.

CUSTOMERS

Based on a twelve-month average of residential, commercial, industrial, government, and municipal general business electric and gas customers.

Used primarily for the allocation of costs associated with the support of customer based services. Would include customer service and support, marketing, economic forecasts, environmental services, financial and regulatory analyses and customer information systems.

EMPLOYEES

Based on the number of full-time employees at period end.

Used primarily for the allocation of costs associated with the support of employee-based services. Would include administration of employee benefits programs, employee communications, employee training, and various facilities-based benefits and information technology desktop support.

RESPONSIBILITY RATIO

Based on the ratio of the company's load at time of system peak load. The peak load is the average of the twelve monthly highest clock-hour demands in kilowatts of the interconnected system occurring each month coincident with the system peak load.

Used primarily for the allocation of costs incurred in fossil plant support and integrated planning.

TRANSMISSION LINE MILES

Based on the number of miles of transmission lines, weighted for design voltage (Voltage < 400kv = 1; Voltage >=400kv =2).

Used primarily for the allocation of costs associated with project design, maintenance and installation of Entergy transmission lines.

SUBSTATIONS

Based on the number of high voltage substations weighted for Voltage (Voltage < 500kv = 1; Voltage >= 500kv = 2).

Used primarily for the allocation of related engineering and technical support for transmission and distribution substation operations and maintenance as well as for engineering and project management associated with substation construction.

COMPOSITE - TRANSMISSION LINES/SUBSTATIONS

Based on two components: Transmission Line Miles (30% weighting) and the Number of High Voltage Substations (70% weighting).

Used primarily for the allocation of the costs associated with the support of the transmission and distribution function that has both a transmission line component as well as a substation or load component.

GAS CONSUMPTION

Based on the volume of natural gas consumed annually by all gas fired generating units within the Entergy System.

Used for the allocation of costs associated with services in support of gas purchased for generation units.

LEVEL OF ESI SERVICE

Based on ESI total billings to each System company, excluding corporate overhead.

Used for the allocation of costs associated with support of ESI as a legal entity.

SYSTEM CAPACITY (NON-NUCLEAR)

Based on the power level, in kilowatts, that could be achieved if all non-nuclear generating units were operating at maximum capability simultaneously.

Used primarily for the allocation of costs associated with the support of the fossil operations of the System. This would include services provided by plant support, environmental and purchasing.

LABOR DOLLARS BILLED

Based on total labor dollars billed to each company.

Used primarily to allocate the costs associated with employee benefits plans, payroll taxes, departmental indirect costs and performance based compensation plans for ESI employees.

DISTRIBUTION LINE MILES

Based on the number of miles of distribution lines of 34.5kv or less.

Used primarily for the allocation of costs associated with project design, maintenance and installation of Entergy distribution lines.

COAL CONSUMPTION

Based on the quantity of tons of coal delivered for a twelve-month period to each coal plant within the Entergy System.

Used for the allocation of costs associated with services in support of coal purchased for coal generating units.

ACCOUNTS PAYABLE TRANSACTIONS

Based on a twelve-month number of accounts payable transactions processed.

Used for the allocation of costs associated with the support of the accounts payable function.

SQUARE FOOTAGE

Based on square footage occupied by ESI functional business units.

Used primarily to allocate the costs associated with facilities supervision and support.

INSURANCE PREMIUMS (NON-NUCLEAR)

Based on non-nuclear insurance premiums.

Used for the allocation of costs associated with risk management.

ASSET LOCATIONS

Based on the number of asset locations at period end.

Used for the allocation of costs associated with the fixed asset accounting function.

CAPITAL EXPENDITURE AUTHORIZATIONS

Based on a twelve-month average of outstanding Capital Expenditure Authorizations and Storm Job Orders.

Used for the allocation of costs associated with the capital project costing accounting function.

TOTAL ASSETS

Based on total assets at period end.

Used primarily to allocate costs associated with the oversight and safeguarding of corporate assets. This would include services provided by financial management and certain finance functions, among others. Also used when the services provided are driven by the relative size and complexity of the System Companies and there is no functional relationship between the services and any other available allocation formula.

BANK ACCOUNTS

Based on the number of bank accounts at period end.

Used for the allocation of costs associated with daily cash management activities.

SERVER AND MAINFRAME USAGE COMPOSITE

Based on the use of historical expenditures.

Used primarily for the allocation of costs associated with mainframe, unix servers and related database administration.

GENERAL LEDGER TRANSACTIONS

Based on the number of general ledger transactions for the period.

Used primarily for the allocation of costs associated with general ledger activities, including related information systems, and for general accounting activities.

TRANSITION TO COMPETITION

Based on a twelve-month average of residential, commercial, industrial, government, and municipal general business of gas and/or electric customers.

Used primarily for the allocation of costs associated with the management support of the Entergy System's strategy for and transition to competition.

TELEPHONES

Based on the number of telephones within each Legal Entity at period end.

Used for the allocation of costs associated with maintenance and support of telephones.

FIBER

Based on capacity and use of the Entergy System's fiber optic network.

Used primarily for the allocation of fiber optic operations and maintenance expenses.

NUCLEAR UNITS

Based on the number of nuclear units managed and operated by each Entergy System Company.

Used primarily to allocate nuclear fuel-related services.

NUCLEAR SITES

Based on the number of nuclear sites managed and operated by each Entergy System Company.

Used to allocate miscellaneous nuclear-related services.

ACCOUNTS RECEIVABLE INVOICES

Based on a twelve-month number of accounts receivable transactions processed.

Used for the allocation of costs associated with the support of the accounts receivable function.

PAYCHECKS

Based on the number of paychecks issued at each Legal Entity at period end.

Used for the allocation of costs associated with the processing of payroll.

PROPERTY AND LIABILITY PAID LOSSES

Based on a five-year annual average of the property and liability losses paid by the system companies.

Used for the allocation of costs associated with the operation and maintenance of the Risk Information System.

COMPOSITE- SUPPLY CHAIN (Number of Transactions, Stockroom Count and Procurement Total Spending)

Based on three components with weighting to each: number of transactions, stockroom count, and procurement total spending.

Used for the allocation of costs associated with the management and operations of the materials management and work order processing system.

SUPPLY CHAIN - Inventory Management Fossil, Transmission & Distribution Issues, Transfers & Returns

Based on the number of issues, transfer & return transactions for each Legal Entity at period end.

Used for the allocation of costs associated with the management and operations of investment recovery, including Fossil, but excluding Nuclear.

SUPPLY CHAIN - Procurement Total Spending

Based on the dollar amount of procurement spending within each Legal Entity at period end.

Used for the allocation of costs associated with procurement activities for the Entergy System.

SUPPLY CHAIN - Labor Dollars

Based on the labor dollars for the Transformer, Meter, and Light Shops.

Used primarily for the allocation of costs associated with services provided by employees in the supply chain equipment refurbishment and repair department.

DISTRIBUTION SUBSTATIONS TRANSFORMERS

Based on the number of transformers at the Distribution Substations at period end.

Used primarily for the allocation of costs associated with the maintenance, administrative activities, and technical analysis of all Distribution Substations.

REMOTE ACCESS SERVICES (RAS) ID's

Based on the number of RAS ID's within each Legal Entity at period end.

Used for the allocation of costs associated with providing Remote Access Service to Entergy employees and contractors.

VEHICLES

Based on the number of vehicles owned by each Legal Entity.

Used for the allocation of costs associated with the maintenance of company vehicles.

MANAGED ACCOUNTS

Based on the number of industrial and commercial managed accounts.

Used for the allocation of costs associated with the maintenance of Entergy's industrial and commercial customer accounts.

NUMBER OF CALLS - CUSTOMER SERVICE CENTERS

Based on a twenty-four month average of customer calls for each Legal Entity.

Used for the allocation of costs associated with the administration and support of Entergy's Customer Service Centers.

RADIO USAGE

Based on usage of Entergy's 2-way radio system.

Used for the allocation of costs associated with the administration and support of Entergy's 2-way radio system.

TOTAL IT SPEND

Based on the total dollars spent in the Information Technology plan.

Used for the allocation of costs associated with the administration and support of Entergy's IT business planning.

SUPPLY CHAIN MATERIALS TRANSACTIONS

Based on the number of Supply Chain materials transactions for each Legal Entity.

Used for the allocation of costs associated with the support of systems that manage Supply Chain materials.

AVERAGE NUMBER OF CAPITAL EXPENDITURE AUTHORIZATION PROJECTS FOR INFORMATION TECHNOLOGY, CUSTOMER SERVICE, DISTRIBUTION AND TRANSMISSION

Based on a twelve-month average of outstanding Capital Expenditure Authorizations for the Information Technology, Customer Service, Distribution and Transmission organizations.

Used for the allocation of costs associated with the prioritization of capital projects for the Information Technology, Customer Service, Distribution and Transmission organizations.

SECTION 263A TAX BENEFITS

Based on Section 263A tax benefits for each Legal Entity.

Used for the allocation of costs associated with tax administration, planning, and support related to Section 263A tax benefits.

OPEN WORKERS' COMPENSATION CLAIMS

Based on the number of open claims for each Legal Entity.

Used for the allocation of costs associated with managing workers' compensation claims processes and budgets.

UNIT POWER SALES AGREEMENT

Based on fixed allocation percentages under Entergy's Unit Power Sales Agreement.

Used primarily for the allocation of certain Tax Department services in connection with Entergy's Unit Power Sales Agreement.

RECORDS MANAGEMENT

Based on the number of employees at each Legal Entity using records management services.

Used to allocate costs associated with the management and supervision of non-nuclear business unit records management processes.

EX-12

				Exhibit 12(a)
Entergy Arkansas, Inc.
Computation of Ratios of Earnings to Fixed Charges and
Ratios of Earnings to Combined Fixed Charges and Preferred Dividends
	2000	2001	2002	2003	2004
Fixed charges, as defined:
Total Interest Charges	$101,600	$109,523	$103,210	$91,221	$84,430
Interest applicable to rentals	16,449	14,563	12,762	15,425	13,171
Total fixed charges, as defined	118,049	124,086	115,972	106,646	97,601
Preferred dividends, as defined (a)	13,479	12,348	11,869	14,274	12,646
Combined fixed charges and preferred dividends, as defined	$131,528	$136,434	$127,841	$120,920	$110,247
Earnings as defined:
Net Income	$137,047	$178,185	$135,643	$126,009	$142,210
Add:
Provision for income taxes:
Total	100,512	105,933	71,404	105,296	89,064
Fixed charges as above	118,049	124,086	115,972	106,646	97,601
Total earnings, as defined	$355,608	$408,204	$323,019	$337,951	$328,875
Ratio of earnings to fixed charges, as defined	3.01	3.29	2.79	3.17	3.37
Ratio of earnings to combined fixed charges and
preferred dividends, as defined	2.70	2.99	2.53	2.79	2.98
- ------------------------
(a) "Preferred dividends," as defined by SEC regulation S-K, are computed by dividing the       preferred dividend requirement by one hundred percent (100%) minus the income tax       rate.

EX-12

				Exhibit 12(b)
Entergy Gulf States, Inc.
Computation of Ratios of Earnings to Fixed Charges and
Ratios of Earnings to Combined Fixed Charges and Preferred Dividends
	2000	2001	2002	2003	2004
Fixed charges, as defined:
Total Interest charges	$158,949	$174,368	$144,840	$157,343	$133,598
Interest applicable to rentals	18,307	18,520	16,483	16,694	13,707
Total fixed charges, as defined	177,256	192,888	161,323	174,037	147,305
Preferred dividends, as defined (a)	15,742	13,017	6,190	6,485	6,991
Combined fixed charges and preferred dividends, as defined	$192,998	$205,905	$167,513	$180,522	$154,296
Earnings as defined:
Income (loss) from continuing operations before extraordinary items and
the cumulative effect of accounting changes	$180,343	$179,444	$174,078	$63,895	$192,264
Add:
Income Taxes	103,603	82,038	65,997	24,249	108,288
Fixed charges as above	177,256	192,888	161,323	174,037	147,305
Total earnings, as defined (b)	$461,202	$454,370	$401,398	$262,181	$447,857
Ratio of earnings to fixed charges, as defined	2.60	2.36	2.49	1.51	3.04
Ratio of earnings to combined fixed charges and
preferred dividends, as defined	2.39	2.21	2.40	1.45	2.90
(a) "Preferred dividends," as defined by SEC regulation S-K, are computed by dividing the preferred dividend      requirement by one hundred percent (100%) minus the income tax rate.

EX-12

				Exhibit 12(c)
Entergy Louisiana, Inc.
Computation of Ratios of Earnings to Fixed Charges and
Ratios of Earnings to Combined Fixed Charges and Preferred Dividends
	2000	2001	2002	2003	2004
Fixed charges, as defined:
Total Interest	$111,743	$116,076	$100,667	$76,756	$74,141
Interest applicable to rentals	6,458	7,951	6,496	6,359	5,595
Total fixed charges, as defined	118,201	124,027	$107,163	$83,115	$79,736
Preferred dividends, as defined (a)	16,102	12,374	10,647	$11,189	$10,899
Combined fixed charges and preferred dividends, as defined	$134,303	$136,401	$117,810	$94,304	$90,635
Earnings as defined:
Net Income	$162,679	$132,550	$144,709	$146,154	$127,495
Add:
Provision for income taxes:
Total Taxes	112,645	86,287	84,765	97,408	79,475
Fixed charges as above	118,201	124,027	107,163	83,115	79,736
Total earnings, as defined	$393,525	$342,864	$336,637	$326,677	$286,706
Ratio of earnings to fixed charges, as defined	3.33	2.76	3.14	3.93	3.60
Ratio of earnings to combined fixed charges and
preferred dividends, as defined	2.93	2.51	2.86	3.46	3.16
- ------------------------
(a) "Preferred dividends," as defined by SEC regulation S-K, are computed      by dividing the preferred dividendrequirement by one hundred percent      (100%) minus the income tax rate.

EX-12

				Exhibit 12(d)
Entergy Mississippi, Inc.
Computation of Ratios of Earnings to Fixed Charges and
Ratios of Earnings to Combined Fixed Charges and Preferred Dividends
	2000	2001	2002	2003	2004
Fixed charges, as defined:
Total Interest	$44,877	$50,991	$45,464	$47,464	$44,637
Interest applicable to rentals	1,596	1,849	1,916	1,880	1,162
Total fixed charges, as defined	46,473	52,840	$47,380	$49,344	$45,799
Preferred dividends, as defined (a)	5,347	4,674	4,490	5,099	5,067
Combined fixed charges and preferred dividends, as defined	$51,820	$57,514	$51,870	$54,443	$50,866
Earnings as defined:
Net Income	$38,973	$39,620	$52,408	$67,058	$73,497
Add:
Provision for income taxes:
Total income taxes	22,868	20,464	17,846	34,431	37,040
Fixed charges as above	46,473	52,840	47,380	49,344	45,799
Total earnings, as defined	$108,314	$112,924	$117,634	$150,833	$156,336
Ratio of earnings to fixed charges, as defined	2.33	2.14	2.48	3.06	3.41
Ratio of earnings to combined fixed charges and
preferred dividends, as defined	2.09	1.96	2.27	2.77	3.07
- ------------------------
(a) "Preferred dividends," as defined by SEC regulation S-K, are computed by dividing the preferred       dividendrequirement by one hundred percent (100%) minus the income tax rate.

EX-12

				Exhibit 12(e)
Entergy New Orleans, Inc.
Computation of Ratios of Earnings to Fixed Charges and
Ratios of Earnings to Combined Fixed Charges and Preferred Dividends
	2000	2001	2002	2003	2004
Fixed charges, as defined:
Total Interest	$15,891	$19,661	$27,950	$17,786	$16,610
Interest applicable to rentals	1,008	977	1,043	910	644
Total fixed charges, as defined	16,899	20,638	28,993	18,696	17,254
Preferred dividends, as defined (a)	1,643	2,898	2,736	1,686	1,545
Combined fixed charges and preferred dividends, as defined	$18,542	$23,536	$31,729	$20,382	$18,799
Earnings as defined:
Net Income	$16,518	($2,195)	($230)	$7,859	$28,072
Add:
Provision for income taxes:
Total	11,597	(4,396)	(422)	5,875	16,868
Fixed charges as above	16,899	20,638	28,993	18,696	17,254
Total earnings, as defined	$45,014	$14,047	$28,341	$32,430	$62,194
Ratio of earnings to fixed charges, as defined	2.66	0.68	0.98	1.73	3.60
Ratio of earnings to combined fixed charges and
preferred dividends, as defined	2.43	0.60	0.89	1.59	3.31
- ------------------------
(a) "Preferred dividends," as defined by SEC regulation S-K, are computed by dividing the preferred       dividend requirement by one hundred percent (100%) minus the income tax rate.
(b) For Entergy New Orleans, earnings for the twelve months ended December 31, 2001 were      not adequate to cover fixed charges and combined fixed charges and preferred dividends by      $6.6 million and $9.5 million, respectively.
(c) For Entergy New Orleans, earnings for the twelve months ended December 31, 2002 were      not adequate to cover combined fixed charges and preferred dividends by $0.7 million and      $3.4 million, respectively.

EX-12

					Exhibit 12(f)
System Energy Resources, Inc.
Computation of Ratios of Earnings to Fixed Charges and
Ratios of Earnings to Fixed Charges
	2000	2001	2002	2003	2004
Fixed charges, as defined:
Total Interest	$118,519	$138,018	$76,639	$64,620	$58,928
Interest applicable to rentals	5,753	4,458	3,250	3,793	3,426
Total fixed charges, as defined	$124,272	$142,476	$79,889	$68,413	$62,354
Earnings as defined:
Net Income	$93,745	$116,355	$103,352	$106,003	$105,948
Add:
Provision for income taxes:
Total	81,263	43,761	76,177	75,845	78,013
Fixed charges as above	124,272	142,476	79,889	68,413	62,354
Total earnings, as defined	$299,280	$302,592	$259,418	$250,261	$246,315
Ratio of earnings to fixed charges, as defined	2.41	2.12	3.25	3.66	3.95

EX-21

Exhibit 21

The seven registrants, Entergy Corporation, System Energy Resources, Inc., Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc., are listed below (for a list of the remaining direct and indirect subsidiaries of Entergy Corporation, with the exception of certain subsidiaries that in the aggregate would not constitute a "significant subsidiary," see Exhibit 1 to Entergy Corporation's Public Utility Holding Company Act of 1935 filing made in File No. 70-9123 on February 24, 2005):

	State or Other Jurisdiction of Incorporation
Entergy Corporation	Delaware
System Energy Resources, Inc. (a)	Arkansas
Entergy Arkansas, Inc. (a)	Arkansas
Entergy Gulf States, Inc. (a)	Texas
Entergy Louisiana, Inc. (a)	Louisiana
Entergy Mississippi, Inc. (a)	Mississippi
Entergy New Orleans, Inc. (a)	Louisiana

_______________________

(a) Entergy Corporation owns all of the Common Stock of System Energy Resources, Inc., Entergy Arkansas Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc.

EX-23

Exhibit 23(b)

Consent of Independent Auditors

We consent to the incorporation by reference in Post-Effective Amendments No. 3 and 5A on Form S-8 and their related prospectuses to Registration Statement on Form S-4 (No. 33-54298) of Entergy Corporation, Registration Statements on Form S-3 (Nos. 333-02503 and 333-22007) of Entergy Corporation and Registration Statements on Form S-8 (Nos. 333-98179, 333-90914, 333-75097, 333-55692, and 333-68950) of Entergy Corporation of our report dated March 1, 2005, with respect to the consolidated financial statements of Entergy-Koch, LP included in Exhibit 99(a) in this Annual Report on Form 10-K of Entergy Corporation for the year ended December 31, 2004.

                                                                                                /s/ Ernst & Young LLP

Houston, Texas
March 8, 2005

EX-24

Exhibit 24

March 8, 2005

TO:         Nathan E. Langston
               John M. Adams, Jr.

Re:          Power of Attorney; 2004 Form 10-K

Entergy Corporation, referred to herein as the Company, will file with the Securities and Exchange Commission its Annual Report on Form 10-K for the year ended December 31, 2004 pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

The Company and the undersigned persons, in their respective capacities as directors and/or officers of the Company, as specified in Attachment I, do each hereby make, constitute and appoint Nathan Langston and John M. Adams, Jr. and each of them, their true and lawful Attorneys (with full power of substitution) for each of the undersigned and in his or her name, place and stead to sign and cause to be filed with the Securities and Exchange Commission the aforementioned Annual Report on Form 10-K and any amendments thereto.

Yours very truly,

ENTERGY CORPORATION

By: /s/ J. Wayne Leonard                            
          J. Wayne Leonard 9;
         Chief Executive Officer and Director

/s/ Maureen S. Bateman	/s/ Simon D. deBree
Maureen S. Bateman	Simon D. deBree
Director	Director
/s/ W. Frank Blount	/s/ Claiborne P. Deming
W. Frank Blount	Claiborne P. Deming
Director	Director
/s/ Alexis M. Herman	/s/ Donald C. Hintz_
Alexis M. Herman	Donald C. Hintz
Director	Director
/s/ J. Wayne Leonard	/s/ Robert v.d. Luft
J. Wayne Leonard	Robert v. d. Luft
Chief Executive Officer	Chairman of the Board
Director	Director
/s/ Kathleen A. Murphy	/s/ Paul W. Murrill
Kathleen A. Murphy	Paul W. Murrill
Director	Director
/s/ James R. Nichols	/s/ William A. Percy, II
James R. Nichols	William A. Percy, II
Director	Director
/s/ Dennis H. Reilley	/s/ Wm. Clifford Smith
Dennis H. Reilley	Wm. Clifford Smith
Director	Director
/s/ Bismark A. Steinhagen	/s/ Steven V. Wilkinson
Bismark A. Steinhagen	Steven V. Wilkinson
Director	Director
/s/ Leo P. Denault_
Leo P. Denault
Executive Vice President and Chief Financial Officer

ATTACHMENT I

Entergy Corporation

Chief Executive Officer and Director - J. Wayne Leonard (principal executive officer)
Executive Vice President and Chief Financial Officer - Leo P. Denault (principal financial officer)

Directors - Maureen S. Bateman, W. Frank Blount, Simon D. deBree, Claiborne P. Deming, Alexis M. Herman, Donald C. Hintz, J. Wayne Leonard, Robert v.d. Luft, Kathleen A. Murphy, Paul W. Murrill, James R. Nichols, William A. Percy, II, Dennis H. Reilley, Wm. Clifford Smith, Bismark A. Steinhagen, Steven V. Wilkinson

March 8, 2005

TO:         Nathan E. Langston
               John M. Adams, Jr.

Re:          Power of Attorney; 2004 Form 10-K

Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc., and System Energy Resources, Inc. (collectively referred to herein as the Companies) will each file with the Securities and Exchange Commission its Annual Report on Form 10-K for the year ended December 31, 2004 pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

The Companies and the undersigned person, in their respective capacities as directors and/or officers of the Companies, as specified in Attachment I, do each hereby make, constitute and appoint Nathan Langston and John M. Adams, Jr. and each of them, their true and lawful Attorneys (with full power of substitution) for each of the undersigned and in his or her name, place and stead to sign and cause to be filed with the Securities and Exchange Commission the aforementioned Annual Report on Form 10-K and any amendments thereto.

Yours very truly,

ENTERGY ARKANSAS, INC. (hereinafter "EAI")
ENTERGY GULF STATES, INC. (hereinafter "EGSI")
ENTERGY LOUISIANA, INC. (hereinafter "ELI")
ENTERGY MISSISSIPPI, INC. (hereinafter "EMI")
ENTERGY NEW ORLEANS, INC. (hereinafter "ENOI")
SYSTEM ENERGY RESOURCES, INC. (hereinafter "SERI")

/s/ Hugh T. McDonald	/s/ E. Renae Conley
HUGH T. McDONALD Chairman, President, and Chief Executive Officer of Entergy Arkansas, Inc.	E. RENAE CONLEY President and Chief Executive Officer - Louisiana of Entergy Gulf States, Inc. and Chairman, President and Chief Executive Officer of Entergy Louisiana, Inc.
/s/ Joseph F. Domino	/s/ Carolyn C. Shanks
JOSEPH F. DOMINO Chairman, President and Chief Executive Officer-Texas of Entergy Gulf States, Inc.	CAROLYN C. SHANKS Chairman, President, and Chief Executive Officer of Entergy Mississippi, Inc.
/s/ Daniel F. Packer	/s/ Gary J. Taylor
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.

/s/ Joseph F. Domino	/s/ Carolyn C. Shanks
Joseph F. Domino	Carolyn C. Shanks
Director, Chairman of the Board, President and Chief Executive Officer-Texas of EGSI	Director, Chairman of the Board, President and Chief Executive Officer of EMI
/s/ Mark T. Savoff	/s/ Hugh T. McDonald
Mark T. Savoff	Hugh T. McDonald
Director of EAI, EGSI, ELI, EMI and ENOI	Director, Chairman of the Board, President and Chief Executive Officer of EAI
/s/ Richard J. Smith	/s/ Gary J. Taylor
Richard J. Smith	Gary J. Taylor
Director of EAI, EGSI, ELI, EMI and ENOI	Director, Chairman of the Board, President and Chief Executive Officer of SERI
/s/ Daniel F. Packer	/s/ Leo P. Denault
Daniel F. Packer	Leo P. Denault
Director, Chairman of the Board, President and Chief Executive Officer of ENOI	Director of EAI, EGSI, ELI, EMI, ENOI and SERI
/s/ E. Renae Conley	/s/ Jay A. Lewis
E. Renae Conley Director of ELI and EGSI, Chairman of the Board, President and Chief Executive Officer of ELI, President and Chief Executive Officer - - Louisiana of EGSI	Jay A. Lewis Vice President and Chief Financial Officer, Utility Operations Group of EAI, EGSI, ELI, EMI and ENOI
/s/ Theodore Bunting	/s/ Steven C. McNeal
Theodore Bunting Vice President and Chief Financial Officer, Nuclear Operations of SERI	Steven C. McNeal Director of SERI

ATTACHMENT I

Entergy Arkansas, Inc.

Chairman of the Board, President and Chief Executive Officer - Hugh T. McDonald (principal executive officer); Vice President and Chief Financial Officer, Utility Operations Group - - Jay A. Lewis (principal financial officer).

Directors - Hugh T. McDonald, Leo P. Denault, Mark T. Savoff and Richard J. Smith

Entergy Gulf States, Inc.

Chairman of the Board, President and Chief Executive Officer- Texas - Joseph F. Domino (principal executive officer); President and Chief Executive Officer-Louisiana - - E. Renae Conley, (principal executive officer), Vice President and Chief Financial Officer, Utility Operations Group - - Jay A. Lewis (principal financial officer).

Directors - Joseph F. Domino, E. Renae Conley, Leo P. Denault, Mark T. Savoff and Richard J. Smith

Entergy Louisiana, Inc.

Chairman of the Board, President and Chief Executive Officer - E. Renae Conley (principal executive officer); Vice President and Chief Financial Officer, Utility Operations Group - - Jay A. Lewis (principal financial officer).

Directors - E. Renae Conley, Leo P. Denault, Mark T. Savoff and Richard J. Smith

Entergy Mississippi, Inc.

Chairman of the Board, President and Chief Executive Officer - Carolyn C. Shanks (principal executive officer); Vice President and Chief Financial Officer, Utility Operations Group - - Jay A. Lewis (principal financial officer).

Directors - Carolyn C. Shanks, Leo P. Denault, Mark T. Savoff and Richard J. Smith

Entergy New Orleans, Inc.

Chairman of the Board, President and Chief Executive Officer - Daniel F. Packer (principal executive officer); Vice President and Chief Financial Officer, Utility Operations Group - - Jay A. Lewis (principal financial officer).

Directors - Daniel F. Packer, Leo P. Denault, Mark T. Savoff and Richard J. Smith

System Energy Resources, Inc.

Chairman of the Board, President and Chief Executive Officer - Gary J. Taylor (principal executive officer); Vice President and Chief Financial Officer, Nuclear Operations - - Theodore H. Bunting (principal financial officer).

Directors - Gary J. Taylor, Leo P. Denault and Steven C. McNeal

EX-31

Exhibit 31(a)

CERTIFICATIONS

	I, J. Wayne Leonard, certify that:
1.	I have reviewed this annual report on Form 10-K of Entergy Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

                  /s/ J. Wayne Leonard                        
J. Wayne Leonard
Chief Executive Officer of Entergy Corporation

Date:  March 9, 2005

EX-31

Exhibit 31(b)

CERTIFICATIONS

	I, Leo P. Denault, certify that:
1.	I have reviewed this annual report on Form 10-K of Entergy Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

                         /s/ Leo P. Denault                               
Leo P. Denault
Executive Vice President and Chief Financial Officer of
Entergy Corporation

Date:  March 9, 2005

EX-31

Exhibit 31(c)

CERTIFICATIONS

	I, Hugh T. McDonald, certify that:
1.	I have reviewed this annual report on Form 10-K of Entergy Arkansas, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

                    /s/ Hugh T. McDonald                         
Hugh T. McDonald
Chairman, President, and Chief Executive Officer of
Entergy Arkansas, Inc.

Date: March 9, 2005

EX-31

Exhibit 31(d)

CERTIFICATIONS

	I, Joseph F. Domino, certify that:
1.	I have reviewed this annual report on Form 10-K of Entergy Gulf States, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

                       /s/ Joseph F. Domino                           
Joseph F. Domino
Chairman, President and Chief Executive Officer-Texas
of Entergy Gulf States, Inc.

Date: March 9, 2005

EX-31

Exhibit 31(e)

CERTIFICATIONS

	I, E. Renae Conley, certify that:
1.	I have reviewed these annual reports on Form 10-K of Entergy Gulf States, Inc. and Entergy Louisiana, Inc.;
2.	Based on my knowledge, these reports do not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by these reports;
3.	Based on my knowledge, the financial statements, and other financial information included in these reports, fairly present in all material respects the financial condition, results of operations and cash flows of the registrants as of, and for, the periods presented in these reports;
4.	The registrants' other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrants and have:
	a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrants, including their consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which these reports are being prepared;
	b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c) Evaluated the effectiveness of the registrants' disclosure controls and procedures and presented in these reports our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by these reports based on such evaluation; and
	d) Disclosed in these reports any change in the registrants' internal control over financial reporting that occurred during the registrants' most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrants' internal control over financial reporting; and
5.	The registrants' other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants' auditors and the audit committee of the registrants' board of directors (or persons performing the equivalent functions):
	a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants' ability to record, process, summarize and report financial information; and
	b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants' internal control over financial reporting.

                         /s/ E. Renae Conley                               
E. Renae Conley
Chairman, President, and Chief Executive Officer of
Entergy Louisiana, Inc.; President and Chief Executive
Officer-Louisiana of Entergy Gulf States, Inc.

Date: March 9, 2005

EX-31

Exhibit 31(f)

CERTIFICATIONS

	I, Carolyn C. Shanks, certify that:
1.	I have reviewed this annual report on Form 10-K of Entergy Mississippi, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

                      /s/ Carolyn C. Shanks                           
Carolyn C. Shanks
Chairman, President, and Chief Executive Officer of
Entergy Mississippi, Inc.

Date: March 9, 2005

EX-31

Exhibit 31(g)

CERTIFICATIONS

	I, Daniel F. Packer, certify that:
1.	I have reviewed this annual report on Form 10-K of Entergy New Orleans, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

                      /s/ Daniel F. Packer                            
Daniel F. Packer
Chairman, President, and Chief Executive Officer of
Entergy New Orleans, Inc.

Date:   March 9, 2005

EX-31

Exhibit 31(h)

CERTIFICATIONS

	I, Gary J. Taylor, certify that:
1.	I have reviewed this annual report on Form 10-K of System Energy Resources, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

                           /s/ Gary J. Taylor                                
Gary J. Taylor
Chairman, President, and Chief Executive Officer of
System Energy Resources, Inc.

Date:  March 9, 2005

EX-31

Exhibit 31(i)

CERTIFICATIONS

	I, Jay A. Lewis, certify that:
1.	I have reviewed these annual reports on Form 10-K of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc.;
2.	Based on my knowledge, these reports do not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by these reports;
3.	Based on my knowledge, the financial statements, and other financial information included in these reports, fairly present in all material respects the financial condition, results of operations and cash flows of the registrants as of, and for, the periods presented in these reports;
4.	The registrants' other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrants and have:
	a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrants, including their consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which these reports are being prepared;
	b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c) Evaluated the effectiveness of the registrants' disclosure controls and procedures and presented in these reports our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by these reports based on such evaluation; and
	d) Disclosed in these reports any change in the registrants' internal control over financial reporting that occurred during the registrants' most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrants' internal control over financial reporting; and
5.	The registrants' other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants' auditors and the audit committee of the registrants' board of directors (or persons performing the equivalent functions):
	a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants' ability to record, process, summarize and report financial information; and
	b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants' internal control over financial reporting.

                             /s/ Jay A. Lewis                                  
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.

Date:  March 9, 2005

EX-31

Exhibit 31(j)

CERTIFICATIONS

	I, Theodore H. Bunting, Jr., certify that:
1.	I have reviewed this annual report on Form 10-K of System Energy Resources, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

           /s/ Theodore H. Bunting, Jr.                 
Theodore H. Bunting, Jr.
Vice President and Chief Financial Officer
of System Energy Resources, Inc.

Date:  March 9, 2005

EX-32

Exhibit 32(a)

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

              I, J. Wayne Leonard, Chief Executive Officer of Entergy Corporation (the "Company"), certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Annual Report on Form 10-K of the Company for the year ended December 31, 2004 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods presented in the Report.

 

                  /s/ J. Wayne Leonard                       
J. Wayne Leonard
Chief Executive Officer of Entergy Corporation

Date:  March 9, 2005

EX-32

Exhibit 32(b)

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

            I, Leo P. Denault, Chief Financial Officer of Entergy Corporation (the "Company"), certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Annual Report on Form 10-K of the Company for the year ended December 31, 2004 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods presented in the Report.

                           /s/ Leo P. Denault                                
Leo P. Denault
Executive Vice President and Chief Financial Officer
of Entergy Corporation

Date:  March 9, 2005

EX-32

Exhibit 32(c)

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

                I, Hugh T. McDonald, Chairman, President and Chief Executive Officer of Entergy Arkansas, Inc. (the "Company"), certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Annual Report on Form 10-K of the Company for the year ended December 31, 2004 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods presented in the Report.

 

                    /s/ Hugh T. McDonald                         
Hugh T. McDonald
Chairman, President, and Chief Executive Officer

Date:  March 9, 2005

EX-32

Exhibit 32(d)

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

                I, Joseph F. Domino, Chairman, President and Chief Executive Officer-Texas of Entergy Gulf States, Inc. (the "Company"), certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Annual Report on Form 10-K of the Company for the year ended December 31, 2004 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods presented in the Report.

 

                          /s/ Joseph F. Domino                               
Joseph F. Domino
Chairman, President and Chief Executive Officer-Texas of
Entergy Gulf States, Inc.

Date: March 9, 2005

EX-32

Exhibit 32(e)

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

            I,E. Renae Conley, President and Chief Executive Officer-Louisiana of Entergy Gulf States, Inc. and Chairman, President and Chief Executive Officer of Entergy Louisiana, Inc. (the "Companies"), certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Annual Report on Form 10-K of each of the Companies for the year ended December 31, 2004 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in each Report fairly presents, in all material respects, the financial condition and results of operations of each respective Company as of the dates and for the periods presented in each Report.

                              /s/ E. Renae Conley                                   
E. Renae Conley
President and Chief Executive Officer-Louisiana of
Entergy Gulf States, Inc. and Chairman, President, and Chief
Executive Officer of Entergy Louisiana, Inc.

Date:   March 9, 2005

EX-32

Exhibit 32(f)

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
 

                    I, Carolyn C. Shanks, Chairman, President and Chief Executive Officer of Entergy Mississippi, Inc. (the "Company"), certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Annual Report on Form 10-K of the Company for the year ended December 31, 2004 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods presented in the Report.

                     /s/ Carolyn C. Shanks                           
Carolyn C. Shanks
Chairman, President, and Chief Executive Officer of
Entergy Mississippi, Inc.

Date: March 9, 2005

EX-32

Exhibit 32(g)

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

                    I, Daniel F. Packer, Chairman, President and Chief Executive Officer of Entergy New Orleans, Inc. (the "Company"), certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Annual Report on Form 10-K of the Company for the year ended December 31, 2004 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods presented in the Report.

                       /s/ Daniel F. Packer                            
Daniel F. Packer
Chairman, President, and Chief Executive Officer of
Entergy New Orleans, Inc.

Date:  March 9, 2005

EX-32

Exhibit 32(h)

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

            I, Gary J. Taylor, Chairman, President and Chief Executive Officer of System Energy Resources, Inc. (the "Company"), certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Annual Report on Form 10-K of the Company for the year ended December 31, 2004 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods presented in the Report.

                           /s/ Gary J. Taylor                                
Gary J. Taylor
Chairman, President, and Chief Executive Officer of
System Energy Resources, Inc.

Date:  March 9, 2005

EX-32

Exhibit 32(i)

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

            I,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. (the "Companies"), certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Annual Report on Form 10-K of each of the Companies for the year ended December 31, 2004 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in each Report fairly presents, in all material respects, the financial condition and results of operations of each respective Company as of the dates and for the periods presented in each Report.

                          /s/ Jay A. Lewis                               
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.

Date:  March 9, 2005

EX-32

Exhibit 32(j)

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

              I, Theodore H. Bunting, Jr., Chief Financial Officer of System Energy Resources, Inc. (the "Company"), certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Annual Report on Form 10-K of the Company for the year ended December 31, 2004 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods presented in the Report.

 

             /s/ Theodore H. Bunting, Jr.                  
Theodore H. Bunting, Jr.
Vice President and Chief Financial Officer
of System Energy Resources, Inc.

Date:  March 9, 2005

EX-99

Exhibit 99(a)

CONSOLIDATED FINANCIAL STATEMENTS

Entergy - Koch, LP
Years ended December 31, 2004, 2003, and 2002
 

                                                                                    Report of Independent Auditors

The Audit Committee of the Board of
    Directors of EKLP, LLC, and
    Partners of Entergy - Koch, LP

We have audited the accompanying consolidated balance sheets of Entergy - Koch, LP (the "Partnership"), as of December 31, 2004 and 2003, and the related consolidated statements of income, changes in partners' capital, and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Entergy - - Koch, LP, at December 31, 2004 and 2003, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States.

As further discussed in Note 3 to the consolidated financial statements, in 2003 the Partnership changed its method of accounting for inventory held for trading purposes and energy trading contracts not qualifying as derivatives.

                                                                                                /s/ Ernst & Young LLP

Houston, Texas
March 1, 2005

Entergy - Koch, LP

Consolidated Balance Sheets
(In Thousands)

	December 31
	2004	2003
Assets
Current assets:
Cash and cash equivalents	$ 240,052	$ 277,964
Margin and collateral deposits	4,485	186,624
Accounts receivable:
Trade (less allowance of $4,526 and $12,307,              respectively)	44,655	839,995
Affiliates	1,201	37,305
Receivable from Partners	-	4,500
Natural gas inventory	-	239,150
Assets from trading activities	6,617	680,643
Other current assets	4,365	192,011
Pipeline assets held for sale	-	1,019,873
Total current assets	301,375	3,478,065
Noncurrent assets:
Restricted cash - escrow	200,300	-
Property, plant, and equipment, net	-	20,787
Assets from trading activities	-	192,316
Other noncurrent assets	-	26,474
Total noncurrent assets	200,300	239,577
Total assets	$ 501,675	$ 3,717,642

	December 31
		2004	2003
Liabilities and Partners' capital
Current liabilities:
Accounts payable:
Trade		$ 38,734	$ 807,168
Affiliates		-	7,478
Collateral held on deposit		3,991	114,347
Liabilities from trading activities		6,617	574,870
Accrued liabilities		67,046	87,228
Notes payable - credit facilities		-	32,337
Other current liabilities		11	6,485
Pipeline liabilities held for sale		-	97,569
Total current liabilities		116,399	1,727,482
Noncurrent liabilities:
Senior notes (net of discount)		-	501,721
Liabilities from trading activities		-	291,542
Deferred gain on sale of trading assets		200,300	-
Other noncurrent liabilities		15,535	13,651
Total noncurrent liabilities		215,835	806,914
Commitments and contingencies (Note 10)
Partners' capital:
General Partner (including accumulated other comprehensive        income (loss) of $-0- and $(21), respectively)		1,694	11,832
Limited Partners (including accumulated other comprehensive        income (loss) of $-0- and $(2,030), respectively)		167,747	1,171,414
Total Partners' capital		169,441	1,183,246
Total liabilities and Partners' capital		$ 501,675	$ 3,717,642

See accompanying notes.

Entergy - Koch, LP

Consolidated Statements of Income
(In Thousands)

	Year ended December 31
	2004	2003	2002
Net (loss) gain from trading activities	$ (108,302)	$ 339,362	$ 259,472
Depreciation and amortization	6,744	11,790	11,233
General and administrative	107,997	117,805	122,726
Operating (loss) income	(223,043)	209,767	125,513
Other income and expense:
Gain on sale of trading assets	869,114	-	-
Interest income	8,143	6,020	1,439
Interest expense	(22,842)	(28,124)	(24,317)
Loss on extinguishment of debt	(60,228)	-	-
Other (expense) income	(5,120)	171	19,149
Total other income (expense)	789,067	(21,933)	(3,729)
Income from continuing operations before     income tax expense and cumulative effect of     change in accounting principle	566,024	187,834	121,784
Income tax expense	15,761	4,494	3,684
Income from continuing operations before     cumulative effect of change in accounting     principle	550,263	183,340	118,100
Discontinued operations:
Income (loss) from discontinued operations	43,246	(17,941)	31,160
Gain on sale of discontinued operations	157,885	-	-
Income before cumulative effect of change in     accounting principle	751,394	165,399	149,260
Cumulative effect of change in accounting     principle (net of tax benefit of $4,477 in     2003)	-	14,711	-
Net income	$ 751,394	$ 180,110	$ 149,260

See accompanying notes.

Entergy - Koch, LP

Consolidated Statements of Changes in Partners' Capital
(In Thousands)

	General Partner	Limited Partners	Total
Balance at December 31, 2001	$ 10,248	$ 1,014,609	$ 1,024,857
Capital contributions	328	32,503	32,831
Net income	1,493	147,767	149,260
Other comprehensive income:
Foreign currency translation	37	3,606	3,643
Net cash flow hedge gain	26	2,543	2,569
Net cash flow hedge gain recognized in net          income	(40)	(3,955)	(3,995)
Total other comprehensive income	23	2,194	2,217
Total comprehensive income	1,516	149,961	151,477
Balance at December 31, 2002	12,092	1,197,073	1,209,165
Capital distributions	(2,000)	(198,000)	(200,000)
Net income	1,801	178,309	180,110
Other comprehensive income (loss):
Foreign currency translation	69	6,824	6,893
Net cash flow hedge loss	(133)	(13,114)	(13,247)
Net cash flow hedge loss recognized in net          income	3	322	325
Total other comprehensive loss	(61)	(5,968)	(6,029)
Total comprehensive income	1,740	172,341	174,081
Balance at December 31, 2003	11,832	1,171,414	1,183,246
Capital contributions	-	72,750	72,750
Capital distributions	(17,673)	(1,822,327)	(1,840,000)
Net income	7,514	743,880	751,394
Other comprehensive income (loss):
Foreign currency translation	(109)	(10,762)	(10,871)
Net cash flow hedge loss	(188)	(18,685)	(18,873)
Net cash flow hedge loss recognized in net          income	318	31,477	31,795
Total other comprehensive income	21	2,030	2,051
Total comprehensive income	7,535	745,910	753,445
Balance at December 31, 2004	$ 1,694	$ 167,747	$ 169,441

Entergy - Koch, LP

Consolidated Statements of Cash Flows
(In Thousands)

	Year ended December 31
	2004	2003	2002
Cash flows from operating activities - continuing operations and discontinued operations
Net income	$ 751,394	$ 180,110	$ 149,260
Adjustments to reconcile net income to net cash flows     provided by (used in) operating activities:
Gain on sales of trading assets and discontinued          operations	(1,026,999)	-	-
Loss on extinguishment of debt	60,228	-	-
Provision for loss on accounts receivable	1,508	1,182	11,507
Depreciation and amortization	30,718	42,851	42,087
Cumulative effect of change in accounting principle	-	(15,245)	-
Change in net assets from trading activities	410,282	87,801	15,844
Gain on sale of assets	-	-	(775)
Net changes in working capital	(207,091)	132,656	(373,657)
Change in net other noncurrent assets and liabilities	19,988	1,273	13,426
Net cash flows provided by (used in) operating activities	40,028	430,628	(142,308)
Cash flows from investing activities - continuing operations and discontinued operations
Capital expenditures	(45,999)	(88,277)	(50,133)
Proceed from sale of asset	-	-	9,897
Net proceeds from sale of discontinued operations	1,116,828	-	-
Net proceeds from sales of trading assets (exclusive of     restricted cash of $200,000)	1,205,249	-	-
Net cash flows provided by (used in) investing activities	2,276,078	(88,277)	(40,236)
Cash flows from financing - continuing operations and discontinued operations
Net (repayment) borrowing - credit facilities notes payable	(32,337)	(215,663)	88,000
Net (repayment) proceeds - senior notes	(555,674)	199,910	-
Capital contribution	72,750	32,831	-
Capital distributions	(1,840,000)	(200,000)	-
Net cash flows (used in) provided by financing activities	(2,355,261)	(182,922)	88,000
Effect of exchange rate changes on cash and cash equivalents	1,243	2,575	3,486
Net change in cash and cash equivalents	(37,912)	162,004	(91,058)
Cash and cash equivalents, beginning of year	277,964	115,960	207,018
Cash and cash equivalents, end of year	$ 240,052	$ 277,964	$ 115,960
Cash paid for income taxes (in millions)	$ 15.7	$ 6.9	$ 6.4
Cash paid for interest (in millions)	$ 34.1	$ 27.8	$ 25.9

See accompanying notes.

                                                                                            Entergy - Koch, LP

                                                                        Notes to Consolidated Financial Statements


                                                                                            December 31, 2004


1.     Organization and Nature of Operations

Entergy - Koch, LP ("EKLP" or the "Partnership"), is a limited partnership indirectly owned by subsidiaries of Entergy Corporation ("Entergy") and Koch Industries, Inc. ("Koch") (collectively, the "Partners"). Subsidiaries of Entergy and Koch own 99% of the Partnership through limited partner interests, and the remaining 1% of the Partnership is owned by the general partner, EKLP, LLC, a company owned 50% by EK Holding III, LLC (an Entergy subsidiary), and 50% by Koch Energy, Inc. (a Koch subsidiary). EKLP, LLC, is managed by a board of directors, with each partner having equal representation.

Pursuant to the Agreement of Limited Partnership, dated January 31, 2001 (the "Partnership Agreement"), general distributions are equally shared by the Partners; however, the Partners disproportionately share in certain profits and special allocations, which occur periodically and would occur upon liquidation. The Partnership Agreement also requires that distributions of cash be made quarterly, if EKLP, LLC, determines there is excess cash, based on EKLP management's recommendation.

EKLP was formed to combine certain natural gas and power trading contracts and assets of Entergy with the natural gas pipeline business and the natural gas, power, and weather trading business of Koch. The accompanying consolidated financial statements reflect the transactions of the Partnership subsequent to its inception. The Partnership operated these contributed businesses, contracts, and assets primarily through four wholly owned subsidiaries: Gulf South Pipeline Company, LP ("Gulf South"), Entergy - Koch Trading, LP ("EKT US"), Entergy - Koch Trading Canada, ULC ("EKT CAN"), and Entergy - Koch Trading, Ltd. ("EKT Europe"). On September 2, 2004, Entergy announced that EKLP had signed a definitive agreement to sell EKT Europe, EKT CAN, and substantially all of the assets of EKT US ("Trading Assets") to Merrill Lynch Commodities, Inc. ("MLCI"), and was conducting a competitive process to sell Gulf South.

On November 1, 2004, EKLP sold Trading Assets to MLCI for a purchase price of $800 million plus the fair value of all trading assets sold. The agreement called for EKLP to establish an escrow account for $200 million that EKLP is entitled to, two years from closing, contingent on certain events that may preclude former EKLP executives from being able to continue their services with MLCI. The $200 million contingent gain has been deferred and is classified as restricted cash - escrow in noncurrent assets, and is recorded as a noncurrent liability on the consolidated balance sheets. Interest earned on the restricted cash accrues to the benefit of EKLP, pending resolution of the contingency. Such interest amounts to $0.3 million as of December 31, 2004.

Due to the nature of the assets sold, mainly contracts with third parties, and because EKLP will have to legally continue to maintain and manage all the rights and obligations for certain contracts that are not assigned by the third party to MLCI, the sale of the Trading Assets do not qualify for discontinued operations in accordance with Statement of Financial Accounting Standards ("SFAS") No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"). As such, the gain on the sale of the Trading Assets is included in net income from continuing operations in the consolidated statements of income. As part of the sales agreement, EKLP entered into a total return swap whereby MLCI assumes all the benefits and detriments associated with any of EKLP's contracts that were included in the sales agreement and have not been assigned to MLCI. See Note 7, "Concentrations of Credit Risk."

On December 29, 2004, EKLP sold Gulf South to TGT Pipeline, LLC. In accordance with SFAS No. 144, Gulf South's assets, liabilities, and results of operations have been reclassified to discontinued operations in the consolidated balance sheets and consolidated statements of income for all periods presented. See Note 8, "Discontinued Operations."

EKLP's future operations will consist of winding down the affairs of the Partnership. The proceeds from the combined sales were used to retire all of EKLP's senior notes and other credit facilities. Remaining proceeds, in excess of future working capital needs and minimum contractual capitalization requirements, as determined by EKLP, were distributed to the Partners.

2.     Significant Accounting Policies

Principles of Consolidation - The consolidated financial statements include the accounts of all of the Partnership's wholly owned subsidiaries after the elimination of significant intercompany transactions and balances. Investments in entities that are not controlled by the Partnership are accounted for using either the cost or equity method, as appropriate. These investments are regularly reviewed for impairment and propriety of current accounting treatment.

Cash and Cash Equivalents - Cash and cash equivalents consist primarily of cash on deposit, certificates of deposit, and money market accounts with original maturities of three months or less. All highly liquid investments with original maturities of three months or less are classified as cash and cash equivalents.

Margin and Collateral Deposits - Margin and collateral deposits consist primarily of cash that the Partnership has on deposit with counterparties for margin or collateral requirements related to trading futures, swap, and option contracts. Pursuant to the Partnership's contracts with each counterparty, the margin or collateral on deposit will vary based on changes in market prices, the Partnership's credit rating, and various other factors. As further discussed in Note 7, "Concentrations of Credit Risk," the Partnership also requires collateral from its counterparties based on similar criteria. Amounts from financial instruments received as collateral from counterparties are recorded as "collateral held on deposit."

Accounts Receivable-Trade - Accounts receivable-trade are stated at the historical carrying amount net of write-offs and allowance for doubtful accounts receivable, and represent claims against third parties that will be settled in cash. An allowance for doubtful accounts is established when needed based on factors including historical experience with the particular counterparty, economic trends and conditions, the age of the underlying receivable, and the Partnership's ability to exercise the right of offset. Interest receivable on delinquent accounts receivable is included in the accounts receivable-trade balance and recognized as interest income when contractually permissible and collectibility is reasonably assured. Past-due accounts receivable-trade are written off when either internal collection efforts have been unsuccessful or when a settlement is reached for an amount that is less than the outstanding historical balance.

Natural Gas Inventory - Inventory is comprised of natural gas held for resale. As further discussed in Note 3, "Changes in Accounting Principles and New Accounting Pronouncements," the Partnership adopted Emerging Issues Task Force ("EITF") Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities ("EITF No. 02-3"). As such, inventory as of December 31, 2003, is recorded at the lower of weighted-average cost or market.

Included in other current assets as of December 31, 2003, are amounts related to natural gas volumes held in third-party facilities and for which title transferred to such third parties but to which the Partnership had rights in the future. Such amounts are recorded at the lower of weighted-average cost or market based on the notional volumes to which the Partnership had rights. The Partnership held title to other natural gas volumes to which third parties had the rights under similar arrangements. The amounts related to these transactions are recorded in other current liabilities at the higher of market or weighted-average cost.

Trading and Risk Management Activities - Trading Services - EKLP offered risk management services to the natural gas, power, and weather markets, and optimization services related to the natural gas storage and transportation assets of its customers. These services were provided through a variety of financial instruments, including forward contracts involving cash settlement or physical delivery of natural gas or power; swap contracts requiring payment to (or receipts from) counterparties based on the difference between two prices for (or related to) natural gas, power, or weather; and option contracts requiring payment to (or receipts from) counterparties based on the difference between the option's strike and the related market price for natural gas, power, or weather.

As required by EITF No. 02-3, the mark-to-market method is used to account for all derivative trading activities and the accrual method of accounting is used to account for storage, transportation, and asset optimization contracts not qualifying as derivatives under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended ("SFAS No. 133").

As required by EITF Issue No. 99-2, Accounting for Weather Derivatives ("EITF No. 99-2"), the Partnership uses the mark-to-market method to account for all trading-related weather contracts.

Under the mark-to-market method, derivative contracts are recorded at quoted or estimated market value, with resulting unrealized gains and losses recorded as "Assets from trading activities" and "Liabilities from trading activities," respectively, on the consolidated balance sheets according to their term to maturity. Current period changes in the assets and liabilities from trading activities are recognized as net gains or losses in "Net gain (loss) from trading activities" on the consolidated statements of income. Changes in the assets and liabilities from trading activities result primarily from changes in the valuation of the portfolio of contracts, maturity and settlement of contracts, and newly originated transactions. Terms regarding cash settlement of the contracts vary with respect to the actual timing of cash receipts and payments. Accounts receivable, accounts payable, and margin and collateral deposits include settlement amounts for financial derivatives for which the contractual settlement price has been published at the end of the accounting period. As a result, at December 31, 2003, accounts receivable and accounts payable included $88.2 million and $64 million, respectively, of January 2004 settled financial forward contracts valued using the published January 2004 futures price. Margin and collateral deposits include $(1.9) million of January 2004 settled futures at December 31, 2003.

The market prices and models used to value the derivatives reflect management's best estimate considering various factors, including closing exchange and over-the-counter quotations, time value, and volatility underlying the contracts. The values are adjusted to reflect the potential impact of liquidating EKLP's positions in an orderly manner over a reasonable time period under present market conditions and to reflect other types of risks, including model risk and credit risk. When quoted market prices are not available, EKLP utilizes other valuation techniques to estimate market value. The use of these techniques requires estimations with respect to future prices, volatility, liquidity, and other variables. Changes in market prices and the estimations used directly affect the estimated market value of these transactions. Accordingly, it is reasonably possible that such estimates could change in the near term.

Beginning January 1, 2003, EKT US utilized futures contracts to mitigate the variability in cash flows of anticipated future natural gas purchases and sales. EKT US designated and accounted for these derivatives as cash flow hedges in accordance with SFAS No. 133. The changes in the fair value of the hedge contracts were expected to, and did, have a high correlation to changes in the anticipated natural gas purchases and sales and, therefore, qualified as cash flow hedges under SFAS No. 133. In addition, if the hedge contracts ceased to have high correlation, or if the forecasted purchase or sale were deemed no longer probable to occur, hedge accounting was terminated and the associated change in fair value of the derivatives was recognized in the related period of change in "Net (loss) gain from trading activities" on the consolidated statements of income.

The fair value of these derivatives is reported in the consolidated balance sheets in "Assets and liabilities from trading activities." As of December 31, 2003, EKT US included a net deferred loss on these cash flow hedges in "Accumulated other comprehensive income" of approximately $11.8 million. For the years ended December 31, 2004 and 2003, the ineffective portion of these hedges recorded in "Net (loss) gain from trading activities" was approximately $5 million and $6 million, respectively. Upon the sale of the Trading Assets, EKLP reclassified approximately $55 million of losses deferred in other comprehensive income to "Net gain from trading activities" because the forecasted purchase or sale that was being hedged became probable of not occurring by the end of the originally specified time period, as documented at the inception of the hedging relationship. EKLP did not have any open cash flow hedges as of December 31, 2004.

EKLP's asset optimization contracts relate to the natural gas storage and transportation assets of the related counterparties. Revenues, costs, and profit-sharing obligations associated with these asset optimization contracts are recognized based on the terms of the contract as such revenues are earned and costs are incurred, and when profit-sharing obligations arise. In addition, EKLP entered into derivative contracts to manage market risk associated with its asset optimization contracts. These derivative contracts were not designated as hedges and continued to be recorded at fair value.

Trading and Risk Management Activities - Treasury - The Partnership entered into an interest rate swap agreement for interest rate risk exposures, which was designated as a fair value hedge pursuant to SFAS No. 133. The interest rate swap agreement utilized by the Partnership effectively modified the Partnership's exposure to interest risk by converting the Partnership's $200 million in fixed rate debt issued August 21, 2003, to a floating rate. This agreement involved the receipt of fixed rate amounts in exchange for floating rate interest payments over the life of the agreement without an exchange of the underlying principal amount.

Hedge effectiveness is assessed as the change in the fair value of the hedging instrument relative to the change in the fair value of the related debt. During the year ended December 31, 2003, the Partnership recognized an immaterial net gain, included as a component of interest income, related to the ineffective portion of its fair value hedge of interest rate risk exposure. The effect of the fair value hedge for the year ended December 31, 2003, was to increase the carrying value of the associated debt by $2.5 million. A corresponding asset for approximately the same amount is recorded in "Other assets." The Partnership terminated this hedge in August 2004 upon liquidating the interest rate swap.

Additionally, the Partnership entered into forward foreign currency swaps associated with certain intercompany debt balances carried by the domestic entity, which are denominated in British pounds. The swaps were used to counteract the effects of changes in foreign currency exchange rates. For the years ended December 31, 2004 and 2003, the foreign currency swaps resulted in a loss of $9 million and $15.9 million, respectively.

Property, Plant, and Equipment - Property, plant, and equipment includes computer hardware and software and is depreciated using the straight-line method based on average useful lives ranging from three to five years.

Assets Held for Sale - The Partnership classifies assets as held for sale when the assets meet the held for sale criteria of SFAS No. 144. This statement established the criteria to determine when a qualified group of long-lived assets and liabilities should be classified as held for sale. Among other indicators, to classify long-lived assets as held for sale, an entity must be actively marketing the assets and the sale of the asset group must be probable.

Intangible Assets - EKLP's intangible assets related to the weather trading business and represented the logic utilized in the proprietary weather derivative valuation models, analytics used to translate weather information into trading strategies, and the proprietary data infrastructure that facilitates creation of structured weather derivative products. The logic and valuation models were sold to MLCI as part of sale of the Trading Assets.

Income Taxes - The Partnership's consolidated financial statements reflect no provision for United States federal and state income taxes since such taxes, if any, are the liabilities of the Partners. Foreign income taxes are provided for the Partnership's subsidiaries, which are subject to taxation in foreign jurisdictions. All operating foreign subsidiaries were sold as part of the sale of the Trading Assets. At December 31, 2004, there were no deferred tax assets or liabilities. Such deferred tax assets and liabilities were not significant at December 31, 2003.

Net (loss) Gain From Trading Activities - The accompanying consolidated financial statements present revenues, costs, and realized and unrealized gains and losses from derivatives for trading services, including physical sales and purchases of natural gas and power, on a net basis in "Net (loss) gain from trading activities" in the consolidated statements of income. Revenues from sales of physical natural gas and power are recognized in the month of delivery. The associated costs, including transportation and transmission charges, are recognized concurrent with the revenue.

Foreign Currency - Management determined the functional currency of EKT Europe to be the British pound. As such, the assets and liabilities of EKT Europe were translated at the exchange rate at December 31, 2003. Revenues and expenses for EKT Europe were translated at a weighted-average exchange rate for each reporting period presented in the accompanying consolidated statements of income. Foreign currency translation adjustments are reported in Partners' capital (as a component of other comprehensive income). Individually significant transactions are translated at the exchange rate on the date of the transaction. Foreign exchange transaction gains and losses are recognized as "Other income (expense)" on the consolidated statements of income for the period. For the years ended December 31, 2004, 2003, and 2002, foreign exchange gains of approximately $7.0 million, $14.1 million, and $7.1 million, respectively, were included in "Other income (expense)." All operating foreign subsidiaries were sold as part of the sale of the Trading Assets. Approximately $12 million of foreign exchange gain was reclassified from "accumulated other comprehensive income" to gain on sale of trading assets in the consolidated statements of income.

Use of Estimates - The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make various assumptions and estimates that affect amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. See related discussion in "Trading and Risk Management Activities."

Reclassifications - Certain reclassifications have been made to the presentation of balances from prior periods to conform with the current-period presentation. These reclassifications have no net effect on previously reported results of operations.

3.     Changes in Accounting Principles and New Accounting Pronouncements

Changes in Accounting Principles

EITF No. 02-3 - In October 2002, the EITF reached consensus in EITF No. 02-3 to rescind EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities ("EITF No. 98-10"), EITF Issue No. 00-17, Measuring the Fair Value of Energy-Related Contracts in Applying No. 98-10, and Financial Accounting Standards Board ("FASB") Staff Announcement Topic D-105, Accounting in Consolidation for Energy Trading Contracts, between Affiliated Entities When Activities of One but Not Both Affiliates Are within the Scope of EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" ("Topic No. D-105"). According to the consensus, "other energy contracts" such as storage and transportation contracts, not qualifying as derivatives pursuant to SFAS No. 133, executed prior to October 26, 2002, shall no longer be marked-to-market effective January 1, 2003. The accrual basis of accounting is required for contracts executed subsequent to October 25, 2002. In addition, for fiscal years beginning after December 15, 2002, gains and losses on all derivative instruments should be shown net in the income statement, whether or not settled physically, if the derivatives are held for trading purposes. EITF No. 02-3 also clarified that with the rescission of EITF No. 98-10, it would no longer be an acceptable industry practice to account for inventory held for trading purposes at fair value when fair value exceeds cost, except as provided by higher level accounting principles generally accepted in the United States.

The Partnership prospectively adopted the provisions of EITF No. 02-3 relating to inventory held for trading purposes and energy trading contracts not qualifying as derivatives and executed subsequent to October 25, 2002. The Partnership adopted EITF No. 02-3 in January 1, 2003, for its nonderivative energy trading contracts executed prior to October 26, 2002, and reported an increase to net income of $14.7 million as a cumulative effect of a change in accounting principle, net of tax. As a result of the adoption of EITF No. 02-3, the Partnership no longer recognizes energy trading contracts under mark-to-market accounting unless these contracts meet the definition of a derivative in accordance with SFAS No. 133 or the contract is a weather derivative. The Partnership has retained net presentation of all of its trading activities in the consolidated statements of income.

In November 2002, EITF No. 02-3 was revised to state that an unrealized gain or loss at inception of a derivative instrument should not be recognized unless the fair value of that instrument is obtained from a quoted market price in an active market or is otherwise evidenced by comparison to other observable current market transactions or based on a valuation technique incorporating observable market data. Adoption by the Partnership of this November revision to EITF No. 02-3 was applied by the Partnership prospectively and did not have a material impact on the Partnership's consolidated financial position or results of operations.

SFAS No. 149 - In April 2003, SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities ("SFAS No. 149"), was issued. SFAS No.149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and hedging activities under SFAS No. 133. SFAS No. 149 clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative as discussed in SFAS No. 133. In addition, it clarifies when a derivative contains a financing component that warrants special reporting in the statement of cash flows. SFAS No. 149 amends certain other existing pronouncements. These changes will result in a more consistent reporting of contracts that are derivatives in their entirety or that contain embedded derivatives that warrant separate accounting. SFAS No. 149 was effective for contracts entered into or modified after June 30, 2003, except as stated below, and for hedging relationships designated after June 30, 2003. The guidance is to be applied prospectively. The provisions of SFAS No. 149 that relate to SFAS No. 133, Implementation Issues, that have been effective for periods that began prior to June 15, 2003, continue to be applied in accordance with their respective effective dates. The adoption of SFAS No. 149 did not have an impact on the consolidated financial statements of the Partnership.

4.     Accumulated Other Comprehensive Income (Loss)

The components of accumulated other comprehensive income are as follows:

	December 31, 2004			December 31, 2003			December 31,
	General Partner	Limited Partners	Total	General Partner	Limited Partners	Total	General Partner	Limited Partners	Total
	(In Thousands)
Accumulated other     comprehensive income:
Accumulated foreign currency     translation	$ -	$ -	$ -	$ 109	$ 10,762	$ 10,871	$ 40	$ 3,938	$ 3,978
Accumulated net cash flow     hedge (loss) gain	-	-	-	(51)	(5,013)	(5,064)	82	8,101	8,183
Accumulated net cash flow     hedge gain recognized in net     income	-	-	-	(79)	(7,779)	(7,858)	(82)	(8,101)	(8,183)
	$ -	$ -	$ -	$ (21)	$ (2,030)	$ (2,051)	$ 40	$ 3,938	$ 3,978

5.     Supplemental Cash Flow Information

Changes in the components of working capital are as follows:

	Year ended December 31
	2004	2003	2002
	(In Thousands)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable,       trade	$ 125,207	$ (91,225)	$ (262,697)
Increase in accounts receivable, affiliate	(3,965)	(7,238)	(8,387)
Decrease in receivable from partners	6,755	891	3,731
Change in net transportation and exchange        receivables and payables	3,456	(5,111)	(1,461)
Change in net margin and collateral	(237,652)	(76,404)	4,056
(Increase) decrease in natural gas inventory	(238,819)	154,641	(168,327)
(Decrease) increase in accounts payable, trade	(65,146)	128,680	231,953
Increase (decrease) in accounts payable,        affiliates	5,596	(24,300)	1,392
(Decrease) increase in accrued liabilities	(74,139)	42,934	(20,583)
Change in other current assets and liabilities, net	271,616	9,788	(153,334)
Total	$ (207,091)	$ 132,656	$ (373,657)

6.     Fair Value of Financial Instruments

At December 31, 2004 and 2003, the carrying amounts of certain financial instruments held by the Partnership, including cash equivalents, accounts receivable, accounts payable, and notes payable are representative of fair value because of the short-term maturity of these instruments. In addition to the financial instruments listed below, the Partnership held financial instruments for trading and risk management activities, as well as debt instruments, as disclosed.

The fair value of all of the Partnership's derivative financial instruments and other trading contracts is the estimated amount at which management believes the instruments could be liquidated over a reasonable period of time, based on quoted market prices, current market conditions, or other estimates obtained from third-party brokers or dealers. See Note 2, "Significant Accounting Policies," under "Trading and Risk Management Activities" for additional information.

The fair value of the Partnership's derivatives, financial instruments, and other trading contracts at December 31, 2004 and 2003, is summarized in the following tables:

	December 31, 2004
	Estimated Fair Value		Carrying Amount
	Assets	Liabilities	Assets	Liabilities
	(In Thousands)
Trading
Natural gas	$ 6,557	$ 218	$ 6,557	$ 218
Power	30	-	30	-
Weather	30	7	30	7
Other(1)	-	6,392	-	6,392
	$ 6,617	$ 6,617	$ 6,617	$ 6,617

(1) Represents the fair value of the total return swap with MLCI. See Note 7, "Concentrations of Credit Risk."
 

	December 31, 2003
	Estimated Fair Value		Carrying Amount
	Assets	Liabilities	Assets	Liabilities
	(In Thousands)
Trading(1)
Natural gas	$ 499,610	$ 541,699	$ 499,610	$ 541,699
Power	348,267	296,814	348,267	296,814
Weather	20,069	21,177	20,069	21,177
Other energy-related commodities	5,013	6,722	5,013	6,722
	$ 872,959	$ 866,412	$ 872,959	$ 866,412
Non-Trading(2)
Interest rate swap	$ 2,058	$ -	$ 2,058	$ -
Foreign currency swap	-	1,497	-	1,497
	$ 2,058	$ 1,497	$ 2,058	$ 1,497
Debt instruments
Senior notes(3)	$ -	$ 546,252	$ -	$ 501,721

(1)    Represents the fair value of all derivatives of trading services, including natural gas derivatives for cash flow
         hedges accounted for in accordance with SFAS No. 133. The carrying amount of trading services
         derivatives is included in the consolidated balance sheet as "Assets and liabilities from trading activities."
(2)    The carrying amount is included in the consolidated balance sheet in "Other current assets" and "Other
         current liabilities."
(3)    The estimated fair value of the senior notes has been determined by the Partnership using available
         market information and selected valuation methodologies. Considerable judgment is required in
         interpreting market data to develop the fair value estimate. The use of different market assumptions or
         valuation  methodologies could have a material effect on the estimated fair value.

7.     Concentrations of Credit Risk

EKLP managed its own portfolio through its Trading Assets using a variety of financial instruments, which include forwards, futures, swaps, options, storage contracts, and transportation contracts. This portfolio was sold in its entirety to MLCI as part of the sale of the Trading Assets. As part of the sale, EKLP entered into a total return swap with MLCI where MLCI assumes all the benefits and detriments associated with any of EKLP contracts that were included in the sales agreement and have not been assigned to MLCI. Assets and liabilities from trading activities that have not been assigned at December 31, 2004, are $6.6 million and $0.2 million, respectively. To record the total return swap, $6.4 million due to MLCI has been recorded in liabilities from trading activities. Trade receivables and payables relating to the contracts that have not been assigned to MLCI at December 31, 2004, but that are related to the total return swap are $37.8 million and $1.1 million, respectively. To record the total return swap, a net $36.7 million payable due to MLCI has been recorded in trade payables.

Inherent in trading and risk management activities are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the contracts and derivative financial instruments will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or an agreement. The total return swap transferred all market risk and credit risk to MLCI. Thus, at December 31, 2004, EKLP is only exposed to credit risk with MLCI. During January 2005 contracts, related to approximately 70% of the fair value of the total return swap at December 31, 2004, were assigned to MLCI. Based on MLCI's creditworthiness, the Partnership does not anticipate a material adverse effect on its consolidated financial position as a result of counterparty nonperformance.

The notional volumes of the Partnership's realized physical activity included in "Net gain from trading activities" are set forth below. These notional volumes represent the gross transaction volumes for trading contracts before the sale of the Trading Assets that were physically settled and are not a measure of the Partnership's exposure to market or credit risk.

	Year ended December 31
	2004	2003
	(In Thousands)
Trading
Power (in MWh)	323,421	445,979
Gas (in MMBtu)	1,713,861	2,347,045

Financial instruments, which subject the Partnership to credit risk, consist principally of cash equivalents and trade receivables. In accordance with the Partnership's investment policy, cash equivalents are invested such that credit exposure to any one financial institution is limited.

Trade receivables are predominantly with energy, utility, and other trading companies in the United States. For the years ended December 31, 2004, 2003, and 2002, no single counterparty contributed in excess of 10% of "Net gain from trading activities" on the consolidated statements of income.

The counterparties associated with "Assets from trading activities" at December 31, 2003, are summarized in the following tables:
 

	December 31, 2003
	Investment Grade(1)	Total
	(In Thousands)
Gas and electric utilities	$ 188,105	$ 211,220
Energy marketers	117,732	274,712
Financial institutions	285,879	300,805
Oil and gas producers	15,642	66,766
Industrials	10,570	11,746
Other	12,245	12,534
Total	$ 630,173	877,783
Credit valuation adjustments		(4,824)
Trading exposure(2)		872,959
Collateral		(379,735) (3)
Assets from trading activities, net of collateral		$ 493,224

(1)     "Investment Grade" is primarily determined using publicly available credit ratings along with consideration
         of cash, collateral, standby letters of credit, and parent company guarantees. Included in "Investment
         Grade" are counterparties with a minimum, or a minimum implied through internal credit analysis,
         Standard & Poor's or Moody's rating of BBB- or Baa3, respectively.
(2)     Trading exposure reflects netting between current and noncurrent assets and liabilities from trading activities
         under master netting agreements, as applicable.  Three customers' exposure at December 31, 2003,
         comprised greater than 5% of assets from trading activities, of which two are included above as
         "Investment Grade."
(3)     Includes collateral held on deposit and standby letters of credit. An additional $73.5 million of collateral is
         being applied against estimated accounts receivable.

8.     Discontinued Operations

On December 29, 2004, EKLP sold its pipeline business for $1.136 billion plus the net working capital as of the closing date ("Base Purchase Price"). Accordingly, the assets, liabilities, and results of operations of the pipeline business have been reported as discontinued operations for all periods presented. Operating revenues for Gulf South classified as discontinued operations in the consolidated statements of income for the years ended December 31, 2004, 2003, and 2002, were $198 million, $177 million, and $161 million, respectively.

The Partnership reclassified $0.5 million from the 2003 cumulative effect of a change in accounting principle related to Gulf South's adoption of SFAS No. 143, Accounting for Asset Retirement Obligations, to loss from discontinued operations.

A summary of assets and liabilities related to Gulf South reclassified as assets and liabilities held for sale on the consolidated balance sheets as of December 31, 2003, is as follows:
 

	December 31
	2003
	(In Thousands)
ASSETS
Accounts receivables	$ 19,333
Transportation and exchange receivables	44,169
Receivable from partners	2,255
Natural gas inventory	10,182
Property, plant, and equipment, net	927,053(1)
Other assets	16,881
Total assets	$ 1,019,873
LIABLITIES
Accounts payables	$ 14,567
Transportation and exchange payables	28,277
Accrued liabilities	48,348
Other liabilities	6,377
Total liabilities	$ 97,569

(1)     Net property, plant, and equipment includes land of $712, pipeline facilities of $861,661, working gas and
         base gas of $93,635, computer hardware and software of $13,832, construction in progress of $43,464,
         and accumulated depreciation of $(86,251).

In accordance with the Purchase and Sale Agreement between EKLP and TGT Pipeline, LLC (the "Agreement"), TGT Pipeline, LLC, has assumed all contingent liabilities related to the pipeline business. Management has made customary representations and warranties in the Agreement regarding contingent liabilities and other matters related to the pipeline business. All representations and warranties made in the Agreement are in effect until nine months after the closing date, and the purchase price will be adjusted if aggregate losses actually incurred by the buyer exceed 2% of the Base Purchase Price and in no event shall EKLP's aggregate liabilities exceed 10% of the Base Purchase Price. Management does not anticipate, and no provision has been made in these financial statements for, subsequent payments under these indemnification provisions in the Agreement.

In addition, each party under the Agreement is allowed time to evaluate the final working capital calculation used to determine the Base Purchase Price. TGT Pipeline, LLC's period for evaluation expired on February 28, 2005, after which EKLP has 45 days to continue its evaluation. TGT Pipeline, LLC, has identified a $4.2 million adjustment to the Base Purchase Price. EKLP disagrees with the adjustment and continues to assess a resolution. The Agreement provides for mediation if a resolution cannot be reached. Any changes in the working capital adjustment will result in adjustment to the Base Purchase Price. No provision has been made in these consolidated financial statements for this disputed item.

9.     Senior Notes and Credit Facilities

The Partnership's debt is summarized as follows:

	December 31
	2004	2003
	(In Thousands)
Short-term debt:
Entergy - Koch, LP Credit Agreement (364-Day)	$ -	$ -
Entergy - Koch, LP Credit Agreement (Five-Year Term)	-	-
Entergy - Koch Trading, LP Margin Facility Agreement	-	25,000
Entergy - Koch Trading, Ltd. Short-Term Revolving Facility	-	7,337
Notes payable - credit facilities	$ -	$ 32,337
Long-term debt:
Entergy - Koch, LP 3.65% Senior Notes due 2006, net of       discount and including fair value adjustment	$ -	$ 202,408
Entergy - Koch, LP 6.90% Senior Notes due 2011, net of       discount	-	299,313
Senior notes (net of discount)	$ -	$ 501,721

Short-Term Debt

EKLP historically maintained two primary credit facilities to manage its short-term cash requirements: a 364-day credit facility and a multi-year credit facility. In addition to these two facilities, Entergy - Koch Trading, LP, and Entergy - Koch Trading, Ltd., had short-term credit facilities for additional liquidity.

On December 19, 2003, EKLP renewed its 364-day credit facility with total commitments of $230 million. This facility included the ability to issue up to $75 million of letters of credit within the total commitment of $230 million. This facility was terminated and all commitments and obligations under this agreement were released on November 1, 2004, in conjunction with the sale of the Trading Assets to MLCI. At December 31, 2003, no loans or letters of credit were outstanding under this facility.

On February 1, 2001, EKLP entered into a multi-year credit facility with total commitments of $105 million. This facility included the ability to issue up to $105 million of letters of credit within the total commitment of $105 million. At December 31, 2003, no loans were outstanding under this facility and $3.9 million in letters of credit were outstanding. This facility was terminated and all commitments and obligations under this agreement were released on November 1, 2004, in conjunction with the sale of the Trading Assets to MLCI. At the time of termination, EKLP had $4.48 million in letters of credit outstanding. EKLP entered into a collateral agreement under which cash was posted to fully collateralize the outstanding letters of credit until the credits could be returned and terminated. At December 31, 2004, no collateral had been returned, but EKLP expects to have all letters of credit terminated and the cash collateral returned by March 31, 2005.

On September 25, 2003, EKT US entered into a 364-day credit facility with a total commitment of $25 million. This facility was used solely for the purpose of financing a portion of the Partnership's margin requirements related to energy trading. Advances under the facility would bear interest at LIBOR plus 0.75%, and the Partnership was required to pay a facility fee at a rate of 0.125% per annum on the total commitment regardless of usage. As of December 31, 2003, $25 million was outstanding under this facility at a weighted-average interest rate of 1.85%. This facility expired on September 23, 2004, and was not renewed.

On December 1, 2003, EKT Europe entered into an uncommitted short-term credit facility with a limit of 10 million British pounds. Advances under the facility would bear interest at the bank's cost of funds plus 0.75%. As of December 31, 2003, loans in the amount of 4.1 million British pounds ($7.3 million) were outstanding at a weighted-average interest rate of 1.84%. This facility expired on April 24, 2004, and was renewed. In conjunction with the sale of the Trading Assets to MLCI, all rights and obligations were assigned at closing to MLCI.

Long-Term Debt

On August 21, 2003, EKLP issued $200 million of senior unsecured notes at 3.65%, due August 20, 2006. These senior notes were offered at a discounted issue price of 99.955%, resulting in an effective interest rate of 3.67%.

On July 24, 2001, EKLP issued $300 million of senior unsecured notes at 6.9%, due August 1, 2011. These senior notes were offered at a discounted issue price of 99.698%, resulting in an effective interest rate of 6.92%.

In conjunction with the sale of the Trading Assets to MLCI, a tender offer was made for the full amount of outstanding notes. At December 31, 2004, all notes had been tendered or redeemed as provided for in the debenture, and EKLP no longer has any obligations outstanding under the debentures. EKLP recognized a loss of $60.2 million as loss on extinguishment of debt in the consolidated statements of income due to the early retirement of these notes.

Other Credit Facilities

On October 31, 2003, EKT Europe entered into a 364-day credit facility with a commitment of 40 million British pounds. At December 31, 2003, letters of credit/bank guarantees in the amount of 19.3 million British pounds ($34.6 million) were outstanding. This facility expired on October 29, 2004, and was not renewed. There are no further obligations outstanding under this facility.

On December 1, 2003, EKT Europe entered into an uncommitted short-term credit facility with a limit of 25 million British pounds. At December 31, 2003, letters of credit/bank guarantees in the amount of 15.1 million British pounds ($27.0 million) were outstanding. This facility expired on April 24, 2004, and was renewed. In conjunction with the sale of the Trading Assets to MLCI, all rights and obligations under this agreement were assigned and transferred to MLCI effective with the closing of the sale.
 
10.     Commitments and Contingencies

Purchase Agreement Indemnifications - In the purchase agreements for the sale of Trading Assets and Gulf South, EKLP has agreed to indemnify the respective purchasers for certain potential losses relating to any breaches of the sellers' representations, warranties and obligations under each of the purchase agreements. EKLP does not expect any material claims under these indemnification obligations, but to the extent that any are asserted and paid, subsequent adjustments to the realized gains on these sales will be required.

Litigation - The Partnership is party to various legal actions arising in the normal course of business. Management believes that the disposition of outstanding legal actions will not have a material adverse impact on the Partnership's consolidated financial position.

Environmental and Other Indemnification Matters - Koch Energy, Inc., indemnified the Partnership for all known environmental liabilities as of February 1, 2001, arising from conditions existing or events occurring at Gulf South prior to the inception of the Partnership. In addition, Koch Energy, Inc., and affiliates of Entergy have indemnified the Partnership for any unknown environmental liabilities that occurred prior to February 1, 2001, related to the respective assets contributed to the Partnership by such parties, which are identified before the tenth anniversary date of the Partnership's formation. Any such environmental liabilities first identified prior to the sixth anniversary date are subject to a $50,000 per event deductible while those first identified after the sixth anniversary date but before the tenth anniversary date are subject to a $1.0 million per event deductible.

All environmental liabilities arising from the operations of the Partnership subsequent to January 31, 2001, are the obligation of the Partnership. Koch Energy, Inc., and affiliates of Entergy have also agreed to indemnify the Partnership for all other losses and expenses the Partnership incurs in connection with any claim, litigation, or suit arising prior to the Partnership's formation out of the operations of the Partners' respective businesses or assets that the Partners contributed to EKLP.

In connection with the sale of Gulf South, this indemnification, as it related to the pipeline operations, was terminated and a $5.4 million payment was made to Gulf South from a Koch subsidiary for the indemnification release. EKLP does not anticipate any additional future losses in excess of $5.4 million related to these environmental matters.

Regulatory Matters - EKLP is subject to regulation by various federal, state, and local government agencies and from time to time receives formal and informal requests for information from such agencies.

As an indirect partially owned subsidiary of Entergy, a registered holding company under the Public Utility Holding Company Act of 1935 (the "1935 Act"), EKLP generally must comply with certain requirements established in the 1935 Act, as well as rules and orders issued by the Securities and Exchange Commission under the 1935 Act that are applicable to investments by Entergy in non-utility companies.

At the federal level, the Federal Energy Regulatory Commission ("FERC") regulates certain activities of EKT US regarding energy commodity transportation and wholesale trading. EKT US is also subject to certain aspects of the jurisdiction of the Commodity Futures Trading Commission ("CFTC").

Commodity Futures Trading Commission Matter - On March 26, 2003, the FERC published a "Final Report on Price Manipulation in Western Markets," focusing on gas and power activity in California. EKT US was listed in the FERC report among the entities that had allegedly engaged in so-called "wash trading" in the gas markets with respect to 61 pairs of trades. In addition, EKT US received a subpoena from the CFTC seeking certain information about its gas and power business, relating to so-called "wash trades," and about information furnished to energy industry publications. EKT US also received a document request in connection with an informal inquiry by the Securities and Exchange Commission (the "SEC") relating to so-called "wash trades."

On January 28, 2004, the CFTC approved an order settling the administrative action relating to the CFTC's investigation. EKT US agreed to pay a civil penalty of $3 million without admitting or denying the CFTC's findings and recorded a liability for such amount as of December 31, 2003, which was paid in full in February 2004. The order cites EKT US for reporting false price information. There were no findings of price manipulation, attempted price manipulation, or wash trading made against EKT US or the Partnership. The order requires EKT US's continued cooperation with the CFTC. The CFTC notified EKT US that this settlement concluded the issues that were subject to their investigation.

Cornerstone Matter - On August 18, 2003, Cornerstone Propane Partners, LP, filed suit against EKT US and other entities on behalf of a putative class of persons who purchased and/or sold natural gas futures and options contracts on the New York Mercantile Exchange ("NYMEX") between January 1, 2000, and December 31, 2002. On November 14, 2003, Dominick Viola filed a similar complaint, naming EKT US. On November 25, 2003, the District Court for the Southern District of New York consolidated these cases with two other cases, neither of which named EKT US as a defendant. On January 20, 2004, the plaintiffs filed a consolidated class action complaint that alleges violations of the Commodity Exchange Act including manipulation (Section 9(a)), wash trades (Section 4c), and aiding and abetting violations of the Act (Section 22(a)). The defendants including EKT US filed a joint motion to dismiss this consolidated complaint on February 19, 2004. On September 24, 2004, the court denied the joint motion to dismiss. Discovery has commenced. Plaintiffs filed a Motion for the Class Certification on January 25, 2005. Defendants' Motion in Opposition to Class Certification is due on March 25, 2005. The outcome of this litigation cannot be determined at this time. Consequently, it is not possible to assess the impact, if any, of this action on EKT US. EKT US intends to vigorously defend this action.

Northern Illinois Gas Company Matter - On November 12, 2002, the SEC issued a subpoena requesting that Koch Industries, Inc., produce certain documents and information concerning business activities with Nicor, Inc. ("Nicor"). On November 22, 2002, the Partnership submitted to the SEC a limiting letter that, among other things, clarified that the entity that had the business relationship with Nicor was EKT US. EKT US is cooperating with the SEC and the U.S. Attorney's office in this matter and has produced documents and information in response to the subpoena. The SEC's inquiry regarding Nicor is ongoing, and the outcome or timing of this matter cannot be predicted. Other federal governmental authorities that are also investigating Nicor may be focusing on its business relationship with EKT US.

Proceedings have been underway since 2002 before the Illinois Commerce Commission (the "ICC") concerning Nicor that appear to be examining, at least in part, its business relationship with EKT US. EKT US has received certain requests for documents and information in that proceeding and in connection with a civil action in Cook County, Illinois, in which Nicor sought declaratory relief and specific performance. That action has been settled. Other governmental authorities in Illinois are participating in the ICC proceedings and may themselves have authority to conduct their own investigations into these matters.

On May 19, 2004, Nicor filed under seal a Verified Complaint against EKT US in Circuit Court of Cook County, Illinois, Chancery Division. The Complaint sought production of certain records that Nicor claimed were necessary to verify the accuracy of payments it made to EKT US pursuant to certain contracts between them. Nicor further asked for an accounting between the parties. The Complaint did not include a claim for damages. On July 16, 2004, the Circuit Court entered a Protective Order and a Dismissal Order, dismissing the Complaint in part with prejudice and in part without prejudice, while retaining jurisdiction to enforce or modify the Protective Order entered along with the Dismissal Order. On August 3, 2004, the parties, following extensive negations, entered into an Order modifying the terms of the Court's prior Protective Order. As before, however, the case was dismissed, in part without prejudice and with the Court retaining the right to enforce or modify its Protective Order. To date, no enforcement proceedings have been initiated against EKT US.

On August 25, 2004, the CFTC issued an informal request that EKT US produce certain information and preserve records that are related to any asset optimization agreement entered into between EKLP and/or IMD Storage and Transportation Asset Management Company ("IMD") and any third party. In 1998, Koch Energy Trading, Inc. ("KET"), a predecessor of EKT US, acquired a 50% ownership share in IMD. In 2000, KET increased its existing stake in IMD to 100% by acquiring the remaining ownership interest. The assets of KET, including IMD, subsequently became part of EKLP in February 2001. On September 13, 2004, a formal order of investigation was issued. The CFTC clarified the scope of its informal request and requested that EKT US produce information as part of an investigation related to EKT US's and/or IMD's trading activities with Nicor and Public Service Enterprise Group through December 31, 2002. EKT US is cooperating with the CFTC and is providing the requested information and preserving the referenced records. No enforcement proceedings have been initiated against EKT US or any of its affiliates.

Illinois Commerce Commission v. Entergy-Koch Trading, L.P. - On November 22, 2004, the Illinois Commerce Commission ("ICC") filed an Application to Compel Attendance of Witnesses and the Production of Tape Recordings and Documents ("Application") against EKT US in the Circuit Court of Cook County, Illinois. The Application seeks the production of certain tape recordings and documents sought by Nicor as specified in a subpoena issued by the ICC in June 2004 pursuant to Nicor's request in an ICC proceeding to which EKT US is not a party. The Application does not seek monetary damages. On February 1, 2005, the Court denied EKT US's motion to dismiss the Application on jurisdictional grounds. EKT US is pursuing as appeal of that ruling. EKT US's answer to the Application is due on February 22, 2005. No discovery has occurred in the case. No enforcement proceedings have been initiated against EKT US or any of its affiliates.

City of Tacoma v. American Electric Power Service Corporation, et al - On June 7, 2004, a complaint was filed in the U.S. District Court for the Western District of Washington in which Koch Energy Trading, Inc., a predecessor of EKT US, was named as a defendant along with approximately 55 other entities. The complaint relates to power trading in California in 2000 and 2001 and seeks damages under the Sherman Act.

On August 20, 2004, the judicial Panel on Multidistrict Litigation issued a Conditional Transfer Order, transferring the case to the Southern District of California to be assigned to Judge Robert H. Whaley and to be consolidated or coordinated with the other cases involved in the In re California Wholesale Electricity Antitrust Litigation, MDL No. 1405. Plaintiffs have represented that two of the suits in front of judge Whaley have been dismissed and are now on appeal to the Ninth Circuit and that the remainder of the suits in front of Judge Whaley have been stayed pending the Ninth Circuit's decision on the dismissed cases. The defendant filed a joint motion to dismiss the complaint on December 9, 2004, which EKT US joined. On February 11, 2005, the Court granted the motion to dismiss and dismissed the lawsuit. It is not certain what the City of Tacoma will do in response to the Court's dismissal of the case. EKT US intends to continue to vigorously defend this action, if necessary.

Other - In addition, EKT US has received several formal and informal requests for information from various regulatory and governmental agencies in connection with the Partnership's gas and power businesses. At this point, the Partnership does not believe that these inquiries will result in a material impact on the Partnership.

Non-Cancelable Operating Obligations

Optimization Contracts - EKT is required to make specified minimum payment relative to optimizing certain customers' natural gas storage and transportation assets. For the years ended December 31, 2004, 2003, and 2002, approximately $54.2 million, $30.5 million, and $20.4 million, respectively, of these specified minimum payments were made. All optimization contracts were assigned to MLCI as part of the sale of Trading Assets to MLCI.

Operating Leases - EKLP has various noncancelable operating lease commitments extending through the year 2011. Most operating leases were assigned to MLCI and TGT Pipeline, LLC, as part of the sale of Trading Assets and Gulf South. Total operating lease expense for the years ended December 31, 2004, 2003, and 2002, were $5.0 million, $6.3 million, and $6.5 million, respectively. EKLP's remaining minimum future commitments related to these items as of December 31, 2004, are as follows (in thousands):
 

2005	$ 180
2006	180
2007	180
2008	180
2009	180
Thereafter	195
Total	$ 1,095

11.     Related-Party Transactions

EKT US was a party to an electric power purchase and sale agreement with an Entergy affiliate to provide various energy risk management services. For the years ended December 31, 2004, 2003, and 2002, EKT US received $2.3 million, $3.5 million, and $3.9 million, respectively, from the Entergy affiliate as reimbursement for the resources needed to provide these services.

EKT Europe was party to an energy management agreement with Entergy affiliates whereby EKT Europe provides various risk management services for the Entergy affiliates. For the year ended December 31, 2002, EKT Europe received $0.9 million from the Entergy affiliate as reimbursement for the resources needed to provide these services. This agreement has expired in 2003, and the amount received by EKT Europe for the year ended December 31, 2003, was immaterial.

At December 31, 2004, the Partnership did not hold any assets and liabilities from trading activities relative to transactions with Entergy and Koch affiliates. At December 31, 2003, included in assets and liabilities from trading activities are assets of $15.5 million and liabilities of $8.7 million relative to transactions with Entergy and Koch affiliates.

Included in the net gain from trading activities for the year ended December 31, 2004, are affiliate revenues of $378.2 million (1.8% of trading revenues), affiliate cost of sales of $79.5 million (0.4% of trading cost of sales), and net realized affiliate gain of $11.4 million from financial instruments. Included in the net gain from trading activities for the year ended December 31, 2003, are affiliate revenues of $538.6 million (2.3% of trading revenues), affiliate cost of sales of $188.2 million (0.8% of trading cost of sales), and net realized affiliate loss of $17.7 million from financial instruments. Included in the net gain from trading activities for the year ended December 31, 2002, are affiliate revenues of $434.0 million (2.7% of trading revenues), affiliate cost of sales of $424.4 million (3.2% of trading cost of sales), and net realized affiliate loss of $9.0 million from financial instruments.

EKLP has a building operating lease agreement with Entergy and Koch extending to the years 2014 and 2011, respectively. The Partnership had related rent expense of approximately $2.6 million, $4.0 million, and $3.1 million for the years ended December 31, 2004, 2003, and 2002, respectively.

Gulf South had trade receivables with an affiliate, Entergy, in the amounts of $0.6 million as of December 31, 2003. Gulf South provided transportation and storage services to Entergy and related companies in the amount of $7.2 million, $7.7 million, and $8.1 million for the years ended December 31, 2004, 2003, and 2002, respectively.

Additionally, the Partnership purchased information technology services from a Koch affiliate in the amount of $10.2 million, $11.2 million, and $12.0 million for the years ended December 31, 2004, 2003, and 2002, respectively.

Included in receivables from Partners at December 31, 2003, are amounts related to certain incentive compensation obligations that existed prior to the formation of the Partnership. Such amounts were fully reimbursed in 2004 by the Partners.

See also Note 12, "Partners' Capital," for indemnification provided by Entergy.

12.     Partners' Capital

Pursuant to the Partnership Agreement, one of the limited partners made a contribution of $72.7 million in January 2004. The equivalent amounts were distributed to the remaining limited partner. In addition, in January 2004 certain assets of the Partnership were revalued to measure the economic impact to the Partners at this date. Such revaluation did not have any effect on the historical cost basis consolidated financial statements of the Partnership.

In 2002, EKLP had a contractual dispute with a counterparty, and the resulting loss was indemnified by Entergy. In connection with the indemnification, the Partnership recorded a receivable from Entergy of $32.8 million and a corresponding contribution to capital in the accompanying consolidated statement of changes in partners' capital as December 31, 2002. The $32.8 million was paid by Entergy to the Partnership on February 7, 2003. As part of the indemnification arrangement, beginning in January 2003, Entergy is entitled to all the benefits and detriments associated with the contractual agreements with the counterparty, and as a result, EKLP had a $2.3 million receivable (included in receivables from affiliated from Entergy at December 31, 2003). EKLP no longer services the power needs of the counterparty on behalf of Entergy.

13.     Employee Retirement Plans

For its domestic operations, the Partnership established the Money Purchase Pension Plan, which is available to all active employees meeting certain minimum requirements. This plan is a defined contribution plan subject to the provisions of the Employee Retirement Income Security Act of 1974 ("ERISA"). Under the terms of the plan, 4% of employees' base compensation is contributed to the plan.

For its domestic operations, the Partnership also established the 401(k) Retirement Plan, which is available to all active employees. This plan is a defined contribution plan subject to the provisions of the ERISA. Under the terms of the plan, employees may contribute a percentage of their annual salary, subject to Internal Revenue Service limits, with the Partnership matching 100% of the first 6% contributed by employees with over one year of service.

In December 2004, the Partnership transferred sponsorship of both the Money Purchase Pension Plan and the 401(k) Retirement Plan to Gulf South. Upon the sale of Gulf South, EKLP ceased to have any title, interest, or liabilities associated with either of these plans.

For its European operations, the Partnership established a Group Personal Pension Plan, which is available to all active employees and is managed by Scottish Equitable. Under the terms of the plan, employees can contribute from 2% to 5% of their base compensation on a pretax basis. The Partnership contributed from 3% to 8% of an employee's base compensation depending on the amount that the employee contributed to the plan. The Group Personal Pension Plan was held by EKLP's subsidiary EKT Europe, which was sold as part of the sale of the Trading Assets to MLCI.

For its employees' participation in these plans, the Partnership recorded expense for the years ended December 31, 2004, 2003, and 2002, of approximately $4.5 million, $4.5 million, and $4.4 million, respectively. Partnership contributions to the above plans are subject to vesting requirements.

14.     Taxes

EKT Europe is subject to UK taxes. The net income before income taxes and cumulative effect of change in accounting principle attributed to European operations for the years ended December 31, 2004, 2003, and 2002, is $48.3 million, $20.6 million, and $9.8 million, respectively. The total income tax expense related to the net income before income taxes and cumulative effect of change in accounting principle that is attributed to foreign operations is $15.8 million, $4.5 million, and $3.7 million for the years ended December 31, 2004, 2003, and 2002, respectively. Such income tax expense amounts were reflected as current income taxes.

15.     Accrued Liabilities

Accrued liabilities is summarized as follows:

	December 31
	2004	2003
	(In Thousands)
Accrued working capital adjustments related to the sale of the     trading assets and Gulf South	$ 32,596	$ -
Accrued transaction and exit costs	26,348	-
Accrued interest	-	11,273
Other accrued liabilities	8,102	75,955
Total accrued liabilities	$ 67,046	$ 87,228